Method and apparatus for quantitatively determining the water influx of a deep-seated dissolution body reservoir

Abstract

The application provides a method for quantitatively determining water inflow of a deep fault-dissolution body oil reservoir, which comprises the following steps: a water inflow direction determining step: according to the static connectivity analysis result of a well group to be analyzed, a water inflow direction result is obtained; a connectivity degree calculating step: the position of a bottom water and the position of a well perforation are determined, and then the initial value of a conductivity and a connected volume are set, and then the connectivity degree result of the well group to be analyzed at different production time points is calculated through production history matching; and a water inflow amount calculating step: the connectivity degree result obtained through normalization processing is combined with a water inflow amount calculation model to calculate the water inflow amount. The application uses the production dynamic data of an injection-production well group, performs fine history matching, quantitatively calculates the connectivity degree, calculates the water inflow amount distribution through normalized connectivity degree, proposes the treatment direction of the well group, forms the water inflow treatment and adjustment scheme of the injection-production well group, and realizes the differentiated and quantitative water inflow treatment of the fault-dissolution body oil reservoir injection-production well group.

Description

Technical Field

[0001] This invention relates to the field of carbonate rock fractured-dissolve reservoir development technology, and more specifically, to a method and apparatus for quantitatively determining the inflow water of deep fractured-dissolve reservoirs. Background Technology

[0002] Fractures and bottom water increase the complexity of water injection development in fault-collapsed reservoirs, significantly impacting the effectiveness of water injection development in deep fault-collapsed reservoirs. In the middle and late stages of fault-collapsed reservoir development, in order to maintain formation energy, it is necessary to transfer some poorly developed, high-water-cut wells for injection, which results in water injection advancing along a few transverse fractures into the wells.

[0003] Due to the complex reservoir properties and strong heterogeneity of deep fault-collapse reservoirs, indiscriminate water injection not only fails to achieve high production but also exacerbates the injection-production conflict, severely impacting well production and stability. Ensuring differentiated and balanced water injection across different layers and for each well is a key issue in the design of water injection for deep fault-collapse reservoirs. Furthermore, as fault-collapse reservoirs are developed, bottom water and injected water preferentially flow along certain channels, displacing the surrounding crude oil. After water breakthrough, the crude oil in the channels is replaced by formation water or injected water with lower flow resistance. These channels are then called water flow channels. Crude oil connected to these channels is difficult to continue being driven, forming a residual oil shielded by a high-conductivity channel. Subsequent water injection will result in the same amount flowing out as injected, at which point the well group is considered an ineffective or inefficient water injection well group.

[0004] It can be said that controlling and managing the flow of water in fractures directly controls the development effect of the entire fractured-collapse reservoir. Effectively reducing water channeling in fractures is the core technology for managing injection-production well groups in deep fractured-collapse reservoirs. A large part of the management work for injection-production well groups focuses on water control and water reduction, because reducing water production also improves the efficiency of water injection development to a certain extent.

[0005] Practice has shown that the effectiveness of water control is directly related to the direction, volume, and intensity of the incoming water. Therefore, it is necessary to determine whether the water produced by the oil well comes from bottom water or artificially injected water. Only by determining the direction and volume of the incoming water, and calculating the intensity of the incoming water based on the direction and volume, can we determine the type, volume, and injection location of the plugging material, change the water flow channel, and displace the remaining oil, thereby maximizing the sweep efficiency and injection effect of the water.

[0006] The existing technology provides a system and method for calculating the increased discharge volume based on water diversion and water conservation measures (CN103413034A), which includes a data management module, a data standardization module, an increased discharge volume calculation module, and a calculation result output and display module.

[0007] The existing method for forecasting reservoir inflow (CN103164628A) discloses a method for continuously smoothing segmented flow forecast data at time nodes. First, the minimum time and maximum time period of the required flow are determined. Then, the integral distribution of the segmented forecast data along the interval is obtained by cumulative summation. Subsequently, spline interpolation is performed on the integrated data to obtain the function distribution of the integral over the interval. Finally, the derivative of the function at each time point is obtained to obtain the forecasted inflow process line.

[0008] The prior art, a regional water resources optimization allocation method based on the MAEPSO algorithm (CN106529166A), proposes a regional water resources optimization allocation method based on the MAEPSO algorithm, which realizes global optimization, improves computational efficiency, and meets the calculation requirements of multi-objective optimal allocation schemes of selected water resources systems.

