A shale oil horizontal well huff and puff method

Abstract

The present application belongs to the field of oil development, and discloses a shale oil horizontal well injection-production method, which comprises the following steps: selecting all horizontal wells in a test area as test wells; determining a CO2 injection mode; determining a maximum injection pressure at a wellhead; building a three-dimensional geological model and a numerical model of the test area, determining a recovery pressure target value, and calculating a single-well injection amount; determining a single-well gas injection speed; determining a well blanking time; determining a production flow pressure; and determining a preset oil replacement rate corresponding to a huff and puff cycle. The present application can effectively prevent the problem of gas channeling between wells by optimizing the injection-production parameters of the horizontal well, and the optimized injection-production parameters can fully play the synergistic effect of CO2 swelling energy increase, extraction and extraction, improve the reservoir fluid percolation capacity, greatly improve the shale oil recovery rate, and predict that the recovery rate can be increased by more than 3%.

Description

TECHNICAL FIELD

[0001] The present application belongs to the field of oil development, and particularly relates to a shale oil horizontal well huff and puff oil production method. BACKGROUND

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

[0003] Gas injection is the main way of shale oil enhanced oil recovery, the injected medium is mainly CO2 and other gas media, and the gas injection mode of huff and puff is mainly adopted. The following three important understandings are obtained through field huff and puff test: first, the key to successful huff and puff is to ensure that the injected gas is sealed in the fracture volume; second, a large enough fracture contact area is the key to improve the huff and puff effect; third, selecting a reasonable huff and puff mode and injection and production parameter design is an important basis for guaranteeing the huff and puff effect.

[0004] Shale oil reservoir is low-porosity and dense, and part of it has natural fractures, due to low natural production capacity, most of them are developed by volume fracturing. However, after volume fracturing, the reservoir heterogeneity is aggravated, and when the horizontal well is huffed and puffed, the injected gas quickly advances along the direction of artificial fracturing cracks, which is easy to cause gas channeling of adjacent wells.

[0005] Therefore, it is necessary to provide a shale oil horizontal well huff and puff injection and production method, which can prevent the diffusion of injected CO2 from getting out of control, avoid gas channeling of adjacent wells, optimize injection and production parameters, and improve the oil production after CO2 injection. SUMMARY

[0006] In order to overcome the defects of the prior art, the purpose of the present application is to provide a shale oil horizontal well huff and puff injection and production method, which can prevent the diffusion of injected CO2 from getting out of control, avoid gas channeling of adjacent wells, optimize injection and production parameters, and improve the oil production after CO2 injection.

[0007] In order to achieve the above purpose, the present application provides the following technical scheme:

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

[0009] Select all horizontal wells with intact wellbore structure in the test area as test wells;

[0010] Determine the CO2 injection mode according to the drilled fault condition of the horizontal well;

[0011] Determine the maximum injection pressure at the wellhead according to the hydraulic fracturing theory;

[0012] A three-dimensional geological model and a numerical model of the test area are established, the numerical model is used to determine a recovery pressure target value, and a single-well injection amount is calculated according to the recovery pressure target value;

[0013] A first correlation chart of an oil increment after huff and puff and a single-well gas injection speed is established according to the numerical model, and the single-well gas injection speed is determined according to the first correlation chart of the oil increment after huff and puff and the single-well gas injection speed;

[0014] A correlation chart of an oil increment after huff and puff and a well-shut-in time is established according to the numerical model, and the well-shut-in time is determined according to the correlation chart of the oil increment after huff and puff and the well-shut-in time;

[0015] A correlation curve of a near-wellbore pressure after huff and puff and a production flow pressure is established according to the numerical model, and the production flow pressure is determined according to the correlation curve of the near-wellbore pressure after huff and puff and the production flow pressure;

[0016] A correlation chart of an oil replacement rate and a huff and puff cycle is established according to the numerical model, and a huff and puff cycle corresponding to a preset oil replacement rate is determined.

[0017] In some embodiments of the present application, at least 10-meter interbeds are developed at the top and bottom of a gas injection energy supplement target layer where the test area is located.

