A method and device for predicting the injection pressure of nano-agent displacement in a shale oil reservoir

Abstract

A method and device for predicting the injection pressure of nano-agent displacement in a shale oil reservoir, belonging to the technical field of reservoir development, predicting the injection pressure according to the equivalent production method; predicting the injection pressure according to the starting pressure gradient method, predicting the injection pressure according to the equivalent production method formula and the improved starting pressure gradient experimental device, and verifying each other, providing an important basis for the feasibility of continuous displacement development of shale oil. The present invention solves the prediction of the injection pressure, which is a key factor for displacement feasibility, in the optimization of sustainable development methods for shale oil and shale oil. The displacement of nano-agent replenishes the reservoir energy and improves the oil displacement efficiency and recovery rate of unconventional reservoirs such as shale oil and shale oil. If the predicted injection pressure can be achieved in the field, it is of great significance for the determination of the economically recoverable reserves of unconventional reservoirs, the identification of "sweet spots", the increase of single-well EUR and the increase of reservoir recovery rate.

Description

Technical Field

[0001] The present invention belongs to the technical field of reservoir development, and particularly relates to a method and device for predicting the injection pressure of nanoparticle flooding in shale reservoirs. Background Art

[0002] According to the draft standard "Method for Geological Evaluation of Shale Oil" initially formed in July 2019 by the National Standardization Administration of China (GB / T 35545-2019): "Shale oil refers to the petroleum contained in organic-rich shale formations. The single-layer thickness of siltstone, fine sandstone, and carbonate rock in the hydrocarbon source rock of the organic-rich shale formation is not 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 the production is lower than the lower limit of industrial oil production, and special technological measures are required to obtain industrial oil production."

[0003] China is rich in shale oil resources. In 2014, the technically recoverable shale oil resources evaluated by the national oil and gas resources reached 20.3×10^8 t. It is estimated that the technically recoverable shale oil resources in China are 4.393×10^8 t, accounting for about 6% of the global total and ranking third in the world. Shale oil is the most important alternative resource for future oil exploration and development in China, mainly distributed in basins such as Songliao, Ordos, Sichuan, and Junggar. In 2016, the technically recoverable shale oil resources evaluated by PetroChina in China were 14.5×10^8 t. The comprehensive evaluation of the medium-high maturity shale oil resources in continental facies in China is about 20×10^8 t, higher than the previous estimate. China has made important progress in the exploration and technology of continental shale oil. However, generally speaking, it is still in the exploration stage. On October 31, 2022, in the guiding opinions of PetroChina on strengthening the exploration and development of shale oil and gas (Zhongyouban

[2022] No. 215), it was proposed to focus on promoting the exploration and evaluation and development of shale oil and gas such as Chang 7 shale oil, Gulong shale oil, Jimusaer shale oil, deep shale gas in southern Sichuan, Jurassic shale oil in Sichuan, and Qaidam shale oil.

[0004] Due to the tight physical properties of shale oil reservoirs, the natural production capacity is extremely low. There is usually no edge water and gas cap, and the elastic and dissolved gas energy is limited. Energy storage volume fracturing has become the main technology for economic and effective development. However, its energy is invested once and then continuous production occurs, which is similar to huff and puff, and is a process of continuous energy depletion. Therefore, there is a relatively low upper limit of recovery efficiency, generally not exceeding 12%. In order to improve the recovery efficiency, more than 10 successive development methods such as refracturing, water flooding, water injection huff and puff, carbon dioxide flooding, carbon dioxide huff and puff, and chemical flooding have been studied and partially tested. However, they are mostly used in low-permeability and extra-low-permeability oil reservoirs. For shale oil reservoirs with a permeability less than 0.3 mD, water injection huff and puff and continuous water flooding are mainly used, and gas injection is tested, but no mature and popular successive development method has been formed.

