A method for selecting a profile control and flooding process for controlling bottom water invasion in a jurassic reservoir

Abstract

The application discloses a kind of Jurassic system reservoir control bottom water invasion profile control process selection method, comprising the following steps: S1, first, the cumulative oil production of reservoir, cumulative water production, cumulative injection, geological reserves, crude oil volume coefficient, formation water volume coefficient, comprehensive compression coefficient, crude oil original volume coefficient, formation original pressure and current reservoir pressure data are collected, then the data collected is used to calculate the water invasion amount of block in past years, and curve is drawn;S2, according to the water invasion amount of block in past years and water invasion amount curve trend, select profile control process;S3, according to the profile control process selected in step S2, the well group that needs profile control of Jurassic bottom water reservoir is profile controlled.The application calculates and characterizes the bottom water invasion condition of Jurassic system reservoir, calculates the different states of bottom water reservoir water invasion, and selects different profile control processes according to the different states of bottom water reservoir water invasion, so as to realize the purpose of controlling bottom water invasion and inhibiting water content.

Description

TECHNICAL FIELD

[0001] The application belongs to the technical field of oil exploitation, and particularly relates to a method for selecting a profile control process for controlling bottom water invasion in a Jurassic reservoir. BACKGROUND

[0002] At present, most of the oilfields in China have entered the middle and high water cut stage, and the oil production decreases rapidly after entering the high water cut stage. In these high water cut oilfields, the number of bottom water reservoirs is huge, and the reserves are abundant. In the oil reservoir with bottom water, before the exploitation of the oil reservoir, the water is located at the lower part of the oil layer, and the opening of the upper part of the oil layer will form a hemispherical potential distribution. Due to the influence of the vertical potential gradient, the oil-water contact surface will deform, and the potential gradient along the well axis direction reaches the maximum, forming a water cone. With the increase of oil and gas production speed, the water cone rises continuously, breaks into the well bottom, causes oil-water or gas-water production, and reduces the oil and gas production. This process of vertical advancement of bottom water with oil and gas production is called bottom water coning. Once the bottom water coning occurs, it is very unfavorable for the exploitation of oil and gas reservoirs. Due to the channeling of bottom water into the wellbore, a large amount of water is produced in the oil and gas well, which greatly reduces the oil and gas production, even stops the production of oil and gas, and seriously affects the normal production and benefits of the oil and gas well.

[0003] For the control of bottom water invasion in bottom water reservoirs, at present, mainly through the injection of polymers, oil-water emulsions, foams or air, etc. in the injection well, the viscosity of the water phase is increased to delay the water cone. Search for the selection of profile control process in bottom water reservoirs, find related technologies, and the following three are taken as examples:

[0004] The patent for invention with publication (announcement) No. CN 116066039A discloses a method for oil displacement in a strong bottom water sandstone reservoir in the late stage of high water cut development. The method adopts a double horizontal well injection mixed gas mode, the double horizontal well includes a horizontal injection well and a horizontal oil production well, and the mixed gas includes carbon dioxide and nitrogen. For the reservoir in which water flooding efficiency is the main contradiction and water coning is the secondary contradiction, the bottom horizontal well is used for injection of mixed gas, and the top horizontal well is used for oil production. For the reservoir in which water coning is the main problem and water flooding efficiency is the secondary problem, the top horizontal well is used for injection of mixed gas, and the bottom horizontal well is used for oil production. After effectively controlling the water coning, the oil displacement effect is exerted. First, for the water coning reservoir, the method ignores the size and degree of water coning, and second, the injection pipe column suitable for CO2 needs to be replaced, and the wellbore operation is relatively cumbersome.

[0005] The patent for invention with publication (announcement) No. CN104342095B discloses a self-generating gas expandable foam gel and a preparation method and application thereof. The self-generating gas expandable foam gel can treat the problem of edge and bottom water invasion, but does not involve the subsequent selection of profile control process.

