Residual oil distribution determination method and device for deepwater turbidite reservoir

Abstract

The invention provides a remaining oil distribution determination method and device for a deepwater turbidite oil reservoir, and relates to the technical field of deepwater turbidite oil reservoir development. The method comprises the steps that geological deposition characteristics of deepwater turbidite are obtained; performing quality analysis on the seismic data volume of the deepwater turbidite and performing feasibility analysis on development of the deepwater turbidite reservoir according to geological deposition characteristics; if the quality analysis result is not less than a first threshold value and the feasibility analysis result is not less than a second threshold value, determining a representation data volume, a water drive front, a structural feature and an original oil-water interface of the deepwater turbidite reservoir; and determining the distribution characteristics of the remaining oil according to the representation data volume, the water drive front, the structural characteristics and the original oil-water interface. Thus, the sand body boundary of the deepwater turbidite reservoir is determined, then the distribution characteristics of the remaining oil are automatically determined, the efficiency and reliability of determining the distribution characteristics of the remaining oil are improved, and the distribution characteristics of the remaining oil can be visually obtained.

Description

Technical Field

[0001] This invention relates to the field of deep-water turbidite reservoir development technology, and more specifically, to a method and apparatus for determining the distribution of remaining oil in deep-water turbidite reservoirs. Background Technology

[0002] Deepwater turbidites, as an important research area in deepwater oil and gas exploration and development, have always been a hot topic in global oil and gas exploration and development. Deepwater turbidite reservoirs have large reserves and good reservoir properties, but the reservoirs are highly heterogeneous, and the distribution of remaining oil in the reservoir is difficult to describe in detail during the development process, which restricts the efficient development of deepwater turbidite reservoirs. Therefore, determining the distribution of remaining oil is particularly important.

[0003] Currently, the main methods for determining the distribution of remaining oil include development geology methods, core observation, description and analysis testing methods, well logging interpretation methods for water-flooded layers, four-dimensional seismic methods, various mathematical and statistical methods, reservoir numerical simulation methods, dynamic monitoring and analysis methods, reservoir engineering methods, and well test interpretation methods. Among these, four-dimensional seismic technology is one of the effective means to monitor deep-water turbidite reservoirs and find the distribution of remaining oil and gas.

[0004] In existing technologies, there are two methods for determining the distribution of remaining oil using four-dimensional seismic methods. The first is a comprehensive manual interpretation method, which combines geological data, four-dimensional seismic attribute difference analysis, and reservoir development dynamics to predict the distribution of remaining oil. The second is a method based on reservoir numerical simulation to predict the distribution of remaining oil. Neither of these methods can determine the sand body boundaries of deep-water turbidite reservoirs, nor can they automatically determine the distribution of remaining oil.

[0005] To address the problems of existing technologies, this invention provides a method and apparatus for determining the distribution of residual oil in deep-water turbidite reservoirs. Summary of the Invention

[0006] To address the problems of existing technologies, this invention provides a method and apparatus for determining the remaining oil distribution in deep-water turbidite reservoirs, the method comprising:

[0007] To obtain the geological sedimentary characteristics of deep-water turbidites;

[0008] Based on the geological and sedimentary characteristics, a quality analysis of the seismic data volume of the deep-water turbidite and a feasibility analysis of the development of deep-water turbidite reservoirs were conducted.

[0009] If the quality analysis result is not less than the first threshold and the feasibility analysis result is not less than the second threshold, then the characterization data volume, water drive front, structural features and original oil-water interface of the deep-water turbidite reservoir are determined; wherein, the characterization data volume is used to characterize the characteristic parameters of the sand body boundary;

[0010] The distribution characteristics of the remaining oil are determined based on the characterization data, the water-drive front, the structural features, and the original oil-water interface.

[0011] According to an embodiment of the present invention, the characterization data volume is determined by the following steps:

[0012] Obtain the dominant offset and imaging data volume of the deep-water turbidite reservoir;

[0013] Based on the dominant offset and the imaging data volume, the seismic lithology data volume is determined;

[0014] Calculate the variance of the seismic lithology data volume and identify the sand body boundaries of the deep-water turbidite reservoir;

[0015] Determine the distribution characteristics of the amplitude variance in the variance volume to generate the characterization data volume.

