Fracturing construction process for improving fracture height crossing expanding force of hydraulic fracture of heterogeneous reservoir

Abstract

The invention discloses a fracturing construction process for improving hydraulic fracture height crossing expansive force of a heterogeneous reservoir. The fracturing construction process comprises the following steps: S1, site selection: geological exploration and evaluation, reservoir characteristic analysis and investment cost and income prediction; s2, horizontal borehole trajectory design, wherein the inclination angle of a borehole and the trajectory and length of a horizontal section are determined; s3, perforation position selection: proper perforation positions and intervals are selected; s4, optimizing the size of a perforation hole: adopting perforation with a uniform aperture; s5, designing fracturing fluid and adding filling particles: selecting the type of the fracturing fluid and adding a small-particle-size proppant; s6, hydraulic fracturing operation, wherein liquid is injected, fracturing is monitored, and evaluation is conducted after fracturing; and S7, post-treatment: crack cleaning, production test and the like. According to the method, the longitudinal layer penetrating capacity of the crack is improved and the height of the crack is increased in the mode of large-hole small-hole-number energy-gathered fracturing, the high-edge oriented perforation process and the superfine propping agent accompanying injection.

Description

Technical Field

[0001] The present invention belongs to the technical field of heterogeneous reservoir stimulation in shale oil and gas resource development, and particularly relates to a fracturing construction process for enhancing the cross-layer extension force of hydraulic fractures in heterogeneous reservoirs. Background Art

[0002] Heterogeneous interbedded shale oil reservoirs often have high resource potential. With the progress of exploration technologies, the commercial value of these reservoirs has gradually emerged. Compared with shale gas reservoirs, heterogeneous oil and gas reservoirs have large differences in physical properties between reservoir layers, extremely poor porosity and permeability, which makes the development more difficult and requires more precise technologies. Especially the stress shielding problem in heterogeneous reservoirs severely restricts the longitudinal cross-layer extension distance of reservoir hydraulic fractures, limits the effective length and conductivity of fractures, and thus affects the effective production efficiency of oil and gas. At present, on-site operations mainly use preflush high-viscosity fracturing fluid to enhance the extension ability of fracture height, but the effect is not good. The application of high-viscosity fracturing fluid requires a relatively high applied pressure. Excessive pressure may reach capillary pressure or fracture pressure, resulting in the inability of the fracture to further expand, causing the fracture to stagnate after initial expansion and unable to achieve the designed expansion effect. The relatively high resistance between the high-viscosity fracturing fluid and the rock during injection and the filtration during flow in the rock lead to a decrease in effective pressure and the inability to generate sufficient fracture extension force. Moreover, in heterogeneous reservoirs, fracture development is affected by various factors such as formation stress and physical properties, and high-viscosity fluids may not be able to effectively guide the growth of fracture height. Therefore, there is an urgent need for a fracturing construction process to improve the cross-layer extension ability of hydraulic fracturing fractures in this type of formation. Summary of the Invention

[0003] The present invention is proposed to solve the problems of low effective pressure, uncertainty in fracture propagation direction, and fracture propagation stagnation during the fracturing of heterogeneous interbedded shale oil reservoirs in the prior art, and its purpose is to provide a fracturing construction process for enhancing the cross-layer extension force of hydraulic fractures in heterogeneous reservoirs.

[0004] The present invention is achieved through the following technical solutions:

[0005] A fracturing construction process for enhancing the cross-layer extension force of hydraulic fractures in heterogeneous reservoirs, comprising the following steps:

[0006] S1. Site Selection

[0007] Based on geological exploration and evaluation, analyze reservoir characteristics, predict investment costs and benefits, and select the horizontal wellbore location;

[0008] Geological exploration is based on reservoir characteristics (porosity, permeability, formation pressure, etc.) and heterogeneity analysis (such as lithology, pore structure, permeability difference, etc.);

[0009] The evaluation criteria follow the general practices in the field of petroleum engineering. For example, reservoir physical property distribution analysis is carried out using geological modeling software (such as Petrel); the formation stress state is evaluated in combination with the fracture breakdown pressure prediction model; the return on investment (ROI) is predicted through an economic analysis model; the specific criteria are flexibly adjusted according to the actual reservoir conditions and engineering objectives.