[0005] The displacement and imbibition experiment results of shale oil and ultra-low permeability Class III show that the oil displacement efficiency of displacement is close to that of imbibition. The movable reserves of imbibition are limited to artificial fractures and connected natural fractures, which are close to the movable reserves that can be produced by water flooding before the fracture closure, that is, the sweep volume coefficients are similar. Therefore, shale oil displacement can not only continuously supplement the formation energy, but also help to reduce the decline rate of crude oil production and improve the recovery rate. The main difficulty is whether atmospheric pressure injection can be achieved. Therefore, accurate prediction of injection pressure is very important. Summary of the Invention

[0006] To solve the above problems, the present invention proposes: a method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs, predicting the injection pressure according to the equivalent production volume method, and the equivalent production volume method calculates the injection wellhead pressure based on actual production data and formulas;

[0007] Predict the injection pressure according to the starting pressure gradient method, and the starting pressure gradient method predicts the injection pressure according to reservoir core experiment data or relevant formula calculation data and injection-production connection distance.

[0008] Predict the injection pressure according to the equivalent production volume method formula and the improved starting pressure gradient experimental device, and verify each other, providing an important basis for the feasibility of continuous displacement development of shale oil.

[0009] Furthermore, the injection pressure prediction formula and process of the equivalent production volume method are as follows: Apply production data to correct the wellhead injection pressure predicted by the starting pressure gradient method according to the equivalent production volume method. According to the reservoir seepage principle, the injection water volume and injection pressure are calculated based on the liquid production volume 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 injection water volume, m 3 / d; Q L , daily liquid production volume, m 3 / d; P inj , wellhead injection pressure, MPa; P res, corresponding to the average reservoir pressure at a certain time, MPa; P f , bottom-hole flowing pressure of production well, MPa; h w , depth of the horizontal section from the wellhead, m.

[0013] For oil wells lacking measured pressure data, the initial data during flowback are adopted. At that time, the wellhead pressure and production data are complete. The formation pressure is calculated according to the pressure buildup material balance equation. After shut-in, the pressure data conform to the actual situation. The pressure of multiphase fluid in the string is estimated based on water cut, production gas-oil ratio, and whether sand production occurs.

[0014] Furthermore, based on the startup pressure gradient data and the prediction process of injection-production connection distance and injection pressure under fracturing conditions are as follows: Currently, the differential pressure-flow method is used to measure the startup pressure gradient of single-phase fluid. This method obtains the pseudo startup pressure gradient in the engineering sense through the fitting of the pressure gradient curve. According to the differential pressure-flow method, the experimental process of measuring the startup pressure gradient of crude oil is divided into the following steps:

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

[0016] ② Place the core in the holder, evacuate it while saturating it with oil, and after aging for 24 h, determine the pore volume of the core according to the weight difference of the core before and after oil saturation;

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

[0018] ④ Slightly compress the gas volume in the pressure vessel using a hand pump. After the pressure stabilizes, measure the differential pressure across the core and the flow rate at the outlet end through a high-precision differential pressure sensor and a micro flow measurement device;

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

[0020] ⑥ Process the data, plot the crude oil seepage curve, and determine the startup pressure gradient of crude oil.

[0021] Furthermore, based on the startup pressure gradient measured in the above experiment, a relationship between the single-phase and two-phase startup pressure gradients and reservoir permeability is proposed, which is a power function relationship with a high degree of correlation:

[0022] D p =aK -b

[0023] In the formula, D p , startup pressure gradient, MPa / m; K, reservoir permeability, mD, a, b, correlation coefficients.

[0024] Applying this correlation formula can calculate the startup pressure gradients of different reservoirs without coring and analysis, saving costs and time.

[0025] Further, after determining the starting pressure gradient, the injection wellhead pressure of nanoparticle displacement in unconventional reservoirs can be predicted by the following formula:

[0026] P inj = D p × L + P f - 0.01h w

[0027] wherein, L is the distance outside the effective fracturing radius between the injection and production wells in the unconventional reservoir, in m; P inj , the wellhead water injection pressure, in MPa; P f , the bottom hole flowing pressure of the production well, in MPa; h w , the vertical depth of the injection-production interval from the wellhead, in m; Dp is the starting pressure gradient determined by the formula according to the reservoir permeability, in MPa / m.

