Exploitation optimization design method for high-water-content small oil reservoir in high-porosity, high-permeability and strong-edge water

Abstract

The invention relates to an exploitation optimization design method for a high-water-content small reservoir in high-porosity, high-permeability and strong-edge water, and belongs to the technical field of oilfield development. According to the injection-production scheme optimization design method for the strong-edge-water small oil reservoir, numerical simulation is utilized, on the basis of oil reservoir remaining oil distribution characteristic research, through numerical simulation optimization of water injection and polymer injection, the simulation result shows that by means of the injection-production scheme, the recovery efficiency can be effectively improved, the advancing speed of edge water can be restrained, the water-free oil production period of an oil well can be prolonged, and the oil recovery efficiency can be improved. And finally, the oil reservoir recovery efficiency is improved, and a basis and guidance are provided for potential tapping of the remaining oil of the high-porosity, high-permeability and strong-edge-water oil reservoir in the middle-high water content later stage. Wherein the polymer flooding has the effects of controlling the mobility ratio, adjusting the water absorption profile and the like. An injection-production scheme capable of improving the recovery efficiency is provided for the high-water-content small oil reservoir in the high-porosity high-permeability strong-edge water, and technical reference is provided for other oil reservoirs of the same type.

Description

Technical Field

[0001] The invention relates to a method for optimizing the design of mining a small oil reservoir with high water content in high-porosity, high-permeability, strong edge water, and belongs to the technical field of oilfield development. Background Art

[0002] Small oil reservoirs with high porosity, high permeability, strong edge water and high water content are characterized by small reserves, good and relatively homogeneous reservoir properties, strong edge water energy and low crude oil viscosity. With the continuous deepening of development, the liquid and oil production rate is high, the waterline advancement speed is fast, and the water content rises rapidly. After entering the medium and high water content period, the small sand body cannot be effectively utilized due to the one-time development of natural energy at the top and flanks of the remaining oil, and efficient adjustment is ineffective.

[0003] To improve the recovery rate of strong edge water reservoirs, Chinese patent document CN106437650A discloses a method for improving the recovery rate of strong edge water heavy oil reservoirs through foam-assisted steam flooding, comprising the following steps: a. injecting a mixture of foam, nitrogen, and steam into oil wells at the oil-water edge for 8 to 15 days, and performing nitrogen foam-assisted steam stimulation on the edge wells; b. injecting the mixture of foam, nitrogen, and steam into steam injection wells in the middle of the reservoir for 10 to 30 days; c. injecting steam into the steam injection wells in the middle of the reservoir alone for 80 to 120 days; d. repeating steps a, b, and c; the steam injection rate is 4 to 10 t / h; the foam is a sulfonate containing benzene rings with a linear chain structure on the benzene rings, and the foam injection rate is 0.4 to 1.2% (by mass) of the steam injection rate; and the nitrogen injection rate is 0.5 to 1.5 times (by underground volume) of the steam injection rate. This method involves adding a high-temperature foaming agent and nitrogen to generate foam in the formation pores. The high-strength foam film seals high-permeability layers or large pores, effectively inhibiting steam from entering high-permeability zones and diverting it to undisplaced zones such as low-permeability zones. This increases the displacement volume, broadens the steam sweep area, effectively controls the rate of reservoir edge and bottom water intrusion, reduces the water content of the produced fluid, and thus improves the recovery rate of heavy oil reservoirs with strong edge water. However, this method is only suitable for steam development of heavy oil and is not suitable for small reservoirs with high porosity, high permeability, strong edge water, and high water content.

[0004] Therefore, there is an urgent need to develop an optimization design method for improving the production of small oil reservoirs with high porosity, high permeability and strong edge water in the medium and high water cut period. Summary of the Invention

[0005] The purpose of the present invention is to provide a method for optimizing the design of mining of small oil reservoirs with high porosity, high permeability and strong edge water and high water content, which can solve the problem of low recovery rate of small oil reservoirs with high porosity, high permeability and strong edge water and high water content in the middle and high water content stage.

[0006] In order to achieve the above-mentioned object, the technical solution adopted by the method for optimizing the design of exploitation of small oil reservoirs with high porosity, high permeability, strong edge water and high water content of the present invention is as follows:

[0007] A method for optimizing the design of production of a small oil reservoir with high porosity, high permeability, strong edge water and high water content comprises the following steps:

[0008] (1) Establish a numerical simulation model for a small oil reservoir with high porosity, high permeability, and strong edge water, and then perform numerical simulation to determine the distribution of remaining oil in the reservoir;

[0009] (2) Conduct water flooding simulations for small oil reservoirs with high porosity, high permeability, strong edge water, and high water content, and optimize the water flooding well pattern and water flooding injection and production parameters, including injection rate and production rate;

[0010] (3) Conduct a feasibility analysis of polymer flooding on a small oil reservoir with high porosity, high permeability, and strong edge water and high water content. If the small oil reservoir with high porosity, high permeability, and strong edge water and high water content meets the conditions for polymer flooding, perform polymer flooding simulation on the small oil reservoir with high porosity, high permeability, and strong edge water and high water content after water flooding simulation, and optimize the polymer flooding well pattern and the injection and production parameters of the polymer flooding. The injection and production parameters of the polymer flooding include the injection and production ratio, the slug volume, the concentration of the polymer in the polymer flooding agent, and the injection rate of the polymer flooding agent.

[0011] The method for optimizing the design of injection and production schemes for small oil reservoirs with high porosity, high permeability, and strong edge water and high water content of the present invention utilizes numerical simulation. Based on the research on the distribution characteristics of the remaining oil in the reservoir, the method optimizes the numerical simulation of water injection and polymer injection. The simulation results show that the use of the above-mentioned injection and production scheme can effectively improve the recovery rate, inhibit the advancement speed of the edge water, increase the waterless production period of the oil well, and ultimately improve the recovery rate of the reservoir, providing a basis and guidance for the potential of the remaining oil in high-porosity, high-permeability, and strong edge water reservoirs entering the late stage of medium-high water content. Among them, polymer drive has the functions of controlling the mobility ratio and adjusting the water absorption profile, and can reduce the steam channeling caused by the imbalance of the formation in the subsequent nitrogen drive. The present invention provides a set of injection and production schemes that can improve the recovery rate for small oil reservoirs with high porosity, high permeability, and strong edge water and high water content, and provides a technical reference for other oil reservoirs of the same type.

[0012] In the present invention, a small oil reservoir with high porosity, high permeability, strong edge water and high water content refers to an oil reservoir that meets the following conditions: (1) porosity greater than 25%; (2) permeability greater than 800 mD; (3) edge water volume greater than 300 times the reservoir volume; (4) comprehensive water content of the oil reservoir greater than 80%; and (5) oil reservoir reserves less than 10 million tons.

[0013] The development stages of small oil reservoirs with high porosity, high permeability and strong edge water include water-free development, low water content development and medium-high water content development stages. Oil reservoirs entering the medium-high water content development stage belong to the late development process, that is, small oil reservoirs with high porosity, high permeability and strong edge water and high water content.

[0014] Preferably, during water flooding simulation, the water flooding well pattern is optimized first, the water injection wells are determined, and then the water injection rate and production rate in the injection-production parameters are optimized in sequence.

[0015] Preferably, when optimizing the water drive well pattern, the optimization criteria for the water drive well pattern is: when the daily water injection rate of the injection wells is the same and the daily liquid production rate of the oil production wells is the same, the water drive well pattern corresponding to the maximum oil increase is the preferred water drive well pattern.

[0016] Preferably, when optimizing the injection and production parameters of water drive, the optimal criterion for water injection rate is: under the condition of the same daily liquid production of a single well, the water injection rate corresponding to the maximum oil production increment is the optimal water injection rate; the optimal criterion for production rate is: under the condition of the same water injection rate of the water injection wells, the production rate corresponding to the maximum recovery degree is the optimal production rate.

[0017] In the present invention, the production rate in the injection and production parameters of water flooding refers to the daily liquid production of the oil well.

[0018] In the present invention, the conditions for polymer flooding can be determined by referring to the requirements of the standard "SY / T6575-2016 Technical Specifications for Screening Methods for Enhanced Oil Recovery in Oil Fields".

[0019] During polymer flooding simulations, the injection-production ratio is 1.0 when the formation pressure retention rate of a small reservoir with high porosity, high permeability, and high water content in high-edge water is at least 94%. The formation pressure retention rate is equal to the ratio of the current formation pressure to the original formation pressure. The slug size and polymer concentration in the polymer flooding agent can be determined based on the relevant parameters of polymer flooding in existing reservoirs with similar properties to the small reservoir with high porosity, high permeability, and high water content in high-edge water.

[0020] Preferably, during polymer flooding simulation, the polymer flooding well pattern is optimized first to determine the injection wells, and then the injection rate of the polymer flooding agent, the concentration of the polymer in the polymer flooding agent, and the slugging volume among the injection and production parameters of the polymer flooding are optimized in sequence.

[0021] Preferably, when optimizing the polymer flooding well pattern, the preferred criterion for the polymer flooding well pattern is: under the conditions of the same daily injection volume of the injection wells, the same concentration of the polymer in the polymer flooding agent, the same slug size, and the same daily liquid production of the oil production wells, the polymer flooding well pattern corresponding to the maximum oil increase is the preferred polymer flooding well pattern.

[0022] Preferably, when optimizing the injection and production parameters of polymer flooding, the preferred criterion for the injection rate of the polymer flooding agent is: under the same conditions of injection-production ratio, polymer concentration in the polymer flooding agent, and slug size, the injection rate corresponding to the maximum recovery factor improvement is the preferred polymer flooding agent injection rate;

[0023] The optimal standard for polymer concentration in polymer flooding is: under the same injection-production ratio, injection rate, and slug size, the polymer concentration in the polymer flooding agent corresponding to the maximum comprehensive index is the optimal polymer concentration in the polymer flooding agent. The comprehensive index is equal to the ratio of the product of the recovery improvement value and the oil increase per ton of polymer solution to 100.

[0024] The optimal criterion for slug volume is: under the same conditions of injection-production ratio, injection rate, polymer concentration in polymer flooding agent, and slug size, the slug volume corresponding to the maximum comprehensive index is the optimal slug volume. The comprehensive index is equal to the ratio of the product of the recovery improvement value and the oil increase per ton of polymer solution to 100.