[0010] The reservoir characteristics include porosity, permeability, and formation pressure.

[0011] Reservoir heterogeneity analysis evaluates whether the reservoir has the potential for longitudinal cross-layer fracture propagation (such as low stress difference areas and the degree of natural fracture development) through the fracture breakdown pressure model and fracture propagation simulation; economic feasibility is comprehensively weighed by combining investment costs (such as drilling costs and fracturing fluid costs) and expected revenues (oil and gas production); engineering goal-oriented. For example, if the reservoir permeability is extremely low but the fracture development potential is high, even if the porosity is low, economic production may still be achieved through optimized perforation and fracturing designs; in practical applications, the appropriate range of specific reservoir parameters needs to be determined through numerical simulations (such as finite element analysis and fluid flow simulation) and field tests.

[0012] S2. Horizontal wellbore trajectory design

[0013] Determine the horizontal wellbore trajectory of the wellbore and decide the horizontal wellbore trajectory in combination with heterogeneity analysis.

[0014] The horizontal wellbore trajectory includes the inclination angle and the length of the horizontal section of the wellbore.

[0015] The inclination angle and the length of the horizontal section of the wellbore are determined according to the well depth, well deviation angle, azimuth angle, coordinate parameters, flexure parameters, and the fracture breakdown pressure prediction model of the heterogeneous reservoir.

[0016] S21. Determination of the inclination angle of the wellbore. The specific method is as follows:

[0017] S211. Determine the inclination angle range according to the reservoir burial depth:

[0018] For shallow reservoirs with a reservoir burial depth < 1500m, the inclination angle is 30° - 45° to smoothly transition to the horizontal section and reduce the drilling difficulty.

[0019] For medium-deep reservoirs with a reservoir burial depth between 1500m and 3000m, the inclination angle is 45° - 60° to ensure that the wellbore effectively enters the target layer.

[0020] For ultra-deep reservoirs with a reservoir burial depth > 3000m, the inclination angle is 60° - 90° to quickly penetrate the overburden layer and reduce the friction caused by wellbore bending.

[0021] S212. Analyze the influence of geological structures

[0022] When there are faults, folds or complex lithological interfaces in the reservoir, analyze the structural morphology through 3D seismic data and geological modeling (such as Petrel software), and adjust the inclination angle to avoid drilling into high-risk areas;

[0023] S213. Match the in-situ stress direction

[0024] Determine the direction of the maximum horizontal principal stress (σ~H~) through in-situ stress tests (such as borehole wall sloughing method, micro-fracture test) or seismic inversion; the horizontal wellbore trajectory is perpendicular to the direction of the maximum horizontal principal stress (i.e., along the direction of the minimum principal stress σ~h~) to utilize the natural propagation law of hydraulic fracturing and promote the longitudinal penetration of fractures through the reservoir layers; if the in-situ stress direction does not match the reservoir boundary, adjust the inclination angle to optimize the stress field matching;

[0025] The horizontal wellbore trajectory preferably selects the fracture-developed area, and the fracture-developed area is the area with low stress difference.

