Method for determining permeability time variation of polymer flooding reservoir

Abstract

The invention discloses a method for determining the permeability time variation of a polymer flooding reservoir. The method comprises the following steps that S1, the displacement strength and the displacement multiple of reservoir physical property time varying of the polymer flooding reservoir are determined; s2, carrying out a polymer displacement experiment according to the displacement strength and the displacement multiple determined in the step S1; s3, after the displacement pressure is stable, a KCl solution is injected until the pressure is stable, and the permeability of the core after polymer flooding and the time-varying parameters of the core after polymer flooding are calculated and determined through a Darcy formula. In the displacement strength switching process, after the polymer flooding pressure is stable, the KCl solution is injected at a low speed until the pressure is stable again, and the reservoir permeability time-varying parameters after polymer flooding are determined through the Darcy formula. The method is simple and convenient to operate and reliable in result, and the problem that the reservoir permeability is difficult to measure due to the influence of viscosity after polymer flooding can be solved.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, and specifically to a method for determining the time-varying permeability of polymer flooding reservoirs. Background Technology

[0002] Core and dynamic testing data from loose sandstone reservoirs in the high water-cut period show that geological factors such as reservoir mineral composition, cement type and occurrence, pore-throat structure, crude oil viscosity, and formation temperature have changed significantly compared to the initial development stage. Physical properties of the reservoir rock, such as wettability, porosity, permeability, and oil saturation, continue to change during development, a phenomenon known as reservoir property time-varying. After polymer flooding development, the reservoir has a higher water washing ratio, with a significant increase in the proportion of strong and medium water washing and a decrease in the proportion of unwashed water, making it more difficult to tap the remaining oil potential. Simultaneously, reservoir properties, oil content, and pore structure have all changed considerably, making the mechanism of reservoir parameter changes more complex. Many factors influence reservoir permeability changes: firstly, the scouring effect of the displacement medium; secondly, the interaction between liquid and rock leading to the transformation, dispersion, and migration of clay minerals; and for polymer flooding reservoirs, polymer retention and degradation are also contributing factors to permeability changes. These multiple factors determine the dynamic characteristics of reservoir permeability changes in polymer flooded reservoirs.

[0003] Currently, there are numerous studies on experimental methods and variation patterns of reservoir permeability after long-term waterflooding, mainly using Darcy's law to calculate reservoir permeability. However, there are fewer methods for determining the time-varying reservoir permeability in polymer flooding reservoirs. These methods are affected by changes in polymer solution viscosity and cannot be directly used to determine the reservoir permeability of polymer flooding reservoirs. Therefore, this invention provides a method for studying the time-varying reservoir permeability in polymer flooding reservoirs. Summary of the Invention

[0004] The purpose of this invention is to provide a method for determining the time-varying permeability of polymer flooding reservoirs. This method can simulate the pore throat structure characteristics after polymer flooding to the greatest extent, thereby obtaining the permeability of the porous medium during polymer flooding in a relatively objective manner. It provides certain data support for the numerical simulation of polymer flooding with time-varying reservoir properties under different time and space conditions, and has a guiding role in the formulation of polymer flooding technology schemes.

[0005] The method for determining the time-varying permeability of polymer-assisted oil recovery reservoirs provided by this invention includes the following steps: S1. Determine the time-varying displacement intensity and displacement ratio of reservoir properties in polymer flooding reservoirs; S2. Conduct polymer displacement experiments based on the displacement intensity and displacement ratio determined in step S1; S3. After the displacement pressure stabilizes, inject KCl solution until the pressure stabilizes, and calculate the core permeability and its time-varying parameters after polymer flooding using Darcy's formula.

[0006] In step S1, surface flux is used to characterize the scour intensity at different locations in the polymer flooding oilfield, thereby obtaining the displacement intensity and the displacement ratio.

[0007] In step S2, during the polymer displacement experiment, the displacement flow rate is changed multiple times after a specific displacement flow rate is used to displace the polymer by a corresponding multiple. The displacement flow rate is 0.1 mL / min to 1.0 mL / min, and the corresponding displacement ratio is 20 PV to 3000 PV.

[0008] When conducting polymer displacement experiments, polyacrylamide polymers, such as Aisen polymer (molecular weight 10 million), can be used.

[0009] In step S3, the injection rate of the KCl solution is 0.1~1.0 mL / min, preferably 0.2 mL / min.

[0010] In step S3, the concentration of the KCl solution is 500~2500 mg / L, preferably 2000 mg / L.

[0011] In step S3, the permeability of the core after polymer flooding and its time-varying parameters are calculated using Darcy's formula.

[0012] Compared with the prior art, the present invention has the following beneficial effects: This invention provides a simple and reliable method for determining reservoir permeability after polymer flooding, addressing the challenge of measuring permeability due to viscosity variations. During the displacement intensity switching process, after the polymer flooding pressure stabilizes, a KCl solution is injected at a low rate until the pressure stabilizes again. The time-varying parameters of reservoir permeability after polymer flooding are then determined using the Darcy equation. This invention's method is simple to operate, provides reliable results, and solves the problem of measuring reservoir permeability after polymer flooding due to viscosity variations. Attached Figure Description

[0013] Figure 1 This is a schematic diagram of injection well calculation provided in an embodiment of the present invention (numerical calculation of displacement velocity and displacement ratio).

[0014] Figure 2 This is a schematic diagram showing the injection rate and injection volume at different locations of the oil layer provided in this embodiment of the invention.

