Method for identifying fracture occurrence in fractured reservoirs

Abstract

The application relates to the technical field of oil and gas exploitation, and discloses a method for identifying fracture occurrence of a fractured reservoir, which comprises the following steps: carrying out displacement water injection on a to-be-tested core; obtaining water injection length and water saturation of the to-be-tested core in continuous time, and drawing a first image curve of the water injection length and the water saturation; obtaining oil saturation in a plurality of different fracture gaps in the to-be-tested core, and drawing a second image curve of the fracture gap and the oil saturation; and determining the fracture occurrence of the to-be-tested core according to the first image curve and the second image curve. In this way, the identification difficulty of the fracture occurrence can be reduced under the condition of low cost, and the influence of fracture network distribution on water flooding law can be analyzed.

Description

Technical Field

[0001] This application relates to the field of oil and gas extraction technology, and for example to a method for identifying the occurrence of fractures in fractured reservoirs. Background Technology

[0002] Oil reservoirs formed by the accumulation of oil and gas in fractured traps are called fractured reservoirs. Fractured reservoirs hold a very important position in global oil production and reserves. These reservoirs exhibit various fracture occurrences, leading to their heterogeneity. Furthermore, for water injection development, characteristics such as water seepage along fractures and rapid water breakthrough in wells can occur, severely reducing oilfield recovery rates. Therefore, the study of fracture occurrence is crucial for improving oil well productivity.

[0003] Fractured reservoirs exhibit diverse fracture development within reservoir units, making it generally difficult to characterize the internal fracture network. Conventional methods involve drilling cores and analyzing their internal fracture development to determine the local fracture orientation. Currently, core CT scanning is used to identify fracture development within the core. The procedure involves: placing the core skeleton into a high-precision CT scanner for full-diameter CT scanning; cutting and adjusting the grayscale values ​​of the scanned core slices to obtain grayscale images; filtering and noise removal of the obtained images; and performing three-dimensional reconstruction of the core CT slices to obtain the core skeleton and fracture development.

[0004] While the aforementioned techniques can visually demonstrate the morphology, length, and orientation of fractures, they are costly and require software for three-dimensional reconstruction, increasing the complexity. Furthermore, they only provide information on fracture development and cannot analyze the impact of fracture network distribution on water-driven oil recovery. Summary of the Invention

[0005] To provide a basic understanding of some aspects of the disclosed embodiments, a brief summary is given below. This summary is not intended as a general commentary, nor is it intended to identify key / important components or describe the scope of protection of these embodiments, but rather as a prelude to the detailed description that follows.

[0006] This disclosure provides a method for identifying fracture occurrence in fractured reservoirs. It reduces the difficulty of identifying fracture occurrence at a lower cost and can also analyze the influence of fracture network distribution on waterflooding patterns.

[0007] This disclosure provides a method for identifying the fracture occurrence in fractured reservoirs, including:

[0008] Displacement water injection is performed on the core sample to be tested;

[0009] The water injection length and water saturation of the core sample were obtained over a continuous time period, and a first image curve of the water injection length versus the water saturation was plotted.

[0010] The oil saturation in multiple different fracture gaps in the core sample was obtained, and a second image curve of the fracture gaps and the oil saturation was plotted.

[0011] The fracture orientation of the core sample is determined based on the first image curve and the second image curve.

[0012] Further, based on the first image curve and the second image curve, the fracture orientation of the core sample is determined, including:

[0013] Obtain the preset type curve graph;

[0014] The type of the core sample to be tested is determined based on the first image curve and the preset type curve spectrum.

[0015] The fracture orientation of the core sample is determined based on the type of core sample and the second image curve.

[0016] Further, based on the first image curve and the preset type curve spectrum, the type of the core sample to be tested is determined, including:

[0017] If the first image curve satisfies the first type image curve in the preset type curve spectrum, the core sample to be tested is determined to be of the first type;

[0018] If the first image curve satisfies the second type image curve in the preset type curve spectrum, the core sample to be tested is determined to be of the second type;

[0019] The first type of image curve is a uniform curve, and the first type is a non-penetrating fracture core; the second type of image curve is a non-uniform curve, and the second type is a penetrating fracture core.

[0020] Further, based on the type of the core sample and the second image curve, the fracture orientation of the core sample is determined, including:

[0021] Obtain the preset fracture orientation curve map;

[0022] When the core sample to be tested is of the first type, the second image curve is compared with the first fracture orientation curve in the preset fracture orientation curve atlas.

