Method for improving fracturing reconstruction volume of tight sandstone reservoir and application

Abstract

The application discloses a method for improving fracturing reconstruction volume of compact sandstone reservoirs and application thereof. The method comprises the following steps: through the optimization selection of a fracturing fluid system and a proppant, the combination of a fracturing fracture forming technology and a sand adding mode, the full utilization and opening of potential natural fractures and branch fractures, the full excavation of reservoir potential within a limited thickness range, the formation of a more complex multi-scale fracture system, the improvement of fracturing reconstruction volume, and the improvement of support efficiency and flow conductivity of a fracture system. The method can effectively solve the problem that the long-term flow conductivity of the fracture system of the reservoir is poor, and can alleviate or solve the problems of low initial production after fracturing, rapid production decline, short stable production period and the like, and improve the fracturing reconstruction effect of the reservoir and the reservoir producing degree.

Description

Technical Field

[0001] This invention relates to the field of fracturing technology, and more specifically, to a method and application for increasing the fracturing volume in tight sandstone reservoirs. Background Technology

[0002] Volumetric fracturing technology has become one of the important technologies for improving initial fracturing production and extending post-fracturing stable production in tight oil reservoirs. Maximizing the effective stimulated volume and improving fracture conductivity are the main goals of tight oil fracturing. In tight sandstone reservoir fracturing, the optimization of fracture morphology and fracture profile directly affects the stimulated volume (SRV), fracture complexity, proppant placement efficiency within the fracture, and effective proppant volume (ESRV), thereby affecting post-fracturing fracture conductivity and the effect of increasing and stabilizing production.

[0003] Currently, fracturing in tight oil reservoirs faces the challenge of rapid post-fracturing production decline and short stabilization periods. In North American tight oil reservoirs, the annual production decline rate after fracturing is 65%–75%; in China, tight oil reservoirs (taking the Honghe Oilfield in southern Hubei as an example) have an annual decline rate of 74%–75% for high-yield wells and 82%–83% for medium-yield wells, making the economical and efficient development of such reservoirs extremely difficult. Analysis of the underlying reasons for the difficulty in increasing and stabilizing production through fracturing in tight oil reservoirs mainly includes the following technical issues:

[0004] (1) The types and viscosities of fracturing fluids are relatively limited, which restricts the volume of fracturing and the complexity of the fractures.

[0005] In tight oil reservoir fracturing, a single type of fracturing fluid is often used, and the viscosity of the fracturing fluid is relatively high. Therefore, the fracture morphology formed by fracturing is mainly large-scale main fractures. However, due to the high viscosity of the fracturing fluid used, small-scale branch fractures and even smaller micro fractures are difficult for the fracturing fluid to enter and extend effectively. As a result, the overall opening and extension ratio is low, which limits the overall fracture volume (SRV) and the reservoir potential is not fully explored.

[0006] (2) Poor crack height control affects the fracture morphology.

[0007] In the fracturing of tight sandstone reservoirs, fracture height control is crucial for fracturing. In most domestic tight sandstone reservoirs, the stress difference between the reservoir and its interlayers is relatively small, and the shielding conditions of the interlayers are not ideal. For large-volume fracturing, fracture height is more prone to getting out of control. If fracture height is poorly controlled or gets out of control in the early stages of fracturing, it will cause the fracture to extend excessively in the longitudinal direction, while the fractures within the effective reservoir thickness will not be able to extend effectively in the fracture length direction. Furthermore, it will cause a significant reduction in fracture width and net pressure, preventing the activation of natural fractures and branch fracture systems. This results in a small overall fracturing volume, low fracture complexity, and proppant accumulation mostly in the near-wellbore area or ineffective interlayers outside the reservoir, preventing the truly effective reservoir from being fully extended and supported, and hindering the exploitation of the reservoir's production potential.

[0008] (3) Insufficient targeted measures to increase net pressure within the suture

[0009] In fracturing operations, a constant low to medium flow rate (such as 3m³) is frequently used. 3 / min~4m 3 This means that even if sufficient net pressure is easily accumulated in the wellbore and hydraulic fracture initially due to the relatively small size of the main fracture, as the fracture continues to extend, the size of the main fracture becomes larger and larger. Under the same injection rate, the rate of net pressure accumulation becomes slower and slower. At this point, the net pressure is no longer sufficient to overcome the biaxial stress difference and the tensile strength of the rock to open and extend potential natural fractures and branch fracture systems. On the other hand, net pressure within the fracture is increased by varying the injection rate and increasing the fluid viscosity, but due to the lack of targeted measures within the fracture and at the fracture ends, the increase in net pressure is mainly used for the continued extension of the fracture length, which is contrary to the goal of increasing fracture complexity.

