Shale oil horizontal well huff and puff oil production method

Abstract

The invention belongs to the field of oil development, and discloses a shale oil horizontal well huff and puff injection and production method which comprises the following steps: selecting all horizontal wells in a test area as test wells; determining a CO2 injection mode; determining the maximum injection pressure of a wellhead; establishing a three-dimensional geologic model and a numerical model of the test area, determining a recovery pressure target value, and calculating a single well injection rate; the single well gas injection speed is determined; determining well closing time; determining production flow pressure; and the throughput round corresponding to the preset oil change rate is determined. According to the method, the gas channeling problem between wells can be effectively prevented by optimizing the huff and puff injection and production parameters of the horizontal well, the synergistic effect of CO2 swelling energy increasing, extraction and the like can be fully played through the optimized injection and production parameters, the reservoir fluid seepage capacity is improved, the shale oil recovery rate is greatly increased, and the predicted recovery rate can be increased by 3% or above.

Description

Technical Field

[0001] The invention belongs to the field of petroleum development, and in particular relates to a shale oil horizontal well huff-and-puff oil production method. Background Art

[0002] Shale oil is one of the important areas of unconventional oil exploration and development in the world. At present, the main technology of shale oil development is horizontal well volume fracturing natural energy development, which can effectively improve the daily oil production capacity of a single well in the early stage of development. However, large decline and low predicted recovery rate are still the key issues restricting the efficient development of shale oil.

[0003] Gas injection is the main way to improve the recovery of shale oil. The injection medium is mainly gas media such as CO2, and the main method of gas injection is huff and puff. The following three important insights were obtained from the field huff and puff test: First, the key to successful huff and puff is to ensure that the injected gas is enclosed in the fracture-controlled volume; second, a sufficiently large fracture contact area is the key to improving the huff and puff effect; third, choosing a reasonable huff and puff mode and designing injection and suffocation parameters are important foundations for ensuring the huff and puff effect.

[0004] Shale oil reservoirs are low-porosity and dense, with some natural fractures. Due to low natural productivity, most of them are developed by volume fracturing. However, after volume fracturing, the reservoir heterogeneity is aggravated, and the injected gas advances rapidly along the direction of the artificial fracture during the huff and puff of horizontal wells, which can easily cause gas channeling in adjacent wells.

[0005] Therefore, it is necessary to provide a shale oil horizontal well huff-and-puff injection-production method to prevent the uncontrolled diffusion of injected CO2 and avoid gas channeling from adjacent wells, while optimizing the injection-production parameters and increasing the oil production after CO2 injection. Summary of the invention

[0006] In order to overcome the defects of the above-mentioned prior art, the purpose of the present invention is to provide a shale oil horizontal well throughput injection and production method, which can prevent the uncontrolled diffusion of injected CO2 and avoid gas breakthrough in adjacent wells, while optimizing the injection and production parameters and increasing the oil production after CO2 injection.

[0007] To achieve the above object, the present invention provides the following technical solutions:

[0008] A shale oil horizontal well huff-and-puff oil production method, comprising:

[0009] All horizontal wells with intact wellbore structures in the test area are selected as test wells;

[0010] Determine the CO2 injection method based on the fault conditions encountered during drilling of the horizontal well;

[0011] Determine the maximum injection pressure at the wellhead based on hydraulic fracturing theory;

[0012] Establish a three-dimensional geological model and numerical model of the test area, use the numerical model to determine the target value of recovery pressure, and calculate the single well injection volume based on the target value of recovery pressure;

[0013] The first graph of the correlation between the increased oil volume after huff and puff and the gas injection rate of a single well is established according to the numerical model, and the gas injection rate of a single well is determined according to the first graph of the correlation between the increased oil volume after huff and puff and the gas injection rate of a single well;

[0014] A correlation chart of the increased oil volume after huff and puff and the well-clogging time is established based on the numerical model, and the well-clogging time is determined based on the correlation chart of the increased oil volume after huff and puff and the well-clogging time;

[0015] A correlation curve between the pressure in the near-wellbore area after huff-and-puff and the production flow pressure is established based on the numerical model, and the production flow pressure is determined based on the correlation curve between the pressure in the near-wellbore area after huff-and-puff and the production flow pressure;

[0016] A correlation chart between oil change rate and throughput cycles is established based on the numerical model to determine the throughput cycles corresponding to the preset oil change rate.