[0025] Preferably, the extraction optimization design method for small oil reservoirs with high porosity, high permeability and strong edge water and high water content also includes the following steps: before the water drive simulation, first carry out nitrogen drive numerical simulation optimization of small oil reservoirs with high porosity, high permeability and strong edge water and high water content, and then carry out water drive simulation; or after the water drive simulation, first carry out nitrogen drive numerical simulation optimization of small oil reservoirs with high porosity, high permeability and strong edge water and high water content, and then carry out polymer drive feasibility analysis and polymer drive simulation; or after the polymer drive simulation, carry out nitrogen drive numerical simulation optimization of small oil reservoirs with high porosity, high permeability and strong edge water and high water content; the nitrogen drive numerical simulation optimization includes optimization of gas injection wells and nitrogen drive injection and production parameters, and the nitrogen drive injection and production parameters include gas injection volume, gas injection rate, well shut-in time and daily liquid production.

[0026] When nitrogen drive numerical simulation optimization is performed before water drive simulation, water drive is started when the nitrogen drive reaches a water content of more than 95%; when nitrogen drive numerical simulation optimization is performed after water drive simulation, nitrogen drive is started when the water drive reaches a water content of more than 95%; when nitrogen drive numerical simulation optimization is performed after polymer drive simulation, nitrogen drive is started when the polymer drive reaches a water content of more than 95%.

[0027] Preferably, when carrying out numerical simulation optimization of nitrogen drive, the gas injection wells are optimized first to determine the gas injection wells, and then the gas injection volume, gas injection rate, well shut-in time and daily liquid production in the nitrogen drive injection and production parameters are optimized in turn.

[0028] Preferably, when performing numerical simulation optimization of nitrogen flooding, the selection criteria for the injection wells are: under the same conditions of gas injection volume, gas injection rate, well shut-in time, daily liquid production and injection method, the injection well with the maximum oil increase is the preferred injection well;

[0029] The method for optimizing the gas injection volume is as follows: first, select candidate gas injection volumes from the designed gas injection volume values, and then select the minimum gas injection volume value from the candidate gas injection volume values, which is the preferred gas injection volume; wherein, the method for selecting the candidate gas injection volume values is as follows: if the oil increase at a certain gas injection volume is the maximum value, and the reduction in the oil change rate at this gas injection volume is not less than 0.7t / 10 4 m 3 , then the gas injection amount is the candidate gas injection amount value; the reduction range of the oil change rate at a certain gas injection amount is equal to (DC) / (BA), where D is the oil change rate when the gas injection amount is B, C is the oil change rate when the gas injection amount is A, gas injection amounts A and B are two adjacent gas injection amount design values, and B>A, and BA≤20×10 4 m 3 ;

[0030] The optimal standard for gas injection speed is: if the daily nitrogen injection capacity of the nitrogen injection equipment is Bm 3 , when the injection rate is changed from Bm 3 / d decreases by 5000m 3 / d corresponds to an increase in oil volume of no more than 7t or an increase in oil change rate of no more than 0.1t / 10 4 m 3 When Bm 3 That is the preferred gas injection rate;

[0031] The optimal soaking time is as follows: if the increase in oil production at a particular soaking time is the largest and no less than 70% of the nitrogen has migrated to the top of the structure at that soaking time, then that soaking time is the optimal soaking time. The increase in oil production at a particular soaking time is equal to (DC) / (BA), where D is the oil production at soaking time B, C is the oil production at soaking time A, soaking time A and soaking time B are two adjacent soaking time design values, B>A, and BA≤30d.

[0032] The optimal standard for daily fluid production is: if the oil change rate corresponding to a certain daily fluid production is not less than 35t / 10 4 m 3 , and when the daily liquid production is increased by 5t / d on the basis of the daily liquid production, the corresponding cumulative oil production is reduced by not less than 812t, and the corresponding oil change rate is reduced by not less than 4t / 10 4 m 3 When , the daily liquid production is the preferred daily liquid production. BRIEF DESCRIPTION OF THE DRAWINGS

[0033] Figure 1 Schematic diagram of relative permeability of the P2 block in the embodiment;

[0034] Figure 2The remaining oil distribution diagram of the P2 block obtained by numerical simulation in the embodiment;

[0035] Figure 3 Schematic diagram of the simulation prediction results of the cumulative oil increase and comprehensive indicators at different polymer injection concentrations in the embodiment;

[0036] Figure 4 Schematic diagram of simulation prediction results of recovery enhancement value, oil increase per ton of polymer and comprehensive indicators under different slug amounts in the embodiment;

[0037] Figure 5 Schematic diagram of the numerical simulation results of water flooding and polymer flooding in the embodiment;

[0038] Figure 6 Schematic diagram of the equilibrium interfacial tension of CO2 / crude oil and N2 / crude oil systems at different pressures in the examples;

[0039] Figure 7 Schematic diagram of the remaining oil at the top of the P2 block read from a planar structural map drawn by mapbase software in the embodiment; wherein the blue area represents the remaining oil at the top of the structure;

[0040] Figure 8 Schematic diagram of nitrogen displacement results obtained by numerical simulation using P206-25 as the gas injection well in the embodiment; wherein the numbers represent well numbers, blue areas represent areas without nitrogen in the reservoir, orange areas represent areas with the highest nitrogen abundance, and yellow areas represent areas with relatively high nitrogen abundance;

[0041] Figure 9 Schematic diagram of nitrogen displacement results obtained by numerical simulation using P206-2 as the gas injection well in the embodiment; wherein the numbers represent well numbers, blue areas represent areas without nitrogen in the reservoir, orange areas represent areas with the highest nitrogen abundance, and yellow areas represent areas with relatively high nitrogen abundance;

[0042] Figure 10 Schematic diagram of nitrogen displacement results obtained by numerical simulation using P206-33 as the gas injection well in the embodiment; wherein the numbers represent well numbers, blue areas represent areas without nitrogen in the reservoir, orange areas represent areas with the highest nitrogen abundance, and yellow areas represent areas with relatively high nitrogen abundance;

[0043] Figure 11 Schematic diagram of nitrogen displacement results obtained by numerical simulation using P206-26 as the gas injection well in the embodiment; wherein the numbers represent well numbers, blue areas represent areas without nitrogen in the reservoir, orange areas represent areas with the highest nitrogen abundance, and yellow areas represent areas with relatively high nitrogen abundance;

[0044] Figure 12Schematic diagram of the oil increase and oil change rate simulated under different gas injection amounts in the embodiment;

[0045] Figure 13 Schematic diagram of the oil increase and oil change rate simulated at different gas injection speeds in the embodiment;

[0046] Figure 14 Schematic diagram of the oil increase and oil change rate simulated under different soaking times in the embodiment;

[0047] Figure 15 This is a gas saturation diagram of Well P206-2 when the well was soaked for 90 days in the embodiment; the yellow area represents the area with the highest nitrogen abundance, the blue area represents the area without nitrogen in the reservoir, and the green area represents the area with high nitrogen abundance;

[0048] Figure 16 Schematic diagram of the simulated oil increase and oil change rate under different single-well daily fluid production rates in the embodiment;

[0049] Figure 17 This is a diagram showing the distribution of residual oil saturation when the water cut reaches 98% after polymer flooding in the embodiment; the red area represents the area with the highest oil saturation, the yellow area represents the area with relatively high oil saturation, and the green area represents the area with relatively low oil saturation;

[0050] Figure 18 This is a diagram showing the distribution of residual oil saturation when the gas cap displacement reaches a water cut of 98% in the embodiment; the blue area represents the area with the highest nitrogen abundance, the red area represents the area with the highest oil saturation, the yellow area represents the area with relatively high oil saturation, and the green area represents the area with relatively low oil saturation;

[0051] Figure 19 This is a schematic diagram of the production curve of the P2 block predicted by numerical simulation in the embodiment. DETAILED DESCRIPTION

[0052] The technical solution of the present invention will be further described below with reference to specific embodiments.

[0053] Example 1

[0054] Taking the P2 block as an example, the total geological reserves of the block are 5.1392 million tons. The edge water energy of the P2 block is strong, and the edge water volume is more than 300 times the reservoir volume. It is a strong edge water driven development reservoir. The average viscosity of the crude oil is 1.67 mPa·s, which is light oil. The P2 block is a small oil reservoir with strong edge water and light oil. The comprehensive water cut of the oil reservoir is currently 81%, and the production has entered the medium-high water cut stage, which meets the characteristics of late-stage development. The permeability is greater than 800 mD. The injection and production scheme optimization design method for a small oil reservoir with high porosity, high permeability, strong edge water and high water cut in this embodiment specifically includes the following steps:

[0055] 1. Research on remaining oil potential

[0056] 1.1 Simulator selection

[0057] The P2 block is currently undergoing edge water flooding. To determine the distribution of remaining oil in the P2 block, this embodiment uses the black oil model simulator in the Eclipse software, which is mature in the oil industry. Since CMG software performs better than Eclipse software in simulating chemical flooding, thermal recovery, and other three-phase recovery, it will be used to simulate water flooding and polymer flooding for mid-sized reservoirs in the later stages of development. The grid type of the reservoir grid model is "corner grid", and the simulated fluid considers the three phases of oil, water, and gas.

[0058] The reservoir numerical simulation model mainly includes: ① geological model; ② rock seepage characteristic model; the rock seepage characteristic model is used to describe the seepage characteristics of reservoir rock-fluid, and is characterized by the relative permeability of oil, gas and water phases, as well as capillary pressure and rock compressibility; relative permeability is used to describe the relative seepage capacity of different fluid phases, affecting the flow and distribution of oil, gas and water; capillary pressure represents the interaction between different fluid molecules and the relationship between the interaction with the rock surface, affecting the distribution of the original saturation of oil, gas and water, the size of the transition zone and the calculation of the pressure gradient; the rock compressibility reflects the elasticity or compressibility of the rock, affecting the change of reservoir pressure; the experimental data of the relative permeability and capillary pressure of oil, gas and water phases must be screened, transformed, classified, normalized, averaged and restored. Original processing, and then establish zonings reflecting different seepage characteristics according to different rock types, while also considering the problems of quasi-function, saturation calibration and hysteresis; ③ Fluid model; used to describe the distribution and properties of reservoir fluids, by describing the interfaces between oil and gas, oil and water, and gas and water, to establish an equilibrium system, or by directly specifying the initial saturation and pressure distribution of the fluid, to divide the oil zone, gas zone, water zone and transition zone. For special water bodies, the numerical simulation software describes them in the form of keywords; according to the heterogeneity of fluid properties, establish zonings reflecting different fluid properties; ④ Dynamic model; The dynamic model is used to characterize the historical process of reservoir development, and describes in detail the well trajectory, oil well and water well production dynamic data, perforation and plugging conditions. For co-injection and co-production wells, the problem of production splitting may be involved;

[0059] 1.2 Simulation grid system

[0060] Based on the regional geological characteristics and well layout of the P2 block, the plane grid of the reservoir's geological model adopts a uniform step size. Taking into account the number of software nodes and the need for simulation accuracy, the grid step size is 10 meters in the x-axis direction and 10 meters in the y-axis direction. The distribution of well points is also taken into account, so that each well point is located in a different grid, and adjacent wells are ensured to be separated by at least five grids in the x-axis or y-axis direction. This helps better reflect the gradual changes in parameters such as water saturation and reservoir pressure, and reduces interference between wells.