[0028] Further, the injection wellhead pressure can be predicted through the following steps:

[0029] ① Determine the reservoir permeability of the water injection layer of the injection well from well logging curves or experimental analysis, etc.;

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

[0031] ③ Determine the remaining distance of injection-production connection according to the monitoring of the fracture length of the injection-production well or the results of numerical simulation prediction and the well spacing;

[0032] ④ Predict the bottom hole pressure of the injection well according to the injection-production distance, the starting pressure gradient, the bottom hole pressure of the production well, and the formation pressure at the bottom of the fracture of the production well;

[0033] ⑤ Predict the wellhead pressure of the injection well according to the bottom hole pressure of the injection well, the frictional loss in the wellbore, the head pressure, etc.

[0034] A device for predicting the injection pressure of nanoparticle displacement in a shale oil reservoir includes a hand pump, a pressure vessel, an isolation vessel, a displacement vessel, and a constant speed and constant pressure pump. The hand pump, the pressure vessel, the isolation vessel, the displacement vessel, and the constant speed and constant pressure pump are connected in sequence, and a constant temperature box is connected to the displacement vessel.

[0035] Further, the starting pressure gradient experimental device is improved as follows: place the core holder in the constant temperature box to better simulate the reservoir temperature and improve the accuracy of experimental data.

[0036] Further, the starting pressure gradient experimental device is improved as follows: connect a micro flowmeter and a differential pressure sensor to the core holder, and connect the micro flowmeter and the differential pressure sensor to a computer to more precisely control the experimental process, adjust the flow rate and pressure, and measure the experimental results.

[0037] The beneficial effects of the present invention are as follows: By using the technical solution of the present invention, the prediction of the injection pressure, which is a key factor for displacement feasibility in the preferred sustainable development method of shale oil and shale oil, is solved. Research shows that nanoparticle displacement can effectively supplement the energy of the reservoir and significantly improve the oil displacement efficiency and recovery rate of unconventional reservoirs such as shale oil and shale oil. If the predicted injection pressure can be achieved in the field, it is of great significance for determining the economically recoverable reserves of unconventional reservoirs, identifying the "sweet spot" areas, increasing the EUR of a single well, and improving the reservoir recovery rate. BRIEF DESCRIPTION OF THE DRAWINGS

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

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

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

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

[0042] Figure 5 are the experimental results and fitting curves of the pressure gradient and seepage velocity of single-phase and two-phase fluids of the present invention Figure 4 , in the figure: d Experimental data and regression curve of the starting pressure gradient of two-phase fluid in an extra-low permeability reservoir, Chang 2 oil layer. Abscissa, pressure gradient (MPa / m); ordinate, seepage velocity (ml / min).

[0043] Figure 6 are the experimental results and fitting curves of the pressure gradient and seepage velocity of single-phase and two-phase fluids of the present invention Figure 5, in the figure: Experimental data and regression curve of the starting pressure gradient of two-phase fluids in the e shale oil reservoir, Chang 7 oil layer. Abscissa, pressure gradient (MPa / m); Ordinate, seepage velocity ml / min.

[0044] Figure 7 are the experimental results and fitting curves of the single-phase and two-phase fluid pressure gradients and seepage velocities of the present invention Figure 6 , in the figure: Experimental data and regression curve of the starting pressure gradient of two-phase fluids in the f ultra-low permeability oil reservoir, Chang 8 oil layer. Abscissa, pressure gradient (MPa / m); Ordinate, seepage velocity ml / min.