[0006] The patent publication (announcement) No. CN112943162B discloses a method for rapidly densifying the artificial baffle of the gas-water interface of the edge-bottom water gas reservoir, comprising: (1) injecting a water phase monomer solution with a pH value of 10-12 into the gas-water interface, the water phase monomer solution being composed of a water phase monomer and a water phase solvent, and the mass fraction of the water phase monomer being 2-5%; (2) injecting an oil phase monomer solution into the gas-water interface to spread the oil phase monomer solution, and converting the gas-water interface into an oil-water interface, the oil phase monomer solution being composed of a novel oil phase monomer, a spreading agent, nanoparticles and an oil phase solvent, the mass fraction of the novel oil phase monomer being 0.1-1%, the mass fraction of the spreading agent being 0.05-0.1%, and the addition amount of the nanoparticles being 0.01-0.02 g / ml; (3) the water phase monomer in the water layer and the novel oil phase monomer undergo an interfacial polymerization reaction to form a polymer water-blocking layer on the oil-water interface; and (4) under the production pressure difference, impurity particles block the pore throat, crystallization occurs, and a more dense polymer water-blocking layer is formed. The method does not involve the judgment of the water invasion amount of the water body. SUMMARY

[0007] The present application aims to provide a method for selecting a profile control and flooding process for controlling bottom water invasion in a Jurassic reservoir, so as to overcome the above technical defects.

[0008] To achieve the above-mentioned purpose, the technical scheme adopted by the present application is as follows:

[0009] A method for selecting a profile control and flooding process for controlling bottom water invasion in a Jurassic reservoir, comprising the following steps:

[0010] S1, first collect the cumulative oil production, cumulative water production, cumulative injection, geological reserves, crude oil volume coefficient, formation water volume coefficient, comprehensive compression coefficient, crude oil original volume coefficient, formation original pressure and current reservoir pressure data of the reservoir, then calculate the water invasion amount of the block in the past years by using the collected data, and draw a curve of the water invasion amount changing with the development time;

[0011] S2, selecting a profile control and flooding process according to the water invasion amount of the block in the past years and the trend of the water invasion amount curve;

[0012] S3, profile controlling and flooding the well group of the Jurassic bottom water reservoir according to the profile control and flooding process selected in step S2.

[0013] Further, the water invasion amount calculation formula of the block in the past years is:

[0014]

[0015] In the formula:

[0016] W e is the water invasion amount;

[0017] N pN is the cumulative oil production, unit is 10 4 t;

[0018] B o N is the cumulative oil production, unit is 10

[0019] ρ o N is the cumulative oil production, unit is 10 3 ;

[0020] W p N is the cumulative oil production, unit is 10 4 m 3 ;

[0021] B w N is the cumulative oil production, unit is 10

[0022] W i N is the cumulative oil production, unit is 10 4 m 3 ;

[0023] C t N is the cumulative oil production, unit is 10

[0024] N is the cumulative oil production, unit is 10 4 t;

[0025] B oi N is the cumulative oil production, unit is 10

[0026] ΔP is the difference between the original formation pressure and the current reservoir pressure, MPa.

[0027] Further, the cumulative oil production N p is obtained by adding the monthly oil production of each oil well in the reservoir since the start of production.

[0028] Further, the cumulative water production W p is obtained by adding the monthly water production of each oil well in the reservoir since the start of production.

[0029] Further, the cumulative water injection W i is obtained by adding the monthly water injection of each water injection well since the start of production.

[0030] Further, the specific method of selecting the profile control process according to the annual water influx value and water influx curve trend of the block is:

[0031] (1) When the bottom water influx is negative, it indicates that it is a bottom water inhibited block, and polymer microspheres are selected for profile control;

[0032] (2) when the bottom water invasion amount is positive and the water invasion trend changes year by year, it is indicated that the bottom water has invaded the reservoir but has been inhibited, the PEG series gel particles are selected for profile control and flooding, and the liquid production intensity is reduced to continuously slow down the bottom water lifting;

[0033] (3) when the bottom water invasion amount is positive and the water invasion trend changes year by year, it is indicated that the bottom water has invaded the reservoir and the invasion is intensified year by year, the viscoelastic self-regulating agent is selected for profile control and flooding to inhibit the bottom water invasion.