[0061] 1.3 Reservoir fluid parameters

[0062] The fluid model mainly consists of three parts: the first is the fluid distribution and pressure distribution in the original state of the formation; the fluid distribution data is obtained from the analysis of seismic and well logging interpretation data, and the reservoir pressure data is obtained from the regression analysis of oil test pressure measurement; the second is the high-pressure physical properties of the fluid, which are mainly obtained from laboratory high-pressure physical property experiments and field crude oil physical property analysis data; the third is the relative permeability data of the fluid, the results of which are obtained from the relative permeability test results under core formation conditions;

[0063] The relative permeability of the P2 block is as follows: Figure 1 As shown, the horizontal axis represents water saturation, the left vertical axis represents oil relative permeability, the right vertical axis represents water relative permeability, the green curve represents the oil relative permeability curve, and the red curve represents the water relative permeability curve;

[0064] 1.4 History Matching

[0065] After the numerical model was established, history matching began. The historical matching metric was cumulative production, including cumulative liquid production, water production, oil production, and gas production. The main goal was to determine geological reserves through fitting. The quality of geological reserve fitting has a significant impact on subsequent fitting results. In this example, the fitting rate for the entire area was 80%, and the fitting rate for each well was no less than 75%. To ensure the accuracy of the block fitting, the relative permeability of the fluid and the oil saturation in some areas of the P2 block were adjusted accordingly based on reservoir physical parameters.

[0066] 1.5 Residual oil distribution

[0067] According to the remaining oil distribution results of the P2 block obtained by numerical simulation software, Figure 2 As shown, during the development of the P2 block, formation water will continue to advance as crude oil is produced. By October 2022, all production wells in the structural lows of the reservoir had already seen water, and the remaining oil in the P2 well area was mainly distributed at the edges of the structural highs and on the edges of the two flanks of the reservoir.

[0068] 2. Optimize the injection and production well pattern and injection and production parameters

[0069] 2.1 Injection-production well pattern optimization

[0070] The main purpose of water injection in oil fields is to increase the oil production rate and crude oil recovery rate, which not only increases crude oil production but also maintains the stability of formation pressure and pore structure;

[0071] In order to change the direction of liquid flow and thus improve the recovery rate, five types of well patterns were designed, including bottom row + point injection and production well pattern, small well spacing five-point injection and production well pattern, five-point injection and production well pattern, middle row + point flexible injection and production well pattern and row injection and production well pattern. Among them, the bottom row + point injection and production well pattern refers to using a row of production wells at the lowest point of the reservoir in the original well pattern as injection wells, and at the same time using two wells with lower energy (near the residual oil boundary) at the structural high point of the reservoir as injection wells; the small well spacing five-point injection and production well pattern refers to adding 9 new water injection wells to the original well pattern. The well spacing in the original well pattern is 405 meters, and the well spacing after adding 9 water injection wells is 350 meters; the five-point injection and production well pattern refers to a one-injection and four-production well pattern. The well pattern arrangement is a pattern where four wells arranged at the vertices of a square are used as oil production wells, and the well at the center of the square is used as a water injection well. The central row + point flexible injection-production well pattern refers to relying on the original well pattern to use a row of production wells at the oil-water boundary line in the middle of the reservoir and two wells with lower energy (near the residual oil boundary) in the reservoir as injection wells. The row injection-production well pattern refers to relying on the original well pattern to use a row of production wells at the oil-water boundary line in the middle of the reservoir as water injection wells. The controlled reserves of each type of well pattern and the well pattern parameters of each type of well pattern are determined by numerical simulation methods. The well pattern parameters specifically include the well spacing and row spacing of vertical wells. Finally, the well pattern parameters of each type of well pattern, the corresponding controlled reserves and characteristics are summarized in Table 1.

[0072] Table 1 Comparison of well pattern types and characteristics

[0073]

[0074]

[0075] Injection wells are designed according to five well patterns. The design value of daily water injection of each injection well is 50 cubic meters. The daily liquid production of the corresponding production wells is numerically simulated according to the current daily liquid production. The daily liquid production of the newly added production wells is equal to the average daily liquid production of all the original production wells, which is 25m 3 / d, and then numerical simulations were performed to determine the corresponding incremental oil production for these five well patterns. The results are shown in Table 1. The incremental oil production refers to the difference between the predicted cumulative oil production after the well pattern change and the cumulative oil production of the current production well pattern. The results show that the central row + point flexible injection and production well pattern has the highest incremental oil production, reaching 9,379 tons. Therefore, the central row + point flexible injection and production well pattern is the preferred water injection well pattern.

[0076] 2.2 Optimization of injection and production parameters

[0077] After determining the water injection well pattern, the injection and production parameters in the water injection process are numerically simulated and compared to analyze the effects of water injection rate and production rate on the final recovery degree;

[0078] 2.2.1 Optimal Optimization of Injection Rate for Injection Wells

[0079] Under the condition of daily liquid production of 15t / d per well, the injection rate is 10m 3 / d to 100m 3 Ten scenarios were set for daily water injection rates of individual wells within a range of 1 / d. The total oil production of the P2 block corresponding to different daily water injection rates was then simulated and predicted. The difference between the predicted total oil production and the total oil production before water flooding was calculated to obtain the incremental oil production. The results are shown in Table 2.

[0080] Table 2 Oil production increment corresponding to different daily water injection rates of single wells in P2 block

[0081]

[0082] It can be seen from the table above that the oil production increment changes with the change of water injection rate (daily water injection volume of a single well). When the water injection rate is less than 20m 3 / d, the oil production increment increases with the increase of water injection rate. When the water injection rate is greater than 20m 3 / d, the oil production increment decreases with the increase of water injection rate. Therefore, the optimal water injection rate is 20m 3 / d; The optimal water injection rate is based on the following criteria: Under the condition of the same daily liquid production of a single well, the water injection rate corresponding to the maximum oil production increment is the optimal water injection rate; however, when allocating water to the injection wells, the actual water absorption capacity of the wells should be taken into consideration, and flexible adjustments should be made based on the dynamic changes of the oil wells;

[0083] 2.2.2 Determination of oil well production rate (daily liquid production)

[0084] According to the production rate design, when the water injection rate is 20m 3 / d, the total daily liquid production of the production wells in the P2 block ranged from 85t / d to 425t / d. Five scenarios were set. The total oil mass and recovery degree corresponding to different total daily liquid production rates were predicted through numerical simulation. The difference between the predicted total oil mass and the total oil mass before water flooding was calculated to obtain the oil production increment. The results are shown in Table 3. Among them, the total oil production volume without water flooding is 3672266m 3 , the total oil production was 2,970,863.5t, and the recovery rate was 57.81%;

[0085] Table 3 Total oil production volume, total oil production mass, oil production increment and recovery degree at different daily liquid production rates

[0086] Daily liquid output (t / d) <![CDATA[Total volume of oil production (m 3 )]]> Total oil production mass (t) Oil production increment (t) Recovery rate (%) 85 3678341 2980938.6 10075.1 58.00 170 3678341 2980787.1 9923.6 58.00 255 3677911 2980544.2 9680.7 58.00 340 3683983 2980342.3 9478.8 57.99 425 3676516 2979101.2 8237.7 57.97

[0087] As can be seen from the table above, overall, the degree of recovery decreases with increasing production rate. When the production rate (liquid production) exceeds 340 t / d, the degree of recovery drops rapidly. This is because excessive flow rate causes water channeling, which exacerbates the increase in water content in the produced oil. Therefore, the optimal production rate (daily liquid production) should be no more than 340 t / d. The optimal production rate is: under the same injection rate for the injection wells, the production rate corresponding to the maximum degree of recovery is the optimal production rate.

[0088] According to the optimized design plan (daily water injection volume of single well is 20m 3 / d, production rate 340t / d), when the water content in the produced oil reached 98%, water flooding was stopped, and the cumulative oil production was 298.0342×10 4 Compared with edge water flooding, the oil production increased by 9478.8t and the recovery factor increased by 0.2%;

[0089] 3. Research on polymer injection development technology

[0090] 3.1 Polymer flooding feasibility analysis

[0091] Polymer flooding technology has been promoted and applied in multiple units of the P2 oilfield. We have accumulated rich experience in injection parameter optimization, field implementation and parameter adjustment, and achieved good results.

[0092] The reason why polymer flooding has achieved good results in the oil field where the P2 block is located is that it has the following mechanism to improve oil recovery:

[0093] First, the mobility control of polymers is one of the important mechanisms of polymer flooding. For homogeneous reservoirs, under water flooding conditions, the viscosity of the injected water is usually lower than that of the crude oil, resulting in an unreasonable oil-water mobility ratio during the flooding process. This causes the water content in the produced fluid to increase rapidly, and the economic limit of water content is reached prematurely.

[0094] Second: adjust the water absorption profile to expand the swept volume;

[0095] Third: The polymer itself has a certain degree of viscoelasticity, which can not only increase the swept volume, but also displace low-permeability areas that are not reached by water injection and residual oil after water flooding, thereby improving oil displacement efficiency;

[0096] The P2 block is characterized by medium-to-high water content, high permeability, high porosity, and strong edge water. Its water-free recovery was high in the early stages of development. However, as development progressed, water breakthrough occurred in the mid-to-high-level wells, causing the water content to rise rapidly and crude oil production to decline. A feasibility study of polymer flooding in the P2 block was conducted in accordance with the standard "SY / T6575-2016 Technical Specification for Screening Methods for Enhanced Oil Recovery in Oilfields." The results are shown in Table 4.

