Reservoir fluid property determination method and device, equipment and storage medium

Abstract

The invention provides a reservoir fluid property determination method and device, equipment and a storage medium. The method comprises the following steps: acquiring an electric imaging logging image of a reservoir; standardizing the electrical imaging logging image to obtain a standardized imaging picture; converting the imaging picture into a well panoramic porosity image; based on the well panoramic porosity image, acquiring development information of the reservoir; judging whether the reservoir is an effective reservoir or not based on the development information; if the reservoir is the effective reservoir, judging whether the reservoir has a water-containing pore area or not; and if the reservoir has the water-containing pore area, the fluid property of the reservoir is determined based on the water saturation of the water-containing pore area, and the fluid property of the complex reservoir can be determined.

Description

Technical Field

[0001] The present application relates to the technical field of oil and gas exploration, and in particular to a method, device, equipment and storage medium for determining reservoir fluid properties. Background Art

[0002] Existing technologies use electrical imaging porosity spectrum analysis primarily for qualitative analysis of the pore structure of complex reservoirs, such as clastic rocks, carbonate rocks, and igneous rocks. This analysis is used to identify effective reservoirs, classify reservoirs, and study reservoir heterogeneity. Furthermore, based on the combined characteristics of the apparent porosity spectrum, matrix porosity and secondary porosity are quantitatively calculated to quantitatively characterize secondary porosity and analyze its impact on productivity. However, the literature does not yet support the use of electrical imaging porosity spectrum analysis for research on reservoir fluid properties.

[0003] Conventional logging methods, such as calculating water saturation using the Archie formula based on porosity, deep lateral resistivity, and determining fluid properties using porosity-saturation intersection, have been effective in porous medium-sized reservoirs. However, complex reservoirs such as fractured-cavity carbonate rocks and clastic rock fracture bodies are generally dense and have well-developed fractures and cavities. These reservoirs exhibit strong heterogeneity, weak gas-water differential response characteristics, and difficulty in discerning fluid properties. Conventional methods no longer meet the needs of fluid property evaluation in complex reservoirs such as fracture bodies, and can easily have adverse effects on testing and subsequent development. Summary of the Invention

[0004] In response to the above-mentioned problems, the present application provides a method, apparatus, device and storage medium for determining reservoir fluid properties, which can realize the determination of fluid properties in complex reservoirs.

[0005] The present application provides a method for determining reservoir fluid properties, including:

[0006] Acquire electrical imaging logging images of the reservoir;

[0007] Standardizing the electrical imaging logging image to obtain a standardized imaging image;

[0008] converting the imaging image into a wellbore porosity image;

[0009] Acquiring development information of the reservoir based on the wellbore circumferential porosity image;

[0010] Based on the development information, determining whether the reservoir is an effective reservoir;

[0011] If the reservoir is an effective reservoir, determining whether the reservoir has a water-bearing pore zone;

[0012] If the water-containing pore zone exists in the reservoir, the fluid properties of the reservoir are determined based on the water saturation of the water-containing pore zone.

[0013] In some embodiments, the step of normalizing the electrical imaging logging image to obtain a standardized imaging image includes:

[0014] The data of each plate in the electrical imaging logging image is scaled to a grayscale of 0-255 to obtain a standardized imaging image.

[0015] In some embodiments, converting the image into a wellbore porosity image comprises:

[0016] Obtain conventional well logging curves;

[0017] Determining the water saturation of the flushing zone based on the conventional well logging curve;

[0018] Apparent porosity is calculated based on the water saturation of the flushing zone and Archie's formula;

[0019] Based on the apparent porosity, a wellbore peripheral apparent porosity image is constructed.

[0020] In some embodiments, determining whether the reservoir is a valid reservoir based on the development information includes:

[0021] If the secondary pore zone of the reservoir is not developed, the reservoir is judged to be an ineffective reservoir;

[0022] If the secondary pore zone is developed, the reservoir is judged to be an effective reservoir.

[0023] In some embodiments, including:

[0024] If the reservoir is an effective reservoir and there is no water-bearing pore zone, it is determined that the reservoir is a gas reservoir.

[0025] In some embodiments, if the water-containing pore zone exists in the reservoir, determining the fluid properties of the reservoir based on the water saturation of the water-containing pore zone includes:

[0026] If the water saturation of the water-containing pore zone is less than or equal to a first preset saturation, determining that the reservoir is a gas layer;

[0027] If the water saturation of the water-bearing pore zone is greater than a first preset saturation and less than a second preset saturation, the reservoir is determined to be a gas-water layer;

[0028] If the water saturation of the water-containing pore zone is greater than or equal to the second preset saturation, the reservoir is determined to be a water layer.

[0029] In some embodiments, further comprising:

[0030] Obtaining the total porosity and clay mineral volume percentage of the reservoir;

[0031] The porosity of the secondary pore zone and the water-bearing pore zone is corrected for shale based on the total porosity and the clay mineral volume percentage.

