Method and device for determining stratified injection-production ratio of three-dimensional injection-production system of oil reservoir

Abstract

This application provides a method, apparatus, and storage medium for determining the stratified injection-production ratio in a three-dimensional injection-production system for oil reservoirs. The system includes an upper vertical well injection-production system, a lower horizontal well injection-production system, and a mixed influence zone system. The method includes: dividing the target oil reservoir into multiple injection-production well groups, each group containing a set of water injection wells and a set of oil production wells; acquiring production dynamic data, production profile test data, and water absorption profile test data for each injection-production well group within a preset observation period; selecting corresponding splitting rules based on the test status represented by the data to obtain the production contribution ratio or water absorption contribution ratio of each well in different layers; determining the total production volume and total water injection volume of each injection-production well group in different layers based on the production contribution ratio or water absorption contribution ratio, the production dynamic data, and the inter-well correlation within the injection-production well group; and determining the stratified injection-production ratio of each layer based on the total production volume and total water injection volume of each layer.

Description

Technical Field

[0001] This application relates to the field of oil and gas exploration technology, specifically to a method, apparatus, and storage medium for determining the layered injection-production ratio in a three-dimensional injection-production system for oil reservoirs. Background Technology

[0002] In the early stages of development, benefiting from the excellent reservoir connectivity and formation energy support of the thick carbonate reservoirs, these reservoirs generally adopted a mixed injection and production model with vertical wells as the main method. This model simplified the process and maintained the overall pressure system through multi-layer combined injection and production. However, as water injection development entered the middle and late stages, the reservoirs gradually exposed problems such as prominent contradictions between injection and production, uneven water drive advancement, and significant differences in inter-layer response. This led to a decline in well group production, a rapid increase in water cut, and an abnormal uplift of the oil-water interface. The traditional integrated injection and production method could no longer support the technical requirements for differentiated management and development optimization.

[0003] To address the issues of declining water drive efficiency and uneven sweep, oilfields have been gradually promoting a three-dimensional injection-production development model in recent years. Under this model, the existing vertical well water injection-production system is typically retained or optimized in the upper reservoir layers to maintain overall pressure; while in the middle and lower reservoir layers, horizontal wells are widely deployed to implement high-sweep injection-production, thereby increasing the utilization of low-permeability sections and delaying water channeling. Especially in areas where well networks are adjusted locally, a complex well network pattern has gradually formed, characterized by "upper vertical well injection-production + lower horizontal well injection-production + mixed injection-production zones," i.e., a three-dimensional injection-production system. This system breaks away from the previous two-dimensional well network coupling model, introducing multiple structural changes at the vertical layer, lateral coupling, and well type combination levels. This results in multi-scale, multi-channel, and multi-response characteristics in the injection-production relationship, leading to an imbalance in water injection ratios and produced fluid distribution, significantly increasing the difficulty of stratified injection-production control. Against this development backdrop, accurately identifying and dynamically calculating the injection-production matching relationship between different layers and well types, especially the stratified injection-production ratio, has become a core technical requirement for field development adjustments. The stratified injection-production ratio is an important indicator reflecting the degree of injection-production coupling in each stratum. It can effectively reveal the energy support efficiency of water drive, the rationality of the well network structure, and the possibility of various anomalies (such as crossflow, over-injection, and loss-injection). It is a prerequisite for realizing differentiated management and optimal measures in a three-dimensional injection-production system. However, the injection-production ratio calculation methods commonly used in the field are mostly limited to the level of single wells or well groups as a whole, and there is a lack of systematic calculation methods for three-dimensional structure and stratified response.

[0004] Therefore, there is an urgent need for a new method for calculating the layered injection-production ratio in three-dimensional injection-production systems applicable to thick carbonate reservoirs. Summary of the Invention

[0005] The purpose of this application is to provide a method, apparatus, and storage medium for determining the stratified injection-production ratio in a three-dimensional injection-production system for oil reservoirs. It aims to solve the key technical problems of inaccurate identification of the stratified injection-production ratio, lack of standardization of the calculation process, and lack of engineering applicability of the results caused by factors such as complex well type combinations, incomplete profile test data, and unclear interlayer coupling relationships when an upper vertical well injection-production system, a lower horizontal well injection-production system, and a locally mixed well network coexist.

[0006] To achieve the above objectives, the first aspect of this application provides a method for determining the stratified injection-production ratio in a three-dimensional injection-production system for an oil reservoir, wherein the oil reservoir is a thick carbonate reservoir, and the three-dimensional injection-production system includes an upper vertical well injection-production system, a lower horizontal well injection-production system, and a mixed influence zone system. The method includes:

[0007] The target reservoir is divided into multiple injection-production well groups according to the three-dimensional injection-production system. Each injection-production well group contains a set of water injection wells and a set of oil production wells.

[0008] Acquire production dynamic data, production fluid profile test data, and water absorption profile test data for each injection-production well group within a preset observation period;

[0009] Based on the test status represented by the production profile test data and the water absorption profile test data, the corresponding splitting rules are selected to perform layered splitting of the production profile of each oil well and the water absorption profile of each water injection well, so as to obtain the production contribution ratio or water absorption contribution ratio of each well in different layers.

[0010] Based on the proportion of fluid production contribution or water absorption contribution, production dynamic data, and the inter-well correlation within the injection-production well group, the total fluid production and total water injection of each injection-production well group in different layers are determined.

[0011] The stratified injection-production ratio for each stratum is determined based on the total liquid production and total water injection volume of each stratum.

[0012] The second aspect of this application provides a device for determining the stratified injection-production ratio in a three-dimensional injection-production system for oil reservoirs, comprising:

[0013] The memory is configured to store instructions;

[0014] The processor is configured to retrieve instructions from memory and, when executing instructions, to implement the method described above for determining the layered injection-production ratio in a three-dimensional injection-production system for reservoirs.

[0015] A third aspect of this application provides a machine-readable storage medium storing instructions that, when executed by a processor, configure the processor to perform the aforementioned method for determining the layered injection-production ratio in a three-dimensional reservoir injection-production system.

[0016] This application addresses key technical issues arising from the coexistence of an upper vertical well injection-production system, a lower horizontal well injection-production system, and a locally mixed well network. These issues stem from factors such as complex well configurations, incomplete profile test data, and unclear interlayer coupling relationships, leading to inaccurate identification of stratified injection-production ratios, a lack of standardized calculation procedures, and insufficient engineering applicability of the results. This method aims to construct an engineering-graded stratified injection-production ratio analysis tool based on conventional dynamic production data, enabling automated identification and calculation. It is suitable for the structural identification, dynamic diagnosis, and optimization of measures in the current phase of adjusting the three-dimensional injection-production system in a certain region's massive carbonate reservoirs.

[0017] Other features and advantages of the embodiments of this application will be described in detail in the following detailed description section. Attached Figure Description

[0018] The accompanying drawings are provided to further illustrate the embodiments of this application and form part of the specification. They are used together with the following detailed description to explain the embodiments of this application, but do not constitute a limitation on the embodiments of this application. In the drawings:

[0019] Figure 1 The illustration shows a flowchart of a method for determining the stratified injection-production ratio of a three-dimensional injection-production system for a reservoir according to an embodiment of this application;

[0020] Figure 2 The illustration shows a flowchart of a method for determining the stratified injection-production ratio of a three-dimensional injection-production system for a reservoir according to another embodiment of this application;

[0021] Figure 3 This illustration schematically shows a single vertical well injection and production system for the upper strata of an oilfield according to an embodiment of this application;

[0022] Figure 4 This illustration schematically shows a single horizontal well injection and production system in the lower strata of an oilfield according to an embodiment of this application;

[0023] Figure 5 This schematic diagram illustrates a current stage of an oilfield's upper vertical well injection-production system (layers A and B) + lower horizontal well + vertical well hybrid injection-production system (C) according to an embodiment of this application.

[0024] Figure 6 The diagram illustrates the internal structure of a computer device according to an embodiment of this application. Detailed Implementation

[0025] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are only for illustration and explanation of the embodiments of this application and are not intended to limit the embodiments of this application. All other embodiments obtained by those skilled in the art based on the embodiments of this application without creative effort are within the scope of protection of this application.

