Method and device for predicting displacement injection pressure of shale oil reservoir nano agent

Abstract

The invention discloses a shale oil reservoir nano agent displacement injection pressure prediction method and device, and belongs to the technical field of oil reservoir development. The injection pressure is predicted according to a starting pressure gradient method, the injection pressure is predicted according to a production quantity equivalent method formula and an improved starting pressure gradient experimental device, mutual verification is carried out, and an important basis is provided for shale oil continuous displacement development feasibility. According to the method, in shale oil and shale oil sustainable development mode optimization, the injection pressure serving as a key factor of displacement feasibility is predicted, oil reservoir energy is supplemented through nano-agent displacement, the oil displacement efficiency and the recovery efficiency of unconventional oil reservoirs such as shale oil and shale oil are improved, and if the predicted injection pressure can be achieved on site, the prediction of the injection pressure can be achieved on site. The method is of great significance to determination of economic recoverable reserves of unconventional oil reservoirs, determination of sweet spot areas, improvement of single well EUR and improvement of oil reservoir recovery efficiency.

Description

Technical Field

[0001] The invention belongs to the technical field of oil reservoir development, and in particular relates to a method and a device for predicting the injection pressure of nano-agent displacement in a shale oil reservoir. Background Art

[0002] According to the National Standardization Administration Document

[2019] No. 22, the draft standard for "Shale Oil Geological Evaluation Methods" was initially formed in July 2019: "Shale oil refers to petroleum that is stored in organic-rich shale formations. The thickness of a single layer of siltstone, fine sandstone, and carbonate rock in the source rock of the organic-rich shale formation is no more than 5m, and the cumulative thickness accounts for less than 30% of the total thickness of the shale formation. There is no natural production capacity or it is below the lower limit of industrial oil production, and special process and technical measures are required to obtain industrial oil production."

[0003] my country is rich in shale oil resources. In 2014, the technically recoverable shale oil resources of the national oil and gas resource evaluation reached 203×108t. It is estimated that the technically recoverable shale oil resources in China are 43.93×108t, accounting for about 6% of the world, ranking third in the world. Shale oil is the most important replacement resource for my country's future oil exploration and development, mainly distributed in Songliao, Ordos, Sichuan, Junggar and other basins. In 2016, PetroChina evaluated the technically recoverable shale oil resources of the country to be 145×108t. Comprehensively evaluated the national continental medium-to-high maturity shale oil resources of about 200×108t, which is higher than the previous estimate. China has made important progress in the exploration and technology of continental shale oil, but generally speaking, it is still in the exploratory stage. On October 31, 2022, CNPC proposed in its Guiding Opinions on Strengthening Shale Oil and Gas Exploration and Development (CNPC Office

[2022] 215) to focus on promoting the exploration, evaluation and development of shale oil and gas such as Chang 7 shale oil, Gulong shale oil, Jimusar shale oil, southern Sichuan deep shale gas, Sichuan Jurassic shale oil, and Qaidam shale oil.

[0004] Due to the dense physical properties of shale oil reservoirs, extremely low natural production capacity, usually no edge water gas cap, limited elasticity and dissolved gas energy, energy storage volume fracturing has become the main technology for economical and effective development. However, its energy is a one-time investment, followed by continuous production, which is similar to throughput, and is a process of continuous energy exhaustion. Therefore, there is a low upper limit for recovery, generally not exceeding 12%. In order to improve the recovery rate, more than 10 types of follow-up development methods have been studied and partially tested, including repeated fracturing, water flooding, water injection and huffing, carbon dioxide flooding, carbon dioxide huffing and puffing, and chemical flooding. However, it is mostly used in low-permeability and ultra-low-permeability reservoirs. For shale oil reservoirs with a permeability of less than 0.3mD, water injection and huffing, continuous water flooding, and experimental gas injection are mainly used, but a mature and popular follow-up development method has not yet been formed.