[0023] In cases where the second image curve coincides with or is located below the first fracture orientation curve, the fracture orientation of the core sample is determined to be a non-penetrating fracture.

[0024] Furthermore, determining the fracture orientation of the core sample based on its type and the second image curve further includes:

[0025] If the core sample to be tested is of the second type, the second image curve is compared with the second fracture orientation curve and the third fracture orientation curve in the preset fracture orientation curve atlas.

[0026] In cases where the second image curve coincides with or is located above the second fracture orientation curve, the fracture orientation of the core sample is determined to be a first through fracture.

[0027] If the second image curve is located between the second fracture orientation curve and the third fracture orientation curve, the fracture orientation of the core sample is determined to be the second through fracture.

[0028] Furthermore, the first through-slit is a horizontal through-slit, and the second through-slit is a low-angle through-slit.

[0029] Further, the preset category curve graphs are obtained in the following manner, including:

[0030] The first and second types of experimental rock cores were produced;

[0031] Displacement water injection experiments were conducted on the experimental cores.

[0032] By scanning multiple experimental cores with nuclear magnetic resonance to obtain the water injection length and water saturation over a continuous period of time, and plotting multiple curves of water injection length versus water saturation, a pre-defined type of curve spectrum was obtained.

[0033] Furthermore, first and second types of experimental cores were manufactured, including:

[0034] Calculate the location of the fracture in the experimental core based on the required fracture dip angle, length, and end face.

[0035] The crack location is cut open;

[0036] Based on the quantitative relationship between the mesh size of the experimental core and its permeability, the cut cracks were partially filled to produce the first and second types of experimental cores.

[0037] Furthermore, a displacement water injection experiment was conducted on the experimental core, including:

[0038] The experimental core was evacuated.

[0039] Experimental oil was injected into the vacuumed experimental core at the first flow rate until saturation.

[0040] The first remaining amount of experimental fluid was injected into the experimental core after the experimental oil was injected at the second flow rate.

[0041] Furthermore, the experimental core includes an artificial carbonate rock core, the experimental oil includes kerosene, and the experimental fluid includes heavy water.

[0042] Further, the preset fracture orientation curve is obtained as follows:

[0043] By scanning the oil saturation of multiple experimental cores in different fracture gaps using nuclear magnetic resonance, and plotting multiple curves of fracture gaps versus oil saturation, a pre-defined fracture orientation curve map was obtained.

[0044] The method for identifying fracture orientation in fractured reservoirs provided in this disclosure can achieve the following technical effects:

[0045] The process involves water displacement injection into the core sample; obtaining the injection length and water saturation of the core sample over a continuous time period, and plotting a first image curve showing the relationship between injection length and water saturation; obtaining the oil saturation within multiple different fracture gaps in the core sample, and plotting a second image curve showing the relationship between fracture gaps and oil saturation; and determining the fracture orientation of the core sample based on the first and second image curves. This method reduces the difficulty of fracture orientation identification at a lower cost, while also requiring less sophisticated equipment and software processing capabilities, and is easy to operate. Furthermore, it considers both the development of reservoir fractures and the influence of the fracture system on water-drive oil recovery, thereby determining the fracture development within the core sample and more accurately understanding the formation parameters of fractured reservoirs. This approach is more targeted, closer to actual production, and provides stronger guidance for improving oilfield development.

[0046] The above general description and the description below are exemplary and illustrative only and are not intended to limit this application. Attached Figure Description

[0047] One or more embodiments are illustrated by way of example with reference to the accompanying drawings. These illustrations and drawings do not constitute a limitation on the embodiments. Elements having the same reference numerals in the drawings are shown as similar elements. The drawings are not to be scaled. And wherein:

[0048] Figure 1 This is a schematic diagram of a method for identifying fracture occurrence in fractured reservoirs provided in an embodiment of this disclosure;

[0049] Figure 2 This is a schematic diagram of nuclear magnetic resonance imaging of non-penetrating fracture cores at different displacement stages provided in the embodiments of this disclosure;

[0050] Figure 3This is a schematic diagram of nuclear magnetic resonance imaging of a low-angle through-fracture core at different displacement stages, provided in an embodiment of this disclosure.