[0017] In some embodiments of the present invention, at least 10-meter interlayers are developed at the top and bottom of the target layer for gas injection and energy replenishment in the test area.

[0018] In some embodiments of the present invention, the CO2 injection method is determined according to the fault situation encountered by the horizontal well, including:

[0019] When a horizontal well encounters a fault and there is a reformed section near the fault, a segmented injection method is used;

[0020] When the horizontal well does not encounter faults, and the pump-off pressure range of the horizontal well's transformation section is less than 10% of the regional minimum horizontal principal stress, a general injection method is used;

[0021] When the horizontal well does not encounter a fault and the pump-off pressure range of the transformation section of the horizontal well is not less than 10% of the regional minimum horizontal principal stress, the segmented injection method is adopted.

[0022] In some embodiments of the present invention, determining the maximum wellhead injection pressure according to hydraulic fracturing theory includes:

[0023] The maximum wellhead injection pressure is calculated using the following formula:

[0024]

[0025]

[0026] Among them, P 注气井口max is the maximum injection pressure, MPa; P 裂缝开启 is the secondary opening pressure of the crack, MPa; 0.9 is the safety factor; is the CO2 liquid column pressure in the wellbore, MPa; is the density of CO2, g / cm 3 ; H is the depth from the wellhead to the injection layer, m; g is the gravity acceleration, m / s 2 .

[0027] In some embodiments of the present invention, establishing a three-dimensional geological model and a numerical model of the test area includes:

[0028] The fracture network development in the test area is simulated by using a three-dimensional geological model in conjunction with fracturing construction parameters;

[0029] The daily fluid production, daily oil production and water content of the horizontal wells in the test area were historically matched through the numerical model.

[0030] In some embodiments of the present invention, determining the target value of the recovery pressure by using a numerical model includes:

[0031] According to the numerical model, the oil increase when restoring different formation pressures is simulated and calculated, and the second chart of the correlation between the oil increase after throughput and the formation pressure is established. The target value of the recovery pressure is determined according to the inflection point of the curve of the second chart of the correlation between the oil increase after throughput and the formation pressure.

[0032] In some embodiments of the present invention, calculating the single well injection rate according to the recovery pressure target value includes:

[0033] Calculate the formation deficit Q1 when the pressure returns to the original formation pressure:

[0034] Q1=V w +V g B g -N p B o -W p -G p B gi

[0035] Among them, V w is the cumulative water injection volume, m 3 ; V g is the cumulative gas injection volume, m 3 ; N p is the cumulative oil production, m 3 ; W p is the cumulative water production, m 3 ; G p is the cumulative gas production, m 3 ; B o is the volume coefficient of crude oil, m 3 / m 3 ; B gi is the volume coefficient of produced gas, m 3 / m 3 ; B gis the volume coefficient of injected gas, m 3 / m 3 ;

[0036] Calculate the injection volume Q2 from the original formation pressure to the target recovery pressure value:

[0037] V=(CV)△p 压裂

[0038] Q2=(CV)△p

[0039] Where V is the amount of liquid entering the ground, MPa; △p 压裂 is the change in formation pressure after volume fracturing, MPa; CV is the product of the comprehensive compression coefficient and the horizontal well control volume; △p is the difference between the recovery pressure target value and the original formation pressure;

[0040] Single well injection volume Q = Q1 + Q2.

[0041] In some embodiments of the present invention, determining the single well gas injection rate according to the first chart of the correlation between the increased oil volume after throughput and the single well gas injection rate includes:

[0042] The gas injection rate of a single well is determined according to the inflection point of the curve in the first graph of the correlation between the increased oil production after huff and puff and the gas injection rate of a single well.

[0043] In some embodiments of the present invention, determining the well blocking time according to the correlation chart between the increased oil volume after throughput and the well blocking time includes:

[0044] The well blocking time is determined according to the inflection point of the curve of the correlation chart of the increased oil volume after huff and puff and the well blocking time.

