Fluid identification method, apparatus, processor, and machine-readable storage medium

Abstract

This invention provides a fluid identification method, device, processor, and machine-readable storage medium, relating to the field of oil and gas reservoir evaluation. The method includes: determining the porosity correction coefficient for escaping fluids in multiple full-diameter core sections; determining the apparent total porosity, two-dimensional nuclear magnetic resonance T1-T2 spectra, and porosity of each fluid component in the full-diameter core; determining the porosity of the fluid distribution range, the porosity of the bound fluid distribution range, the porosity of the movable fluid in vacuum-saturated water, and the total porosity; determining the escaping fluid porosity correction coefficient based on the total porosity, apparent total porosity, and bound water porosity of the full-diameter core, and establishing a porosity correction coefficient model based on the correction coefficients of multiple core sections, and determining the total porosity based on the model; and determining the oil and gas saturation and water cut of the entire well section core using the apparent total porosity, total porosity, water saturation, and porosity of each fluid component. Through this invention, the porosity of gas reservoir cores can be accurately measured, fluid properties can be accurately identified, and quantitative evaluation can be performed.

Description

Technical Field

[0001] This invention relates to the field of oil and gas reservoir evaluation technology, specifically to a fluid identification method, a fluid identification method apparatus, a processor, and a machine-readable storage medium. Background Technology

[0002] As oilfields delve deeper into complex reservoirs, reservoir evaluation becomes increasingly challenging, demanding more rigorous microscopic analysis and requiring higher levels of timeliness and accuracy. Furthermore, with increasing exploration difficulty and deeper development, edge water, bottom water, and surrounding injection wells impact the original reservoir, causing varying degrees of water flooding in different strata. This leads to increased water content in the original reservoir, further complicating reservoir evaluation.

[0003] In existing technologies, the evaluation of the reservoir properties and hydrocarbon potential of complex reservoirs mainly relies on well logging data and laboratory plunger core experiments. Conventional well logging primarily uses the response equation of the well logging curve and the resistivity and three-porosity data in the well logging data to obtain the apparent formation water resistivity, thereby identifying the reservoir fluid properties. Alternatively, oil and water identification can be performed using nuclear magnetic resonance logging data in dual-TE mode with a long waiting time (Tw).

[0004] With the diversification of exploration fields, complex reservoirs such as shale oil, carbonate rocks, and low-resistivity oil layers generally exhibit a certain degree of heterogeneity. Rock electrical parameters are greatly influenced by lithology, well logging curve response characteristics are not obvious, the applicability of Archie's formula is limited, fluid properties and saturation calculations are difficult, and well logging data acquisition is easily affected by well conditions. In rock physics experiments, most laboratory experiments require plunger samples. Plunger rock samples are relatively small in volume, providing limited formation information, have long experimental cycles, and suffer from significant oil and gas escape, making it difficult to identify reservoir fluid properties, quantitative analysis of hydrocarbon content is challenging, and the experimental processes are complex and costly, failing to meet the requirements of oilfield companies for rapid interpretation and evaluation of complex reservoirs.

[0005] Fluid identification can also be performed using full-diameter core NMR experiments at the well site. This involves continuous, high-precision, non-destructive, and rapid NMR scanning of the entire diameter of a newly drilled well to obtain information such as porosity, pore structure, and fluid characteristics. It is unaffected by the wellbore environment, has a high safety factor, and produces large sample volumes, maximizing the preservation of original geological information. In heterogeneous reservoirs, the obtained continuous pore information can reflect formation properties. However, this method is only suitable for heavy oil and heavy hydrocarbon reservoirs where oil and gas are not easily dispersed. It is not applicable to conventional oil layers, light oil layers, and gas layers in China. Especially in gas reservoirs, movable oil and gas disperse to some extent when the core is removed from the formation. As the core is pulled to the surface, pressure and temperature changes increase the amount of dispersed fluid, affecting the accuracy of the measurement results. Summary of the Invention

[0006] To address the technical problems of severe oil and gas leakage in existing technologies, making it difficult to identify reservoir fluid properties and quantitatively analyze oil and gas content, this invention provides a fluid identification method, a fluid identification device, a processor, and a machine-readable storage medium. This fluid identification method can correct for the porosity of leaking fluids, improving the accuracy of measurement results. By quantitatively calculating reservoir water content and gas saturation, fluid identification and quantitative evaluation are performed, providing experimental data support for oilfield development plans and recovery rates.

[0007] To achieve the above objectives, a first aspect of the present invention provides a fluid identification method, comprising: determining the porosity correction coefficients for escaping fluids in multiple full-diameter core segments; wherein the escaping fluid porosity correction coefficients for each full-diameter core segment are determined by: determining the apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectra of the full-diameter core, and using the two-dimensional NMR T1-T2 spectra to determine the porosity of each component fluid in the full-diameter core; wherein the porosity of each component fluid includes at least bound water porosity; and determining the two-dimensional NMR T1-T2 spectra using time-lapse NMR measurements of the full-diameter core. The fluid distribution range is determined, and the porosity of the bound fluid distribution range of the full-diameter core is determined; wherein, the fluid distribution range includes the escaping fluid distribution range and the bound fluid distribution range; the porosity of the movable fluid in the vacuum-saturated water of the full-diameter core is determined by NMR measurement using vacuum saturated water; the total porosity of the full-diameter core is determined based on the porosity of the movable fluid in the vacuum-saturated water of the full-diameter core and the porosity of the bound fluid distribution range of the full-diameter core; the correction coefficient for the escaping fluid porosity of this section of the full-diameter core is determined based on the total porosity, apparent total porosity, and bound water porosity of the full-diameter core. A porosity correction coefficient model for the entire well section was established based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core sections. The total porosity of the core sample in the entire well section is determined based on the porosity correction coefficient model for the entire well section. The apparent total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section were determined. The apparent total porosity, total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section were then used to determine the oil and gas saturation and water cut of the core sample of the entire well section.

