Method and device for quantitatively adjusting flow potential of low-efficiency injection-production well group in deep cataclastic oil reservoir

Abstract

The application provides a low-efficiency injection-production well group flow potential quantitative adjustment method for a deep-layer dissolution body oil reservoir, which comprises the following steps: a connectivity calculation step: the position of the bottom water and the position of the oil well perforation are determined, the initial value of the conductivity and the connectivity volume is set, and then the connectivity results of the to-be-analyzed well group at different production moments are calculated through production history fitting; a water source determination and flow potential calculation step: the adjustment mode is determined according to the conductivity in the connectivity result, wherein the adjustment mode comprises flow channel adjustment and flow potential adjustment; an optimization and adjustment step: according to the equipotential line and the water cut contour distribution map, the injection well and the production well working system are calculated in real time to determine the real-time adjustment scheme and predict the treatment effect of the to-be-analyzed well group. The application submits the flow potential adjustment and treatment scheme of the injection-production well group, realizes the differentiated and quantitative treatment of the dissolution body oil reservoir injection-production well group, and provides a basis for the water-out treatment of the dissolution body oil reservoir.

Description

Technical Field

[0001] This invention relates to the field of carbonate rock fractured-dissolved reservoir development technology, specifically to a method and device for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fractured-dissolved reservoirs. Background Technology

[0002] Statistics show that the number of inefficient and ineffective well groups is increasing year by year. As of the end of 2019, among the 436 injection-production well groups in the Tarim Oilfield, 84 well groups were classified as inefficient based on a water consumption rate greater than 15 per ton of oil. Of these, 44 were in fractured-dissolve reservoirs, accounting for 52.3%, highlighting the urgent need to strengthen the management of injection-production well groups in fractured-dissolve reservoirs. Field practice indicates that methods for managing inefficient well groups include adjusting flow channels, adjusting flow potential, gas injection, backfilling, sidetracking, targeted acid fracturing, and infill drilling. Due to the impact of low oil prices, methods that are effective, cost-effective, and easy to operate should be selected whenever possible.

[0003] The prior art is a method and apparatus for characterizing residual oil based on fluid potential field (CN104881522A). It obtains the values ​​of various parameters in the development fluid potential according to the mathematical model of oil-water two-phase fluid seepage; establishes a distribution model of the actual fluid potential field of the reservoir; and analyzes the distribution of high potential region and low potential region of the fluid potential field according to the distribution model of the actual fluid potential field to achieve the characterization of residual oil.

[0004] The existing technology, namely the simulation method and system for dominant channels inside heterogeneous transport layers (CN104899383A), provides a simulation method and system for dominant channels inside heterogeneous transport layers. It can quickly calculate the dominant channels leading to traps in the transport layer during the accumulation process, rather than simply selecting the path with the largest difference. It optimizes the most likely path under the current data conditions. The method itself is closer to the real conditions from the perspective of implementation than simulation based on fluid potential and flow path.

[0005] The prior art method and apparatus for predicting the range of oil and gas migration and accumulation (CN104021296A) discloses a method and apparatus for predicting the range of oil and gas migration and accumulation. The method includes: obtaining caprock bottom morphology data, reservoir sand body distribution data and hydrodynamic data of the study area based on geological stratification, geological logging and formation pressure test data; determining the weight coefficients of various types of data after normalization of the data; calculating the normalized fluid potential of the study area; and predicting the range of oil and gas migration and accumulation of the study area based on the normalized fluid potential.

[0006] Existing technology, a high-precision hydrocarbon migration simulation method based on corner grids (CN106846470A), establishes a three-dimensional parametric spatial geological model based on corner grids, forming a giant, complex, open system that matches the natural hydrocarbon system. Based on this, a feedback control mechanism between the basin system and the hydrocarbon system is established. Hydrocarbon expulsion data is extracted to calculate the impact of expulsion on hydrocarbon generation simulation. Under conditions of hydrocarbon migration, the migration velocity, direction, and amount of hydrocarbons are dynamically calculated, ultimately achieving a relative balance in hydrocarbon migration. It can be seen that currently, no patents related to dynamic fracture identification have been publicly released, either domestically or internationally.