[0051] Figure 4 This is a schematic diagram of nuclear magnetic resonance imaging of a horizontally penetrated fracture core at different displacement stages, provided in an embodiment of this disclosure.

[0052] Figure 5 This is a graph showing the degree of mobilization of the low-angle through-fracture core provided in the embodiments of this disclosure;

[0053] Figure 6 This is a graph showing the degree of mobilization of the horizontally penetrated fracture core provided in the embodiments of this disclosure;

[0054] Figure 7 These are curves of each core sample in the preset type curve graph provided in this embodiment of the disclosure;

[0055] Figure 8 This is a graph of each core sample in the preset fracture orientation curve provided in this embodiment. Detailed Implementation

[0056] To provide a more detailed understanding of the features and technical content of the embodiments of this disclosure, the implementation of the embodiments of this disclosure will be described in detail below with reference to the accompanying drawings. The accompanying drawings are for illustrative purposes only and are not intended to limit the embodiments of this disclosure. In the following technical description, for ease of explanation, several details are used to provide a full understanding of the disclosed embodiments. However, one or more embodiments may still be implemented without these details. In other cases, well-known structures and devices may be simplified in their depiction to simplify the drawings.

[0057] The terms "first," "second," etc., used in the specification, claims, and accompanying drawings of this disclosure are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate for the embodiments of this disclosure described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover non-exclusive inclusion.

[0058] Unless otherwise stated, the term "multiple" means two or more.

[0059] In this embodiment of the disclosure, the character " / " indicates that the objects before and after it are in an "or" relationship. For example, A / B means: A or B.

[0060] The term "and / or" describes an association between objects, indicating that three relationships can exist. For example, A and / or B means: A or B, or A and B.

[0061] The term "correspondence" can refer to an association or binding relationship. The correspondence between A and B means that there is an association or binding relationship between A and B.

[0062] Combination Figure 1 As shown in the embodiments of this disclosure, a method for identifying the fracture occurrence of fractured reservoirs is provided, including:

[0063] S101. Displacement and water injection are performed on the core sample to be tested;

[0064] S102. Obtain the water injection length and water saturation of the core sample within a continuous time period, and plot the first image curve of water injection length versus water saturation.

[0065] S103. Obtain the oil saturation in multiple different fracture gaps in the core sample and plot the second image curve of the fracture gaps versus the oil saturation.

[0066] S104. Determine the fracture orientation of the core sample based on the first and second image curves.

[0067] The method for identifying fracture occurrence in fractured reservoirs, as provided in this embodiment, involves water displacement injection into the core sample. The injection length and water saturation of the core sample over a continuous time period are obtained, and a first image curve showing the relationship between injection length and water saturation is plotted. The oil saturation within multiple different fracture gaps in the core sample is also obtained, and a second image curve showing the relationship between fracture gaps and oil saturation is plotted. Based on the first and second image curves, the fracture occurrence of the core sample is determined. This method reduces the difficulty of fracture occurrence identification at a lower cost, while also requiring less sophisticated equipment and software processing capabilities, and is easy to operate. Furthermore, it considers both the development of reservoir fractures and the influence of the fracture system on water-drive oil recovery, thereby determining the development of fractures within the core sample and more accurately understanding the formation parameters of fractured reservoirs. Its targeted approach is more closely aligned with actual production, providing stronger guidance for improving oilfield development.

[0068] In this embodiment, a core sample is selected, the internal fracture orientation of which is unknown. The core sample is then subjected to displacement water injection. Nuclear magnetic resonance (NMR) is used to detect the injection length and water saturation of the core sample over a continuous period, and a first image curve showing the relationship between injection length and water saturation is plotted. This provides a clear visual representation of the water saturation characteristic curve of the core sample. Next, NMR is used to detect the oil saturation within multiple different fracture gaps in the core sample, and a second image curve showing the relationship between fracture gaps and oil saturation is plotted. This provides a clear visual representation of the oil saturation characteristic curve of the core sample, allowing for the calculation of the oil displacement efficiency. The fracture orientation of the core sample can then be determined based on the oil displacement efficiency.

[0069] In this embodiment, in order to determine the core pore throat structure and the oil-water migration and occurrence patterns during the waterflooding process, this embodiment has an online nuclear magnetic resonance (NMR) scanning experimental platform. The experimental platform includes a displacement pump, a confining pressure pump, a special clamp, an NMR scanner, a processor, and a display.