[0009] It can be seen that the existing technology does not involve the relevant technical content on the method for determining the water inflow of deep fault-collapse reservoirs. In view of the above situation, the present invention provides a method and apparatus for quantitatively determining the water inflow of deep fault-collapse reservoirs. Summary of the Invention

[0010] To address the above problems, this invention provides a method for quantitatively determining the inflow water of deep fractured-dissolved reservoirs, the method comprising:

[0011] Steps for determining the direction of incoming water: Based on the static connectivity analysis results of the well group to be analyzed, the direction of incoming water is obtained;

[0012] Connectivity calculation steps: Determine the bottom water location and oil well perforation location, set the initial values ​​of conductivity and connectivity volume, and calculate the connectivity results of the well group to be analyzed at different production times by fitting the production history.

[0013] Water inflow calculation steps: Based on the connectivity results obtained after normalization, the water inflow is calculated using the water inflow calculation model.

[0014] According to an embodiment of the present invention, the step of determining the direction of incoming water specifically includes the following steps:

[0015] Data collection and analysis steps: Select injection-production well groups with fault-collapsed reservoir geological background as candidate well groups, collect production dynamic data and seismic data of the candidate well groups, and obtain historical production data after removing abnormal data points.

[0016] According to an embodiment of the present invention, the step of determining the direction of incoming water specifically includes the following steps:

[0017] Static connectivity analysis steps: Based on the seismic data in the historical production data, the reservoir group of the candidate well group is sculpted, the static connectivity between the reservoir groups is analyzed, and the static connectivity analysis results are obtained.

[0018] According to an embodiment of the present invention, the step of determining the direction of incoming water specifically includes the following steps:

[0019] Well group determination steps: Based on the production dynamic data in the historical production data, conduct production dynamic analysis of the candidate well groups, determine whether the candidate well groups are connected, delete the disconnected well numbers, and determine the well groups to be analyzed.

[0020] According to an embodiment of the present invention, the analysis to obtain the direction of incoming water specifically includes the following steps:

[0021] Based on the static connectivity analysis results, the communication between the reservoir and the bottom water is analyzed to determine the main connected oil and water wells, clarify the possible main water inflow direction, and determine whether the inflow is mainly bottom water, injected water, or both.

[0022] According to one embodiment of the present invention, the connectivity results include, but are not limited to, the conductivity and connectivity volume between the injection well and the production well, between the production well and the bottom water.

[0023] According to one embodiment of the present invention, the water inflow calculation model includes the following formula:

[0024] Q in =Q out *A ijz *T ijz

[0025] Among them, Q in Q represents the water inflow. out A represents the cumulative liquid volume produced in a given stage. ijz T represents conductivity. ijz The connected volume is represented by , where i represents a water injection well, j represents an oil production well, and z represents bottom water.

[0026] According to one embodiment of the present invention, the method further includes:

[0027] Water management steps: Based on the results of the incoming water direction and the incoming water volume, propose water management measures and plans.

[0028] According to another aspect of the invention, a storage medium is also provided, which includes a series of instructions for performing the steps of the method described in any of the preceding claims.

[0029] According to another aspect of the present invention, an apparatus for quantitatively determining the inflow water of a deep fractured-collapse reservoir is also provided, which performs the method for quantitatively determining the inflow water of a deep fractured-collapse reservoir as described in any of the preceding claims, the apparatus comprising:

[0030] The water inflow direction determination module is used to analyze and obtain the water inflow direction result based on the static connectivity analysis results of the well group to be analyzed;

[0031] The connectivity calculation module is used to determine the bottom water location and the oil well perforation location. After setting the initial values ​​of conductivity and connectivity volume, it calculates the connectivity results of the well group under analysis at different production times by fitting the production history.

[0032] The water inflow calculation module is used to calculate the water inflow based on the connectivity results obtained after normalization and the water inflow calculation model.

[0033] The method and apparatus for quantitatively determining the inflow of water into deep fault-collapse reservoirs provided by this invention utilize the production dynamic data of injection-production well groups. Through precise historical fitting, the connectivity degree is quantitatively calculated. After normalizing the connectivity degree, the water inflow distribution is calculated. Based on this, the well group management direction is proposed, and a water inflow management and adjustment scheme for the injection-production well group is formed. This realizes differentiated and quantitative water inflow management of injection-production well groups in fault-collapse reservoirs, providing a method for water flooding management and oil production enhancement and water reduction in fault-collapse reservoirs.

[0034] 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

[0035] 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:

[0036] Figure 1 A flowchart of a method for quantitatively determining the inflow water of a deep fractured-dissolved reservoir according to an embodiment of the present invention is shown;

[0037] Figure 2 A flowchart of a method for quantitatively determining the inflow water of a deep fractured-dissolve reservoir according to another embodiment of the present invention is shown;

[0038] Figure 3 This shows a comprehensive development curve of the TH12120 well group according to an embodiment of the present invention;

[0039] Figure 4This image shows the reservoir engraving results of the TH12120 well group according to an embodiment of the present invention;

[0040] Figure 5 The image shows the fracture tracking and identification results of the TH12120 well group according to an embodiment of the present invention;

[0041] Figure 6 The figure showing the calculation results of the inter-well conductivity of the TH12120 well group according to an embodiment of the present invention is illustrated.

