Method for quantitatively characterizing reservoir permeability change after fluid injection development

Abstract

The application discloses a method for quantitatively characterizing reservoir permeability change after fluid injection development, comprising the following steps: step (1), establishing the relationship between reservoir permeability and average pore throat radius; step (2), determining the average particle size of the migrated particles in the reservoir after the fluid injection development; step (3), determining the turning value of the reservoir permeability change after the fluid injection development; step (4), establishing the functional relationship between the reservoir permeability change rate after the fluid injection development and the fluid injection pore volume multiple when the original reservoir permeability is greater than the turning value of the reservoir permeability change after the fluid injection development; step (5), establishing the functional relationship between the reservoir permeability change rate after the fluid injection development and the fluid injection pore volume multiple when the original reservoir permeability is less than or equal to the turning value of the reservoir permeability change after the fluid injection development; and step (6), quantitatively calculating the reservoir permeability after the fluid injection development.

Description

TECHNICAL FIELD

[0001] The present application belongs to the technical field of oilfield development, and particularly relates to a method for quantitatively characterizing the change of reservoir permeability after fluid injection development. BACKGROUND

[0002] The change law of reservoir permeability after fluid injection development is an important research content of fine reservoir description.

[0003] After long-term fluid development such as water injection, steam injection and chemical agent injection in old oilfields such as Daqing and Shengli in China, the reservoir permeability has changed significantly compared with the original permeability, which greatly affects the distribution of remaining oil in the reservoir and has an important influence on the subsequent development effect of the oilfield. Therefore, the quantitative characterization of the change of reservoir permeability after fluid injection development has important guiding significance for optimizing the development adjustment scheme of old oilfields, improving the recovery of old oilfields and improving the development effect of old oilfields.

[0004] At present, in terms of the change of reservoir permeability after water injection development, most people mainly conduct some qualitative research to analyze the change characteristics of reservoir permeability at different development stages.

[0005] In 1996, Deng Yuzhen et al. published an article entitled "Change Law of Reservoir Physical Properties in Water Injection Development Process" in Oil and Gas Recovery Technology. By using coring well data, the change law of reservoir permeability in water injection development process was qualitatively understood by stages and the reasons were analyzed. In 2006, Wu Suying published an article entitled "Change Law of Reservoir Parameters in Long-term Water Injection Scouring and Its Influence on Development Effect" in Daqing Petroleum Geology and Development. Through the study of the change law of formation particles, permeability, pore throat network and wettability in the reservoir at different water cut stages, the influence of reservoir parameter change on development effect was analyzed. In 2021, Xu Wanli et al. published an article entitled "Research on Numerical Simulation Method Based on Pore Network Simulation and Time-varying Reservoir Properties" in Petroleum Engineering Construction. Based on the pore network simulation method, a pore network model of a carbonate rock sample was established. By using micro numerical simulation method, the change law of reservoir wettability and permeability under different water passing multiples was analyzed. The above literatures believe that the reservoir permeability changes after water injection development, and at different water cut stages (initial, medium water cut period, high water cut period and ultra-high water cut period), the permeability has different change laws. Especially in the medium-high water cut development period and the ultra-high water cut development period, due to the continuous scouring of long-term water injection to the reservoir, the reservoir permeability has changed significantly. However, these articles only qualitatively and quantitatively characterize the change law of reservoir permeability at different stages, and do not perform full-process uninterrupted quantitative characterization.

[0006] In order to accurately and quantitatively characterize the change of reservoir permeability after fluid injection development, it is particularly important to establish a reasonable mathematical model. Therefore, we invented a method for quantitatively characterizing the change of reservoir permeability after fluid injection development. SUMMARY

[0007] The purpose of the present application is to provide a method for quantitatively characterizing the change of reservoir permeability after fluid injection development.

[0008] Technical scheme: The method for quantitatively characterizing the change of reservoir permeability after fluid injection development comprises the following steps:

[0009] Step (1), establishing the relationship between the reservoir permeability and the average pore throat radius;

[0010] Step (2), determining the average particle size of the migrated particles in the reservoir after fluid injection development;

[0011] Step (3), determining the change turning point of the reservoir permeability after fluid injection development;

[0012] Step (4), establishing the functional relationship between the change rate of the reservoir permeability after fluid injection development and the fluid injection pore volume multiple when the original reservoir permeability is greater than the change turning point of the reservoir permeability after fluid injection development;

[0013] Step (5), establishing the functional relationship between the change rate of the reservoir permeability after fluid injection development and the fluid injection pore volume multiple when the original reservoir permeability is less than or equal to the change turning point of the reservoir permeability after fluid injection development;

[0014] Step (6), quantitatively calculating the reservoir permeability after fluid injection development.