[0008] Furthermore, determining the apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectrum of the full-diameter core includes: conducting full-diameter core NMR measurements at the well site to determine the apparent total porosity and two-dimensional NMR T1-T2 spectrum of the full-diameter core.

[0009] Furthermore, the method of determining the porosity of each component of the full-diameter core using two-dimensional nuclear magnetic resonance T1-T2 spectra includes: determining the fluid saturation of each component using two-dimensional nuclear magnetic resonance T1-T2 spectra; and determining the fluid porosity of each component based on the fluid saturation of each component and the apparent total porosity.

[0010] Furthermore, the fluid saturation of each component was determined in the following manner: ; ; ; Among them, Y k Let be the signal intensity corresponding to the k-th fluid in the two-dimensional NMR T1-T2 spectrum; P(i,j) be the signal intensity of the coordinate point where T2 is i and T1 is j in the two-dimensional NMR T1-T2 spectrum; Y be the total signal intensity of the two-dimensional NMR T1-T2 spectrum; S k Let be the fluid saturation of the k-th fluid.

[0011] Furthermore, the fluid porosity of each component in the full-diameter core also includes: movable water porosity and apparent oil and gas porosity.

[0012] Furthermore, the step of using full-diameter core time-lapse NMR measurement to determine the fluid distribution range of the two-dimensional NMR T1-T2 spectrum includes: obtaining two-dimensional NMR T1-T2 spectra at different times after the core exits the casing using full-diameter core time-lapse NMR measurement; determining the fluid signal variation law based on the characteristics of the two-dimensional NMR T1-T2 spectra at different times after the core exits the casing; and determining the fluid distribution range of the two-dimensional NMR T1-T2 spectrum based on the fluid signal variation law.

[0013] Furthermore, the total porosity of the full-diameter core was determined in the following way: Φ 岩总 =Φ 束缚流体 +Φ 抽真空饱和水可动流体 ; Where, Φ 岩总 Φ represents the total porosity of the full-diameter core. 束缚流体 The porosity of the bound fluid distribution area in the full-diameter core is Φ. 抽真空饱和水可动流体 The porosity of the vacuum-saturated water movable fluid in the full-diameter core sample is given.

[0014] Furthermore, the porosity correction factor for the escaping fluid is obtained as follows: Escaped fluid porosity correction factor = (Φ 岩总 -Φ 岩束缚水 ) / (Φ 岩视总孔 -Φ 岩束缚水 ); Where, Φ 岩总 Φ represents the total porosity of the full-diameter core.岩视总孔 The apparent total porosity of the full-diameter core is Φ. 岩束缚水 This represents the bound water porosity of a full-diameter core sample.

[0015] Furthermore, the total porosity of the entire well core section was obtained through the following methods: Φ 总 =Φ 束缚水 +(Φ 视总孔 -Φ 束缚水 * Porosity correction factor for escaping fluid; Where, Φ 总 Φ represents the total porosity of the core sample throughout the well. 视总孔 Φ represents the apparent total porosity of the entire core section. 束缚水 This refers to the bound water porosity of the core sample throughout the entire well.

[0016] Furthermore, the hydrocarbon saturation of the entire well core section was determined in the following way: Sog = (Φ 总 -Sw*Φ 视总孔 ) / Φ 总 ; Where Sog represents the hydrocarbon saturation of the entire well core section, and Φ 总 Φ represents the total porosity of the core sample throughout the well, Sw represents the water saturation of the core sample throughout the well, and Φ represents the total porosity of the core sample throughout the well. 视总孔 The apparent total porosity is the core sample from the entire well section.

[0017] Furthermore, the water cut of the entire well core section was determined in the following way: Fw=Φ 可动水 / (Φ 总 -Φ 视总孔 +Φ 可动水 + Φ 视含油气 ); Where Fw is the water cut of the entire core section, Φ 总 Φ represents the total porosity of the core sample throughout the well. 视总孔 Φ represents the apparent total porosity of the entire core section. 可动水 The movable water porosity of the entire well core section, Φ 视含油气 This represents the apparent oil and gas porosity of the core sample throughout the well.

[0018] Furthermore, the establishment of a porosity correction coefficient model for the entire well section based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core segments includes: fitting the porosity correction coefficient of the escaping fluid from multiple full-diameter core segments; and establishing a porosity correction coefficient model for the entire well section based on the fitting results.