[0007] The existing technology, oil potential field simulation method and apparatus (CN111027780A), provides an oil potential field simulation method and apparatus. This method first determines the contact line between the fault and the source rock of the target geological body; then, based on the hydrocarbon generation rate per unit mass of total organic carbon in the source rock, the rock density of each lithology, and the abundance of organic matter, it calculates the oil potential at each point on the contact line; subsequently, it calculates the oil-generating capacity of the source rock; next, based on the density of the crude oil, lithological distribution data, displacement pressure of each lithology, and fault distribution data, it determines the effective reservoir in the target geological body; then, it calculates the oil-storing capacity of the target geological body; it determines whether the oil-storing capacity is greater than the oil-generating capacity; if so, according to a preset oil and gas migration rule, it determines the actual oil content of the effective reservoir, and then calculates the oil potential of the effective reservoir; based on the oil potential at each point on the contact line and the oil potential of the effective reservoir, it simulates the oil potential field of the target geological body.

[0008] The existing technology, a method for determining the charging potential energy of oil and gas reservoirs (CN107701178A), relates to the field of oil and gas field exploration technology. It first establishes a reservoir potential energy calculation model, then a fluid potential calculation model, and then a source-reservoir pressure difference calculation model. Subsequently, it calculates the reservoir charging potential energy index, and finally uses the obtained index to determine the reservoir potential. An index greater than 1 indicates good oil and gas charging, with a higher value indicating stronger charging capacity and a higher probability of reservoir formation. An index less than 1 indicates insufficient charging capacity and a low probability of reservoir formation. This method can more comprehensively describe the ability of oil and gas to charge into the reservoir, laying the foundation for oil and gas reservoir prediction.

[0009] It can be seen that the existing technology does not involve the relevant technical content of quantitative adjustment of flow potential in inefficient injection-production well groups in deep fault-collapsed reservoirs. In view of the above situation, the present invention provides a method and device for quantitative adjustment of flow potential in inefficient injection-production well groups in deep fault-collapsed reservoirs. Summary of the Invention

[0010] To address the above problems, this invention provides a method for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fault-collapsed reservoirs, the method comprising:

[0011] 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.

[0012] Water source determination and flow potential calculation steps: Determine the adjustment method based on the conductivity in the connectivity results, wherein the adjustment method includes channel adjustment and flow potential adjustment;

[0013] 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 regimes of water injection wells and oil production wells are calculated in real time to determine the real-time adjustment plan and predict the treatment effect of the well group to be analyzed.

[0014] According to one embodiment of the present invention, the method comprises:

[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 one embodiment of the present invention, the method comprises:

[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 one embodiment of the present invention, the method comprises:

[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 one embodiment of the present invention, the method comprises:

[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 an embodiment of the present invention, the water source determination and flow potential calculation steps include:

[0024] Based on the conductivity, determine the main oil and water wells that are connected, and clarify whether the water source is bottom water or injected water. For well groups connected to bottom water, the main adjustment is to adjust the flow channel, and for wells connected to injection and production wells, the main adjustment is to adjust the flow potential.

[0025] When adjusting the flow channel, a flow channel adjustment system of a preset volume 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.

[0026] When adjusting the flow potential, the flow potential distribution of the well group is calculated, equipotential lines are drawn, and the production of each well in the connected well group is adjusted according to the flow potential distribution, so as to adjust the flow potential and oil-water distribution of the well group and increase the production of the oil well.

[0027] According to an embodiment of the present invention, the optimization and adjustment step includes:

[0028] Using the degree of connectivity between wells and bottom water as the control variable, and the production and pressure of oil and water wells as the independent variables, the material balance equation and development indicators are iteratively calculated to obtain the development indicators and flow potential field distribution of well groups at different development times.

[0029] 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.

[0030] According to another aspect of the present invention, a device for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fractured-dissolved reservoirs is also provided, which performs the method as described in any of the preceding claims, the device comprising:

[0031] Connectivity calculation module: It is used to determine the bottom water location and 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.

[0032] Water source determination and flow potential calculation module: It is used to determine the adjustment method based on the conductivity in the connectivity result, wherein the adjustment method includes channel adjustment and flow potential adjustment;

[0033] The optimization and adjustment module is used to calculate the working system of water injection wells and oil production wells in real time based on the distribution maps of equipotential lines and water-cut contour lines, with the constraint of maximizing the cumulative oil production volume, in order to determine the real-time adjustment plan and predict the treatment effect of the well group to be analyzed.