[0015] Further, in step (1), it comprises:

[0016] (11), obtaining the capillary pressure curve of the reservoir core;

[0017] (12), using the test data of the capillary pressure curve of the reservoir core, establishing the relationship between the reservoir permeability and the average pore throat radius:

[0018] K = f (R m ) (1)

[0019] In the formula:

[0020] K—reservoir permeability, 10 -3 μm 2 ;

[0021] R m —reservoir average pore throat radius, μm.

[0022] Further, the oil reservoir core capillary pressure curve in step (11) is obtained by any one of the following methods:

[0023] a. mercury injection method;

[0024] b. centrifugal method.

[0025] Further, in step (12), the specific expression of the relationship between the oil reservoir permeability and the average pore throat radius is as follows:

[0026]

[0027] In the formula:

[0028] K—reservoir permeability, 10 -3 μm 2 ;

[0029] R m —reservoir average pore throat radius, μm;

[0030] a, b—undetermined coefficients (i.e. different constants obtained by fitting regression).

[0031] Further, the specific steps of step (2) are as follows:

[0032] Through the core fluid injection scouring experiment, the size of the reservoir particles flushed out in the core outlet liquid is statistically analyzed to determine the average particle size of the migrated particles in the reservoir after the oil reservoir fluid injection development.

[0033] Further, in step (3), the average particle size of the migrated particles in the reservoir after the oil reservoir fluid injection development obtained in step (2) is substituted into the relationship between the oil reservoir permeability and the average pore throat radius established in step (1), i.e. the oil reservoir permeability change turning point after the oil reservoir fluid injection development is obtained.

[0034] Further, in step (4), through the core fluid injection scouring experiment, the functional relationship between the reservoir permeability change rate after fluid injection and the fluid injection pore volume multiple is established when the original reservoir permeability is greater than the oil reservoir permeability turning point after the oil reservoir fluid injection development, i.e.:

[0035] When K o >K t ,

[0036] K r =f(PV) (2)

[0037] Wherein

[0038]

[0039] In the formula:

[0040] K t —reservoir permeability after fluid injection, 10 -3 μm 2 ;

[0041] K r —reservoir permeability change rate after fluid injection, dimensionless;

[0042] PV—fluid injection pore volume multiple, dimensionless;

[0043] K i —reservoir permeability after fluid injection, 10 -3 μm 2 ;

[0044] K o —original reservoir permeability, 10 -3 μm 2 .

[0045] Further, when the original reservoir permeability is greater than the reservoir permeability after fluid injection turning point value, the reservoir permeability change rate K r after fluid injection and the fluid injection pore volume multiple PV between the functional relationship of the specific expression is:

[0046] K r = e clnPV+d (2a)

[0047] In the formula:

[0048] K r —reservoir permeability change rate after fluid injection, dimensionless;

[0049] PV—fluid injection pore volume multiple, dimensionless;

[0050] c, d—undetermined coefficients (i.e. different constants obtained by fitting regression).

[0051] Further, in step (5), by core fluid injection scouring experiment, the function relationship between the reservoir permeability change rate after fluid injection and the fluid injection pore volume multiple when the original reservoir permeability is less than or equal to the reservoir permeability after fluid injection turning point value is established, that is:

[0052] When K o ≤ K t ,

[0053] K r = f(PV) (4)

[0054] Where

[0055]

[0056] wherein:

[0057] K t - the reservoir permeability turning point after fluid injection, 10 -3 μm 2 ;

[0058] K r - the reservoir permeability change rate after fluid injection, dimensionless;

[0059] PV - the fluid injection pore volume multiple, dimensionless.

[0060] K i - the reservoir permeability after fluid injection, 10 -3 μm 2 ;

[0061] K o - the original reservoir permeability, 10 -3 μm 2 .

[0062] Further, when the original reservoir permeability is less than or equal to the reservoir permeability turning point after fluid injection, the specific expression of the functional relationship between the reservoir permeability change rate after fluid injection and the fluid injection pore volume multiple is

[0063] K r = e mlnPV+n (4a)

[0064] wherein:

[0065] K r - the reservoir permeability change rate after fluid injection, dimensionless;

[0066] PV - the fluid injection pore volume multiple, dimensionless.

[0067] m, n - undetermined coefficients (i.e. different constants obtained by fitting regression).