[0016] According to an embodiment of the present invention, the seismic lithology data volume is determined by the following steps:

[0017] The advantageous offset distance is superimposed on the imaging data volume;

[0018] The superimposed results are subjected to Hilbert transformation to obtain the seismic lithology data volume.

[0019] According to an embodiment of the present invention, the variance body is obtained through the following steps:

[0020] The variance volume is calculated using the target formula;

[0021] The target formula is as follows:

[0022]

[0023] w = sinθ (0 ≤ θ ≤ 90) 0 ;0≤w≤1)

[0024] in, The variance of sampling points in the seismic trace near the well; The weighted variance of sampling points in the seismic trace near the well; x ij The earthquake amplitude value at time j, i-th channel; The average seismic amplitude of I samples at time j; i refers to the number of adjacent traces required to calculate the variance; L refers to the time window length for variance calculation; w j-t This refers to the triangular weighting function of the sampling points within the target time window, with a maximum value of 1 and a minimum value of 0.

[0025] According to one embodiment of the present invention, the water drive leading edge is determined by the following steps:

[0026] Select four-dimensional seismic data that are sensitive to the water content of the deep-water turbidite reservoir, including basic seismic data and monitoring seismic data;

[0027] Based on the basic seismic data, the monitored seismic data, and the imaging data volume, a feature data volume is determined;

[0028] The distribution characteristics of the feature data volume are determined to identify the water-drive leading edge.

[0029] According to an embodiment of the present invention, the feature data body is determined by the following steps:

[0030] Based on the basic seismic data, the monitored seismic data, and the imaging data volume, a four-dimensional seismic difference data volume is determined;

[0031] The feature data volume is obtained by performing a Hilbert transform on the four-dimensional seismic difference data volume.

[0032] According to an embodiment of the present invention, the four-dimensional seismic differential data volume is determined through the following steps:

[0033] The basic seismic data and the imaging data volume are superimposed to obtain the first four-dimensional seismic data volume;

[0034] The monitored seismic data and the imaging data volume are superimposed to obtain the second four-dimensional seismic data volume;

[0035] The difference between the amplitudes corresponding to the second four-dimensional seismic data volume and the first four-dimensional seismic data volume is calculated to obtain the four-dimensional seismic difference data volume.

[0036] According to one embodiment of the present invention, the method further includes: deploying infill wells in the target area of ​​the remaining oil distribution.

[0037] According to another aspect of the invention, a storage medium is also provided, comprising a series of instructions for performing the steps of the method as described in any of the preceding claims.

[0038] According to another aspect of the invention, an apparatus for determining the remaining oil distribution in deep-water turbidite reservoirs is also provided, performing the method as described in any of the preceding claims, the apparatus comprising:

[0039] The acquisition module is used to acquire the geological sedimentary characteristics of deep-water turbidites;

[0040] The analysis module is used to perform quality analysis on the seismic data volume of the deep-water turbidite and feasibility analysis on the development of deep-water turbidite reservoirs based on the geological sedimentary characteristics.

[0041] The first determining module is used to determine the characterization data volume, water drive front, structural features, and original oil-water interface of the deep-water turbidite reservoir if the quality analysis result is not less than a first threshold and the feasibility analysis result is not less than a second threshold; wherein, the characterization data volume is used to characterize the characteristic parameters of the sand body boundary;

[0042] The second determining module is used to determine the distribution characteristics of the remaining oil based on the characterization data volume, the water-drive front, the structural features, and the original oil-water interface.