[0034] This invention provides a method and apparatus for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fault-collapse reservoirs. Utilizing the production dynamics data of the injection-production well groups, and through precise historical data fitting, the method quantitatively calculates the inter-well connectivity, flow potential, and water flooding distribution. Based on this, it proposes directions for flow potential adjustment and well group management. Through real-time optimization of injection and production parameters, the injection and production volumes are determined, forming a flow potential adjustment and management scheme for the injection-production well groups. This achieves differentiated and quantitative 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.

[0035] 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

[0036] 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:

[0037] Figure 1 A flowchart of a method for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fractured-dissolved reservoirs according to an embodiment of the present invention is shown.

[0038] Figure 2 A flowchart of a method for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fractured-dissolved reservoirs according to another embodiment of the present invention is shown;

[0039] Figure 3 This shows a comprehensive development curve of the TH12120 well group according to an embodiment of the present invention;

[0040] Figure 4 This image shows the reservoir engraving results of the TH12120 well group according to an embodiment of the present invention;

[0041] Figure 5 The image shows the fracture tracking and identification results of the TH12120 well group according to an embodiment of the present invention;

[0042] 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.

[0043] 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;

[0044] Figure 8This diagram shows the current flow potential distribution of the TH12120 well group according to an embodiment of the present invention.

[0045] Figure 9 This diagram shows the current water flooding distribution of the TH12120 well group according to an embodiment of the present invention.

[0046] Figure 10 The diagram shows the first-stage adjustment scheme and implementation effect of the flow potential of the TH12120 well group according to an embodiment of the present invention.

[0047] Figure 11 The diagram shows the second and third stage adjustment schemes for the flow potential of the TH12120 well group according to an embodiment of the present invention, as well as the implementation effect.

[0048] Figure 12 This diagram shows the integrated development curve of the TH12437X well group according to an embodiment of the present invention;

[0049] Figure 13 The image shows the reservoir engraving and fracture tracing results of the TH12437X well group according to an embodiment of the present invention;

[0050] Figure 14 This figure shows the calculation results of the inter-well connectivity of the TH12437X well group according to an embodiment of the present invention;

[0051] Figure 15 This diagram shows the current flow potential distribution of the TH12437X well group according to an embodiment of the present invention.

[0052] Figure 16 This diagram shows the current water flooding distribution of the TH12437X well group according to an embodiment of the present invention.

[0053] Figure 17 This diagram illustrates the first and second stage adjustment schemes for the flow potential of the TH12437X well group according to an embodiment of the present invention, along with their implementation effects.

[0054] Figure 18 A structural block diagram of a device for quantitatively adjusting the flow potential of an inefficient injection-production well group in a deep fractured-dissolve reservoir according to an embodiment of the present invention is shown. Detailed Implementation

[0055] 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.

[0056] Deep fault-dissolved reservoirs are one of the main oil and gas reservoir types in the northern margin of the Tarim Basin, such as the Tarim River periphery and Shunbei. The development of reservoirs is mainly controlled by faults. 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 fault fracture zone are the three main types of reservoir spaces. Due to the subordination relationship between fractures and faults, the development of fractures is controlled by the development law of faults, and their orientation is basically consistent with the orientation of faults. 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 reservoirs in the Tarim River area [J]. Petroleum and Gas Geology, 2015, 36(3): 347-09).

[0057] Research results on fractured-dissolved reservoirs show that a large number of vertical fractures are developed in the deep part of the reservoir. These vertical fractures are connected to the bottom water. Due to the high energy and large volume of the bottom water, water channeling is serious along the high-angle fractures, causing the oil wells to quickly produce water, which directly affects the development effect of fractured-dissolved reservoirs (Tang Hai, He Juan, Rong Yuanshuai, Li Xiaobo, Water injection displacement law and residual oil distribution characteristics of typical fractured-dissolved reservoirs in Tahe River [J], Oil & Gas Geology and Recovery, 2018, 25(3):95-06).

[0058] In the middle and late stages of development of fractured-dissolve reservoirs, in order to maintain formation energy, it is necessary to transfer some poorly developed, high-water-cut oil wells for injection. This results in water injection pointing towards the oil wells along the 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). 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. As the oil wells reach water, the crude oil in the channels is replaced by formation water or injected water with lower flow resistance. At this time, the channels are called water flow channels. Afterward, the crude oil connected to the water flow channels is difficult to continue to be driven, forming residual oil shielded by high-conductivity channels. The amount of water injected will flow out as well. At this point, the water injection of the well group is called an ineffective or inefficient water injection well group. It can be said that controlling and managing the flow of water in fractures controls the development effect of the entire fractured-dissolved reservoir. Effectively reducing the degree of water channeling in fractures is the core technology for the management of injection-production well groups in fractured-dissolved reservoirs.