[0026] S214. Optimize the well inclination angle and azimuth

[0027] Use wellbore trajectory design software (such as Landmark Compass) to simulate the wellbore path at different inclination angles, and combine with the dogleg severity analysis (DLS) to determine the maximum allowable curvature to avoid drill string sticking;

[0028] The calculation formula for the dogleg severity is:

[0029] DLS = 30×Δθ / L

[0030] In the formula: DLS is the dogleg severity, with the unit of ° / 30m; Δθ is the change in well inclination angle, with the unit of °; L is the well section length, with the unit of m;

[0031] S215. Determine the inclination angle of the final wellbore by combining steps S211 - S2145;

[0032] S22. Method for determining the horizontal section length, and the specific method is:

[0033] S221. Evaluate reservoir heterogeneity

[0034] Determine the location of the fracture-intensive zone in the reservoir through natural fracture identification techniques (such as imaging logging, microseismic monitoring), and the horizontal section should cover these areas as much as possible;

[0035] When the reservoir heterogeneity is strong (such as large permeability difference), it is necessary to design the horizontal section length in segments and preferentially extend to the high-permeability area;

[0036] S222. Analyze the stress difference

[0037] Use a fracture propagation simulation software (such as Meyer Fracturing) to predict the fracture extension range at different horizontal section lengths, and select a low stress difference area (Δσ < 5 MPa) to reduce the fracture propagation resistance and enhance the ability of the fracture height to penetrate layers;

[0038] S223. Determine the perforation cluster spacing

[0039] Match the horizontal section length with the perforation cluster spacing (usually 20 m to 50 m) to ensure that the fracturing fluid can evenly cover the target area;

[0040] The calculation formula for the number of perforation clusters is:

[0041] N cluster =L horizontal / S cluster Ncluste

[0042] In the formula: N cluster is the number of perforation clusters, in units of; S cluster is the perforation cluster spacing, in units of; L horizontal is the horizontal section length, in units of m;

[0043] The definitions and measurement methods of the well depth, well deviation angle, azimuth angle, coordinates, and DLS are common technologies in the industry. The fracture breakdown pressure prediction model for heterogeneous reservoirs is based on GOHFER or ABAQUS. Input the grid data of the heterogeneous reservoir and simulate the fracture propagation process;

[0044] S3. Select appropriate perforation positions and perforation spacings;

[0045] Use the fracture breakdown pressure prediction model for heterogeneous reservoirs to calculate the breakdown pressure at different perforation densities according to the horizontal well in-situ stress, well deviation angle, azimuth angle, poroelastic coefficient, permeability coefficient, rock tensile strength, perforating charge depth, perforating charge aperture, etc., and select appropriate perforation positions and spacings; the perforation cluster spacing determines the distance between clusters, and the perforation spacing determines the interval between holes within the cluster;

[0046] The designed perforation spacing helps to reduce the flow interference around the wellbore, enabling the fracture to better propagate at a higher pressure when injecting the fracturing fluid;

[0047] The design of the perforation spacing needs to consider the influence of reservoir heterogeneity, formation stress state, fluid properties, and economic factors. It is necessary to combine various methods such as geological models, fracture simulations, optimization algorithms, and field tests to formulate the best perforation strategy. The comprehensive calculation formula for the perforation spacing is:

[0048] D opt =D sim ·f geo ·f econ

[0049] Wherein:

[0050] D opt is the perforation interval, i.e., the optimal perforation density, with the unit of holes / meter;

[0051] D sim is the perforation density obtained based on simulation, with the unit of holes / meter;

[0052] f geo is the adjustment factor considering geological heterogeneity, with the unit of dimensionless;

[0053] f econ is the adjustment factor considering economic factors, with the unit of dimensionless;

[0054] The calculation formula for the adjustment factor considering geological heterogeneity is:

[0055] f geo = 1 + α·CV lith + β·Δσ - γ·FDI

[0056] In the formula: α, β, γ are weight coefficients, determined by regression of historical data or experimental calibration, α = 0.4, β = 0.15, γ = 0.1;

[0057] CV lith is the lithology variation coefficient. By logging data or core analysis, the distribution difference of different lithologies (such as sandstone, mudstone) is calculated. Its calculation formula is: CV lith = standard deviation of lithology thickness / average lithology thickness;

[0058] Δσ is the stress difference coefficient, and its calculation formula is: Δσ = σH - σh

