A method for evaluating the adaptability of polymer-containing oil displacement agent reservoirs by constant pressure injection

Abstract

The application discloses a method for evaluating adaptability of a polymer-containing oil displacement agent reservoir by constant pressure injection, and belongs to the technical field of water drive reservoir chemical flooding enhanced oil recovery, wherein the pressure gradient is calculated by using actual reservoir injection-production pressure difference and well spacing to determine the pressure difference value used in core experiment, and the liquid absorption pressure difference and liquid absorption index retention rate are used as constraint conditions for evaluating adaptability of the polymer-containing oil displacement agent reservoir.

Description

Technical Field

[0001] This invention belongs to the technical field of chemical flooding enhanced oil recovery in water-driven reservoirs, and relates to a method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection. Background Technology

[0002] Currently, major oil reservoirs in China, such as Daqing, Shengli, and Bohai, are all terrestrial sedimentary reservoirs. Terrestrial reservoirs have complex formation conditions, diverse sedimentary types, and significant variations in rock properties over time and space.

[0003] Terrestrial sedimentary rocks are mainly composed of clastic rocks and claystones. The clastic materials are mostly angular, and the bedding includes cross bedding, wavy bedding, and horizontal bedding. The biological fossils are mainly freshwater animals and terrestrial plants. The sediment transport distance is not large. During the waterflooding development of terrestrial oil reservoirs, due to the macroscopic and microscopic heterogeneity of the reservoir, the permeability difference in different parts causes different liquid initiation pressures, resulting in different liquid inflow differentials and liquid inflow volumes in different parts. Consequently, some areas (especially low-permeability parts of the reservoir) are not swept and residual oil is formed. In addition, in the waterflooded area, due to the influence of factors such as oil-water interfacial tension, the residual oil saturation has not yet been reduced to the level of residual oil saturation. Therefore, improving the recovery rate of waterflooded oil reservoirs should start from two aspects: expanding the swept volume and improving the oil washing efficiency, with expanding the swept volume as the main focus.

[0004] Long-term practice has clearly shown that increasing the injection pressure of water wells can increase the pressure differential and fluid absorption in low-permeability areas of the reservoir, thereby expanding the swept volume. In the mining field, increasing the injection pressure of water wells can be approached from two aspects: firstly, increasing the injection rate; and secondly, reducing the permeability (i.e., the fluid absorption index) in high-permeability areas of the reservoir. However, increasing the injection rate is constrained by the water supply at the injection end, the capacity of the injection equipment, and the capabilities of artificial lifting and surface oil-water separation at the production end. From a techno-economic perspective, significantly increasing the injection rate is not feasible. Furthermore, the majority of the additional fluid injected through increased injection rate enters the high-permeability areas of the reservoir. Additionally, the increased fluid absorption in low-permeability areas will flow back to the high-permeability areas within the reservoir. Therefore, increasing the injection rate does not significantly expand the actual swept volume. Thus, in existing technologies, reducing the permeability of high-permeability areas of the reservoir through artificial intervention has become the most commonly used approach to increase injection pressure.

[0005] One of the most common methods of artificial intervention is chemical flooding, which involves injecting polymer-containing flooding agents into the reservoir. In the early stages, these agents could only enter and remain in the high-permeability areas of the reservoir, thus reducing the permeability of that area, i.e., decreasing the liquid uptake index. With the injection rate kept constant, the decrease in the liquid uptake index in the high-permeability areas of the reservoir would cause an increase in injection pressure, which in turn would lead to an increase in the reservoir's liquid uptake differential and an increase in the liquid uptake in the medium and low-permeability areas, ultimately achieving the goal of expanding the swept volume and improving the recovery rate.

[0006] The compatibility of polymer-containing flooding agents with reservoirs, i.e., the matching relationship between polymer molecular aggregates in the polymer-containing flooding agent and the pore size of reservoir rocks, has a significant impact on the oil enhancement and water reduction effect of chemical flooding. The traditional method for evaluating the reservoir compatibility of polymer-containing flooding agents usually adopts the "constant rate" injection method to carry out core displacement experiments. The experimental steps are as follows: (1) Selecting polymer-containing flooding agents (the relative molecular mass and polymer concentration of the polymer, as well as the concentrations of other additives such as surfactants, alkalis and salts are known); (2) Initially selecting cores with specific permeability; (3) Injecting the polymer-containing flooding agent into the core using the "constant rate" injection method and observing the trend of injection pressure changes. If the injection pressure continues to rise, it indicates that the injected core volume of the polymer flooding agent is greater than the produced volume, and the polymer flooding agent is not compatible with the core, resulting in blockage. In this case, the core permeability is increased by 5-10 mD (millidarcy), and the next round of core displacement experiments is carried out until the injection pressure can reach a stable level. At this point, the injected core volume of the polymer flooding agent equals the produced volume, and the core permeability at this level is the minimum permeability at which the polymer flooding agent can enter the core, also known as the permeability limit. If the injection pressure can reach a stable level, the core permeability is decreased by 5-10 mD, and the next round of core displacement experiments is carried out until the injection pressure continues to rise. The core permeability of the previous round of experiments is the permeability limit of the polymer flooding agent.

