A method for designing well concentration of three types of oil reservoirs based on system hydrodynamic radius

Abstract

The present application relates to a kind of three types of oil layer classification well concentration design method based on system hydrodynamics radius. Mainly solve the existing method when the concentration design of single well only gives the lower limit value of concentration without reasonable upper limit value, for the injection concentration of three types of oil layer with smaller pore throat radius is too high, which can lead to injection difficulty even plugging oil layer problem. Including the following steps: 1, obtain classification well K80;2, calculate the pore throat radius corresponding to K80;3, through the ratio of pore throat radius / hydrodynamics radius and flow state, the different hydrodynamics radius limit value corresponding to classification well K80 is determined;4, test the water dynamic radius of injection system under different concentration conditions;5, determine the concentration range suitable for classification well;6, determine the average concentration design standard of classification well according to the formation coefficient of classification well;7, determine the injection concentration of single well. The method can ensure the stable injection of polymer at the initial stage of injection, and ensure that the concentration design of different types of well group is more reasonable.

Description

Technical fields:

[0001] This invention relates to the field of tertiary oil recovery technology for three types of oil reservoirs, and in particular to a method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system. Background technology:

[0002] Polymer flooding technology has developed rapidly and is widely used in major oilfields. With the continuous promotion of industrialization in Class I oil reservoirs, the tertiary recovery reserves of Class I reservoirs are decreasing year by year. To achieve production succession, the target of polymer flooding has shifted from Class I to Class III oil reservoirs. Class III oil reservoirs are thin and exhibit significant inter-well variations. When using polymer flooding, it is necessary to design the system concentration individually based on the reservoir development and injection conditions of each well to ensure successful injection. Currently, a single-well concentration design method is used for Class III oil reservoirs. This method mainly relies on the matching chart of the injection system, finding the lower limit of the concentration on the chart according to the permeability K80 of the single well. The concentration of the single well is considered to be greater than or equal to the lower limit, with no upper limit requirement. However, this method does not consider the effective thickness, pore throat radius, and injection pressure level of the single well. Furthermore, the pore throat radius of Class III oil reservoirs is small, and excessively high injection concentrations can lead to injection difficulties or even reservoir blockage. Therefore, the single-well concentration design method is not suitable for classifying well concentrations in Class III oil reservoirs. Summary of the Invention:

[0003] This invention overcomes the limitations of existing methods in the prior art, which only provide a lower limit for concentration design in single-well applications without a reasonable upper limit. For Class III oil reservoirs with small pore throat radii, excessively high injection concentrations can lead to injection difficulties or even reservoir blockage. This invention provides a concentration design method for Class III oil reservoirs based on the system's hydrodynamic radius. This method, by incorporating the system's hydrodynamic radius, ensures stable polymer injection in the initial stages of polymerization, resulting in more rational concentration design for different well types.

[0004] The present invention solves its problem through the following technical solution: The method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system includes:

[0005] The permeability distribution of classified wells is statistically analyzed. Based on the statistical distribution of permeability of classified wells, the permeability value corresponding to the classified well when the cumulative effective thickness ratio reaches 80% is determined, namely K80.

[0006] Based on the obtained K80, calculate the throat radius corresponding to K80;

[0007] Based on the obtained pore throat radius corresponding to K80, the boundary values ​​of different hydrodynamic radii corresponding to K80 of the classification wells are determined by the ratio of pore throat radius / hydrodynamic radius and flow state.

[0008] The hydrodynamic radius of the injected system was tested under different concentration conditions, and a table of hydrodynamic radius relationships for different concentration systems was generated.

[0009] Based on the obtained hydrodynamic radius limit value and the corresponding hydrodynamic radius relationship table under different concentration systems, the suitable concentration range for classification wells is determined;

[0010] Based on the determined suitable concentration range of the classification wells, the average concentration of the classification wells is determined according to the formation coefficient of the classification wells.

[0011] Based on the average concentration of the classified wells, the injection concentration of a single well is determined according to the pressure space of the single well.