[0059] In the formula: σH is the maximum horizontal principal stress, with the unit of MPa; σh is the minimum horizontal principal stress, with the unit of MPa;

[0060] FDI is the fracture density index, and the number of natural fractures per unit volume is counted through imaging logging or microseismic data; the calculation formula for the fracture density index is: FDI = total fracture length / reservoir volume

[0061] The unit of the total fracture length is m;

[0062] The unit of the reservoir volume is m 3 ;

[0063] Perforation density adjustment based on the calculated adjustment factor f geo considering geological heterogeneity:

[0064] Reservoir heterogeneity:

[0065] High heterogeneity reservoir: fgeo > 1, the perforation density needs to be increased to improve connectivity;

[0066] Low heterogeneity reservoir: f geo ≈ 1, the perforation density can be appropriately reduced;

[0067] Formation stress state:

[0068] High stress difference: f geo > 1, the perforation density needs to be increased to relieve stress concentration;

[0069] Low stress difference: f geo ≈ 1, the perforation density can be appropriately reduced;

[0070] Degree of fracture development:

[0071] Natural fractures developed: f geo < 1, the perforation density can be reduced;

[0072] No natural fractures: f geo > 1, the perforation density needs to be increased.

[0073] The perforation density D obtained based on the simulation sim is calculated according to the literature "KAREEM Hasanain J.; HASINI Hasril; ABDULWAHID Mohammed A.. Influence of perforation density distribution on the production performance of horizontal wells [J]. Petroleum Exploration and Development, 2024, 51(02): 409 - 417.";

[0074] The selection of the perforation position uses the high-side directional perforation technology to enhance the perforation energy-gathering ability and avoid the chance of perforation sand burial, appropriately increasing the spacing to ensure that the fractures can effectively propagate during the injection of fracturing fluid and reducing the influence of inter-fracture interference on the fracture height extension;

[0075] The high-side directional perforation technology is as Figure 4 shown, improved from the original spiral perforation technology to the high-side directional perforation technology. Using this technology can minimize the separation phenomenon of proppant and fracturing fluid caused by the inertial effect, minimize the proppant settlement and layering phenomenon induced by the gravity effect, and at the same time reduce the chance of perforation hole sand burial;

[0076] S4. Optimize the perforation hole size

[0077] Use perforation with a uniform aperture. Consistent hole diameters can avoid differences in the fracture pressure of holes in different phases;

[0078] The perforation aperture is determined according to reservoir characteristics, fracturing design, and engineering goals, and needs to be coordinated with the particle size of the small-particle proppant in step S5;

[0079] The selected perforation aperture is 12 mm, which is a verified optimal value applicable to most conventional reservoirs, capable of balancing the shaped charge effect, fracture pressure consistency, and construction feasibility; the 12-mm aperture is slightly larger than that of the previous spiral perforation process. The advantages of this are as follows: the large aperture can enhance the shaped charge effect of perforation, increasing the ability of the fracturing crack to penetrate layers and extend; the uniform aperture can avoid differences in fracture pressure at different phase holes.

[0080] S5. Fracturing fluid design and addition of filling particles

[0081] At the beginning stage of pumping (gel stage), pump the gel to create wide fractures and reduce the filtration of fracturing fluid into small fractures.

[0082] In the remaining stage (high-viscosity proppant-carrying stage), pump high-viscosity fracturing fluid to improve the fluid's proppant-carrying capacity.

[0083] The viscosity of the gel reaches above 500 mPa·s at a shear rate of 170 s -1 The high-viscosity gel can effectively create wide fractures and reduce the filtration of fracturing fluid into microfractures. The selected gel is a crosslinked gel fracturing fluid, such as boron-crosslinked gel or organometallic-crosslinked gel; the crosslinked gel has high viscosity, low filtration, and good fracture-creating ability.