[0032] The present invention provides a device for distinguishing fluid properties in a complex reservoir, comprising:

[0033] A first acquisition module is used to acquire electrical imaging logging images;

[0034] A standardization module, used for standardizing the electrical imaging logging image to obtain a standardized imaging image;

[0035] A conversion module, configured to convert the image into a wellbore porosity image;

[0036] A second acquisition module is configured to acquire development information of the reservoir based on the wellbore circumferential porosity image;

[0037] A first judgment module is used to judge whether the reservoir is a valid reservoir based on the development information;

[0038] A second judgment module is configured to judge whether there is a water-bearing pore zone in the reservoir if the reservoir is a valid reservoir;

[0039] The determination module is configured to determine the fluid properties of the reservoir based on the water saturation of the water-containing pore zone if the water-containing pore zone exists in the reservoir.

[0040] An embodiment of the present application provides an electronic device, including:

[0041] A memory and a processor, wherein a computer program is stored in the memory, and when the computer program is executed by the processor, any one of the above methods is executed.

[0042] An embodiment of the present application provides a storage medium, which stores a computer program that can be executed by one or more processors and can be used to implement any of the above-mentioned methods for determining reservoir fluid properties.

[0043] The present application provides a method, apparatus, device and storage medium for determining reservoir fluid properties, which obtain electrical imaging logging images of the reservoir; standardize the electrical imaging logging images to obtain standardized imaging maps; convert the imaging maps into circumferential porosity images; obtain development information of the reservoir based on the circumferential porosity images; determine whether the reservoir is an effective reservoir based on the development information; if the reservoir is an effective reservoir, determine whether the reservoir has a water-bearing porous area; if the reservoir has a water-bearing porous area, determine the fluid properties of the reservoir based on the water saturation of the water-bearing porous area, and can determine the fluid properties of complex reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0044] Hereinafter, the present application will be described in more detail based on embodiments with reference to the accompanying drawings.

[0045] Figure 1 A schematic diagram of a flow chart for implementing a method for determining reservoir fluid properties provided in an embodiment of the present application;

[0046] Figure 2 A schematic diagram of the distribution of the wellbore porosity image converted from the imaging image provided in the embodiment of the present application;

[0047] Figure 3 A schematic diagram of the imaging logging porosity spectrum of Well YX1 provided in an embodiment of the present application;

[0048] Figure 4 A schematic diagram of the structure of a complex reservoir fluid property discrimination device provided in an embodiment of the present application;

[0049] Figure 5 A schematic diagram of the structure of an electronic device provided in an embodiment of the present application.

[0050] In the drawings, like components are given like reference numerals, and the drawings are not drawn to scale. DETAILED DESCRIPTION

[0051] In order to make the purpose, technical solutions and advantages of this application clearer, the application will be further described in detail below with reference to the accompanying drawings. The described embodiments should not be regarded as limiting this application. All other embodiments obtained by ordinary technicians in this field without making creative work are within the scope of protection of this application.

[0052] In the following description, reference is made to “some embodiments”, which describes a subset of all possible embodiments, but it will be understood that “some embodiments” may be the same subset or different subsets of all possible embodiments and may be combined with each other without conflict.

[0053] If similar descriptions of "first\second\third" appear in the application documents, the following explanation will be added. In the following description, the terms "first\second\third" are only used to distinguish similar objects and do not represent a specific order for the objects. It can be understood that "first\second\third" can be interchanged with a specific order or sequence where permitted, so that the embodiments of the present application described herein can be implemented in an order other than that illustrated or described herein.

[0054] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by those skilled in the art to which this application pertains. The terms used herein are for the purpose of describing the embodiments of this application only and are not intended to limit this application.

[0055] Based on the problems existing in the related art, an embodiment of the present application provides a method for determining the properties of a reservoir fluid, and the execution subject of the method for determining the properties of a reservoir fluid can be an electronic device. The electronic device can be various types of terminals such as a heat preservation device, a laptop computer, a tablet computer, a desktop computer, a set-top box, a mobile device (for example, a mobile phone, a portable music player, a personal digital assistant, a dedicated messaging device, a portable gaming device), and can also be implemented as a server. The server can be an independent physical server, or a server cluster or distributed system composed of multiple physical servers, or a cloud server that provides basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communications, middleware services, domain name services, security services, content delivery networks (CDNs), and big data and artificial intelligence platforms.

[0056] The functions implemented by the reservoir fluid property determination method provided in the embodiment of the present application can be implemented by calling program codes by a processor of an electronic device, wherein the program codes can be stored in a computer storage medium.

[0057] The present invention provides a method for determining reservoir fluid properties. Figure 1 A schematic diagram of a method for determining reservoir fluid properties provided in an embodiment of the present application is shown in FIG. Figure 1 Shown, including:

[0058] Step S1: Acquire electrical imaging logging images of the reservoir;

[0059] In an embodiment of the present application, the electrical imaging logging image can be collected by an XRMI electrical imaging logging instrument or an FMI formation microresistivity scanning imaging. Taking the XRMI electrical imaging logging instrument as an example, the XRMI electrical imaging logging instrument has 6 plates, each with 25 electrodes, which measures the conductivity of the formation (the inverse of the resistivity).