[0070] In the disclosed embodiments of this application, determining the fracture orientation of the core sample based on the first image curve and the second image curve includes: obtaining a preset type curve spectrum; determining the type of the core sample based on the first image curve and the preset type curve spectrum; and determining the fracture orientation of the core sample based on the type of the core sample and the second image curve.

[0071] Optionally, in this embodiment, the preset type curve spectrum is obtained in the following manner: manufacturing experimental cores of the first type and the second type; conducting displacement water injection experiments on the experimental cores; scanning the water injection length and water saturation of multiple experimental cores over a continuous time period using nuclear magnetic resonance, and plotting multiple curves of water injection length and water saturation to obtain the preset type curve spectrum.

[0072] In this embodiment, achieving fractures with a specific dip angle is extremely difficult, and it is essential to ensure that the fracture permeability remains within a reasonable range. Therefore, an inclined fracture cutting and filling method is used to create experimental cores. Specifically, this involves: calculating the fracture location of the experimental core based on the required fracture dip angle, length, and end face; cutting open the fracture at the desired location; and partially filling the cut fracture based on the quantitative relationship between the mesh size of the ceramsite and permeability, to create two types of experimental cores. Specifically, the fracture location is calculated based on the fracture dip angle, the length of the experimental core, and the diameter of its end face; a high-precision cutting saw is used to prepare unfilled fractures; and fine-tuning the fracture filling is performed by combining the quantitative relationship between different mesh sizes of ceramsite and permeability. This allows for the preparation of fractured cores with different fracture orientations and permeabilities, ensuring that the various indicators of the experimental cores essentially reach the target oilfield level. Here, the core samples with fracture orientations include pure matrix cores, high-angle non-penetrating fracture cores (fracture dip angle 75°), low-angle non-penetrating fracture cores (fracture dip angle 30°), low-angle penetrating fracture cores (fracture dip angle 15°), and horizontal penetrating fracture cores (fracture dip angle 0°). The first type of experimental cores consists of pure matrix cores, high-angle non-penetrating fracture cores, and low-angle non-penetrating fracture cores. The second type of experimental cores consists of low-angle penetrating fracture cores and horizontal penetrating fracture cores.

[0073] In this embodiment, the first type of experimental core is easily saturated; the second type is more difficult to saturate because the fluid tends to rush rapidly along the fractures, making it difficult for the matrix to be affected during the saturation process. To improve the degree of saturation and saturation efficiency, a stepped variable flow rate bidirectional saturation method is used, that is, starting from an injection flow rate of 0.001 mL / min, the flow rate is increased stepwise with the change in water cut at the outlet end, and bidirectional saturation is achieved at both the injection and extraction ends of the experimental core.

[0074] In this embodiment, a variable flow rate bidirectional saturation scheme is adopted using the saturation sequence and flow rate shown in Table 1 below. Throughout the experiment, the porosity and permeability of the experimental core samples need to be measured. Before displacement, the core is saturated with water, and then the bound water is calculated before the displacement operation begins. The oil and water production rates at different times are obtained, and the recovery rate and water cut changes under different fracture orientations are calculated.

[0075] Table 1 shows the saturation sequence and flow velocity for a bidirectional saturation scheme with variable flow rate.

[0076]

[0077]

[0078] In the disclosed embodiments of this application, a displacement water injection experiment is performed on the experimental core, including: evacuating the experimental core; injecting experimental oil into the evacuated experimental core at a first flow rate until saturation; and injecting a first residual amount of experimental fluid into the experimental core after the experimental oil injection at a second flow rate.

[0079] Optionally, in the disclosed embodiments of this application, the experimental core includes an artificial carbonate rock core, the experimental oil includes kerosene, and the experimental fluid includes heavy water. The experimental fluids used in the experiment are heavy water (density 1.1 g / cm³) and kerosene (density 0.8 g / cm³, viscosity 2.2 mPa·s at 25°C). The experimental core is an artificial carbonate rock core with a porosity of 15% and a permeability of 30 mD. Here, the parameters of the experimental core are designed based on actual oilfields. Specifically, the experimental core is 90 mm long, 25 mm in diameter, and its mineral composition is 70% dolomite and 30% calcite; it is non-water-sensitive and has neutral to weakly hydrophilic wettability.