[0015] Figure 3 This is a graph showing the variation of displacement pressure and permeability with displacement ratio at a rock sample flooding ratio of 3000 PV, provided in an embodiment of the present invention. Detailed Implementation

[0016] Unless otherwise specified, the experimental methods used in the following examples are conventional methods.

[0017] Unless otherwise specified, all materials and reagents used in the following examples are commercially available.

[0018] Example 1 A block of a certain offshore oilfield was selected to characterize the scouring intensity at different locations in the polymer flooding oilfield by means of surface flux. Surface flux refers to the cumulative volume of fluid passing through a unit cross-sectional area, as shown in equation (1).

[0019] (1) In the formula: M —Surface flux, cm 3 / cm 2 ; Q w —Cumulative injection volume, cm 3 ; A – Pore cross-sectional area, cm² 2 .

[0020] refer to Figure 1 The reservoir production profile is set with radius R and thickness h = 1 m, and fluid flows radially after injection. Taking a reservoir distance of 1 m from the wellbore as an example, the on-site flow rate is 20 m³ / s. 3 / d / m, with an average porosity of 29% and an area of ​​A1 (the side area of ​​a cylinder), the surface flux at this location is calculated according to equation (1). M 1 = 0.0127 cm 3 / cm 2 .

[0021] The injection period is set at 100 days, with an injection volume of 2000 m³ per unit thickness. 3 / m, the pore volume is the pore volume of a cylinder with a reservoir radius of 1 m, and the displacement ratio is calculated to be 2195 PV according to formula (2).

[0022] (2) PV —Injection multiple; Q w —Cumulative injection volume, cm 3 ; A – Pore volume, cm³ 3 .

[0023] refer to Figure 2 Different locations within the reservoir correspond to different injection velocities and injection volumes. Based on this, the flow velocity and displacement ratio of the injected fluid at locations 0.2–10.0 m from the wellbore in the actual reservoir can be calculated, as shown in Table 1.

[0024] Table 1. Calculation of Displacement Rate and Displacement Ratio

[0025] The fluid surface flux in the laboratory core was defined to be the same as that in the actual reservoir to ensure that the time-varying laws of the simulated physical properties were consistent with those in the field. The laboratory core was set with a radius of r = 1.25 cm, and the injected fluid flowed axially perpendicularly. The injection velocity for the simulation experiment was calculated. During the experiment, displacement velocities of 0.1 mL / min, 0.2 mL / min, 0.5 mL / min, and 1.0 mL / min were selected, corresponding to displacement ratios of 20 PV, 80 PV, 500 PV, and 3000 PV, respectively.

[0026] Example 2 This embodiment aims to obtain the curve of core permeability as a function of polymer solution displacement intensity and displacement ratio. The specific steps are as follows: ① Dry the core and measure its basic parameters, including length, diameter, and dry weight.

[0027] ② Vacuum saturate the core with simulated formation water for 24 hours, weigh the wet weight, and calculate the core porosity.

[0028] ③ First, inject 20 PV polymer (Aisen polyacrylamide (molecular weight 10 million) with a viscosity of 58 mPa·s, 65℃) at a flow rate of 0.1 mL / min; then inject 80 PV polymer at a flow rate of 0.2 mL / min; then inject 500 PV polymer at a flow rate of 0.5 mL / min; finally, inject 3000 PV polymer at a flow rate of 1.0 mL / min to end the experiment.

[0029] ④ Before switching between different injection flow rates, after the polymer flooding pressure stabilized, KCl solution (2000 mg / L) was injected at a flow rate of 0.2 mL / min until the pressure basically stabilized. The permeability of the core at different stages was calculated using the Darcy equation. The variation law of permeability measured by KCl solution was used to characterize the time-varying law of polymer flooding permeability.

[0030] refer to Figure 3 The results show that with increasing displacement intensity, the displacement pressure (pressure difference between the two ends of the core) generally increases; at the same displacement intensity, the displacement pressure first increases, then decreases, and finally tends to reach equilibrium with increasing injection ratio. Based on the variation law of displacement pressure, the variation law of permeability is calculated: with increasing polymer displacement ratio, the permeability of the core increases.

Claims

1. A method for time-varying reservoir permeability in polymer-assisted oil recovery reservoirs, comprising the following steps: S1. Determine the time-varying displacement intensity and displacement ratio of reservoir properties in polymer flooding reservoirs; S2. Conduct polymer displacement experiments based on the displacement intensity and displacement ratio determined in step S1; S3. After the displacement pressure stabilizes, inject KCl solution until the pressure stabilizes, and calculate the core permeability and its time-varying parameters after polymer flooding using Darcy's formula.

2. The method according to claim 1, characterized in that: In step S1, surface flux is used to characterize the scour intensity at different locations in the polymer flooding oilfield, thereby obtaining the displacement intensity and the displacement ratio.

3. The method according to claim 1 or 2, characterized in that: In step S2, during the polymer displacement experiment, the displacement flow rate is changed multiple times after a specific displacement flow rate is used to displace the polymer by a corresponding multiple.

4. The method according to claim 3, characterized in that: In step S2, the displacement flow rate is 0.1 mL / min to 1.0 mL / min, and the corresponding displacement factor is 20 PV to 3000 PV.

5. The method according to any one of claims 1-4, characterized in that: In step S3, the injection rate of the KCl solution is 0.1~1.0 mL / min.

6. The method according to any one of claims 1-5, characterized in that: In step S3, the concentration of the KCl solution is 500~2500 mg / L.

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