[0005] The results of displacement and imbibition experiments of shale oil and ultra-low permeability III show that the displacement efficiency is close to that of imbibition, and the movable reserves of imbibition are limited to artificial fractures and connected natural fractures, which are close to the movable reserves of water drive before the fractures are closed, that is, the swept volume coefficient is similar. Therefore, shale oil displacement can not only realize the continuous replenishment of formation energy, but also help to reduce the decline rate of crude oil production and improve the recovery rate. The main difficulty is whether it can achieve normal pressure injection, so the accurate prediction of injection pressure is very important. Summary of the invention

[0006] In order to solve the above problems, the present invention proposes: a method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs, which predicts the injection pressure according to the production equivalent method, and the production equivalent method calculates the injection wellhead pressure according to the actual production data and formula;

[0007] The injection pressure is predicted according to the starting pressure gradient method, which predicts the injection pressure based on the reservoir core experimental data or correlation calculation data and the injection-production connection distance.

[0008] Based on the production equivalent formula and the improved start-up pressure gradient experimental device, the injection pressure is predicted and verified with each other, providing an important basis for the feasibility of shale oil follow-up displacement development.

[0009] Furthermore, the injection pressure prediction formula and process of the production equivalent method are as follows: the wellhead injection pressure predicted by the start-up pressure gradient is corrected by using the production data according to the production equivalent method, and the water injection volume and injection pressure are converted according to the reservoir seepage principle, the liquid production and the corresponding production pressure difference:

[0010] Q inj =Q L ×(P inj +0.01h w -P res ) / (P res -P f )

[0011] P inj =Q inj *(P res -P f ) / Q L +P res -0.01h w

[0012] In the formula, Q inj , daily water injection volume, m 3 / d;Q L , daily liquid output, m 3 / d;P inj , wellhead injection pressure, MPa; P res, corresponding to the average reservoir pressure at that time, MPa; P f , bottom flow pressure of production well, MPa; h w , depth of horizontal section from wellhead, m.

[0013] For oil wells lacking measured pressure data, the initial data of blowdown are used. At that time, the data of wellhead pressure and production are complete. The formation pressure is calculated based on the pressure storage material balance equation. After the well is soaked, the pressure data is consistent with the actual situation. The multiphase fluid pressure of the tubing string is estimated based on the water content, production gas-oil ratio and whether sand is produced.

[0014] Furthermore, the prediction process of injection-production connection distance and injection pressure under the starting pressure gradient data and fracturing conditions is as follows: At present, the pressure difference-flow method is used to measure the starting pressure gradient of single-phase fluid. This method obtains the pseudo starting pressure gradient in the engineering sense by fitting the pressure gradient curve. According to the pressure difference-flow method, the crude oil starting pressure gradient measurement experiment process is divided into the following steps:

[0015] ① Dry the core for 24 hours and then measure the basic parameters of the core;

[0016] ② Place the core in a holder and evacuate it while saturating it with oil. After aging for 24 hours, determine the core pore volume based on the core weight difference before and after saturation with oil.

[0017] ③ Connect the instrument, making sure that the pressure in the pressure vessel is one atmosphere at the experimental temperature;

[0018] ④ Use a hand pump to slightly compress the gas volume in the pressure vessel, and after the pressure stabilizes, use a high-precision differential pressure sensor and a micro-flow metering device to measure the pressure difference at both ends of the core and the flow rate at the outlet;

[0019] ⑤Gradually and slowly increase the pressure of the gas in the pressure vessel, and read the corresponding values ​​after the pressure difference and flow rate are basically stable;

[0020] ⑥Process the data, draw the crude oil seepage curve and determine the crude oil starting pressure gradient.

[0021] Furthermore, based on the start-up pressure gradient measured in the above experiment, it is proposed to establish the relationship between the single-phase and two-phase start-up pressure gradient and the reservoir permeability, which is a power function relationship with high correlation:

[0022] D p =aK -b

[0023] Where D p , starting pressure gradient, MPa / m; K, reservoir permeability, mD, a, b, correlation coefficient.

