Reservoir fluid identification method and device, electronic equipment and storage medium

Abstract

The embodiment of the invention discloses a reservoir fluid identification method and device, electronic equipment and a storage medium. The method comprises the following steps: processing a full-diameter rock core of a target interval by adopting a nuclear magnetic resonance sequence in a mode of alternating first waiting time and second waiting time, and determining first transverse relaxation time distribution; applying a pulse gradient magnetic field to the full-diameter rock core, acquiring a first echo signal at a first preset echo interval, and determining a first fluid diffusion coefficient of the full-diameter rock core according to the first preset echo interval and the first transverse relaxation time distribution; determining a second fluid diffusion coefficient of formation water of the target layer section and a third fluid diffusion coefficient of crude oil; the first fluid diffusion coefficient is compared with the second fluid diffusion coefficient and the third fluid diffusion coefficient, and the fluid property of the target layer section reservoir is determined. By adopting the scheme, the precision of the signal-to-noise ratio, the transverse relaxation time distribution and the fluid diffusion coefficient of the small pores can be improved, so that the fluid property identification precision is improved.

Description

Technical Field

[0001] The embodiments of the present invention relate to the fields of petroleum exploration and logging technology, and in particular to a reservoir fluid identification method, device, electronic equipment and storage medium. Background Technology

[0002] Nuclear magnetic resonance (NMR) technology is a novel well site measurement technique that can provide reservoir information independent of lithology, such as porosity, permeability, bound water saturation, and pore distribution, as well as fluid information. Currently, NMR data are derived from laboratory core measurements, full-diameter core measurements at the well site, and NMR logging, providing crucial data for reservoir evaluation and fluid property identification.

[0003] Laboratory core measurements, full-diameter core measurements at the well site, and nuclear magnetic resonance (NMR) logging data primarily rely on the lateral relaxation time T2. The magnitude of T2 directly determines the accuracy of reservoir parameters and the fluid identification accuracy. However, due to the degree of overlap between oil and water signals in the reservoir, one-dimensional NMR data based on T2 is insufficient to obtain oil saturation information. By increasing the diffusion coefficient D and the longitudinal relaxation time T1, two-dimensional NMR data (D-T2 and T1-T2) can be obtained for oil-water signal separation, enabling the calculation of oil saturation. However, due to the low signal-to-noise ratio (SNR) of the NMR data obtained under logging conditions, the combined inversion of D-T2 and T1-T2 distributions is affected by the SNR, resulting in significant errors in fluid identification and low fluid identification accuracy.

[0004] Therefore, how to improve the accuracy of reservoir fluid identification is a technical problem that urgently needs to be solved by those skilled in the art. Summary of the Invention

[0005] This invention provides a reservoir fluid identification method, apparatus, electronic device, and storage medium to improve the measurement accuracy of the fluid diffusion coefficient and to achieve the identification of fluid properties using a high-precision diffusion coefficient.

[0006] In a first aspect, embodiments of the present invention provide a reservoir fluid identification method, comprising:

[0007] Nuclear magnetic resonance sequences were used to process the full-diameter core of the target section in an alternating manner with the first waiting time and the second waiting time to determine the first lateral relaxation time distribution;

[0008] A pulsed gradient magnetic field is applied to the full-diameter core to determine the first echo signal, and the first fluid diffusion coefficient of the full-diameter core is determined based on the first echo signal and the first transverse relaxation time distribution.

[0009] The second transverse relaxation time distribution and the second preset echo interval of the formation water in the target layer are determined, and the second fluid diffusion coefficient of the formation water is determined based on the second transverse relaxation time distribution and the second preset echo interval.

[0010] The third transverse relaxation time distribution and the third preset echo interval of the crude oil in the target layer are determined, and the third fluid diffusion coefficient of the crude oil is determined based on the third transverse relaxation time distribution and the third preset echo interval.

[0011] The first fluid diffusion coefficient is compared with the second and third fluid diffusion coefficients to determine the fluid properties of the target reservoir.

[0012] Secondly, embodiments of the present invention also provide a reservoir fluid identification device, comprising:

[0013] The first transverse relaxation time distribution determination module is used to process the full-diameter core of the target section using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the first transverse relaxation time distribution.

[0014] The first fluid diffusion coefficient determination module is used to apply a pulsed gradient magnetic field to the full-diameter core to determine the first echo signal, and to determine the first fluid diffusion coefficient of the full-diameter core based on the first echo signal and the first transverse relaxation time distribution.

[0015] The second fluid diffusion coefficient determination module is used to determine the second lateral relaxation time distribution and the second preset echo interval of the formation water in the target layer, and to determine the second fluid diffusion coefficient of the formation water based on the second lateral relaxation time distribution and the second preset echo interval.

[0016] The third fluid diffusion coefficient determination module is used to determine the third transverse relaxation time distribution and the third preset echo interval of crude oil in the target layer, and to determine the third fluid diffusion coefficient of crude oil based on the third transverse relaxation time distribution and the third preset echo interval.

[0017] A reservoir fluid property determination module is used to compare a first fluid diffusion coefficient with a second fluid diffusion coefficient and a third fluid diffusion coefficient to determine the fluid properties of the target reservoir section. Thirdly, embodiments of the present invention also provide an electronic device, which includes:

[0018] One or more processors;

[0019] Storage device for storing one or more programs;

[0020] When the one or more programs are executed by the one or more processors, the one or more processors implement the reservoir fluid identification method according to any embodiment of the present invention.

[0021] Fourthly, embodiments of the present invention also provide a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the reservoir fluid identification method described in any embodiment of the present invention.