[0068] Further, in step (6), by respectively establishing the relationship between the reservoir permeability change rate after fluid injection and the fluid injection pore volume multiple when the original reservoir permeability is greater than the reservoir permeability change turning point, and

[0069] the relationship between the reservoir permeability change rate after fluid injection and the fluid injection pore volume multiple when the original reservoir permeability is less than or equal to the reservoir permeability change turning point, the reservoir permeability after fluid injection is quantitatively calculated, and the calculation formula is as follows

[0070] K i = Ko XK r (5), wherein

[0071] K i reservoir permeability after fluid injection development, 10 -3 μm 2 ;

[0072] K o reservoir original permeability, 10 -3 μm 2 ;

[0073] K r reservoir permeability change rate after fluid injection development.

[0074] Beneficial effects: The oil reservoir fluid injection development reservoir permeability change quantitative characterization method disclosed by the application has the following beneficial effects:

[0075] 1. By studying the dynamic change process law of different reservoir permeabilities with the deepening of oil reservoir fluid injection development degree, a mathematical model for quantitatively describing and characterizing the whole process dynamic change of reservoir permeability is established, so as to realize the whole process high-precision quantitative mathematical characterization of reservoir permeability change after oil reservoir fluid injection development;

[0076] 2. It lays a foundation for oil reservoir engineering calculation, water flooding oil theory and derivation of oil reservoir numerical simulation calculation method, can accurately predict the oil reservoir fluid injection development effect and trend, has important guiding significance for optimizing old oilfield development adjustment scheme, improving old oilfield recovery rate and improving old oilfield development effect. BRIEF DESCRIPTION OF DRAWINGS

[0077] Figure 1 is a flow chart of the oil reservoir fluid injection development reservoir permeability change quantitative characterization method disclosed by the application;

[0078] Figure 2 is a schematic diagram of the relationship between the oil reservoir permeability and the average pore throat radius in Example 1.

[0079] Figure 3 is a schematic diagram of the relationship between the reservoir permeability change rate after fluid injection development and the fluid injection pore volume multiple when the reservoir original permeability is greater than the reservoir permeability change turning value in Example 1 of the application.

[0080] Figure 4 is a schematic diagram of the relationship between the reservoir permeability change rate after fluid injection development and the fluid injection pore volume multiple when the reservoir original permeability is less than or equal to the reservoir permeability change turning value in Example 1 of the application. DETAILED DESCRIPTION

[0081] The specific embodiments of the application are described in detail below.

[0082] At present, in the aspect of reservoir permeability change after water injection development, most people mainly carry out some qualitative research, and analyze the reservoir permeability change characteristics in different development periods. However, the research analysis and method only qualitatively characterize the reservoir permeability change rule in stages, and do not quantitatively characterize the whole process without interruption, so that the effect and trend after the oil reservoir fluid injection development cannot be accurately predicted.

[0083] In view of the above problems of the prior art, the present application discloses a method for quantitatively characterizing the change of reservoir permeability after fluid injection development, comprising the following steps:

[0084] Step (1), establishing the relationship between the reservoir permeability and the average pore throat radius;

[0085] Step (2), determining the average particle size of the migrated particles in the reservoir after the fluid injection development of the oil reservoir;

[0086] Step (3), determining the reservoir permeability change turning point after the fluid injection development of the oil reservoir;

[0087] Step (4), establishing the functional relationship between the reservoir permeability change rate after the fluid injection development and the fluid injection pore volume multiple when the original reservoir permeability is greater than the reservoir permeability change turning point after the fluid injection development of the oil reservoir;

[0088] Step (5), establishing the functional relationship between the reservoir permeability change rate after the fluid injection development and the fluid injection pore volume multiple when the original reservoir permeability is less than or equal to the reservoir permeability change turning point after the fluid injection development of the oil reservoir;

[0089] Step (6), quantitatively calculating the reservoir permeability after the fluid injection development of the oil reservoir.

[0090] Among them:

[0091] The "reservoir original permeability" in step (3) is calculated by using the core analysis data, and is represented by Ko;

[0092] The core fluid injection scouring experiment in step (4) is mainly to measure the relationship between the core permeability (reservoir permeability Ki after fluid injection development) and the injected fluid pore volume multiple PV, wherein:

[0093] The reservoir permeability change rate K after fluid injection development r = reservoir permeability Ki after fluid injection development / reservoir original permeability Ko, and Ko represents the reservoir original permeability.