[0034] Preferably, the injection volume concentration of the polymer microspheres is 0.1%-0.15%, and the injection amount is 8-10t.

[0035] Preferably, the particle size of the polymer microspheres is 50-100nm.

[0036] Preferably, the injection volume concentration of the PEG series gel particles is 0.4-0.6%, and the injection amount is 8-10t.

[0037] Preferably, the injection volume concentration of the viscoelastic self-regulating agent is 0.1-0.15%.

[0038] Preferably, the injection amount of the viscoelastic self-regulating agent is 5-6t.

[0039] Preferably, the liquid production intensity is reduced by reducing the stroke and the frequency.

[0040] Compared with the prior art, the present application has the following beneficial effects:

[0041] 1. The present application calculates and characterizes the bottom water invasion state of the Jurassic reservoir, calculates the different states of the bottom water invasion of the reservoir, and selects different profile control and flooding processes according to the different states of the bottom water invasion of the reservoir, so as to realize the purpose of controlling the bottom water invasion and inhibiting water.

[0042] 2. The profile control and flooding process selection method for controlling the bottom water invasion of the Jurassic reservoir provided by the present application is as follows: according to the material balance equation, the water invasion amount in each year is calculated, the bottom water invasion state is judged according to the value and change trend of the water invasion amount, and the profile control and flooding process is selected according to the bottom water invasion state: when the bottom water invasion amount is negative, it is indicated that the bottom water is inhibited in the block, the polymer microspheres are selected for profile control and flooding to effectively improve the water flooding contradiction; when the bottom water invasion amount is positive and the trend changes year by year, it is indicated that the bottom water has invaded the reservoir and has been inhibited year by year, the PEG series gel particles are selected, and the liquid production intensity is reduced to continuously slow down the bottom water lifting; when the bottom water invasion amount is positive and the trend changes year by year, it is indicated that the bottom water has invaded the reservoir and the invasion is intensified year by year, the viscoelastic self-regulating agent is selected to increase the viscosity of the dominant channel and inhibit the bottom water invasion.

[0043] The above description is only a summary of the technical solutions of the present application. In order to more clearly understand the technical means of the present application, and can be implemented in accordance with the content of the specification, the following is a preferred embodiment of the present application and will be described in detail below. BRIEF DESCRIPTION OF DRAWINGS

[0044] In order to more clearly illustrate the technical solutions in the embodiments of the present application, the drawings needed in the embodiments will be briefly introduced as follows. Obviously, the drawings in the following description are only some embodiments of the present application, and for those skilled in the art, other design solutions and drawings can be obtained without creative labor on the basis of these drawings.

[0045] Figure 1 For the comprehensive development curve of Yan 9 reservoir;

[0046] Figure 2 For the water invasion amount of A62 area of Yan 9 reservoir changing with development time;

[0047] Figure 3 For the dynamic curve of PEG profile control well group of A62 Yan 9 reservoir;

[0048] Figure 4 For the comprehensive development curve of Z8 Yan 9 reservoir;

[0049] Figure 5 For the natural decline, comprehensive decline and water cut increase rate change graph of Z8 Yan 9 reservoir over the years;

[0050] Figure 6 For the water invasion amount of Z8 area changing with development time;

[0051] Figure 7 For the water drive control degree, water drive utilization degree and pressure maintenance level change graph of Z8 area over the years

[0052] Figure 8 For the comprehensive development curve of Z8 area;

[0053] Figure 9 For the comprehensive development curve of Yan 10 reservoir;

[0054] Figure 10 For the bottom water contact relationship diagram of X4 area;

[0055] Figure 11 For the water invasion amount of X4 area changing with development time;

[0056] Figure 12 For the dynamic curve of viscoelastic self-regulating agent 4 well group in the northeast of the reservoir.