[0012] Furthermore, the method for determining the permeability value corresponding to a classified well when the cumulative effective thickness ratio reaches 80%, i.e., K80, includes:

[0013] The oil layers of the same type of well group are sorted by permeability, and then sorted from highest to lowest permeability to calculate the cumulative effective thickness ratio.

[0014] Based on the obtained cumulative effective thickness ratio, the permeability value corresponding to the oil layer when the cumulative effective thickness ratio reaches 80% is the K80 of the well group.

[0015] Furthermore, the formula for calculating the pore throat radius corresponding to the permeability value of K80 is as follows:

[0016]

[0017] In the formula:

[0018] Dr is the pore throat radius, in μm;

[0019] K is the permeability, in μm 2 ;

[0020] Porosity.

[0021] Furthermore, the ratio of the orifice throat radius to the hydrodynamic radius and the corresponding flow state are as follows:

[0022] When the ratio of pore throat radius to hydrodynamic radius is less than 3.3, the system becomes blocked in the oil layer.

[0023] When 3.6 < pore throat radius / hydrodynamic radius ≤ 3.3, the system is difficult to inject into the oil layer;

[0024] When the ratio of pore throat radius to hydrodynamic radius is greater than 3.6, the system is successfully injected into the oil layer.

[0025] Further methods for testing the hydrodynamic radius of the injected system under different concentration conditions include:

[0026] First, prepare injection systems of different concentrations;

[0027] The viscosity of the injection system at different concentrations was measured;

[0028] For each concentration of the injection system, under the same pressure conditions, the injection system is allowed to flow through microporous filter membranes with different pore sizes. Then, the viscosity of the filtrate passing through the filter membrane is measured, the viscosity retention rate is calculated, and a relationship curve between the viscosity retention rate and the pore size of the microporous filter membrane is plotted. From the relationship curve, the filter membrane size corresponding to the point where the viscosity retention rate is 80% is found, which is the hydrodynamic radius of the injection system at that concentration.

[0029] Based on the hydrodynamic radius of the injected system at each concentration, a table of hydrodynamic radius relationships for different concentration systems is created.

[0030] Furthermore, the formula for calculating the viscosity retention rate is as follows:

[0031] Rs = (η2 / η1) * 100%;

[0032] In the formula: Rs is the viscosity retention rate, %; η1 is the viscosity of the system injected before passing through the filter membrane, mPa.s;

[0033] η2 is the viscosity of the filtrate after passing through the filter membrane, in mPa·s.

[0034] Furthermore, methods for determining the concentration range of classified wells include:

[0035] By comparing the calculated hydrodynamic radius limit value of the injection system corresponding to the K80 classification well with the formed relationship table, the hydrodynamic radius range in which the hydrodynamic radius limit value of the injection system is located is found.

[0036] Then, based on the correspondence between system concentration and hydrodynamic radius in the relationship table, the corresponding injection concentration range is found. The upper and lower limits of this concentration range are the suitable concentration range (n1-n2) for this type of well group, where n1 is the suitable lower limit of concentration and n2 is the suitable upper limit of concentration.

[0037] Furthermore, the formation coefficient of a classified well is equal to the product of the average effective thickness and the average permeability.

[0038] Furthermore, methods for determining the average concentration of classified wells based on their formation coefficients include:

[0039] When the formation coefficient of a classified well is greater than the average formation coefficient of the block, the upper limit of the concentration range shall be taken as the design standard for the well group.

[0040] For well groups with low formation coefficients, while ensuring stable polymer injection, it is also necessary to ensure polymer flooding effect. The average value of the concentration range should be selected as the average concentration of the well group.

[0041] Furthermore, methods for determining the injection concentration of a single well based on the single well pressure space include:

[0042] For wells whose pressure space is within ±0.5 MPa of the average pressure space of the well group, the injection concentration of the well shall be the average injection concentration of the well group.

[0043] For a single well whose pressure space is greater than the average pressure space of the well group by 0.5 MPa, the injection concentration of that well is 200 mg / L higher than the average injection concentration.

[0044] For wells with a pressure space less than 0.5 MPa of the average pressure space of the well group, the injection concentration of that well is 200 mg / L lower than the average injection concentration.