[0094] The method for quantitatively characterizing the change of reservoir permeability after fluid injection development of the oil reservoir quantitatively characterizes the change law of reservoir permeability after long-term fluid injection development of the oil reservoir, lays a foundation for derivation of oil reservoir engineering calculation, water drive oil theory and numerical simulation calculation method of the oil reservoir, can accurately predict the development effect and trend of the oil reservoir after fluid injection development, and has important guiding significance for optimizing the development adjustment scheme of the old oilfield, improving the recovery of the old oilfield and improving the development effect of the old oilfield.

[0095] Embodiment 1

[0096] The core of the A block of Shengli Oilfield is analyzed to obtain a series of test data, and the quantitative characterization of the change of reservoir permeability after fluid injection development of the oil reservoir is carried out.

[0097] As shown in Figure 1 , the method for quantitatively characterizing the change of reservoir permeability after fluid injection development of the oil reservoir comprises the following specific steps:

[0098] Step (1), establishing the relationship between the reservoir permeability and the average pore throat radius:

[0099] (11), obtaining the capillary pressure curve of the reservoir core;

[0100] (12), using the test data of the capillary pressure curve of the reservoir core to establish the relationship between the reservoir permeability and the average pore throat radius.

[0101] Further, the capillary pressure curve of the reservoir core in step (11) is obtained by the mercury injection method.

[0102] The test data of the capillary pressure curve of the reservoir core are shown in the following table:

[0103] Sample No. Permeability, 10 -32 ]] Average pore throat radius, pm 7 2050 14.790 8 3670 16.650 16 401 4.246 20 1520 8.670 21 2490 12.890 28 1100 4.843 31 1510 5.060 32 1800 11.500 33 5100 19.070 39 300 4.614 52 5770 18.550 60 1650 7.989 70 5010 16.160 72 1340 10.430 74 8790 21.990 75 4540 13.000 76 1470 10.310 79 1350 9.519 83 1240 8.915 85 1690 8.222 87 908 7.346 88 1150 10.290

[0104] The above test data are entered into the double natural logarithmic coordinates, and specifically as shown in Figure 2 , it can be seen that the reservoir permeability has a good linear relationship with the average pore throat radius of the reservoir, and therefore the relationship between the reservoir permeability and the average pore throat radius is established by fitting:

[0105] K=e 1.5360lnRm+3.9658 R 2 =0.7864 (1a)

[0106] In the formula:

[0107] K- the reservoir permeability, 10 -3 μm 2 ;

[0108] R m - the average pore throat radius of the reservoir, μm.

[0109] Step (2), determining the average particle size of the migrated particles in the reservoir after the reservoir is developed by fluid injection:

[0110] The particle size distribution range of the flushed reservoir particles is determined by statistical analysis of the particle size of the flushed reservoir particles in the core outlet fluid in the core water injection scouring experiment, and then the average particle size of the flushed reservoir particles after the reservoir is developed by fluid injection is determined

[0111] The average particle size r of the flushed reservoir particles after the reservoir is developed by fluid injection is determined by experimental measurement m = 1.306 μm.

[0112] Step (3), determining the turning value of the reservoir permeability change after the reservoir is developed by fluid injection:

[0113] The average particle size r of the migrated particles in the reservoir after the reservoir is developed by fluid injection obtained in step (2) m = 1.306 μm is substituted into the relationship K = e 1.5360lnRm+3.9658 established in step (1) between the reservoir permeability and the average pore throat radius, i.e. m = r m = 1.306 μm, to obtain the turning value K of the reservoir permeability change after the reservoir is developed by fluid injection t , i.e. t = 79.5 x 10 -3 μm 2 .

[0114] In the reservoir, the reservoir permeability is different at different positions, and the corresponding average pore throat radius is also different. In the part of the reservoir where the average pore throat radius is greater than the average particle size r of the flushed reservoir particles m , the average pore throat radius of the reservoir will become larger and larger, and the reservoir permeability will also become larger and larger; and in the part of the reservoir where the average pore throat radius is less than or equal to the average particle size r of the flushed reservoir particles m , the average pore throat radius of the reservoir will become smaller and smaller due to the plugging of the previous flushed reservoir particles, and the reservoir permeability will also become smaller and smaller, so there is a turning value K of the reservoir permeability change corresponding to the average particle size of the flushed reservoir particles in the reservoir. t

[0115] Step (4), establishing the functional relationship between the reservoir permeability change rate and the fluid injection pore volume multiple after the reservoir is developed by fluid injection when the original reservoir permeability is greater than the turning value of the reservoir permeability change after the reservoir is developed by fluid injection:

[0116] The functional relationship between the reservoir permeability change rate K o and the fluid injection pore volume multiple after the reservoir is developed by fluid injection when the original reservoir permeability K t is greater than the turning value K r of the reservoir permeability change after the reservoir is developed by fluid injection is established by the core fluid injection scouring experiment.The function relationship between the reservoir permeability change rate K and the fluid injection pore volume multiple PV is:

[0117] When K o > K t , the reservoir permeability change rate K r is greater than zero, and the function relationship between the reservoir permeability change rate K and the fluid injection pore volume multiple PV is: Figure 3

[0118] K r = e 0.0153lnPV+1.0128 R2=0.7051 (2a)

[0119] wherein

[0120]

[0121] In the formula:

[0122] K r is the reservoir permeability change rate after fluid injection development, and is dimensionless;

[0123] PV is the fluid injection pore volume multiple, and is dimensionless;

[0124] K i is the reservoir permeability after fluid injection development, and is 10 -3 μm 2 ;

[0125] K o is the original reservoir permeability, and is 10 -3 μm 2 ;

[0126] Step (5), the function relationship between the reservoir permeability change rate after fluid injection development and the fluid injection pore volume multiple when the original reservoir permeability is less than or equal to the reservoir permeability change turning value after fluid injection development:

[0127] Through the core fluid injection scouring experiment, the function relationship between the reservoir permeability change rate K o and the fluid injection pore volume multiple PV when the original reservoir permeability K t is less than or equal to the turning value K r is established: Figure 3

[0128] When K o ≤ K t , the reservoir permeability change turning value K r after fluid injection development and the natural logarithm of the fluid injection pore volume multiple PV also have a linear relationship (as shown in Figure 4 ), and the following can be obtained:

[0129] K​​r = e -0.1264lnPV+1.6122 R 2 = 0.9014 (4a)

[0130] wherein

[0131]

[0132] (6) Quantitative calculation of reservoir permeability change after fluid injection development by establishing reservoir original permeability K o greater than and less than or equal to the reservoir permeability change turning point K t , the relationship between the reservoir permeability change rate K r and the fluid injection pore volume multiple PV, and quantitative calculation of reservoir permeability after fluid injection development:

[0133]

[0134] According to the above steps, the quantitative calculation and characterization of the reservoir permeability change after fluid injection development in the A block of Shengli Oilfield are realized. The quantitative characterization method of reservoir permeability change after fluid injection development can greatly improve the characterization accuracy of reservoir permeability change after fluid injection development compared with the traditional method, and lays a foundation for reservoir engineering calculation, water flooding theory and derivation of numerical simulation calculation method. It can accurately predict the effect and trend of oil reservoir fluid injection development, and has important guiding role for oilfield development and production practice.

[0135] Example 2

[0136] The same as example 1, the only difference is that the reservoir core capillary pressure curve in step (11) is obtained by centrifugal method.

[0137] The above describes the embodiments of the present application in detail. However, the present application is not limited to the above embodiments, and various changes can be made within the knowledge of those skilled in the art without departing from the spirit of the present application.

Claims

1. A method for quantitatively characterizing the change in reservoir permeability after fluid injection development of an oil reservoir, characterized in that, The method comprises the following steps: Step (1), establishing the relationship between the reservoir permeability and the average pore throat radius; Step (2), determining the average particle size of the migrated particles in the reservoir after fluid injection; Step (3), determining the turning point of the reservoir permeability change after fluid injection; Step (4), establishing the functional relationship between the reservoir permeability change rate and the fluid injection pore volume multiple after fluid injection when the original reservoir permeability is greater than the turning point of the reservoir permeability change after fluid injection; Step (5), establishing the functional relationship between the reservoir permeability change rate and the fluid injection pore volume multiple after fluid injection when the original reservoir permeability is less than or equal to the turning point of the reservoir permeability change after fluid injection; Step (6), quantitatively calculating the reservoir permeability after fluid injection, wherein: The specific steps of step (2) are as follows: Through core fluid injection scouring experiment, the particle size of the reservoir particles flushed out in the core outlet liquid is statistically analyzed to determine the average particle size of the migrated particles in the reservoir after fluid injection; In step (3), the average particle size of the migrated particles in the reservoir after fluid injection obtained in step (2) is substituted into the relationship between the reservoir permeability and the average pore throat radius established in step (1) to obtain the turning point of the reservoir permeability change after fluid injection.