[0080] In this embodiment, since the main principle of nuclear magnetic resonance (NMR) scanning for fluid identification is the identification of hydrogen atoms, heavy water was used to displace kerosene in order to distinguish the fluid inside the experimental core. Heavy water does not contain conventional hydrogen atoms, while kerosene does; therefore, the distribution of the oil phase can be represented by the color intensity of the scanned image.

[0081] Combination Figure 2As shown, the first type of experimental core, based on its initial saturated oil state, exhibits good oil saturation. Throughout the displacement process, injected water initially occupies the injection end pore throat, and then, as displacement progresses, the displacement front continuously advances until water is encountered at the core outlet. Images at the end of displacement indicate that the oil displacement efficiency is higher at the injection end, with remaining oil mainly concentrated near the outlet. Combined with… Figure 3 and Figure 4 The figures shown are schematic diagrams of nuclear magnetic resonance (NMR) at different displacement stages in core samples from low-angle through-fractures and at different displacement stages in core samples from horizontal through-fractures.

[0082] In one specific embodiment, the experimental core was evacuated, and the oil phase was saturated at a rate of 0.01 ml / min for 72 hours. After saturation, the oil phase permeability was measured. Displacement was then carried out at a rate of 0.5 ml / min, and data such as time, pressure difference, oil production, and water production were recorded. After 2.2 PV of heavy water displacement, the water phase permeability at the residual oil saturation level was measured. Here, the entire experimental process involved 8 NMR scans, combined with... Figure 2 As shown, the scans include one scan at the end of saturated oil production (0 PV of water displacement), six scans during the displacement process (0.1 PV, 0.2 PV, 0.3 PV, 0.4 PV, 0.6 PV, and 1.6 PV of water displacement), and one scan at the end of displacement (2.2 PV of water displacement). Thus, based on the recorded cumulative oil and water production, combined with the oil volume in the saturated core (original geological reserves), the recovery rate and water cut at any displacement time for different fracture orientations can be calculated.

[0083] In this embodiment, displacement water injection experiments were performed on the first type of experimental core and the second type of experimental core, respectively. Therefore, corresponding preset type curve spectra can be obtained. By using the first image curve and the preset type curve spectra, the type of core to be tested can be determined.

[0084] In this embodiment, the differences in water drive characteristics of different fracture orientations can also be obtained by measuring the degree of mobilization of experimental oil or the degree of mobilization of injected fluid in the experimental core.

[0085] The commonly used formula for calculating oil saturation based on nuclear magnetic resonance experiments is as follows:

[0086]

[0087] The area enclosed by the T2 spectrum curve and the x-axis when the oil is initially saturated. To displace the area under the T2 spectrum curve at a certain moment, the ratio of the two is the oil saturation at that moment, S. o T represents oil saturation. min For the minimum relaxation time, Tmax For the maximum relaxation time, T 2i Let i be the NMR signal intensity at a certain moment during water injection, and T be the time of that moment. 2saturated oil The NMR signal intensity is the initial saturation of the oil.

[0088] To determine the extent of mobilization along the length of the core sample, this embodiment establishes a relationship between nuclear magnetic resonance signal intensity (oil saturation) and the extent of mobilization based on the image: the calculation formula is as follows:

[0089]

[0090] ∑T Saturated Oil The summation of signal intensity at a certain section of the core under initial oil saturation state, ∑T i To sum the signal strength at a certain cross section under a certain PV, E oi T represents the degree of water usage at a given moment. i T represents the cross-sectional signal intensity at a certain moment during water injection. saturated oil The cross-sectional signal strength is when the oil is initially saturated.

[0091] In this embodiment, the change in the degree of mobilization of the experimental core at a certain stage of displacement can be calculated to obtain a mobilization profile. Since there is no bound water in this embodiment, the bound water saturation is 0, and the final residual oil saturation is approximately 60%. When the displacement ends, the degree of mobilization is relatively uniform along the length of the experimental core, with only a slight rise at the outlet end of the experimental core. Due to the end effect of the experimental core, for water-wet cores, when the water phase reaches the end of the experimental core, the water phase lags behind due to the disappearance of capillary force, resulting in a local increase in water saturation.