[0042] Figure 7 The figure shows the calculation results of the inter-well connectivity volume of the TH12120 well group according to an embodiment of the present invention;

[0043] Figure 8 The diagram shows the water inflow distribution of the TH12120 well group according to an embodiment of the present invention.

[0044] Figure 9 This diagram shows the integrated development curve of the TH12437X well group according to an embodiment of the present invention;

[0045] Figure 10 The image shows the reservoir engraving and fracture tracing results of the TH12437X well group according to an embodiment of the present invention;

[0046] Figure 11 This figure shows the calculation results of the inter-well connectivity of the TH12437X well group according to an embodiment of the present invention;

[0047] Figure 12 A water inflow distribution diagram of the TH12437X well group according to an embodiment of the present invention is shown; and

[0048] Figure 13 A block diagram of an apparatus for quantitatively determining the inflow water of a deep fractured solution reservoir according to an embodiment of the present invention is shown. Detailed Implementation

[0049] To make the objectives, technical solutions, and advantages of the present invention clearer, the embodiments of the present invention will be described in further detail below with reference to the accompanying drawings.

[0050] The development of high-angle fractures is the main geological feature of deep fault-dissolved bodies in the northern margin of the Tarim Basin, such as the Tarim River periphery and Shunbei. After the strata reach a certain depth, the development of horizontal fractures is significantly lower than that of high-angle fractures. The description results of deep fault-dissolved oil reservoirs such as Shunbei also confirm that high-angle fractures account for more than 72% of deep fault-dissolved oil reservoirs. The development of reservoirs is mainly controlled by fractures. Among them, the collapse forming a small number of caves, the collapse of rock blocks forming part of breccia fractures, and the large number of structural fractures in the fracture fracture zone are the three main types of reservoir spaces. Due to the subordination relationship between fractures and fractures, the development of fractures is controlled by the fracture development law. The direction of fractures is basically consistent with the direction of fractures. Fractures not only serve as flow channels for carbonate oil and gas reservoirs, but are also one of the main types of reservoir spaces (Lu Xinbian, Hu Wenge, Wang Yan, et al. Characteristics and development practice of carbonate fault-dissolved oil reservoirs in Tarim River area [J]. Petroleum and Gas Geology, 2015, 36(3): 347-09).

[0051] Bottom water development is another important geological feature of deep fault-dissolved reservoirs. Studies have confirmed that the volume of bottom water in the northern margin of the Tarim Basin is generally ten to several tens of times that of the reserves. Bottom water development saves water injection costs and ensures the formation energy and the effect of depletion-type development. On the other hand, a large number of high-angle fractures develop in the deep part of the reservoir and communicate with the bottom water. Due to the high energy and large volume of bottom water, severe water channeling occurs along the high-angle fractures, causing rapid water breakthrough in oil wells and directly reducing the development effect of fault-dissolved reservoirs (Tang Hai, He Juan, Rong Yuanshuai, Li Xiaobo, Typical fault-dissolved reservoir water injection displacement law and residual oil distribution characteristics [J], Oil and Gas Geology and Recovery, 2018, 25(3):95-06). Making full use of the dual role of bottom water energy has always been a difficult and hot issue in the development of bottom water reservoirs.

[0052] Fractures and bottom water increase the complexity of water injection development in fractured-dissolve reservoirs, greatly affecting the effectiveness of water injection development in deep fractured-dissolve reservoirs. In the middle and late stages of fractured-dissolve reservoir development, in order to maintain formation energy, it is necessary to transfer some poorly developed, high-water-cut wells for injection. This results in water injection pointing towards the wells along a few transverse fractures (Liu Baozeng, Qi Lixin, Li Zongjie, et al. Spatial carving and quantitative description technology of ultra-deep fractured-dissolve reservoirs in Shunbei area [J]. Acta Petrolei Sinica, 2020, 40(4):412-09). Due to the complex reservoir properties and strong heterogeneity of deep fractured-dissolve reservoirs, indiscriminate water injection not only fails to achieve high production, but also exacerbates the contradiction between injection and production, seriously affecting the production and stable production capacity of wells. Ensuring differentiated and balanced water injection in each layer and each well is the key issue in the design of water injection for deep fractured-dissolve reservoirs. In addition, as the development of fractured-dissolve reservoirs progresses, bottom water and injected water preferentially flow along certain channels, displacing the crude oil around the channels.

[0053] After water is encountered in an oil well, the crude oil in the channel is replaced by formation water or injected water with lower flow resistance. This channel is called the water flow channel. Afterward, the crude oil connected to the water flow channel is difficult to continue to be driven, forming a residual oil shielded by a high conductivity channel. As a result, the amount of water injected will flow out as well. At this point, the well group is called an ineffective or inefficient water injection well group.