[0045] In some embodiments of the present invention, the production flow pressure is determined according to the correlation curve between the pressure in the near-wellbore area after huff and puff and the production flow pressure, including:

[0046] When determining the production flow pressure, control the pressure in the area near the wellbore to be no lower than the pressure before throughput.

[0047] Technical effects and advantages of the present invention:

[0048] The present invention can effectively prevent the problem of gas crossover between wells by optimizing the injection and production parameters of horizontal wells. The optimized injection and production parameters can give full play to the synergistic effects of CO2 swelling energy enhancement, extraction and extraction, improve the seepage capacity of reservoir fluid, and greatly improve the shale oil recovery rate. The predicted recovery rate can be increased by more than 3%.

[0049] Other features and advantages of the present invention will be described in the following description, and partly become apparent from the description, or understood by practicing the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures pointed out in the description, claims and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0050] Figure 1 This is a flow chart of a shale oil horizontal well huff and puff oil production method of the present invention;

[0051] Figure 2 A flow chart for determining the CO2 injection method for the present invention;

[0052] Figure 3 It is a schematic diagram of the numerical model of the test area of ​​the embodiment;

[0053] Figure 4 The second figure of the correlation between the increased oil throughput and the formation pressure in the embodiment;

[0054] Figure 5 It is a line graph of the wellhead pressure during the well blocking period after hydraulic fracturing in the embodiment;

[0055] Figure 6 This is a graph showing the correlation between the throughput increase and the single well gas injection rate in the embodiment;

[0056] Figure 7 This is a graph showing the correlation between the throughput increase and the well blocking time in the embodiment;

[0057] Figure 8 This is a graph showing the correlation between increased oil throughput and production flow pressure in the example. DETAILED DESCRIPTION

[0058] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0059] like Figure 1 As shown, the present invention provides a shale oil horizontal well huff-and-puff oil production method, comprising:

[0060] All horizontal wells with intact wellbore structures in the test area are selected as test wells;

[0061] Determine the CO2 injection method based on the fault conditions encountered during drilling of the horizontal well;

[0062] Determine the maximum injection pressure at the wellhead based on hydraulic fracturing theory;

[0063] Establish a three-dimensional geological model and numerical model of the test area, use the numerical model to determine the target value of recovery pressure, and calculate the target value of single well injection volume based on the recovery pressure;

[0064] The first graph of the correlation between the increased oil volume after huff and puff and the gas injection rate of a single well is established according to the numerical model, and the gas injection rate of a single well is determined according to the first graph of the correlation between the increased oil volume after huff and puff and the gas injection rate of a single well;

[0065] A correlation chart of the increased oil volume after huff and puff and the well-clogging time is established based on the numerical model, and the well-clogging time is determined based on the correlation chart of the increased oil volume after huff and puff and the well-clogging time;

[0066] A correlation curve between the pressure in the near-wellbore area after huff-and-puff and the production flow pressure is established based on the numerical model, and the production flow pressure is determined based on the correlation curve between the pressure in the near-wellbore area after huff-and-puff and the production flow pressure;

[0067] A correlation chart between oil change rate and throughput cycles is established based on the numerical model to determine the throughput cycles corresponding to the preset oil change rate.

[0068] By designing a huff-and-puff oil production method for all horizontal wells in the test area, gas crossover between wells can be effectively prevented.

[0069] In some embodiments of the present invention, at least 10-meter interlayers are developed at the top and bottom of the target layer for gas injection and energy replenishment in the test area.

[0070] It should be noted that when the thickness of the interlayer is less than 10m, the water content of the horizontal well decreases slowly, and the initial daily oil production of the 100-meter oil layer is low. According to the analysis of the stratified pressure test of adjacent vertical wells during the horizontal well fracturing process, when the thickness of the interlayer is greater than or equal to 10m, the possibility of vertical fracture height communication is small.

[0071] In some embodiments of the present invention, Figure 2 As shown in the figure, the CO2 injection method is determined according to the fault situation encountered by the horizontal well, including:

[0072] When a horizontal well encounters a fault and there is a reformed section near the fault, a segmented injection method is used;

[0073] When the horizontal well does not encounter faults, and the pump-off pressure range of the horizontal well's transformation section is less than 10% of the regional minimum horizontal principal stress, a general injection method is used;

[0074] When the horizontal well does not encounter a fault and the extreme difference in the pump-off pressure of the transformation section of the horizontal well is not less than 10% of the regional minimum horizontal principal stress, a segmented injection method is adopted. For example, perforation sections with similar pump-off pressures are combined into one section for segmented injection.