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

[0046] The markings in the figure are: 1, differential pressure sensor; 2, hand pump; 3, pressure vessel; 4, isolator; 5, displacement vessel; 6, core holder; 7, micro flowmeter; 8, constant speed and constant pressure pump; 9, constant temperature box; 10, computer. Detailed implementation manners

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

[0048] The present invention provides a new method for predicting the injection pressure of nano-agent displacement in a shale oil reservoir. The new method includes: predicting the injection pressure according to the equivalent production volume method; predicting the injection pressure according to the starting pressure gradient. The equivalent production volume method calculates the injection wellhead pressure based on actual production data and formulas; the starting pressure gradient method predicts the injection pressure according to the reservoir core experimental data or relevant formula calculation data and the injection-production connection distance. Thus, according to the equivalent production volume 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 continuous displacement development of shale oil.

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

[0050] The injection wellhead pressure predicted by the starting pressure gradient can be corrected by applying production data according to the equivalent production volume method.

[0051] According to the reservoir seepage principle, the injection water volume and injection pressure can be converted based on the liquid production volume 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] Wherein, Q inj , daily water injection volume, m 3 / d; Q L , daily liquid production volume, m 3 / d; P inj , wellhead water injection pressure, MPa; P res , average reservoir pressure at corresponding time, MPa; P f , bottom-hole flowing pressure of production well, MPa; h w , depth of horizontal section from wellhead, m.

[0055] For oil wells lacking measured pressure data, the initial flowback data can be used. At that time, data such as wellhead pressure and production are complete, and the formation pressure can be calculated by the material balance equation of pressure build-up. After shut-in, the pressure data is also close to the actual situation, and the pressure of multiphase fluid in the pipe string is estimated according to the water cut, production gas-oil ratio and whether there is sand production.

[0056] A method for predicting injection pressure and injection-production connection distance under fracture conditions based on start-up pressure gradient data is as follows:

[0057] The developed shale oil data shows that when the pressure gradient is lower than a certain limit, the pressure difference cannot overcome the flow resistance and no flow occurs, that is, there is a start-up pressure gradient; after the pressure gradient is greater than the start-up pressure gradient, the relationship between the pressure gradient and the flow rate is not a simple linear relationship, but a complex non-linear seepage relationship. The permeability of shale oil reservoirs is lower, so the flow law of fluids in shale oil reservoirs no longer conforms to the classical Darcy's seepage law. At present, the testing methods for low-permeability start-up pressure are relatively mature at home and abroad, and there is a lot of 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 measuring the pressure difference across the core at the instant when the fluid starts to flow from rest to percolation. However, under current technical conditions, it is difficult to accurately control and measure the instant start of percolation. Therefore, in current experiments, the test method for the starting pressure gradient is to gradually reduce the experimental flow rate, measure the pressure difference across the core at different flow rates, plot the flow rate-pressure gradient experimental curve, and fit the intercept of the curve on the pressure gradient coordinate. This fitted value is taken as the starting pressure gradient value of the core. An optoelectronic micro-flow detector is used to measure the flow rate under a constant reservoir temperature environment, and a computer automatically records the data, avoiding the disadvantages of large environmental influence and discontinuous measurement existing in weighing with a balance. Moreover, a gas cylinder and a low-pressure constant-pressure device are used as the pressure source to completely describe the percolation process of the fluid in the tight core.

[0059] Currently, the differential pressure-flow method is mainly used to measure the starting pressure gradient of single-phase fluids. This method can obtain the pseudo starting pressure gradient in the engineering sense through the fitting of the pressure gradient curve. According to the differential pressure-flow method, the experimental process for measuring the starting pressure gradient of crude oil can be divided into the following steps:

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

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

[0062] ③ Connect the instruments as shown in the appendix, and note to ensure that the pressure in the pressure vessel is one atmospheric pressure at the experimental temperature; Figure 1 Shown, pay attention to ensuring 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. After the pressure stabilizes, measure the pressure difference across the core and the outlet flow rate through a high-precision differential pressure sensor and a micro-flow measurement device;

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

[0065] ⑥ Process the data, plot the crude oil percolation curve, and determine the starting pressure gradient of the crude oil.