[0007] As chemical flooding in major reservoirs gradually enters the subsequent waterflooding development stage, the application of chemical flooding is gradually shifting from major oil-bearing layers (Class I in Daqing Oilfield) to non-major oil-bearing layers (Class II and III reservoirs). Compared with major oil-bearing layers, non-major oil-bearing layers have poorer sand body development, lower average permeability, and increased heterogeneity. The shortcomings and problems of the "constant rate" injection evaluation method for reservoir adaptability of polymer-containing flooding agents used in major oil-bearing layers are beginning to show, which has a significant adverse impact on the oil production and water reduction effects of chemical flooding in non-major oil-bearing layers. Theoretical analysis and core experiments show that when using the existing "constant rate" injection evaluation method for reservoir adaptability of polymer flooding agents, the injection pressure is not limited. The pressure gradient value generated on the core is much greater than the maximum pressure gradient value that the reservoir can withstand for chemical flooding (because the injection pressure for chemical flooding in the field cannot exceed the reservoir rock fracturing pressure). Therefore, when the field uses this method to screen polymer flooding agents for testing, it will cause the injection pressure to rise rapidly to the reservoir fracturing pressure. This not only disrupts the injection-production balance, but also accelerates the reversal of the fluid absorption profile, reduces the swept volume of chemical flooding, and decreases the oil production and water reduction effects.

[0008] In summary, when using the "constant rate" injection method to determine the adaptability of reservoirs containing polymer flooding agents, the injection pressure, i.e., the injection pressure gradient, needs to be in an unrestricted environment to meet the optimal conditions, i.e., a relatively ideal environment. However, in actual field injection, the injection pressure is limited by the reservoir rock fracturing pressure, and its injection pressure gradient is much smaller than the core experiment value. Therefore, when conducting field tests based on the permeability limit of polymer flooding agents determined by core experiments, a rapid increase in injection pressure to the fracturing pressure will cause injection difficulties and accelerate the return speed of the liquid absorption profile, ultimately reducing the oil enhancement and water reduction effects. Summary of the Invention

[0009] The purpose of this invention is to address the problems in the prior art by providing a method for evaluating the adaptability of polymer flooding agent reservoirs using "constant pressure" injection, which calculates the pressure gradient based on the actual reservoir injection-production pressure difference and well spacing to determine the pressure difference value used in core experiments, and uses indicators such as suction pressure difference and suction index retention rate as constraints for evaluating the adaptability of polymer flooding agent reservoirs.

[0010] A method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection includes the following steps 1-4, specifically: Step 1: Determine the average pressure gradient δP of the actual reservoir during the water drive stage. 水驱 =(P 水 -P 流 )÷R, and the average pressure gradient δP of the actual reservoir during the chemical flooding stage. 化学驱 =(P 破 -P 流 )÷R; Determine the pressure difference ΔP during the chemical flooding stage in the reservoir adaptability experiment involving polymer flooding agents. 化学驱 =δP 化学驱 ×L, and water drive pressure difference ΔP 水驱 =δP 水驱 ×L; where P 水 P represents the average injection pressure of the actual oil reservoir at the end of waterflooding. 流 P is the average production flow pressure of the oil well. 破 R is the reservoir rock fracture pressure, i.e., the maximum injection pressure for chemical flooding; L is the distance between the injection well and the production well; and L is the length of the experimental core. Specifically, in step 1, the polymer-containing oil displacement agent injected into the reservoir during the chemical flooding stage includes one or more of the following: polymer, a binary composite system of polymer / surfactant, a ternary composite system of polymer / alkali / surfactant, and a ternary composite system of polymer / salt / surfactant.

[0011] More specifically, the polymer includes common polymers and / or salt-resistant polymers with a concentration of 500 mg / L to 5000 mg / L.