[0075] In some embodiments of the present invention, the maximum wellhead injection pressure is determined according to hydraulic fracturing theory. According to hydraulic fracturing theory, the pump-off pressure of the hydraulic fracturing curve can represent the secondary opening pressure of the fracture, so the average pump-off pressure value of the horizontal section is taken to represent the secondary opening pressure of the fracture.

[0076] The maximum wellhead injection pressure is calculated using the following formula:

[0077]

[0078]

[0079] Among them, P 注气井口max is the maximum injection pressure, MPa; P 裂缝开启 is the secondary opening pressure of the crack, MPa; 0.9 is the safety factor; is the CO2 liquid column pressure in the wellbore, MPa; is the CO2 density, select the CO2 density at the corresponding temperature and pressure, g / cm 3 ; H is the depth from the wellhead to the injection layer, m; g is the gravity acceleration, m / s 2 .

[0080] In some embodiments of the present invention, establishing a three-dimensional geological model and a numerical model of the test area includes:

[0081] The fracture network development in the test area is simulated by using a three-dimensional geological model in conjunction with fracturing construction parameters;

[0082] The daily liquid production, daily oil production and water content of the horizontal wells in the test area are historically matched through numerical models and optimized and adjusted to meet the requirements.

[0083] In some embodiments of the present invention, determining the target value of the recovery pressure by using a numerical model includes:

[0084] According to the numerical model, the oil increase when restoring different formation pressures is simulated and calculated, and the second chart of the correlation between the oil increase after throughput and the formation pressure is established. The target value of the recovery pressure is determined according to the inflection point of the curve of the second chart of the correlation between the oil increase after throughput and the formation pressure.

[0085] In some embodiments of the present invention, due to the strong heterogeneity of shale oil reservoirs, the theoretical calculation adaptability used in conventional oil reservoirs is poor, and it is necessary to consider the availability of reservoir and fluid parameters at the same time and establish a new method for calculating the injection volume of a single well.

[0086] Calculate the single well injection volume based on the recovery pressure target value, including:

[0087] Calculate the formation deficit Q1 when the pressure returns to the original formation pressure:

[0088] Q1=V w +V g B g -N p B o -W p -G p B gi

[0089] Among them, V w is the cumulative water injection volume, m 3 ; V g is the cumulative gas injection volume, m 3 ; N p is the cumulative oil production, m 3 ; W p is the cumulative water production, m 3 ; G p is the cumulative gas production, m 3 ; B o is the volume coefficient of crude oil, m 3 / m 3 ; B gi is the volume coefficient of produced gas, m 3 / m 3 ; B g is the volume coefficient of injected gas, m 3 / m 3 ;

[0090] Calculate the injection volume Q2 from the original formation pressure to the target recovery pressure value:

[0091] V=(CV)△p 压裂

[0092] Q2=(CV)△p

[0093] Where V is the amount of liquid entering the ground, MPa; △p 压裂 is the change in formation pressure after volume fracturing, MPa; CV is the product of the comprehensive compression coefficient and the horizontal well control volume; △p is the difference between the recovery pressure target value and the original formation pressure;

[0094] Single well injection volume Q = Q1 + Q2.

[0095] A low gas injection rate in a single well will affect the production time rate, and a high gas injection rate in a single well will increase the risk of gas channeling, both of which will have an adverse effect on the production effect. In some embodiments of the present invention, the gas injection rate in a single well is determined according to the first graph of the correlation between the increased oil volume after throughput and the gas injection rate in a single well, including:

[0096] The gas injection rate of a single well is determined according to the inflection point of the curve in the first graph of the correlation between the increased oil production after huff and puff and the gas injection rate of a single well.