[0084] The viscosity of the high-viscosity fracturing fluid reaches 20400 mPa·s - 400 mPa·s at a shear rate of 170 s -1 The high-viscosity fracturing fluid can effectively carry proppant and ensure the uniform distribution of proppant in the fractures. The selected high-viscosity fracturing fluid is linear gel fracturing fluid or low-crosslinked gel fracturing fluid; linear gel fracturing fluid has high viscosity and good proppant-carrying ability.

[0085] The pumping time of the gel is 10% - 20% of the total pumping time; the pumping volume of the gel is 15% - 30% of the total fracturing fluid volume; the total fracturing fluid volume refers to the sum of the gel and the high-viscosity fracturing fluid.

[0086] Add filling particles. The selected particles are small-size proppants, which are beneficial for filling microfractures near the perforations, forcing the liquid into the main fracture channel, thereby improving the overall liquid efficiency.

[0087] The small-size proppants are used to fill the inside of the fracture, forming temporary plugging inside the fracture, promoting the extension of the main fracture, and achieving the purpose of enhancing the fracture height extension.

[0088] The particle size of the small-size proppants is determined according to reservoir characteristics, fracturing design, and engineering objectives; the specific range can be adjusted according to the actual situation, and the most suitable proppant particle size is selected through numerical simulation, laboratory testing, and field tests.

[0089] The particle size of the small-particle-size proppant is usually selected to be 200 mesh to 400 mesh (about 37 μm to 74 μm), and 300 mesh is selected in this embodiment.

[0090] S6. Hydraulic fracturing operation

[0091] Inject liquid, and inject the fracturing fluid by means of large-displacement pumping to reduce the influence caused by liquid filtration and improve the longitudinal fracture propagation ability.

[0092] Fracture monitoring, record parameters such as pressure and flow rate to evaluate the effect in real time; post-fracture evaluation, evaluate the fracture propagation effect and initial production.

[0093] S7. Post-treatment:

[0094] Clean the fracture, and pump a small amount of guar gum into the wellbore to clean it.

[0095] Conduct production tests, evaluate the oil and gas production, analyze the fracturing effect and production data, and feedback to the design optimization.

[0096] The beneficial effects of the present invention are:

[0097] The present invention provides a fracturing construction process for improving the vertical fracture penetration force of heterogeneous reservoirs, and uses the method of large-hole small-number shaped charge fracturing + high-side directional perforation technology + ultra-fine proppant co-injection to enhance the vertical penetration ability of fractures; the present invention can effectively solve the problems of low effective pressure, uncertainty of fracture propagation direction and fracture propagation stagnation during the fracturing process of heterogeneous interbedded shale oil reservoirs, improve the vertical penetration ability of fractures, and increase the fracture height. Description of the drawings

[0098] Figure 1 is the process flow chart of the method of the present invention;

[0099] Figure 2 is the schematic diagram before and after perforation optimization of the large-hole small-number shaped charge fracturing + high-side directional perforation technology of the present invention;

[0100] Figure 3 is the front view of the position of the perforation after optimization of the present invention in the target formation;

[0101] Figure 4 is the side view of the position of the perforation after optimization of the present invention in the target formation (the left side shows the relationship between the perforation direction and the high-side direction, the perforation direction is aligned with the high side, and the right side shows the relationship between the perforation depth and the formation profile, and the perforation position is within the target interval);

[0102] Figure 5 is the front view of the distribution of the ultra-fine proppant after fracturing of the present invention;

[0103] Figure 6It is a side view of the distribution of ultra-fine proppants after pressing in the present invention.

[0104] Among them:

[0105] 1 - Interlayer, 2 - Reservoir, 3 - Wellbore, 4 - Perforation spacing, 5 - Cluster spacing, 6 - Perforation, 7 - Horizontal well, 8 - Packers, 9 - High-pressure fluid, 10 - Hydraulic fracture, 11 - Natural fracture, 12 - Injection of ultra-fine proppants.