[0024] The correlation can be applied to calculate the starting pressure gradient of different reservoirs without coring and analysis, saving cost and time.

[0025] Furthermore, after determining the starting pressure gradient, the nano-agent injection wellhead pressure in unconventional oil reservoirs can be predicted by the following formula:

[0026] P inj =D p ×L+P f -0.01h w

[0027] Where, L is the distance outside the effective fracturing radius between injection and production wells in unconventional oil reservoirs, m; P inj , wellhead injection pressure, MPa; P f , bottom flow pressure of production well, MPa; h w , vertical depth of the injection-production section from the wellhead, m; Dp, starting pressure gradient determined by the formula based on reservoir permeability, MPa / m.

[0028] Furthermore, the injection pressure at the water injection wellhead can be predicted by the following steps:

[0029] ① Determine the reservoir permeability of the injection layer of the water injection well from the well logging curve or experimental analysis;

[0030] ② According to whether the water injection well is a new well or an old oil well before it is converted to an injection well, select the single-phase or oil-water two-phase starting pressure gradient correlation formula to obtain the starting pressure gradient value;

[0031] ③ According to the monitoring results of the injection-production well fracture length or the numerical model prediction results and the well spacing, determine the remaining distance for injection-production connection;

[0032] ④ Predict the injection well bottom pressure based on the injection-production distance, start-up pressure gradient, oil well bottom pressure, and formation pressure at the bottom of the oil well fracture;

[0033] ⑤ Predict the injection wellhead pressure based on the injection well bottom pressure, wellbore friction loss, head pressure, etc.

[0034] A shale oil reservoir nano-agent displacement injection pressure prediction device comprises a hand pump, a pressure vessel, an isolation container, a displacement container and a constant speed and pressure pump. The hand pump, the pressure vessel, the isolation container, the displacement container and the constant speed and pressure pump are connected in sequence, and a constant temperature box is connected to the displacement container.

[0035] Furthermore, the start-up pressure gradient experimental device was improved as follows: the core holder was placed in a constant temperature box to better simulate the reservoir temperature and improve the accuracy of the experimental data.

[0036] Furthermore, the start-up pressure gradient experimental device was improved as follows: a micro flow meter and a differential pressure sensor were connected to the core holder, and the micro flow meter and the differential pressure sensor were connected to a computer to more accurately control the experimental process, adjust the flow and pressure, and measure the experimental results.

[0037] The beneficial effect of the present invention is that the technical solution described in the present invention solves the problem of predicting the injection pressure, a key factor in the feasibility of displacement, in the optimization of sustainable development methods for shale oil and shale oil. Studies have shown that nano-agent displacement can effectively supplement reservoir energy and significantly improve the oil displacement efficiency and recovery rate of unconventional oil reservoirs such as shale oil and shale oil. If the predicted injection pressure can be achieved on site, it is of great significance for determining the economically recoverable reserves of unconventional oil reservoirs, identifying "sweet spot" areas, improving the EUR of single wells, and improving the recovery rate of oil reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0038] Figure 1 It is a schematic diagram of the starting pressure gradient experimental device of the present invention;

[0039] Figure 2 The experimental results and fitting curves of the pressure gradient and seepage velocity of single-phase and two-phase fluids of the present invention are Figure 1 ; In the figure: a. Experimental data of start-up pressure gradient of single-phase fluid in ultra-low permeability reservoir and regression curve of long 2 oil layer. Abscissa, pressure gradient (MPa / m); ordinate, seepage velocity ml / min.

[0040] Figure 3 The experimental results and fitting curves of the pressure gradient and seepage velocity of single-phase and two-phase fluids of the present invention are Figure 2 , In the figure: b shale oil reservoir single-phase fluid start-up pressure gradient experimental data and regression curve long 7 oil layer. Abscissa, pressure gradient (MPa / m); ordinate, seepage velocity ml / min.