[0060] In the examples of this application, the fractured-cavity carbonate reservoir of the fourth member of the marine Leikoupo Formation in the Pengzhou gas field in the Longmenshan piedmont of the western Sichuan Basin is used as an example. The lithology of the fourth member of the Leikoupo Formation includes a variety of lithologic combinations, such as dolomite, limy dolomite, muddy dolomite, gypsum dolomite, gypsum, limestone, and marl-bearing limestone. The lithology is diverse, the reservoir has well-developed fractures and cavities, and the pore structure is complex. The fault-body reservoir of the second member of the Xujiahe Formation in the Xinchang tectonic zone of the western Sichuan Depression is used as an example. Its lithology is mainly characterized by a combination of quartz sandstone, feldspathic sandstone, lithic sandstone, mudstone, and carbonaceous shale. The reservoir is dense, with well-developed fractures, making reservoir fluid identification difficult. Based on the resistivity differences and rock structural characteristics of different lithologies, the lithology can be qualitatively determined using electrical imaging logging images.

[0061] Step S2: standardizing the electrical imaging logging image to obtain a standardized imaging image;

[0062] In the embodiments of the present application, according to the principles of electrical imaging logging, high-resistivity materials generally correspond to bright images on electrical imaging logging images, while low-resistivity materials correspond to dark images. Geological phenomena such as high-mud shale layers, water-bearing formations, metallic minerals, fractures and holes, and drilling fluid intrusion in the formation may all exhibit low-resistivity characteristics, thus appearing as dark images on the imaging map. However, the resistivity distribution ranges and conventional logging responses of these low-resistivity geological phenomena vary to a certain extent. In order to enhance the image display effect and to more accurately obtain the actual porosity spectrum distribution characteristics of the reservoir during spectral analysis, so as to accurately determine the water content characteristics of the reservoir, it is necessary to standardize the data of each electrical imaging plate, that is, the plate data can be scaled to a grayscale of 0-255 to obtain a standardized imaging map.

[0063] Step S3: converting the image into a wellbore porosity image;

[0064] In the embodiment of the present application, the basic principle of the well circumference porosity image analysis technology is as follows: the electrical imaging logging of the imaging figure (2(a)) can obtain N conductivity (reciprocal resistivity) curves within the 360-degree range of the well circumference (150 for XRMI and 192 for FMI), that is, the porosity curve at the same depth can be obtained. Figure 2 (b)) By dividing the intervals according to the size of the porosity, a porosity frequency histogram can be formed; with the porosity size interval of each depth point as the horizontal axis and the frequency as the vertical axis, a certain window length and step size are used to perform frequency histogram statistics on the porosity image to form a frequency diagram of continuous depth points in the vertical direction, similar to the porosity spectrum of the T2 spectrum of nuclear magnetic resonance logging. The lateral distribution of the porosity spectrum represents the pore range of the formation, while the amplitude represents the proportion of pores of the corresponding size in the formation at the current depth point. This method can intuitively observe the frequency distribution of porosity of different sizes in each depth segment ( Figure 2(c) Electrical imaging logging has high resolution and circumferential coverage. It converts electrical conductivity from imaging logging into apparent formation resistivity and then calculates reservoir porosity. This method offers high accuracy and excellent discrimination for complex reservoirs with strong heterogeneity.

[0065] In the embodiments of this application, in the actual processing of apparent porosity spectrum analysis, since static electrical imaging logging data is processed using a unified standard across the entire well section, the standardized static electrical imaging can be used to convert it into a wellbore apparent porosity image. This means that the apparent porosities calculated by each plate at the same depth are arranged in ascending order to form a porosity spectrum. Generally speaking, the deeper the electrical imaging logging image in the reservoir section, the lower the indicated resistivity, indicating a larger pore size; the lighter the image color, the higher the resistivity, indicating a smaller pore size. This corresponds precisely to the behavior of secondary pores, such as matrix pores and fracture dissolution pores, in fracture-vuggy carbonate reservoirs.

[0066] In the embodiment of the present application, when the normalized image is converted into a wellbore porosity image, it is still affected by the high clay mineral content. Therefore, mud correction can be carried out in the subsequent porosity calculation of the secondary pore area and the porosity of the water-bearing pore area.

[0067] Step S4: acquiring the reservoir development information based on the wellbore circumferential porosity image;

[0068] In the embodiment of the present application, there are many matrix pores in the formation, corresponding to the high frequency peak position of the porosity size spectrum ( Figure 2 The small pores in the matrix of area A in (c) are mainly contributed by high resistance); the small peaks at the back represent secondary pores such as crack dissolution holes, with low frequency ( Figure 2 (c) Secondary macropores in Zone B, primarily due to low resistivity. The matrix pores and secondary pores are not continuous, but rather exhibit distinct abrupt changes. Matrix pores are small and numerous, with a wide and continuous range of pore size variation, while secondary pores are large and few, with a relatively narrow range of pore size variation. Statistical features and spectral peak differences in the wellbore porosity image can be used to distinguish between matrix and secondary pore zones. Once these distinctions are established, reservoir development information can be derived from the secondary pore zones.

[0069] Step S5: Based on the development information, determining whether the reservoir is an effective reservoir;

[0070] In the embodiment of the present application, when the secondary pore zone of the reservoir is not developed and the matrix pore zone is relatively uniformly developed, the porosity distribution spectrum shows a single peak that moves forward (at Figure 2 (c) Only area A appears), and the reservoir can be judged as an ineffective reservoir. When the pores in the reservoir matrix pore area are small and the secondary pore area is more uniformly developed, the porosity distribution spectrum shows a single peak that shifts backward (at Figure 2(c) Only zone B is developed), then the reservoir can be judged as an effective reservoir. When the reservoir matrix pore zone is developed and the secondary pore zone is unevenly developed, the porosity distribution spectrum shows a bimodal or multimodal feature (in Figure 2 (c) If area A and area B appear at the same time, or the combination of area A, area B and area C appears at the same time, the reservoir can be judged as an effective reservoir.