[0019] A second aspect of the present invention provides a fluid identification device, the fluid identification device comprising: A full-diameter core correction coefficient determination module is used to determine the escaping fluid porosity correction coefficient for multiple full-diameter core segments. The escaping fluid porosity correction coefficient for each full-diameter core segment is determined as follows: The apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectra of the full-diameter core are determined, and the porosity of each component fluid in the full-diameter core is determined using the two-dimensional NMR T1-T2 spectra; wherein the porosity of each component fluid includes at least bound water porosity; the fluid distribution range of the two-dimensional NMR T1-T2 spectra is determined using time-lapse NMR measurements of the full-diameter core, and the... The porosity of the bound fluid distribution range in the full-diameter core is determined; wherein, the fluid distribution range includes the escaping fluid distribution range and the bound fluid distribution range; the porosity of the movable fluid in the vacuum-saturated water of the full-diameter core is determined by NMR measurement using vacuum-saturated water; the total porosity of the full-diameter core is determined based on the movable fluid porosity in the vacuum-saturated water and the porosity of the bound fluid distribution range in the full-diameter core; and the correction coefficient for the escaping fluid porosity of this section of the full-diameter core is determined based on the total porosity, apparent total porosity, and bound water porosity of the full-diameter core. The porosity correction coefficient model determination module is used to establish a porosity correction coefficient model for the entire well section based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core sections. The total porosity determination module is used to determine the total porosity of the core sample throughout the entire well section based on a porosity correction coefficient model. The fluid quantitative module is used to determine the apparent total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section. It also uses the apparent total porosity, total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section to determine the oil and gas saturation and water cut of the core sample of the entire well section.

[0020] A third aspect of the present invention provides a processor configured to perform the fluid recognition method described above.

[0021] A fourth aspect of the present invention provides a machine-readable storage medium storing instructions that, when executed by a processor, configure the processor to perform the fluid identification method described above.

[0022] The present invention has at least the following technical effects through the technical solution provided by the present invention: The fluid identification method of this invention acquires multiple full-diameter core segments and determines the porosity correction coefficient for the escaping fluid in each full-diameter core segment: First, the apparent total porosity, two-dimensional NMR T1-T2 spectrum, and porosity of each component fluid in the full-diameter core are determined; the fluid distribution range of the two-dimensional NMR T1-T2 spectrum is determined using time-lapse NMR measurements of the full-diameter core, and the porosity of the bound fluid distribution range in the full-diameter core is determined; the porosity of the movable fluid in the vacuum-saturated water of the full-diameter core is determined using NMR measurements of the vacuum-saturated water of the full-diameter core; the porosity of the escaping fluid is supplemented using the porosity of the movable fluid in the vacuum-saturated water of the full-diameter core, and the total porosity of the escaping fluid in the full-diameter core is supplemented based on the porosity of the movable fluid in the vacuum-saturated water of the full-diameter core and the porosity of the bound fluid distribution range in the full-diameter core; the escaping fluid porosity correction coefficient for that full-diameter core segment is determined based on the total porosity, apparent total porosity, and fluid porosity of the full-diameter core. After determining the porosity correction coefficients for escaping fluids in multiple full-diameter core sections, a porosity correction coefficient model for the entire well section is established based on these coefficients. The total porosity of the entire well section is then determined based on this model. The apparent total porosity, water saturation, and porosity of each component fluid in the entire well section are then determined. Using these parameters, the oil and gas saturation and water cut of the entire well section are calculated. The fluid identification method provided by this invention can correct for escaping fluid porosity, accurately determine the porosity of gas reservoir cores, improve the accuracy of measurement results, and accurately identify and quantitatively evaluate fluids by quantitatively calculating reservoir water cut and gas saturation, providing experimental data support for oilfield development plans and recovery rates.

[0023] Other features and advantages of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0024] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings: The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings: Figure 1 A flowchart of the fluid identification method provided in an embodiment of the present invention; Figure 2 The fluid identification method provided in this embodiment of the invention utilizes full-diameter core time-lapse NMR measurements to obtain two-dimensional NMR T1-T2 spectra at different times after core collection; Figure 3This is a schematic diagram comparing the two-dimensional nuclear magnetic resonance T1-T2 spectra of a full-diameter core before and after vacuum saturation in the fluid identification method provided in this embodiment of the invention. Figure 4 A schematic diagram of the porosity correction coefficient model established in the fluid identification method provided in this embodiment of the invention; Figure 5 A schematic diagram comparing the total porosity of vacuum saturated water obtained by NMR measurement in the fluid identification method provided in this embodiment of the invention with the total porosity of indoor plunger samples and the total porosity of CMR-NG NMR logging; Figure 6 This is a schematic diagram comparing the total porosity after correction by NMR measurement of the whole diameter core at the well site with the total porosity of CMR-NG NMR logging in the fluid identification method provided in this embodiment of the invention. Figure 7 A schematic diagram comparing the actual and calculated water cut values ​​of well DN2-29H in the fluid identification method provided in this embodiment of the invention. Figure 8 This is a schematic diagram of a fluid identification device provided in an embodiment of the present invention. Detailed Implementation

[0025] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the scope of the present invention.

[0026] It should be noted that, unless otherwise specified, the embodiments and features described in the present invention can be combined with each other.

[0027] In this invention, unless otherwise stated, directional terms such as "upper," "lower," "top," and "bottom" are generally used to describe the relative positions of components in relation to the directions shown in the accompanying drawings or in relation to the vertical, perpendicular, or gravitational directions.

[0028] As described in the background section, existing semiconductor structures have poor performance. This will be explained in detail below with reference to the accompanying drawings.