[0097] If the well-clogging time is too short, CO2 diffusion is insufficient and the oil change efficiency is low; if the well-clogging time is too long, the diffusion range is too large, which affects the pressure recovery. In some embodiments of the present invention, the well-clogging time is determined according to the correlation chart between the increased oil volume after throughput and the well-clogging time, including:

[0098] The well blocking time is determined according to the inflection point of the curve of the correlation chart of the increased oil volume after huff and puff and the well blocking time.

[0099] The lower the production flow pressure after huff and puff, the higher the oil production that can be obtained in the short term. When the production flow pressure is too low, it affects the energy replenishment effect of subsequent rounds. In some embodiments of the present invention, the production flow pressure is determined based on the correlation curve between the pressure in the near-wellbore area after huff and puff and the production flow pressure, including:

[0100] When determining the production flow pressure, control the pressure in the near-wellbore area to be no lower than the pressure before throughput.

[0101] The more throughput cycles there are, the less oil increase in a single cycle and the lower the oil change rate. In some embodiments of the present invention, the oil change rates of different throughput cycles are simulated and calculated based on a numerical model, and a correlation chart between the oil change rate and the throughput cycles is established. The throughput cycles are optimized to ensure that the oil change rate is greater than 0.3t / t.

[0102] In order to better illustrate the present invention, the following examples are provided.

[0103] Example

[0104] The southwestern part of the X233 area in the Ordos Basin was selected as the test area, and all horizontal wells (YP2, YP3, YP4, YP5, and XY235-42) in the southwestern part of the X233 area were selected as test wells to carry out CO2 injection and extraction tests. The five test wells developed the C72 layer, with a mudstone interlayer of 10.5 to 14.7 m at the top and a mudstone interlayer of 50 to 70 m at the bottom. The five test wells were developed at a distance of 300 to 500 m, and the controlled area was 2.56 km 2 , 1.17 million tons of geological reserves were used, the average horizontal section length of a single well was 1518m, the oil layer drilling rate was 89.6%, 11.6 sections and 23 clusters were transformed, and the amount of sand added was 483m 3 , displacement 6.3m 3 / min, liquid volume entering the ground: 6835m 3 ; In the initial stage of production, the average daily oil production of a single well is 10.9t, with a water content of 27.6%. As of May 2022, the average cumulative oil production of a single well is 13,250 tons, the recovery rate is 5.66%, the oil production rate is 0.39%, and the daily liquid production of a single well is 3.8m 3 , daily oil production is 2.5t, and the comprehensive water content is 34.3%.

[0105] S1: Five horizontal wells (YP2, YP3, YP4, YP5, and XY235-42) in the southwest of the X233 area were selected to carry out CO2 injection and extraction experiments.

[0106] S2: According to 3D seismic data, faults are not developed in the test area, and the maximum difference in pump-off pressure in the reformed section of the five horizontal wells is 2.6 MPa, which is less than 10% of the regional minimum horizontal principal stress (30 MPa). The heterogeneity of the horizontal well section is relatively weak, and general injection is the preferred injection method.

[0107] S3: The depth from the wellhead to the injection layer of the test well is H = 1978m, the average pump-off pressure in the horizontal section is 15.0MPa, and the secondary opening extension pressure of the artificial fracture is calculated according to the hydraulic fracturing theory. 裂缝开启 The pressure is 34.8 MPa. Considering the 90% safety factor and the friction during injection (1-2 MPa), the CO2 density is 0.88 g / cm 3 , the optimal wellhead maximum injection pressure P 注气井口max It is 16.0MPa.

[0108] S4: Establish a three-dimensional geological model and numerical model of the test area, where the numerical model is as follows: Figure 3 As shown, the fracture network development in the test area is simulated through the three-dimensional geological model and fracturing construction parameters, and the daily fluid production, daily oil production and water content of the test well are fitted through the numerical model, with a high degree of conformity.

[0109] According to the numerical model, the oil increase when restoring different formation pressures is simulated and calculated, such as Figure 4 As shown, the second graph of the correlation between the increased oil volume after huff and puff and the formation pressure is established, and the target value of the recovery pressure is determined to be 18.5 MPa.