[0010] Chinese patent CN107476790A discloses a pressure-limited but flow-unlimited fracturing method for increasing the volume of shale gas fractures, including: (1) pre-fracturing reservoir evaluation and real-time assessment before fracturing construction; (2) conducting layered small-scale fracturing tests on a vertical pilot well; (3) performing simulation analysis using the software MEYER; (4) carrying out normal fracturing construction, with one or two instantaneous pump shutdowns during the construction; (5) deducing the expected wellhead construction pressure from the bottom hole pressure; (6) increasing the flow rate as long as the wellhead construction pressure is lower than the expected pressure in step (5), so that the wellhead construction pressure is close to the expected value; (7) if the wellhead construction pressure after increasing the flow rate still does not reach the expected pressure, increasing the sand-fluid ratio during construction.

[0011] The core of this patent is to reverse the expected wellhead pressure by stopping the pump once or twice during fracturing operations. During the operation, if the pressure is lower than the expected wellhead pressure, the volume of fracturing is increased by increasing the pumping rate and the sand-fluid ratio. This patent is mainly for fracturing shale gas reservoirs. Although it can increase the volume of fracturing and fracture complexity to a certain extent, it is not applicable to the fracturing of tight oil reservoirs.

[0012] Therefore, a method for increasing the fracturing volume of tight sandstone reservoirs is proposed to address the aforementioned limitations. Summary of the Invention

[0013] Current fracturing techniques for tight sandstone oil reservoirs generally face challenges such as rapid post-fracturing production decline and short stabilization periods, resulting in generally poor development outcomes for most domestic reservoirs and making it difficult to achieve the expected economically effective development goals. This hinders the effective development and utilization of these reservoirs' reserves. To improve the fracturing effect and effectiveness of tight sandstone oil reservoirs, and to address the problems in existing technologies, this invention provides a method and application for increasing the fracturing volume in tight sandstone oil reservoirs. In the fracturing of tight sandstone oil reservoirs, the stress difference between the reservoir and interlayers is generally relatively small in most domestic tight sandstone oil reservoirs, the shielding conditions of the upper and lower interlayers are not ideal, and the reservoirs are generally thin. For large-volume fracturing, fracture height is more likely to get out of control, making fracture height control crucial for fracturing.

[0014] One of the objectives of this invention is to provide a method for increasing the volume of fracturing in tight sandstone reservoirs.

[0015] include:

[0016] By optimizing the selection of fracturing fluid systems and proppant, combining fracturing techniques that increase fracture complexity with proppant addition methods, potential natural fractures and branch fractures can be fully utilized and opened, reservoir potential within a limited thickness range can be fully explored, a more complex multi-scale fracture system can be formed, the fracturing volume can be increased, and the support efficiency and conductivity of the fracture system can be improved.

[0017] The method specifically includes:

[0018] (1) Evaluation of key reservoir parameters;

[0019] (2) Parameter optimization;

[0020] (3) Low-viscosity fracturing fluid is used to create the main fracture;

[0021] Low-viscosity fracturing fluid carrying proppant was injected via a slug injection method.

[0022] (4) Seal the sand-loosening joints around the main crack;

[0023] Low-viscosity fracturing fluid carrying proppant was injected via a slug injection method.

[0024] (5) High-viscosity fracturing fluid significantly increases net pressure;

[0025] (6) Low-viscosity fracturing fluid expands branched fractures;

[0026] When the injection volume of low-viscosity fracturing fluid in this stage reaches 10% to 20% of the total fracturing fluid volume, slug injection carrying proppant is carried out.

[0027] (7) Expanding branched fractures with medium-viscosity fracturing fluid;

[0028] Medium-viscosity fracturing fluid carrying 40-70 mesh proppant is injected using a slug or continuous proppant injection method.

[0029] (8) High-viscosity fracturing fluid carrying large-diameter proppant during construction;

[0030] (9) Replacement stage.

[0031] In a preferred embodiment of the present invention,

[0032] In step (2), the parameter optimization includes: optimization of perforation location, optimization of fracture parameters, and optimization of fracturing construction parameters.