[0059] Certain adjustment measures can be taken to increase the driving force of subsequent water injection on crude oil and improve the water injection effect of well groups. This process is called inefficient well group management. According to statistics, the number of inefficient and ineffective well groups is increasing year by year. As of the end of 2019, among the 436 injection-production well groups in the Tarim Oilfield, 84 well groups were classified as inefficient based on a water consumption rate greater than 15 per ton of oil. Among them, 44 well groups (52.3%) were of the fractured-dissolved reservoir type, and there is an urgent need to strengthen the management of injection-production well groups in fractured-dissolved reservoirs. Field practice shows that methods for managing inefficient well groups include adjusting the flow channel, adjusting the flow potential, gas injection, backfilling, sidetracking, targeted acid fracturing, and infill drilling. Due to the influence of low oil prices, methods that are effective, low-cost, and easy to operate should be selected as much as possible. Analysis of production and scientific research shows that the hydrodynamic-based flow potential adjustment method is one of the most effective methods for managing injection-production well groups in carbonate fractured-cavity reservoirs (Liu Jingge, Fan Honghai, Feng Deyong, et al. A three-dimensional formation fluid potential calculation method and its application [J]. Oil & Gas Geology and Recovery, 2014, 21(3):41-04). The hydrodynamic method for flow potential adjustment has this advantage. Currently, flow potential adjustment accounts for 38% of the workload in the management of fractured-cavity reservoir well groups in the Tarim Basin every year, and this is increasing year by year. Now, the flow potential adjustment work of 26 inefficient well groups is completed every year, with an annual cumulative increase of 45,500 tons of oil, and the effect is obvious.

[0060] Flow potential (also known as fluid potential) is the sum of the energy of fluid flow. Therefore, flow potential adjustment aims to achieve energy equilibration in the reservoir from an energy perspective. Strictly speaking, flow potential adjustment should include two main categories of methods: physical and chemical, including conventional methods such as water injection, gas injection, and polymer injection. This patent relates to flow potential adjustment measures based on hydrodynamic methods. The flow potential adjustment method, based on hydrodynamics, involves adjusting the working conditions of oil and water wells according to optimal control calculations to achieve formation flow potential equilibration, while simultaneously increasing oil well production and reducing water injection, thus achieving economical and effective development. However, current flow potential calculation and adjustment present significant challenges, especially in fractured-dissolve reservoirs with well-developed bottom water. These reservoirs have short development histories and limited experience. Furthermore, due to the unique geological characteristics of fractured-dissolve reservoirs, the vertical flow capacity of oil and water is significantly higher 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 well. According to on-site statistics, the recovery rate of most reservoirs is around 10%. There are obvious water flow channels and a large amount of residual oil between the water body and the production well group in the reservoir. The potential tapping of these residual oils is the material basis for the management of injection and production well groups.

[0061] Based on field experience, current flow potential adjustment generally involves two stages: well selection and optimization. Flow potential distribution, remaining oil distribution, and scale abundance are key factors. These indicators can typically only be obtained through geological modeling and numerical simulation, requiring long-term fitting and dynamic analysis, thus hindering the application and promotion of flow potential adjustment technology in fractured-vuggy reservoirs. From a production perspective, the connectivity between oil wells and bottom water, and between oil wells and water wells, are limiting factors for oil-water movement patterns, water cut rise patterns, and water drive recovery rates. Therefore, relying on the connectivity between oil wells and natural and artificial water bodies, and based on historical fitting of the well group, the difference between flow potential distribution and water cut distribution can be calculated. Based on the flow potential and water cut distribution, qualitative flow potential adjustments can be carried out; further quantitative adjustments to the operating regimes of oil and water wells can be made using production optimization methods. While balancing the flow potential between oil and water wells, the direction and degree of oil and water flow can be adjusted to achieve increased oil production. This reduces the workload of geological modeling and numerical simulation calculations, and allows for real-time adjustment of the operating schedule of oil and water wells, providing an feasible solution for the treatment of injection and production well groups in fault-collapsed reservoirs in the Tarim Oilfield.