[0029] Please refer to Figure 1The first aspect of this invention provides a fluid identification method, which includes: S101: determining the porosity correction coefficient of escaping fluid in multiple full-diameter core segments; wherein the escaping fluid porosity correction coefficient of each full-diameter core segment is determined by: determining the apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectrum of the full-diameter core, and using the two-dimensional NMR T1-T2 spectrum to determine the porosity of each component fluid in the full-diameter core; wherein the porosity of each component fluid includes at least bound water porosity; and using time-lapse NMR measurements of the full-diameter core to determine the two-dimensional NMR T1-T2 spectrum. The fluid distribution range of the spectrum is determined, and the porosity of the bound fluid distribution range of the full-diameter core is determined; wherein, the fluid distribution range includes the escaping fluid distribution range and the bound fluid distribution range; the porosity of the movable fluid in the vacuum saturated water of the full-diameter core is determined by NMR measurement using vacuum saturated water; the total porosity of the full-diameter core is determined based on the movable fluid porosity in the vacuum saturated water and the porosity of the bound fluid distribution range of the full-diameter core; the correction coefficient for the escaping fluid porosity of this section of the full-diameter core is determined based on the total porosity, apparent total porosity, and bound water porosity of the full-diameter core. S102: Establish a porosity correction coefficient model for the entire well section based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core sections; S103: Determine the total porosity of the core sample throughout the entire well section based on the porosity correction coefficient model. S104: Determine the apparent total porosity, water saturation, and fluid porosity of the entire well section core, and use the apparent total porosity, total porosity, water saturation, and fluid porosity of the entire well section core to determine the oil and gas saturation and water cut of the entire well section core.

[0030] Specifically, step S101 is first executed: determining the porosity correction coefficient for the escaping fluid of multiple full-diameter core segments; wherein, the porosity correction coefficient for the escaping fluid of each full-diameter core segment is determined by the following method: determining the apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectrum of the full-diameter core, and using the two-dimensional NMR T1-T2 spectrum to determine the porosity of each component fluid in the full-diameter core; wherein, the porosity of each component fluid includes at least the porosity of bound water; using time-lapse NMR measurements of the full-diameter core, determining the fluid distribution range of the two-dimensional NMR T1-T2 spectrum, and confirming... The porosity of the bound fluid distribution range in the full-diameter core is determined; wherein, the fluid distribution range includes the escaping fluid distribution range and the bound fluid distribution range; the porosity of the movable fluid in the vacuum-saturated water of the full-diameter core is determined by NMR measurement using vacuum-saturated water; the total porosity of the full-diameter core is determined based on the movable fluid porosity in the vacuum-saturated water and the porosity of the bound fluid distribution range in the full-diameter core; and the correction coefficient for the escaping fluid porosity of this section of the full-diameter core is determined based on the total porosity, apparent total porosity, and bound water porosity of the full-diameter core. Furthermore, determining the apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectrum of the full-diameter core includes: conducting full-diameter core NMR measurements at the well site to determine the apparent total porosity and two-dimensional NMR T1-T2 spectrum of the full-diameter core.

[0031] Furthermore, the method of determining the porosity of each component of the full-diameter core using two-dimensional nuclear magnetic resonance T1-T2 spectra includes: determining the fluid saturation of each component using two-dimensional nuclear magnetic resonance T1-T2 spectra; and determining the fluid porosity of each component based on the fluid saturation of each component and the apparent total porosity.

[0032] Furthermore, the fluid saturation of each component was determined in the following manner: ; ; ; Among them, Y k Let be the signal intensity corresponding to the k-th fluid in the two-dimensional NMR T1-T2 spectrum; P(i,j) be the signal intensity of the coordinate point where T2 is i and T1 is j in the two-dimensional NMR T1-T2 spectrum; Y be the total signal intensity of the two-dimensional NMR T1-T2 spectrum; S k Let be the fluid saturation of the k-th fluid.

[0033] Furthermore, the fluid porosity of each component in the full-diameter core also includes: movable water porosity and apparent oil and gas porosity.

[0034] Furthermore, the step of using full-diameter core time-lapse NMR measurement to determine the fluid distribution range of the two-dimensional NMR T1-T2 spectrum includes: obtaining two-dimensional NMR T1-T2 spectra at different times after the core exits the casing using full-diameter core time-lapse NMR measurement; determining the fluid signal variation law based on the characteristics of the two-dimensional NMR T1-T2 spectra at different times after the core exits the casing; and determining the fluid distribution range of the two-dimensional NMR T1-T2 spectrum based on the fluid signal variation law.

[0035] Furthermore, the total porosity of the full-diameter core was determined in the following way: Φ 岩总 Φ 束缚流体 +Φ 抽真空饱和水可动流体 ; Where, Φ 岩总 Φ represents the total porosity of the full-diameter core. 束缚流体 The porosity of the bound fluid distribution area in the full-diameter core is Φ. 抽真空饱和水可动流体 The porosity of the vacuum-saturated water movable fluid in the full-diameter core sample is given.

[0036] Furthermore, the porosity correction factor for the escaping fluid is obtained in the following way: Escaped fluid porosity correction coefficient = (Φ 岩总 -Φ 岩束缚水 ) / (Φ 岩视总孔 -Φ 岩束缚水 ); Where, Φ 岩总 Φ represents the total porosity of the full-diameter core. 岩视总孔 The apparent total porosity of the full-diameter core is Φ. 岩束缚水 This represents the bound water porosity of a full-diameter core sample.

[0037] Specifically, in this embodiment of the invention, multiple full-diameter core samples are collected. Immediately after each full-diameter core sample collection, full-diameter core NMR measurements are performed at the well site to obtain the apparent total porosity and two-dimensional NMR T1-T2 spectra of the full-diameter core. The fluid saturation of each component in the full-diameter core is determined using the two-dimensional NMR T1-T2 spectra. ; ; ; Among them, Y k Let be the signal intensity corresponding to the k-th fluid in the two-dimensional NMR T1-T2 spectrum; P(i,j) be the signal intensity of the coordinate point where T2 is i and T1 is j in the two-dimensional NMR T1-T2 spectrum; Y be the total signal intensity of the two-dimensional NMR T1-T2 spectrum; S k Let be the fluid saturation of the k-th fluid.