[0097] Table 4 Comparison of SY / T6575-2016 polymer flooding screening indicators and reservoir conditions in the P2 block

[0098]

[0099] As shown in the table above, the reservoir and fluid properties of Block P2 meet the requirements of polymer flooding for reservoir and fluid properties (reservoir depth, lithology, reservoir temperature, reservoir permeability, API density, and formation crude oil viscosity, etc.). Therefore, polymer flooding field trials can be implemented in Block P2.

[0100] 3.2 Screening and evaluation of polymer flooding agents

[0101] Polymer flooding feasibility analysis

[0102] Based on the reservoir lithology, reservoir temperature and other reservoir condition parameters of the P2 block, it is necessary to carry out polymer flooding agent screening and evaluation in the laboratory. By screening the basic properties of the polymer, such as viscosity-concentration relationship, viscosity-temperature relationship, and thermal stability, a polymer flooding agent suitable for the reservoir conditions of the P2 block is selected. The standards for the polymer flooding agent suitable for the reservoir conditions of this embodiment are as follows: when the polymer concentration is 1500 mg / L, the viscosity must reach 80 mPa·s; when the polymer concentration is 1500 mg / L, the viscosity at 40°C must reach 100 mPa·s; when the polymer concentration is 1500 mg / L, the viscosity at 40°C must be no less than 90% of the viscosity at 30°C;

[0103] Due to the experimental conditions in this example, the polymer flooding agent screening and evaluation part is not performed. Only the viscosity-concentration relationship and viscosity-temperature relationship of the polymer solution required for the numerical simulation software CMG calculation are required. The viscosity-concentration relationship of the polymer solution refers to the viscosity of the polymer solution of different concentrations at the formation temperature, and the viscosity-temperature relationship of the polymer solution refers to the viscosity of the polymer solution at different temperatures.

[0104] 3.2.1 Viscosity-Concentration Relationship of Polymer Solutions

[0105] The viscosity-concentration relationship of a polymer solution primarily examines the polymer's ability to increase viscosity. In this example, a solution of ultrahigh molecular weight polymer P is used as an example. The viscosity-concentration relationship of the polymer solution (i.e., the viscosity of polymer solutions of different concentrations at 40°C) is shown in Table 5.

[0106] Table 5 Viscosity-concentration relationship of polymer solution

[0107] Concentration mg / L 500 1000 1500 1800 2000 2200 2500 3000 Viscosity mPa·s 13.9 37.3 82.5 114.1 135.5 167.6 213 306.8

[0108] As can be seen from the table above, the viscosity of the polymer solution increases with increasing concentration. When the concentration is higher than 1500 mg / L, the viscosity reaches 82.5 mPa·s, and the viscosity increase rate becomes larger. The viscosity-concentration relationship of the polymer solution meets the standard. Therefore, the polymer solution can be used as a flooding agent for polymer flooding of the oil reservoir in this example.

[0109] 3.2.2 Viscosity-temperature relationship of polymer solution

[0110] The viscosity-temperature relationship of polymer solutions primarily examines how the viscosity of polymer solutions changes with temperature and is an important indicator of the heat resistance of polymer products. Taking a solution of ultrahigh molecular weight polymer P as an example, a polymer solution with a concentration of 2000 mg / L was prepared, and then the viscosity of the polymer solution at different temperatures was measured. The results are shown in Table 6.

[0111] Table 6 Viscosity-temperature relationship of polymer solution

[0112] Temperature 30 40 50 60 70 80 Viscosity mPa·s 148.3 135.5 132.3 123.7 119.5 109.9

[0113] As can be seen from the table above, the ultra-high molecular weight polymer P has good temperature resistance. The solution viscosity decreases only slightly with increasing temperature. The viscosity at 80°C retains more than 70% of the viscosity at 30°C. The viscosity-temperature relationship of the polymer solution meets the standard. Therefore, this polymer solution can be used as a flooding agent for polymer flooding in the oil reservoir of this example.

[0114] Through analysis of the viscosity-concentration and viscosity-temperature relationships, a solution of ultra-high molecular weight polymer P, with its superior viscosity-increasing properties and good temperature resistance, was preliminarily selected as the flooding agent for the polymer flooding numerical simulation in the P2 block.

[0115] 3.2.3 Polymer flooding well pattern optimization

[0116] The adaptability of the well pattern to the reservoir directly determines the development effect of the reservoir. When deploying the well pattern, it is necessary to reduce the number of wells to reduce investment, maximize the controlled reserves to reduce reserve loss, and at the same time ensure that the vast majority of reserves are within the effective displacement range to improve the recovery rate of the reservoir.

[0117] Consistent with the water injection well network design plan, five types of well networks were designed, including bottom row + point injection and production well network, small well spacing five-point injection and production well network, five-point injection and production well network, middle row + point flexible injection and production well network and row injection and production well network. Among them, the bottom row + point injection and production well network refers to using a row of production wells at the lowest point of the reservoir in the original well network as injection wells, and at the same time using two wells with lower energy (near the residual oil boundary) in the structural high part of the reservoir as injection wells; the small well spacing five-point injection and production well network refers to adding 9 new water injection wells to the original well network. The well spacing in the original well network is 405 meters, and the well spacing after adding 9 water injection wells is 350 meters; the five-point injection and production well network refers to A one-injection, four-production well pattern uses four wells arranged like the vertices of a square as production wells, and the well at the center of the square as an injection well. A central row + point flexible injection-production well pattern uses a row of production wells at the oil-water boundary in the middle of the reservoir and two wells with lower energy (near the residual oil boundary) in the reservoir as injection wells, relying on the original well pattern. A row injection-production well pattern uses a row of production wells at the oil-water boundary in the middle of the reservoir as injection wells, relying on the original well pattern. The well pattern parameters for each type of well pattern were determined using numerical simulation methods. The well pattern parameters specifically include the well spacing and row spacing of vertical wells. The controlled reserves and characteristics corresponding to each type of well pattern are summarized in Table 7.

[0118] Injection wells were designed according to five well patterns. The daily injection volume of each injection well was designed to be 20 cubic meters, the designed injection concentration was 1800 mg / L, the slug size was 0.33 PV, and the liquid production rate (production rate) was based on the production data at that time. The five well pattern characteristics were numerically simulated to obtain the total oil production corresponding to different types of well patterns. The difference between the total oil production after polymer flooding and the total oil production before polymer flooding was calculated to obtain the oil increase corresponding to different types of well patterns. The results are shown in Table 7. The results show that the central row + point flexible injection and production well pattern corresponds to the largest oil increase, reaching 22,978 tons. The central row + point flexible injection and production well pattern is preferred as the injection and production well pattern. The optimization criterion for the polymer flooding well pattern is that the injection and production well pattern corresponding to the maximum oil increase is the optimal polymer flooding well pattern.

[0119] Table 7 Polymer injection wells corresponding to different polymer injection well patterns, total daily polymer injection volume and incremental oil production of polymer injection wells

[0120]

[0121]

[0122] 3.3 Polymer injection parameter design and effect prediction

[0123] The polymer injection blocks in the A and B oil fields, which are similar in nature to the P2 block, were developed after long-term water flooding. The unit (block) pressure maintenance level is generally around 60%-80%, so the polymer flooding injection-production ratio is generally greater than 1.0; to prevent the generation of aggregates due to excessive injection speed, the injection rate is generally maintained between 0.11 and 0.13 PV / a; however, the injection concentration and slug size of each unit (block) vary greatly, and the original formation pressure of the P2 block reservoir is 10.21 MPa. After years of development, the current formation pressure is 9.61 MPa, and the pressure level is still maintained at 94.1%. Layer energy balance. In this example, an injection-production ratio of 1.0 was selected. Based on the experimental evaluation results of the reservoir in Oilfield A, the designed polymer injection concentration was 1800 mg / L and the slug size was 0.33 PV. Then, numerical model optimization and effect prediction of the polymer injection rate, polymer injection concentration, and slug size were performed. The polymer flooding parameters of the polymer-injected blocks in the first stratum of Oilfield A, the second stratum of Oilfield A, the first block of Oilfield B, and the second block of Oilfield B, as well as the polymer flooding parameters of Block P2, are shown in Table 8. The injection slug and polymer injection concentration of Block P2 were determined according to the average values of the first slugs in the first stratum of Oilfield A and the average values of the polymer injection concentration in Block 1 of Oilfield B, respectively.

[0124] Table 8 Polymer flooding parameters for the first formation of oilfield A, the second formation of oilfield A, the first block of oilfield B, the second block of oilfield B, and the polymer flooding blocks and the P2 block

[0125]

[0126]

[0127] 3.3.1 Determination of polymer flooding injection rate

[0128] To determine a reasonable polymer flooding injection rate, the polymer concentration in the polymer flooding agent was set at 1800 mg / L when the injection-production ratio was 1.0 and the slug size was 0.33 PV. The polymer flooding injection rates were set at 0.08, 0.09, 0.10, 0.11, 0.12, 0.13, and 0.14 PV / a, respectively. Simulation predictions were then performed for these seven schemes. The simulation prediction results for the injection rate, cumulative oil increase, and recovery factor improvement at different polymer flooding injection rates are shown in Table 9.

[0129] Table 9 Injection rate, cumulative oil increase and recovery factor improvement at different polymer flooding rates

[0130] Injection rate (PV / a) <![CDATA[Dispensing amount (m 3 )]]> <![CDATA[Cumulative oil increment (×10 4 t)]]> Recovery efficiency improvement (%) 0.08 123 2.26 6.24 0.09 138 2.29 6.33 0.1 153 2.3 6.35 0.11 170 2.33 6.44 0.12 184 2.25 6.22 0.13 199 2.28 6.3

[0131] The prediction results in the table above show that at low injection rates, as the injection rate of the polymer flooding agent increases, the recovery improvement value (up to 98% water cut) gradually increases. When the injection rate reaches 0.11PV / a, the recovery improvement value is the highest, at 6.44%. After that, as the injection rate increases, the oil enhancement effect deteriorates, indicating that the polymer crossflow rate in the heterogeneous formation is accelerated, the water cut rises faster after the peak, and the role of the polymer solution in expanding the swept volume is reduced, affecting the polymer flooding effect. Therefore, the optimal polymer flooding agent injection rate for the P2 block is determined to be 0.11PV / a. The optimal criterion for the polymer flooding agent injection rate is: under the conditions of the same injection-production ratio, polymer concentration in the polymer flooding agent, and slug size, the injection rate corresponding to the maximum recovery improvement value is the preferred polymer flooding agent injection rate.