[0012] More preferably, the salt-resistant polymer comprises one or more of hydrophobic associative polymers, functional polymers, and surfactants.

[0013] More specifically, the surfactant concentration is 300 mg / L to 10000 mg / L, including one or more of anionic, nonionic and amphoteric surfactants; More specifically, the alkali includes strong alkali NaOH and / or weak alkali Na2CO3 with a concentration of 500 mg / L to 14000 mg / L.

[0014] More specifically, the salt is NaCl with a concentration of 500 mg / L to 14000 mg / L.

[0015] Step 2: Select an experimental core with a permeability of K1, and determine the water drive pressure difference ΔP based on the method used in Step 1. 水驱 As a constant pressure simulating waterflooding injection during the adaptability experiment of polymer-containing oil displacement agent reservoirs using experimental cores, the waterflooding fluid uptake rate Q of the experimental cores during waterflooding injection was determined. 水驱 ; Furthermore, in step 2, the experimental cores used in the reservoir adaptability experiment of polymer flooding agent include natural cores taken from actual reservoirs, as well as artificial cores made by pressing according to the mineral composition and pore structure of the natural cores. Artificial cores have the characteristics of good repeatability, low cost and wide availability, and are currently the main experimental cores used in core displacement experiments.

[0016] Furthermore, the artificial core is made using a quartz sand epoxy resin bonding method based on the permeability, mineral composition, and pore structure determined from actual oil reservoir logging and core sampling data. After the artificial core is completed, a core drill bit is used to drill columnar cores, and finally, the permeability of the cores is measured by gas, from which cores that meet the permeability requirements are selected for use.

[0017] Step 3, select a penetration rate of K n The experimental core, based on the pressure difference ΔP determined in step 1 during the chemical flooding stage. 化学驱 As a constant pressure simulating chemical flooding injection during the adaptation experiment of polymer flooding agent reservoirs on experimental cores, the chemical flooding uptake rate Q of the experimental cores was determined when the flow rate reached a steady state during the chemical flooding injection process. 化学驱 And based on the water-driven liquid absorption rate Q determined in step 2 水驱 The permeability is calculated to be K. n The retention rate of the experimental core liquid adsorption index α = Q 化学驱 ÷Q 水驱 ; Step 4: Compare the liquid absorption index retention rate α of the experimental core calculated in Step 3 with the specified value α of the liquid absorption index retention rate. 规定值 In comparison, the α 规定值 The prior threshold is determined based on actual reservoir production needs. If the liquid absorption index retention rate α ≥ α 规定值 Then, a penetration rate of K will be selected. n+1 Repeat steps 2 and 3 with the experimental core, where the permeability K of the experimental core is... n+1 =K n - (5~10mD), until the retention rate α of the experimental core liquid absorption index calculated in step 3 is < α 规定值 Then, the permeability of the experimental core used in the previous round is taken as the lowest core permeability that the polymer-containing flooding agent can penetrate, i.e., the permeability limit; if the liquid absorption index retention rate α≤α 规定值 Then, a penetration rate of K will be selected. n+1 Repeat steps 2 and 3 with the experimental core, where the permeability K of the experimental core is... n+1 =K n + (5~10mD), until the retention rate of the experimental core liquid absorption index calculated in step 3 is ≥ α 规定值 Then the permeability of the experimental core used in the previous round is taken as the lowest core permeability that the polymer-containing oil displacement agent can enter, i.e., the permeability limit.

[0018] More preferably, the injection water used in the reservoir adaptability test containing polymer flooding agent is prepared by weighing the corresponding salt and distilled water according to the actual reservoir injection water ion composition, and then mixing the salt and distilled water to obtain simulated injection water.

[0019] Beneficial effects Compared with existing technologies, this technical solution proposes a "constant pressure" injection method for evaluating the adaptability of reservoirs containing polymer flooding agents. It calculates the pressure gradient using the actual reservoir injection-production pressure difference and well spacing, thereby determining the pressure difference value used in core experiments. Furthermore, considering the significant reduction in the fluid absorption index of water-filled wells caused by chemical flooding, it proposes using two indicators—fluid absorption pressure difference and fluid absorption index retention rate—as constraints for evaluating the adaptability of reservoirs containing polymer flooding agents. Compared with the existing "constant rate" injection method, the "constant pressure" injection method limits the injection pressure increase and introduces the fluid absorption index retention rate, making the laboratory evaluation results closer to the actual needs of the mining field. Attached Figure Description

[0020] The foregoing and hereinafter detailed description of the invention becomes clearer when read in conjunction with the following drawings, in which: Figure 1 This is a schematic diagram of the simulation experimental equipment used in this technical solution. Detailed Implementation

[0021] The following specific embodiments further illustrate the technical solutions for achieving the objectives of this invention. It should be noted that the technical solutions protected by this invention include, but are not limited to, the following embodiments.