[0043] This invention provides a method and apparatus for determining the remaining oil distribution in deep-water turbidite reservoirs, which has the following advantages compared with the prior art:

[0044] This invention first analyzes the quality of deep-water turbidites and the feasibility of their oil reservoirs based on their geological sedimentary characteristics. If the quality analysis result is not less than a first threshold and the feasibility analysis result is not less than a second threshold, then the quality of the deep-water turbidites and the feasibility of developing the oil reservoirs are guaranteed. Next, it determines the characteristic parameters used to characterize sand body boundaries, water drive fronts, structural features, and original oil-water interfaces in the deep-water turbidite reservoirs to determine the distribution characteristics of remaining oil. This approach, on the one hand, determines the sand body boundaries of the deep-water turbidite reservoirs, thereby automatically determining the distribution characteristics of remaining oil, improving the efficiency and reliability of this determination. On the other hand, it provides a direct view of the remaining oil distribution characteristics, offering a reliable basis for optimizing development plans for deep-water turbidite reservoirs and effectively improving the recovery rate. It also provides reliable information on the distribution of remaining oil in the reservoir for infill well deployment and optimization of oilfield development plans. Furthermore, it determines the distribution characteristics of remaining oil without the need for a reservoir model, improving the convenience of this determination.

[0045] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the description, claims, and drawings. Attached Figure Description

[0046] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with the embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0047] Figure 1 A flowchart of a method for determining the remaining oil distribution in deep-water turbidite reservoirs according to an embodiment of the present invention is shown;

[0048] Figure 2(a) shows a schematic diagram of quality analysis of seismic data volume according to an embodiment of the present invention;

[0049] Figure 2(b) shows a schematic diagram of quality analysis of seismic data volume according to yet another embodiment of the present invention;

[0050] Figure 3 A top structural diagram of a deep-water turbidite reservoir according to an embodiment of the present invention is shown;

[0051] Figure 4 A distribution characteristic map of residual oil according to an embodiment of the present invention is shown;

[0052] Figure 5 A schematic diagram of the sand body boundary of a deep-water turbidite reservoir according to an embodiment of the present invention is shown;

[0053] Figure 6 A distribution feature diagram of the feature data volume according to an embodiment of the present invention is shown;

[0054] Figure 7 A schematic diagram showing the response parameter characteristics of a cryptographic well according to an embodiment of the present invention is provided.

[0055] Figure 8 A schematic diagram showing the production dynamics of a cryptographic well according to an embodiment of the present invention is provided.

[0056] Figure 9 A block diagram of an apparatus for determining the remaining oil distribution in deep-water turbidite reservoirs according to an embodiment of the present invention is shown.

[0057] In the accompanying drawings, the same parts use the same reference numerals. Also, the drawings are not drawn to scale. Detailed Implementation

[0058] To make the objectives, technical solutions, and advantages of the present invention clearer, the embodiments of the present invention will be further described in detail below with reference to the accompanying drawings.

[0059] Existing technologies (Application of Time-lapse Seismic Technology in Reservoir Monitoring – A Case Study of the West African Deepwater Fan A Oilfield) mention that, based on a combined dynamic and static approach and multi-dimensional integration, by comprehensively considering structural faults, reservoir structure, sedimentary facies, well patterns, and time-lapse seismic impedance differences, instances of remaining oil-rich areas can be identified. However, this existing technology cannot determine the sandbody boundaries of deepwater turbidite reservoirs, nor can it automatically determine the distribution of remaining oil.

[0060] The existing technology (CN117365429A) mentions a time-shift seismic prediction method for remaining oil, which includes: using seismic data acquired twice, combined with drilling sonic velocity and density logging curves from the same period as the two sets of measured seismic data, and employing a phase-controlled high-resolution time-shift seismic inversion method to predict the distribution of remaining oil. This existing technology involves reservoir parameter inversion techniques based on an initial model, which is relatively complex. Furthermore, this existing technology cannot determine the sand body boundaries of deep-water turbidite reservoirs, nor can it automatically determine the distribution of remaining oil.

[0061] To address the aforementioned deficiencies in the prior art, this invention provides a method and apparatus for determining the remaining oil distribution in deep-water turbidite reservoirs. Figure 1 A flowchart of a method for determining the remaining oil distribution in deep-water turbidite reservoirs according to an embodiment of the present invention is shown. The method includes:

[0062] S101, to obtain the geological sedimentary characteristics of deep-water turbidites;

[0063] S102, based on geological sedimentary characteristics, conduct quality analysis on seismic data of deep-water turbidite and feasibility analysis on the development of deep-water turbidite reservoirs;

[0064] S103, if the quality analysis result is not less than the first threshold and the feasibility analysis result is not less than the second threshold, then determine the characterization data volume, water drive front, structural features and original oil-water interface of the deep-water turbidite reservoir; wherein, the characterization data volume is used to characterize the characteristic parameters of the sand body boundary.