[0106] For those of ordinary skill in the art, without creative efforts, other relevant drawings can be obtained based on the above drawings. Detailed implementation manners

[0107] In order to enable those skilled in the art of this technology to better understand the technical solution of the present invention, the technical solution of the present invention will be further described below with reference to the drawings in the specification and through specific implementation manners.

[0108] As Figure 1 shown, a fracturing construction process for improving the force of hydraulic fracture height penetration and layer crossing in heterogeneous reservoirs includes the following steps:

[0109] S1. Site selection

[0110] According to geological exploration and evaluation, analyze the reservoir characteristics, and predict the investment cost and benefits;

[0111] The reservoir characteristics include porosity, permeability, and formation pressure;

[0112] S2. Horizontal wellbore trajectory design

[0113] Determine the inclination angle and horizontal section length of the wellbore, and determine the wellbore path in combination with the heterogeneity analysis;

[0114] The wellbore path preferably selects the fracture development area;

[0115] Select the low stress difference area to optimize the balanced fracture propagation;

[0116] The determination of the wellbore path considers the in-situ stress of the formation, selects to arrange the horizontal wellbore in the direction perpendicular to the maximum horizontal in-situ stress, so that the hydraulic pressure can effectively break through the mechanical limit of the formation, and promotes the fracture to expand along the direction of the minimum horizontal in-situ stress. For the azimuth of the wellbore trajectory in the formation in this embodiment, see Figure 2 , 3 shown, the horizontal well 7 passes through the interlayer 1 and enters the reservoir 2, and packers 8 are set in the horizontal section

[0117] The direction of the wellbore 3 is perpendicular to the direction of the maximum horizontal in-situ stress. Perforations 6 are opened in the horizontal section of the horizontal well, and the perforations 6 are evenly distributed in clusters; the cluster spacing 5 of the perforations determines the distance between clusters, and the perforation spacing 4 determines the interval between the perforation holes 6 within the cluster;

[0118] S3. Perforation Location Selection

[0119] Attack the target layer and select appropriate perforation locations and perforation intervals;

[0120] The selection of perforation locations uses high-side directional perforation technology to enhance the perforation energy-gathering ability and avoid the chance of perforation sand burial. Appropriately increase the interval to ensure that the fracture can effectively propagate when the fracturing fluid is injected, and reduce the influence of interference between fractures on the fracture height extension;

[0121] The design of the perforation interval helps to reduce the flow interference around the wellbore, enabling the fracture to better expand under a higher pressure when injecting the fracturing fluid;

[0122] The design of the perforation interval needs to consider the influence of reservoir heterogeneity, formation stress state, fluid properties, and economic factors. It is necessary to combine various methods such as geological models, fracture simulations, optimization algorithms, and field tests to formulate the best perforation strategy. The comprehensive calculation formula for the perforation interval is:

[0123] D opt =D sim ·f geo ·f econ

[0124] Where:

[0125] D opt is the optimal perforation density, with the unit of;

[0126] D sim is the perforation density obtained based on simulation, with the unit of;

[0127] f geo is the adjustment factor considering geological heterogeneity, with the unit of;

[0128] f econ is the adjustment factor considering economic factors, with the unit of;

[0129] The high-side directional perforation technology is as Figure 4 shown. It is improved from the original spiral perforation technology to high-side directional perforation technology. Using this technology can minimize the separation phenomenon of proppant and fracturing fluid caused by the inertial effect, minimize the proppant settlement and stratification phenomenon induced by the gravity effect, and at the same time reduce the chance of perforation hole sand burial;

[0130] S4. Optimize the Perforation Hole Size

[0131] Adopt perforation with a uniform hole diameter. Consistent hole diameters can avoid the difference in fracture pressure of holes in different phases;

[0132] The homogenized aperture perforation selects a 12-mm aperture size, which is slightly larger than the aperture of the previous spiral perforation process. The advantages of this are as follows: The large aperture can enhance the energy-gathering effect of perforation, increasing the ability of the fracturing crack to penetrate through layers; the homogenized aperture can avoid the difference in fracture pressure at different-phase holes.