[0033] In a preferred embodiment of the present invention,

[0034] In step (3), the viscosity of the low-viscosity fracturing fluid is 10 mP·s to 15 mP·s, and the pH value is 6 to 7.

[0035] The displacement is 50% to 60% of the maximum design displacement, and the fluid volume is 30% to 35% of the total fracturing fluid volume;

[0036] The particle size of the proppant is 70-140 mesh;

[0037] The sand-liquid ratio is 4% to 6%; the sand-liquid ratio can be gradually increased in steps, such as 4%, 5%, 6%, etc.

[0038] In a preferred embodiment of the present invention,

[0039] In step (4),

[0040] The proppant has a bulk density of <1.4 g / cm³. 3 Low-density proppant;

[0041] The proppant is a combination of three particle sizes: 70-140 mesh, 40-70 mesh, and 20-40 mesh, or a combination of three proppant sizes: 70-140 mesh, 40-70 mesh, and 30-50 mesh.

[0042] The sand-liquid ratio is 5% to 15%; the sand-liquid ratio can be gradually increased in steps, such as: 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%; technicians can determine the ratio based on the specific construction conditions.

[0043] The volume of fracturing fluid is 5% to 15% of the total fracturing fluid volume, and the discharge rate is 60% to 70% of the maximum design discharge rate.

[0044] In a further preferred embodiment of the present invention,

[0045] In step (4), the ratio of the three particle sizes of proppant is 1:(0.7-1):(0.5-1).

[0046] In a preferred embodiment of the present invention,

[0047] In step (5),

[0048] The viscosity of the high-viscosity fracturing fluid is 90 mP·s to 120 mP·s, and the pH value is 6 to 7.

[0049] The displacement of high-viscosity fracturing is 70% to 80% of the maximum design displacement;

[0050] The injection volume of high-viscosity fracturing fluid is determined based on the rise in wellhead pressure. When the net pressure calculated through the wellhead pressure in this stage is ≥ 2 times the original horizontal stress difference, the construction in this stage ends.

[0051] In a preferred embodiment of the present invention,

[0052] Step (6),

[0053] The proppant uses a combination of proppants with two particle sizes: 70-140 mesh and 40-70 mesh.

[0054] The sand-liquid ratio is 8% to 15%; the sand-liquid ratio can be gradually increased in steps, such as: 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%; technicians can determine the ratio based on the specific construction conditions.

[0055] The volume of fracturing fluid should be 20% to 25% of the total fracturing fluid volume, and the injection rate should be 80% to 90% of the maximum design rate.

[0056] In a further preferred embodiment of the present invention,

[0057] In step (6),

[0058] The ratio of the two particle sizes of proppant is 1:(0.7~1);

[0059] The ratio of low-density proppant to high-density proppant in each particle size proppant is 1:(0.5~1);

[0060] The low-density proppant has a bulk density of <1.4 g / cm³. 3 ;

[0061] The high-density proppant has a bulk density >1.8 g / cm³. 3 .

[0062] In a preferred embodiment of the present invention,

[0063] In step (7),

[0064] The medium-viscosity fracturing fluid has a viscosity of 30 mP·s to 40 mP·s and a pH value of 6 to 7.

[0065] For medium-viscosity fracturing, the volume of fracturing fluid should be 10% to 20% of the total fracturing fluid volume, and the discharge rate should be 80% to 90% of the maximum design discharge rate.

[0066] The sand-liquid ratio is 15% to 25%, and it can be gradually increased in steps, such as 15%, 16%, 17%, 18%, 19%, 20%, 21%, 22%, 23%, 24%, and 25%. Technicians can determine the ratio based on the specific construction conditions.

[0067] In a preferred embodiment of the present invention,

[0068] In step (8),

[0069] High-viscosity fracturing fluid carrying 20-40 mesh or 30-50 mesh proppant is injected via a continuous proppant addition method; the bulk density of the proppant is <1.4 g / cm³. 3 ;

[0070] The sand-liquid ratio is 20%–35%. The sand-liquid ratio can be gradually increased in steps, such as: 20%, 21%, 22%, 23%, 24%, 25%, 26%, 27%, 28%, 29%, 30%, 31%, 32%, 33%, 34%, 35%. Technicians can determine the ratio based on the specific construction conditions.

[0071] The fracturing fluid volume is 10% to 20% of the total fracturing fluid volume, and the injection displacement is 90% to 100% of the maximum design displacement.