[0022] This invention provides a method, apparatus, electronic device, and storage medium for reservoir fluid identification. It processes a full-diameter core sample of a target formation using nuclear magnetic resonance (NMR) sequences with alternating first and second waiting times to determine a first transverse relaxation time distribution. A pulsed gradient magnetic field is applied to the full-diameter core sample, and a first echo signal is acquired at a first preset echo interval. Based on the first preset echo interval and the first transverse relaxation time distribution, a first fluid diffusion coefficient of the full-diameter core sample is determined. Based on the determination method of the first fluid diffusion coefficient of the full-diameter core sample, a second fluid diffusion coefficient of formation water and a third fluid diffusion coefficient of crude oil in the target formation are determined. The first fluid diffusion coefficient is compared with the second and third fluid diffusion coefficients to determine the fluid properties of the reservoir in the target formation. By employing echo trains with different waiting times, the signal-to-noise ratio of NMR is improved; by using echo trains with different echo intervals to determine the reservoir fluid diffusion coefficient, the measurement accuracy of the fluid diffusion coefficient is improved, enabling the identification of fluid properties using high-precision diffusion coefficients. Attached Figure Description

[0023] Other features, objects, and advantages of the invention will become more apparent from the following detailed description of non-limiting embodiments with reference to the accompanying drawings. The drawings are for illustrative purposes only and are not intended to limit the invention. Furthermore, the same reference numerals denote the same parts throughout the drawings. In the drawings:

[0024] Figure 1 This is a flowchart of a reservoir fluid identification method provided in an embodiment of the present invention;

[0025] Figure 2 This is a flowchart of another reservoir fluid identification method provided in this embodiment of the invention;

[0026] Figure 3 This is a schematic diagram of the spectrum of a nuclear magnetic resonance pulse sequence provided in an embodiment of the present invention;

[0027] Figure 4 This is a schematic diagram of a lateral relaxation time distribution concave point splicing provided in an embodiment of the present invention:

[0028] Figure 5 This is a schematic diagram of a multi-echo interval nuclear magnetic resonance acquisition provided in an embodiment of the present invention;

[0029] Figure 6 This is a schematic diagram of the reservoir lateral relaxation time distribution and fluid diffusion coefficient provided in an embodiment of the present invention;

[0030] Figure 7 This is a schematic diagram of the structure of a reservoir fluid identification device provided in an embodiment of the present invention;

[0031] Figure 8 This is a schematic diagram of the structure of an electronic device provided in an embodiment of the present invention. Detailed Implementation

[0032] The present invention will now be described in further detail with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are merely illustrative of the invention and not intended to limit it. Furthermore, it should be noted that, for ease of description, the accompanying drawings show only the parts relevant to the present invention, and not all of the structures.

[0033] Before discussing the exemplary embodiments in more detail, it should be mentioned that some exemplary embodiments are described as processes or methods depicted as flowcharts. Although the flowcharts describe the operations (or steps) as sequential processes, many of the operations (or steps) may be performed in parallel, concurrently, or simultaneously. Furthermore, the order of the operations may be rearranged. The process may be terminated when its operation is completed, but may also have additional steps not included in the figures. The process may correspond to a method, function, procedure, subroutine, subroutine, etc.

[0034] The acquisition, storage, use, and processing of data in the technical solution of this application all comply with the relevant provisions of national laws and regulations.

[0035] Figure 1 This is a flowchart of a reservoir fluid identification method provided in an embodiment of the present invention. This embodiment is applicable to the identification of reservoir fluids. The method of this embodiment can be executed by a reservoir fluid identification device, which can be implemented in hardware and / or software. This device can be configured in a reservoir fluid identification server. The method specifically includes the following steps:

[0036] S110. Nuclear magnetic resonance sequences were used to process the full-diameter core of the target section in an alternating manner with the first waiting time and the second waiting time to determine the first lateral relaxation time distribution.

[0037] Full-diameter cores are columnar cores extracted from oil and gas reservoirs without cutting or splitting, used entirely in the laboratory for analysis and parameter determination. Full-diameter cores are characterized by multi-scale and continuous characteristics, facilitating non-destructive testing of large-diameter core samples, effectively preserving their original state, and ensuring their utilization rate in subsequent research and exploration.

[0038] Nuclear magnetic resonance (NMR) sequences, by applying combined pulses, cause the NMR signal to invert back and forth within a time range to maintain the original NMR signal intensity as much as possible, thereby achieving shorter relaxation information acquisition and improving the accuracy of crosslinking degree testing. The primary NMR acquisition mode is the NMR sequence. The main steps for obtaining the transverse relaxation time (T2) distribution using Car Purcell Meiboom Gill (CPMG) sequences are: first, ensuring complete magnetization of the sample over a relatively long period; then, using 90-degree pulses to flip the magnetization vector in the Z-direction onto the XY plane, followed by a series of 180-degree pulses; obtaining echo signals between adjacent 180-degree pulses, and combining all echo signals into an echo train for inversion processing to obtain the T2 distribution; this sequence is called a CPMG pulse sequence. The sample magnetization time (wait time, TW) is constant, and the echo interval between the two 180-degree pulses required for acquisition is constant. The CPMG sequence can provide the original echo train signal, whose amplitude decays exponentially with time. The transverse relaxation time T2 can be obtained by data inversion using the original echo train.

[0039] The first waiting time and the second waiting time are different. In this embodiment of the invention, the first waiting time can be a long waiting time, such as 3 seconds; the second waiting time can be a short waiting time, such as 10 ms. In this embodiment of the invention, the first waiting time is used to obtain the echo train signal of the large-pore reservoir, and the second waiting time is used to obtain the echo train of the small-pore reservoir, thereby improving the signal-to-noise ratio of nuclear magnetic resonance and thus improving the accuracy of fluid property identification.

[0040] In this embodiment of the invention, nuclear magnetic resonance (NMR) sequences are used to process the full-diameter core of the target layer with alternating first and second waiting times to determine the first transverse relaxation time distribution. For example, an NMR sequence with a 3-second waiting time is first used to process the full-diameter core of the target layer, followed by an NMR sequence with a 10-ms waiting time, to finally determine the first transverse relaxation time distribution of the full-diameter core.

[0041] S120. Apply a pulsed gradient magnetic field to the full-diameter core and acquire the first echo signal at a first preset echo interval. Determine the first fluid diffusion coefficient of the full-diameter core based on the first preset echo interval and the first transverse relaxation time distribution.

[0042] The gradient magnetic field can be generated by several coils located inside the magnet cavity through the current, and added to the main magnetic field. It can increase or decrease the strength of the main magnetic field, so that the spin protons along the gradient direction have different magnetic field strengths, and thus have different types of resonance frequencies.

[0043] An echo signal can refer to a signal transmitted by the transmitting end during communication, received at the receiving end, and reflected back to the transmitting end. For example, when a pulsed gradient magnetic field is applied to a full-diameter core, the magnetic signal transmitted to the core and reflected back to the transmitting end is used as an echo signal. The echo interval can refer to the time interval between two adjacent echoes acquired during a single radio frequency pulse excitation.