[0018] In some embodiments of the present application, a CO2 injection mode is determined according to a fault drilled by a horizontal well, including:

[0019] When the horizontal well drills a fault and there is a transformation section near the fault, a segmented injection mode is adopted;

[0020] When the horizontal well does not drill a fault and a pump pressure difference of a transformation section of the horizontal well is less than 10% of a regional minimum horizontal principal stress, a general injection mode is adopted;

[0021] When the horizontal well does not drill a fault and the pump pressure difference of the transformation section of the horizontal well is not less than 10% of the regional minimum horizontal principal stress, the segmented injection mode is adopted.

[0022] In some embodiments of the present application, a maximum injection pressure at a wellhead is determined according to a hydraulic fracturing theory, including:

[0023] The maximum injection pressure at the wellhead is calculated by using the following formula,

[0024]

[0025]

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

[0027] In some embodiments of the present application, a three-dimensional geological model and a numerical model of the test area are established, comprising:

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

[0029] The daily liquid production, daily oil production and water content of the horizontal well in the test area are history-matched by the numerical model.

[0030] In some embodiments of the present application, the numerical model is used to determine the recovery pressure target value, comprising:

[0031] According to the numerical model, the oil increment when different formation pressures are recovered is simulated and calculated, a second graph of the oil increment after stimulation and the formation pressure correlation is established, and the recovery pressure target value is determined according to the inflection point of the curve of the second graph of the oil increment after stimulation and the formation pressure correlation.

[0032] In some embodiments of the present application, the single-well injection amount is calculated according to the recovery pressure target value, comprising:

[0033] The formation depletion Q1 when the pressure is recovered to the original formation pressure is calculated:

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

[0035] Wherein, V w is the cumulative injected water amount, m 3 ; V g is the cumulative injected gas amount, m 3 ; N p is the cumulative oil production amount, m 3 ; W p is the cumulative water production amount, m 3 ; G p is the cumulative gas production amount, m 3 ; B o is the crude oil volume coefficient, m 3 / m 3 ; B gi is the gas production volume coefficient, m 3 / m 3 ; B gFor injection gas volume coefficient, m 3 / m 3 ;

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

[0037] V=(CV)△p 压裂

[0038] Q2=(CV)△p

[0039] Wherein, V is the liquid volume into the ground, MPa;△p 压裂 The volume of the fractured formation pressure change value, 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 amount Q=Q1+Q2.

[0041] In some embodiments of the application, the single well gas injection speed is determined according to the first chart of the correlation between the oil increment after the throughput and the single well gas injection speed, comprising:

[0042] According to the curve inflection point of the first chart of the correlation between the oil increment after the throughput and the single well gas injection speed, the single well gas injection speed is determined.

[0043] In some embodiments of the application, the soaking time is determined according to the chart of the correlation between the oil increment after the throughput and the soaking time, comprising:

[0044] According to the curve inflection point of the chart of the correlation between the oil increment after the throughput and the soaking time, the soaking time is determined.

[0045] In some embodiments of the application, the production flow pressure is determined according to the correlation curve between the near wellbore pressure after the throughput and the production flow pressure, comprising:

[0046] When determining the production flow pressure, the near wellbore pressure is controlled to be not lower than the pressure before the throughput.

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

[0048] The present application can effectively prevent the interwell gas channeling problem by optimizing the injection-production parameters of the horizontal well throughput, and the optimized injection-soaking-production parameters can fully play the synergies of CO2 swelling energy extraction and extraction, improve the reservoir fluid percolation capacity, and greatly improve the shale oil recovery rate, and the predicted recovery rate can be increased by more than 3%.

[0049] Other features and advantages of the present application will be described in the subsequent specification, and some will become apparent from the specification, or will be understood by those skilled in the art through implementation of the present application. The purpose and other advantages of the present application can be achieved and obtained by the structure indicated in the specification, claims and drawings. BRIEF DESCRIPTION OF DRAWINGS

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

[0051] Figure 2 A flow chart of determining CO2 injection mode of the present application;

[0052] Figure 3 A numerical model schematic diagram of the example test area;

[0053] Figure 4 A second graph of the example huff and puff oil production amount and formation pressure correlation;

[0054] Figure 5 A wellhead pressure broken line graph during the example well shut-in period after hydraulic fracturing;

[0055] Figure 6 A graph of the example huff and puff oil production amount and single well gas injection speed correlation;

[0056] Figure 7 A graph of the example huff and puff oil production amount and shut-in time correlation;

[0057] Figure 8 A graph of the example huff and puff oil production amount and production flow pressure correlation. DETAILED DESCRIPTION

[0058] The technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application. Obviously, the described embodiments are only part of the embodiments of the present application, rather than all the embodiments of the present application. Based on the embodiments in the present application, all other embodiments obtained by those of ordinary skill in the art without creative work fall within the protection scope of the present application.