[0057] In order to make the above objectives, characteristics and advantages of the present application more obvious and easy to understand, the present application will be further described in detail below with reference to the drawings and specific embodiments. DETAILED DESCRIPTION

[0058] The present application can be further understood with regard to the following detailed description of the preferred method of the present application and the examples included herein. Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this application belongs. If there is a conflict between the definitions provided in this specification and those provided in the art to which this application pertains, the definitions provided in this specification control.

[0059] The present application provides a method for selecting a profile control and flooding process for controlling bottom water invasion in a Jurassic reservoir, comprising the following steps:

[0060] S1, first collect cumulative oil production, cumulative water production, cumulative injection, geological reserves, crude oil volume coefficient, formation water volume coefficient, comprehensive compression coefficient, crude oil original volume coefficient, formation original pressure and current reservoir pressure data of the reservoir, then calculate the water invasion amount of the block in previous years using the collected data, and draw a curve of water invasion amount changing with development time, with development time (unit: year) as the horizontal coordinate and water invasion amount (unit: 10 4 m 3 );

[0061] S2, select a profile control and flooding process according to the water invasion amount of the block in previous years and the water invasion amount curve trend;

[0062] S3, profile control and flooding for the well group that needs profile control and flooding in the Jurassic bottom water reservoir according to the profile control and flooding process selected in step S2.

[0063] Further, the water invasion amount calculation formula of the block in previous years is:

[0064]

[0065] In the formula,

[0066] W e is the water invasion amount;

[0067] N p is the cumulative oil production, with the unit of 10 4 t;

[0068] B o is the crude oil volume coefficient;

[0069] ρ o is the density of crude oil, with the unit of t / m 3 ;

[0070] W pN is the cumulative oil production, unit is 10 4 m 3 ;

[0071] B w N is the cumulative water production volume coefficient of the formation;

[0072] W i N is the cumulative injection volume, unit is 10 4 m 3 ;

[0073] C t N is the comprehensive compression coefficient;

[0074] N is the cumulative injection volume, unit is 10 4 t;

[0075] B oi N is the cumulative injection volume, unit is 10

[0076] ΔP is the difference between the original formation pressure and the current reservoir pressure, MPa.

[0077] Further, the cumulative oil production N p is obtained by cumulatively adding the monthly oil production of each oil well in the reservoir since the start of production.

[0078] Further, the cumulative water production W p is obtained by cumulatively adding the monthly water production of each oil well in the reservoir since the start of production.

[0079] Further, the cumulative water injection W i is obtained by cumulatively adding the monthly water injection of each injection well since the start of production.

[0080] Further, the specific method of selecting the profile control process according to the water influx value and water influx curve trend of the block over the years is:

[0081] (1) When the bottom water influx is negative, it indicates that it is a bottom water inhibited block, and polymer microspheres are selected for profile control, which effectively improves the water flooding contradiction; wherein the polymer microspheres can be preferably the name of nanoscale polymer microspheres or polyacrylamide polymer microspheres WQ50N produced by Xi'an Wande Energy Chemical Co., Ltd. for profile control, production batch number is 202308130005;

[0082] (2) When the bottom water invasion amount is a positive value and the water invasion trend changes year by year, it indicates that the bottom water has invaded the reservoir but has been inhibited, and the PEG series gel particles (i.e. polymer elastic gel) are selected for profile control and flooding, and the liquid production intensity is reduced (preferably by reducing the stroke and frequency to achieve), and the bottom water lifting is continuously slowed down; wherein the PEG series gel particles can preferably be PEG-1, a polyacrylamide profile control agent for enhanced oil recovery produced by Gansu Zhongke Polymer Petroleum Technology Co., Ltd., with a production batch number of 202303154004;

[0083] (3) When the bottom water invasion amount is a positive value and the water invasion trend changes year by year, it indicates that the bottom water has invaded the reservoir and the invasion has intensified year by year, and the viscoelastic self-regulating agent is selected for profile control and flooding to increase the viscosity of the dominant channel and inhibit the bottom water invasion. The viscoelastic self-regulating agent can preferably be NT-1, a silicate oil displacement agent for oil production produced by Shaanxi Rixin Petrochemical Co., Ltd., with a production batch number of 202305201008.