[0026] Figure 1 The illustration schematically shows a flowchart of a method for determining the stratified injection-production ratio in a three-dimensional injection-production system for oil reservoirs according to an embodiment of this application. Figure 1 As shown in one embodiment of this application, a method for determining the stratified injection-production ratio in a three-dimensional injection-production system for oil reservoirs is provided, comprising the following steps:

[0027] Step 102: Divide the target reservoir into multiple injection-production well groups according to the three-dimensional injection-production system. Each injection-production well group contains a set of water injection wells and a set of oil production wells.

[0028] Step 104: Obtain production dynamic data, production fluid profile test data and water absorption profile test data for each injection-production well group within the preset observation period;

[0029] Step 106: Based on the test status characterized by the production profile test data and the water absorption profile test data, select the corresponding splitting rule to perform layered splitting of the production profile of each oil well and the water absorption profile of each water injection well, and obtain the production contribution ratio or water absorption contribution ratio of each well in different layers.

[0030] Step 108: Based on the contribution ratio of production fluid or water absorption, production dynamic data, and the inter-well correlation within the injection-production well group, determine the total production fluid and total water injection volume of each injection-production well group in different layers.

[0031] Step 110: Determine the stratified injection-production ratio for each stratum based on the total liquid production and total water injection volume of each stratum.

[0032] This embodiment establishes a method and device for calculating the injection-production ratio in a three-dimensional injection-production system for thick carbonate reservoirs, specifically addressing a "upper vertical well—lower horizontal well—mixed well network" structure. Utilizing readily available production data (such as monthly water injection volume, fluid production, resistivity, and profile testing), it achieves intelligent profile identification, layered injection-production segmentation, dynamic structural division, and coupled injection-production ratio calculation under complex well network structures. This method allows for precise on-site monitoring of the dynamic injection-production matching status of each well group and layer, supporting dynamic control of layered development and providing strong data support for refined water-drive management.

[0033] In this embodiment, the carbonate reservoir refers to an oil and gas reservoir with carbonate minerals (such as limestone and dolomite) as the main reservoir rocks. The reservoir in this embodiment is a super-thick carbonate reservoir. Super-thick carbonate reservoirs refer to reservoirs with large thickness, significant vertical extension, and high development difficulty. Based on well network geometry and stratigraphic attribution, the spatial coupling relationship between the upper vertical well injection-production system, the lower horizontal well injection-production system, and the mixed well network is clarified, forming a three-dimensional injection-production system identification framework that can be used at the well group-well network level. The interlayer energy transfer and injection-production response paths are clarified, providing stratigraphic and well type boundaries for subsequent layered injection-production ratio calculations. In this embodiment, the three-dimensional injection-production system refers to a development system that arranges water injection wells and oil production wells in three-dimensional space, including the upper vertical well injection-production system, the lower horizontal well injection-production system, and the mixed influence zone system. The upper vertical well injection-production system refers to the area in the upper part of the reservoir where vertical wells are used for water injection and oil production. It is suitable for controlling the top oil layer and mainly undertakes the functions of stabilizing production and maintaining pressure. The injection-production relationship is relatively clear. The lower horizontal well injection-production system refers to the area in the lower part of the reservoir where horizontal wells are used for water injection and oil production. It can increase the contact area with the reservoir and improve the recovery rate. This area is mainly characterized by high-efficiency sweep, and is prone to flow along the wellbore and uneven pressure support. The mixed influence zone system refers to the area where the upper and lower injection-production systems interact. In this area, vertical well oil production and horizontal well water injection coexist, resulting in strong injection-production interference and large response uncertainty. Based on the above classification, a spatial connectivity matrix and coupling relationship standard between injection-production well groups are established to provide a structural basis and discrimination boundary for the subsequent risk indicator system. Therefore, in the plane, based on the principle of "similar injection-production streamlines and reasonable plane distance", water injection wells and oil production wells are divided into multiple injection-production well groups. Each injection-production well group contains a set of water injection wells and a set of oil production wells. Well group division is based on geological structure and well network layout, facilitating local monitoring and management. In thick porous carbonate reservoirs, upper vertical well injection-production systems and lower horizontal well injection-production systems coexist. Without first clearly defining the injection-production unit types and well group boundaries, subsequent stratified injection and allocation is impossible. This step clarifies the scope of subsequent stratified injection and allocation and the corresponding injection-production relationships through unified injection-production unit division and well group identification.

[0034] Next, the processor can acquire production dynamic data and profile test data for each injection-production well group within a preset observation period. The profile test data includes production profile test data and water absorption profile test data. The preset observation period can be set according to project needs, such as a quarter, a month, or a year. Production dynamic data refers to oilfield production data collected within the preset observation period, specifically including data on water injection volume and production volume. Profile test data is stratified data obtained through downhole logging or testing, used to characterize the fluid dynamics of each layer. Specifically, profile test data can include production profile test data, water absorption profile test data, and resistivity data. Production profile test data can include production volume distribution data for each layer of production wells, and water absorption profile test data can include water injection volume distribution data for each layer of injection wells. Resistivity data includes electrical resistivity values, in Ω·m, used as a proxy indicator of permeability for approximate splitting in case of missing data. After acquiring the production dynamics data and profile test data of each injection-production well group within a preset observation period, abnormal data can be identified, and common anomalies can be marked, such as inter-layer flow, blocked sections, missing test data, and sliding sleeve interference. Therefore, based on the test status represented by the profile test data, the processor can select the corresponding splitting rule to perform stratified splitting of the production profile or water absorption profile of each well, thereby obtaining the production contribution ratio or water absorption contribution ratio of each well in different sections. The splitting rule refers to the mathematical rule that allocates the total production or water injection volume of a single well to each section according to the quality or status of the profile test data. This rule may include normalization calculations, resistivity approximation, and anomaly handling (such as the removal of flow-through or blocked sections) to ensure the accuracy of the stratified contribution estimation. The production contribution ratio refers to the proportion (dimensionless) of the production volume of a certain section in a production well to the total production volume of that well. The water absorption contribution ratio refers to the proportion of water injected into a certain layer of a water injection well relative to the total water injected into that well (dimensionless). Then, the processor can determine the total production volume and total water injection volume of each injection-production well group in different layers based on the production contribution ratio or water absorption contribution ratio, the aforementioned production dynamic data, and the inter-well correlation within the injection-production well group. Finally, based on the total production volume and total water injection volume of each layer, the stratified injection-production ratio of each layer is determined to ensure a reasonable configuration of water injection volume in each layer, reflecting the actual structural coupling of energy support between wells.

[0035] Specifically, if it is found that the actual injection volume of a certain layer in a water injection well is much higher than the design volume, and the injection volume of adjacent layers is abnormally low, inter-layer crossflow may exist. In handling this, the injection volume allocation can be adjusted according to production phenomena (e.g., reassigning the crossflow volume to the actual layer it entered), and the injection ratio of the abnormal layer should be increased as a warning when calculating the support coefficient. If necessary, it is recommended to use packers to isolate the layer to prevent crossflow from recurring. "No profile data" refers to situations like horizontal water injection well 1, which lack stratified flow profiles. In such cases, the injection volume can be approximated by using a formula based on well section length or reservoir parameters, while noting that the results have low reliability. The injection volume allocation formula for such wells includes a reference to the total injection volume to ensure that the allocation of each layer is automatically updated if the total volume is adjusted. Regarding abnormal phenomena such as zero water cut but water production, this refers to situations where some wells in a vertical well group show water production dynamics, but stratified production tests do not detect water production in layer A, indicating that water may have entered the wellbore of layer A from layer B and then been produced. For this type of interlayer crossflow on the production side, the actual water produced by the well can be reassigned to the possible source layer (layer B) and corrected when calculating the layer's production. This way, when calculating the injection-production ratio, the production of layer B will include this cross-layer water, reflecting the true interlayer balance. Mixed-layer plugging refers to a situation where, for example, layer B in injection well 1 and layer A in some production wells, the flow in that layer is temporarily halted (no effective profile) due to plugging measures or contamination. For injection wells, the plugged layer can be treated as having an injection volume ≈ 0. For production wells, the plugged layer is treated as having a production volume = 0, and its production contribution comes entirely from the unplugged layer. Based on these situations, a corresponding Excel spreadsheet can be constructed. When calculating in Excel, the injection / production volume cells for these plugged layers are set to zero, and the injection-production ratio formula will correspondingly give an outlier of 0 or infinity (if the production is 0, the layer is not included in the ratio calculation). Uneven injection profile refers to a situation where, despite single-layer water injection in horizontal well 2, due to its long well section and uneven permeability, most of the water may enter the near-wellbore production well along the optimal channel, while the distant wells may not receive effective support. This phenomenon was discovered through monitoring the water cut dynamics of the production wells: one horizontal production well showed high water cut very early, while the other remained at low water cut. In calculations, due to a lack of detailed profile data, the injection volume was temporarily allocated to the two production well areas on an average basis. This anomaly suggests the need for further optimization of the water injector distribution or the addition of profile-adjusting plugging agents. Through the above anomaly identification and handling, it is ensured that the stratified injection volume and production volume data used for calculation are as close as possible to the actual inter-layer injection-production correspondence. Furthermore, in the Excel spreadsheet, adjusted or assumed data can be marked with different colors, along with explanations, to facilitate review and tracking of anomaly handling measures by engineering personnel.