[0132] 3.3.2 Determination of polymer concentration in polymer flooding

[0133] When the injection-production ratio is 1.0, the injection rate is 0.11PV / a, and the slug size is 0.33PV, six schemes with polymer concentrations of 1400, 1600, 1800, 2000, 2200, and 2400 mg / L were optimized. The simulation prediction results of the cumulative oil increase, recovery factor improvement, polymer solution dosage, oil increase per ton of polymer solution, and comprehensive indicators at different polymer injection concentrations are shown in Table 10. The simulation prediction results of the cumulative oil increase and comprehensive indicators at different polymer injection concentrations are plotted, and the results are shown in Table 10. Figure 3 As shown; the horizontal axis is the injection concentration, the unit is mg / L, and the vertical axis on the left is the cumulative oil increase, the unit is 10 4 t, the right vertical axis is a comprehensive index, dimensionless;

[0134] Table 10 Cumulative oil increase, recovery factor improvement, polymer solution dosage, oil increase per ton of polymer solution, and comprehensive indicators at different polymer injection concentrations

[0135]

[0136]

[0137] As can be seen from the above table, as the concentration of polymer in the polymer flooding agent increases, the recovery improvement value increases, and the corresponding oil increase per ton of polymer solution decreases. When the concentration of polymer in the polymer flooding agent is higher than 1800 mg / L, the increase in the recovery improvement value and the corresponding oil increase per ton of polymer solution slows down, and the comprehensive index shows an inflection point and a downward trend. The reason is that it is difficult to inject polymer injection wells in the local low permeability area of the reservoir, and it is difficult to achieve the injection rate. Therefore, in order to ensure normal injection in the mine and achieve maximum benefits, the polymer concentration in the polymer flooding agent is selected to be 1800 mg / L; the optimal standard for the concentration of polymer in the polymer flooding agent is: under the conditions of the same injection-production ratio, injection rate, and slug size, the polymer concentration in the polymer flooding agent corresponding to the maximum comprehensive index is the preferred polymer solution. The comprehensive index is equal to the ratio of the product of the recovery improvement value and the corresponding oil increase per ton of polymer solution to 100;

[0138] 3.3.3 Slug Design

[0139] According to the above optimization results, in order to obtain the maximum oil increase benefit, eight schemes were adopted, including an injection-production ratio of 1.0, an injection rate of 0.11 PV / a, a slug size of 0.33 PV, a polymer concentration of 1800 mg / L in the polymer flooding agent, and slug volumes of 400, 450, 500, 550, 600, 650, 700, and 750 mg / L×PV. The cumulative oil increase, recovery improvement, polymer dosage, oil increase per ton of polymer, and comprehensive indicators predicted by the numerical simulation of polymer flooding at different polymer injection concentrations are shown in Table 11. The simulation prediction results of the recovery improvement (IOR), oil increase per ton of polymer (oil increase per ton of polymer), and comprehensive indicators at different slug volumes are plotted, as shown in Figure 11. Figure 4 As shown; where the horizontal axis is the slugging volume, the unit is mg / L×PV, the left vertical axis is the recovery factor improvement value or comprehensive index, the unit is % or dimensionless, and the right vertical axis is the oil increase corresponding to each ton of polymer, the unit is t;

[0140] Table 11 Cumulative oil increase, recovery factor improvement, polymer dosage, oil increase per ton of polymer, and comprehensive indicators at different polymer injection concentrations

[0141]

[0142] As shown in the table above, as the slug volume increases, the recovery improvement value increases, while the corresponding oil increase per ton of polymer (oil change rate per ton of polymer) decreases. When the slug volume reaches 600 mg / L×PV, the comprehensive index reaches an inflection point and the increase begins to decrease. Therefore, the preferred slug volume is 600 mg / L×PV. The optimal slug volume is: under the same injection-production ratio, injection rate, polymer concentration in the polymer flooding agent, and slug size, the slug volume corresponding to the maximum comprehensive index is the preferred slug volume. The comprehensive index is equal to the ratio of the product of the recovery improvement value and the oil increase per ton of polymer solution to 100.

[0143] 3.3.4 Production and injection and polymer dosage

[0144] 3.3.4.1 Principles of production and injection allocation

[0145] (1) Maintain the injection rate of polymer flooding agent at 0.11PV / a;

[0146] (2) Maintaining an overall balance between injection and production;

[0147] (3) The production and injection volume of a single well should not only be consistent with the actual capacity of the reservoir, but also be feasible in terms of technology;

[0148] 3.3.4.2 Production and Note Allocation

[0149] Maintaining the injection rate of polymer flooding at 0.11PV / a, determine the total injection volume of polymer flooding; under the condition of an injection-production ratio of 1.0, determine the total liquid production volume with reference to the daily liquid production capacity of the oil well during production; the total injection volume of the polymer injection area in the P2 block is 170m 3 / d, the total liquid allocation is 170t / d. The production and injection allocation of each oil well (production well) and polymer injection well are detailed in Table 12;

[0150] Table 12P2 Block Polymer Flooding Production and Injection Allocation

[0151] Injection well number <![CDATA[Polymer injection volume (m 3 )]]> Production well number <![CDATA[Liquid production rate (m 3 )]]> P2-1 40 P206-2 15 P2-18 20 P206-26 6 P2-13 20 P206-32 8 P206-25 30 P206-33 15 P206 20 P206-4 7 P206-3 20 P206-Side 1 12 P206-5 20 P206-Side 27 3 - - P2-16 12 - - P2-161 12 - - P2-17 8 - - P2-181 5 - - P2-182 12 - - P2-183 19 - - P2-185 15 - - P2-27 8 - - P2-28 8 P2-4 4 total 170 total 170

[0152] 3.3.4.3 Polymer dosage

[0153] According to the slug and concentration parameters of the P2 block, the polymer slug injection time is 1095 days, or 3 years (36 months), the slug size is 0.33PV, and the total polymer powder consumption is 336t (polymer powder consumption is pure polymer consumption). The corresponding polymer powder consumption of polymer slugs at different times is shown in Table 13.

[0154] Table 13 Polymer dosage corresponding to polymer slug at different times

[0155] Time (month) 6 months 12 months 12 months 6 months Polymer dosage (t) 56 112 112 56

[0156] 3.3.5 Prediction of polymer flooding effect

[0157] The oil-bearing area of the oil sand body affected by the polymer flooding process of the seven polymer injection wells selected in the P2 block is 0.46 km 2 The controlled reserves of the polymer injection well group are 36.2×10 4 When the water cut of polymer flooding reaches 98%, the oil production increases by 2.33×10 4 t, calculated based on the actual controlled reserves of the polymer flooding well pattern, the recovery rate of polymer flooding is 6.44% higher than that of water flooding. The amount of polymer dry powder used is 335t, and the corresponding oil increase per ton of polymer dry powder is 69.4t / t. Water flooding numerical simulation is carried out under the optimized water flooding parameters, and polymer flooding numerical simulation is carried out under the optimized polymer flooding parameters. The water flooding numerical simulation results and the polymer flooding numerical simulation results are plotted, and the results are shown in the figure. Figure 5 As shown; the horizontal axis represents time, the unit is year and month, the vertical axis on the left is the daily oil production, the unit is t, and the vertical axis on the right is the water content, the unit is %; the daily oil production is determined by numerical simulation.

[0158] Example 2

[0159] This embodiment takes the P2 block as an example to study the recovery efficiency of the P2 block by nitrogen artificial gas cap flooding. The injection and production scheme optimization design method of the embodiment for a small oil reservoir with high porosity, high permeability, strong edge water and high water content specifically includes the following steps:

[0160] 1.1 Nitrogen flooding mechanism

[0161] 1.1.1 Miscible displacement, immiscible displacement, and near-miscible displacement

[0162] Regardless of which gas injection development method is adopted, people first hope to achieve miscible flooding;

[0163] Miscible is defined as the condition where no phase interface is formed between two or more fluids when mixed in any proportion, and all mixtures remain a single homogeneous phase. Conversely, if a phase interface exists, the fluids are considered immiscible. Miscible displacement is one of the important methods for enhancing oil recovery. Its basic mechanism is that the injected displacing agent (miscible gas) and the displaced agent (formation crude oil) form a miscible phase under reservoir conditions, eliminating the phase interface and reducing the capillary force in the porous medium to zero, thereby reducing the oil trapped by capillary retention due to the capillary effect. In principle, this can achieve a microscopic oil recovery efficiency of 100%.

[0164] According to the type of injected gas and its characteristics with the crude oil system, miscible flooding can be divided into two types: first-contact miscible (FCM) and multi-contact miscible (MCM).

[0165] The miscibility principle shows that as pressure increases, even when lean gas is used to drive heavy oil containing fewer intermediate molecular weight hydrocarbons, miscibility can occur. However, the pressure required to achieve miscibility is extremely high, which is sometimes impossible to achieve in reservoir gas injection projects. In such cases, gas injection can only be an immiscible displacement. Hydrocarbon gas has a certain solubility in crude oil. Dissolved gas at a certain pressure can change oil flow characteristics. At the same time, there is a mass transfer effect between the immiscible gas and liquid. Therefore, immiscible displacement can also increase crude oil recovery.

[0166] For a long time, theory and laboratory experiments believed that there were two types of miscible phases: condensate-type and evaporation-type, collectively known as the traditional theory. However, in recent years, some domestic and foreign literature and laboratory experimental results have confirmed the existence of a new displacement type: condensate-evaporation-type, also known as near-miscible displacement. Under the dual effects of condensation and evaporation, the interfacial tension between the oil and gas phases can reach a lower point, and the recovery factor can be higher, but the gas and liquid phases are not miscible in the strict physical and chemical sense.

[0167] 1.1.2 Gravity drive

[0168] During gravity displacement, the microscopic displacement of "attic oil" by injected gas, the downward stabilization of oil displacement by injected gas due to gravity, the phase change during the gas injection process, and the stability mechanism of the oil-gas-water interface movement are all different from those of horizontal displacement.