[0041] Figure 4 The experimental results and fitting curves of the pressure gradient and seepage velocity of single-phase and two-phase fluids of the present invention are Figure 3 , Figure: c Ultra-low permeability reservoir single-phase fluid start-up pressure gradient experimental data and regression curve Long 8 oil layer. Abscissa, pressure gradient (MPa / m); ordinate, seepage velocity ml / min.

[0042] Figure 5 The experimental results and fitting curves of the pressure gradient and seepage velocity of single-phase and two-phase fluids of the present invention are Figure 4 , Figure: d Experimental data of the start-up pressure gradient of two-phase fluid in ultra-low permeability reservoir and the regression curve of the long 2 oil layer. The horizontal axis is the pressure gradient (MPa / m); the vertical axis is the seepage velocity ml / min.

[0043] Figure 6 The experimental results and fitting curves of the pressure gradient and seepage velocity of single-phase and two-phase fluids of the present invention are Figure 5, Figure: e shale oil reservoir two-phase fluid start-up pressure gradient experimental data and regression curve long 7 oil layer. Abscissa, pressure gradient (MPa / m); ordinate, seepage velocity ml / min.

[0044] Figure 7 The experimental results and fitting curves of the pressure gradient and seepage velocity of single-phase and two-phase fluids of the present invention are Figure 6 , Figure: f ultra-low permeability reservoir two-phase fluid start-up pressure gradient experimental data and regression curve long 8 oil layer. Abscissa, pressure gradient (MPa / m); ordinate, seepage velocity ml / min.

[0045] Figure 8 It is a curve diagram of the relationship between the startup pressure gradient and the reservoir permeability of the present invention; in the figure, 1 is a fitting curve of the single-phase startup pressure gradient experimental data; 2 is a fitting curve of the two-phase startup pressure gradient experimental data.

[0046] The following are marked in the figure: 1. differential pressure sensor; 2. hand pump; 3. pressure vessel; 4. isolator; 5. displacement vessel; 6. core holder; 7. micro flow meter; 8. constant speed and pressure pump; 9. constant temperature box; 10. computer. DETAILED DESCRIPTION

[0047] A method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs. The invention relates to shale oil reservoirs, development methods, reservoir energy replenishment and residual oil displacement, oil displacement efficiency improvement and crude oil recovery rate improvement, and specifically to a method and device for predicting the injection pressure of shale oil in reservoir energy replenishment and residual oil potential tapping feasibility after energy storage volume fracturing development.

[0048] The present invention provides a new method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs. The new method includes: predicting the injection pressure according to the production equivalent method; predicting the injection pressure according to the starting pressure gradient. The production equivalent method calculates the injection wellhead pressure based on actual production data and formulas; the starting pressure gradient method predicts the injection pressure based on reservoir core experimental data or correlation calculation data and injection-production connection distance. Therefore, according to the production equivalent method formula and the improved starting pressure gradient experimental device, the injection pressure can be accurately predicted and verified with each other, providing an important basis for the feasibility of shale oil follow-up displacement development.

[0049] A method and formula for predicting injection pressure using the production equivalent method are as follows:

[0050] The wellhead injection pressure predicted by the start-up pressure gradient can be corrected using production data according to the production volume equivalent method.

[0051] According to the reservoir seepage principle, the water injection volume and injection pressure can be converted according to the liquid production and the corresponding production pressure difference:

[0052] Qinj =Q L ×(P inj +0.01h w -P res ) / (P res -P f ) 1

[0053] P inj =Q inj *(P res -P f ) / Q L +P res -0.01h w 2

[0054] In the formula, Q inj , daily water injection volume, m 3 / d;Q L , daily liquid output, m 3 / d;P inj , wellhead injection pressure, MPa; P res , corresponding to the average reservoir pressure at that time, MPa; P f , bottom flow pressure of production well, MPa; h w , depth of horizontal section from wellhead, m.