[0036] This application addresses key technical issues arising from the coexistence of an upper vertical well injection-production system, a lower horizontal well injection-production system, and a locally mixed well network. These issues stem from factors such as complex well configurations, incomplete profile test data, and unclear interlayer coupling relationships, leading to inaccurate identification of stratified injection-production ratios, a lack of standardized calculation procedures, and insufficient engineering applicability of the results. This method aims to construct an engineering-graded stratified injection-production ratio analysis tool that relies on conventional dynamic production data (such as monthly water injection volume, fluid production volume, electrical resistivity, and profile test records) for automated identification and calculation. It is suitable for the structural identification, dynamic diagnosis, and optimization of measures in the current phase of stratified injection-production adjustment in a certain region's massive carbonate reservoirs.

[0037] Specifically, the segmentation rules correspond to the production profile and the water absorption profile. It can also be described as follows: the production profile corresponds to the production profile segmentation rules, and the water absorption profile corresponds to the water absorption profile segmentation rules. The first test state represented by the production profile test data includes at least one of the following: standard test state, abnormal water production state, interlayer crossflow state, layer blockage state, and no test data state. The segmentation rules corresponding to different test states represented by the production profile test data are different. In one embodiment, when the first test state represented by the production profile test data is the corresponding standard test state, the corresponding production profile segmentation rule is: determine the production contribution ratio using a normalized calculation method. When the first test state is an abnormal water production state, such as when the water cut of the test profile is zero but the well has produced water, it is considered that the water production is distributed according to the oil production ratio. In this case, the production profile segmentation rule is: allocate the total water production according to the tested oil production ratio to estimate the stratified water production, and combine this with the oil production to determine the production contribution ratio. When the first test state is interlayer crossflow or layer blockage, the production profile splitting rule is as follows: the production volume or production contribution ratio of the abnormal layer is set to zero, and the production contribution ratio of the non-abnormal layer is re-normalized. When the first test state is no test data, it means there is no direct dynamic test data at all. In this case, the production profile splitting rule is as follows: a normalized estimate is performed based on resistivity data to determine the production contribution ratio.

[0038] Specifically, in one embodiment, when the first test state is the corresponding standard test state, i.e., when the product profile test data is normal product profile data, the corresponding product profile splitting rule is to calculate the contribution ratio using a normalization formula. The normalization formula is as follows:

[0039]

[0040] Among them, f i This refers to the proportion of liquid production contribution from the i-th layer (dimensionless), q i This refers to the test yield of the i-th layer, in m³. 3 / d; n refers to the total number of layers, qj This refers to the test yield of the j-th layer, in m³. 3 / d.

[0041] In one embodiment, when the first test state is an abnormal water production state, such as when the water cut of the test profile is zero but the well is producing water, then the water production is considered to be distributed proportionally with the oil production. In this case, the estimated water production of the i-th layer is determined by the following formula:

[0042]

[0043] Where, q w (i) refers to the estimated water production of the i-th layer, q o (i) refers to the tested oil production of the i-th layer, q o (j) refers to the test yield of the j-th layer, Q w This refers to the total water production of the oil well, and n refers to the total number of layers. It's important to note that the estimated water production calculated using this formula is an estimate, while the production contribution percentage f calculated using the previous formula is an estimate. i This is calculated based on the actual situation.

[0044] In one embodiment, when the first test state is the corresponding no-test-data state, the contribution ratio of the liquid production of the i-th layer is calculated by the following formula:

[0045]

[0046] Among them, f i R refers to the proportion of liquid production contribution from the i-th layer. i This refers to the logging resistivity value of the i-th layer, R. j This refers to the logging resistivity value of the j-th layer, and n refers to the total number of layers.

[0047] In one embodiment, when interlayer crossflow exists, the crossflow segment can be assigned a value of 0, and other layers can be renormalized, as shown in the following formula:

[0048] q k =0, (intermittent flow section)

[0049]

[0050] When the test shows a mixed-layer state but a certain layer m is currently blocked, the blocked layer segment can be removed and the normalization process repeated, as shown in the following formula:

[0051] q m =0, (blocking section)

[0052]

[0053] In one embodiment, the second test state characterized by the water absorption profile test data includes at least one of the following: standard test state, tool interference or blockage state, and no test data state.

[0054] Furthermore, in one embodiment, when the second test state is the corresponding standard test state, the corresponding water absorption profile splitting rule is: the water absorption contribution ratio is determined by normalization calculation; when the second test state is a tool interference or blockage state, the water absorption profile splitting rule is: the water injection volume or water absorption contribution ratio of the interfered or blocked layer is set to zero, and the water absorption contribution ratio of the normal layer is normalized again; when the second test state is a no-test-data state, the water absorption profile splitting rule is: if there is available historical water absorption profile data, the historical data is used first to determine the water absorption contribution ratio; if there is no available historical water absorption profile data, the water absorption contribution ratio is determined by normalization estimation based on resistivity data.

[0055] The treatment of the water intake profile is similar to that of the product fluid profile, so it will not be elaborated further. However, the water intake profile requires additional consideration of interference from the sliding sleeve or nozzle. Specifically, if historical profile data q is available before installing the sliding sleeve / nozzle... inj_old (i) If the stratification ratio is correct, then the stratification ratio should be used first. If no historical profile data is available, the resistivity should be normalized for estimation. The specific formula is as follows:

[0056]

[0057] q inj (i)=P inj (i)·Q inj

[0058] Among them, P inj (i) refers to the water absorption contribution ratio of the i-th layer (dimensionless); q inj (i) refers to the water injection volume of the i-th layer, in m³. 3 / d;Q inj This refers to the total water injection volume of the well, in cubic meters (m³). 3 / d; R(i) refers to the resistivity value of the i-th layer, in Ω·m; n refers to the total number of layers, R j This refers to the logging resistivity value of the j-th layer.

[0059] In one embodiment, the total fluid production and total water injection volume of each injection-production well group in different formations are determined by the following formula:

[0060]

[0061] Among them, Q liq (i,j) refers to the fluid production of the j-th layer in the i-th well, Q inj (i,j) refers to the water injection volume of the j-th layer in the i-th well, Qliq (j) refers to the total fluid production of the well group in the j-th layer, Q inj (j) refers to the total water injection volume of the well group in the j-th layer, and m refers to the total number of wells in the well group.

[0062] Furthermore, in one embodiment, the stratified injection-production ratio is determined according to the following formula:

[0063]

[0064] Where Ratio(j) refers to the injection-production ratio of the well group in the j-th layer, Q liq (j) refers to the total fluid production of the well group in the j-th layer, Q inj (j) refers to the total water injection volume of the well group in the j-th layer.