[0071] Step S6: If the reservoir is an effective reservoir, determine whether there is a water-bearing pore zone in the reservoir;

[0072] In the embodiment of the present application, when the reservoir is an effective reservoir, it is necessary to determine whether there is a water-containing pore zone, so as to determine the fluid properties of the reservoir by the water saturation of the water-containing pore zone if there is a water-containing pore zone.

[0073] Step S7: If the water-bearing pore zone exists in the reservoir, the fluid properties of the reservoir are determined based on the water saturation of the water-bearing pore zone.

[0074] In an embodiment of the present application, when it is determined that there are water-containing porous areas in the reservoir, the fluid properties of the reservoir can be determined based on the water saturation of the water-containing porous areas, where the fluid properties of the reservoir can be divided into gas layers, gas-water layers, and water layers. The judgment condition can be to determine the fluid properties of the reservoir based on the comparison of the water saturation of the water-containing porous areas with a preset threshold value, and the fluid properties are gas layers, gas-water layers, or water layers.

[0075] In summary, by acquiring an electrical imaging logging image of the reservoir; standardizing the electrical imaging logging image to obtain a standardized imaging map; converting the imaging map into a wellbore porosity image; acquiring the development information of the reservoir based on the wellbore porosity image; judging whether the reservoir is an effective reservoir based on the development information; if the reservoir is an effective reservoir, judging whether the reservoir has a water-bearing porous zone; if the reservoir has a water-bearing porous zone, determining the fluid properties of the reservoir based on the water saturation of the water-bearing porous zone, the determination of the fluid properties of complex reservoirs can be achieved.

[0076] In some embodiments, step S2 includes:

[0077] Step S21: scaling the plate data in the electrical imaging logging image to a grayscale of 0-255 to obtain a standardized imaging image.

[0078] In the embodiment of the present application, the plate data in the electrical imaging logging image is scaled to a grayscale of 0-255 to obtain a standardized image. Taking the XRMI electrical imaging logging tool as an example, the plate data normalization formula is as follows:

[0079] XRMI_S1=((log(BTi)-log(BTmin)) / ((log(BTmax)-log(BTmin))*256)

[0080] Where BTi is the conductivity value of an electrode on the plate, BTmax and BTmin are the maximum and minimum values ​​measured by all electrodes, log is the logarithmic value, and XRMI_S1 is the imaging data obtained by the standardized method.

[0081] In some embodiments, step S3 includes:

[0082] Step S31: obtaining a conventional well logging curve diagram;

[0083] Step S32: determining the water saturation of the flushing zone based on the conventional well logging curve;

[0084] Step S33: Calculating apparent porosity based on the water saturation of the flushing zone and Archie's formula;

[0085] Step S34: constructing a wellbore peripheral apparent porosity image based on the apparent porosity.

[0086] In the embodiments of the present application, the improved Archie formula can be used to approximately calculate the apparent porosity of the formation, converting the standardized electrical conductivity data of each electrode plate (the reciprocal of which is the resistivity) of the electrical imaging into an apparent porosity image around the well. The present application improves the Archie formula, and the improved Archie formula is:

[0087]

[0088] Where S XO is the water saturation of the flushing zone; Rmf is the resistivity of the mud filtrate; a, b, m, and n correspond to the rock electrical experimental parameters of the Archie model; XRMI_S1 is the plate conductivity value (derivative of resistivity) after normalization of the electrical imaging logging image; Apparent porosity.

[0089] In actual operation, the water saturation of the flushing zone S XO Conventional shallow lateral logging (RLLS) logging curves are generally used for calculation. The vertical resolution of conventional shallow lateral logging curves RLLS (RLLS sampling interval is 0.0762m or 0.1m) is much lower than the vertical resolution of electrical imaging logging (XRMI sampling interval is 0.0025m). The apparent porosity is inversely calculated from the water saturation of the flushing zone calculated by RLLS. This will increase the calculation error to a certain extent.

[0090] In the embodiment of the present application, an estimation method can be used to give S XOThe initial value is 100%, that is, the default water saturation of the flushing zone is 100%, in order to ensure the high resolution characteristics of the electrical imaging logging. According to the characteristics of the tight and complex gas-bearing reservoirs in the Sichuan Basin, even if there is a small amount of natural gas remaining in the flushing zone, that is, the water saturation of the flushing zone S XO ≤100%, resulting in a calculated apparent porosity It is slightly higher, but has little effect on the peak difference combination characteristics on the apparent porosity frequency spectrum, and does not affect the results of judging the fluid properties of the reservoir.

[0091] In some embodiments, step S5 includes:

[0092] Step S51: If the secondary pore zone of the reservoir is not developed, the reservoir is determined to be an ineffective reservoir;

[0093] Step S52: If the secondary pore zone is developed, the reservoir is determined to be an effective reservoir.

[0094] In the embodiment of the present application, the development information includes the development of the secondary pore zone, so that whether the reservoir is an effective reservoir can be judged by whether the secondary pore zone is developed, which can quickly determine whether the reservoir is an effective reservoir.