[0022] This example provides a method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection. The reagent used is a polymer, specifically partially hydrolyzed polyacrylamide, including six polymers (common polymers with relative molecular masses M=700, 900, 1200, 1900, and 2500×10⁻⁶). 4 The effective contents of the JD anti-salt polymers were 88.9%, 88.9%, 88.8%, 89.7%, 88.9%, and 89.8%, respectively.

[0023] First, simulated injection water was prepared. Based on the target oilfield's injection water ionic composition, the corresponding salt and distilled water were weighed out. The salt and distilled water were then mixed to obtain the simulated injection water, which contained the cation Ca. 2+ Mg 2+ and Na + The mass concentrations were 32.10, 7.30, and 1265.00 mg / L, and the anions were HCO3-, Cl-, and SO42-. 2- The mass concentrations were 1708.60, 780.10 and 9.60 mg / L, and the simulated total mineralization of the injected water was 4012.70 mg / L.

[0024] Then, the polymer solution was prepared. A certain volume of solvent water was measured according to the experimental requirements, and the designed amount of dry polymer powder was added to the water in stages. The mixture was stirred and matured for 2 hours. After that, the viscosity was measured, and the polymer solution was pre-sheared to ensure that its viscosity retention rate was 60%.

[0025] Next, artificial core samples are prepared. Based on reservoir logging and core sampling data from the actual oil reservoir, the permeability, mineral composition, and pore structure of the artificial cores are determined. The artificial cores are then prepared using a quartz sand and epoxy resin bonding method. Afterward, core samples are drilled using a core drill bit, and finally, the permeability of the cores is measured using gas. Cores meeting the permeability requirements are selected for later use.

[0026] Finally, the average pressure gradients for waterflooding and polymer flooding in the target reservoir were determined. The rock fracture pressure P in the target reservoir was collected. 破 =25MPa (bottom hole, same below), average injection pressure P at the end of water drive 水 =21MPa, average production pressure of oil well P 流 Based on data such as 5MPa and an average well spacing of 125m between oil and water wells, the average water drive pressure gradient δP was calculated. 水驱 =0.128 MPa / m and polymer flooding average pressure gradient δP 聚合物驱 =0.16MPa / m. If the length of the artificial core is L=10cm, then the water drive pressure difference ΔP in the core is...水驱 =0.0128MPa, polymer drive pressure difference ΔP 聚合物驱 =0.016MPa.

[0027] Then as Figure 1 As shown, the simulation experimental apparatus in this embodiment includes components such as an ICSO constant pressure pump, a hand-cranked pump, an intermediate container, a pressure sensor, pipelines, and gates. Except for the ICSO constant pressure pump and the hand-cranked pump, the other components are placed in a 45°C constant temperature chamber.

[0028] The aforementioned columnar core was measured for geometric dimensions and weighed dry. Then, the core was saturated with simulated water under vacuum and weighed wet. The apparent volume, pore volume, and porosity of the core were calculated. A polymer solution was placed in an intermediate container, and the columnar core was placed in a core holder. A stainless steel pipeline connected a horizontal flow pump, the intermediate container, and the core holder to form a core displacement experimental system. The system was tested using a pressure difference ΔP. 水驱 =0.0128MPa "constant pressure" water drive until the fluid production rate stabilizes, determine the fluid production rate Q. 水驱 Subsequently, the oil displacement agent was replaced with a polymer solution, using a pressure difference ΔP 化学驱 =0.016MPa "constant pressure" polymer flooding until the fluid collection rate stabilizes, and the fluid collection rate Q is determined. 化学驱 Based on experimental data Q 水驱 and Q 化学驱 Calculate the liquid absorption index and retention rate α = Q 化学驱 ÷Q 水驱 If the liquid absorption index and retention rate α ≥ α 规定值 (α) 规定值 =0.3), then reduce the core permeability to K. g ′ (K) g -(5~10mD)), using K g ′ The new core samples will be used for the next round of displacement experiments until the liquid retention index α < α0. 规定值 Take the permeability K from the previous core sample. g ′ The minimum core permeability that the polymer solution can penetrate, i.e., the permeability limit; if the liquid absorption index retention rate α ≤ α 规定值 This increases the core permeability to K. g ′ (K) g +(5~10mD)), also using new core K g ′ Continue conducting the next round of displacement experiments until the liquid absorption index retention rate α > α 规定值 Take the permeability K from the previous core sample. g ′ This serves as the permeability limit of the polymer solution.