[0038] In this embodiment, using a sandstone reservoir as the background, the fluid components in the full-diameter core mainly consist of clay-bound water, capillary-bound water, residual oil and gas, movable water, and escaped oil and gas (not detectable at the surface). The escape of oil and gas from the core leads to a lower total porosity value in the full-diameter core NMR measurements at the well site. The measured fluids are mainly bound water (including clay-bound water and capillary-bound water), residual oil and gas, and movable water. The bound water saturation, residual oil and gas saturation, and movable water saturation of the full-diameter core are determined using two-dimensional NMR T1-T2 spectra. Multiplying the fluid saturation by the apparent total porosity yields the corresponding porosity of each fluid component, namely, bound water porosity, movable water porosity, and apparent oil and gas porosity.

[0039] Next, time-lapse NMR measurements were performed on the full-diameter core to obtain two-dimensional NMR T1-T2 spectra at different times after core exit. The variation patterns of fluid signals for each component in the T1-T2 spectra at different times were determined. The intervals where the fluid signal did not change were defined as the bound fluid distribution intervals, and the intervals where the fluid signal changed were defined as the escaped fluid distribution intervals. Simultaneously, the porosity Φ of the bound fluid distribution intervals in the full-diameter core was obtained through full-diameter core NMR measurements at the well site. 束缚流体 .

[0040] In one possible implementation, time-lapse NMR measurements of the full-diameter core are performed to obtain, as shown below... Figure 2 The two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectra at different times after core collection are shown. The variation law of fluid signal in the two-dimensional NMR T1-T2 spectra at different times was determined. It was found that the fluid signal amplitude remained unchanged in the interval T2≤1ms, indicating that this interval is the distribution interval of bound fluid. In the interval 1<T2≤10ms, the fluid signal amplitude decreased slowly. In the interval T2>10ms, the fluid signal amplitude changed significantly, which is the interval of main escaping fluid. Therefore, the interval T2≤1ms was determined to be the distribution interval of bound fluid, and the interval T2>1ms was determined to be the distribution interval of escaping fluid.

[0041] Then, after conducting a full-diameter core vacuum saturation water experiment on the full-diameter core, nuclear magnetic resonance (NMR) measurements were performed to determine the porosity of the movable fluid region under vacuum saturation conditions, i.e., the movable fluid porosity Φ under vacuum saturation water conditions. 抽真空饱水可动流体 The porosity of the escaping fluid region (i.e., the kinetic fluid region) under vacuum saturation compensates for the porosity of the escaping oil and gas portion in the core directly measured. Therefore, the porosity Φ of the bound fluid distribution region of the entire diameter core is considered... 束缚流体 The porosity of the movable fluid zone under vacuum saturation state in a full-diameter core (i.e., the movable fluid porosity under vacuum saturation water) Φ 抽真空饱水可动流体 The total porosity Φ of the full-diameter core can be obtained by adding them together. 岩总 It is also the total porosity measured by NMR in vacuum saturated water, Φ 岩总 =Φ岩束缚水 +Φ 岩可动水 +Φ 岩视含油气 +Φ 岩逸散油气 =Φ 束缚流体 +Φ 抽真空饱水可动流体 , Φ 岩逸散油气 The porosity of the escaping oil and gas in the full-diameter core.

[0042] Please refer to Figure 3 In one possible implementation, after determining the bound fluid distribution range for T2 ≤ 1 ms and the escaped fluid distribution range for T2 > 1 ms, a full-diameter core is subjected to a full-diameter core vacuum saturation water experiment followed by NMR measurements to determine the porosity Φ in the T2 > 1 ms range of the full-diameter core under vacuum saturation water conditions. 抽真空饱和水T2>1ms Therefore, the total porosity Φ of the full-diameter core is obtained. 岩总 =Φ T2≤1ms +Φ 抽真空饱和水T2>1ms .

[0043] Then calculate the escaping fluid porosity correction factor for the full-diameter core segment: escaping fluid porosity correction factor = Φ 岩可动流体 / Φ 岩视可动流体 =(Φ 岩总 -Φ 岩束缚水 ) / (Φ 岩视总孔 -Φ 岩束缚水 ), Φ 岩视总孔 =Φ 岩束缚水 +Φ 岩可动水 +Φ 岩视含油气 , Φ 岩可动流体 For the movable fluid porosity of the full-diameter core, Φ 岩视可动流体 The porosity of the movable fluid is directly measured from the full-diameter core, i.e., the apparent movable fluid porosity. The fluid escape correction coefficients for the remaining full-diameter core segments were obtained using the same method.

[0044] Next, proceed to step S102: establish a porosity correction coefficient model for the entire well section based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core sections.

[0045] Furthermore, the establishment of a porosity correction coefficient model for the entire well section based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core segments includes: fitting the porosity correction coefficient of the escaping fluid from multiple full-diameter core segments; and establishing a porosity correction coefficient model for the entire well section based on the fitting results.

[0046] like Figure 4 As shown, specifically, in this embodiment of the invention, the porosity correction coefficient of the escaping fluid in multiple full-diameter core sections is fitted, and the fitting result is used as the porosity correction coefficient model for the entire well section.