[0133] S5. Fracturing fluid design and addition of filling particles

[0134] At the beginning stage of pumping, a gel is pumped to create a wide crack, reducing the filtration loss of the fracturing fluid into small cracks. In the remaining stage, a high-viscosity fracturing fluid is selected to improve the sand-carrying capacity of the liquid.

[0135] Filling particles are added. The particles are small-particle-size proppants. The small-particle-size proppants are beneficial for filling the microcracks near the perforations, forcing the liquid into the main crack channel, thereby improving the overall liquid efficiency.

[0136] See Figure 5 、 6 For the small-particle-size proppants, 300-mesh proppants are uniformly selected to fill the inside of the crack 11, forming a temporary plug inside the crack 11 to promote the extension of the main crack 10, achieving the purpose of enhancing the crack height extension.

[0137] S6. Hydraulic fracturing operation

[0138] Inject liquid (high-pressure fluid 9). The fracturing fluid is injected by a large-displacement pumping method to reduce the influence caused by liquid filtration loss and improve the longitudinal extension ability of the crack.

[0139] Fracturing monitoring, recording parameters such as pressure and flow rate to evaluate the effect in real time; post-fracturing evaluation, evaluating the crack extension effect and initial production.

[0140] S7. Post-treatment:

[0141] Clean the crack, pump a small amount of guar gum to clean the wellbore.

[0142] Conduct a production test, evaluate the oil and gas production, analyze the fracturing effect and production data, and feedback to the design optimization.

[0143] The applicant declares that the above is only the specific implementation manner of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily thought of by those skilled in the art within the technical scope disclosed by the present invention fall within the protection scope and the disclosure scope of the present invention.

Claims

1. A fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs, characterized by: The following steps are involved: S1. Analyze reservoir characteristics, predict investment costs and returns, and select horizontal wellbore locations based on geological exploration and evaluation; S2, determine the horizontal wellbore trajectory in combination with heterogeneity analysis; S3, determining the perforation position and perforation spacing; S4. Optimize the perforation hole size; S5. Fracturing fluid design and addition of filler particles; S6. Hydraulic fracturing operation: inject liquid and conduct fracturing monitoring; conduct post-fracturing evaluation based on monitoring data to evaluate the crack expansion effect and initial production; S7. Post-processing.

2. The fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs according to claim 1, characterized in that: The horizontal wellbore trajectory in step S2 includes the wellbore's inclination angle and horizontal section length.

3. The fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs according to claim 2, characterized in that: The method for determining the inclination angle of the wellbore is: S211. Determine the range of the inclination angle according to the reservoir burial depth: For shallow reservoirs with a burial depth of less than 1500m, the inclination angle is 30° to 45°; For medium-deep reservoirs with a burial depth of 1500m to 3000m, the inclination angle is 45° to 60°; For ultra-deep reservoirs with a burial depth of >3000m, the inclination angle is 60° to 90°; S212. Analyze the impact of geological structure When faults, folds or complex lithology interfaces exist in the reservoir, the structural morphology is analyzed through 3D seismic data and geological modeling, and the inclination angle is adjusted to avoid drilling in high-risk areas; S213, Matching the direction of ground stress Determine the direction of the maximum horizontal principal stress through geostress testing or seismic inversion; the horizontal wellbore trajectory is perpendicular to the direction of the maximum horizontal principal stress; S214, Optimize well inclination and azimuth Use wellbore trajectory design software to simulate wellbore paths at different inclination angles and determine the maximum allowable curvature in combination with flexural strength analysis; The calculation formula of the flexural strength is: DLS=30×Δθ / L Where: DLS is the flexural strength, unit is ° / 30m; Δθ is the change in well inclination, unit is °; L is the well section length, unit is m; S215. Determine the final inclination angle of the wellbore in combination with steps S211 to S2145.