[0055] For oil wells that lack measured pressure data, the initial data of the blowout can be used. At that time, the wellhead pressure, production and other data are complete, and the formation pressure can be calculated by the pressure storage material balance equation. After the well is soaked, the pressure data is also close to the actual situation. The multiphase fluid pressure of the tubing string is estimated based on the water content, production gas-oil ratio and whether sand is produced.

[0056] A method for predicting the injection-production connection distance and injection pressure based on the startup pressure gradient data and fracturing conditions is as follows:

[0057] Data from developed shale oil indicate that when the pressure gradient is lower than a certain limit, the pressure difference cannot overcome the resistance to flow and no flow occurs, i.e., there is a starting pressure gradient; when the pressure gradient is greater than the starting pressure gradient, the relationship between the pressure gradient and the flow rate is not a simple linear relationship, but a complex nonlinear seepage relationship, and the permeability of shale oil reservoirs is even lower. Therefore, the flow law of fluids in shale oil reservoirs no longer conforms to the classic Darcy's seepage law. At present, the testing methods for low permeability starting pressure at home and abroad are relatively mature, and there are more materials and data. The present invention provides a method for indirectly determining the injection pressure in shale oil displacement based on these data and permeability.

[0058] The test of the starting pressure gradient theoretically requires testing the pressure difference at both ends of the core at the moment when the fluid goes from static to seepage. However, under current technical conditions, it is difficult to accurately control and measure the instantaneous start of seepage. Therefore, the test method of the starting pressure gradient in the current experiment is to gradually reduce the experimental flow rate, measure the pressure difference at both ends of the core at different flow rates, draw the flow-pressure gradient experimental curve, and fit the intercept of the curve on the pressure gradient coordinate. The fitting value is the starting pressure gradient value of the core. The photoelectric micro-flow detector is used to measure the flow rate and the computer automatically records it under the constant temperature reservoir temperature environment, avoiding the shortcomings of the balance weighing that is greatly affected by the environment and the discontinuous measurement; and the gas cylinder and low-pressure constant pressure device are used as the pressure source to fully describe the seepage process of the fluid in the dense core.

[0059] At present, the pressure difference-flow method is mainly used to measure the starting pressure gradient of single-phase fluid. This method can obtain the pseudo starting pressure gradient in the engineering sense by fitting the pressure gradient curve. According to the pressure difference-flow method, the crude oil starting pressure gradient measurement experiment process can be divided into the following steps:

[0060] ① Dry the core for 24 hours and then measure the basic parameters of the core;

[0061] ② Place the core in a holder and evacuate it while saturating it with oil. After aging for 24 hours, determine the core pore volume based on the core weight difference before and after saturation with oil.

[0062] ③ Press attachment Figure 1 Connect the instrument as shown, taking care to ensure that the pressure in the pressure vessel is one atmosphere at the experimental temperature;

[0063] ④ Use a hand pump to slightly compress the gas volume in the pressure vessel, and after the pressure stabilizes, use a high-precision differential pressure sensor and a micro-flow metering device to measure the pressure difference at both ends of the core and the flow rate at the outlet;

[0064] ⑤Gradually and slowly increase the pressure of the gas in the pressure vessel, and read the corresponding values ​​after the pressure difference and flow rate are basically stable;

[0065] ⑥Process the data, draw the crude oil seepage curve and determine the crude oil starting pressure gradient.

[0066] According to the starting pressure gradient measured in the above experiment, it is proposed to establish the relationship between the single-phase and two-phase starting pressure gradient and the reservoir permeability, which is a power function relationship with high correlation:

[0067] D p =aK -b 1

[0068] Where D p , starting pressure gradient, MPa / m; K, reservoir permeability, mD, a, b, correlation coefficient.

[0069] The correlation can be applied to calculate the starting pressure gradient of different reservoirs without coring and analysis, saving cost and time.