[0047] Next, proceed to step S103: determine the total porosity of the core sample in the entire well section based on the porosity correction coefficient model for the entire well section.

[0048] Furthermore, the total porosity of the entire well core section was obtained through the following methods: Φ 总 =Φ 束缚水 +(Φ 视总孔 -Φ 束缚水 * Porosity correction factor for escaping fluid; Where, Φ 总 Φ represents the total porosity of the core sample throughout the well. 视总孔 Φ represents the apparent total porosity of the entire core section. 束缚水 This refers to the bound water porosity of the core sample throughout the entire well.

[0049] Specifically, in this embodiment of the invention, the formula for the porosity correction coefficient of the escaping fluid from the previous step is converted to obtain the total porosity Φ of the core sample throughout the well section. 总 , Φ 总 =Φ 束缚水 +(Φ 视总孔 -Φ 束缚水 *The porosity correction factor for the escaping fluid is used to determine the apparent total porosity Φ of the core sample throughout the well. 视总孔 and the bound water porosity Φ of the entire well core section 束缚水 Then, the total porosity Φ of the entire well core section can be obtained. 总 .

[0050] Finally, step S104 is executed: determine the apparent total porosity, water saturation, and porosity of each component fluid in the core of the entire well section, and use the apparent total porosity, total porosity, water saturation, and porosity of each component fluid in the core of the entire well section to determine the oil and gas saturation and water cut of the core of the entire well section.

[0051] Furthermore, the hydrocarbon saturation of the entire well core section was determined in the following way: Sog = (Φ 总 -Sw*Φ 视总孔 ) / Φ 总 ; Where Sog represents the hydrocarbon saturation of the entire well core section, and Φ 总 Φ represents the total porosity of the core sample throughout the well, Sw represents the water saturation of the core sample throughout the well, and Φ represents the total porosity of the core sample throughout the well. 视总孔 The apparent total porosity is the core sample from the entire well section.

[0052] Furthermore, the water cut of the entire well core section was determined in the following way: Fw=Φ 可动水 / (Φ 总 -Φ 视总孔 +Φ 可动水 + Φ 视含油气); Where Fw is the water cut of the entire core section, Φ 总 Φ represents the total porosity of the core sample throughout the well. 视总孔 Φ represents the apparent total porosity of the entire core section. 可动水 The movable water porosity of the entire well core section, Φ 视含油气 This represents the apparent oil and gas porosity of the core sample throughout the well.

[0053] Specifically, in this embodiment of the invention, the apparent total porosity Φ of the entire well section core is determined by full-diameter core nuclear magnetic resonance measurement at the well site. 视总孔 Water saturation Sw and fluid porosity (including Φ) 可动水 and Φ 视含油气 Based on the apparent total porosity, total porosity, water saturation, and fluid porosity of the entire well core section, the hydrocarbon saturation and water cut of the entire well core section are determined. The hydrocarbon saturation Sog of the entire well core section = (Φ 总 -Sw*Φ 视总孔 ) / Φ 总 The water content of the core sample throughout the well is Fw = Φ 可动水 / (Φ 总 -Φ 视总孔 +Φ 可动水 + Φ 视含油气 ).

[0054] This invention utilizes rapid NMR measurement of apparent total porosity from full-diameter core samples at the well site, along with T1-T2 spectra, to qualitatively and quantitatively identify fluids and calculate the porosity of each fluid component. Simultaneously, a vacuum-saturated water experiment is conducted on the full-diameter core samples at the well site, followed by NMR measurements. The difference between the porosity measured by vacuum-saturated water and the directly measured porosity is used to compensate for the porosity of escaping oil and gas, thus correcting the total porosity. By combining the results of full-diameter core NMR measurements with vacuum-saturated water NMR measurements, parameters such as total porosity, movable fluid porosity, and water saturation can be effectively calculated. Furthermore, the water cut and oil and gas saturation of the entire reservoir core section can be calculated, quantitatively evaluating the reservoir's oil and gas content and water content. The fluid identification method provided by this invention can correct for escaping fluid porosity, improving the accuracy of measurement results. By quantitatively calculating reservoir water cut and gas saturation, accurate fluid identification and quantitative evaluation are achieved, providing experimental data support for oilfield development plans and recovery rates.

[0055] Please refer to Figure 5 The total porosity measured by vacuum saturated water NMR in this embodiment is compared with the total porosity measured by indoor plunger samples and CMR-NG NMR logging. The results show that the total porosity measured by vacuum saturated water NMR is consistent with the actual detected total porosity and can reflect the original total porosity of the formation.

[0056] Please refer to Figure 6 The total porosity after correction by NMR measurement of the full diameter core at the well site is consistent with the total porosity of CMR-NG NMR logging, indicating that the established porosity correction coefficient model has good applicability.

[0057] Example 1 like Figure 7 As shown, the above method was used to calculate the oil and gas saturation and water cut of the reservoir in well DN2-29H of the Suweiyi Formation. This well is a water-flooded condensate gas reservoir. The calculations revealed that the reservoir Fw in section E2-3s1 of the Suweiyi Formation was <10%, indicating no water flooding and thus an oil and gas layer; while sections E2-3s2 and E2-3s3 had Fw = 65-90%, indicating high water cut reservoirs, and sections with relatively strong and strong water flooding were interpreted as gas-bearing water layers. Oil testing of sections E2-3s1 and E2-3s3 showed them to be condensate gas layers and gas-bearing water layers, respectively, with a 100% agreement rate with the experimental measurement and analysis results, verifying the good applicability of this method.