[0066] Based on the starting pressure gradient measured by the above experiments, a relationship between the single-phase and two-phase starting pressure gradients and the reservoir permeability is proposed, which is a power function relationship with a high degree of correlation:

[0067] D p =aK -b 1

[0068] In the formula, D p , the starting pressure gradient, MPa / m; K, the reservoir permeability, mD, a, b, correlation coefficients.

[0069] The startup pressure gradient of different reservoirs can be calculated by applying this correlation formula, eliminating the need for core sampling and analysis, thus saving costs and time.

[0070] After determining the startup pressure gradient, the injection wellhead pressure of nanofluid displacement in unconventional reservoirs can be predicted by the following formula:

[0071] P inj =D p ×L + P f - 0.01h w 2

[0072] In the formula, L is the distance outside the effective fracturing radius between the injection and production wells in the unconventional reservoir, in m; P inj is the wellhead injection pressure, in MPa; P f is the bottom hole flowing pressure of the production well, in MPa; h w is the vertical depth from the injection-production interval to the wellhead, in m; Dp is the startup pressure gradient determined by Formula (1) according to the reservoir permeability, in MPa / m.

[0073] The injection wellhead pressure can be predicted through the following steps:

[0074] ① Determine the reservoir permeability of the injection layer of the injection well from well logging curves or experimental analysis, etc.

[0075] ② Select the correlation formula for the single-phase or oil-water two-phase startup pressure gradient according to whether the injection well was a new well or an old oil well before conversion to injection, and obtain the startup pressure gradient value.

[0076] ③ Determine the remaining distance of injection-production connection according to the monitoring of the fracture length of the injection-production wells or the results of numerical simulation prediction and the well spacing.

[0077] ④ Predict the bottom hole pressure of the injection well according to the injection-production distance, startup pressure gradient, bottom hole pressure of the production well, and formation pressure at the bottom of the fracture of the production well.

[0078] ⑤ Predict the wellhead pressure of the injection well according to the bottom hole pressure of the injection well, wellbore friction loss, head pressure, etc.

[0079] A device for predicting the injection pressure of nanofluid displacement in a shale reservoir includes a hand pump 2, a pressure vessel 3, an isolation vessel 4, a displacement vessel 5, and a constant-speed constant-pressure pump 8. The hand pump 2, pressure vessel 3, isolation vessel 4, displacement vessel 5, and constant-speed constant-pressure pump 8 are connected in sequence, and a constant-temperature box 9 is connected to the displacement vessel 5.

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

[0081] Among them, the improvement of the starting pressure gradient experimental device is as follows: The micro flowmeter 7, the differential pressure sensor 1 are connected to the core holder 6, and the micro flowmeter 7, the differential pressure sensor 1 are connected to the computer 10 to more precisely control the experimental process, adjust the flow rate and pressure, and measure the experimental results.

[0082] An improvement of the starting pressure gradient experimental device is as follows:

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

[0084] Improvement 2: Connect the micro flowmeter 7, the differential pressure sensor 1, etc. to the computer 10 to more precisely control the experimental process, adjust the flow rate and pressure, and measure the experimental results.

[0085] Example 1 Predict the wellhead injection pressure according to the experimental results of the starting pressure gradient.

[0086] Step 1: Obtain the experimental results of the single-phase and two-phase starting pressure gradients according to the starting pressure gradient experiment, as shown in Equation 1. Figures 2 - 7 , Equation 1.

[0087] Step 2: Analyze the relationship between the starting pressure gradient and the reservoir permeability. Both the single-phase and two-phase fluid starting pressure gradients have a highly correlated power function relationship with the reservoir permeability, as shown in Figure 8 , and the correlation coefficients are 0.986 and 0.999 respectively:

[0088] In the formula, Dp is the starting pressure gradient, MPa / m; K is the reservoir permeability, mD.