[0095] In some embodiments, after step S6, the following steps are included:

[0096] Step S61: If the reservoir is an effective reservoir and there is no water-bearing pore area, it is determined that the reservoir is a gas layer.

[0097] In the embodiments of the present application, when judging that the reservoir is an effective reservoir, it can be divided into two types according to the development of the secondary pore zone. One is that the secondary pore zone develops evenly and there is no water-containing pore zone in the reservoir, in which case the fluid properties of the reservoir can be directly determined to be gas layer properties; the other is that the secondary pore zone develops unevenly and there is a water-containing pore zone in the reservoir, in which case the fluid properties of the reservoir cannot be directly judged.

[0098] In some embodiments, step S7 includes:

[0099] Step S71: if the water saturation of the water-containing pore zone is less than or equal to a first preset saturation, determining that the reservoir is a gas layer;

[0100] Step S72: If the water saturation of the water-bearing pore zone is greater than a first preset saturation and less than a second preset saturation, then the reservoir is determined to be a gas-water layer;

[0101] Step S73: If the water saturation of the water-containing pore zone is greater than or equal to the second preset saturation, the reservoir is determined to be a water layer.

[0102] In the embodiments of the present application, the water saturation of the water-containing pore zone is compared with the first preset saturation and the second preset saturation, so as to determine the fluid property of the reservoir. Specifically, when the water saturation of the water-containing pore zone is less than the first preset saturation, it is determined that the reservoir is of gas layer property; when the water saturation of the water-containing pore zone is greater than or equal to the first preset saturation and less than the second preset saturation, it is determined that the reservoir is of gas-water layer property; and when the water saturation of the water-containing pore zone is greater than or equal to the second preset saturation, it is determined that the reservoir is of water layer property. The water content of the reservoir can be determined, so as to determine the fluid property of the reservoir according to the water content of the reservoir.

[0103] In some embodiments, further comprising:

[0104] Step S101: obtaining the total porosity and the clay mineral volume percentage of the reservoir;

[0105] Step S102: performing shale correction on the porosities of the secondary pore zone and the water-containing pore zone based on the total porosity and the clay mineral volume percentage.

[0106] In the embodiments of the present application, the wellbore view porosity frequency distribution spectrum of the wellbore view porosity image is statistically analyzed to find the boundary ENV1 (matrix pore envelope) of the matrix pore and the secondary pore such as fracture dissolution pore hole, and to find the boundary ENV2 (water-containing pore segmentation line) of the secondary pore such as fracture dissolution pore hole and the water-containing pore, and then the matrix pore zone, the secondary pore zone and the water-containing pore zone are divided by the ENV1 (matrix pore envelope) and the ENV2 (water-containing pore segmentation line).

[0107] In the embodiments of the present application, the imaging image after standardization is affected by high clay mineral content when being converted into the wellbore view porosity image, so shale correction needs to be performed in the subsequent secondary porosity and the water saturation of the water-containing pore zone is greater than the first preset saturation and less than the second preset saturation, so the reservoir is determined to be of gas-water layer property. The porosity of the matrix pore zone is denoted as POR1, the porosity of the secondary pore zone is denoted as POR2, the porosity of the water-containing pore zone is denoted as PORW, and the water saturation of the water-containing pore zone is denoted as Swf. Shale correction is performed in the calculation process of the porosity POR2 of the secondary pore zone and the porosity PORW of the water-containing pore zone, that is:

[0108] POR2 = (1-VSH) * POR2';

[0109] PORW = (1-VSH) * PORW';

[0110] Swf = PORW / POR*100.

[0111] Wherein, POR2: porosity of secondary pore zone after shale correction, %; POR2': porosity of secondary pore zone without shale correction, %; PORW: porosity of water-bearing pore zone after shale correction, %; PORW': porosity of water-bearing pore zone without shale correction, %; Swf: water saturation of water-bearing pore zone, %; POR: total porosity calculated by porosity spectrum, %; VSH: volume percentage of clay minerals, %.

[0112] In the embodiments of the present application, qualitative identification is first performed, exemplarily: if the imaging apparent porosity frequency graph shows the simultaneous development of secondary pore zones and water-bearing pore zones, this qualitatively indicates that the reservoir has relatively developed secondary pores and that the water-bearing pore zones are highly saturated with formation water. Furthermore, since fractures and vugs are generally large-scale pores, the formation water within the fractures (vugs) can be considered to be movable water. Therefore, formation water will be produced during completion testing, leading to adverse effects such as simultaneous gas and water production or even waterlogging of the gas well. If the imaging apparent porosity frequency graph shows the development of secondary pore zones and the absence of water-bearing pore zones, this qualitatively indicates that the reservoir has relatively developed secondary pores and that the fractures (vugs) do not contain movable formation water, resulting in no water production during completion testing. The second is quantitative calculation: if the water-bearing pore area is developed and the calculated movable water saturation Swf in the large pores of the fractures (holes) reaches 5-10% or above, it indicates that the reservoir has obvious water characteristics. If the calculated Swf ≤ 5%, it indicates that the reservoir has weak water characteristics. If Swf = 0, it indicates that the reservoir does not contain water.

[0113] In some embodiments, step S101 includes:

[0114] Step S1011: Calculating the volume percentage of the clay minerals through conventional natural gamma ray or uranium-free gamma ray logging curves.