[0062] In the 1940s and 1950s, M.K. Hubbert used the concept of flow potential (also known as fluid potential) to explain the movement law of underground fluids (oil, gas, and water) (Hubbert M K. Enrapment of petroleum under hydrodynamic conditions[J]. AAPG Bulletin, 1953, 37(8): 1954-2026). The mechanical energy (Φ) of a unit mass of fluid is defined as the fluid potential. In the process of reservoir water injection development, flow potential energy consists of potential energy, pressure energy, kinetic energy, and interface energy, which is the result of the force acting on the fluid inside the reservoir. Potential energy is determined by the position of the fluid. There are differences in elevation at different points inside the reservoir, which causes differences in potential energy at different points. At the same time, the change in position during the fluid's movement causes changes in its potential energy. Pressure energy is the energy caused by pressure acting on the fluid. Pressure includes reservoir static pressure and external supply pressure. There are differences in fluid pressure energy at different points inside the reservoir, which causes the fluid to move. Kinetic energy is the energy possessed by a fluid during its flow. It is the result of the combined action of various forces. The uneven distribution of forces acting on the fluid at different points within an oil reservoir leads to differences in its kinetic energy. Interfacial energy is the result of capillary and viscous forces acting on the fluid. Its magnitude depends on reservoir properties such as interfacial tension, pore throat radius, and wettability. The heterogeneity of the reservoir within an oil reservoir causes differences in the interfacial energy of the fluids within the reservoir. These differences in the distribution of the interfacial energy field control the flow of fluids within the reservoir.

[0063] WKEngland defines flow potential as the work required to transfer a unit volume of fluid from a reference point to the study point (subsurface environment) (Zawisza L, Wojna E, Dylag, Smulski R. Hydrodynamic conditions of hydrocarbon migration and accumulation exemplified by the Pomorsko, Czerwiensk, and Zarnowiec Oil Fields, Poland [R]. IPTC10925, 2005). Alternatively, it can be described as the total potential energy of a unit volume of fluid relative to the reference surface. The main factors affecting the total potential energy of formation pore fluids are gravity, elasticity, and surface tension. If the reference surface is taken at a certain depth underground, the flow potential expression of MKHubbert is:

[0064]

[0065] The flow potential expression for WKEngland is:

[0066]

[0067] In the formula: Φ is the flow potential (J), and g is the acceleration due to gravity (m / s²). 2 Z is the distance (m) from point A in the formation to the reference surface, P is the formation fluid pressure (Pa), Po is the formation fluid pressure (Pa) at the reference surface, and ρ(P) is the fluid density as a function of pressure (kg / m³). 3 ), where q is the formation fluid velocity (m / s), σ is the interfacial tension (N / m); θ is the wetting angle, and r is the capillary radius of the rock pores at point A (m).

[0068] The composition and calculation formula of the flow potential show that the magnitude of the flow potential is mainly affected by the formation pressure, and the formation pressure has a linear relationship with the reservoir burial depth. The surface energy calculated using conventional reservoir parameters is in the range of 10. -1 ~10 -3 Between KJ, based on a daily production of 100 tons, the kinetic energy term ranges from 10. 2 ~10 3 Between KJ, the potential energy of oil reservoirs at depths greater than 5000 meters is approximately 10. 6 ~10 8Since the flow potential is KJ, interfacial energy and kinetic energy can be ignored, and potential energy or pressure energy can be directly used to replace flow potential for calculation, analysis and adjustment. Thus, the problem of how to quickly calculate the distribution of flow potential in the reservoir is transformed into the calculation of formation pressure distribution. The difficulty in calculating flow potential lies in ensuring balanced effect in oil and gas development by adjusting the flow potential according to the flow potential distribution and fluid distribution.

[0069] From the perspective of flow potential composition, flow potential calculation involves many parameters, making the calculation difficult. Currently, common calculation methods include numerical simulation and analytical solution methods. Because numerical simulation requires the establishment of a geological model, it offers high accuracy but is time-consuming and not easily generalized. This problem is even more pronounced in flow potential adjustment and optimization, as production optimization requires multiple calls to the geological model and numerical simulation results. Analytical solution methods establish flow mathematical and physical equations based on the principle of mass balance and then perform analytical solutions. This method is fast, but due to the numerous factors involved, the mathematical model often cannot be solved quickly due to modeling limitations, severely impacting its application and promotion. Therefore, there is an urgent need to find a method that lies between numerical simulation and reservoir process methods, combining the advantages of both to improve application effectiveness.