[0070] After determining the starting pressure gradient, the nano-agent injection wellhead pressure in unconventional oil reservoirs can be predicted by the following formula:

[0071] P inj =D p ×L+P f -0.01h w 2

[0072] Where, L is the distance outside the effective fracturing radius between injection and production wells in unconventional oil reservoirs, m; P inj , wellhead injection pressure, MPa; P f , bottom flow pressure of production well, MPa; h w , vertical depth of the injection-production section from the wellhead, m; Dp, starting pressure gradient determined by formula (1) based on reservoir permeability, MPa / m.

[0073] The injection pressure at the water injection wellhead can be predicted by the following steps:

[0074] ① Determine the reservoir permeability of the injection layer of the water injection well from the well logging curve or experimental analysis;

[0075] ② According to whether the water injection well is a new well or an old oil well before it is converted to an injection well, select the single-phase or oil-water two-phase starting pressure gradient correlation formula to obtain the starting pressure gradient value;

[0076] ③ According to the monitoring results of the injection-production well fracture length or the numerical model prediction results and the well spacing, determine the remaining distance for injection-production connection;

[0077] ④ Predict the injection well bottom pressure based on the injection-production distance, start-up pressure gradient, oil well bottom pressure, and formation pressure at the bottom of the oil well fracture;

[0078] ⑤ Predict the injection wellhead pressure based on the injection well bottom pressure, wellbore friction loss, head pressure, etc.

[0079] A shale oil reservoir nano-agent displacement injection pressure prediction device comprises a hand pump 2, a pressure vessel 3, an isolation container 4, a displacement container 5 and a constant speed and pressure pump 8. The hand pump 2, the pressure vessel 3, the isolation container 4, the displacement container 5 and the constant speed and pressure pump 8 are connected in sequence, and a constant temperature box 9 is connected to the displacement container 5.

[0080] Among them, the start-up pressure gradient experimental device is improved as follows: the core holder 6 is placed in a constant temperature box 9 to better simulate the reservoir temperature and improve the accuracy of the experimental data.

[0081] Among them, the starting pressure gradient experimental device is improved as follows: the micro flow meter 7 and the pressure difference sensor 1 are connected to the core clamp 6, and the micro flow meter 7 and the pressure difference sensor 1 are connected to the computer 10 to more accurately control the experimental process, adjust the flow and pressure, and measure the experimental results.

[0082] An improvement to the start-up pressure gradient experimental device is as follows:

[0083] Improvement 1: placing the core holder 6 in a constant temperature box 9 to better simulate the reservoir temperature and improve the accuracy of the experimental data.

[0084] Improvement 2: Connect the micro flow meter 7 and the pressure difference sensor 1 to the computer 10 to more accurately control the experimental process, adjust the flow and pressure, and measure the experimental results.

[0085] Example 1 predicts the wellhead injection pressure based on the start-up pressure gradient test results.

[0086] Step 1: Obtain the single-phase and two-phase starting pressure gradient test results according to the starting pressure gradient test. Figure 2-Figure 7 , formula 1.

[0087] Step 2: Analyze the relationship between the start-up pressure gradient and reservoir permeability. Whether it is single-phase or two-phase fluid, the start-up pressure gradient has a highly correlated power function relationship with the reservoir permeability. Figure 8 , with correlation coefficients of 0.986 and 0.999 respectively:

[0088] Where, Dp, starting pressure gradient, MPa / m; K, reservoir permeability, mD.

[0089] According to the above correlation formula, the average permeability of the Chang 7 shale oil sweet spot is 0.26mD, and the two-phase starting pressure gradient is 0.255MPa / m. Taking the N51-H702D well depth of 1670.52m as an example, the water injection wellhead pressure is 21MPa, the lowest pressure saturation pressure when the oil production well bottom is not degassed is 5.0MPa, the injection-production pressure difference is 32.7MPa, and the corresponding injection-production connection distance is 128.4m. When the two wells are volume fracturing and the effective fracturing radius reaches more than 150m, microseismic monitoring and dynamic test analysis show that the effective fracturing radius of most wells exceeds 150m. For the existing old wells with a well spacing of 400m-500m, continuous water injection and displacement can be fully achieved. If re-fracture or water injection is used with a new well, the single-phase starting pressure gradient is only 0.104MPa / m, and the injection-production connection well spacing can reach 315.5m. Because the oil production well has been volume fracturing, medium and low pressure water injection can also be achieved.