[0045] Under the condition of the same molecular weight of the injected system, the higher the concentration of the injected system, the higher the viscosity of the system, the larger the hydrodynamic size, the stronger its ability to expand the swept volume, and the greater the viscoelasticity of the injected system, the higher the oil sweeping efficiency in the oil layer. However, if the size of the injected system is too large, it will not match the pore throat radius of the oil layer, causing most of the injected system to be blocked when passing through the pore throat, making the injection difficult, causing pore blockage in the oil layer, and in severe cases, causing the oil layer to be abandoned. If the polymer molecule size is too small, the displacement effect is not very obvious, the economic cost is high, and the polymer flooding effect is poor. Due to the poor connectivity of the three types of oil layers, strong planar heterogeneity, and significant differences in oil layer development and injection capacity between different well groups, a single injection concentration cannot meet the polymer flooding development of all wells. Therefore, when designing the injection concentration of a single well, the relationship between the pore throat radius of the classified well and the hydrodynamic radius of the injected system is applied. Under the premise of fully considering the oil layer development and pressure space of the classified well, the injection concentration of the classified well is designed individually.

[0046] Compared with the above-mentioned background technology, the present invention has the following beneficial effects:

[0047] This invention presents a method for designing injection concentrations in three types of oil reservoirs based on the hydrodynamic radius of the system. When designing the injection concentration of a single well, the relationship between the pore throat radius of the classified well and the hydrodynamic radius of the injection system is applied. Under the premise of fully considering the oil reservoir development and pressure space of the classified wells, the injection concentration of the classified wells is designed in a personalized manner, which can improve the compliance rate of single-well injection schemes, control the rate of injection pressure rise, increase the liquid absorption thickness of the oil reservoir, greatly reduce the overall water cut, and significantly increase the daily oil production.

[0048] This invention has been applied in the field test area of ​​the Pu I1-2 layer in Xingnan Development Zone. The initial single-well injection scheme compliance rate reached 85.71%, which is 7.14 percentage points higher than the scheme designed directly using drawings. Polymer injection in the test area started in February 2020. After 8 months of polymer injection, the injection pressure in the whole area gradually increased, with an average monthly injection pressure increase rate of 0.3 MPa / month. The oil layer fluid absorption thickness increased by 14.3 percentage points compared with before polymer injection. The produced wells showed good polymer flooding development effect, with daily oil production increasing from 21.1t before polymer injection to 41.3t. The overall water cut decreased from 94.77% before polymer injection to 91.35%, a decrease of 3.42 percentage points. Attached image description:

[0049] Appendix Figure 1 This is a block diagram of the concentration design method for three types of oil reservoirs based on the hydrodynamic radius of the system, as described in this invention.

[0050] Appendix Figure 2 This is a permeability distribution map of the classified wells in the test area of ​​an embodiment of the present invention;

[0051] Appendix Figure 3 The curves showing the relationship between filter membrane size and viscosity retention rate for different concentrations of low-molecular-weight 9 million polymer systems in the experimental area of ​​this invention are shown. Detailed implementation method:

[0052] To make the objectives, technical solutions, and advantages of the present invention clearer, the embodiments of the present invention will be described in further detail below with reference to the accompanying drawings.

[0053] like Figure 1 As shown, the concentration design method for three types of oil reservoirs based on the hydrodynamic radius of the system includes the following steps:

[0054] (1) Statistically analyze the permeability distribution of classified wells and determine the permeability value corresponding to K80 (when the cumulative effective thickness ratio reaches 80%). Specifically, sort the oil layers of the same type of well group according to permeability from high to low, calculate the cumulative effective thickness ratio, and find the permeability value corresponding to the oil layer when the cumulative effective thickness ratio reaches 80%, which is the K80 of the well group;

[0055] (2) Calculate the pore throat radius corresponding to the permeability value of K80, based on...

[0056]

[0057] In the formula:

[0058] Dr is the pore throat radius, in μm;

[0059] K is the permeability, in μm 2 ;

[0060] Porosity.