[0070] Existing technologies, such as the water-drive development of multi-layer reservoirs inter-well connectivity inversion model (Zhao Hui, Kang Zhijiang, Sun Haitao, et al. Water-drive development of multi-layer reservoirs inter-well connectivity inversion model [J]. Petroleum and Gas Geology, 2016, 43(1): 99-08), have established a method for calculating inter-well connectivity based on the flow tube method, which can obtain the inter-well connectivity at different development stages in real time. However, the above existing technologies do not involve the quantitative adjustment of the flow potential of inefficient injection-production well groups in deep fractured-dissolve reservoirs.

[0071] Based on the current state of existing technology, this invention utilizes production dynamic data, through production history fitting, to calculate the connectivity between oil wells and water bodies, obtain the flow potential distribution, analyze the flow potential and water cut distribution, and use optimization methods to propose flow potential adjustment suggestions for well groups, determine reasonable flow potential adjustment and well group management schemes, and provide a basis for the organization of inefficient water injection wells.

[0072] Figure 1 A flowchart illustrating a method for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fractured-dissolve reservoirs according to an embodiment of the present invention is shown.

[0073] like Figure 1 As shown, step S101 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.

[0074] 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.

[0075] 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.

[0076] 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.

[0077] In one embodiment, the method for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fault-collapsed reservoirs further includes data collection and analysis steps: selecting injection-production well groups with the geological background of fault-collapsed reservoirs as candidate well groups, collecting production dynamic data and seismic data of 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, as this may be due to human error and should be removed.

[0078] In one embodiment, the method for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fractured-karst reservoirs further 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.

[0079] In one embodiment, the method for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fractured-dissolved reservoirs further includes a well group determination step: conducting production dynamic analysis of candidate well groups based on production dynamic data from historical production data, determining whether candidate well groups are interconnected, deleting disconnected well numbers, and determining the well group to be analyzed. Specifically, determining whether candidate well groups are interconnected includes analyzing water cut, production, and pressure change curves to determine whether there is interconnection between oil wells and between oil and water wells.

[0080] In one embodiment, the method for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fractured-dissolved reservoirs further includes analyzing the communication between the reservoir and bottom water based on the results of static connectivity analysis, identifying the main connected oil and water wells, clarifying the possible main water inflow direction, and determining that the inflow is mainly bottom water, injection water, or both.

[0081] In addition, the quantitative adjustment method for the flow potential of inefficient injection-production well groups in deep fractured-dissolved reservoirs also includes a water inflow calculation step: the water inflow is calculated based on the connectivity results obtained after normalization and combined with the water inflow calculation model.

[0082] 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 .

[0083] In one embodiment, the inflow calculation model includes the following formula:

[0084] Q in =Q out *A ijz *T ijz

[0085] 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.

[0086] like Figure 1 As shown, step S102 is the water source determination and flow potential calculation step: the adjustment method is determined based on the conductivity in the connectivity result, wherein the adjustment method includes flow channel adjustment and flow potential adjustment.

[0087] In one embodiment, the water source determination and flow potential calculation steps include steps S1021, S1022, and S1023, specifically:

[0088] Step S1021: 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.

[0089] Step S1022: 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. 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.

[0090] Step S1023: 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 water injection well, 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.

[0091] like Figure 1 As shown, step S103 is the optimization and adjustment step: based on the distribution map of equipotential lines and water-cut contour lines, with the maximum cumulative oil production volume as the 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.

[0092] 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.

[0093] Figure 2 A flowchart of a method for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fractured-dissolve reservoirs according to another embodiment of the present invention is shown.

[0094] like Figure 2 As shown, a qualitative analysis of the connectivity between injection and production well groups is first conducted based on the production data of the fractured-vuggy unit and the seismic data of the fractured-vuggy unit.

[0095] 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.

[0096] like Figure 2As shown, based on the connectivity results, flow potential field distribution analysis and water flooding degree distribution analysis were then performed. Production optimization was then implemented for the well group, with adjustment plans formulated for oil wells and water wells respectively. A comprehensive flow potential adjustment plan for the well group was then obtained. The degree of water flooding can be assessed using water-bearing contour lines as a similar indicator, and connectivity can also be used to track the saturation field, serving as the basis for water flooding degree analysis.

[0097] like Figure 2 As shown, the well group flow potential adjustment plan was finally implemented and tracked in real time, and adjustments were made in real time when problems were found.