[0044] The fluid diffusion coefficient can be a physical quantity that refers to the degree of diffusion of gas or solid. In this embodiment of the invention, it refers to the migration rate of gas or liquid molecules between different locations in the reservoir.

[0045] In this embodiment of the invention, a pulsed gradient magnetic field is applied to the full-diameter core, and a first echo signal is determined using a first preset echo interval. The first fluid diffusion coefficient of the full-diameter core is then determined based on the first echo signal and the determined first transverse relaxation time distribution.

[0046] S130. Determine the second transverse relaxation time distribution and the second preset echo interval of the formation water in the target layer, and determine the second fluid diffusion coefficient of the formation water based on the second transverse relaxation time distribution and the second preset echo interval.

[0047] The formation water in the target section can refer to the formation water belonging to the same target section as the full-diameter core. The formation water can be the formation water in the target section of this well or the formation water in the target section of an adjacent well.

[0048] In this embodiment of the invention, the method for obtaining the second fluid diffusion coefficient of formation water is the same as the method for obtaining the first fluid diffusion coefficient of a full-diameter core. Both require obtaining the lateral relaxation time distribution and the preset echo interval, and determining the fluid diffusion coefficient based on the lateral relaxation time distribution and the preset echo interval.

[0049] It is understandable that the first lateral relaxation time distribution can be used metaphorically to distinguish different lateral relaxation time distributions that appear before and after the corresponding logic in the embodiments. Any lateral relaxation time distribution selected from these distributions is used to illustrate the execution logic. Therefore, the lateral relaxation time distribution appearing for the first time in this document is called the first lateral relaxation time distribution, and other lateral relaxation time distributions that appear later and differ from the first lateral relaxation time distribution are called the second lateral relaxation time distributions, which will not be elaborated further. The same applies to the first preset echo interval, the first echo signal, and the first fluid diffusion coefficient.

[0050] S140. Determine the third transverse relaxation time distribution and the third preset echo interval of the crude oil in the target layer, and determine the third fluid diffusion coefficient of the crude oil based on the third transverse relaxation time distribution and the third preset echo interval.

[0051] The target layer crude oil can refer to crude oil belonging to the same target layer as the full-diameter core. The crude oil can be crude oil from the target layer of this well or crude oil from the target layer of an adjacent well.

[0052] In this embodiment of the invention, the method for obtaining the third fluid diffusion coefficient of crude oil is the same as the method for obtaining the first fluid diffusion coefficient of a full-diameter core. Both require obtaining the transverse relaxation time distribution and the preset echo interval, and determining the fluid diffusion coefficient based on the transverse relaxation time distribution and the preset echo interval.

[0053] S150. The first fluid diffusion coefficient is compared with the second fluid diffusion coefficient and the third fluid diffusion coefficient to determine the fluid properties of the target reservoir.

[0054] In this embodiment of the invention, the oil and water content in the target reservoir are determined by the fluid properties. The fluid properties of the target reservoir include, but are not limited to, water layers, oil-water layers, oil-water co-layers, and oil layers.

[0055] The fluid diffusion coefficients of the determined full-diameter cores are compared with those of formation water and crude oil to determine the fluid properties of the target reservoir.

[0056] This invention provides a reservoir fluid identification method. It involves processing a full-diameter core sample of a target formation using nuclear magnetic resonance (NMR) sequences with alternating first and second waiting times to determine a first transverse relaxation time distribution. A pulsed gradient magnetic field is applied to the full-diameter core sample, and a first echo signal is acquired at a first preset echo interval. A first fluid diffusion coefficient of the full-diameter core sample is determined based on the first preset echo interval and the first transverse relaxation time distribution. A second transverse relaxation time distribution and a second preset echo interval for formation water in the target formation are determined, and a second fluid diffusion coefficient for formation water is determined based on the second transverse relaxation time distribution and the second preset echo interval. A third transverse relaxation time distribution and a third preset echo interval for crude oil in the target formation are determined, and a third fluid diffusion coefficient for crude oil is determined based on the third transverse relaxation time distribution and the third preset echo interval. The first fluid diffusion coefficient is compared with the second and third fluid diffusion coefficients to determine the fluid properties of the reservoir in the target formation. The technical solution of this invention uses echo trains with different waiting times to improve the signal-to-noise ratio of nuclear magnetic resonance; it uses echo trains with different echo intervals to determine the reservoir fluid diffusion coefficient, thereby improving the measurement accuracy of the diffusion coefficient and realizing the discrimination of fluid properties using a high-precision diffusion coefficient.

[0057] Figure 2This is a flowchart of another reservoir fluid identification method provided in an embodiment of the present invention. The embodiments of the present invention further optimize the aforementioned embodiments, and can be combined with various optional solutions from one or more of the above embodiments. For example... Figure 2 As shown, the reservoir fluid identification method provided in this embodiment of the invention may include the following steps:

[0058] S210. Nuclear magnetic resonance sequences were used to process the full-diameter core of the target section in an alternating manner with the first waiting time and the second waiting time to determine the first lateral relaxation time distribution.

[0059] In this embodiment of the invention, a first waiting time is used, with the minimum resolution of the NMR sequence as the step size, to measure the first echo train signal obtained under the first waiting time; and a second waiting time is used alternately to obtain the second echo train signal; the first echo train signal and the second echo train signal are spliced ​​together to obtain the first transverse relaxation time distribution. The first waiting time can refer to a long waiting time greater than a first preset time threshold, such as a waiting time greater than 3 seconds; the second waiting time can refer to a short waiting time less than a second preset time threshold, such as a waiting time less than 10 ms.

[0060] As an optional but non-limiting implementation, the method of processing the full-diameter core of the target section using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the first transverse relaxation time distribution includes, but is not limited to, steps A1-A3:

[0061] Step A1: Perform nuclear magnetic resonance processing on the full-diameter core of the target section using a nuclear magnetic resonance sequence with a first waiting time to obtain the first echo train signal.

[0062] Step A2: Perform nuclear magnetic resonance processing on the full-diameter core of the target section using a nuclear magnetic resonance sequence with a second waiting time to obtain the second echo train signal.