4. The fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs according to claim 2, characterized in that: The method for determining the length of the horizontal segment is: S221. Evaluate reservoir heterogeneity The location of the fracture-intensive zone in the reservoir is determined by natural fracture identification technology, and the horizontal section covers the fracture-intensive zone; When the reservoir heterogeneity is strong, the length of the horizontal section is designed in sections, and the horizontal section is preferentially extended to the high permeability area; S222, Analyze stress difference The crack extension simulation software was used to predict the crack extension range under different horizontal segment lengths, and the low stress difference area with Δσ<5MPa was selected; S223. Determine the perforation cluster spacing The perforation cluster spacing is 20m to 50m; The calculation formula for the number of perforation clusters is: N cluster =L horizontal / S cluster Where: N cluster is the number of perforation clusters, in units of; S cluster is the perforation cluster spacing, unit: L horizontal is the length of the horizontal section, in meters.

5. The fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs according to claim 1, characterized in that: The comprehensive calculation formula for the perforation spacing is: D opt =D sim ·f geo ·f econ Where: D opt is the perforation spacing, i.e. the optimal perforation density, in units of holes / m; D sim is the perforation density obtained based on simulation, in units of holes / m; f geo is the adjustment factor to take into account geological heterogeneity, and its unit is dimensionless; f econ It is an adjustment factor that takes economic factors into account and its unit is dimensionless.

6. The fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs according to claim 5, characterized in that: The calculation formula of the adjustment factor considering economic factors is: f geo =1+α·CV lith +β·Δσ-γ·FDI Where: α, β, γ are weight coefficients, which are calibrated by historical data regression or experiment, α = 0.4, β = 0.15, γ = 0.1; CV lith CV is the coefficient of variation of lithology. The distribution difference of different lithologies is calculated through logging data or core analysis. The calculation formula is: lith = standard deviation of lithology thickness / average lithology thickness; Δσ is the stress difference coefficient, and its calculation formula is: Δσ=σH-σh; Where: σH is the maximum horizontal principal stress, in MPa; σh is the minimum horizontal principal stress, in MPa; FDI is the fracture density index, which counts the number of natural fractures per unit volume through imaging logging or microseismic data; The calculation formula of FDI fracture density index is: FDI = total fracture length / reservoir volume; the unit of total fracture length is m; The unit of reservoir volume is m 3 .

7. The fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs according to claim 1, characterized in that: The perforation position is determined by using a high-edge directional perforation process technology; the perforation holes are perforated with a uniform aperture, and the perforation aperture is selected to be 12 mm.

8. The fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs according to claim 1, characterized in that: The fracturing fluid design in step S5 is specifically as follows: S51, at the beginning of the pumping phase, the jelly is pumped to create a wide seam, and the viscosity of the jelly is 170s -1 The shear rate reaches 500mPa·s or more; the pumping time of the gel is 10% to 20% of the total pumping time; the pumping volume of the gel is 15% to 30% of the total fracturing fluid volume; S52, pumping high viscosity fracturing fluid in the remaining stage; The viscosity of the high viscosity fracturing fluid is 170s -1 The shear rate reaches 20400mPa·s~400mPa·s; The filling particles in step S5 are small-size proppants, and the particle size of the small-size proppants is 200-400 meshes.

9. The fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs according to claim 1, characterized in that: In the step S6, during the hydraulic fracturing operation, the fracturing fluid is injected by a large displacement pumping method.

10. The fracturing construction process for improving the high penetration expansion force of hydraulic fractures in heterogeneous reservoirs according to claim 1, characterized in that: The S7 post-processing includes: S71, clean the cracks and pump a small amount of guar gum into the wellbore to clean it; S72. Conduct production tests, evaluate oil and gas production, analyze fracturing effects and production data, and provide feedback for design optimization.

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