[0115] In the embodiments of the present application, the clay mineral volume content value can be obtained by conventional natural gamma ray (GR) or uranium-free gamma ray (KTH) logging curves. Taking the natural gamma ray logging curve as an example, the calculation formula is as follows:

[0116]

[0117]

[0118] In the formula: GCUR is an empirical coefficient related to geological age, with the value of old strata being 2; GR is natural gamma, API; GRmax is the natural gamma response value of pure mudstone layer, API; Grmin is the natural gamma response value of pure sandstone layer, API; VSH is the volume percentage of clay minerals, %.

[0119] By reasonably selecting the values ​​of GRmin and GRmax, the calculated volume percentage of clay minerals can be made as close as possible to the results of clay mineral test analysis.

[0120] This application combines Figure 3 A method for determining reservoir fluid properties provided in this application is verified.

[0121] In the embodiment of the present application, according to the technical principle of identifying reservoir effectiveness and judging fluid properties through spectrum analysis, the frequency spectrum of the wellbore porosity image of the fractured-cavity carbonate gas well YX1 in the fourth member of the Leishan Formation in Pengzhou, western Sichuan was processed and interpreted. In the interpretation and evaluation diagram, the porosity POR2 corresponds to the secondary pore area (area B) of the imaging spectrum, and the porosity PORW corresponds to the water-bearing pore area (area C) of the imaging spectrum. For details, see Figure 3 .

[0122] First, the lithology is identified through imaging images. The imaging image of 5712-5714.6m is dark and massive, with high values ​​of natural gamma logging curve, indicating low-resistivity mudstone; 5714.6-5723.0m is medium-to-high-resistivity dolomite. The imaging results show that the dolomite at 5714.6-5723.0m has locally developed dark dissolution features against a high-resistivity background, indicating that it is a reservoir development section.

[0123] Analysis of the circumferential porosity image shows that matrix pores (Area A) and secondary pores (Area B) are well developed in the depth intervals of 5717.5-5917.9m and 5719.2-5720.6m, indicating that the reservoir is predominantly composed of matrix pores and dissolution pores, with good reservoir effectiveness. A water-bearing pore zone (Area C) is also visible on the far right of the circumferential porosity image. However, secondary pores (Area B) are undeveloped in the depth intervals of 5714.6-5717.4m, 5917.9m-5719.2m, and 5720.6-5723.0m, indicating that the reservoir is predominantly composed of matrix pores (Area A) and lacks secondary pores, indicating poor reservoir effectiveness.

[0124] The spectral peak characteristics of the water-bearing pore zone (zone C) within the depth of 5717.5-5917.9m are weak, the porosity PORW is low, and the water saturation SWf is distributed between 0-9%. The water-bearing characteristics in this reservoir section are weak, and the gas-bearing characteristics are dominant.

[0125] The water-bearing pore zone (Zone C) at a depth of 5719.2-5720.6m exhibits distinct spectral peaks, with high porosity (PORW) values ​​ranging from 0-3.1%, and water saturation (SWf) values ​​ranging from 3-24%. While pure gas-bearing carbonate layers typically have very low water saturations, this reservoir section reaches a peak of approximately 24%. Qualitative identification of the water-bearing pore zone (Zone C) and quantitative calculation of the SWf indicate that this interval exhibits significant water content, leading to the assessment of a coexisting gas-water layer.

[0126] Acid fracturing test was conducted on the 5715-5723m of YX1 well, producing 111,100 cubic meters of natural gas per day and 74.75 cubic meters of water per day.

[0127] The test results confirmed that the reservoir fluid properties determined by the electrical imaging spectrum analysis technology in Well YX1 were consistent with the acid fracturing test results.

[0128] Based on the foregoing embodiments, an embodiment of the present application provides a device for distinguishing the properties of complex reservoir fluids. The modules included in the device, and the units included in each module, can be implemented by a processor in a computer device; of course, they can also be implemented by a specific logic circuit; in the implementation process, the processor can be a central processing unit (CPU), a microprocessor (MPU), a digital signal processor (DSP), or a field programmable gate array (FPGA), etc.

[0129] The present invention provides a device for distinguishing the properties of complex reservoir fluids. Figure 4 A schematic diagram of the structure of the complex reservoir fluid property discrimination device provided in the embodiment of the present application is shown as follows: Figure 4 Shown, including:

[0130] A first acquisition module is used to acquire electrical imaging logging images;

[0131] A standardization module, used for standardizing the electrical imaging logging image to obtain a standardized imaging image;

[0132] A conversion module, configured to convert the image into a wellbore porosity image;

[0133] A second acquisition module is configured to acquire development information of the reservoir based on the wellbore circumferential porosity image;

[0134] A first judgment module is used to judge whether the reservoir is a valid reservoir based on the development information;

[0135] A second judgment module is configured to judge whether there is a water-bearing pore zone in the reservoir if the reservoir is a valid reservoir;

[0136] The determination module is configured to determine the fluid properties of the reservoir based on the water saturation of the water-containing pore zone if the water-containing pore zone exists in the reservoir.

[0137] In some embodiments, the standardization module includes:

[0138] The normalization unit is used to scale the data of each plate in the electrical imaging logging image to a grayscale of 0-255 to obtain a standardized imaging image.