[0063] Step A3: Perform concave splicing on the first echo train signal and the second echo train signal to obtain the first transverse relaxation time distribution of the full-diameter core; wherein, the second waiting time is less than the first waiting time.

[0064] Taking a first waiting time of 3 seconds and a second waiting time of 10 ms as an example, based on the minimum resolution of the NMR sequence, the CPMG pulse sequence is used to measure the NMR information of the entire diameter core segment by alternating between the first and second waiting times, based on the step size measurement of the first and second waiting times, and the minimum resolution of the NMR sequence. The CPMG pulse sequence obtained by alternating between the first and second waiting times is as follows: Figure 3As shown, the first echo train signal obtained based on the first waiting time and the second echo train signal obtained based on the second waiting time are spliced ​​together to obtain the full-diameter transverse relaxation time T2 distribution.

[0065] In one optional embodiment of the present invention, the T2 spectrum is calculated using a first waiting time and a second waiting time, respectively. The T2 spectrum with the second waiting time mainly reflects the small aperture signal, while the T2 spectrum with the first waiting time mainly measures the large aperture signal. Figure 4 As shown, the horizontal axis represents the size of the T2 region, and the vertical axis represents the amplitude of the T2 spectrum. The blue line represents the T2 spectrum acquired during the second waiting time, and the green line represents the T2 spectrum acquired during the first waiting time. In regions with smaller T2 values, the amplitude of the T2 spectrum acquired during the second waiting time is initially greater than that acquired during the first waiting time. As the T2 value increases, the amplitude of the T2 spectrum acquired during the first waiting time becomes greater than that acquired during the second waiting time. A "concave point" is formed at the position where the amplitude of the T2 spectrum acquired during the first waiting time equals that acquired during the second waiting time. The concave point splicing method refers to taking the T2 amplitude acquired during the second waiting time as the value smaller than the concave point, and taking the T2 amplitude acquired during the first waiting time as the value larger than the concave point.

[0066] As an optional but non-limiting implementation, nuclear magnetic resonance (NMR) sequences are used to process the full-diameter core of the target section with a second waiting time to obtain a second echo train signal, including but not limited to steps B1-B2:

[0067] Step B1: Repeat the measurement of the echo train signal of the full diameter core of the target section at the second waiting time until the preset number of measurements is met.

[0068] Step B2: Determine the echo train signal obtained from repeated measurements, and superimpose the echo train signals obtained from repeated measurements to obtain the second echo train signal.

[0069] In addressing the issue of weak signals and low signal-to-noise ratio (SNR) in small-aperture NMR, this embodiment employs multiple second-time measurements to ensure a sufficiently high SNR for the echo train of the short-relaxation signal. For example, after a first-time measurement, multiple measurements are performed using the second-time method until a preset number of measurements is met, such as 20-50 repetitions. The echo train signals obtained from these repeated measurements are then superimposed to obtain the second echo train signal, thereby improving both the small-aperture NMR signal and its SNR.

[0070] S220. Apply a pulsed gradient magnetic field to the full-diameter core and acquire the first echo signal at a first preset echo interval. Determine the first fluid diffusion coefficient of the full-diameter core based on the first preset echo interval and the first transverse relaxation time distribution.

[0071] The first preset echo interval can refer to acquiring the first echo signal at an echo interval that is 2, 4, 8, or 16 times the minimum echo interval. For example, if the minimum echo interval is 0.2 ms, the corresponding first preset echo intervals could be 0.4 ms, 0.8 ms, 1.6 ms, and 3.2 ms. The first fluid diffusion coefficient of the full-diameter core is determined using different first preset echo intervals and a determined first transverse relaxation time distribution.

[0072] As an optional but non-limiting implementation, a pulsed gradient magnetic field is applied to the full-diameter core, and a first echo signal is acquired at a first preset echo interval. The first fluid diffusion coefficient of the full-diameter core is determined based on the first preset echo interval and the first transverse relaxation time distribution, including but not limited to steps C1-C3:

[0073] Step C1: Apply a pulsed gradient magnetic field to the full-diameter core using a gradient coil, and collect the first echo signal of the full-diameter core according to at least two first preset echo intervals.

[0074] Step C2: Determine at least two fluid diffusion coefficients for the full-diameter core based on the at least two first preset echo intervals and the determined first transverse relaxation time distribution.

[0075] Step C3: Preprocess the at least two fluid diffusion coefficients to obtain the first fluid diffusion coefficient of the full-diameter core; the preprocessing includes least squares processing.

[0076] In this method, a pulsed gradient magnetic field was applied to the full-diameter core using gradient coils. The first four echoes were acquired using a first preset echo interval of 2, 4, 8, and 16 times the minimum echo interval (0.4 ms, 0.8 ms, 1.6 ms, and 3.2 ms, respectively), with the minimum resolution of the nuclear magnetic resonance sequence as the step size. (See appendix.) Figure 5 As shown. The first transverse relaxation time distribution obtained in step S210 is used for data inversion to obtain the fluid diffusion coefficient of the full-diameter core. See [link / reference]. Figure 6 The left side shows the lateral relaxation time distribution, and the right side shows the fluid diffusion coefficient obtained from data inversion. The data inversion formula can be expressed as:

[0077]

[0078] Where T2 is the transverse relaxation time; T E γ is the preset echo interval; γ is the gyromagnetic ratio, a constant; G is the magnetic field gradient; D is the fluid diffusion coefficient.

[0079] Different fluid diffusion coefficients can be obtained based on different first preset echo intervals. The obtained multiple fluid diffusion coefficients are preprocessed to obtain the first fluid diffusion coefficient of the full-diameter core. The preprocessing includes, but is not limited to, calculating the least squares method, taking the mean, and taking the variance of the multiple fluid diffusion coefficients.

[0080] S230. Determine the second transverse relaxation time distribution and the second preset echo interval of the formation water in the target layer, and determine the second fluid diffusion coefficient of the formation water based on the second transverse relaxation time distribution and the second preset echo interval.

[0081] In this process, formation water samples are obtained from the target layer of the well or adjacent well. Steps S210 and S220 are repeated to obtain the second lateral relaxation time distribution and the second fluid diffusion coefficient of the formation water samples.

[0082] As an optional but non-limiting implementation, the second lateral relaxation time distribution and the second preset echo interval of the formation water in the target layer are determined, and the second fluid diffusion coefficient of the formation water is determined based on the second lateral relaxation time distribution and the second preset echo interval, including but not limited to steps D1-D2:

[0083] Step D1: The formation water in the target section is processed using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the second lateral relaxation time distribution.