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

[0060] Selecting all horizontal wells with intact wellbore structures in the test area as test wells;

[0061] Determining the CO2 injection mode according to the drilled fault conditions of the horizontal wells;

[0062] Determining the maximum injection pressure at the wellhead according to the hydraulic fracturing theory;

[0063] Building a three-dimensional geological model and a numerical model of the test area, determining the recovery pressure target value by using the numerical model, and calculating the single well injection amount target value according to the recovery pressure;

[0064] The first chart of the correlation between the increased oil production after huff and puff and the gas injection rate of a single well is established based on the numerical model, and the gas injection rate of a single well is determined based on the first chart of the correlation between the increased oil production 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 time of well blocking is established based on the numerical model, and the time of well blocking is determined based on the correlation chart of the increased oil volume after huff and puff and the time of well blocking.

[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] Based on the numerical model, a correlation chart between oil change rate and throughput cycles is established 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 gas injection energy replenishment layer in the test area.

[0070] It should be noted that when the interlayer thickness is less than 10m, the water cut in the horizontal well declines slowly, resulting in low initial daily oil production within the 100-meter oil layer. Analysis of pressure tests performed on adjacent vertical wells during horizontal well fracturing indicates that when the interlayer thickness is 10m or greater, the likelihood of vertical fracture height communication is low.

[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 staged injection method is used;

[0073] When the horizontal well does not encounter a fault and the pump-off pressure range of the horizontal well's stimulation 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 pump-off pressure in the stimulation section of the horizontal well is not less than 10% of the regional minimum horizontal principal stress, a staged injection method is adopted. For example, perforation sections with similar pump-off pressures are combined into one section for staged injection.

[0075] In some embodiments of the present invention, the maximum injection pressure at the wellhead 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 injection pressure at the wellhead is calculated using the following formula:

[0077]

[0078]

[0079] wherein, P 注气井口max is the maximum injection pressure, MPa; P 裂缝开启 is the fracture re-opening pressure, MPa; 0.9 is the safety factor; is the CO2 liquid column pressure in the wellbore, MPa; is the CO2 density, the CO2 density corresponding to the temperature and pressure is selected, g / cm 3 ; H is the depth from the wellhead to the injection horizon, m; g is the acceleration of gravity, m / s 2 .

[0080] In some embodiments of the present application, a three-dimensional geological model and a numerical model of the test area are established, comprising:

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

[0082] The daily liquid production, daily oil production and water content of the horizontal well in the test area are history-matched by the numerical model, and are optimized and adjusted to meet the requirements.

[0083] In some embodiments of the present application, the numerical model is used to determine the recovery pressure target value, comprising:

[0084] According to the numerical model, the oil increment when different formation pressures are recovered is simulated and calculated, a second graph of the oil increment after stimulation and the formation pressure correlation is established, and the recovery pressure target value is determined according to the curve inflection point of the second graph of the oil increment after stimulation and the formation pressure correlation.

[0085] In some embodiments of the present application, due to the strong heterogeneity of shale oil reservoirs, the adaptability of the theoretical calculation used in conventional reservoirs is poor, and the acquisition of reservoir and fluid parameters needs to be considered at the same time, a new method for calculating single well injection volume is established,

[0086] According to the recovery pressure target value, the single well injection volume is calculated, comprising:

[0087] The formation depletion volume Q1 when the pressure is recovered to the original formation pressure is calculated:

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

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

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

[0091] V=(CV)△p 压裂

[0092] Q2=(CV)△p

[0093] Wherein, V is the liquid volume into the ground, MPa; △p 压裂 is the volume fracturing formation pressure change value, 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] The single well gas injection speed is small, which will affect the production rate, and the single well gas injection speed is too large, the risk of gas channeling increases, which will adversely affect the effect of increasing production, in some embodiments of the present application, the single well gas injection speed is determined according to the first chart of the correlation between the oil increment after stimulation and the single well gas injection speed, including:

[0096] The single well gas injection speed is determined according to the curve inflection point of the first chart of the correlation between the oil increment after stimulation and the single well gas injection speed.