[0139] In some embodiments, the conversion module comprises:

[0140] An acquisition unit, used for acquiring conventional logging curve graphs;

[0141] a determination unit, configured to determine the water saturation of the flushing zone based on the conventional well logging curve;

[0142] a calculation unit, configured to calculate apparent porosity based on the water saturation of the flushing zone and Archie's formula;

[0143] A construction unit is used to construct an apparent porosity image around the well based on the apparent porosity.

[0144] In some embodiments, the first determination module includes:

[0145] A first judgment unit is configured to judge that the reservoir is a non-effective reservoir if the secondary pore zone of the reservoir is not developed;

[0146] The second judgment unit is used to judge that the reservoir is an effective reservoir if the secondary pore zone is developed.

[0147] In some embodiments, the second determination module includes:

[0148] If the reservoir is an effective reservoir and there is no water-containing pore area, it is determined that the reservoir is a gas layer.

[0149] In some embodiments, the determining module includes:

[0150] a third judgment unit, configured to determine that the reservoir is a gas layer if the water saturation of the water-bearing pore zone is less than or equal to a first preset saturation;

[0151] a fourth judgment unit, configured to determine that the reservoir is a gas-water layer if the water saturation of the water-bearing pore zone is greater than a first preset saturation and less than a second preset saturation;

[0152] The fifth judgment unit is configured to determine that the reservoir is a water layer if the water saturation of the water-bearing pore zone is greater than or equal to the second preset saturation.

[0153] In some embodiments, a mud correction module is also included:

[0154] For obtaining the total porosity and clay mineral volume percentage of the reservoir;

[0155] The method is used to perform shale correction on the porosity of the secondary pore zone and the water-bearing pore zone based on the total porosity and the volume percentage of the clay mineral.

[0156] It should be noted that in the embodiments of the present application, if the above-mentioned reservoir fluid property determination method is implemented in the form of a software function module and sold or used as an independent product, it can also be stored in a computer-readable storage medium. Based on this understanding, the technical solution of the embodiments of the present application, or the part that contributes to the prior art, can be embodied in the form of a software product. The computer software product is stored in a storage medium and includes several instructions for enabling a computer device (which can be a personal computer, server, or network device, etc.) to execute all or part of the methods described in each embodiment of the present application. The aforementioned storage medium includes various media that can store program codes, such as a USB flash drive, a mobile hard disk, a read-only memory (ROM), a magnetic disk, or an optical disk. In this way, the embodiments of the present application are not limited to any specific combination of hardware and software.

[0157] Accordingly, an embodiment of the present application provides a storage medium on which a computer program is stored, characterized in that when the computer program is executed by a processor, the steps in the reservoir fluid property determination method provided in the above embodiment are implemented.

[0158] An embodiment of the present application provides an electronic device; Figure 5 A schematic diagram of the structure of an electronic device provided in an embodiment of the present application is shown in FIG. Figure 5 As shown, the electronic device 400 includes: a processor 401, at least one communication bus 402, a user interface 403, at least one external communication interface 404, and a memory 405. The communication bus 402 is configured to facilitate communication between these components. The user interface 403 may include a display screen, and the external communication interface 404 may include a standard wired interface and a wireless interface. The processor 401 is configured to execute a program for the reservoir fluid property determination method stored in the memory to implement the steps of the reservoir fluid property determination method provided in the above-described embodiment.

[0159] It should be noted that the descriptions of the above storage medium and electronic device embodiments are similar to the descriptions of the above method embodiments and have similar beneficial effects as the method embodiments. For technical details not disclosed in the storage medium and device embodiments of this application, please refer to the descriptions of the method embodiments of this application for understanding.

[0160] It should be understood that "one embodiment" or "an embodiment" mentioned throughout the specification means that the specific features, structures or characteristics related to the embodiment are included in at least one embodiment of the present application. Therefore, "in one embodiment" or "in an embodiment" appearing throughout the specification does not necessarily refer to the same embodiment. In addition, these specific features, structures or characteristics can be combined in one or more embodiments in any suitable manner. It should be understood that in the various embodiments of the present application, the size of the serial numbers of the above-mentioned processes does not mean the order of execution. The execution order of each process should be determined by its function and internal logic, and should not constitute any limitation on the implementation process of the embodiments of the present application. The above-mentioned serial numbers of the embodiments of the present application are for description only and do not represent the advantages and disadvantages of the embodiments.

[0161] It should be noted that, in this document, the terms "comprises," "includes," or any other variations thereof are intended to encompass non-exclusive inclusion, such that a process, method, object, or apparatus comprising a series of elements includes not only those elements but also other elements not explicitly listed, or elements inherent to such process, method, object, or apparatus. In the absence of further limitations, an element defined by the phrase "comprising a ..." does not preclude the presence of other identical elements in the process, method, object, or apparatus comprising the element.

[0162] In the several embodiments provided in this application, it should be understood that the disclosed devices and methods can be implemented in other ways. The device embodiments described above are merely schematic. For example, the division of the units is merely a logical function division. In actual implementation, there may be other division methods, such as: multiple units or components can be combined, or can be integrated into another system, or some features can be ignored or not executed. In addition, the coupling, direct coupling, or communication connection between the components shown or discussed can be through some interfaces, and the indirect coupling or communication connection of the devices or units can be electrical, mechanical or other forms.