[0065] In one embodiment, when the injection-production well group is a hybrid well network unit, the inter-well relationship is characterized by constructing an injection-production support coefficient matrix. The matrix is ​​used to quantify the energy support of the injection wells for the production wells, so as to determine the total water injection volume.

[0066] Specifically, in one embodiment, the above-mentioned determination method further includes constructing an injection-production support coefficient matrix, wherein the logic for constructing the injection-production support coefficient matrix includes: for a standard inverse nine-point well network structure, the oil well is supported by the water injection well directly opposite it, and the support coefficient is 1; for well formation plugging or no support required, the support coefficient is 0; for horizontal wells without vertical well support, the support coefficient is determined by weighted allocation based on the horizontal distance between the oil well and each water injection well.

[0067] The standard inverted nine-point well network structure features one injection well at the center and eight production wells distributed across the eight cardinal directions (four side wells and four corner wells). This is an idealized two-dimensional model with a clear and symmetrical injection-production relationship. The support coefficient quantifies the coupling strength between injection and production well pairs. The sum of the support coefficients of all injection wells supporting the same production well should be 1, indicating that 100% of the production well's fluid production is supported by these injection wells. Well blockage refers to the physical isolation of a formation due to downhole operations (such as the use of packers, bridge plugs, etc.), preventing injection wells from injecting fluid into that formation or production wells from extracting fluid from it. No support is required because, based on geology or development plans, certain wells or formations are determined to have no injection-production relationship at the current stage, for example, not belonging to the same flow unit or being abandoned. For well blockage or no support requirements, the support coefficient is 0. Furthermore, horizontal wells without vertical well support refer to horizontal production wells deployed in the lower layers of the reservoir (such as layer C), where there are few or no vertical injection wells directly providing energy replenishment from the layers above (such as layers A and B). Their energy primarily comes from horizontal injection wells in the same or adjacent layers. The horizontal distance between the production well and each injection well refers to the straight-line distance between the wellheads of a production well and an injection well on a two-dimensional plane projection. In this embodiment, this distance is a key parameter for measuring the energy transfer efficiency between wells, based on the physical principle that the closer the distance, the higher the energy transfer efficiency. For horizontal wells without vertical well support, a weighted allocation is performed based on the horizontal distance between the production well and each injection well to determine the support coefficient.

[0068] Specifically, in one embodiment, for horizontal wells without vertical well support, the support coefficient of the production well from the injection well is weighted according to the horizontal distance, wherein the support coefficient is calculated by the following formula:

[0069]

[0070] Among them, w k , refers to the weighting factor, a(i,k) refers to the support coefficient (dimensionless), D(i,k) refers to the horizontal distance between the i-th oil well and the k-th water injection well, and n refers to the total number of water injection wells.

[0071] In one embodiment, the determination method further includes: identifying the injection-production imbalance layer based on the stratified injection-production ratio; calculating the reasonable injection volume adjustment value required for the injection-production imbalance layer based on the deviation between its stratified injection-production ratio and the target injection-production ratio; allocating the reasonable injection volume adjustment value to the injection wells corresponding to the injection-production imbalance layer, and outputting the injection volume adjustment plan.

[0072] The stratified injection-production ratio (IPR) refers to the ratio of total injected water to total produced fluid in a specific stratum (e.g., strata A and B). It is a core indicator for measuring the dynamic balance between injection and production in that stratum. A stratum with an IPR imbalance is an oil-bearing stratum whose IPR deviates significantly from the reasonable target range. These are "problem strata" that require close monitoring and adjustment during development. They typically include under-injected and over-injected strata. IPR imbalances can be identified based on the stratified IPR. For strata with IPR imbalances, the processor can calculate the required reasonable injection volume adjustment value based on the deviation between the stratified IPR and the target IPR. The target IPR is the ideal IPR value set for different strata based on oilfield development strategies and geological reservoir characteristics. It is usually centered at 1, but can fluctuate within a certain range (e.g., 0.9-1.1) according to actual needs. The target IPR is the benchmark for judging whether there is an "imbalance" and the "range" of adjustment. To restore the injection-production ratio of an imbalanced stratum to the target ratio, the daily injection volume for that stratum needs to be increased or decreased. Therefore, the required adjustment value for the injection volume allocation for that stratum can be calculated based on the deviation between the stratum's injection-production ratio and the target ratio. This adjustment value is then allocated to the injection wells corresponding to the imbalanced stratum, and an injection adjustment plan is output, clearly indicating which injection well (or wells), which stratum, and how much injection volume needs to be increased or decreased.

[0073] In one embodiment, the determination method further includes: constructing a multi-dimensional risk indicator for comprehensive risk early warning of a three-dimensional injection-production system, wherein the multi-dimensional risk indicator includes at least energy balance indicators, dynamic response indicators, and structural coupling indicators, wherein the stratified injection-production ratio is the core indicator among the energy balance indicators; performing dimensionless standardization processing on the multi-dimensional risk indicators to obtain the standardized risk value corresponding to each indicator; fusing the standardized risk values ​​of indicators belonging to the same category to obtain the comprehensive value of that category; determining the comprehensive risk score based on the comprehensive value of each category; and determining the risk level based on the comprehensive risk score.

[0074] In this embodiment, a multi-dimensional risk index for comprehensive risk early warning of a three-dimensional injection-production system can also be constructed. This multi-dimensional risk index includes energy balance indicators, dynamic response indicators, and structural coupling indicators. Energy balance indicators are used to assess the energy matching degree between injection and production, such as pressure retention rate, injection-production ratio, energy utilization rate, and stratified injection-production ratio. The stratified injection-production ratio calculated in previous embodiments of this application is a core indicator among the energy balance indicators. Dynamic response indicators reflect the system's sensitivity and stability to changes in injection and production, such as production response time, water cut rise rate, and production decline rate. Structural coupling indicators evaluate the structural relationships and connectivity between wells, such as the inter-well interference coefficient, injection-production correspondence rate, and connectivity index. Furthermore, the processor can perform dimensionless standardization processing on the multi-dimensional risk indicators to eliminate the influence of units and dimensions, thereby obtaining the standardized risk value corresponding to each indicator. Through normalization processing and weight allocation, indicators with different dimensions and data sources are uniformly transformed into risk quantification indicators in the [0,1] interval, i.e., standardized risk values. This establishes a robust handling mechanism for situations with missing indicators or incomplete data, ensuring the comparability and reliability of risk assessment results under different data completeness conditions. Specifically, in one embodiment, since the indicators have different dimensions and numerical ranges, the following formula can be used to perform dimensionless standardization processing on multi-dimensional risk indicators:

[0075]

[0076] Among them, X i Let X be the original value of the i-th indicator. min and X max These are the preset lower and upper safety limits for this indicator. This refers to the dimensionless standardized value of the i-th indicator, where the closer the standardized value is to 1, the higher the risk level. For indicators where data is unavailable, estimation is performed using expert scoring or nearest-well completion methods to ensure the continuity and robustness of risk quantification.

[0077] Then, the comprehensive risk score of each injection-production well group can be determined based on the standardized risk values ​​corresponding to each indicator. For example, the comprehensive risk score of each injection-production well group can be calculated by weighted summation of the standardized risk values ​​of each indicator. It can be seen that this embodiment will construct a three-dimensional risk matrix model, which maps various indicators dimensionlessly to a three-dimensional space, where the X-axis represents injection-production balance, the Y-axis represents dynamic response, and the Z-axis represents structural coupling, achieving spatial expression and intuitive identification of risk levels. Then, the risk level of each injection-production well group is determined based on its comprehensive risk score. Risk levels can include low risk, medium risk, high risk, and critical risk. Specifically, this scheme can adopt a four-level risk grading standard (Level I: Green, Level II: Yellow, Level III: Orange, Level IV: Red), achieving a leap from single-indicator analysis to systematic comprehensive diagnosis. This scoring system can maintain stability through expert weighting and data compensation when indicators are missing, ensuring the consistency and comparability of evaluation results under different data completeness levels, significantly improving the robustness and generalizability of the early warning model.