[0065] S104. Based on the characterization data volume, water-drive front, structural features, and original oil-water interface, the distribution characteristics of the remaining oil are determined.

[0066] For example, the first threshold and the second threshold can be determined according to the actual application scenario, and the present invention does not limit them.

[0067] This process involves analyzing seismic data from deep-water turbidite deposits to obtain their geological sedimentary characteristics. Based on these characteristics, a quality analysis of the seismic data volume is then performed, including analyzing the dominant frequency, bandwidth, and resolution. Figure 2(a) shows the amplitude profile of the seismic data volume, and Figure 2(b) shows its spectral analysis. Following this, a feasibility analysis for developing deep-water turbidite oil reservoirs can be conducted.

[0068] like Figure 3 The diagram shown is the top structural map of a deep-water turbidite reservoir. Figure 3It is known that the deep-water turbidite reservoir exhibits a turtle-back tectonic structure, with the reservoir mainly distributed in the high parts of the structure. The original oil-water interface of the deep-water turbidite reservoir can be determined using existing techniques. Subsequently, by fusing the characterization data volume, waterflood front, structural features, and original oil-water interface, a distribution map of the remaining oil can be obtained, as shown in the figure. Figure 4 As shown, to determine the distribution characteristics of the remaining oil, by Figure 4 It can be seen that the remaining oil is mainly distributed in the high parts of the structure and the low-structure area in the southeast, that is... Figure 4 The region corresponding to 0-15000.

[0069] This invention first analyzes the quality of deep-water turbidites and the feasibility of their oil reservoirs based on their geological sedimentary characteristics. If the quality analysis result is not less than a first threshold and the feasibility analysis result is not less than a second threshold, then the quality of the deep-water turbidites and the feasibility of developing the oil reservoirs are guaranteed. Next, it determines the characteristic parameters used to characterize sand body boundaries, water drive fronts, structural features, and original oil-water interfaces in the deep-water turbidite reservoirs to determine the distribution characteristics of remaining oil. This approach, on the one hand, determines the sand body boundaries of the deep-water turbidite reservoirs, thereby automatically determining the distribution characteristics of remaining oil, improving the efficiency and reliability of this determination. On the other hand, it provides a direct view of the remaining oil distribution characteristics, offering a reliable basis for optimizing development plans for deep-water turbidite reservoirs and effectively improving the recovery rate. It also provides reliable information on the distribution of remaining oil in the reservoir for infill well deployment and optimization of oilfield development plans. Furthermore, it determines the distribution characteristics of remaining oil without the need for a reservoir model, improving the convenience of this determination.

[0070] In one possible embodiment, the characterization data volume is determined through the following steps:

[0071] Obtain the dominant offset and imaging data volume of deep-water turbidite reservoirs;

[0072] Based on the dominant offset and imaging data volume, the seismic lithology data volume is determined;

[0073] Calculate the variance volume of the seismic lithology data volume and identify the sand body boundaries of deep-water turbidite reservoirs;

[0074] Determine the distribution characteristics of amplitude variance in the variance volume to generate a characterization data volume.

[0075] In this process, the dominant offset of the seismic data volume can be obtained by identifying the areas where seismic data is mainly concentrated in deep-water turbidite reservoirs. Alternatively, the deep-water turbidite reservoir can be imaged to obtain an imaging data volume. Then, the dominant offset and the imaging data volume are overlaid to determine the seismic lithology data volume, thereby predicting the distribution characteristics of sand bodies in deep-water turbidite reservoirs.

[0076] Next, an improved amplitude variance algorithm is applied to calculate the variance volume of the seismic lithology data and identify the sand body boundaries of deep-water turbidite reservoirs, such as... Figure 5 As shown, the sand body boundary corresponds to the region between 0.30 and 0.55. Then, the distribution characteristics of the amplitude variance in the variance volume can be determined by plotting the distribution feature map of the amplitude variance in the variance volume. Afterwards, the contour line algorithm (as shown in Equation 1) is applied to generate the characterization data volume.