[0163] The units described above as separate components may or may not be physically separated, and the components displayed as units may or may not be physical units; they may be located in one place or distributed across multiple network units; some or all of the units may be selected according to actual needs to achieve the purpose of the scheme of this embodiment.

[0164] In addition, all functional units in the embodiments of the present application can be integrated into one processing unit, or each unit can be a separate unit, or two or more units can be integrated into one unit; the above-mentioned integrated units can be implemented in the form of hardware or in the form of hardware plus software functional units.

[0165] Those skilled in the art will understand that all or part of the steps of implementing the above-mentioned method embodiments can be completed by hardware related to program instructions, and the aforementioned program can be stored in a computer-readable storage medium. When the program is executed, it executes the steps of the above-mentioned method embodiments; and the aforementioned storage medium includes: mobile storage devices, read-only memories (ROMs), magnetic disks, optical disks, and other media that can store program codes.

[0166] Alternatively, if the above-mentioned integrated unit of the present application is implemented in the form of a software functional module and sold or used as an independent product, it can also be stored in a computer-readable storage medium. Based on this understanding, the technical solution of the embodiment of the present application, or the part that contributes to the prior art, can be embodied in the form of a software product. The computer software product is stored in a storage medium and includes a number of instructions for enabling a controller to execute all or part of the methods described in each embodiment of the present application. The aforementioned storage medium includes: various media that can store program codes, such as mobile storage devices, ROMs, magnetic disks or optical disks.

[0167] The above is merely an embodiment of the present application, but the scope of protection of the present application is not limited thereto. Any changes or substitutions that can be easily conceived by a person skilled in the art within the technical scope disclosed in this application should be included in the scope of protection of this application. Therefore, the scope of protection of this application should be based on the scope of protection of the claims.

Claims

1. A method for determining reservoir fluid properties, characterized in that: include: Acquire electrical imaging logging images of the reservoir; Standardizing the electrical imaging logging image to obtain a standardized imaging image; converting the imaging image into a wellbore porosity image; Acquiring development information of the reservoir based on the wellbore circumferential porosity image; Based on the development information, determining whether the reservoir is an effective reservoir; If the reservoir is an effective reservoir, determining whether the reservoir has a water-bearing pore zone; If the water-containing pore zone exists in the reservoir, the fluid properties of the reservoir are determined based on the water saturation of the water-containing pore zone.

2. The method according to claim 1, characterized in that The step of normalizing the electrical imaging logging image to obtain a standardized imaging image includes: The data of each plate in the electrical imaging logging image is scaled to a grayscale of 0-255 to obtain a standardized imaging image.

3. The method according to claim 1, characterized in that The step of converting the image into a wellbore porosity image comprises: Obtain conventional well logging curves; Determining the water saturation of the flushing zone based on the conventional well logging curve; Apparent porosity is calculated based on the water saturation of the flushing zone and Archie's formula; Based on the apparent porosity, a wellbore peripheral apparent porosity image is constructed.

4. The method according to claim 1, wherein The determining whether the reservoir is an effective reservoir based on the development information includes: If the secondary pore zone of the reservoir is not developed, the reservoir is judged to be an ineffective reservoir; If the secondary pore zone is developed, the reservoir is judged to be an effective reservoir.

5. The method according to claim 1, wherein include: If the reservoir is an effective reservoir and there is no water-bearing pore zone, it is determined that the reservoir is a gas reservoir.

6. The method according to claim 1, characterized in that If the water-bearing pore zone exists in the reservoir, determining the fluid properties of the reservoir based on the water saturation of the water-bearing pore zone includes: If the water saturation of the water-containing pore zone is less than or equal to a first preset saturation, determining that the reservoir is a gas layer; If the water saturation of the water-bearing pore zone is greater than a first preset saturation and less than a second preset saturation, the reservoir is determined to be a gas-water layer; If the water saturation of the water-containing pore zone is greater than or equal to the second preset saturation, the reservoir is determined to be a water layer.

7. The method according to claim 1, characterized in that Also includes: Obtaining the total porosity and clay mineral volume percentage of the reservoir; The porosity of the secondary pore zone and the water-bearing pore zone is corrected for shale based on the total porosity and the clay mineral volume percentage.

8. A complex reservoir fluid property identification device, characterized in that: include: A first acquisition module is used to acquire electrical imaging logging images; A standardization module, used for standardizing the electrical imaging logging image to obtain a standardized imaging image; A conversion module, configured to convert the image into a wellbore porosity image; A second acquisition module is configured to acquire development information of the reservoir based on the wellbore circumferential porosity image; A first judgment module is used to judge whether the reservoir is a valid reservoir based on the development information; A second judgment module is configured to judge whether there is a water-bearing pore zone in the reservoir if the reservoir is a valid reservoir; The determination module is configured to determine the fluid properties of the reservoir based on the water saturation of the water-containing pore zone if the water-containing pore zone exists in the reservoir.

9. An electronic device, characterized in that: include: A memory and a processor, wherein a computer program is stored in the memory, and when the computer program is executed by the processor, the method according to any one of claims 1 to 7 is executed.

10. A storage medium, characterized in that: The computer program stored in the storage medium can be executed by one or more processors and can be used to implement the method according to any one of claims 1 to 7.

Images