[0054] It can be said that controlling and managing the flow of water in fractures directly controls the development effect of the entire fractured-collapse reservoir. Effectively reducing water channeling in fractures is the core technology for managing injection-production well groups in deep fractured-collapse reservoirs. A large part of the management work for injection-production well groups focuses on water control and water reduction, because reducing water production also improves the efficiency of water injection development to a certain extent.

[0055] Practice has shown that the effectiveness of water control is directly related to the direction, volume, and intensity of the incoming water. Therefore, it is necessary to determine whether the water produced by the oil well comes from bottom water or artificially injected water. Only by determining the direction and volume of the incoming water, and calculating the intensity of the incoming water based on the direction and volume, can we determine the type, volume, and injection location of the plugging material, change the water flow channel, and displace the remaining oil, thereby maximizing the sweep efficiency and injection effect of the water.

[0056] Furthermore, deep fault-collapse reservoirs with well-developed bottom water have limited development time and experience. Due to their unique geological characteristics, the vertical flow of oil and water is significantly stronger than in other directions. The strong bottom water energy and high-angle fractures create substantial development risks, manifesting as a sharp decline in development effectiveness once water is encountered in the wells. According to field statistics, the recovery rate of these reservoirs is mostly around 10%. A clear water flow channel and a large amount of residual oil exist between the bottom water body and the production well group. The potential of this residual oil is the material basis for the management of injection-production well groups.

[0057] From a production process perspective, the connectivity between oil wells and bottom water, and between oil wells and water wells, is a limiting factor for oil-water movement patterns, water cut rise patterns, and water drive recovery rates. Therefore, based on the connectivity between oil wells and natural and artificial water bodies, and by fitting the historical data of the well group, the differences in the direction, volume, and intensity of water inflow from oil wells are determined. Based on these water inflow analysis results, production optimization methods are used to further adjust the operating regimes of oil and water wells. Simultaneously, the type of water control measures is determined, and a water control plan is developed. While controlling and adjusting the water inflow between oil and water wells, the direction and intensity of oil-water flow are adjusted to achieve increased oil production. This approach reduces the workload of geological modeling and numerical simulation calculations, and allows for real-time adjustments to the operating regimes of oil and water wells, providing an feasible solution for the management of injection-production well groups in deep fault-collapsed reservoirs.

[0058] Determining the inflow of water includes its direction, volume, and intensity, with the intensity related to injection pressure and the thickness of the aquifer. Methods for determining oil well inflow mainly include numerical simulation, tracer methods, and reservoir engineering methods (TailaiWen, Marco R. Thiele, Waterflood Management using two-stage Optimization with Streamline Simulation[J]. Computational Geosciences.2014(3-4)). Numerical simulation requires establishing a suitable geological model, performing detailed reservoir production history fitting, and numerical simulation calculations to determine the volume of natural bottom water and artificially injected water. The drawback of this method is that it requires detailed geological modeling based on a deterministic reservoir description and fitting of the production history, resulting in a certain degree of uncertainty in the results. The tracer method involves injecting a certain volume of water-soluble tracer slug into the injection well, monitoring the relationship between the tracer and time in other wells around the well, and using specialized tracer simulation software to calculate the water injection splitting factor to assess the inflow rate and direction. However, this method cannot obtain bottom water data, thus having certain limitations. Reservoir engineering methods are mostly based on mass balance methods, establishing mathematical models suitable for reservoir characteristics. In calculating inflow rate or water injection splitting factor, reservoir engineering methods primarily consider the influence of vertical reservoir heterogeneity, with little consideration given to planar heterogeneity.

[0059] For reservoir engineering methods, there are many articles on calculating the water injection splitting coefficient or the inflow volume. A large portion of these studies focus on influencing factors, which mainly include permeability, connectivity coefficient, effective reservoir thickness, number of injection and production wells, intervention coefficients, and well spacing. These factors are categorized into three main types: geological factors, controllable factors, and comprehensive factors (Analytical Method to Predict Waterflood Performance [J]. MK(Val)Lerma, TroyConsulting, SPE83511, 2003, 5). This study uses grey relational analysis to analyze the influence of each factor on the water injection volume of each layer, identifying the main influencing factors to construct the splitting coefficient, thereby calculating the stratified injection volume. Clearly, the splitting of water injection volume, like the analysis of inflow volume from production wells, should be a three-dimensional problem, including both vertical and planar dimensions. The calculation of the vertical splitting coefficient, which changes to the reasonable injection volume of each layer, aims to ensure that the oilfield maintains a stratified injection-production balance during water injection development, achieving reasonable stratified injection allocation. The methods for calculating the splitting coefficient of the strata are mainly the effective thickness method (H method), the static splitting formation coefficient (Kh method), the water absorption profile coefficient method, the seepage resistance coefficient method, and the comprehensive multi-factor dynamic splitting coefficient method, etc. (Tang Shenglai, Wang Nutao, et al. Research on new methods for calculating the splitting coefficient of water injection wells, fault block oil and gas field [J]. 2006.13(5):43-45).