[0084] Step D2: Apply a pulsed gradient magnetic field to the formation water and acquire a second echo signal at a second preset echo interval. Determine the second fluid diffusion coefficient of the formation water based on the second preset echo interval and the second transverse relaxation time distribution.

[0085] Specifically, nuclear magnetic resonance (NMR) processing is performed on the formation water in the target layer using alternating first and second waiting times to determine the second transverse relaxation time distribution of the formation water. A pulsed gradient magnetic field is applied to the formation water, and a second echo signal is acquired at a second preset echo interval. The second fluid diffusion coefficient of the formation water is determined based on the second preset echo interval and the second transverse relaxation time distribution. The second preset echo interval can be the same as the first preset echo interval, i.e., 2, 4, 8, or 16 times the minimum echo interval.

[0086] S240. Determine the third transverse relaxation time distribution and the third preset echo interval of the crude oil in the target layer, and determine the third fluid diffusion coefficient of the crude oil based on the third transverse relaxation time distribution and the third preset echo interval.

[0087] Specifically, crude oil samples from the target formation of this well or adjacent wells are obtained, and steps S210 and S220 are repeated to obtain the third lateral relaxation time distribution and the third fluid diffusion coefficient of the crude oil samples.

[0088] As an optional but non-limiting implementation, the determination of the third transverse relaxation time distribution and the third preset echo interval of the crude oil in the target layer, and the determination of the third fluid diffusion coefficient of the crude oil based on the third transverse relaxation time distribution and the third preset echo interval, includes, but is not limited to, steps E1-E2:

[0089] Step E1: The crude oil in the target layer is processed using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the third lateral relaxation time distribution.

[0090] Step E2: Apply a pulse gradient magnetic field to the crude oil and obtain the third echo signal at the third preset echo interval. Determine the third fluid diffusion coefficient of the crude oil based on the third preset echo interval and the third transverse relaxation time distribution.

[0091] Specifically, nuclear magnetic resonance (NMR) processing is performed on the target layer crude oil using alternating first and second waiting times to determine the third transverse relaxation time distribution of the crude oil. A pulsed gradient magnetic field is applied to the crude oil, and a third echo signal is acquired at a third preset echo interval. The third fluid diffusion coefficient of the crude oil is determined based on the third preset echo interval and the third transverse relaxation time distribution. The third preset echo interval can be the same as the first preset echo interval, i.e., 2, 4, 8, or 16 times the minimum echo interval.

[0092] S250. The first fluid diffusion coefficient is compared with the second fluid diffusion coefficient and the third fluid diffusion coefficient to determine the fluid properties of the target reservoir.

[0093] The first fluid diffusion coefficient of the full-diameter core is compared with the third fluid diffusion coefficient of the crude oil and the second fluid diffusion coefficient of the formation water to determine the fluid properties of the reservoir in the target section where the full-diameter core is located.

[0094] As an optional but non-limiting implementation, the first fluid diffusion coefficient is compared with the second and third fluid diffusion coefficients respectively to determine the fluid properties of the target reservoir, including but not limited to steps F1-F4:

[0095] Step F1: If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is less than the first preset threshold, then the fluid property of the target reservoir is determined to be an aqueous layer.

[0096] Step F2: If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is greater than the first preset threshold and less than the second preset threshold, then the fluid properties of the target reservoir are determined to be an oil-water layer.

[0097] Step F3: If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is greater than the second preset threshold, and the ratio of the first fluid diffusion coefficient to the third fluid diffusion coefficient is greater than the third preset threshold, then the fluid properties of the target layer reservoir are determined to be oil-water co-layer.

[0098] Step F4: If the ratio of the first fluid diffusion coefficient to the third fluid diffusion coefficient is less than the third preset threshold, then the fluid properties of the target reservoir are determined to be oil.

[0099] Taking a first preset threshold of 2, a second preset threshold of 5, and a third preset threshold of 2 as examples, if the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is less than the first preset threshold, then the fluid property of the target reservoir is determined to be an aqueous layer, which can be expressed as:

[0100]

[0101] Where D represents the first fluid diffusion coefficient, D W This represents the second fluid diffusion coefficient.

[0102] If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is greater than a first preset threshold and less than a second preset threshold, then the fluid properties of the target reservoir are determined to be an oil-water-bearing layer, which can be expressed as:

[0103]

[0104] If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is greater than a second preset threshold, and the ratio of the first fluid diffusion coefficient to the third fluid diffusion coefficient is greater than a third preset threshold, then the fluid properties of the target reservoir are determined to be oil-water co-layers, which can be expressed as:

[0105] and

[0106] Among them, D O This represents the third fluid diffusion coefficient.

[0107] If the ratio of the first fluid diffusion coefficient to the third fluid diffusion coefficient is less than a third preset threshold, then the fluid properties of the target reservoir are determined to be oil, which can be expressed as:

[0108]

[0109] In one optional embodiment of the present invention, referring to Table 1, the fluid diffusion coefficient of reservoir number 1 is greater than 5 with that of formation water, but less than 2 with that of crude oil; therefore, reservoir number 1 is an oil layer. The fluid diffusion coefficient of reservoir number 2 is greater than 5 with that of formation water and greater than 2 with that of crude oil; therefore, reservoir number 2 is an oil-water co-layer. The fluid diffusion coefficient of reservoir number 3 is less than 2 with that of formation water; therefore, reservoir number 3 is a water layer.