[0077] F = F(x,y) Equation 1

[0078] Here, F refers to the data volume.

[0079] In this way, a characterization data volume is generated to characterize the sand body boundary, providing a basis for determining the distribution characteristics of the remaining oil.

[0080] In one possible embodiment, the seismic lithology data volume is determined through the following steps:

[0081] Superimpose the advantageous offset distance with the imaging data volume;

[0082] The superimposed results are subjected to Hilbert transformation to obtain the seismic lithology data volume.

[0083] The formula for the Hilbert transform is shown in Equation 2:

[0084]

[0085] Where x(t) refers to the superimposed real-valued function. The function after Hilbert transformation refers to the seismic lithology data volume.

[0086] In this way, based on the advantageous offset and imaging data volume, a seismic lithology data volume can be obtained, providing a basis for generating a characterization data volume.

[0087] In one possible embodiment, the variance body is obtained through the following steps:

[0088] Calculate the variance using the target formula;

[0089] The objective formula is:

[0090]

[0091] w = sinθ (0 ≤ θ ≤ 90) 0 Equation 5 (0≤w≤1)

[0092] in, The variance of sampling points in the seismic trace near the well; The weighted variance of sampling points in the seismic trace near the well; x ijThe earthquake amplitude value at time j, i-th channel; The average seismic amplitude of I samples at time j; i refers to the number of adjacent traces required to calculate the variance; L refers to the time window length for variance calculation; w j-t This refers to the triangular weighting function of the sampling points within the target time window, with a maximum value of 1 and a minimum value of 0.

[0093] Equations 3, 4, and 5 can be used to calculate the variance of each sampling point in the entire three-dimensional data volume, and finally obtain the three-dimensional variance data volume.

[0094] In this way, the variance volume was calculated using the objective formula, providing a basis for generating the characterization data volume.

[0095] In one possible embodiment, the water drive leading edge is determined by the following steps:

[0096] Select four-dimensional seismic data that are sensitive to water content in deep-water turbidite reservoirs. The four-dimensional seismic data includes basic seismic data and monitoring seismic data.

[0097] Based on basic seismic data, monitoring seismic data, and imaging data volumes, characteristic data volumes are determined;

[0098] Determine the distribution characteristics of the feature data volume to identify the water drive front.

[0099] Among them, a distribution feature map of the feature data volume can be drawn, such as Figure 6 As shown, to determine the distribution characteristics of the feature data volume, a characteristic color palette representing the feature data volume can be used in the distribution feature map. Next, the locations of abrupt changes in water saturation within the feature data volume can be identified as the water drive front, for example... Figure 6 The position corresponding to 60,000-70,000. Additionally, by... Figure 6 It can be seen that the water body advances from the lower structural part to the higher structural part along the fault and sand body dominant channels.

[0100] This identified the waterflood front of deep-water turbidite reservoirs, providing a basis for determining the distribution characteristics of the remaining oil.

[0101] In one possible embodiment, the feature data body is determined through the following steps:

[0102] Based on basic seismic data, monitoring seismic data, and imaging data volumes, a four-dimensional seismic differential data volume is determined.

[0103] The characteristic data volume is obtained by performing a Hilbert transform on the four-dimensional seismic difference data volume.

[0104] The feature data volume is used to characterize the differences in reservoir parameters caused by fluid variations during the development of deep-water turbidite reservoirs. For example, the feature data volume can be obtained based on Equation 6:

[0105] A H-diff =A diff *H[x(t)] Equation 6

[0106] Among them, A H-diff Refers to the feature data body; A diff H[x(t)] refers to the four-dimensional seismic differential data volume; H[x(t)] refers to the Hilbert transform.

[0107] In this way, the characteristic data volume of deep-water turbidite reservoirs can be determined, providing a basis for identifying the waterdrive front.

[0108] In one possible implementation, the four-dimensional seismic differential data volume is determined through the following steps:

[0109] The basic seismic data and imaging data volume are superimposed to obtain the first four-dimensional seismic data volume;

[0110] By overlaying the monitored seismic data and the imaging data, a second four-dimensional seismic data volume is obtained.