[0097] The well soaking time is too short, CO2 diffusion is insufficient, and the oil replacement efficiency is low; the well soaking time is too long, the diffusion range is too large, and the pressure recovery is affected, in some embodiments of the present application, the well soaking time is determined according to the correlation chart of the oil increment after stimulation and the well soaking time, including:

[0098] The well soaking time is determined according to the curve inflection point of the correlation chart of the oil increment after stimulation and the well soaking time.

[0099] The lower the production flow pressure after the stimulation, the higher the oil production that can be obtained in the short term. When the production flow pressure is too low, the energy supplement effect of the subsequent cycle is affected. In some embodiments of the present application, the production flow pressure is determined according to the near-wellbore pressure after stimulation versus production flow pressure correlation curve, including:

[0100] When determining the production flow pressure, the near-wellbore pressure is controlled to be no lower than the pre-stimulation pressure.

[0101] The more the stimulation cycles, the lower the oil increment in a single cycle and the lower the oil replacement rate. In some embodiments of the present application, the oil replacement rate of different stimulation cycles is simulated and calculated according to the numerical model, and a correlation chart of the oil replacement rate and the stimulation cycle is established, and the stimulation cycle is optimized to ensure that the oil replacement rate is greater than 0.3 t / t.

[0102] In order to better illustrate the present scheme, the following embodiments are provided.

[0103] Embodiment

[0104] The southwest part of X233 area in Ordos Basin is taken as a test area, and all the horizontal wells (YP2, YP3, YP4, YP5, XY235-42) in the southwest part of X233 area are taken as test wells to carry out CO2 injection stimulation test. The five test wells develop C72 layer, and the top develops 10.5-14.7m of mudstone interlayer, and the bottom develops 50-70m of mudstone interlayer. The development well spacing of the five test wells is 300-500m, and the control area is 2.56km 2 , the producing geological reserves are 1.17 million tons, the average single well horizontal section length is 1518m, the oil layer drilling rate is 89.6%, 11.6 sections and 23 clusters are transformed, the sand injection amount is 483m 3 , the displacement is 6.3m 3 / min, the ground liquid amount is 6835m 3 ; the average daily oil production of a single well in the early production stage is 10.9t, and the water content is 27.6%. As of May 2022, the average single well cumulative oil production is 13250 tons, the recovery degree is 5.66%, the oil production rate is 0.39%, the single well daily liquid production is 3.8m 3 , the daily oil production is 2.5t, and the comprehensive water content is 34.3%.

[0105] S1: Select five horizontal wells (YP2, YP3, YP4, YP5, XY235-42) in the southwest part of X233 area to carry out CO2 injection stimulation test.

[0106] S2: According to the three-dimensional seismic data, the test area has no developed faults, the maximum difference of the pump-off pressure of the transformation section of the five horizontal wells is 2.6MPa, which is less than 10% of the minimum horizontal principal stress (30MPa), the horizontal well section has relatively weak heterogeneity, and the injection mode is preferably general injection.

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

[0108] S4: The three-dimensional geological model and the numerical model of the test area are built, wherein the numerical model is shown as Figure 3 The fracture network development situation of the test area is simulated through the three-dimensional geological model and the fracturing construction parameters, and the daily liquid production, the daily oil production and the water content of the test well are fitted through the numerical model, and the fitting degree is high.

[0109] According to the numerical model, the oil increment when the different formation pressures are restored is simulated and calculated, as shown in Figure 4 The second graph of the oil increment after the huff and puff and the formation pressure correlation is established, and the target value of the pressure recovery is determined as 18.5 MPa.

[0110] According to the fracturing reconstruction data and the production dynamic data of the test well, the injection amount Q of the single well when the formation pressure is restored to 18.5 MPa is calculated:

[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] Wherein,△p 压裂 is the formation pressure change value after the volume fracturing, as shown in Figure 5 The value of△p 压裂 is determined by fitting the formation pressure through the wellhead pressure change after the well is sealed.