[0169] In summary, the main mechanisms of improving oil recovery by injecting nitrogen into artificial gas cap flooding are as follows:

[0170] ① Gravity differentiation of oil and gas. During the gas injection process, since the density difference between oil and gas is much greater than that between oil and water, gas injection can utilize the gravity differentiation caused by the density difference between oil and gas to gather the top "attic oil" into a new front-edge enriched oil zone, which moves more evenly to the lower part of the structure and enters the production well for production;

[0171] ② By reducing interfacial tension, nitrogen flooding can further reduce the residual oil saturation in small pores after water flooding;

[0172] From a microscopic perspective, the interfacial tension between oil and gas in the N2 / crude oil system gradually decreases with increasing pressure. When the interfacial tension reaches 0, it means that the two are miscible, and the pressure at this time is the minimum miscible pressure. Figure 6It can be seen that even at a high pressure of 36 MPa, the interfacial tension of nitrogen in equilibrium is 9.8 mN / m, and the formation pressure in the middle of the P2 block reservoir is 10.2 MPa, making it even less likely to be miscible with crude oil. Therefore, injecting nitrogen for artificial gas cap flooding is an immiscible displacement mode.

[0173] ③ Viscosity reduction effect. Generally speaking, hydrocarbon gases are more soluble in crude oil than nitrogen, so the viscosity reduction ability of hydrocarbon gases dissolved in formation oil is higher than that of nitrogen. However, compared with the formation oil before nitrogen dissolution, the viscosity of the formation oil after dissolving a certain amount of nitrogen does decrease to a certain extent, which is beneficial to the flow of formation oil.

[0174] ④ Change the direction of fluid flow. After water flooding is implemented in the reservoir, a certain amount of residual oil will exist in the high part of the reservoir. When the oil recovery method is changed from bottom water flooding to artificial gas cap flooding, the crude oil in the formation moves from upward to downward, and the oil-water interface will also drop accordingly, which is conducive to improving the production conditions of the oil well.

[0175] ⑤ Gas cap expansion: From a microscopic perspective, gas cap expansion is the diffusion of molecules. Gas is composed of molecules, and these molecules are constantly moving in an irregular manner. A large amount of gas is quickly injected into the formation, and then all wells are closed to cut off the connection between the gas and the ground. At this time, the large amount of injected gas is in a high-temperature and high-pressure environment, and the molecular diffusion becomes very active. Therefore, the energy generated by the artificial gas cap expansion is also very huge and can no longer be ignored. Under the action of this energy, the artificial gas cap continues to expand, pushing the remaining oil in the high position to the lower position. When the well is opened for production, the formation oil will quickly move from the high position to the production well, thereby greatly improving the development effect.

[0176] 1.2 Top residual oil volume

[0177] The plane structure drawing drawn from mapbase software ( Figure 7 ) The oil-bearing area is 22571.4m 2 The average thickness is 2.3m, the average porosity is 34.1%, and the pore volume is 17702.7m 3 , as shown in Table 14; then according to the ideal gas state equation PV=nRT, the volume of 1m under reservoir conditions (reservoir formation temperature and pressure) is calculated. 3 The volume of gas under ground conditions is 96.6m 3 ; The conversion conditions and results are shown in Table 15;

[0178] Table 14 Total pore volume of remaining oil at the top of Block P2

[0179] <![CDATA[Gas injection well group area (m 2 )]]> Average thickness (m) Porosity (%) <![CDATA[Total pore volume (m 3 )]]> 22571.4 2.3 34.1 17702.7

[0180] Table 15 Conversion table of gas volume under reservoir and surface conditions

[0181] index Pressure P (MPa) Celsius temperature (℃) T(K) <![CDATA[Volume V (m 3 )]]> Reservoir conditions 10.21 42 315.15 1 Ground conditions 0.1 25 298.15 96.6

[0182] 1.3 Optimal selection of gas injection wells

[0183] The wells with the closest remaining oil distance to the top of the P2 block are P206-2 (103 m from the top of the reservoir structure), P206-33 (45 m from the top of the reservoir structure), and P206-26 (41 m from the top of the reservoir structure). The well below the top remaining oil is P206-25 (243 m from the top of the reservoir structure). Figure 7 As shown, the designed gas injection volume is 1 million cubic meters and the gas injection speed is 20,000m 3 / d. The four adjacent wells were all shut down for 3 months. The planned liquid production after gas injection is 15m 3 / d, the injection method is continuous injection, and then numerical simulation prediction is carried out. The simulation results of the corresponding oil increase when the four gas wells are used as gas injection wells are shown in Table 16;

[0184] Table 16 The corresponding oil increase when the four gas wells near the top residual oil are used as gas injection wells

[0185] Gas injection wells <![CDATA[Injection volume (10 4 m 3 )]]> Oil increase (t) P206-25 100 2750 P206-2 100 3042 P206-33 100 950 P206-26 100 1868

[0186] When the water cut of gas injection production reaches the economic limit of 98%, the characteristics of nitrogen displacement in different injection wells are different:

[0187] ① After nitrogen was injected into P206-25, it migrated along the upper left side. Finally, 60% of the gas gathered in the remaining oil area above P206-2, and 30% of the gas gathered at the top of P206-26. A small amount of gas remained and scattered along the injection path (such as Figure 8 Its characteristics are that nitrogen has a wide range of influence and the oil production is second only to the P206-2 injection well solution, with an oil production increase of 2,750 tons.

[0188] ② After nitrogen is injected into P206-2, it moves directly upwards. Eventually, 90% of the gas gathers in the remaining oil area above P206-2, and only a small amount of gas remains and spreads along the injection path (e.g. Figure 9 As shown in the figure, the injected gas (nitrogen) migrates upward along the shortest path under the action of gravity differentiation and stays at the top of the structure. The amount of gas dissipated below the oil-water interface is very small, so the oil-increasing effect is the best, which is 3042t.

[0189] ③ After nitrogen was injected into P206-33, it migrated along the upper boundary of the structure. Finally, 75% of the gas gathered in the remaining oil area above P206-2, and 20% of the gas gathered near the fault above P206-33 (such as Figure 10As shown in the figure, the gas displacement range is mostly at the top of the structure and the structural boundary of the fault line. The area of the residual oil enrichment zone is the smallest, so the oil injection effect is the worst, only 950t, which is less than one-third of the oil injection amount when P206-2 is used as the injection well. However, the injection of nitrogen into this well has a significant effect on displacing the residual oil at the left boundary of the fault.

[0190] ④ After nitrogen was injected into P206-26, it migrated in both the upward and downward directions along the structural boundary. Finally, 60% of the gas gathered in the remaining oil area above P206-2, and 30% of the gas gathered at the structural corner above P206-32 (such as Figure 11 As shown in the figure, the gas dissipates more to the area below the oil-water boundary with less remaining oil, resulting in a poor oil increase effect, with the oil increase amount being only 1868t;

[0191] Therefore, Well P206-2, which has a large displacement area of residual oil and the highest oil production increase, was selected as the injection well for nitrogen cap flooding. The selection criteria for nitrogen cap flooding injection wells are as follows: under the same conditions of injection volume, injection rate, well shut-in time, daily liquid production, and injection method, the injection well with the highest oil production increase is the preferred injection well. When initially selecting an injection well, ensure that the distance between the well and the top of the reservoir structure does not exceed 250 meters.

[0192] 1.4 Injection method design

[0193] Injection methods can generally be divided into continuous injection and intermittent injection. For nitrogen injection artificial gas cap flooding technology, it is necessary to continuously inject gas into the formation to form an artificial gas cap at the high part of the reservoir as quickly as possible to reduce energy dissipation. Therefore, this embodiment adopts the continuous injection method.

[0194] 1.5 Optimization design of injection and production parameters

[0195] Injection-production parameters include gas injection volume, injection rate, well-holding time, and daily liquid production. Different schemes were designed to compare performance indicators such as oil production increase and oil change rate under different injection-production parameters, ultimately selecting the most cost-effective injection-production parameter as the optimal scheme for field implementation. Based on previous field implementation experience, the order of injection-production parameter optimization is gas injection volume, gas injection rate, well-holding time, and daily liquid production. During the injection-production parameter optimization process, the oil production increase is calculated as follows: numerical simulation is used to predict the total oil production under a certain injection-production parameter, and then the difference between the predicted total oil production and the total oil production before gas flooding is calculated to obtain the oil production increase.

[0196] 1.5.1 Gas injection volume

[0197] The pore volume of remaining oil at the top of the reservoir under surface conditions is 94×10 4 m 3 According to the pore volume at the top of the reservoir, the designed gas injection volume is 80×10 4 m3 , 100×10 4 m 3 , 120×10 4 m 3 , 140×10 4 m 3 and 160×10 4 m 3 Then, numerical simulations were conducted on the five schemes to investigate the injection PV number, total oil production volume, total oil production mass, oil increase, and oil production per 10,000 m 3 The corresponding oil increase (unit oil increase), cumulative gas production, gas injection volume and oil change rate under formation (temperature and pressure) conditions are shown in Table 17. The simulated oil increase and oil change rate obtained under different gas injection volumes are plotted as shown in Table 17. Figure 12 As shown; where the horizontal axis is the gas injection volume, the unit is m 3 The left vertical axis is the oil increase, the unit is t, and the right vertical axis is the oil change rate, the unit is t / 10 4 m 3 ;

[0198] Table 17 Gas injection PV number, total oil production volume, total oil production mass, oil increase, and per 10,000 m3 at different gas injection rates 3 Increased oil production corresponding to gas, cumulative gas production, and gas injection volume under formation conditions

[0199]

[0200] Table 17 shows that the five designed gas injection schemes with different gas injection rates all have an oil production increase effect compared with the original scheme without gas injection. According to the numerical simulation results, the gas injection rate of Well P206-2 is less than 120×10 4 m 3 (The gas injection volume under formation conditions is 12424m 3 ), the oil increase shows an increasing trend with the increase of gas injection volume. When the injection volume is greater than 1.2 million cubic meters, the oil increase reaches a maximum value and the oil change rate is greatly reduced. Therefore, the optimal gas injection volume is determined to be 120×10 4 m 3 The method for optimizing the gas injection amount is as follows: first, select candidate gas injection amounts from the designed gas injection amount values, and then select the minimum gas injection amount from the candidate gas injection amount values, which is the preferred gas injection amount; wherein, the method for selecting the candidate gas injection amount values is as follows: if the oil increase at a certain gas injection amount is the maximum value, and the reduction in the oil change rate at this gas injection amount is not less than 0.7t / 10 4 m 3, then the gas injection amount is the candidate gas injection amount value; the reduction range of the oil change rate at a certain gas injection amount is equal to (DC) / (BA), where D is the oil change rate when the gas injection amount is B, C is the oil change rate when the gas injection amount is A, gas injection amounts A and B are two adjacent gas injection amount design values, and B>A, and BA≤20×10 4 m 3 ;