2. The method of quantitative characterization of reservoir permeability changes after the development of the oil deposit by injection of fluids as claimed in claim 1, characterized in that, In step (1), the following steps are included: (11), obtaining the core capillary pressure curve of the reservoir; (12), using the test data of the core capillary pressure curve of the reservoir to establish the relationship between the reservoir permeability and the average pore throat radius: K = f(R m ) (1) In the formula: K - reservoir permeability, 10 -3 μm 2 ; R m —reservoir average pore throat radius, μm.

3. The method of quantitative characterization of reservoir permeability changes after the reservoir fluid injection development of claim 2, wherein, The core capillary pressure curve of the reservoir in step (11) is obtained by any one of the following methods: a, mercury injection method; b, centrifugal method.

4. The method of quantitative characterization of reservoir permeability changes after the reservoir fluid injection development of claim 2, wherein, In step (12), the specific expression of the relationship between the reservoir permeability and the average pore throat radius is as follows: In the formula: K - reservoir permeability, 10 -3 μm 2 ; R m —reservoir average pore throat radius, μm; a, b - undetermined coefficients.

5. The method according to claim 1, wherein the method is characterized by, In step (4), through core fluid injection scouring experiment, the functional relationship between the reservoir permeability change rate and the fluid injection pore volume multiple after fluid injection is established when the original reservoir permeability is greater than the turning point of the reservoir permeability change after fluid injection, that is: When K o > K t , K r = f(PV) (2) In the formula: PV - fluid injection pore volume multiple, dimensionless; K t - Reservoir permeability break point after fluid injection development, 10 -3 μm 2 ; K r — the rate of change of reservoir permeability after the injection fluid is developed, dimensionless; In the formula: K i Reservoir permeability after injection fluid development, 10 -3 μm 2 ; K o Reservoir original permeability, 10 -3 μm 2 .

6. The method of quantitative characterization of reservoir permeability changes after the development of the oil deposit by injection of fluids as claimed in claim 5, characterized in that, When the reservoir original permeability is greater than the reservoir permeability turning point value after the reservoir is developed by injecting fluid, the reservoir permeability change rate K r The specific expression of the functional relationship between the fluid injection pore volume multiple PV and the reservoir permeability change rate K is: K r = e clnPV+d (2a) PV - fluid injection pore volume multiple, dimensionless; K r — the rate of change of reservoir permeability after the injection fluid is developed, dimensionless; c, d - undetermined coefficients. In step (5), through core fluid injection scouring experiment, the functional relationship between the reservoir permeability change rate and the fluid injection pore volume multiple after fluid injection is established when the original reservoir permeability is less than or equal to the turning point of the reservoir permeability change after fluid injection, that is:

7. The method according to claim 1, wherein the method is characterized by, In the formula: When K o ≤ K t , K r = f(PV) (4) PV - fluid injection pore volume multiple, dimensionless; When the original reservoir permeability is less than or equal to the turning point of the reservoir permeability change after fluid injection, the specific expression of the functional relationship between the reservoir permeability change rate and the fluid injection pore volume multiple after fluid injection is K t - Reservoir permeability break point after reservoir fluid injection development, 10 -3 μm 2 ; K r — the rate of change of reservoir permeability after the injection fluid is developed, dimensionless; In the formula: K i Reservoir permeability after fluid injection, 10 -3 μm 2 ; K o Reservoir original permeability, 10 -3 μm 2 .

8. The method of quantitative characterization of reservoir permeability changes after the reservoir fluid injection development of claim 7, wherein, PV - fluid injection pore volume multiple, dimensionless; K r = e mlnPV+n (4a) m, n - undetermined coefficients. K r — the rate of change of reservoir permeability after the injection fluid is developed, dimensionless; ​ ​ 9. The method according to claim 1, wherein the method is characterized by, In step (6), the relationship between the reservoir permeability change rate after fluid injection and the pore volume multiple of fluid injection is established when the reservoir original permeability is greater than the reservoir permeability change turning point, and the relationship between the reservoir permeability change rate after fluid injection and the pore volume multiple of fluid injection is established when the reservoir original permeability is less than or equal to the reservoir permeability change turning point. The reservoir permeability after fluid injection is quantitatively calculated, and the calculation formula is as follows K i = K o x K r (5), where K i Reservoir permeability after fluid injection, 10 -3 μm 2 ; K o Reservoir original permeability, 10 -3 μm 2 ; K r - Rate of change of reservoir permeability after injection fluid development.

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