[0116] The injection amount of YP2 well is calculated as 17,000 tons, the injection amount of YP3 well is calculated as 13,000 tons, the injection amount of YP4 well is calculated as 16,000 tons, the injection amount of YP5 well is calculated as 16,000 tons, and the injection amount of XP235-42 well is calculated as 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 production after huff and puff 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 production after huff and puff 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 production increase under different well blocking time, such as Figure 7 As shown in FIG, a correlation chart between the increased oil production 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 Figure 1, a correlation curve between the pressure in the near-wellbore area after huff and puff and the production flow pressure is established. Under the premise of ensuring that the pressure in the near-wellbore area is not lower than the pressure before huff and puff, the optimal minimum production flow pressure is 8 MPa.

[0120] S8: Based on the numerical model, simulate and calculate the oil production increase at different throughput cycles, and establish a correlation chart between the oil production increase after throughput and the throughput cycles. When the oil change rate is greater than 0.3t / t, the optimal 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, the method of the present invention can effectively prevent inter-well gas channeling problems by optimizing the horizontal well throughput injection and production parameters. The optimized injection and production parameters can give full play to the synergistic effects of CO2 swelling energy enhancement, extraction and extraction, improve the permeability of reservoir fluids, and greatly improve the shale oil recovery rate. It is predicted that the 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, those skilled in the art can still modify the technical solutions described in the aforementioned embodiments or 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 scope of protection 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 were 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; simulating and calculating the oil increase when restoring different formation pressures based on the numerical model; establishing a second chart showing the correlation between the oil increase after huffing and puffing and the formation pressure; determining a target value for the restored pressure based on the inflection point of the curve of the second chart showing the correlation between the oil increase after huffing and puffing and the formation pressure; and calculating the single-well injection rate based on the target value for the restored pressure. Calculating the single-well injection rate based on the target value for the restored pressure 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 ; Vg 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 ; Calculate the injection volume Q2 from the initial 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 compressibility coefficient and the horizontal well control volume; △p is the difference between the target recovery pressure and the original formation pressure; The single well injection volume Q=Q1+Q2; Establishing a first graph showing the correlation between the increased oil production after huff and puff and the 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 showing the correlation between the increased oil production after huff and puff and the gas injection rate of a single well; Establishing a correlation chart between the increased oil volume after huff and puff and the well-clogging time according to the numerical model, and determining the well-clogging time according to the correlation chart between the increased oil volume after huff and puff and the well-clogging time; Establishing a correlation curve between the pressure in the near-wellbore area 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 area after huff and puff and the production flow pressure; A correlation chart between the oil change rate and the throughput cycles is established based on 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: The top and bottom of the target layer for gas injection and energy replenishment in the test area are both developed with interlayers of at least 10 meters.

3. The method for producing shale oil by huff-and-puff production in a horizontal well according to claim 1, wherein: The method of determining the CO2 injection mode 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 staged injection method is adopted; When the horizontal well does not encounter a fault and the pump-off pressure range of the stimulation 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 staged injection method is adopted.

4. The method for producing shale oil by huff-and-puff production in a horizontal well according to claim 1, wherein: 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 CO2 density, g / cm 3 ; H is the depth from the wellhead to the injection layer, m; g is the acceleration of gravity, m / s 2 .

5. The method for producing shale oil by huff-and-puff production in a horizontal well according to claim 1, wherein: The establishment of the three-dimensional geological model and numerical model of the test area includes: Simulating the fracture network development of the test area by combining the three-dimensional geological model with the fracturing operation 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. The method for producing shale oil from a horizontal well according to claim 1, wherein: The determining of the single-well gas injection rate according to the first chart of the correlation between the increased oil volume after huff-and-puff 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 production after huff-and-puff and the single-well gas injection rate.

7. The method for producing shale oil from a horizontal well according to claim 1, wherein: The determining of 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 huff and puff and the well blocking time.

8. The method for producing shale oil from a horizontal well according to claim 1, wherein: The determining of the production flow pressure according to the correlation curve between the pressure in the near-wellbore area after huff-and-puff and the production flow pressure includes: When determining the production flow pressure, the pressure in the area near the wellbore should be controlled to be no lower than the pressure before huff and puff.

Images