[0201] 1.5.2 Gas injection speed

[0202] Based on the gas injection volume of 1.2 million cubic meters, the gas injection speed is selected as 15000, 20000, and 25000m 3 / d three schemes; then the oil increase and oil change rate at different gas injection speeds were determined by numerical simulation, and the results are shown in Table 18; the oil increase and oil change rate simulated at different gas injection speeds were plotted, as shown in Figure 13 As shown; where the horizontal axis is the gas injection velocity, the unit is m 3 / d, the left vertical axis is the oil increase, the unit is t, the right vertical axis is the oil change rate, the unit is t / 10 4 m 3 ;

[0203] Table 18 Oil increase and oil change rate at different gas injection speeds

[0204] <![CDATA[Gas injection rate (m 3 / d)]]> Oil increase (t) <![CDATA[Oil change rate (t / 10 4 m 3 )]]> 15000 4257 35.5 20000 4250 35.4 25000 4222 35.2

[0205] From the prediction results (as shown in Table 18), the higher the gas injection rate, the lower the oil increase and oil change rate. This is because the higher the gas injection rate, the greater the gas expansion energy, which will cause more gas to migrate downward and dissipate in the water layer. In addition, combined with the data on oil increase, the injection rate is 15,000 m3 per day. 3 The increase in oil production is only slightly greater than the injection rate of 20,000 m3 per day. 3 The oil volume increased by 7 tons, which has a negligible impact, because the nitrogen injection equipment can inject 20,000m3 of nitrogen per day. 3 It is more complicated to control the smaller nitrogen injection rate, so the injection rate is determined to be 20000m 3 / d; The optimal standard for gas injection speed is: if the daily nitrogen injection capacity of the nitrogen injection equipment is Bm 3 , when the injection rate is changed from Bm 3 / d decreases by 5000m 3 / d corresponds to an increase in oil volume of no more than 7t or an increase in oil change rate of no more than 0.1t / 10 4 m 3 When Bm 3 That is the preferred gas injection rate;

[0206] 1.5.3 Well soaking time

[0207] Based on a gas injection volume of 1.2 million cubic meters and a gas injection rate of 20,000 cubic meters per day, numerical simulations show that among all oil-producing wells, Well P206-2 has the largest oil increase, reaching 70% of the total oil increase due to gas injection. Five different soaking time schemes were designed for Well P206-2, with soaking times of 30, 60, 90, 120, and 150 days, respectively. The oil increase and oil change rate under different soaking times were then determined through numerical simulations. The results are shown in Table 19. The oil increase and oil change rate simulated under different soaking times were plotted as shown in Table 19. Figure 14 As shown; the horizontal axis is the soaking time, the unit is d, the left vertical axis is the oil increase, the unit is t, and the right vertical axis is the oil change rate, the unit is t / 10 4 m 3 ;

[0208] Table 19 Oil increase and oil change rate at different soaking times

[0209] Well soaking time (days) Oil increase (t) <![CDATA[Oil change rate (t / 10 4 m 3 )]]> 30 3050 25 60 3318 28 90 4250 35 120 4459 37 150 4669 39

[0210] As shown in Table 19, the simulation results show that the longer the well shut-in time, the higher the oil production and oil change rate. However, when the well shut-in time increases from 60 days to 90 days, the oil production increases by 932 tons, which is the largest increase. Combined with the gas saturation diagram of Well P206-2 when the well shut-in time is 90 days (see Figure 19), the oil production increases by 932 tons, which is the largest increase. Figure 15 (as shown in the figure), when the shut-in time is 90 days, 70% of the nitrogen has migrated to the top of the structure. At the same time, if the shut-in time is extended, the oil production increase is small, resulting in a longer production time. After comprehensive comparison, the optimal shut-in time is selected as 90 days. The optimization criteria for the shut-in time are: if the oil production increase at a certain shut-in time is the largest, and at least 70% of the nitrogen has migrated to the top of the structure at that time, then this shut-in time is the preferred shut-in time. The oil production increase at a certain shut-in time is equal to (DC) / (BA), where D is the oil production increase at the shut-in time B, C is the oil production increase at the shut-in time A, and the shut-in times A and B are two adjacent shut-in time design values, with B>A, and BA≤30d.

[0211] 1.5.4 Daily liquid production

[0212] When the steam injection volume is 1.2 million cubic meters and the injection speed is 20,000m 3 / d, and the well soaking time was 90 days. The production allocation was optimized under the condition that the well was soaked for 90 days. The liquid allocation of the four wells P206-33, P206-2, P206-26 and P206-32 in the high part of the structure was optimized. The daily liquid production of each single well was designed to be 5m 3 / d, 10m 3 / d, 15m 3 / d, 20m 3 / d and 30m 3 / d, and then the five schemes are optimized. The simulated oil increase and oil change rate under different daily liquid production are shown in Table 20; the simulated oil increase and oil change rate under different single well daily liquid production are plotted, as shown in Figure 16 As shown; the horizontal axis is the daily fluid production of a single well, in m 3 / d, the left vertical axis is the oil increase, the unit is t, the right vertical axis is the oil change rate, the unit is t / 10 4 m 3 ;

[0213] Table 20 Oil increase and oil change rate at different daily liquid production

[0214] Liquid production (t / d) Cumulative oil production (t) <![CDATA[Cumulative gas production (m 3 )]]> Oil increase (t) <![CDATA[Oil change rate (t / 10 4 m 3 )]]> 5 2975778 1854 4914 41 10 2975430 8012 4566 38 15 2975114 20745 4250 35 20 2974302 70964 3438 29 30 2973739 120987 2875 24

[0215] From the simulation results, the higher the daily liquid production, the lower the oil increase and oil change rate, and the more gas is produced. The daily liquid production of a single well is 5m 3 / d, 10m 3 / d, 15m 3 / d, the nitrogen oil exchange rate is greater than 35t / 10 4 m 3 , the effect is better, and the daily liquid production of a single well is (daily liquid production) 20m 3 / d, the cumulative crude oil production is significantly reduced, the gas production is significantly increased, and the formation energy is 0.1MPa lower than that of low liquid addition. Under the condition of meeting the production demand, the optimal liquid addition amount (daily liquid production) is 15m 3 / d; The preferred standard for daily fluid production is: if the oil change rate corresponding to a certain daily fluid production is not less than 35t / 10 4 m 3 , and when the daily liquid production is increased by 5t / d on the basis of the daily liquid production, the corresponding cumulative oil production is reduced by not less than 812t, and the corresponding oil change rate is reduced by not less than 4t / 10 4 m 3 When , the daily liquid production volume is the preferred daily liquid production volume;

[0216] 1.5.5 Effect Prediction

[0217] According to the saturation distribution diagram of the remaining oil when the polymer displacement reaches 98% water cut (such as Figure 17 As shown in the figure) and the saturation distribution of the remaining oil when the gas cap displacement reaches a water cut of 98% (as shown in the figure) Figure 18 As shown in the figure, gas cap flooding has two advantages over non-gas injection: 1. Microscopically, the residual oil saturation after gas flooding is 10% lower than that after water flooding; the low interfacial tension between nitrogen and crude oil allows nitrogen to reach smaller pores and increase oil recovery efficiency; 2. Macroscopically, it can displace residual oil in the gas cap and suppress edge water.

[0218] According to the optimized design (gas injection volume of 1.2 million cubic meters and gas injection speed of 20,000m 3 / d, the well soaking time is 90 days, and the daily liquid supply volume per well is 15m 3 / d) to conduct numerical simulation and prediction, and obtain the production curve diagram of P2 block, as shown in Figure 19 As shown, the horizontal axis represents the date in quarters, the vertical axis on the left represents the water saturation in %, and the vertical axis on the right represents the daily oil production in m 3 , the red curve represents the daily oil production when gas is injected, the green curve represents the daily oil production when gas is not injected, the blue curve represents the water content when gas is injected, and the light blue curve represents the water content when gas is not injected; Figure 19 It can be seen that when the water content reaches 98%, the cumulative oil production is 297.5113×10 4 t, compared with edge water flooding, the oil production increased by 4250t, and the recovery rate increased by 0.08%; the gas injection effect can last until 2026, the peak period can last for 4 months, and the unit daily oil production can be increased to 127m 3 / d, the maximum reduction in water content compared with the predicted water content without gas injection is 8%, and the oil production increase by 10,000 cubic meters of N2 is 35.4t.

[0219] Experimental example

[0220] In order to evaluate the reliability of the injection-production scheme optimization design method for small oil reservoirs with strong edge water in Examples 1 and 2, water drive simulation, polymer drive simulation and nitrogen artificial gas cap drive simulation were carried out on the small oil reservoir A with high porosity, high permeability and strong edge water and high water content respectively according to the methods of Examples 1 and 2. Then, water drive, polymer drive and nitrogen artificial gas cap drive were carried out on the small oil reservoir A with high porosity, high permeability and strong edge water and high water content respectively using the simulation optimization results. The field implementation results showed that when the water cut of the produced oil reached 95%, the cumulative oil production B differed from the cumulative oil production obtained by simulation by no more than 3%. Therefore, the injection-production scheme optimization design method for small oil reservoirs with strong edge water in Examples 1 and 2 is relatively reliable.

[0221] In addition, when the parameter order of the polymer flooding simulation and the nitrogen artificial gas cap flooding simulation was not changed, and only the parameter order of the water flooding simulation was changed, that is, the production rate and water injection rate were optimized in sequence, and then the simulation optimization results were used to carry out water flooding, polymer flooding and nitrogen artificial gas cap flooding on the small oil reservoir A1 with high porosity, high permeability, strong edge water and high water content. The field implementation results showed that when the water content of the produced oil reached 95%, the cumulative oil production was significantly different from the simulation results (the difference was greater than 20%), and the cumulative oil production B1 was less than 30% of the cumulative oil production B.