[0110] Table 1 Statistical Table of Fluid Property Results

[0111]

[0112]

[0113] This invention provides a reservoir fluid identification method. It involves processing a full-diameter core sample of a target formation using nuclear magnetic resonance (NMR) sequences with alternating first and second waiting times to determine a first transverse relaxation time distribution. A pulsed gradient magnetic field is applied to the full-diameter core sample, and a first echo signal is acquired at a first preset echo interval. A first fluid diffusion coefficient of the full-diameter core sample is determined based on the first preset echo interval and the first transverse relaxation time distribution. A second transverse relaxation time distribution and a second preset echo interval for formation water in the target formation are determined, and a second fluid diffusion coefficient for formation water is determined based on the second transverse relaxation time distribution and the second preset echo interval. A third transverse relaxation time distribution and a third preset echo interval for crude oil in the target formation are determined, and a third fluid diffusion coefficient for crude oil is determined based on the third transverse relaxation time distribution and the third preset echo interval. The first fluid diffusion coefficient is compared with the second and third fluid diffusion coefficients to determine the fluid properties of the reservoir in the target formation. The technical solution of this invention uses echo trains acquired with a second waiting time, which can improve the signal-to-noise ratio of small pores, thereby improving the accuracy of the transverse relaxation time distribution. Using echo trains with different echo intervals to determine the reservoir fluid diffusion coefficient improves the measurement accuracy of the fluid diffusion coefficient, providing a basis for reservoir evaluation and fluid property identification accuracy.

[0114] Figure 7 This is a schematic diagram of a reservoir fluid identification device provided in an embodiment of the present invention. The technical solution of this embodiment is applicable to reservoir fluid identification. The device can be implemented by software and / or hardware and is generally integrated into any electronic device with network communication capabilities, including but not limited to: servers, computers, personal digital assistants, etc. Figure 7As shown, the reservoir fluid identification device provided in this embodiment may include: a first transverse relaxation time distribution determination module 610, a first fluid diffusion coefficient determination module 620, a second fluid diffusion coefficient determination module 630, a third fluid diffusion coefficient determination module 640, and a reservoir fluid property determination module 650; wherein,

[0115] The first transverse relaxation time distribution determination module 610 is used to process the full-diameter core of the target section using nuclear magnetic resonance sequences in an alternating manner of first waiting time and second waiting time to determine the first transverse relaxation time distribution.

[0116] The first fluid diffusion coefficient determination module 620 is used to apply a pulsed gradient magnetic field to the full-diameter core and acquire a first echo signal with a first preset echo interval, and determine the first fluid diffusion coefficient of the full-diameter core according to the first preset echo interval and the first transverse relaxation time distribution.

[0117] The second fluid diffusion coefficient determination module 630 is used to determine the second lateral relaxation time distribution and the second preset echo interval of the formation water in the target layer, and to determine the second fluid diffusion coefficient of the formation water based on the second lateral relaxation time distribution and the second preset echo interval.

[0118] The third fluid diffusion coefficient determination module 640 is used to determine the third transverse relaxation time distribution and the third preset echo interval of the crude oil in the target layer, and to determine the third fluid diffusion coefficient of the crude oil based on the third transverse relaxation time distribution and the third preset echo interval.

[0119] The reservoir fluid property determination module 650 is used to compare the first fluid diffusion coefficient with the second fluid diffusion coefficient and the third fluid diffusion coefficient to determine the fluid properties of the target reservoir.

[0120] Based on the above embodiments, optionally, the first lateral relaxation time distribution determination module specifically includes:

[0121] Nuclear magnetic resonance (NMR) sequences were used to process the full-diameter core of the target section at the first waiting time to obtain the first echo train signal.

[0122] Nuclear magnetic resonance (NMR) sequences were used to process the full-diameter core of the target section at the second waiting time to obtain the second echo train signal.

[0123] The first echo train signal and the second echo train signal are spliced ​​together with concave dots to obtain the first transverse relaxation time distribution of the full-diameter core; wherein, the second waiting time is less than the first waiting time.

[0124] Based on the above embodiments, optionally, the first lateral relaxation time distribution determination module is further specifically used for:

[0125] The echo train signal of the full diameter core of the target section is repeatedly measured during the second waiting time until the preset number of measurements is met.

[0126] The echo train signals obtained from repeated measurements are determined, and the echo train signals obtained from repeated measurements are superimposed to obtain the second echo train signal.

[0127] Based on the above embodiments, optionally, the first fluid diffusion coefficient determining module is specifically used for:

[0128] A pulsed gradient magnetic field was applied to the full-diameter core using a gradient coil, and the first echo signal of the full-diameter core was acquired according to at least two first preset echo intervals.

[0129] At least two fluid diffusion coefficients of the full-diameter core are determined based on the at least two first preset echo intervals and the determined first transverse relaxation time distribution.

[0130] The first fluid diffusion coefficient of the full-diameter core is obtained by preprocessing the at least two fluid diffusion coefficients; the preprocessing includes least squares processing.

[0131] Based on the above embodiments, optionally, the second fluid diffusion coefficient determining module is specifically used for:

[0132] The formation water in the target layer was processed using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the second lateral relaxation time distribution;

[0133] A pulsed gradient magnetic field is applied to the formation water and a second echo signal is acquired at a second preset echo interval. The second fluid diffusion coefficient of the formation water is determined based on the second preset echo interval and the second transverse relaxation time distribution.

[0134] Based on the above embodiments, optionally, the third fluid diffusion coefficient determining module is specifically used for:

[0135] The target layer crude oil was processed using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the third transverse relaxation time distribution;

[0136] A pulse gradient magnetic field is applied to the crude oil to determine the third echo signal, and the third echo signal is obtained at a third preset echo interval. The third fluid diffusion coefficient of the crude oil is determined based on the third preset echo interval and the third transverse relaxation time distribution.

[0137] Based on the above embodiments, optionally, the reservoir fluid property determination module is specifically used for:

[0138] If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is less than the first preset threshold, then the fluid property of the target reservoir is determined to be an aqueous layer.

[0139] If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is greater than the first preset threshold and less than the second preset threshold, then the fluid properties of the target reservoir are determined to be an oil-water layer.

[0140] If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is greater than the second preset threshold, and the ratio of the first fluid diffusion coefficient to the third fluid diffusion coefficient is greater than the third preset threshold, then the fluid properties of the target layer reservoir are determined to be oil-water co-layer.

[0141] If the ratio of the first fluid diffusion coefficient to the third fluid diffusion coefficient is less than the third preset threshold, then the fluid properties of the target reservoir are determined to be oil.

[0142] The reservoir fluid identification device provided in the embodiments of the present invention can execute the reservoir fluid identification method provided in any of the embodiments of the present invention, and has the corresponding functions and beneficial effects of executing the reservoir fluid identification method. For details, please refer to the relevant operations of the reservoir fluid identification method in the foregoing embodiments.