[0061] (3) Calculate the hydrodynamic radius limit value of the injection system suitable for classification wells.

[0062] In the laboratory, the compatibility of the injection system with different oil layers was obtained using the resistance coefficient method. Furthermore, there was a strong correlation between the pore throat size and the hydrodynamic radius of the injection system (the better the oil layer development, the larger the pore throat radius, and the larger the hydrodynamic radius of the system that can be injected). Comparison of the compatibility results showed that when the pore throat radius / hydrodynamic radius ratio was < 3.3, the system became blocked in that oil layer; when 3.6 < pore throat radius / hydrodynamic radius ≤ 3.3, the system was difficult to inject in that oil layer; and when the pore throat radius / hydrodynamic radius ratio was > 3.6, the system was successfully injected in that oil layer. Based on the pore throat radius / hydrodynamic radius ratio and flow state, the different hydrodynamic radius thresholds corresponding to well K80 were calculated.

[0063] (4) Test the hydrodynamic radius of the injection system under different concentration conditions.

[0064] The hydrodynamic radius of the injection system under different concentration conditions was tested using the microporous membrane filtration method. The specific procedure is as follows: First, the viscosity of the prepared injection system is measured. Under the same pressure conditions, the injection system is allowed to flow through microporous membranes with different pore sizes. Then, the viscosity of the filtrate passing through the membrane is measured, the viscosity retention rate is calculated, and a curve showing the relationship between viscosity retention rate and microporous membrane pore size is plotted. From the curve, the membrane size corresponding to the point where the viscosity retention rate is 80% is identified, which is the hydrodynamic radius of the oil displacement system at that concentration. A table showing the hydrodynamic radius relationships for different concentration systems is then created.

[0065] Rs = (η2 / η1) * 100%

[0066] In the formula:

[0067] Rs represents viscosity retention rate, in %;

[0068] η1 is the viscosity of the precursor oil system through the filter membrane, in mPa·s;

[0069] η2 is the viscosity of the filtrate after passing through the filter membrane, in mPa·s.

[0070] (5) Determine the concentration range of the classification wells.

[0071] By comparing the limit value of the injection system hydrodynamic radius corresponding to the classification well K80 calculated in step (3) with the relationship table formed in step (4), the hydrodynamic radius range where the limit value is located is found. Then, according to the correspondence between the system concentration and the hydrodynamic radius in the relationship table, the corresponding injection concentration range is found. The upper and lower limits of this concentration range are the suitable concentration range (n1-n2) for this type of well group, where n1 is the suitable lower limit of concentration and n2 is the suitable upper limit of concentration.

[0072] (6) Determine the average concentration of the classified wells based on the formation coefficient Kh (average effective thickness * average permeability).

[0073] The effective thickness and permeability of the oil reservoir affect the flow of the injection system within it. Under the same injection pressure and concentration, the larger the formation coefficient of the oil reservoir, the faster the system flows, which is detrimental to the oil displacement effect. Therefore, the formation coefficient of the classified wells was referenced in the concentration design to make the concentration design more reasonable. When the formation coefficient of the classified wells is greater than the block average formation coefficient, the upper limit of the concentration range is taken as the design standard for the well group. For well groups with small formation coefficients, while ensuring stable polymer injection, the polymer flooding effect must also be ensured. The average value of the concentration range ((n1+n2) / 2) can be selected as the design standard for the well group.

[0074] (7) Determine the injection concentration of a single well based on the pressure space of that well.

[0075] For wells with a pressure space within ±0.5 MPa of the average pressure space of the well group, the injection concentration of that well shall be the average injection concentration of the well group. For wells with a pressure space greater than 0.5 MPa of the average pressure space of the well group, the injection concentration of that well shall be 200 mg / L higher than the average injection concentration. For wells with a pressure space less than 0.5 MPa of the average pressure space of the well group, the injection concentration of that well shall be 200 mg / L lower than the average injection concentration.