[0078] This method effectively addresses the key technical challenges of untimely risk identification and the lack of a quantifiable early warning indicator system and unified judgment criteria in situations where upper vertical well injection-production systems and lower horizontal well injection-production systems coexist, and where there are localized well networks involving mixed vertical well oil production and horizontal well water injection or oil production. This method establishes a three-dimensional risk identification and early warning model for injection-production systems based on available dynamic production data, transforming risk monitoring from an "experience-based" to a "data-driven" approach. It constructs an engineered, implementable, and scalable risk early warning system suitable for the current development stage of massive carbonate reservoirs.

[0079] In one embodiment, the multidimensional risk indicators also include at least one of the following indicators: injection-production ratio deviation index, injection-production intensity ratio, wellhead pressure support index, production decline index, water cut rise rate, production decline sensitivity index, horizontal well contribution index, and well network structure index.

[0080] Specifically, energy balance indicators should include at least the stratified injection-production ratio, injection-production ratio deviation index, and wellhead pressure support index. Dynamic response indicators should include at least the production decline index, water cut increase rate, and production decline sensitivity index. Structural coupling indicators should include at least the horizontal well contribution index and well network structure index.

[0081] In one embodiment, such as Figure 2As shown, this method can also generate results visualization and multi-dimensional structure output capabilities. Within the Excel environment, it automatically links data tables, stratified ratio output, and visual charts (such as stratified injection-production ratio heat maps, well group injection-production structure bar charts, etc.), achieving an integrated workflow of input data → automatic calculation → chart refresh → stratified ratio output, facilitating deployment and use by oilfield technicians. Specifically, an engineering tool with the following functional modules can be established:

[0082] Input module: Import production volume, water injection, resistivity, and profile type;

[0083] Profile processing module: Automatically identifies profile status (water-bearing / channeling / sealing / no measurement) and normalizes it. Well group division module: Establishes well groups and injection-production matrices according to spatial relationships and completion types.

[0084] Stratified calculation module: Calculates the stratified production / injection ratio and injection-production ratio;

[0085] Chart output module: Automatically generates injection-production ratio profile and adjustment suggestion list.

[0086] By implementing the above methods, it is possible to achieve profile anomaly identification, automatic construction of support structure, and accurate calculation of stratified injection-production ratio in the three-dimensional injection-production system of thick carbonate reservoirs, providing quantitative basis and engineering tool support for stratified development adjustment and water drive efficiency improvement.

[0087] Furthermore, this application can be deployed under existing data and monitoring systems, and can be smoothly upgraded to access advanced parameters such as stratified pressure, permeability curves, and dynamic simulations. It possesses a continuous evolution path from rule-based algorithm-driven to model-algorithm fusion, and from static segmentation to dynamic feedback optimization. Through the implementation of this application, quantitative identification and dynamic evaluation of the injection and production relationship of each segment in a three-dimensional injection-production system can be achieved, significantly improving the scientificity and efficiency of layer injection-production matching adjustments. This provides theoretical support and an engineering tool platform for oilfield stable production and water control, structural optimization, and development strategy decision-making, while also laying the technical foundation for the future introduction of intelligent optimization and dynamic feedback closed-loop control.

[0088] Specifically, if a well lacks stratified logging data, an analogy and thickness-weighted method is used to estimate the production of each stratum. For example, the production of each stratum in the well is determined based on the proportion of pore thickness in each completed stratum, or by referencing the stratified production ratios of neighboring wells. The formula is expressed as:

[0089] Injection allocation without profile data:

[0090] Among them I i,n h represents the injection volume of the i-th injection well in the n-th layer. i,n and k i,n The thickness and permeability of the nth layer in the well are respectively used as the allocation weights.

[0091] When there is no well logging, the flow rate of each layer can be estimated by the product of layer thickness and permeability.

[0092] Output allocation without profile data is shown in the formula: P j,n =P j,total ×f n,avg

[0093] Where P j,n f is the production output of the j-th oil well in the n-th layer. n,avg It is the average production percentage of the nth layer among adjacent wells. That is, the production percentage of the layer in this well is approximated by multiplying the average production percentage of the adjacent wells by the total production.

[0094] Specifically, as shown in Table 1, a specific embodiment is given, which provides the stratified injection volume, corresponding output volume, and calculation indicators of each injection well.

[0095] Table 1. Injection volume and corresponding production of each water injection well, and calculation indicators.

[0096]

[0097] In Table 1, the support coefficient is defined as the ratio of the injection rate to the production rate of a given layer. For injection wells with only a single layer completed, the support coefficient is considered to be 1.00. The lack of injection in layer B of a mixed well group leads to a higher support coefficient for layer C. The injection-production ratio (ratio of injection volume to production volume) and support coefficient for each injection well are calculated and listed in the table above. Any anomalies encountered during the calculation process are also marked in the last column of the table; each well must include at least one anomaly. For example:

[0098] Due to mixed-layer plugging (blockage occurred in the perforated section of this layer), the actual injection volume of layer B in vertical well injection well 1 was far lower than the planned value, resulting in an injection-production ratio of only 0.78 and a support coefficient of 0.75, indicating insufficient water injection in layer B.

[0099] Inter-layer flow occurred in layer A of vertical injection well 2 (some of the injected water that should have entered layer B instead flowed into layer A through the wellbore or formation), resulting in an excessive injection volume in layer A, with an injection-production ratio of 1.63 and a support coefficient as high as 1.50, which means that layer A was over-injected while layer B was slightly under-injected.

[0100] Due to limitations in logging tools, horizontal injection well 1 has no segmented injection profile, and it is assumed that it injects water uniformly along the horizontal section. Although horizontal injection well 2 is located in the same layer, there may be uneven injection profiles (such as uneven distribution along the well section leading to premature water breakthrough in a certain oil well).

[0101] In the mixed well group, horizontal injection wells only inject water at the bottom of layer C, with no direct injection into layer B. This results in a high injection-production ratio (IPR) of 1.80 for layer C, while the IPR for layer B is 0 (no injection but production). During actual production, a pressure drop was observed in the layer B well group. The two vertical production wells initially had zero water cut but were already producing water (a small amount of water was detected on the surface, but stratified testing showed no water production in layer B, suggesting potential water leakage from layer C), verifying the potential leakage from layer C to layer B. This device, by monitoring this anomaly, indicates the need for supplementary injection into layer B or sealing of the interlayer channel.

[0102] After obtaining injection and production data for each well and layer, the processor can calculate the stratified injection-production ratio, defined as the ratio of the injected volume to the produced volume in a given layer. This is typically calculated using the volume over the same time period (day, month, or cumulative). The formula is as follows:

[0103]

[0104] Among them, I n and P n These represent the total injected volume and total produced volume of a certain formation during the evaluation period, respectively. If the daily injected volume and daily produced volume are taken, the daily injection-production ratio is obtained. For each formation involved in the injection well, a daily injection-production ratio can be calculated (as shown in Table 1). It should be noted that the injection-production ratio is typically used to measure the real-time balance of waterdrive development. If the injection-production ratio = 1, it indicates that the injected and produced volumes of that formation are equal; if the injection-production ratio > 1, it indicates that the injected volume is slightly more than the produced volume, which is beneficial for replenishing formation energy (but excessively high ratios may lead to water channeling). If the injection-production ratio < 1, it indicates insufficient injection, which may result in pressure drop or inadequate utilization. In this embodiment, the initial injection-production ratio of each formation did not all reach the ideal value of 1; this is precisely to identify imbalances through calculation.

[0105] Referring to the data in Table 1, the injection-production ratio results for each well group / layer can be obtained. For example:

[0106] Vertical well group 1: The injection-production ratio of layer A is 1.22, and that of layer B is 0.78. This indicates that layer A has a relatively high injection rate, which may accumulate water drive energy in this layer; while layer B has insufficient water injection, with only 0.78 volumes of water replenished for every 1 volume of fluid produced, which will lead to a long-term depletion of formation energy.

[0107] Vertical well group 2: Injection-production ratio of layer A is 1.63, and layer B is 0.95. Layer A has a significantly high injection ratio, suggesting water channeling or ineffective injection; layer B is close to 1 but slightly low, indicating a slight energy deficit.