[0143] Figure 8 This is a schematic diagram of the structure of an electronic device provided in an embodiment of the present invention. The electronic device 10 is intended to represent various forms of digital computers, such as laptop computers, desktop computers, workstations, personal digital assistants, servers, blade servers, mainframe computers, and other suitable computers. The electronic device may also represent various forms of mobile devices, such as personal digital processors, cellular phones, smartphones, wearable devices (such as helmets, glasses, watches, etc.), and other similar computing devices. The components shown herein, their connections and relationships, and their functions are merely illustrative and are not intended to limit the implementation of the invention described and / or claimed herein.

[0144] like Figure 8As shown, the electronic device 10 includes at least one processor 11 and a memory, such as a read-only memory (ROM) 12 or a random access memory (RAM) 13, communicatively connected to the at least one processor 11. The memory stores computer programs executable by the at least one processor. The processor 11 can perform various appropriate actions and processes based on the computer program stored in the ROM 12 or loaded from storage unit 18 into the RAM 13. The RAM 13 may also store various programs and data required for the operation of the electronic device 10. The processor 11, ROM 12, and RAM 13 are interconnected via a bus 14. An input / output (I / O) interface 15 is also connected to the bus 14.

[0145] Multiple components in electronic device 10 are connected to I / O interface 15, including: input unit 16, such as keyboard, mouse, etc.; output unit 17, such as various types of displays, speakers, etc.; storage unit 18, such as disk, optical disk, etc.; and communication unit 19, such as network card, modem, wireless transceiver, etc. Communication unit 19 allows electronic device 10 to exchange information / data with other devices through computer networks such as the Internet and / or various telecommunications networks.

[0146] Processor 11 can be a variety of general-purpose and / or special-purpose processing components with processing and computing capabilities. Some examples of processor 11 include, but are not limited to, a central processing unit (CPU), a graphics processing unit (GPU), various special-purpose artificial intelligence (AI) computing chips, various processors running machine learning model algorithms, a digital signal processor (DSP), and any suitable processor, controller, microcontroller, etc. Processor 11 performs the various methods and processes described above, such as reservoir fluid identification methods.

[0147] In some embodiments, the reservoir fluid identification method may be implemented as a computer program tangibly contained in a computer-readable storage medium, such as storage unit 18. In some embodiments, part or all of the computer program may be loaded and / or mounted on electronic device 10 via ROM 12 and / or communication unit 19. When the computer program is loaded into RAM 13 and executed by processor 11, one or more steps of the reservoir fluid identification method described above may be performed. Alternatively, in other embodiments, processor 11 may be configured to perform the reservoir fluid identification method by any other suitable means (e.g., by means of firmware).

[0148] Various embodiments of the systems and techniques described above herein can be implemented in digital electronic circuit systems, integrated circuit systems, field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), application-specific standard products (ASSPs), systems-on-a-chip (SoCs), payload-programmable logic devices (CPLDs), computer hardware, firmware, software, and / or combinations thereof. These various embodiments may include implementations in one or more computer programs that can be executed and / or interpreted on a programmable system including at least one programmable processor, which may be a dedicated or general-purpose programmable processor, capable of receiving data and instructions from a storage system, at least one input device, and at least one output device, and transmitting data and instructions to the storage system, the at least one input device, and the at least one output device.

[0149] Computer programs used to implement the methods of the present invention may be written in any combination of one or more programming languages. These computer programs may be provided to a processor of a general-purpose computer, a special-purpose computer, or other programmable data processing device, such that when executed by the processor, the computer programs cause the functions / operations specified in the flowcharts and / or block diagrams to be performed. The computer programs may be executed entirely on a machine, partially on a machine, or as a standalone software package, partially on a machine and partially on a remote machine, or entirely on a remote machine or server.

[0150] In the context of this invention, a computer-readable storage medium can be a tangible medium that may contain or store a computer program for use by or in conjunction with an instruction execution system, apparatus, or device. A computer-readable storage medium may include, but is not limited to, electronic, magnetic, optical, electromagnetic, infrared, or semiconductor systems, apparatus, or devices, or any suitable combination thereof. Alternatively, a computer-readable storage medium may be a machine-readable signal medium. More specific examples of machine-readable storage media include electrical connections based on one or more wires, portable computer disks, hard disks, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), optical fibers, portable compact disk read-only memory (CD-ROM), optical storage devices, magnetic storage devices, or any suitable combination thereof.

[0151] To provide interaction with a user, the systems and techniques described herein can be implemented on an electronic device having: a display device (e.g., a CRT (cathode ray tube) or LCD (liquid crystal display) monitor) for displaying information to the user; and a keyboard and pointing device (e.g., a mouse or trackball) through which the user provides input to the electronic device. Other types of devices can also be used to provide interaction with the user; for example, feedback provided to the user can be any form of sensory feedback (e.g., visual feedback, auditory feedback, or tactile feedback); and input from the user can be received in any form (including sound input, voice input, or tactile input).

[0152] The systems and technologies described herein can be implemented in computing systems that include backend components (e.g., as data servers), or computing systems that include middleware components (e.g., application servers), or computing systems that include frontend components (e.g., user computers with graphical user interfaces or web browsers through which users can interact with implementations of the systems and technologies described herein), or any combination of such backend, middleware, or frontend components. The components of the system can be interconnected via digital data communication of any form or medium (e.g., communication networks). Examples of communication networks include local area networks (LANs), wide area networks (WANs), blockchain networks, and the Internet.

[0153] A computing system can include clients and servers. Clients and servers are generally located far apart and typically interact through a communication network. The client-server relationship is created by computer programs running on the respective computers and having a client-server relationship with each other. The server can be a cloud server, also known as a cloud computing server or cloud host, which is a hosting product within the cloud computing service system to address the shortcomings of traditional physical hosts and VPS services, such as high management difficulty and weak business scalability.

[0154] It should be understood that the various forms of processes shown above can be used, with steps reordered, added, or deleted. For example, the steps described in this invention can be executed in parallel, sequentially, or in different orders, as long as the desired result of the technical solution of this invention can be achieved, and this is not limited herein.

[0155] The specific embodiments described above do not constitute a limitation on the scope of protection of this invention. Those skilled in the art should understand that various modifications, combinations, sub-combinations, and substitutions can be made according to design requirements and other factors. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of this invention should be included within the scope of protection of this invention.