[0060] For multi-well formations with both water injection and production wells, there are three methods for calculating injection volume: the displaceable volume distribution method, the correction coefficient method, and the injection-production ratio method. The displaceable volume distribution method, proposed by J.L. Anthony et al., calculates the upper limit of the injection volume for the entire water injection development process based on the economic consumption required to maintain oilfield development and the limitations of the actual formation's injection and production capacity (J.L. Anthony, translated by Jin Peiqiang. Methods for Determining the Optimal Economic Injection Volume and Oil Production Volume for Large Multi-Well Formations [M]. Oil and Gas Field Development Engineering Translation Series. 1992). The correction coefficient method, proposed by China National Petroleum Corporation (CNPC) North China Petroleum Company based on field statistics, provides an in-depth analysis of the water injection patterns in different time periods for different types of oilfield water injection areas. Mathematical statistics were performed on factors such as water cut rise rate, production capacity of production wells, different characteristics of each water injection block, proportion of water-driven oil layer production, and time aging, and the calculation formula for injection volume was derived (Xie Xiaoqing, Jiang Hanqiao. Theory of Layered Water Distribution in Heterogeneous Reservoirs. Daqing Petroleum Geology and Development [J]. 2008.27(6):83-85). The injection-production ratio method assumes that the water injection section of the injection well will be connected with the production layers of oil wells in multiple directions. Therefore, the production volume of these multiple connected production layers is accumulated as the basis for the injection volume of the water injection well section (Zhang Yurong, Wang Haijun, et al. New progress and development trend of domestic layered water injection technology. Petroleum Drilling and Production Technology [J]. 2011.33(2):103-106).

[0061] The above analysis shows that reservoir engineering methods have certain limitations. The flow mathematical model assumes a material balance in the injection-production system, using bottom water intrusion and cumulative artificial water injection as inputs. Furthermore, it assumes the splitting coefficient is calculated using the same method for both injection processes, failing to consider that the influence of gravity is significantly greater than that of injected water during bottom water rise. This creates significant problems in obtaining the splitting coefficient from production dynamic data, making it impossible to distinguish between bottom water and artificial water injection. This greatly reduces the applicability of the method, as it cannot obtain quantifiable water inflow results.

[0062] Existing technologies, such as the water-drive development of multi-layer reservoirs inversion model (Zhao Hui, Kang Zhijiang, Sun Haitao, et al. Water-drive development of multi-layer reservoirs inversion model [J]. Petroleum and Gas Geology, 2016, 43(1): 99-08), have established a method for calculating well connectivity based on the flow tube method, which can obtain the well connectivity at different development stages in real time. However, the above existing technologies do not involve quantitatively determining the water inflow of deep fault-collapse reservoirs.

[0063] Based on the current state of existing technology, this invention utilizes dynamic production data of oil and water wells in deep fault-collapsed reservoirs. Through refined production history fitting, it conducts connectivity analysis and calculation between oil wells and bottom water bodies, and between oil and water wells, to obtain the degree of connectivity between them. The degree of connectivity is then used to calculate and analyze water inflow. Combined with the water cut distribution, it proposes water management recommendations for well groups, providing a basis for the management of inefficient water injection well groups.

[0064] Figure 1 A flowchart illustrating a method for quantitatively determining the inflow water of a deep fractured solution reservoir according to an embodiment of the present invention is shown.

[0065] like Figure 1 As shown, step S101 is the water inflow direction determination step: based on the static connectivity analysis results of the well group to be analyzed, the water inflow direction result is obtained.

[0066] The process of determining the direction of incoming water also includes data collection and analysis: selecting injection-production well groups with a fault-collapsed reservoir geological background as candidate well groups, collecting production dynamic data and seismic data from the candidate well groups, and obtaining historical production data after removing outlier data points. Specifically, removing outlier data points mainly involves data that suddenly changes within a short period of time in the production dynamic data. Such data may be due to human error and should be removed.

[0067] The process of determining the direction of incoming water also includes a static connectivity analysis step: based on seismic data from historical production data, reservoir sculpting is performed on candidate well groups, and the static connectivity between reservoir groups is analyzed to obtain static connectivity analysis results. Specifically, the static connectivity analysis results mainly indicate whether there is connectivity, and whether it is a fracture or a cavern connection.