[0222] When the order of parameters in the water flooding simulation and nitrogen artificial gas cap drive simulation is not changed, and only the order of parameters in the polymer flooding simulation is changed, that is, the injection rate, slug volume and polymer concentration in the polymer flooding agent are optimized in sequence, or the slug volume, polymer concentration in the polymer flooding agent and polymer flooding agent injection rate are optimized in sequence, or the slug volume, polymer flooding agent injection rate and polymer concentration in the polymer flooding agent are optimized in sequence, and then the simulation optimization results are used to carry out water flooding, polymer flooding and nitrogen artificial gas cap drive on small oil reservoirs A2, A3 and A4 with high porosity, high permeability and strong edge water and high water content. The field implementation results show that when the water cut of the produced oil reaches 95%, the cumulative oil production is significantly different from the simulation results (the difference is greater than 20%), and the corresponding cumulative oil productions B2, B3 and B4 are all less than 30% of the cumulative oil production B;

[0223] When the order of parameters in the water flooding simulation and polymer flooding simulation is not changed, and only the order of parameters in the nitrogen artificial gas cap flooding simulation is changed, that is, the gas injection rate, gas injection volume, well holding time, and daily liquid production are optimized in sequence, or the gas injection volume, well holding time, gas injection rate, and daily liquid production are optimized in sequence, or the daily liquid production, gas injection volume, well holding time, and gas injection rate are optimized in sequence, and then the simulation optimization results are used to carry out water flooding, polymer flooding, and nitrogen artificial gas cap flooding on small oil reservoirs A5, A6, and A7 with high porosity, high permeability, strong edge water, and high water content. The field implementation results show that when the water cut of the produced oil reaches 95%, the cumulative oil production is significantly different from the simulation results (the difference is greater than 20%), and the corresponding cumulative oil productions B5, B6, and B7 are all less than 30% of the cumulative oil production B;

[0224] Among them, small oil reservoirs A, A1, A2, A3, A4, A5, A6, and A7 with high porosity, high permeability, strong edge water and high water content are oil reservoirs with similar properties. The porosity difference between any two oil reservoirs is no more than 2%, the permeability difference is no more than 3%, the ratio of edge water volume to reservoir volume is no more than 2%, the comprehensive water content of the oil reservoirs is no more than 1%, and the oil reserves difference is no more than 3%.

[0225] From the above experimental results, it can be seen that for small oil reservoirs with high porosity, high permeability, strong edge water and high water content, when simulating and determining the production parameters of water flooding, polymer flooding and nitrogen flooding, they need to be optimized in a certain order.

Claims

1. A method for optimizing the design of mining of a small oil reservoir with high porosity, high permeability, strong edge water and high water content, characterized in that: The following steps are involved: (1) Establish a numerical simulation model for a small oil reservoir with high porosity, high permeability, and strong edge water, and then perform numerical simulation to determine the distribution of remaining oil in the reservoir; (2) Conduct water flooding simulations for small oil reservoirs with high porosity, high permeability, strong edge water, and high water content, and optimize the water flooding well pattern and water flooding injection and production parameters, including injection rate and production rate; (3) Conduct a feasibility analysis of polymer flooding on a small oil reservoir with high porosity, high permeability, and strong edge water and high water content. If the small oil reservoir with high porosity, high permeability, and strong edge water and high water content meets the conditions for polymer flooding, perform polymer flooding simulation on the small oil reservoir with high porosity, high permeability, and strong edge water and high water content after water flooding simulation, and optimize the polymer flooding well pattern and the injection and production parameters of the polymer flooding. The injection and production parameters of the polymer flooding include the injection and production ratio, the slug volume, the concentration of the polymer in the polymer flooding agent, and the injection rate of the polymer flooding agent.

2. The method for optimizing the design of mining of a small oil reservoir with high porosity, high permeability, strong edge water and high water content according to claim 1, characterized in that: During water flooding simulation, the water flooding well network is optimized first, the water injection wells are determined, and then the water injection rate and production rate in the injection-production parameters are optimized respectively.

3. The method for optimizing the design of mining of a small oil reservoir with high porosity, high permeability, strong edge water and high water content according to claim 1 or 2, characterized in that: When optimizing the injection and production parameters of water flooding, the optimal criterion for water injection rate is: under the condition of the same daily liquid production of a single well, the water injection rate corresponding to the maximum oil production increment is the optimal water injection rate; the optimal criterion for production rate is: under the condition of the same water injection rate of the injection well, the production rate corresponding to the maximum recovery degree is the optimal production rate.

4. The method for optimizing the design of mining of a small oil reservoir with high porosity, high permeability, strong edge water and high water content according to claim 1, wherein: During polymer flooding simulation, the polymer flooding well pattern is optimized first, the injection wells are determined, and then the injection rate of the polymer flooding agent, the concentration of the polymer in the polymer flooding agent, and the slug volume in the polymer flooding injection and production parameters are optimized in sequence.

5. The method for optimizing the design of mining of a small oil reservoir with high porosity, high permeability, strong edge water and high water content according to claim 1 or 4, characterized in that: When optimizing the injection and production parameters of polymer flooding, the optimal criterion for the injection rate of the polymer flooding agent is: under the same conditions of injection-production ratio, polymer concentration in the polymer flooding agent, and slug size, the injection rate corresponding to the maximum recovery improvement value is the preferred polymer flooding agent injection rate; The optimal standard for polymer concentration in polymer flooding is: under the same injection-production ratio, injection rate, and slug size, the polymer concentration in the polymer flooding agent corresponding to the maximum comprehensive index is the optimal polymer concentration in the polymer flooding agent. The comprehensive index is equal to the ratio of the product of the recovery improvement value and the oil increase per ton of polymer solution to 100. The optimal criterion for slug volume is: under the same conditions of injection-production ratio, injection rate, polymer concentration in polymer flooding agent, and slug size, the slug volume corresponding to the maximum comprehensive index is the optimal slug volume. The comprehensive index is equal to the ratio of the product of the recovery improvement value and the oil increase per ton of polymer solution to 100.

6. The method for optimizing the design of mining of a small oil reservoir with high porosity, high permeability, strong edge water and high water content according to claim 1, 2 or 4, characterized in that: The method for optimizing the design of the exploitation of a small oil reservoir with high porosity, high permeability, and strong edge water and high water content further comprises the following steps: before water flooding simulation, firstly carrying out nitrogen flooding numerical simulation optimization of the small oil reservoir with high porosity, high permeability, and strong edge water and high water content, and then carrying out water flooding simulation; or after water flooding simulation, firstly carrying out nitrogen flooding numerical simulation optimization of the small oil reservoir with high porosity, high permeability, and strong edge water and high water content, and then carrying out polymer flooding feasibility analysis and polymer flooding simulation; or after polymer flooding simulation, carrying out nitrogen flooding numerical simulation optimization of the small oil reservoir with high porosity, high permeability, and strong edge water and high water content; the nitrogen flooding numerical simulation optimization comprises optimizing gas injection wells and nitrogen flooding injection-production parameters, wherein the nitrogen flooding injection-production parameters comprise gas injection volume, gas injection rate, well shut-in time, and daily liquid production.

7. The method for optimizing the design of mining of a small oil reservoir with high porosity, high permeability, strong edge water and high water content according to claim 6, characterized in that: When conducting numerical simulation optimization of nitrogen drive, the gas injection wells are optimized first and determined, and then the gas injection volume, gas injection rate, well shut-in time and daily liquid production in the nitrogen drive injection and production parameters are optimized in turn.

8. The method for optimizing the design of mining of a small oil reservoir with high porosity, high permeability, strong edge water and high water content according to claim 7, characterized in that: When conducting numerical simulation optimization of nitrogen flooding, the optimal selection criteria for injection wells are: under the same conditions of gas injection volume, gas injection rate, well shut-in time, daily liquid production, and injection method, the injection well with the maximum oil increase is the preferred injection well; The method for optimizing the gas injection volume is as follows: first, select candidate gas injection volumes from the designed gas injection volume values, and then select the minimum gas injection volume value from the candidate gas injection volume values, which is the preferred gas injection volume; wherein, the method for selecting the candidate gas injection volume values is as follows: if the oil increase at a certain gas injection volume is the maximum value, and the reduction in the oil change rate at this gas injection volume is not less than 0.7t / 10 4 m 3 , then the gas injection amount is the candidate gas injection amount value; the reduction range of the oil change rate at a certain gas injection amount is equal to (DC) / (BA), where D is the oil change rate when the gas injection amount is B, C is the oil change rate when the gas injection amount is A, gas injection amounts A and B are two adjacent gas injection amount design values, and B>A, and BA≤20×10 4 m 3 ; The optimal standard for gas injection speed is: if the daily nitrogen injection capacity of the nitrogen injection equipment is Bm 3 , when the injection rate is changed from Bm 3 / d decreases by 5000m 3 / d corresponds to an increase in oil volume of no more than 7t or an increase in oil change rate of no more than 0.1t / 10 4 m 3 When Bm 3 That is the preferred gas injection rate; The optimal soaking time is as follows: if the increase in oil production at a particular soaking time is the largest and no less than 70% of the nitrogen has migrated to the top of the structure at that soaking time, then that soaking time is the optimal soaking time. The increase in oil production at a particular soaking time is equal to (DC) / (BA), where D is the oil production at soaking time B, C is the oil production at soaking time A, soaking time A and soaking time B are two adjacent soaking time design values, B>A, and BA≤30d. The optimal standard for daily fluid production is: if the oil change rate corresponding to a certain daily fluid production is not less than 35t / 10 4 m 3 , and when the daily liquid production is increased by 5t / d on the basis of the daily liquid production, the corresponding cumulative oil production is reduced by not less than 812t, and the corresponding oil change rate is reduced by not less than 4t / 10 4 m 3 When , the daily liquid production is the preferred daily liquid production.

9. The method for optimizing the design of mining of a small oil reservoir with high porosity, high permeability, strong edge water and high water content according to claim 1, 2 or 4, characterized in that: Small oil reservoirs with high porosity, high permeability, strong edge water and high water content refer to oil reservoirs that meet the following conditions: (1) porosity greater than 25%; (2) permeability greater than 800mD; (3) edge water volume greater than 300 times the reservoir volume; (4) comprehensive water content of the reservoir greater than 80%; (5) oil reservoir reserves less than 10 million tons.

Images