[0089] According to the above correlation formula, taking the average permeability of the sweet spot of the Chang 7 shale oil as 0.26 mD, the two-phase starting pressure gradient is 0.255 MPa / m. Taking the well depth of Well N51-H702D as 1670.52 m as an example, the wellhead pressure of the injection well is 21 MPa, the lowest pressure saturation pressure when the bottom of the production well is not degassed is 5.0 MPa, the injection-production pressure difference is 32.7 MPa, and the corresponding injection-production connection distance is 128.4 m. In the case of volume fracturing of two wells and the effective fracturing radius reaching more than 150 m, microseismic monitoring and dynamic test analysis show that the effective fracturing radius of most wells exceeds 150 m. Then, for the existing old wells with a well spacing of 400 m - 500 m, continuous water injection and displacement can be fully realized. If re-fracturing or using new wells for water injection, the single-phase starting pressure gradient is only 0.104 MPa / m, and the injection-production connectable well spacing reaches 315.5 m. Since the production wells have been volume fractured, 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 by conventional core analysis, and then the injection wellhead pressure for water flooding or nanofluid displacement in unconventional reservoirs can be predicted, saving analysis time, equipment and costs.

[0092] The equivalent production method provides a method for predicting injection pressure based on production dynamic data. For oil wells lacking measured pressure data, the data at the initial stage of flowback can be used. When flowing back, the wellhead pressure, production and other data are complete, and the formation pressure can be calculated by the pressure accumulation material balance equation. As the production time prolongs, the formation pressure continuously decreases, the crude oil degasses, and the fractures close, resulting in a worse displacement effect. Therefore, timely injection conversion is beneficial to the displacement of horizontal wells in shale oil reservoirs. It is feasible and economically reasonable to convert to nanofluid displacement technology as early as possible after the energy storage volume fracturing production for a period of time, which is a sustainable development method for shale oil and shale oil.

[0093] The above is only a preferred specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Any person skilled in the art within the technical scope disclosed by the present invention, according to the technical solution and its concept of the present invention, makes equivalent substitutions or changes, and should be covered within the protection scope of the present invention.

Claims

1. A method for predicting the injection pressure of nano-agent displacement in a shale oil reservoir, characterized in that: Predict the injection pressure according to the equivalent production method. The equivalent production method calculates the injection wellhead pressure based on actual production data and formulas; The injection pressure prediction formula and process of the equivalent production method are as follows: Apply production data to correct the wellhead injection pressure predicted by the equivalent production method for the startup pressure gradient. According to the reservoir seepage principle, based on the liquid production volume and the corresponding production pressure difference, calculate the injection water volume and injection pressure: 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) Where, Q inj , daily water injection volume, m 3 / d; Q L , daily liquid production volume, m 3 / d; P inj , wellhead water injection pressure, MPa; P res , average reservoir pressure at corresponding time, MPa; P f , bottom hole flowing pressure of production well, MPa; h w , depth of horizontal section from wellhead, m; For oil wells lacking measured pressure data, use the initial data during the blowout period. At that time, the wellhead pressure and production data are complete. The formation pressure is calculated according to the pressure accumulation material balance equation. After shut-in, the pressure data conforms to the actual situation, and the multiphase fluid pressure in the tubing string is estimated according to the water cut, production gas-oil ratio, and whether there is sand production; Predict the injection pressure according to the startup pressure gradient method. The startup pressure gradient method predicts the injection pressure based on reservoir core experiment data or relevant formula calculation data and the injection-production connection distance; Predict the injection pressure according to the equivalent production method formula and the improved startup pressure gradient experimental device, and verify each other, providing an important basis for the feasibility of continuous displacement development of shale oil.