[0068] The process of determining the direction of incoming water also includes a well group determination step: based on the production dynamic data in historical production data, conduct production dynamic analysis of candidate well groups to determine whether the candidate well groups are connected, delete disconnected well numbers, and determine the well group to be analyzed. Specifically, determining whether the candidate well groups are connected includes analyzing water cut, production, and pressure change curves to determine whether there is connectivity between oil wells and between oil and water wells.

[0069] In one embodiment, the analysis of the water inflow direction results specifically includes the following steps: based on the static connectivity analysis results, analyze the communication between the reservoir and the bottom water, determine the main connected oil and water wells, clarify the possible main water inflow direction, and determine that the inflow is mainly bottom water or injected water or both.

[0070] like Figure 1 As shown, step S102 is the connectivity calculation step: after determining the bottom water location and the oil well perforation location, and setting the initial values ​​of conductivity and connectivity volume, the connectivity results of the well group to be analyzed at different production times are calculated by fitting the production history.

[0071] In one embodiment, the bottom water position and well perforation position are determined according to the actual drilling and completion results and oil testing and production results of the reservoir. For wells with a water production rate greater than a preset value (e.g., 20%) during the oil testing and production stage, the bottom water position is set as the bottom water position. For wells with a water production rate less than a preset value (e.g., 20%) during the production stage, the bottom water position is set according to the ingress depth and water production of adjacent wells.

[0072] In one embodiment, the initial values ​​of conductivity and connectivity volume are set empirically, and their magnitudes do not affect the subsequent calculation results, but only the number of calculation iterations.

[0073] In one embodiment, the connectivity results include, but are not limited to, the conductivity and connectivity volume between injection wells and production wells, and between production wells and bottom water. Specifically, based on the principle of material balance, a correlation equation between connectivity and production data is established using dynamic production data, and the connectivity between wells and bottom water at different development stages is obtained by solving the equation.

[0074] like Figure 1 As shown, step S103 is the water inflow calculation step: based on the connectivity results obtained after normalization processing, the water inflow is calculated in combination with the water inflow calculation model.

[0075] In one embodiment, the dimensionless conductivity A is obtained after normalization. ijz and connected volume T ijz Where i represents the water injection well, j represents the oil production well, and z represents the bottom water. For example, the connectivity between the first well and the seventh well is denoted as A. 1-7 and T 1-7 The degree of connectivity with the bottom water is A. 1z A 7z and T 1z T 7z .

[0076] In one embodiment, the inflow calculation model includes the following formula:

[0077] Q in =Q out *A ijz *T ijz

[0078] Among them, Q in Q represents the water inflow. out A represents the cumulative liquid volume produced in a given stage. ijz T represents conductivity. ijz The connected volume is represented by , where i represents a water injection well, j represents an oil production well, and z represents bottom water.

[0079] In one embodiment, the method for quantitatively determining the incoming water in a deep fractured solution reservoir further includes a water control step: based on the results of the incoming water direction and the incoming water volume, proposing water control measures and a water control plan.

[0080] Furthermore, water management measures and plans include steps for determining water sources and calculating flow potential: determining adjustment methods based on the conductivity in the connectivity results, wherein the adjustment methods include channel adjustment and flow potential adjustment.

[0081] In one embodiment, the water source determination and flow potential calculation steps include:

[0082] Step a: Based on the conductivity, determine the main connected oil and water wells, and clarify whether the water source is bottom water or injected water. For well groups connected to bottom water, adjust the flow channel as much as possible; for wells connected to injection and production wells, adjust the flow potential as much as possible. Specifically, based on the conductivity calculation results table in the connectivity calculation results, determine the main connected oil and water wells in descending order of conductivity, and clarify whether the water source is bottom water or injected water.

[0083] Step b: During flow channel adjustment, a predetermined volume of flow channel adjustment system is injected near the bottom of the well to block the connecting cracks between the reservoir and the bottom water, thereby achieving flow channel adjustment. Specifically, because the bottom water volume is large, adjusting the flow potential is difficult and ineffective. Therefore, by injecting a certain volume of flow channel adjustment system near the bottom of the well to block the connecting cracks between the reservoir and the bottom water, flow channel adjustment is achieved.

[0084] Step c: When adjusting the flow potential, calculate the flow potential distribution of the well group, draw equipotential lines, and adjust the production of each well in the connected well group according to the flow potential distribution. This achieves the purpose of adjusting the flow potential and oil-water distribution of the well group, thereby increasing the production of the oil wells. Specifically, for oil wells connected to the injection wells, the production of each well in the connected well group can be simply adjusted according to the flow potential distribution to achieve the purpose of adjusting the flow potential and oil-water distribution of the well group, thereby increasing the production of the oil wells.