[0092] Combination Figure 5 As shown, the water saturation changes in the core sample from the low-angle through-fracture experiment during different displacement stages. Combined with... Figure 6 As shown, the water saturation changes in the core sample from the horizontally penetrated fracture at different displacement stages. The initial oil saturation was high in the first 20 mm before the injection end of the core sample, with little difference in water saturation within the 20–100 mm range. During the waterflooding stage, the injection end of the core sample was the primary site of mobilization. After 2 PV of waterflooding, the water saturation at all locations in the core sample increased significantly. The initial water saturation was defined as 0; the higher the water saturation, the greater the mobilization. After 2 PV of displacement, the water saturation increased significantly, with high water saturation at the injection end. The water saturation at the production end increased due to the end-of-pipe effect of the core sample.

[0093] In this embodiment, the mobilization rate of the first type of experimental core progresses steadily, with the core inlet end being mobilized first, and the core extraction end only being mobilized after 0.6 PV of displacement. In contrast, the mobilization rate of the second type of experimental core changes uniformly. However, at the end of displacement, the inlet end of the low-angle through-fracture core shows a higher mobilization rate, while the overall mobilization of the horizontal through-fracture core is more uniform.

[0094] In this embodiment, based on the aforementioned theory and experimental data, curves for each core sample in the preset type curve spectrum and the preset fracture orientation curve were generated at the end of displacement. Comparison revealed that in the preset type curve spectrum, the water saturation distribution of the non-penetrating fracture cores was uniform, while the water saturation distribution of the penetrating fracture cores varied significantly. In the preset fracture orientation curve, the horizontal penetrating fracture cores exhibited the highest signal intensity peak and the most remaining oil, while the matrix-type cores showed the best oil displacement effect.

[0095] Combination and Figure 7 As shown in the disclosed embodiments of this application, determining the type of the core sample to be tested based on the first image curve and the preset type curve spectrum includes: determining the core sample to be tested as the first type when the first image curve satisfies the first type image curve in the preset type curve spectrum; determining the core sample to be tested as the second type when the first image curve satisfies the second type image curve in the preset type curve spectrum; wherein, the first type image curve is a uniform curve, and the first type is a non-penetrating fracture core sample; the second type image curve is a non-uniform curve, and the second type is a penetrating fracture core sample.

[0096] In this embodiment, the first image curve is compared with the first and second type image curves of a preset type curve atlas. Here, if the curvature of the first image curve does not change much, that is, the water saturation distribution is uniform, the core to be tested is determined to be a non-penetrating fracture core of the first type; if the curvature of the first image curve changes significantly, that is, the water saturation distribution changes significantly, the core to be tested is determined to be a penetrating fracture core of the second type.

[0097] If we further compare the fracture orientation of the core samples with the second type of through-fracture fractures, and the curvature of the first image curve changes the most, indicating the largest change in water saturation distribution, then the core sample is determined to have a horizontal through-fracture orientation. If the curvature of the first image curve changes more than that of the core sample with non-through-fracture fractures but less than that of the core sample with horizontal through-fracture fractures, indicating a moderate change in water saturation distribution, then the core sample is determined to have a low-angle through-fracture orientation.

[0098] In the disclosed embodiments of this application, the combination and Figure 8As shown, the preset fracture orientation curve is obtained in the following manner: by scanning the oil saturation of multiple experimental cores in multiple different fracture gaps through nuclear magnetic resonance, and plotting multiple curves of fracture gaps and oil saturation to obtain the preset fracture orientation curve.

[0099] In the disclosed embodiments of this application, determining the fracture orientation of the core sample based on the type of core sample and the second image curve includes: acquiring a preset fracture orientation curve atlas; when the core sample is of the first type, comparing the second image curve with the first fracture orientation curve in the preset fracture orientation curve atlas; wherein, if the second image curve coincides with or is below the first fracture orientation curve, the fracture orientation of the core sample is determined to be a non-penetrating fracture. When the core sample is of the second type, comparing the second image curve with the second and third fracture orientation curves in the preset fracture orientation curve atlas; wherein, if the second image curve coincides with or is above the second fracture orientation curve, the fracture orientation of the core sample is determined to be a first penetrating fracture; if the second image curve is between the second and third fracture orientation curves, the fracture orientation of the core sample is determined to be a second penetrating fracture; and the first penetrating fracture is a horizontal penetrating fracture, and the second penetrating fracture is a low-angle penetrating fracture.