[0108] Level Group 1 (C Layer): Injection-to-production ratio 1.10, slightly higher than 1, which is within the normal range, indicating that water injection in C Layer basically keeps up with production needs.

[0109] Group 2 (C layer): Injection-production ratio 1.17, slightly higher than Group 1, possibly because the reservoir in this area has only recently been exploited, and pre-injection of water is slightly more than production to maintain pressure.

[0110] In the mixed group, the injection-production ratio in layer C was as high as 1.80, while in layer B it was practically 0 due to the lack of injection. Overall, water injection in layer C was very sufficient, even excessive, but layer B had almost no direct injection support. This explains the field observations: the bottom hole pressure of the two vertical wells in layer B of the mixed group dropped rapidly, while the two horizontal wells in layer C quickly showed signs of water breakthrough (because water mainly circulated in layer C).

[0111] To more vividly illustrate the unevenness of water injection and production in each layer, the total injection and production of the three layers A, B, and C of the entire reservoir can be summarized, and corresponding bar charts can be drawn to more clearly show the injection and total production of each layer.

[0112] Furthermore, based on the analysis of the injection-production ratio, this embodiment introduces the concept of a support coefficient to measure the relative sufficiency of water injection support for each layer. The support coefficient is defined as the ratio of the injection volume of that layer to the total injection volume to the production volume of that layer to the total production volume. Its formula can be expressed as:

[0113]

[0114] Where ∑I and ∑P represent the total injection and total production of each layer in the entire reservoir (or within the evaluation unit), respectively. The above equation shows that the support coefficient is also equal to the ratio of the injection-production ratio of that layer to the global average injection-production ratio. For example, if the overall injection-production ratio of the entire reservoir is 1.09, then the support coefficient of layer A in Table 1 is approximately 1.22 / 1.09 ≈ 1.12 (the slight difference is because this application calculates based on well groups; the precise value in this example is 1.21, and subsequent calculations are based on the entire reservoir).

[0115] A support coefficient of 1 indicates that the water injection support received by a layer matches its output contribution; >1 indicates that the water injection support of that layer is relatively excessive, with the water received exceeding its output proportion; <1 indicates that the water injection support of that layer is relatively insufficient. The support coefficient reflects the fairness of water injection resource allocation between layers more intuitively than the simple injection-production ratio.

[0116] Based on the total calculations of layers A, B, and C of the entire reservoir, we can obtain:

[0117] The support coefficient of layer A is approximately 1.21, indicating that the proportion of water injection received by layer A (approximately 28%) is higher than its output proportion (approximately 23%), and the water injection support is slightly excessive.

[0118] The support coefficient of layer B is approximately 0.68, which is far below 1. This indicates that layer B produced about 42% of the total reservoir liquid volume, but only received about 28% of the water injection volume support, indicating a serious under-injection.

[0119] The support coefficient of layer C is approximately 1.25, indicating that the water injection ratio of layer C (approximately 44%) is higher than its output ratio (approximately 35%), indicating excessive injection.

[0120] As can be seen, this method can quantify the degree of mismatch between water supply and output consumption at each layer. The support coefficient provides direction for further optimization: in this example, it is necessary to increase the support coefficient of layer B to close to 1 (e.g., by increasing the injection volume of layer B or reducing the ineffective output of layer B), while appropriately controlling the water injection of layers A and C (to avoid excessive water cross-contamination leading to ineffective cycles). If the scheme of this application is adopted, the changes in the support coefficient of each layer can be monitored in real time, thereby dynamically adjusting the water injection strategy.

[0121] Furthermore, the solution in this application can also implement the entire above calculation process by building a model in Excel. The main worksheets include:

[0122] Well Formation Data Table: Lists injection / production data and anomaly markers for each layer of each well. Water injection wells and production wells are summarized separately. Formulas can be set in this table to link to data sources; for example, the production data in the water injection well table will reference the production summary of the corresponding production well layer.

[0123] Summary Calculation Table: This table summarizes the total injection and output for each layer, calculates the overall injection-to-production ratio, and the support coefficient for each layer. In this table, the total injection / output for each layer is summed using the SUM function, the injection-to-production ratio is calculated by division, and the support coefficient is then calculated according to the aforementioned formula.

[0124] Parameters and Assumptions Table: Records parameters such as density and volume factor (if necessary, convert standard condition cubic meters to formation conditions). This example uses direct volume comparisons and does not yet introduce volume factor differences; therefore, this table mainly records notes on anomaly handling and the default allocation ratios used.

[0125] Results and Charts: Organize the output tables and the data sources driving the charts.

[0126] In Excel, formula links maintain a dynamic relationship between input data, calculation results, and charts. When a user modifies the injection volume or production data of a well (e.g., adjusting the scheme by adding a B-layer injection well), the relevant cells automatically update the injection-production ratio and support coefficient, and the chart refreshes accordingly. This engineered implementation facilitates repeated trial calculations and scenario analysis.

[0127] Chart generation: Using Excel's charting tools, several graphs were generated to aid in analysis, including:

[0128] Layered injection-to-production ratio curves: Line graphs showing the change of injection-to-production ratio for each layer over time. If monthly data is available, injection-to-production ratio curves for each layer can be plotted to observe the changing trend as development progresses. In the initial stage of this embodiment, only the injection-to-production ratios for each layer at the initial moment are given; subsequent monthly data can be added to form curves.

[0129] Interlayer structure diagram: illustrating the thickness of layers A, B, and C and the connection relationship of wells (this diagram can be drawn in Word or generated by professional drawing software). The diagram shows the positional relationship of vertical wells penetrating layers A / B, horizontal wells extending along layer C, and injection-production wells in mixed well groups.

[0130] Injection Profile Columnar Chart: For each injection well, a layered injection profile columnar chart is drawn. For example, the injection distribution of vertical well injection well 1 in layers A and B (layer A 1750m). 3 / d, B level 750m 3 / d), which visually shows the imbalance where layer A accounts for 70% while layer B only accounts for 30%.

[0131] Production profile bar chart: Similarly, a layered production distribution map of the oil well can be drawn (e.g., for a certain oil well in vertical well group 1: what percentage of oil is produced in layer A, and what percentage is produced in layer B). These charts are used to verify the correspondence between the injection and production profiles.

[0132] Support coefficient comparison chart: The differences in support coefficients of layers A, B, and C are represented by radar charts or bar charts, highlighting the issue that the support coefficient of layer B is significantly lower.

[0133] By implementing the above methods, comprehensive stratified injection-production analysis results were obtained, and the main conclusions are as follows:

[0134] Layer A: The injection-to-production ratio is approximately 1.3, and the support coefficient is >1, indicating that the overall water content in Layer A is slightly high. This is beneficial for maintaining top pressure in the short term, but excessive water injection should be prevented from triggering an early surge. Close monitoring of the water cut dynamics in Layer A is recommended.

[0135] Layer B: With an injection-to-production ratio of only 0.74 and a support coefficient far below 1, it is a weak point in water injection. Layer B bears a large portion of production but does not receive sufficient water injection support, which will eventually lead to a drop in pressure and limited production. Measures must be taken to improve water injection in Layer B: such as increasing water injection channels (e.g., adding a new water injection branch in the mixed well group, or converting a production well in Layer B into a water injection well), and sealing any potential inter-layer crossflow channels to ensure effective water injection into Layer B.

[0136] Layer C: The injection-production ratio is approximately 1.36, with the highest support coefficient (~1.25), indicating relatively abundant water injection. Concentrated water injection in Layer C by the mixed well group has led to localized over-injection. While this rapidly replenishes the underlying energy, it has also caused water breakthroughs in horizontal wells and internal circulation within Layer C at an early stage. Subsequently, the water injection volume in Layer C can be appropriately reduced, transferring excess injection capacity to support Layer B. In terms of equipment, the opening of the distributors in the horizontal injection wells can be adjusted to reduce the water injection intensity in Layer C.