[0085] Furthermore, the water management measures and plans include optimization and adjustment steps: based on the distribution maps of equipotential lines and water-cut contour lines, and with the maximization of cumulative oil production volume as a constraint, the working system of water injection wells and oil production wells is calculated in real time to determine the real-time adjustment plan and predict the treatment effect of the well group to be analyzed.

[0086] In one embodiment, the optimization and adjustment steps include: using the degree of connectivity between wells and bottom water as control variables, and the production and pressure of oil and water wells as independent variables, iteratively calculating the material balance equation and development indicators to obtain the development indicators and flow potential field distribution of well groups at different development times.

[0087] Figure 2 A flowchart of a method for quantitatively determining the inflow water of a deep fractured solution reservoir according to another embodiment of the present invention is shown.

[0088] like Figure 2As shown, qualitative and static connectivity analyses of the well groups between injection and production wells are first conducted based on production data and seismic data of the fractured-vuggy unit.

[0089] like Figure 2 As shown, the process then determines whether the injection and production well groups are connected. If they are not connected, no action is taken; if they are connected, an initial value for the inter-well connectivity is set, and iterative calculations are performed. After meeting the fitting accuracy requirements, the connectivity result is calculated. The connectivity result includes conductivity and connected volume.

[0090] like Figure 2 As shown, the connectivity results are then normalized to determine the direction and volume of incoming water.

[0091] The method and apparatus for quantitatively determining the inflow water of deep fractured-collapse reservoirs provided by this invention 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 quantitatively determining the inflow water of deep fractured-collapse 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.

[0092] 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.

[0093] 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.

[0094] Practical Application A: Flow Potential Adjustment and Control in Well Group TH12120

[0095] This well is located in Block 12 of the Tarim Oilfield, belonging to an injection-production well group within a fault-collapse geological background. The group consists of 5 wells, and the reservoir in the well area has good contiguousness with potential connectivity. (The text then mentions a carving of the TH12120 well group, but this seems unrelated to the main topic and is likely a separate, incomplete sentence.) Figure 4 The well group has reserves of 851,300 tons, with a cumulative oil production of 361,800 tons, representing a recovery rate of 35.5%. Currently, the average daily oil production is 39.2 tons, and intermittent water injection is being implemented. The overall water cut of the well group is 73.6%. The comprehensive development curve for the well group is shown below. Figure 3 . Figure 5The image shows the results of fracture tracing and identification in well group TH12120. Figure 6 The graph shows the calculated inter-well conductivity of well group TH12120. Figure 7 The diagram shows the calculated volume of interconnected wells in the TH12120 well group.

[0096] Analysis of the inflow of water from the TH12120 well group indicates that 82% mainly comes from bottom water, and 18% comes from the TH12120 injection well (e.g., Figure 8 Therefore, it is necessary to control the flooding caused by bottom water upwelling in the well group. Based on this, a water control scheme of adjusting the flow channel was proposed. The overall water cut of the well group was 73.6%. After the treatment, the overall water cut of the well group decreased by 12.1%, and the water control effect was obvious.

[0097] Practical Application B: Flow Potential Adjustment and Control in Well Group TH12437X

[0098] The TH12437X well group belongs to the TH12402 unit, located in the northwest of Block 12, with the target strata being the Ordovician. The well group is situated within a fault-controlled karst setting. As of the end of April 2020, the TH12437X injection-production well group had 3 oil wells in operation and 0 water injection wells, producing 52.1 tons of oil per day, with an overall water cut of 69.3%. The overall development curve of the well group is shown below. Figure 9 . Figure 10 The image shows the reservoir engraving and fracture tracking results of the TH12437X well group. Figure 11 The diagram shows the calculation results of the inter-well connectivity of the TH12437X well group. Figure 12 The diagram shows the water inflow distribution of the TH12437X well group.

[0099] The first phase of the plan was implemented on March 21, 2020, increasing daily oil production from 40.8t to 49.6t, with a cumulative increase of 267.2t in the first phase. After the implementation of the second phase until July 15, daily oil production increased to 61.6t, with a cumulative increase of 1769.6t in this phase. The total increase in oil production from the two phases was 2036.8t, and the effect was very significant.

[0100] Furthermore, as of June 20, 2020, this invention was applied to 12 fracture-cavity units in the deep fracture-collapse reservoir of the Tarim Oilfield, and 48 inefficient and ineffective injection-production well groups were treated. Using the cumulative water injection, cumulative water production, and cumulative oil production of the well group as control parameters, and with the maximization of benefit (NPV) as a constraint, a water control scheme for real-time adjustment of the well group was obtained. After the oilfield implemented the adjustment and treatment scheme, the cumulative increase in crude oil production was 53,200 tons, the cumulative reduction in water production was 168,000 tons, and the cumulative reduction in water injection was 64,000 cubic meters. The effectiveness rate of well group treatment was as high as 85.7%, which has high application value and effect.