[0098] In summary, this invention aims to increase oil production and reduce waterlogging by adjusting the flow potential balance. It utilizes the production dynamics data of the injection-production well group, and through precise historical fitting, quantitatively calculates the connectivity between wells within the group. Then, using the calculated connectivity as a control variable, it calculates the flow potential distribution, analyzes the relationship between flow potential differences between wells and the degree of water flooding, and qualitatively proposes flow potential adjustment and well group management recommendations. Finally, it conducts real-time optimization of injection and production parameters, accurately determines the operating procedures for oil and water wells, and submits flow potential adjustment and management plans for the injection-production well group. This achieves differentiated and quantitative management of injection-production well groups in fractured-dissolve reservoirs, providing a basis for water flooding management of oil wells in fractured-dissolve reservoirs.

[0099] The method and apparatus for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fault-collapsed 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 adjusting the flow potential of inefficient injection-production well groups in deep fault-collapsed reservoirs. The computer program can execute computer instructions, which include computer program code. The computer program code can be in the form of source code, object code, executable files, or some intermediate form.

[0100] 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.

[0101] 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.

[0102] Example A: Flow potential adjustment and control of well group TH12120

[0103] 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 5 The 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.

[0104] Figures 8-9 The current flow potential distribution map and water flooding degree distribution map of the TH12120 well group are displayed. Based on the first round of implementation of the flow regulation plan on February 10, 2020, the TH12120 well group has achieved a cumulative increase of 514 tons of oil, demonstrating significant results (e.g., Figure 10 Following the initial fluid extraction in the first round, the second phase of the program was implemented on April 14, 2020. The flow potential adjustment well in the TH12120 well group was changed from TH12199 to TH12121, resulting in a cumulative increase of 172 tons of oil, with only moderate effectiveness. Subsequently, the flow potential adjustment well was changed from TH12121 to TH12116, implementing the third round of flow potential adjustment and treatment. As of July 10, 2020, this resulted in a cumulative increase of 711 tons of oil, demonstrating significant effectiveness. Figure 11 After three rounds of flow adjustment, the cumulative oil production increased by 1,397 tons, generating a profit of 1.778 million yuan, with almost zero investment. The oilfield suggested extending the adjustment period by half a month and revising the fourth round of treatment plan based on changes in the flow.

[0105] Example B: Flow potential adjustment and control of the TH12437X well group

[0106] 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 in 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, with a daily oil production of 52.1 tons and an overall water cut of 69.3%. Figure 12 The diagram shows the overall development curve of the TH12437X well group. Figure 13 The image shows the results of reservoir carving and fracture tracking in the TH12437X well group. Figure 14 The diagram shows the calculation results of the inter-well connectivity of the TH12437X well group.

[0107] Figures 15-16The current flow potential distribution map and water flooding degree distribution map of the TH12437X well group are displayed. The first phase of the program was implemented on March 21, 2020, increasing daily oil production from 40.8t to 49.6t, a cumulative increase of 267.2t. From the implementation of the second phase until July 15, daily oil production increased to 61.6t, a cumulative increase of 1769.6t. The total increase in oil production across both phases was 2036.8t, demonstrating a very significant effect (e.g., ...). Figure 17 ).

[0108] In summary, as of June 20, 2020, this invention has been applied to 48 injection-production well groups in 12 fracture-cavity units of the Tarim Basin oilfield. With the constraints of well group flow potential equalization and maximizing cumulative oil production, a real-time adjustment and management scheme for the well groups was obtained. After the oilfield implemented the adjustment and management scheme, a cumulative increase of 53,200 tons of crude oil was achieved, a cumulative reduction of 168,000 tons of water production was achieved, and a cumulative reduction of 64,000 cubic meters of water injection was achieved. The effective rate of well group management reached over 85.7%, demonstrating high application value and effectiveness.

[0109] Figure 18 A structural block diagram of a device for quantitatively adjusting the flow potential of an inefficient injection-production well group in a deep fractured-dissolve reservoir according to an embodiment of the present invention is shown.

[0110] like Figure 18 As shown, the inefficient injection-production well group flow potential quantitative adjustment device 1800 in deep fractured solution reservoirs includes a connectivity calculation module 1801, a water source determination and flow potential calculation module 1802, and an optimization and adjustment module 1803.

[0111] The connectivity calculation module 1801 is used to determine the bottom water location and the oil well perforation location. After 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.

[0112] The water source determination and flow potential calculation module 1802 is used to determine the adjustment method based on the conductivity in the connectivity results. The adjustment method includes channel adjustment and flow potential adjustment.