[0137] In summary, the stratified injection-production ratio calculation method for the three-dimensional injection-production system demonstrated in this embodiment successfully quantifies the water injection-production balance of different layers, identifies the main problem (under-injection in layer B), and provides a basis for adjustment. Implemented using Excel, the entire calculation process is transparent and easily updated, and can be used for daily production monitoring and scheme optimization. In practical applications, in conjunction with stratified injection-production devices (such as downhole injection tools and production packers), the injection and production of each layer can be monitored and adjusted simultaneously to achieve dynamic equilibrium and improve water drive development efficiency.

[0138] Furthermore, to more clearly demonstrate the differences between this solution and existing technologies, please refer to the following: Figure 3 The diagram shown is of a single vertical well mixed injection and production system in the upper strata of an oilfield, and... Figure 4 The diagram shows a schematic of a single horizontal well injection-production system in the lower strata of an oilfield. The labels A, B, and C in the diagram represent different development strata or geological units vertically divided into a thick oil reservoir. Layer A typically represents the upper strata of the reservoir. Layer B typically represents the middle strata. Layer C typically represents the lower strata. Figure 4 As shown, the lower formations of this oilfield utilize horizontal wells exclusively. It can be seen that the upper vertical well and lower horizontal well systems operate relatively independently and in parallel in a three-dimensional injection-production mode, which is a typical structure of a three-dimensional injection-production system addressed in this application. The upper vertical well injection-production system includes layers A and B, where development is entirely conducted using vertical wells. Blue vertical wells are water injection wells, and green vertical wells are oil production wells. The upper vertical well injection-production system is primarily responsible for maintaining formation pressure at the top and middle of the reservoir and producing crude oil; the injection-production relationship is relatively clear and independent. The lower horizontal well injection-production system, i.e., layer C, is developed entirely using horizontal wells in this area. Blue horizontal wells are water injection wells, and green horizontal wells are oil production wells. Horizontal wells are located within layer C to maximize reservoir contact, efficiently extract lower oil and gas, and control bottom water propulsion. The advantage of this mode is the relative independence of the upper and lower systems, reducing direct inter-well interference. However, its risks lie in the vertical energy balance and differences in contribution between formations. Vertical energy balance refers to ensuring that water injection into the lower C layer does not prematurely seep into the upper A and B layers, and vice versa. Differences in contribution between layers mean that without effective monitoring, it is difficult to determine which system is primarily responsible for a decrease in yield or an increase in water cut.

[0139] like Figure 5 The diagram shows a current stage of an oilfield's upper vertical well injection-production system (layers A and B) + lower horizontal well + vertical well hybrid injection-production system (C). It can be seen that... Figure 5 The structural diagram shown is compared to Figure 4 More complex, higher risk. For example... Figure 5As shown, a mixed well pattern of vertical and horizontal wells with intersecting injection and production occurs in the lower strata. This is a core challenge that the risk warning method proposed in this application needs to focus on and solve. Figure 5 The upper vertical well injection-production system comprises layers A and B, while the lower mixed well network system is layer C. In layer C, instead of a single well type, vertical wells (green oil production wells) and horizontal wells (blue water injection wells) coexist. This creates a cross-flow field of "vertical well oil production + horizontal well water injection." The vertical well acts as a "point" for production, while the horizontal well acts as a "line" for water injection; this geometric mismatch easily generates complex fluid movements. Therefore, this application considers multi-dimensional risk indicators, including energy balance indicators, dynamic response indicators, and structural coupling indicators, to quantitatively evaluate the coordination of this vertical and horizontal well production capacity configuration. This allows for accurate determination of the risk level of each injection-production well group, enabling risk early warning.

[0140] Therefore, it can be seen that the solution of this application can systematically identify the injection-production structure of well groups, reasonably split profile data, automatically remove anomalies and output the layer injection-production ratio results that can be used for engineering adjustments, thereby supporting the optimization of differentiated development strategies and the dynamic balance adjustment of injection and production in the field.

[0141] Figure 1 This is a flowchart illustrating a method for determining the stratified injection-production ratio in a three-dimensional reservoir injection-production system, as shown in one embodiment. It should be understood that, although... Figure 1 The steps in the flowchart are shown sequentially as indicated by the arrows, but these steps are not necessarily executed in the order indicated by the arrows. Unless otherwise explicitly stated herein, there is no strict order in which these steps are executed, and they can be performed in other orders. Figure 1 At least some of the steps in the process may include multiple sub-steps or multiple stages. These sub-steps or stages are not necessarily completed at the same time, but can be executed at different times. The execution order of these sub-steps or stages is not necessarily sequential, but can be executed in turn or alternately with other steps or at least some of the sub-steps or stages of other steps.

[0142] In one embodiment, an apparatus (not shown in the figure) for determining the stratified injection-production ratio of a three-dimensional injection-production system for a reservoir is provided, the apparatus comprising:

[0143] The memory is configured to store instructions;

[0144] The processor is configured to retrieve the instructions from the memory and, when executing the instructions, to implement the method for determining the stratified injection-production ratio for a three-dimensional injection-production system for reservoirs as described in the above embodiments.

[0145] The processor contains a kernel, which retrieves the corresponding program units from memory. One or more kernels can be configured, and adjusting kernel parameters allows for the determination of the stratified injection-production ratio in a three-dimensional reservoir injection-production system.

[0146] The memory may include non-permanent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM, and the memory includes at least one memory chip.

[0147] This application provides a storage medium storing a program that, when executed by a processor, implements the above-described method for determining the layered injection-production ratio in a three-dimensional injection-production system for oil reservoirs.

[0148] This application provides a processor for running a program, wherein the program executes the above-described method for determining the stratified injection-production ratio of a three-dimensional injection-production system for oil reservoirs.

[0149] In one embodiment, a computer device is provided, which may be a server, and its internal structure diagram may be as follows: Figure 6 As shown. The computer device includes a processor A01, a network interface A02, a memory (not shown), and a database (not shown) connected via a system bus. The processor A01 provides computing and control capabilities. The memory includes internal memory A03 and a non-volatile storage medium A04. The non-volatile storage medium A04 stores an operating system B01, a computer program B02, and a database (not shown). The internal memory A03 provides an environment for the operation of the operating system B01 and the computer program B02 stored in the non-volatile storage medium A04. The network interface A02 is used for communication with external terminals via a network connection. When the processor A01 executes the computer program B02, it implements a method for determining the layered injection-production ratio in a three-dimensional reservoir injection-production system.

[0150] Those skilled in the art will understand that Figure 6 The structure shown is merely a block diagram of a portion of the structure related to the present application and does not constitute a limitation on the computer device to which the present application is applied. Specific computer devices may include more or fewer components than those shown in the figure, or combine certain components, or have different component arrangements.

[0151] This application provides a computer (electronic) device, which includes a processor, a memory, and a program stored in the memory and executable on the processor. When the processor executes the program, it implements the steps of any of the above methods for determining the layered injection-production ratio of a three-dimensional injection-production system for oil reservoirs.

[0152] This application also provides a computer program product that, when executed on a data processing device, is suitable for executing a program that initializes steps for determining the stratified injection-production ratio of a three-dimensional injection-production system for oil reservoirs.

[0153] Those skilled in the art will understand that embodiments of this application can be provided as methods, systems, or computer program products. Therefore, this application can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, this application can take the form of a computer program product embodied on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0154] This application is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of this application. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0155] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0156] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0157] In a typical configuration, a computing device includes one or more processors (CPUs), input / output interfaces, network interfaces, and memory. Memory may include non-persistent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, like read-only memory (ROM) or flash RAM. Memory is an example of computer-readable media.

[0158] Computer-readable media includes both permanent and non-permanent, removable and non-removable media that can store information using any method or technology. Information can be computer-readable instructions, data structures, modules of programs, or other data. Examples of computer storage media include, but are not limited to, phase-change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technologies, CD-ROM, digital versatile optical disc (DVD) or other optical storage, magnetic tape, magnetic magnetic disk storage or other magnetic storage devices, or any other non-transferable medium that can be used to store information accessible by a computing device. As defined herein, computer-readable media does not include transient computer-readable media, such as modulated data signals and carrier waves. It should also be noted that the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element. The above are merely embodiments of this application and are not intended to limit this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the scope of the claims of this application.