[0029] Following the experimental steps described above, core displacement experiments were conducted. The results of the liquid uptake index retention rate of different polymer solutions passing through cores with different permeabilities are shown in Tables 1 to 6 below. Table 1. Liquid Absorption Index Retention Rate (%) Polymer Relative Molecular Mass M = 700 × 10⁻⁶ 4 ) Table 2. Liquid Absorption Index Retention Rate (%, M=900×10) 4 ) Table 3. Liquid Absorption Index Retention Rate (%, M=1200×10 4 ) Table 4. Liquid Absorption Index Retention Rate (%, M=1900×10 4 ) Table 5. Liquid Absorption Index Retention Rate (%, M=2500×10 4 ) Table 6 Liquid Absorption Index Retention Rate (%, JD Salt-Resistant Polymer) To compare the differences in reservoir adaptability evaluation results of polymer solutions obtained by "constant rate" and "constant pressure" injection methods, six polymer solutions (M=1200×10⁻⁶) were tested. 4 , C p =500, 600 and 700 mg / L, shear time 10s, viscosity retention rate approximately 55%; salt-resistant polymer JD, C p =600, 700 and 800 mg / L, shear time 7s, viscosity retention rate of about 55%) "constant rate" injection core displacement experiment.

[0030] The "constant rate" injection method determines the matching relationship between the polymer solution and the rock pores based on whether the injection and production process can reach injection-production equilibrium, i.e., whether the injection pressure relationship curve shows a horizontal segment. In other words, it determines the minimum permeability of the core into which the polymer solution can penetrate, i.e., the permeability limit. K g .

[0031] The core displacement experiment was carried out using the "constant rate" method. The results of the liquid absorption index retention rate when different polymer solutions passed through cores with different permeabilities are shown in Table 7 below.

[0032] Table 7. Drag Coefficient and Residual Drag Coefficient (M=1200×10⁻⁶) 4 ) Based on the above judgment principles, the three polymer solutions (M=1200×10) 4 , C p The core permeability limits (for concentrations of 500, 600, and 700 mg / L) are approximately 44, 74, and 114 × 10⁻⁶, respectively. -3 μm 2 JD anti-salt polymer solution (C p The core permeability limits (600, 700, and 800 mg / L) are approximately... K g =253, 300 and 405×10 -3 μm 2 .

[0033] The same three polymer solutions (M=1200×10) were used in the "constant pressure" injection method. 4 , C p The permeability limit (for concentrations of 500, 600, and 700 mg / L) is approximately 150. 、 150 and 200×10 -3 μm 2 JD anti-salt polymer solution (C p (For concentrations of 600, 700, and 800 mg / L) the permeability limit is approximately 300. 、 400 and 600×10 -3 μm 2 Therefore, it is evident that there is a significant difference in the polymer solution permeability limits determined by the two injection methods. The permeability limit value of the "constant rate" injection method is significantly lower than that of the "constant pressure" injection method, meaning that the former is suitable for a wider range of reservoir permeability. In addition, the pressure gradient of the "constant rate" injection method (approximately 0.30 MPa / m) is also significantly greater than that of the latter (0.16 MPa / m).

[0034] Considering that the injection pressure in the mine is limited by the pressure of reservoir rock fracturing, if the polymer solution determined by the "constant rate" injection method is used for chemical flooding in the mine, technical risks such as rapid increase in injection pressure, rapid reversal of the liquid absorption profile, and injection difficulties will be encountered.

[0035] Therefore, the polymer solution determined by the "constant pressure" injection method has a stronger adaptability to the reservoir, resulting in better oil production and water reduction effects.