[0110] According to the test well fracturing transformation data and production dynamic data, the single well injection volume Q is calculated when the formation pressure recovers to 18.5MPa:

[0111] Q=Q1+Q2,

[0112] Q1=V w +V g B g -N p B o -W p -G p B gi

[0113] V=(CV)△p 压裂

[0114] Q2=(CV)△p

[0115] Among them, △p 压裂 is the change in formation pressure after volume fracturing, such as Figure 5 The results show that △p is determined by fitting the formation pressure with the change in wellhead pressure after the well is blocked. 压裂 The value of .

[0116] Calculations show that the injection volume of YP2 well is 17,000 tons, the injection volume of YP3 well is 13,000 tons, the injection volume of YP4 well is 16,000 tons, the injection volume of YP5 well is 16,000 tons, and the injection volume of XP235-42 well is 12,000 tons.

[0117] S5: According to the numerical model, simulate and calculate the oil increase under different gas injection rates, such as Figure 6 As shown, a correlation chart of the increased oil volume after throughput and the gas injection rate of a single well is established. According to the inflection point of the curve of the correlation chart of the increased oil volume after throughput and the gas injection rate of a single well, the gas injection rate of a single well is preferably 155 tons / day.

[0118] S6: According to the established numerical model, simulate and calculate the oil increase under different well blocking time, such as Figure 7 As shown, a correlation chart between the increased oil volume after huff and puff and the well blocking time is established, and the well blocking time is preferably 30-40 days according to the inflection point of the curve.

[0119] S7: According to the numerical model, Figure 8 As shown in FIG. 1 , a correlation curve between the pressure in the near-wellbore zone after huff and puff and the production flow pressure is established. Under the premise of ensuring that the pressure in the near-wellbore zone is not lower than the pressure before huff and puff, the optimal minimum production flow pressure is 8 MPa.

[0120] S8: According to the numerical model, the oil increase at different throughput cycles is simulated and calculated, and a correlation chart between the oil increase after throughput and the throughput cycles is established. When the oil change rate is greater than 0.3t / t, the preferred throughput cycle is 4 cycles. The numerical model predicts that the single well recovery rate can be increased by more than 3%.

[0121] In summary, by adopting the method of the present invention, by optimizing the injection and production parameters of horizontal wells, the problem of gas crossover between wells can be effectively prevented. The optimized injection and production parameters can give full play to the synergistic effects of CO2 swelling energy enhancement, extraction and extraction, improve the seepage capacity of reservoir fluid, and greatly improve the shale oil recovery rate. The predicted recovery rate can be increased by more than 3%.

[0122] Finally, it should be noted that the above is only a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the aforementioned embodiments, it is still possible for those skilled in the art to modify the technical solutions described in the aforementioned embodiments or to make equivalent substitutions for some of the technical features therein. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the protection scope of the present invention.

Claims

1. A shale oil horizontal well huff and puff oil production method, characterized in that: include: All horizontal wells with intact wellbore structures in the test area are selected as test wells; Determine the CO2 injection method according to the fault situation encountered by the horizontal well; Determine the maximum injection pressure at the wellhead based on hydraulic fracturing theory; Establishing a three-dimensional geological model and a numerical model of the test area, determining a target value of recovery pressure using the numerical model, and calculating a single well injection volume according to the target value of recovery pressure; Establishing a first graph of correlation between increased oil volume after throughput and gas injection rate of a single well according to the numerical model, and determining the gas injection rate of a single well according to the first graph of correlation between increased oil volume after throughput and gas injection rate of a single well; Establishing a correlation chart of the increased oil volume after throughput and the well-clogging time according to the numerical model, and determining the well-clogging time according to the correlation chart of the increased oil volume after throughput and the well-clogging time; Establishing a correlation curve between the pressure in the near-wellbore zone after huff and puff and the production flow pressure according to the numerical model, and determining the production flow pressure according to the correlation curve between the pressure in the near-wellbore zone after huff and puff and the production flow pressure; A correlation chart between the oil change rate and the throughput cycles is established according to the numerical model to determine the throughput cycles corresponding to the preset oil change rate.

2. A shale oil horizontal well huff and puff oil production method according to claim 1, characterized in that: At least 10 meters of interlayers are developed at the top and bottom of the target layer for gas injection and energy replenishment in the test area.