Claims

1. A method for identifying reservoir fluids, characterized in that, The method includes: Nuclear magnetic resonance sequences were used to process the full-diameter core of the target section in an alternating manner with the first waiting time and the second waiting time to determine the first lateral relaxation time distribution; A pulsed gradient magnetic field is applied to a full-diameter core and a first echo signal is acquired at a first preset echo interval. The first fluid diffusion coefficient of the full-diameter core is determined based on the first preset echo interval and the first transverse relaxation time distribution. The second transverse relaxation time distribution and the second preset echo interval of the formation water in the target layer are determined, and the second fluid diffusion coefficient of the formation water is determined based on the second transverse relaxation time distribution and the second preset echo interval. The third transverse relaxation time distribution and the third preset echo interval of the crude oil in the target layer are determined, and the third fluid diffusion coefficient of the crude oil is determined based on the third transverse relaxation time distribution and the third preset echo interval. The first fluid diffusion coefficient is compared with the second and third fluid diffusion coefficients to determine the fluid properties of the target reservoir.

2. The method according to claim 1, characterized in that, The process of processing the full-diameter core of the target section using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the first lateral relaxation time distribution includes: Nuclear magnetic resonance (NMR) sequences were used to process the full-diameter core of the target section at the first waiting time to obtain the first echo train signal. Nuclear magnetic resonance (NMR) sequences were used to process the full-diameter core of the target section at the second waiting time to obtain the second echo train signal. The first echo train signal and the second echo train signal are spliced ​​together with concave dots to obtain the first transverse relaxation time distribution of the full-diameter core; wherein, the second waiting time is less than the first waiting time.

3. The method according to claim 2, characterized in that, Nuclear magnetic resonance (NMR) sequences were used to process the full-diameter core of the target section at a second waiting time to obtain the second echo train signal, which included: The echo train signal of the full diameter core of the target section is repeatedly measured during the second waiting time until the preset number of measurements is met. The echo train signals obtained from repeated measurements are determined, and the echo train signals obtained from repeated measurements are superimposed to obtain the second echo train signal.

4. The method according to claim 1, characterized in that, The step of applying a pulsed gradient magnetic field to the full-diameter core and acquiring a first echo signal at a first preset echo interval, and determining the first fluid diffusion coefficient of the full-diameter core based on the first preset echo interval and the first transverse relaxation time distribution, includes: A pulsed gradient magnetic field was applied to the full-diameter core using a gradient coil, and the first echo signal of the full-diameter core was acquired according to at least two first preset echo intervals. At least two fluid diffusion coefficients of the full-diameter core are determined based on the at least two first preset echo intervals and the determined first transverse relaxation time distribution. The first fluid diffusion coefficient of the full-diameter core is obtained by preprocessing the at least two fluid diffusion coefficients; the preprocessing includes least squares processing.

5. The method according to claim 1, characterized in that, The determination of the second transverse relaxation time distribution and the second preset echo interval of formation water in the target layer, and the determination of the second fluid diffusion coefficient of formation water based on the second transverse relaxation time distribution and the second preset echo interval, includes: The formation water in the target layer was processed using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the second lateral relaxation time distribution; A pulsed gradient magnetic field is applied to the formation water and a second echo signal is acquired at a second preset echo interval. The second fluid diffusion coefficient of the formation water is determined based on the second preset echo interval and the second transverse relaxation time distribution.

6. The method according to claim 1, characterized in that, The determination of the third transverse relaxation time distribution and the third preset echo interval of the crude oil in the target layer, and the determination of the third fluid diffusion coefficient of the crude oil based on the third transverse relaxation time distribution and the third preset echo interval, includes: The target layer crude oil was processed using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the third transverse relaxation time distribution; A pulse gradient magnetic field is applied to the crude oil to determine the third echo signal, and the third echo signal is obtained at a third preset echo interval. The third fluid diffusion coefficient of the crude oil is determined based on the third preset echo interval and the third transverse relaxation time distribution.

7. The method according to claim 1, characterized in that, The step of comparing the first fluid diffusion coefficient with the second and third fluid diffusion coefficients respectively to determine the fluid properties of the target reservoir includes: If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is less than the first preset threshold, then the fluid property of the target reservoir is determined to be an aqueous layer. If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is greater than the first preset threshold and less than the second preset threshold, then the fluid properties of the target reservoir are determined to be an oil-water layer. If the ratio of the first fluid diffusion coefficient to the second fluid diffusion coefficient is greater than the second preset threshold, and the ratio of the first fluid diffusion coefficient to the third fluid diffusion coefficient is greater than the third preset threshold, then the fluid properties of the target layer reservoir are determined to be oil-water co-layer. If the ratio of the first fluid diffusion coefficient to the third fluid diffusion coefficient is less than the third preset threshold, then the fluid properties of the target reservoir are determined to be oil.

8. A reservoir fluid identification device, characterized in that, The device includes: The first transverse relaxation time distribution determination module is used to process the full-diameter core of the target section using nuclear magnetic resonance sequences with alternating first and second waiting times to determine the first transverse relaxation time distribution. The first fluid diffusion coefficient determination module is used to apply a pulsed gradient magnetic field to the full-diameter core to determine the first echo signal, and to determine the first fluid diffusion coefficient of the full-diameter core based on the first echo signal and the first transverse relaxation time distribution. The second fluid diffusion coefficient determination module is used to determine the second lateral relaxation time distribution and the second preset echo interval of the formation water in the target layer, and to determine the second fluid diffusion coefficient of the formation water based on the second lateral relaxation time distribution and the second preset echo interval. The third fluid diffusion coefficient determination module is used to determine the third transverse relaxation time distribution and the third preset echo interval of crude oil in the target layer, and to determine the third fluid diffusion coefficient of crude oil based on the third transverse relaxation time distribution and the third preset echo interval. The reservoir fluid property determination module is used to compare the first fluid diffusion coefficient with the second and third fluid diffusion coefficients to determine the fluid properties of the target reservoir.

9. An electronic device, characterized in that, include: One or more processors; Storage device for storing one or more programs; When the one or more programs are executed by the one or more processors, the one or more processors implement the reservoir fluid identification method according to any one of claims 1-7.

10. A storage medium containing computer-executable instructions, characterized in that, The computer-executable instructions, when executed by a computer processor, are used to perform the reservoir fluid identification method as described in any one of claims 1-7.

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