[0111] The difference between the amplitudes corresponding to the second four-dimensional seismic data volume and the first four-dimensional seismic data volume is calculated to obtain the four-dimensional seismic difference data volume.

[0112] For example, based on Equation 7, a four-dimensional seismic differential data volume can be obtained:

[0113] A diff =A moni -A base Formula 7

[0114] Among them, A moni Refers to the second- or fourth-dimensional seismic data volume; A base Refers to the first four-dimensional seismic data volume.

[0115] In this way, the four-dimensional seismic data volume can be determined, providing a basis for determining the water drive front.

[0116] In one possible embodiment, the method further includes deploying infill wells in the target area of ​​the remaining oil distribution.

[0117] In this regard, infill wells can be deployed in the target area where the remaining oil is distributed, such as deploying a sidetracked infill well P-303st1 in the structural high part of the remaining oil distribution area. Figure 7 The diagram shown illustrates the response parameter characteristics of the encrypted well. Figure 7 It is known that the drilling encountered a sand body of 160 meters; if Figure 8 The diagram shown illustrates the production dynamics of the infill well. Figure 8 It can be seen that the infiltrated well produced 7,200 barrels of crude oil per day, achieving excellent production results and strongly demonstrating the effectiveness of the method.

[0118] In this way, after determining the distribution of remaining oil, reliable information on the distribution of remaining oil in the reservoir can be provided for infill well deployment and optimization of oilfield development plans.

[0119] The present invention provides a method for determining the remaining oil distribution in deep-water turbidite reservoirs, which can also be used in conjunction with a computer-readable storage medium. The storage medium stores a computer program, which is executed to run the method for determining the remaining oil distribution in deep-water turbidite reservoirs. The computer program is capable of executing computer instructions, which include computer program code. The computer program code can be in the form of source code, object code, executable file, or some intermediate form.

[0120] Computer-readable storage media can include: any entity or device capable of carrying computer program code, recording media, USB flash drives, portable hard drives, magnetic disks, optical disks, computer memory, read-only memory (ROM), random access memory (RAM), electrical carrier signals, telecommunication signals, and software distribution media, etc.

[0121] It should be noted that the contents of computer-readable storage media may be appropriately added to or subtracted from the contents according to the requirements of legislation and patent practice in a jurisdiction. For example, in some jurisdictions, according to legislation and patent practice, computer-readable storage media may not include electrical carrier signals and telecommunication signals.

[0122] According to another aspect of the present invention, an apparatus for determining the remaining oil distribution in deep-water turbidite reservoirs is also provided, which performs a method for determining the remaining oil distribution in deep-water turbidite reservoirs. Figure 9 A block diagram of a device for determining the remaining oil distribution in deep-water turbidite reservoirs according to an embodiment of the present invention is shown. The device includes:

[0123] Module 510 is used to acquire the geological sedimentary characteristics of deep-water turbidites;

[0124] Analysis module 520 is used to perform quality analysis on seismic data volumes of deep-water turbidite rocks and feasibility analysis on the development of deep-water turbidite reservoirs based on geological sedimentary characteristics.

[0125] The first determination module 530 is used to determine the characterization data volume, water drive front, structural features and original oil-water interface of deep-water turbidite reservoir if the quality analysis result is not less than the first threshold and the feasibility analysis result is not less than the second threshold; wherein, the characterization data volume is used to characterize the characteristic parameters of the sand body boundary.

[0126] The second determining module 540 is used to determine the distribution characteristics of the remaining oil based on the characterization data volume, the water drive front, structural features, and the original oil-water interface.