[0076] Example 1

[0077] The method of this invention was applied to the Pu I1-2 layer test area in the Xingnan Development Zone of Daqing Oilfield. There are a total of 14 injection wells in the area. In order to achieve personalized tracking and adjustment for different well groups, the well groups in the test area were classified according to the development of the oil layer in a single well. The classification results are as follows: 7 wells in category A and 7 wells in category B. The wells in category A are better developed than those in category B. The average effective thickness of a single well in category A is 9.6m and the average permeability of a single well is 0.360 Darcy. The average effective thickness of a single well in category B is 4.8m and the average permeability of a single well is 0.146 Darcy.

[0078] (1) Statistical analysis of well permeability distribution:

[0079] Oil reservoirs within the same well group were sorted from highest to lowest effective permeability. Simultaneously, the cumulative effective thickness ratio was calculated to determine the permeability values ​​corresponding to K80 (when the cumulative effective thickness ratio reaches 80%) for wells in categories A and B. The calculated permeability for K80 in category A wells was 0.130 Darcy; the permeability for K80 in category B wells was 0.060 Darcy. For the permeability distribution of the well categories, please refer to [reference needed]. Figure 2 ;

[0080] (2) Calculate the pore throat radius corresponding to the permeability value of the K80 well classification.

[0081] Based on the porosity of a single well, the average porosity value of the classified wells is calculated. The average porosity of Class A wells is 26.97%, and the average porosity of Class B wells is 22.72%. Substituting the K80 and porosity values ​​of the classified wells into the following formula, the pore throat radius of the classified wells is calculated. The calculated pore throat radius Dr of Class A wells is... A The borehole throat radius Dr in Class B wells is 1.96 μm. B It is 1.45μm.

[0082]

[0083] In the formula:

[0084] Dr is the pore throat radius, in μm;

[0085] K is the permeability, in μm 2 ;

[0086] Porosity, %.

[0087] (3) Calculate the hydrodynamic radius limit of the injection system.

[0088] When the ratio of pore throat radius to hydrodynamic radius is less than 3.3, it indicates blockage; when 3.6 < pore throat radius / hydrodynamic radius ≤ 3.3, it indicates difficult injection; when the ratio of pore throat radius / hydrodynamic radius is greater than 3.6, it indicates smooth injection. Based on the ratio of pore throat radius to hydrodynamic radius and the flow state, the different hydrodynamic radius limit values ​​corresponding to different well types are calculated. For Class A wells, blockage occurs when the system's hydrodynamic radius is greater than 0.595 μm; injection is difficult when the system's hydrodynamic radius is greater than 0.545 μm but less than 0.595 μm; and injection proceeds smoothly when the system's hydrodynamic radius is less than or equal to 0.545 μm. Therefore, the suitable hydrodynamic radius limit for Class A wells is 0.545 μm. For Class B wells, blockage occurs when the system's hydrodynamic radius is greater than 0.440 μm; injection is difficult when the system's hydrodynamic radius is greater than 0.401 μm but less than 0.440 μm; and injection proceeds smoothly when the system's hydrodynamic radius is less than or equal to 0.401 μm. Therefore, the suitable hydrodynamic radius limit for Class B wells is 0.401 μm.

[0089] (4) Test the hydrodynamic radius of the injection system under different concentration conditions.

[0090] The hydrodynamic radius of the injected system under different concentration conditions was tested using the microporous membrane filtration method. The injected system used a 9 million Mn ultra-low molecular weight polymer from a chemical refinery, and the dilution water was wastewater from the No. 3 injection station in Xing Twelfth District. A clean-to-dilute ratio was adopted. The hydrodynamic radius of the system at different concentrations was determined using the membrane filtration method, and the relationship between the system viscosity retention rate and the membrane size was plotted (see details). Figure 3 The hydrodynamic radius of the injected system at different concentrations was obtained from the relationship curve (see Table 1 for details).

[0091] Table 1. Hydrodynamic radii (μm) of different injection systems determined by the microporous membrane filtration method.