3. A shale oil horizontal well huff and puff oil production method according to claim 1, characterized in that: The method of determining the CO2 injection method according to the fault encountered by the horizontal well comprises: When the horizontal well encounters a fault and there is a reformed section near the fault, a segmented injection method is adopted; When the horizontal well does not encounter a fault, and the pump-off pressure range of the reformed section of the horizontal well is less than 10% of the regional minimum horizontal principal stress, a general injection method is adopted; When the horizontal well does not encounter a fault, and the pump-off pressure range of the reformed section of the horizontal well is not less than 10% of the regional minimum horizontal principal stress, a segmented injection method is adopted.

4. A shale oil horizontal well huff and puff oil production method according to claim 1, characterized in that: The method of determining the maximum wellhead injection pressure according to hydraulic fracturing theory includes: The maximum injection pressure at the wellhead is calculated using the following formula: Among them, P 注气井口max is the maximum injection pressure, MPa; P 裂缝开启 is the secondary opening pressure of the crack, MPa; 0.9 is the safety factor; is the CO2 liquid column pressure in the wellbore, MPa; is the density of CO2, g / cm 3 ; H is the depth from the wellhead to the injection layer, m; g is the gravity acceleration, m / s 2 .

5. A shale oil horizontal well huff and puff oil production method according to claim 1, characterized in that: The three-dimensional geological model and numerical model of the test area are established, including: Simulating the fracture network development of the test area by combining the three-dimensional geological model with fracturing construction parameters; The numerical model is used to perform historical matching on the daily fluid production, daily oil production and water content of the horizontal wells in the test area.

6. A shale oil horizontal well huff and puff oil production method according to claim 1, characterized in that: The method of determining the target value of the recovery pressure by using the numerical model includes: According to the numerical model, the oil increase when restoring different formation pressures is simulated and calculated, a second graph of the correlation between the oil increase after throughput and the formation pressure is established, and the target value of the restored pressure is determined according to the inflection point of the curve of the second graph of the correlation between the oil increase after throughput and the formation pressure.

7. A shale oil horizontal well huff and puff oil production method according to claim 1, characterized in that: The calculation of the single well injection volume according to the recovery pressure target value includes: Calculate the formation deficit Q1 when the pressure returns to the original formation pressure: Q1=V w +V g B g -N p B o -W p -G p B gi Among them, V w is the cumulative water injection volume, m 3 ; V g is the cumulative gas injection volume, m 3 ; N p is the cumulative oil production, m 3 ; W p is the cumulative water production, m 3 ; G p is the cumulative gas production, m 3 ; B o is the crude oil volume coefficient, m 3 / m 3 ; B gi is the volume coefficient of produced gas, m 3 / m 3 ; B g is the volume coefficient of injected gas, m 3 / m 3 ; Calculate the injection volume Q2 from the original formation pressure to the target recovery pressure value: V=(CV)△p 压裂 Q2=(CV)△p Where V is the amount of liquid entering the ground, MPa; △p 压裂 is the change in formation pressure after volume fracturing, MPa; CV is the product of the comprehensive compression coefficient and the horizontal well control volume; △p is the difference between the recovery pressure target value and the original formation pressure; The single well injection volume Q=Q1+Q2.

8. A shale oil horizontal well huff and puff oil production method according to claim 1, characterized in that: The method of determining the single well gas injection rate according to the first chart of the correlation between the increased oil volume after throughput and the single well gas injection rate comprises: The single well gas injection rate is determined according to the inflection point of the curve of the first graph of the correlation between the increased oil volume after throughput and the single well gas injection rate.

9. A shale oil horizontal well huff and puff oil production method according to claim 1, characterized in that: The method of determining the well blocking time according to the correlation chart of the increased oil volume after throughput and the well blocking time includes: The well blocking time is determined according to the inflection point of the curve of the correlation chart of the increased oil volume after the throughput and the well blocking time.

10. A shale oil horizontal well huff and puff oil production method according to claim 1, characterized in that: The method of determining the production flow pressure according to the correlation curve between the pressure in the near-wellbore area after the huff-and-puff and the production flow pressure comprises: When determining the production flow pressure, control the pressure in the area near the wellbore to be no lower than the pressure before throughput.

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