[0127] In summary, this invention provides a method and apparatus for determining the distribution of remaining oil in deep-water turbidite reservoirs, which has the following advantages compared with the prior art:

[0128] This invention first analyzes the quality of deep-water turbidites and the feasibility of their oil reservoirs based on their geological sedimentary characteristics. If the quality analysis result is not less than a first threshold and the feasibility analysis result is not less than a second threshold, then the quality of the deep-water turbidites and the feasibility of developing the oil reservoirs are guaranteed. Next, it determines the characteristic parameters used to characterize sand body boundaries, water drive fronts, structural features, and original oil-water interfaces in the deep-water turbidite reservoirs to determine the distribution characteristics of remaining oil. This approach, on the one hand, determines the sand body boundaries of the deep-water turbidite reservoirs, thereby automatically determining the distribution characteristics of remaining oil, improving the efficiency and reliability of this determination. On the other hand, it provides a direct view of the remaining oil distribution characteristics, offering a reliable basis for optimizing development plans for deep-water turbidite reservoirs and effectively improving the recovery rate. It also provides reliable information on the distribution of remaining oil in the reservoir for infill well deployment and optimization of oilfield development plans. Furthermore, it determines the distribution characteristics of remaining oil without the need for a reservoir model, improving the convenience of this determination.

[0129] Example 1: This invention takes a deep-water P oilfield in West Africa as an example. The P oilfield is a four-sided plunging (with a salt core) turtle-back structure. During the Miocene and Oligocene periods, salt movement and extensional forces resulted in highly developed faults and complex cutting relationships, making it a complex fault-block reservoir. The water depth is approximately 1100 meters. The main target is a Miocene deep-water turbidite reservoir. The reservoir sedimentary type is Tertiary deep-water channel turbidite system sedimentation, with turbidite sandstones distributed in channel sand and lobed patterns. The main source direction is southeast-northwest. This type of oil and gas reservoir is highly heterogeneous, with well-developed internal mudstone interlayers. The distribution of remaining oil in the later stages of development is unclear, hindering the efficient development of deep-water turbidite channel reservoirs. The relevant research was completed using this method, which studied the high-position residual oil in the K sand body group of the Miocene MM20. A sidetracking well, P-303, was deployed. The measured and production results were very good, with an initial daily crude oil production of 7,200 barrels, followed by a stable daily production of nearly 10,000 barrels. This example confirms the effectiveness of the technical method.

[0130] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should be extended to equivalent substitutions of these features as understood by those skilled in the art. It should also be understood that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting.

[0131] In the description of this invention, unless otherwise stated, "a plurality of" means two or more; the terms "upper," "lower," "left," "right," "inner," "outer," "front end," "rear end," "head," "tail," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, and are only for the convenience of describing the invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of the invention. Furthermore, the terms "first," "second," "third," etc., are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0132] In the description of this invention, it should be noted that, unless otherwise explicitly specified and limited, the terms "connected" and "linked" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0133] Certain terms are used throughout this application to refer to specific system components. As those skilled in the art will recognize, the same components may often be referred to by different names, and therefore this application is not intended to distinguish those components that differ only in name and not in function. In this application, the terms “comprise,” “include,” and “have” are used in an open-ended manner and should therefore be interpreted as meaning “including, but not limited to…”. Furthermore, the terms “substantially,” “materially,” or “approximately” as used herein refer to industry-accepted tolerances for the corresponding terms. The term “coupling,” as may be used herein, includes direct coupling and indirect coupling via additional components, elements, circuits, or modules, wherein, for indirect coupling, the intermediate component, element, circuit, or module does not alter the information of the signal but may adjust its current level, voltage level, and / or power level. Inferred coupling (e.g., one element is inferredly coupled to another element) includes direct and indirect coupling between two elements in the same manner as “coupling.”

[0134] The phrase "an embodiment" or "an embodiment" used in this specification means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Therefore, the phrase "an embodiment" or "an embodiment" appearing in various places throughout the specification does not necessarily refer to the same embodiment.

[0135] The embodiments of the present invention are given for illustrative and descriptive purposes only, and are not intended to be exhaustive or to limit the invention to the forms disclosed. Many modifications and variations will be apparent to those skilled in the art. The embodiments were chosen and described in order to better illustrate the principles and practical application of the invention, and to enable those skilled in the art to understand the invention and to design various embodiments with various modifications suitable for a particular purpose.