[0092]

[0093] (5) Determine the concentration range of the classification wells

[0094] Based on the suitable hydrodynamic radius limits for injection systems of Class A and Class B wells, the hydrodynamic radius can be found in Table 1. The suitable hydrodynamic radius for injection systems of Class A wells is 0.545 μm, between 0.5 μm and 0.73 μm, corresponding to a concentration range of 1000 mg / L to 1200 mg / L. The suitable hydrodynamic radius for injection systems of Class B wells is 0.401 μm, between 0.38 μm and 0.43 μm, corresponding to a concentration range of 500 mg / L to 800 mg / L.

[0095] (6) Determine the average concentration of the classification wells

[0096] The formation coefficient for Class A wells is 3.456 μm. 2 The average formation coefficient for Class B wells is 0.701 μm. 2 The average stratigraphic coefficient for the entire region is 2.078 μm. 2 For Class A wells, the oil layer is well-developed and the formation coefficient is high. Therefore, the average concentration of Class A wells is taken as the upper limit of the concentration range, which is 1200 mg / L. For Class B wells, the oil layer is poorly developed and the formation coefficient is small. The average concentration is the average of the upper and lower limits of the concentration range, which is 650 mg / L.

[0097] (7) Determine the injection concentration of a single well based on the single well pressure space.

[0098] The average pressure space of wells in categories A and B was statistically analyzed. Calculations showed that the average pressure space for category A wells was 6.4 MPa, and for category B wells it was 4.8 MPa. In category A, two wells had pressure spaces exceeding the average pressure space by more than 0.5 MPa, with an injection concentration of 1400 mg / L; two wells had pressure spaces within ±0.5 MPa of the average pressure space, with a concentration of 1200 mg / L; and three wells had pressure spaces less than the average pressure space by more than 0.5 MPa, with an injection concentration of 1000 mg / L. Similarly, in category B, two wells had pressure spaces exceeding the average pressure space by more than 0.5 MPa, with an injection concentration of 850 mg / L; three wells had pressure spaces within ±0.5 MPa of the average pressure space, with a concentration of 650 mg / L; and two wells had pressure spaces less than the average pressure space by more than 0.5 MPa, with an injection concentration of 450 mg / L. (For detailed well concentration design results, see Table 2.)

[0099] Table 2 Optimization Design of Injection Concentration for Classified Well Groups in the Experimental Area

[0100]

[0101] The application of this invention in the field test area of ​​the Pu I1-2 layer in Xingnan Development Zone showed that the initial single-well injection scheme compliance rate reached 85.71%, which was 7.14 percentage points higher than the scheme designed directly using charts. Polymer injection in the test area started in February 2020. After 8 months of polymer injection, the injection pressure in the whole area gradually increased, with an average monthly injection pressure increase rate of 0.3 MPa / month. The oil layer fluid absorption thickness increased by 14.3 percentage points compared with before polymer injection. The produced wells showed good polymer flooding development effect, with daily oil production increasing from 21.1t before polymer injection to 41.3t, and the overall water cut decreasing from 94.77% before polymer injection to 91.35%, a decrease of 3.42 percentage points.

Claims

1. A method for designing well concentrations in three types of oil reservoirs based on the hydrodynamic radius of the system, characterized in that: include: The permeability distribution of classified wells is statistically analyzed. Based on the statistical distribution of permeability of classified wells, the permeability value corresponding to the classified well when the cumulative effective thickness ratio reaches 80% is determined, namely K80. Based on the obtained K80, calculate the throat radius corresponding to K80; Based on the obtained pore throat radius corresponding to K80, the boundary values ​​of different hydrodynamic radii corresponding to K80 of the classification wells are determined by the ratio of pore throat radius / hydrodynamic radius and flow state. The hydrodynamic radius of the injected system was tested under different concentration conditions, and a table of hydrodynamic radius relationships for different concentration systems was generated. Based on the obtained hydrodynamic radius limit value and the corresponding hydrodynamic radius relationship table under different concentration systems, the suitable concentration range for classification wells is determined; Based on the determined suitable concentration range of the classification wells, the average concentration of the classification wells is determined according to the formation coefficient of the classification wells. Based on the average concentration of the classified wells, the injection concentration of a single well is determined according to the pressure space of the single well. Methods for determining the injection concentration of a single well based on the single well pressure space include: For wells whose pressure space is within ±0.5 MPa of the average pressure space of the well group, the injection concentration of the well shall be the average injection concentration of the well group. For a single well whose pressure space is greater than the average pressure space of the well group by 0.5 MPa, the injection concentration of that well is 200 mg / L higher than the average injection concentration. For wells with a pressure space less than 0.5 MPa of the average pressure space of the well group, the injection concentration of that well is 200 mg / L lower than the average injection concentration.