[0084] Preferably, the injection volume concentration of the polymer microspheres is 0.1%-0.15%, and the injection amount is 8-10t.

[0085] Preferably, the particle size of the polymer microspheres is 50-100nm.

[0086] Preferably, the injection volume concentration of the PEG series gel particles is 0.4-0.6%, and the injection amount is 8-10t.

[0087] Preferably, the injection volume concentration of the viscoelastic self-regulating agent is 0.1-0.15%, and the injection amount is 5-6t.

[0088] The application will be further described below in conjunction with examples:

[0089] Example 1

[0090] A6 extension 9 reservoir: reference Figure 1 The reservoir was built in 2009, the development layer is extension 9, the average oil layer thickness is 9.9m, the porosity is 17.6%, the permeability is 24.2mD, the oil saturation is 51.5%, the original

[0091] The initial formation pressure is 10.8MPa.

[0092] The reservoir has weakly developed edge and bottom water, and the profile contradiction is prominent after long-term water injection, there are water drive dominant channels, and the water content continues to rise rapidly.

[0093] The cumulative oil production, cumulative water production, cumulative injection, geological reserves, crude oil volume coefficient, formation water volume coefficient, comprehensive compression coefficient, crude oil original volume coefficient, formation original pressure and the data of the reservoir pressure in previous years and the current reservoir pressure of the reservoir are shown in Table 1.

[0094] Using the data in Table 1, the water influx over the years is calculated according to the material balance equation, and the calculation formula is:

[0095]

[0096] In the formula:

[0097] W e is the water influx; N p is the cumulative oil production, with a unit of 10 4 t; B o is the oil volume coefficient; p o is the density of crude oil, with a unit of t / m 3 ; W p is the cumulative water production, with a unit of 10 4 m 3 ; B w is the formation water volume coefficient; W i is the cumulative injection, with a unit of 10 4 m 3 ; C t is the comprehensive compression coefficient; N is the geological reserves, with a unit of 10 4 t; B oi is the original volume coefficient of crude oil; and AP is the difference between the original formation pressure and the current reservoir pressure, MPa.

[0098] Table 1

[0099] According to the calculated water influx value, the water influx curve with the change of formation pressure is drawn, as shown in Figure 2 .

[0100] It can be seen from Figure 2 that the bottom water in the block is relatively developed. In recent years, due to the large liquid production intensity, the bottom water has invaded the reservoir but has been inhibited year by year. At present, the formation pressure is 9.8 MPa, and the water influx reaches 7.37x10 4 m 3 .

[0101] Combined with the bottom water influx, PEG profile control was implemented in March 2021 (the bottom water influx is positive and the trend decreases year by year, indicating that the water influx is controlled year by year, and PEG series gel particles are selected for profile control), and the single well dosage is 8 t. Referring to Figure 3 , after the implementation, the monthly decline is 3.5%-0.9%, the monthly water cut rises by 0.7%-0.4%, the stage less decline of crude oil is 3401 tons, and the profile control effect is remarkable.

[0102] Example 2

[0103] Z8Yan 9 reservoir, referring to Figure 4The reservoir was built in 1997, the development layer is Yan 9, the average oil layer thickness is 13.3 m, the average effective porosity is 19.6%, the air permeability is 33.2*10-3μm2, the permeability is 24.2 mD, and the original formation pressure is 7.65 MPa.

[0104] It can be seen that the bottom water in the middle and western part of the reservoir is developed, and the comprehensive water content continues to rise (88.1%) under the influence of bottom water and injected water, the recoverable reserves recovery degree is high (81.0%), and the water storage rate decreases. Figure 5

[0105] The cumulative oil production, cumulative water production, cumulative injection, geological reserves, crude oil volume coefficient, formation water volume coefficient, comprehensive compression coefficient, crude oil original volume coefficient, formation original pressure and annual and current reservoir pressure data of the reservoir are shown in Table 2.