[0136] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and variations in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection for this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A method for determining the remaining oil distribution in deep-water turbidite reservoirs, characterized in that, The method includes: To obtain the geological sedimentary characteristics of deep-water turbidites; Based on the geological and sedimentary characteristics, a quality analysis of the seismic data volume of the deep-water turbidite and a feasibility analysis of the development of deep-water turbidite reservoirs were conducted. If the quality analysis result is not less than the first threshold and the feasibility analysis result is not less than the second threshold, then the characterization data volume, water drive front, structural features and original oil-water interface of the deep-water turbidite reservoir are determined; wherein, the characterization data volume is used to characterize the characteristic parameters of the sand body boundary; The distribution characteristics of the remaining oil are determined based on the characterization data, the water-drive front, the structural features, and the original oil-water interface.

2. The method as described in claim 1, characterized in that, The characterization data volume is determined through the following steps: Obtain the dominant offset and imaging data volume of the deep-water turbidite reservoir; Based on the dominant offset and the imaging data volume, the seismic lithology data volume is determined; Calculate the variance of the seismic lithology data volume and identify the sand body boundaries of the deep-water turbidite reservoir; Determine the distribution characteristics of the amplitude variance in the variance volume to generate the characterization data volume.

3. The method as described in claim 2, characterized in that, The seismic lithology data volume is determined through the following steps: The advantageous offset distance is superimposed on the imaging data volume; The superimposed results are subjected to Hilbert transformation to obtain the seismic lithology data volume.

4. The method as described in claim 2 or 3, characterized in that, The variance body is obtained through the following steps: The variance volume is calculated using the target formula; The target formula is as follows: w=sinθ(0≤θ≤90 0 ;0≤w≤1) in, The variance of sampling points in the seismic trace near the well; The weighted variance of sampling points in the seismic trace near the well; x ij The earthquake amplitude value at time j, i-th channel; The average seismic amplitude of I samples at time j; i refers to the number of adjacent traces required to calculate the variance; L refers to the time window length for variance calculation; w j-t This refers to the triangular weighting function of the sampling points within the target time window, with a maximum value of 1 and a minimum value of 0.

5. The method according to any one of claims 2-4, characterized in that, The water-drive leading edge is determined by the following steps: Select four-dimensional seismic data that are sensitive to the water content of the deep-water turbidite reservoir, including basic seismic data and monitoring seismic data; Based on the basic seismic data, the monitored seismic data, and the imaging data volume, a feature data volume is determined; The distribution characteristics of the feature data volume are determined to identify the water-drive leading edge.

6. The method as described in claim 5, characterized in that, The feature data body is determined through the following steps: Based on the basic seismic data, the monitored seismic data, and the imaging data volume, a four-dimensional seismic difference data volume is determined; The feature data volume is obtained by performing a Hilbert transform on the four-dimensional seismic difference data volume.

7. The method as described in claim 6, characterized in that, The four-dimensional seismic differential data volume is determined through the following steps: The basic seismic data and the imaging data volume are superimposed to obtain the first four-dimensional seismic data volume; The monitored seismic data and the imaging data volume are superimposed to obtain the second four-dimensional seismic data volume; The difference between the amplitudes corresponding to the second four-dimensional seismic data volume and the first four-dimensional seismic data volume is calculated to obtain the four-dimensional seismic difference data volume.

8. The method according to any one of claims 1-7, characterized in that, The method further includes deploying infiltration wells in the target area of ​​the remaining oil distribution.

9. A storage medium, characterized in that, It includes a series of instructions for performing the method steps as described in any one of claims 1-8.

10. A device for determining the distribution of remaining oil in deep-water turbidite reservoirs, characterized in that, The apparatus for performing the method as described in any one of claims 1-8 comprises: The acquisition module is used to acquire the geological sedimentary characteristics of deep-water turbidites; The analysis module is used to perform quality analysis on the seismic data volume of the deep-water turbidite and feasibility analysis on the development of deep-water turbidite reservoirs based on the geological sedimentary characteristics. The first determining module is used to determine the characterization data volume, water drive front, structural features, and original oil-water interface of the deep-water turbidite reservoir if the quality analysis result is not less than a first threshold and the feasibility analysis result is not less than a second threshold; wherein, the characterization data volume is used to characterize the characteristic parameters of the sand body boundary; The second determining module is used to determine the distribution characteristics of the remaining oil based on the characterization data volume, the water-drive front, the structural features, and the original oil-water interface.

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