[0090] Industrial Applicability:

[0091] According to the correlation formula between the starting pressure gradient of single-phase and two-phase fluids and reservoir permeability provided by the present invention, the starting pressure gradient can be calculated from the reservoir permeability obtained from conventional core analysis, and then the injection wellhead pressure of water flooding or nano-agent displacement in unconventional oil reservoirs can be predicted, saving analysis time, equipment and costs.

[0092] The production volume equivalent method provides a method to predict the injection pressure based on production dynamic data. For oil wells that lack measured pressure data, the initial data of the blowout can be used. When the wellhead pressure, production and other data are complete, the formation pressure can be calculated by the pressure storage material balance equation. As the production time increases, the formation pressure continues to decrease, the crude oil is degassed, the fractures are closed, and the displacement effect will become worse and worse. Therefore, timely injection is beneficial to the displacement of shale oil horizontal wells. It is feasible and economically reasonable to switch to nano-agent displacement technology as soon as possible after a period of energy storage volume fracturing production, and it is a sustainable development method for shale oil and shale oil.

[0093] The above description is only a preferred specific implementation manner of the present invention, but the protection scope of the present invention is not limited thereto. Any technician familiar with the technical field can make equivalent replacements or changes according to the technical solutions and concepts of the present invention within the technical scope disclosed by the present invention, which should be covered by the protection scope of the present invention.

Claims

1. A method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs, characterized in that: The injection pressure is predicted according to the production equivalent method, which calculates the injection wellhead pressure based on actual production data and formulas; The injection pressure is predicted according to the starting pressure gradient method, which predicts the injection pressure based on the reservoir core experimental data or correlation calculation data and the injection-production connection distance. Based on the production equivalent formula and the improved start-up pressure gradient experimental device, the injection pressure is predicted and verified with each other, providing an important basis for the feasibility of shale oil follow-up displacement development.

2. The method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs according to claim 1, characterized in that: The injection pressure prediction formula and process of the production equivalent method are as follows: the wellhead injection pressure predicted by the start-up pressure gradient is corrected by using production data according to the production equivalent method. The water injection volume and injection pressure are calculated according to the reservoir seepage principle, the liquid production and the corresponding production pressure difference: Q inj =Q L ×(P inj +0.01h w -P res ) / (P res -P f ) (1) P inj =Q inj *(P res -P f ) / Q L +P res -0.01h w (2) In the formula, Q inj , daily water injection volume, m 3 / d;Q L , daily liquid output, m 3 / d;P inj , wellhead injection pressure, MPa; P res , corresponding to the average reservoir pressure at that time, MPa; P f , bottom flow pressure of production well, MPa; h w , depth of horizontal section from wellhead, m. For oil wells lacking measured pressure data, the initial data of blowdown are used. At that time, the data of wellhead pressure and production are complete. The formation pressure is calculated based on the pressure storage material balance equation. After the well is soaked, the pressure data is consistent with the actual situation. The multiphase fluid pressure of the tubing string is estimated based on the water content, production gas-oil ratio and whether sand is produced.