Claims

1. A method for determining the stratified injection-production ratio in a three-dimensional injection-production system for oil reservoirs, characterized in that, The reservoir is a thick carbonate rock reservoir. The three-dimensional injection-production system includes an upper vertical well injection-production system, a lower horizontal well injection-production system, and a mixed influence zone system. The method includes: The target reservoir is divided into multiple injection-production well groups according to the three-dimensional injection-production system. Each injection-production well group contains a set of water injection wells and a set of oil production wells. Acquire production dynamic data, production fluid profile test data, and water absorption profile test data for each injection-production well group within a preset observation period; Based on the test status represented by the production profile test data and the water absorption profile test data, the corresponding splitting rules are selected to perform layered splitting of the production profile of each oil well and the water absorption profile of each water injection well, so as to obtain the production contribution ratio or water absorption contribution ratio of each well in different layers. Based on the production contribution ratio or the water absorption contribution ratio, the production dynamic data, and the inter-well correlation within the injection-production well group, the total production volume and total water injection volume of each injection-production well group in different layers are determined. The stratified injection-production ratio for each stratum is determined based on the total liquid production and total water injection volume of each stratum.

2. The determination method according to claim 1, characterized in that, The first test state characterized by the produced fluid profile test data includes at least one of the following: standard test state, abnormal produced water state, interlayer crossflow state, layer blockage state, and no test data state.

3. The determination method according to claim 2, characterized in that, When the first test state is the corresponding standard test state, the corresponding liquid production profile splitting rule is: the proportion of liquid production contribution is determined by normalization calculation method; When the first test state is an abnormal water production state, the liquid production profile splitting rule is as follows: the total water production is allocated according to the test oil production ratio to estimate the stratified water production, and the contribution ratio of the liquid production is determined in combination with the oil production. When the first test state is interlayer crossflow state or layer blockage state, the liquid production profile splitting rule is: set the liquid production volume or liquid production contribution ratio of abnormal layer to zero, and normalize the liquid production contribution ratio of non-abnormal layer. When the first test state is a state with no test data, the liquid production profile splitting rule is: to perform normalized estimation based on resistivity data to determine the proportion of liquid production contribution.

4. The determination method according to claim 3, characterized in that, When the first test state is the corresponding standard test state, the normalization formula is as follows: Wherein, f i is the contribution of the liquid production of the i-th layer, q i is the test liquid production of the i-th layer, n is the total number of layers, q j is the test liquid production of the j-th layer.

5. The determination method according to claim 3, characterized in that, When the first test state is an abnormal water production state, the estimated water production of the i-th layer is determined by the following formula: where q w (i) refers to the estimated water production of the i-th layer segment, q o (i) refers to the test oil production of the i-th layer segment, q o (j) refers to the test fluid production of the j-th layer, Q w refers to the total water production of the oil well, and n refers to the total number of layers.

6. The determining method according to claim 3, characterized in that, When the first test state is the corresponding state with no test data, the contribution ratio of the liquid produced by the i-th layer is calculated using the following formula: Among them, f i R refers to the proportion of liquid production contribution from the i-th layer. i R refers to the resistivity value of the i-th layer in well logging. j This refers to the logging resistivity value of the j-th layer, and n refers to the total number of layers.

7. The determination method according to claim 1, characterized in that, The second test state characterized by the water absorption profile test data includes at least one of the following: standard test state, tool interference or blockage state, and no test data state.

8. The determination method according to claim 7, characterized in that, When the second test state is the corresponding standard test state, the corresponding water absorption profile splitting rule is: the water absorption contribution ratio is determined by normalization calculation method; When the second test state is the tool interference or blockage state, the water absorption profile splitting rule is: set the water injection volume or water absorption contribution ratio of the interfered or blocked layer to zero, and normalize the water absorption contribution ratio of the normal layer. When the second test state is the state of no test data, the water absorption profile splitting rule is as follows: if there is available historical water absorption profile data, the historical data is used first to determine the water absorption contribution ratio; if there is no available historical water absorption profile data, a normalized estimation is performed based on resistivity data to determine the water absorption contribution ratio.

9. The determination method according to claim 1, characterized in that, The total fluid production and total water injection volume of each injection-production well group in different formations are determined using the following formula: Among them, Q liq (i,j) refers to the fluid production of the j-th layer in the i-th well, Q inj (i,j) refers to the water injection volume of the j-th layer in the i-th well, Q liq (j) refers to the total fluid production of the well group in the j-th layer, Q inj (j) refers to the total water injection volume of the well group in the j-th layer, and m refers to the total number of wells in the well group.

10. The determination method according to claim 1, characterized in that, The stratified injection-production ratio is determined according to the following formula: Where Ratio(j) refers to the injection-production ratio of the well group in the j-th layer, Q liq (j) refers to the total fluid production of the well group in the j-th layer, Q inj (j) refers to the total water injection volume of the well group in the j-th layer.

11. The determination method according to claim 1, characterized in that, When the injection-production well group is a mixed well network unit, the inter-well correlation is characterized by constructing an injection-production support coefficient matrix. The matrix is ​​used to quantify the energy support of the injection wells for the production wells, so as to determine the total water injection volume.

12. The determining method according to claim 11, characterized in that, The determination method further includes constructing an injection-production support coefficient matrix, wherein the logic for constructing the injection-production support coefficient matrix includes: For a standard inverted nine-point well network structure, the oil well is supported by the water injection well directly opposite it, and the support coefficient is 1. For well plugging or situations where no support is required, the support coefficient is 0; For horizontal wells without vertical well support, the support coefficient is determined by weighted allocation based on the horizontal distance between the oil production well and each water injection well.

13. The determination method according to claim 12, characterized in that, For horizontal wells without vertical well support, the support coefficient of the production well from the injection well is weighted according to the horizontal distance, wherein the support coefficient is calculated by the following formula: Among them, w k , refers to the weighting factor, a(i,k) refers to the support coefficient (dimensionless), D(i,k) refers to the horizontal distance between the i-th oil well and the k-th water injection well, and n refers to the total number of water injection wells.

14. The determination method according to claim 1, characterized in that, The determination method further includes: Based on the stratified injection-production ratio, identify the layers where injection-production imbalance occurs; For the aforementioned injection-production imbalance strata, the required reasonable injection volume adjustment value for that stratum is calculated based on the deviation between its stratified injection-production ratio and the target injection-production ratio. The reasonable injection volume adjustment value is allocated to the injection wells corresponding to the injection-production imbalance layers, and an injection adjustment plan is output.

15. The determining method according to any one of claims 1 to 14, characterized in that, The determination method further includes: A multi-dimensional risk index is constructed for comprehensive risk early warning of the three-dimensional injection and production system. The multi-dimensional risk index includes at least energy balance index, dynamic response index and structural coupling index. Among them, the stratified injection and production ratio is the core index among the energy balance index. The multi-dimensional risk indicators are subjected to dimensionless standardization to obtain the standardized risk value corresponding to each indicator. The standardized risk values ​​of indicators belonging to the same category are combined to obtain the comprehensive value for that category; The overall risk score is determined based on the comprehensive value of each category; The risk level is determined based on the comprehensive risk score.

16. The determination method according to claim 15, characterized in that, The multi-dimensional risk indicators also include at least one of the following indicators: Injection-production ratio deviation index, injection-production intensity ratio, wellhead pressure support index, production decline index, water cut increase rate, production decline sensitivity index, horizontal well contribution index, and well network structure index.

17. A device for determining the stratified injection-production ratio in a three-dimensional injection-production system for oil reservoirs, characterized in that, include: The memory is configured to store instructions; The processor is configured to retrieve the instructions from the memory and, when executing the instructions, to implement the method for determining the stratified injection-production ratio of a three-dimensional injection-production system for a reservoir according to any one of claims 1 to 16.

18. A machine-readable storage medium storing instructions thereon, characterized in that, When executed by a processor, this instruction causes the processor to be configured to perform the method for determining the stratified injection-production ratio of a three-dimensional injection-production system for a reservoir, as described in any one of claims 1 to 16.

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