Claims

1. A method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection, characterized in that, Includes the following steps: Step 1: Determine the average pressure gradient δP of the actual reservoir during the water drive stage. 水驱 =(P 水 -P 流 )÷R, and the average pressure gradient δP of the actual reservoir during the chemical flooding stage. 化学驱 =(P 破 -P 流 )÷R; Determine the pressure difference ΔP during the chemical flooding stage in the reservoir adaptability experiment containing polymer flooding agents. 化学驱 =δP 化学驱 ×L, and water drive pressure difference ΔP 水驱 =δP 水驱 ×L; where P 水 P represents the average injection pressure of the actual oil reservoir at the end of waterflooding. 流 P is the average production flow pressure of the oil well. 破 R is the reservoir rock fracture pressure, i.e., the maximum injection pressure for chemical flooding; L is the distance between the injection well and the production well; and L is the length of the experimental core. Step 2: Select an experimental core with a permeability of K1, and determine the water drive pressure difference ΔP based on the method used in Step 1. 水驱 As a constant pressure simulating waterflooding injection during the adaptability experiment of polymer-containing oil displacement agent reservoirs using experimental cores, the waterflooding fluid uptake rate Q of the experimental cores during waterflooding injection was determined. 水驱 ; Step 3, select a penetration rate of K n The experimental core, based on the pressure difference ΔP determined in step 1 during the chemical flooding stage. 化学驱 As a constant pressure simulating chemical flooding injection during the adaptation experiment of polymer flooding agent reservoirs on experimental cores, the chemical flooding uptake rate Q of the experimental cores was determined when the flow rate reached a steady state during the chemical flooding injection process. 化学驱 And based on the water-driven liquid absorption rate Q determined in step 2 水驱 The permeability is calculated to be K. n The retention rate of the experimental core liquid adsorption index α = Q 化学驱 ÷Q 水驱 ; Step 4: Compare the liquid absorption index retention rate α of the experimental core calculated in Step 3 with the specified value α of the liquid absorption index retention rate. 规定值 Comparison: If the liquid absorption index and retention rate α ≥ α 规定值 Then, a penetration rate of K will be selected. n+1 Repeat steps 2 and 3 with the experimental core, where the permeability K of the experimental core is... n+1 =K n - (5~10mD), until the retention rate α of the experimental core liquid absorption index calculated in step 3 is < α 规定值 Then, the permeability of the experimental core used in the previous round is taken as the lowest core permeability that the polymer-containing flooding agent can penetrate, i.e., the permeability limit; if the liquid absorption index retention rate α < α 规定值 Then, a penetration rate of K will be selected. n+1 Repeat steps 2 and 3 with the experimental core, where the permeability K of the experimental core is... n+1 =K n + (5~10mD), until the retention rate of the experimental core liquid absorption index calculated in step 3 is ≥ α 规定值 Then the permeability of the experimental core used in the previous round is taken as the lowest core permeability that the polymer-containing oil displacement agent can enter, i.e., the permeability limit.

2. The method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection as described in claim 1, characterized in that: In step 1, the polymer-containing oil displacement agent injected into the reservoir during the chemical flooding stage includes one or more mixtures of polymer, a binary composite system of polymer / surfactant, a ternary composite system of polymer / alkali / surfactant, and a ternary composite system of polymer / salt / surfactant.

3. The method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection as described in claim 2, characterized in that: The polymers include common polymers and / or salt-resistant polymers with concentrations of 500 mg / L to 5000 mg / L.

4. The method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection as described in claim 3, characterized in that: The salt-resistant polymer includes one or more of hydrophobic associative polymers, functional polymers, and surface agents.

5. A method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection as described in claim 2, 3, or 4, characterized in that: The surfactant concentration is 300 mg / L to 10000 mg / L, including one or more of anionic, nonionic and amphoteric surfactants.

6. A method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection as described in claim 2, 3, or 4, characterized in that: The alkali includes strong alkali NaOH and / or weak alkali Na2CO3 with a concentration of 500 mg / L to 14000 mg / L.

7. A method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection as described in claim 2, 3, or 4, characterized in that: The salt is NaCl with a concentration of 500 mg / L to 14000 mg / L.

8. The method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection as described in claim 1, characterized in that: In step 2, the experimental cores used in the reservoir adaptability test of polymer flooding agent include natural cores taken from actual reservoirs and artificial cores made by pressing based on the mineral composition and pore structure of the natural cores.

9. The method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection as described in claim 8, characterized in that: The artificial core is made using a quartz sand and epoxy resin bonding method, based on the permeability, mineral composition, and pore structure determined from actual oil reservoir logging and core sampling data. After the artificial core is completed, a core drill bit is used to drill columnar cores, and finally, the permeability of the cores is measured by gas, from which cores that meet the permeability requirements are selected for use.

10. The method for evaluating the adaptability of reservoirs containing polymer flooding agents using constant pressure injection as described in claim 1, characterized in that: The injection water used in the reservoir adaptability experiment of polymer flooding agent was prepared by weighing the corresponding salt and distilled water according to the actual reservoir injection water ion composition, and then mixing the salt and distilled water to obtain simulated injection water.

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