[0106] Using the data in Table 2, the annual water influx is calculated according to the material balance equation, and the calculation formula is:

[0107]

[0108] In the formula:

[0109] W e is the water influx; N p is the cumulative oil production, unit is 10 4 t; B o is the crude oil volume coefficient; p o is the density of crude oil, unit is t / m 3 ; W p is the cumulative water production, unit is 10 4 m 3 ; B w is the formation water volume coefficient; W i is the cumulative injection, unit is 10 4 m 3 ; C t is the comprehensive compression coefficient; N is the geological reserves, unit is 10 4 t; B oi is the crude oil original volume coefficient; and ΔP is the difference between the original formation pressure and the current reservoir pressure, MPa.

[0110] Table 2

[0111] According to the value of water influx, the water influx curve with formation pressure change is drawn, as shown in Figure 6

[0112] ​​The water invasion amount of Z8 reservoir changes with development time as shown in FIG. 7. The reservoir has been developed for 25 years. With the development process, the liquid production intensity is large, the formation pressure decreases year by year, and the water invasion amount increases year by year. In 2001, it reached the maximum of 91.7x10 4 m 3 After that, due to the strengthening of water injection and suppression of bottom water, the water invasion amount decreases year by year. At present, the formation pressure is 9.2 MPa, the formation pressure remains at 112%, the water invasion amount is negative, and the injected water occupies the dominant position in the production layer.

[0113] From the schematic diagram of water drive degree Figure 8 , it can also be seen that in the past four years, due to the strengthening of water injection, the overall pressure of the reservoir remains at a high level.

[0114] Combined with the bottom water invasion situation, microsphere 100 nm profile control with a concentration of 0.1% was implemented in 2017. Through comprehensive management such as microsphere profile control and injection-production control, the development situation tends to be stable, and the current natural decline is 3.6% and the water cut rise rate is 0.6%.

[0115] Example 3

[0116] X4Yan 10 reservoir, referring to Figure 9 , the development layer is Yan 10, the average oil layer thickness is 9.1 m, the porosity is 16.1%, the air permeability is 16.2 mD, the oil saturation is 48.9%, and it belongs to a low permeability reservoir.

[0117] As shown in Figure 10 , the bottom water is developed in the whole area, the proportion of type I and type II bottom water contact wells is 60.2%, and the interlayer is only developed locally.

[0118] The cumulative oil production, cumulative water production, cumulative injection, geological reserves, crude oil volume coefficient, formation water volume coefficient, comprehensive compression coefficient, crude oil original volume coefficient, formation original pressure and annual and current reservoir pressure data of the reservoir are shown in Table 3.

[0119] Table 3

[0120] Using the data in Table 3, the annual water invasion amount is calculated according to the material balance equation, and the calculation formula is:

[0121]

[0122] In the formula:

[0123] W e is the water invasion amount; N p is the cumulative oil production, which is 10 4 t; B o is the crude oil volume coefficient; For the density of crude oil, unit t / m 3 ; W p For the cumulative water production, unit 10 4 m 3 ; B w For the formation water volume coefficient; W i For the cumulative injection, unit 10 4 m 3 ; C t For the comprehensive compressibility coefficient; N for geological reserves, unit 10 4 t; B oi For the original volume coefficient of crude oil; ΔP for the difference between the original formation pressure and the current reservoir pressure, MPa.

[0124] The curve of reservoir water invasion volume with formation pressure is shown in Figure 11 . The bottom water in this block is relatively developed. In recent years, due to the large liquid production intensity, the water invasion volume is positive and shows an increasing trend year by year, and it is difficult to control water and stabilize oil. At present, the formation pressure is 9.8 MPa, and the water invasion volume reaches 30.73×10 4 m 3 .

[0125] Combined with the bottom water invasion, 10 wells were tested with viscoelastic self-regulating agent from April 2021. Referring to Figure 12 , the daily construction displacement of the well group in the northeast increased from 16 m³ to 26 m³, and the daily oil production increased from 18.5 t to 20.7 t after the test, and the comprehensive water content decreased from 81.6% to 78.7%.