[0113] The optimization and adjustment module 1803 is used to calculate the working system of water injection wells and oil production wells in real time based on the distribution map of equipotential lines and water-cut contour lines, with the constraint of maximizing the cumulative oil production volume, in order to determine the real-time adjustment plan and predict the treatment effect of the well group to be analyzed.

[0114] In summary, the present invention provides a method and apparatus for quantitatively adjusting the flow potential of inefficient injection-production well groups in deep fault-collapse reservoirs. Utilizing the production dynamic data of the injection-production well groups, and through precise historical data fitting, the method quantitatively calculates the distribution of inter-well connectivity, flow potential, and water flooding. Based on this, it proposes directions for flow potential adjustment and well group management. Through real-time optimization of injection and production parameters, the injection and production volumes are determined, forming a flow potential adjustment and management scheme for the injection-production well groups. This achieves differentiated and quantitative 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.

[0115] 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.

[0116] 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.

[0117] 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.

[0118] 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.

[0119] 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.

[0120] 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 quantitatively adjusting the flow potential of an inefficient injection-production well group in a deep dissolution oil reservoir, characterized in that, The method includes: 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. Water source determination and flow potential calculation steps: Determine the adjustment method based on the conductivity in the connectivity results, wherein the adjustment method includes channel adjustment and flow potential adjustment; Optimization and adjustment steps: Based on the distribution map of equipotential lines and water-cut contour lines, with the maximum cumulative oil production volume as the 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. The steps for determining the water source and calculating the flow potential include: determining the main connected oil and water wells according to their conductivity, clarifying whether the water source is bottom water or injected water, adjusting the flow channel for well groups connected to bottom water, and adjusting the flow potential for well groups connected to injection and production wells; when adjusting the flow channel, injecting a predetermined volume of flow channel adjustment system near the bottom of the well to block the connecting cracks between the reservoir and the bottom water, thereby achieving flow channel adjustment; when adjusting the flow potential, calculating the flow potential distribution of the well group, drawing equipotential lines, and adjusting the production of each well in the connected well group according to the flow potential distribution, thereby adjusting the flow potential and oil-water distribution of the well group and increasing the production of the oil wells.

2. The method for quantitative adjustment of flow potential of low-efficiency injection-production well groups in deep dissolution oil reservoirs according to claim 1, characterized in that, The method includes: 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.

3. The method for quantitative adjustment of flow potential of low-efficiency injection-production well groups in deep dissolution oil reservoirs according to claim 2, characterized in that, The method includes: 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.

4. The method for quantitative adjustment of flow potential of low-efficiency injection-production well groups in deep dissolution oil reservoirs according to claim 2, characterized in that, The method includes: 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.

5. The method for quantitative adjustment of flow potential of low-efficiency injection-production well groups in deep dissolution oil reservoirs according to claim 3, characterized in that, The method includes: 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.

6. The method for quantitative adjustment of flow potential of low-efficiency injection-production well groups in deep dissolution oil reservoirs according to claim 1, characterized in that, The connectivity results include the conductivity and connectivity volume between the injection well and the production well, as well as the conductivity and connectivity volume between the production well and the bottom water.

7. The method for quantitative adjustment of flow potential of low-efficiency injection-production well groups in deep dissolution oil reservoirs according to claim 1, characterized in that, The optimization and adjustment steps include: Using the degree of connectivity between wells and bottom water as the control variable, and the production and pressure of oil and water wells as the independent variables, the material balance equation and development indicators are iteratively calculated to obtain the development indicators and flow potential field distribution of well groups at different development times.

8. A storage medium, characterized by It includes a series of instructions for performing the method steps as described in any one of claims 1-7.

9. A device for quantitative adjustment of flow potential of low-efficiency injection-production well groups in deep-dispersed oil reservoirs, characterized in that, The apparatus for performing the method as described in any one of claims 1-7 comprises: Connectivity calculation module: It is used to determine the bottom water location and 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. Water source determination and flow potential calculation module: It is used to determine the adjustment method based on the conductivity in the connectivity result, wherein the adjustment method includes channel adjustment and flow potential adjustment; The optimization and adjustment module is used to calculate the working system of water injection wells and oil production wells in real time based on the distribution maps of equipotential lines and water-cut contour lines, with the constraint of maximizing the cumulative oil production volume, in order to determine the real-time adjustment plan and predict the treatment effect of the well group to be analyzed.

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