[0058] Please refer to Figure 8 The second aspect of the present invention provides a fluid identification device, the fluid identification device comprising: a full-diameter core correction coefficient determination module, used to determine the escaping fluid porosity correction coefficients of multiple full-diameter core segments; wherein the escaping fluid porosity correction coefficients of each full-diameter core segment are determined by: determining the apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectra of the full-diameter core, and using the two-dimensional NMR T1-T2 spectra to determine the porosity of each component fluid in the full-diameter core; wherein the porosity of each component fluid includes at least bound water porosity; and using time-lapse NMR measurements of the full-diameter core to determine the two-dimensional NMR T1-T2 spectra. - The fluid distribution range of the T2 spectrum is determined, and the porosity of the bound fluid distribution range of the full-diameter core is determined; wherein, the fluid distribution range includes the escaping fluid distribution range and the bound fluid distribution range; the porosity of the movable fluid in the vacuum saturated water of the full-diameter core is determined by NMR measurement using vacuum saturated water of the full-diameter core; the total porosity of the full-diameter core is determined based on the porosity of the movable fluid in the vacuum saturated water of the full-diameter core and the porosity of the bound fluid distribution range of the full-diameter core; the correction coefficient for the escaping fluid porosity of this section of the full-diameter core is determined based on the total porosity, apparent total porosity, and bound water porosity of the full-diameter core. The porosity correction coefficient model determination module is used to establish a porosity correction coefficient model for the entire well section based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core sections. The total porosity determination module is used to determine the total porosity of the core sample throughout the entire well section based on a porosity correction coefficient model. The fluid quantitative module is used to determine the apparent total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section. It also uses the apparent total porosity, total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section to determine the oil and gas saturation and water cut of the core sample of the entire well section.

[0059] A third aspect of the present invention provides a processor configured to perform the fluid recognition method described above.

[0060] A fourth aspect of the present invention provides a machine-readable storage medium storing instructions that, when executed by a processor, configure the processor to perform the fluid identification method described above.

[0061] The preferred embodiments of the present invention have been described in detail above with reference to the accompanying drawings. However, the present invention is not limited to the specific details of the above embodiments. Within the scope of the technical concept of the present invention, various simple modifications can be made to the technical solution of the present invention, and these simple modifications all fall within the protection scope of the present invention.

[0062] It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. In order to avoid unnecessary repetition, the present invention will not describe the various possible combinations separately.

[0063] Furthermore, various different embodiments of the present invention can be combined in any way, as long as they do not violate the spirit of the present invention, they should also be regarded as the content disclosed by the present invention.

Claims

1. A fluid identification method, characterized in that, The fluid identification method includes: Determine the porosity correction coefficient for escaping fluid in multiple full-diameter core segments; wherein, the porosity correction coefficient for escaping fluid in each full-diameter core segment is determined in the following manner: The apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectra of the full-diameter core were determined, and the porosity of each component fluid in the full-diameter core was determined using the two-dimensional NMR T1-T2 spectra; wherein, the porosity of each component fluid includes at least the porosity of bound water. Using time-lapse nuclear magnetic resonance (NMR) measurements of the full-diameter core, the fluid distribution range of the two-dimensional NMR T1-T2 spectrum was determined, and the porosity of the bound fluid distribution range of the full-diameter core was also determined; wherein, the fluid distribution range includes the escaping fluid distribution range and the bound fluid distribution range; The porosity of movable fluid in vacuum-saturated water in full-diameter cores was determined by using nuclear magnetic resonance (NMR) measurements. The total porosity of the full-diameter core is determined based on the porosity of the vacuum-saturated water movable fluid in the full-diameter core and the porosity of the bound fluid distribution area in the full-diameter core. The escaping fluid porosity correction coefficient for this section of the full-diameter core is determined based on the total porosity, apparent total porosity, and bound water porosity of the full-diameter core. A porosity correction coefficient model for the entire well section was established based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core sections. The total porosity of the core sample in the entire well section is determined based on the porosity correction coefficient model for the entire well section. The apparent total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section were determined. The apparent total porosity, total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section were then used to determine the oil and gas saturation and water cut of the core sample of the entire well section.

2. The fluid identification method according to claim 1, characterized in that, The determination of the apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectra of the full-diameter core includes: Full-diameter core NMR measurements were conducted at the well site to determine the apparent total porosity and two-dimensional NMR T1-T2 spectra of the full-diameter core.

3. The fluid identification method according to claim 1, characterized in that, The determination of fluid porosity of each component in a full-diameter core using two-dimensional nuclear magnetic resonance T1-T2 spectra includes: The fluid saturation of each component was determined using two-dimensional NMR T1-T2 spectra. The porosity of each component fluid is determined based on the fluid saturation of each component and the apparent total porosity.

4. The fluid identification method according to claim 3, characterized in that, The fluid saturation of each component was determined in the following way: ； ； ； wherein Y k is the signal intensity corresponding to the kth fluid in the two-dimensional nuclear magnetic T1-T2 spectrum; P(i, j) is the signal intensity of the coordinate point with T2 being i and T1 being j in the two-dimensional nuclear magnetic T1-T2 spectrum; Y is the total signal intensity of the two-dimensional nuclear magnetic resonance T1-T2 spectrum; S k is the fluid saturation of the kth fluid.

5. The fluid identification method according to claim 1, characterized in that, The porosity of the fluid components in the full-diameter core also includes: movable water porosity and apparent oil and gas porosity.