[0101] Figure 13A block diagram of an apparatus for quantitatively determining the inflow water of a deep fractured solution reservoir according to an embodiment of the present invention is shown.

[0102] like Figure 13 As shown, the device 1300 for quantitatively determining the incoming water in a deep fractured solution reservoir includes a water direction determination module 1301, a connectivity calculation module 1302, and an incoming water volume calculation module 1303.

[0103] The water inflow direction determination module 1301 analyzes and obtains the water inflow direction result based on the static connectivity analysis results of the well group to be analyzed.

[0104] The connectivity calculation module 1302 identifies the bottom water location and the oil well perforation location. After setting the initial values ​​of conductivity and connectivity volume, it calculates the connectivity results of the well group to be analyzed at different production times by fitting the production history.

[0105] The water inflow calculation module 1303 calculates the water inflow based on the connectivity results obtained after normalization and in combination with the water inflow calculation model.

[0106] In summary, the method and apparatus for quantitatively determining the inflow of water into deep fault-collapse reservoirs provided by this invention utilize the production dynamic data of injection-production well groups. Through precise historical fitting, the connectivity degree is quantitatively calculated. After normalizing the connectivity degree, the water inflow distribution is calculated. Based on this, the well group management direction is proposed, and a water inflow management and adjustment scheme for the injection-production well group is formed. This realizes differentiated and quantitative water inflow management of injection-production well groups in fault-collapse reservoirs, providing a method for water flooding management and oil production enhancement and water reduction in fault-collapse reservoirs.

[0107] 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.

[0108] 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.

[0109] 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.

[0110] 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.

[0111] 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.

[0112] 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 quantifying the influx of a deep-seated diasporic reservoir, characterized by, The method comprises: water influx direction determination step: according to the static connectivity analysis result of the well group to be analyzed, the water influx direction result is analyzed; connectivity degree calculation step: the bottom water position and the oil well perforation position are determined, the initial value of the conductivity and the connected volume is set, and then the connectivity degree result of the well group to be analyzed at different production time is calculated through production history fitting; water influx calculation step: based on the normalized connectivity degree result, the water influx is calculated by combining the water influx calculation model; The water influx direction determination step specifically comprises the following steps: data collection and analysis step: selecting injection-production well groups of fault-dissolution reservoir geological background as candidate well groups, collecting production dynamic data and seismic data of the candidate well groups, and obtaining historical production data after removing abnormal data points; static connectivity analysis step: based on the seismic data in the historical production data, reservoir body sculpture of the candidate well groups is carried out, the static connectivity between reservoir bodies is analyzed, and the static connectivity analysis result is obtained; well group determination step: based on the production dynamic data in the historical production data, production dynamic analysis of the candidate well groups is carried out, whether the candidate well groups are connected is determined, the well numbers of the unconnected well groups are deleted, and the well group to be analyzed is determined; The water influx calculation model comprises the following formula: Q in = Q out *A ijz *T ijz ; where Q in represents the water influx, Q out represents the cumulative production volume of the phase, A ijz represents the transmissibility, T ijz represents the connected volume, i represents the injection well, j represents the production well, and z represents the bottom water.

2. The method of determining the influx of a deep-buried, dissolved oil reservoir as claimed in claim 1, wherein, The water influx direction result analyzed specifically comprises the following steps: Based on the static connectivity analysis result, the communication between the reservoir body and the bottom water is analyzed, the main connected oil-water well is determined, the possible main water influx direction is determined, and it is determined whether the water influx is mainly bottom water or injected water or both.

3. The method of determining the influx of a deep-buried, dissolved oil reservoir as claimed in claim 1, wherein, The connectivity degree result includes but is not limited to: the conductivity and the connected volume between the injection well and the production well, and between the production well and the bottom water.

4. The method of determining the influx of a deep-buried, dissolved oil reservoir as claimed in claim 1, wherein, The method further comprises: water control step: based on the water influx direction result and the water influx, water control measures and water control schemes are proposed.

5. A storage medium, characterized by It comprises a series of instructions for executing the method steps as claimed in any one of claims 1-4.

6. An apparatus for quantifying the influx of a deep-buried, dissolved oil reservoir, characterized by, The device for executing the method for quantitatively determining the water influx of deep fault-dissolution reservoir as claimed in any one of claims 1-4 comprises: a water influx direction determination module for analyzing the water influx direction result according to the static connectivity analysis result of the well group to be analyzed; a connectivity degree calculation module for determining the bottom water position and the oil well perforation position, setting the initial value of the conductivity and the connected volume, and then calculating the connectivity degree result of the well group to be analyzed at different production time through production history fitting; a water influx calculation module for calculating the water influx based on the normalized connectivity degree result and combining the water influx calculation model.

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