2. The method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system according to claim 1, characterized in that: Methods for determining the permeability value corresponding to a well when the cumulative effective thickness ratio reaches 80%, i.e., K80, include: The oil layers of the same type of well group are sorted by permeability, and then sorted from highest to lowest permeability to calculate the cumulative effective thickness ratio. Based on the obtained cumulative effective thickness ratio, the permeability value corresponding to the oil layer when the cumulative effective thickness ratio reaches 80% is the K80 of the well group.

3. The method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system according to claim 1, characterized in that: The formula for calculating the pore throat radius corresponding to the permeability value of K80 is as follows: ； In the formula: Dr is the pore throat radius, in μm; K is the permeability, in μm 2 ; Porosity.

4. The method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system according to claim 1, characterized in that: The ratio of orifice throat radius to hydrodynamic radius and the corresponding flow state are as follows: When the ratio of pore throat radius to hydrodynamic radius is less than 3.3, the system becomes blocked in the oil layer. When 3.6 < pore throat radius / hydrodynamic radius ≤ 3.3, the system is difficult to inject into the oil layer; When the ratio of pore throat radius to hydrodynamic radius is greater than 3.6, the system is successfully injected into the oil layer.

5. The method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system according to claim 1, characterized in that: Methods for testing the hydrodynamic radius of an injected system under different concentration conditions include: First, prepare injection systems of different concentrations; The viscosity of the injection system at different concentrations was measured; For an injection system of the same concentration, under the same pressure conditions, the injection system is allowed to flow through microporous filter membranes with different pore sizes. The viscosity of the filtrate passing through the filter membrane is then measured, the viscosity retention rate is calculated, and a relationship curve between the viscosity retention rate and the pore size of the microporous filter membrane is plotted. The filter membrane size corresponding to the point where the viscosity retention rate is 80% is found from the relationship curve, which is the hydrodynamic radius of the injection system at that concentration. Based on the hydrodynamic radius of the injected system at each concentration, a table of hydrodynamic radius relationships for different concentration systems is created.

6. The method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system according to claim 5, characterized in that: The formula for calculating viscosity retention rate is: Rs=(η2 / η1)*100%; In the formula: Rs is the viscosity retention rate, % η1 is the viscosity of the system injected before passing through the filter membrane, in mPa·s; η2 is the viscosity of the filtrate after passing through the filter membrane, in mPa·s.

7. The method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system according to claim 1, characterized in that: Methods for determining the concentration range of classified wells include: The calculated hydrodynamic radius limit value of the injection system corresponding to the K80 classification well is compared with the hydrodynamic radius relationship table corresponding to the different concentration systems formed, and the hydrodynamic radius range of the injection system hydrodynamic radius limit value is found. Based on the correspondence between system concentration and hydrodynamic radius in the relationship table, the corresponding injection concentration range is found. The upper and lower limits of this concentration range are the suitable concentration range n1-n2 for this type of well group, where n1 is the suitable lower limit of concentration and n2 is the suitable upper limit of concentration.

8. The method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system according to claim 1, characterized in that: The formation coefficient of a classified well is equal to the product of the average effective thickness and the average permeability.

9. The method for designing well concentrations for three types of oil reservoirs based on the hydrodynamic radius of the system according to claim 1, characterized in that: Methods for determining the average concentration of classification wells based on formation coefficients include: When the formation coefficient of a classified well is greater than the average formation coefficient of the block, the upper limit of the concentration range shall be taken as the design standard for the well group. For well groups with small formation coefficients, the average concentration of the concentration range is selected as the average concentration of the well group.

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