3. The method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs according to claim 1, characterized in that: The prediction process of injection-production connection distance and injection pressure under the starting pressure gradient data and fracturing conditions is as follows: At present, the pressure difference-flow method is used to measure the starting pressure gradient of single-phase fluid. This method obtains the pseudo-starting pressure gradient in the engineering sense by fitting the pressure gradient curve. According to the pressure difference-flow method, the crude oil starting pressure gradient measurement experiment process is divided into the following steps: ① Dry the core for 24 hours and then measure the basic parameters of the core; ② Place the core in a holder and evacuate it while saturating it with oil. After aging for 24 hours, determine the core pore volume based on the core weight difference before and after saturation with oil. ③ Connect the instrument, making sure that the pressure in the pressure vessel is one atmosphere at the experimental temperature; ④ Use a hand pump to slightly compress the gas volume in the pressure vessel, and after the pressure stabilizes, use a high-precision differential pressure sensor and a micro-flow metering device to measure the pressure difference at both ends of the core and the flow rate at the outlet; ⑤Gradually and slowly increase the pressure of the gas in the pressure vessel, and read the corresponding values ​​after the pressure difference and flow rate are basically stable; ⑥Process the data, draw the crude oil seepage curve and determine the crude oil starting pressure gradient.

4. The method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs according to claim 3, characterized in that: According to the starting pressure gradient measured in the above experiment, it is proposed to establish the relationship between the single-phase and two-phase starting pressure gradient and the reservoir permeability, which is a power function relationship with high correlation: D p =aK -b (1) Where D p , starting pressure gradient, MPa / m; K, reservoir permeability, mD, a, b, correlation coefficient. The correlation can be applied to calculate the starting pressure gradient of different reservoirs without coring and analysis, saving cost and time.

5. The method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs according to claim 4, characterized in that: After determining the starting pressure gradient, the nano-agent injection wellhead pressure in unconventional oil reservoirs can be predicted by the following formula: P inj =D p ×L+P f -0.01h w (2) Where, L is the distance outside the effective fracturing radius between injection and production wells in unconventional oil reservoirs, m; P inj , wellhead injection pressure, MPa; P f , bottom flow pressure of production well, MPa; h w , vertical depth of the injection-production section from the wellhead, m; Dp, starting pressure gradient determined by equation (1) based on reservoir permeability, MPa / m.

6. The method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs according to claim 5, characterized in that: The injection pressure at the water injection wellhead can be predicted by the following steps: ① Determine the reservoir permeability of the injection layer of the water injection well from the well logging curve or experimental analysis; ② According to whether the injection well is a new well or an old well (oil well) before the water injection well is converted, select the single-phase or oil-water two-phase starting pressure gradient correlation formula to obtain the starting pressure gradient value; ③ According to the monitoring results of the injection-production well fracture length or the numerical model prediction results and the well spacing, determine the remaining distance for injection-production connection; ④ Predict the injection well bottom pressure based on the injection-production distance, start-up pressure gradient, oil well bottom pressure, and formation pressure at the bottom of the oil well fracture; ⑤ Predict the injection wellhead pressure based on the injection well bottom pressure, wellbore friction loss, head pressure, etc.

7. A shale oil reservoir nano-agent displacement injection pressure prediction device, characterized in that: The invention comprises a hand pump (2), a pressure vessel (3), an isolation vessel (4), a displacement vessel (5) and a constant speed and pressure pump (8); the hand pump (2), the pressure vessel (3), the isolation vessel (4), the displacement vessel (5) and the constant speed and pressure pump (8) are connected in sequence, and a constant temperature box (9) is connected to the displacement vessel (5).

8. The shale oil reservoir nano-agent displacement injection pressure prediction device according to claim 7, characterized in that: The start-up pressure gradient experimental device is improved as follows: the core holder (6) is placed in a constant temperature box (9) to better simulate the reservoir temperature and improve the accuracy of the experimental data.

9. The shale oil reservoir nano-agent displacement injection pressure prediction device according to claim 8, characterized in that: The start-up pressure gradient experimental device is improved as follows: a micro flow meter (7) and a pressure difference sensor (1) are connected to a core holder (6), and the micro flow meter (7) and the pressure difference sensor (1) are connected to a computer (10) to more accurately control the experimental process, adjust the flow rate and pressure, and measure the experimental results.

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