2. The method for predicting the displacement injection pressure of nano-agent in shale oil reservoir according to claim 1, wherein, The prediction process of injection pressure based on startup pressure gradient data and injection-production connection distance and injection pressure in the case of fracturing is as follows: Currently, the differential pressure-flow method is used to measure the startup pressure gradient of single-phase fluid. This method obtains the pseudo startup pressure gradient in the engineering sense through the fitting of the pressure gradient curve. According to the differential pressure-flow method, the experimental process of measuring the startup pressure gradient of crude oil is divided into the following steps: ① Dry the core for 24 h and then measure the basic parameters of the core; ② Put the core into the holder, evacuate and saturate with oil at the same time. After aging for 24 h, determine the pore volume of the core according to the weight difference of the core before and after saturation with oil; ③ Connect the instrument, and note that the pressure in the pressure vessel at the experimental temperature is one atmosphere; ④ Use a hand pump to slightly compress the gas volume in the pressure vessel. After the pressure is stable, measure the differential pressure at both ends of the core and the flow rate at the outlet end through a high-precision differential pressure sensor and a micro flow measurement device; ⑤ Gradually and slowly increase the pressure of the gas in the pressure vessel, and wait until the differential pressure and flow rate are basically stable before reading the corresponding values; ⑥ Process the data, draw the crude oil seepage curve and determine the startup pressure gradient of the crude oil.

3. The method for predicting the injection pressure of nano-agent displacement in shale oil reservoirs according to claim 2, wherein Based on the startup pressure gradient measured by the above experiment, establish the relationship between the single-phase and two-phase startup pressure gradients 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 coefficients Applying this relevant formula can calculate the startup pressure gradient of different reservoirs without coring and analysis, saving costs and time.

4. The method for predicting the displacement injection pressure of nano-agent in shale oil reservoirs according to claim 3, wherein After determining the startup pressure gradient, the injection wellhead pressure of nano-agent displacement in unconventional 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 the injection and production wells in unconventional reservoirs, in m; P inj is the injection pressure at the wellhead, in MPa; P f is the flowing bottom-hole pressure of the production well, in MPa; h w is the vertical depth of the injection-production interval from the wellhead, in m; Dp is the starting pressure gradient determined by equation (1) according to the reservoir permeability, in MPa / m.

5. The method for predicting the displacement injection pressure of nano-agent in shale oil reservoirs according to claim 4, wherein The injection wellhead pressure can be predicted through the following steps: ① Determine the reservoir permeability of the water injection layer of the injection well from well logging curves or experimental analysis, etc.; ② According to whether the injection well is a new oil well or an old oil well before water injection conversion, select the relevant formula for the single-phase or oil-water two-phase startup pressure gradient to obtain the startup pressure gradient value; ③ Determine the remaining injection-production connection distance according to the monitoring or numerical simulation prediction results of the fracture lengths of the injection and production wells and the well spacing; ④Predict the bottom hole pressure of the injection well according to the injection-production distance, starting pressure gradient, bottom hole pressure of the production well, and formation pressure at the bottom of the fracture of the production well; ⑤Predict the wellhead pressure of the injection well according to the bottom hole pressure of the injection well, wellbore friction loss, water head pressure, etc.

6. An apparatus for predicting the displacement injection pressure of a nano-agent in a shale oil reservoir according to claim 1, characterized in that, It includes a hand pump (2), a pressure vessel (3), an isolation vessel (4), a displacement vessel (5) and a constant speed and constant pressure pump (8). The hand pump (2), the pressure vessel (3), the isolation vessel (4), the displacement vessel (5) and the constant speed and constant pressure pump (8) are connected in sequence, and a thermostat (9) is connected to the displacement vessel (5).

7. The shale oil reservoir nano-agent displacement injection pressure prediction device according to claim 6, characterized in that Improve the starting pressure gradient experimental device as follows: Place the core holder (6) in the thermostat (9) to better simulate the reservoir temperature and improve the accuracy of experimental data.

8. The shale oil reservoir nano-agent displacement injection pressure prediction device according to claim 7, wherein Improve the starting pressure gradient experimental device as follows: Connect the micro flowmeter (7) and the differential pressure sensor (1) to the core holder (6), and connect the micro flowmeter (7) and the differential pressure sensor (1) to the computer (10) to more precisely control the experimental process, adjust the flow rate and pressure, and measure the experimental results.

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