[0100] The foregoing description and accompanying drawings fully illustrate embodiments of the present disclosure to enable those skilled in the art to practice them. Other embodiments may include structural and other changes. The embodiments represent only possible variations. Individual components and functions are optional unless explicitly required, and the order of operation may vary. Parts and features of some embodiments may be included or substituted for parts and features of other embodiments. Embodiments of the present disclosure are not limited to the structures described above and shown in the accompanying drawings, and various modifications and changes may be made without departing from its scope. The scope of the present disclosure is limited only by the appended claims.

Claims

1. A method for identifying fracture occurrence in fractured reservoirs, characterized in that, include: Displacement water injection is performed on the core sample to be tested; The water injection length and water saturation of the core sample were obtained over a continuous time period, and a first image curve of the water injection length versus the water saturation was plotted. The oil saturation in multiple different fracture gaps in the core sample was obtained, and a second image curve of the fracture gaps and the oil saturation was plotted. The fracture orientation of the core sample is determined based on the first image curve and the second image curve. Determining the fracture orientation of the core sample based on the first image curve and the second image curve includes: Obtain the preset type curve graph; The type of the core sample to be tested is determined based on the first image curve and the preset type curve spectrum. Based on the type of the rock core to be tested and the second image curve, the fracture orientation of the rock core to be tested is determined; Based on the first image curve and the preset type curve spectrum, the type of the core sample to be tested is determined, including: If the first image curve satisfies the first type image curve in the preset type curve spectrum, the core sample to be tested is determined to be of the first type; If the first image curve satisfies the second type image curve in the preset type curve spectrum, the core sample to be tested is determined to be of the second type; Wherein, the first type of image curve is a uniform curve, and the first type is a non-penetrating fracture core; the second type of image curve is a non-uniform curve, and the second type is a penetrating fracture core. Based on the type of the rock core to be tested and the second image curve, the fracture orientation of the rock core to be tested is determined, including: Obtain the preset fracture orientation curve map; When the core sample to be tested is of the first type, the second image curve is compared with the first fracture orientation curve in the preset fracture orientation curve atlas. In cases where the second image curve coincides with or is located below the first fracture orientation curve, the fracture orientation of the core sample is determined to be a non-penetrating fracture. Determining the fracture orientation of the core sample based on its type and the second image curve further includes: If the core sample to be tested is of the second type, the second image curve is compared with the second fracture orientation curve and the third fracture orientation curve in the preset fracture orientation curve atlas. In cases where the second image curve coincides with or is located above the second fracture orientation curve, the fracture orientation of the core sample is determined to be a first through fracture. If the second image curve is located between the second fracture orientation curve and the third fracture orientation curve, the fracture orientation of the core sample is determined to be the second through fracture. Furthermore, the first through-slit is a horizontal through-slit, and the second through-slit is a low-angle through-slit.

2. The identification method according to claim 1, characterized in that, Obtain the preset type curve graphs as follows: The first and second types of experimental rock cores were produced; Displacement water injection experiments were conducted on the experimental cores. By scanning multiple experimental cores with nuclear magnetic resonance to obtain the water injection length and water saturation over a continuous period of time, and plotting multiple curves of water injection length versus water saturation, a pre-defined type of curve spectrum was obtained.

3. The identification method according to claim 2, characterized in that, The first and second types of experimental cores were manufactured, including: Calculate the location of the fracture in the experimental core based on the required fracture dip angle, length, and end face. The crack location is cut open; Based on the quantitative relationship between the mesh size of the experimental core and its permeability, the cut cracks were partially filled to produce the first and second types of experimental cores.

4. The identification method according to claim 2, characterized in that, Displacement and water injection experiments were conducted on the experimental core, including: The experimental core was evacuated. Experimental oil was injected into the vacuumed experimental core at the first flow rate until saturation. The first remaining amount of experimental fluid was injected into the experimental core after the experimental oil was injected at the second flow rate.

5. The identification method according to claim 4, characterized in that, The experimental core includes an artificial carbonate rock core, the experimental oil includes kerosene, and the experimental fluid includes heavy water.

6. The identification method according to claim 2, characterized in that, The preset fracture orientation curve atlas is obtained as follows: By scanning the oil saturation of multiple experimental cores in different fracture gaps using nuclear magnetic resonance, and plotting multiple curves of fracture gaps versus oil saturation, a pre-defined fracture orientation curve map was obtained.

Images