6. The fluid identification method according to claim 1, characterized in that, The method of determining the fluid distribution range of the two-dimensional NMR T1-T2 spectrum using full-diameter core time-lapse NMR measurements includes: Two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectra were obtained at different times after the core was removed from the core tube using time-lapse NMR measurements of the full-diameter core. Based on the characteristics of the two-dimensional nuclear magnetic resonance T1-T2 spectra at different times after the core is removed from the tube, the variation law of the fluid signal is determined. Based on the variation law of fluid signals, the fluid distribution range of the two-dimensional NMR T1-T2 spectrum was determined.

7. The fluid identification method according to claim 1, characterized in that, The total porosity of a full-diameter core is determined in the following way: Φ 岩总 =Φ 束缚流体 +Φ 抽真空饱和水可动流体 ; wherein Φ 岩总 is the total porosity of the full diameter core, Φ 束缚流体 is the bound fluid distribution interval porosity of the full diameter core, Φ 抽真空饱和水可动流体 is the vacuum-saturated water mobile fluid porosity of the full diameter core.

8. The fluid identification method according to claim 1, characterized in that, The porosity correction factor for the escaping fluid is obtained in the following way: Escaped fluid porosity correction coefficient = (Φ 岩总 -Φ 岩束缚水 ) / (Φ 岩视总孔 -Φ 岩束缚水 ); Where, Φ 岩总 Φ represents the total porosity of the full-diameter core. 岩视总孔 The apparent total porosity of the full-diameter core is Φ. 岩束缚水 This represents the bound water porosity of a full-diameter core sample.

9. The fluid identification method according to claim 1, characterized in that, The total porosity of the entire core sample was obtained in the following way: Φ 总 =Φ 束缚水 +(Φ 视总孔 -Φ 束缚水 * Porosity correction factor for escaping fluid; Where, Φ 总 Φ represents the total porosity of the core sample throughout the well. 视总孔 Φ represents the apparent total porosity of the entire core section. 束缚水 This refers to the bound water porosity of the core sample throughout the entire well.

10. The fluid identification method according to claim 1, characterized in that, The hydrocarbon saturation of the entire well core section was determined using the following method: Sog=(Φ 总 -Sw*Φ 视总孔 ) / F 总 ; Where Sog represents the hydrocarbon saturation of the entire well core section, and Φ 总 Φ represents the total porosity of the core sample throughout the well, Sw represents the water saturation of the core sample throughout the well, and Φ represents the total porosity of the core sample throughout the well. 视总孔 The apparent total porosity is the core sample from the entire well section.

11. The fluid identification method according to claim 1, characterized in that, The water cut of the core sample throughout the well was determined in the following way: Fw=Φ 可动水 / (Φ 总 -F 视总孔 +F 可动水 + F 视含油气 ); Where Fw is the water cut of the entire core section, Φ 总 Φ represents the total porosity of the core sample throughout the well. 视总孔 Φ represents the apparent total porosity of the entire core section. 可动水 The movable water porosity of the entire well core section, Φ 视含油气 This represents the apparent oil and gas porosity of the core sample throughout the well.

12. The fluid identification method according to claim 1, characterized in that, The porosity correction coefficient model for the entire well section, based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core sections, includes: Fit the porosity correction coefficient of the escaping fluid in multiple full-diameter core samples; A porosity correction coefficient model for the entire well section was established based on the fitting results.

13. A fluid identification device, characterized in that, The fluid identification device includes: A full-diameter core correction coefficient determination module is used to determine the escaping fluid porosity correction coefficient for multiple full-diameter core segments. The escaping fluid porosity correction coefficient for each full-diameter core segment is determined as follows: The apparent total porosity and two-dimensional nuclear magnetic resonance (NMR) T1-T2 spectra of the full-diameter core are determined, and the porosity of each component fluid in the full-diameter core is determined using the two-dimensional NMR T1-T2 spectra; wherein the porosity of each component fluid includes at least bound water porosity; the fluid distribution range of the two-dimensional NMR T1-T2 spectra is determined using time-lapse NMR measurements of the full-diameter core, and the... The porosity of the bound fluid distribution range in the full-diameter core is determined; wherein, the fluid distribution range includes the escaping fluid distribution range and the bound fluid distribution range; the porosity of the movable fluid in the vacuum-saturated water of the full-diameter core is determined by NMR measurement using vacuum-saturated water; the total porosity of the full-diameter core is determined based on the movable fluid porosity in the vacuum-saturated water and the porosity of the bound fluid distribution range in the full-diameter core; and the correction coefficient for the escaping fluid porosity of this section of the full-diameter core is determined based on the total porosity, apparent total porosity, and bound water porosity of the full-diameter core. The porosity correction coefficient model determination module is used to establish a porosity correction coefficient model for the entire well section based on the porosity correction coefficient of the escaping fluid from multiple full-diameter core sections. The total porosity determination module is used to determine the total porosity of the core sample throughout the entire well section based on a porosity correction coefficient model. The fluid quantitative module is used to determine the apparent total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section. It also uses the apparent total porosity, total porosity, water saturation, and porosity of each component fluid in the core sample of the entire well section to determine the oil and gas saturation and water cut of the core sample of the entire well section.

14. A processor, characterized in that, It is configured to perform the fluid identification method according to any one of claims 1 to 12.

15. A machine-readable storage medium storing instructions thereon, characterized in that, When executed by a processor, the instruction causes the processor to be configured to perform the fluid identification method according to any one of claims 1 to 12.

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