Claims

1. A method for selecting a regulation and drive technology to control bottom water intrusion in Jurassic reservoirs, characterized in that, Includes the following steps: S1. First, collect data on the cumulative oil production, cumulative water production, cumulative injection volume, geological reserves, crude oil volume factor, formation water volume factor, comprehensive compressibility factor, original crude oil volume factor, original formation pressure, and current reservoir pressure of the reservoir. Then, use the collected data to calculate the annual water intrusion of the block and plot the curve of water intrusion changing with development time. S2. Based on the historical water intrusion values ​​and trends of the water intrusion curve in the block, the regulation and drive process is selected. The specific steps are as follows: (1) When the bottom water intrusion is negative, it indicates that the bottom water is suppressed in the block, and polymer microspheres are selected for regulation and driving. (2) When the bottom water intrusion is positive and the water intrusion trend decreases year by year, it indicates that although the bottom water has intruded into the reservoir, it has been suppressed. PEG series gel particles are selected for regulation and displacement, and the production intensity is reduced to continuously slow down the bottom water rise. (3) When the bottom water intrusion is positive and the water intrusion trend increases year by year, it indicates that the bottom water has intruded into the reservoir and the intrusion is intensifying year by year. Select a viscoelastic self-regulating agent for regulation and drive to suppress bottom water intrusion. S3. Perform the adjustment and drive process selected in step S2 on the well groups in the Jurassic bottom water reservoir that require adjustment and drive.

2. The method for selecting a hydraulic displacement process to control bottom water intrusion in Jurassic reservoirs as described in claim 1, characterized in that, In step S1, the formula for calculating the annual water intrusion volume of the block is as follows: In the formula: W e For water intrusion volume; N p Cumulative oil production, in units of 10. 4 t; B o This is the crude oil volume coefficient; ρ o This refers to the density of crude oil, expressed in tons per cubic meter (t / m³). 3 ; W p Cumulative water production, in units of 10. 4 m 3 ; B w This is the formation water volume coefficient; W i This is the cumulative injection amount, in units of 10. 4 m 3 ; C t This is the overall compression coefficient; N represents geological reserves, in units of 10. 4 t; B oi The original volume coefficient of crude oil; ΔP is the difference between the original formation pressure and the current reservoir pressure, in MPa.

3. The method for selecting the regulation and drive technology to control bottom water intrusion in Jurassic reservoirs as described in claim 2, characterized in that: The cumulative oil production N p It is obtained by summing up the monthly oil production of each well in the reservoir since production began; The cumulative water production W p It is obtained by summing up the monthly water production of each oil well in the reservoir since production began; The cumulative water injection volume W i It is obtained by summing up the monthly water injection volume of each injection well since it began production.

4. The method for selecting a hydraulic displacement process to control bottom water intrusion in Jurassic reservoirs as described in claim 1, characterized in that: The injected volume concentration of the polymer microspheres is 0.1%-0.15%, and the injection volume is 8-10t.

5. The method for selecting a hydraulic displacement process to control bottom water intrusion in Jurassic reservoirs as described in claim 1, characterized in that: The polymer microspheres have a particle size of 50-100 nm.

6. The method for selecting the regulation and drive technology to control bottom water intrusion in Jurassic reservoirs as described in claim 1, characterized in that: The injected volume concentration of the PEG series gel particles is 0.4-0.6%, and the injection volume is 8-10t.

7. The method for selecting a regulation and drive process to control bottom water intrusion in Jurassic reservoirs as described in claim 1, characterized in that: The injected volume concentration of the viscoelastic self-regulating agent is 0.1-0.15%.

8. The method for selecting a regulation and drive process to control bottom water intrusion in Jurassic reservoirs as described in claim 1, characterized in that: The amount of viscoelastic self-regulating agent injected is 5-6t.

9. The method for selecting a regulation and drive process to control bottom water intrusion in Jurassic reservoirs as described in claim 1, characterized in that: The reduction in fluid sampling intensity is achieved by adjusting the stroke and the number of strokes.

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