[0072] In a preferred embodiment of the present invention,

[0073] In step (9),

[0074] The displacement stage employs an equal-volume displacement technique, using low-viscosity fracturing fluid to completely displace the proppant in the wellbore to the fracture opening. The amount of fracturing fluid used is the sum of the wellbore volume and the surface pipeline volume.

[0075] The second objective of this invention is to provide a method for increasing the volume of fracturing in tight sandstone reservoirs and its application in oil production.

[0076] The present invention can be specifically implemented using the following technical solutions:

[0077] (1) Evaluation of key reservoir parameters

[0078] By comprehensively analyzing the results of well logging, core testing, and fracturing testing, and combining them with the inversion analysis of fracturing operation data from adjacent wells in the same block, we can gain a comprehensive and in-depth understanding of the various lithologies, mineral components, physical properties, rock mechanics, vertical geostress profiles, and natural fracture development characteristics of the reservoir and interlayers. This provides comprehensive and accurate basic data for fracturing technology and fluid optimization design.

[0079] (2) Optimization of perforation location

[0080] Based on the comprehensive geological sweet spot location, an optimal evaluation of the engineering sweet spot is conducted. Combined with cementing quality, the perforation location and perforation parameters are finally determined. Using fracturing simulation software such as GOHFER, the extension of fracture height and fracture profile at the geological sweet spot location under different perforation lengths and methods are examined. Through comprehensive optimization based on the perforation location, perforation length, and perforation method of the geological sweet spot, the optimal perforation center location is determined that ensures the longitudinal centerline of the fracture nearly coincides with the longitudinal centerline of the effective reservoir thickness, and that the fracture profile covers the effective reservoir thickness to the maximum extent.

[0081] (3) Optimization of crack parameters

[0082] Based on the reservoir's geological and physical characteristics, a geological model was established. Using reservoir numerical simulation software such as ECLIPSE, different combinations of main fractures and secondary fractures were set. The semi-fracture length of the main fracture ranged from 50m to 250m, the spacing between secondary fractures ranged from 5m to 30m, the conductivity of the main fracture ranged from 5D·cm to 20D·cm, and the conductivity of the secondary fractures was set to 20% to 30% of that of the main fracture. Using an orthogonal design method, the parameters to be optimized were set to simulate production changes under different fracture morphologies and complexities. Optimization was performed with the relative maximization of post-compression production as the objective function or with net present value as the objective function. The main controlling factors affecting the production capacity of complex fractures were analyzed, and the optimal fracture combination and parameters were selected.

[0083] (4) Optimization of fracturing construction parameters

[0084] Mature commercial fracture propagation simulation software (such as GOHFER and other fracturing fracture simulation software) is used, and an orthogonal design method is employed to simulate the dynamic changes of fracture parameters and fracture profiles under construction parameters such as displacement, total fracturing fluid volume, proppant dosage, sand-fluid ratio, and fracturing fluid viscosity at different stages of fracturing construction. Through comparison and optimization, the optimal combination of construction parameters under ideal fracture profile is obtained.

[0085] (5) Low-viscosity fracturing fluid stage for creating the main fracture

[0086] ① Use low-viscosity fracturing fluid to create fractures. The reference formula for low-viscosity fracturing fluid is: 0.15%~0.2% SRFP~1 thickener + 0.3% SRCS~1 clay stabilizer + 0.1% SRCU~1 drainage aid, with a liquid viscosity of 10mP·s~15mP·s and a pH value of 6~7.

[0087] ② The injection rate of fracturing fluid in this stage is based on the optimized fracturing operation parameters and is generally 50% to 60% of the maximum design rate. The amount of fracturing fluid in this stage is 30% to 35% of the total fracturing fluid.

[0088] Generally, proppant slugs with a low sand ratio of 2-3 small sand ratios are added. The proppant is a small-particle-size proppant (70-140 mesh fine sand or ceramic powder). The main purpose is to polish the near-wellbore area and reduce porosity and bending friction.

[0089] (6) Sealing stage of sand descaling joints around the main crack

[0090] ① Low-viscosity fracturing fluid carrying proppant is used for injection, and a slug injection method is adopted. The amount of fracturing fluid in this stage is 5% to 15% of the total fracturing fluid volume, and the injection displacement is 60% to 70% of the maximum design displacement. The reference sand-fluid ratio is 5% to 15%. The sand-fluid ratio can be adjusted in real time at the fracturing construction site. The standard is that the construction pressure rise rate reaches 1MPa / min. When the construction pressure rise rate is greater than 1MPa / min, it indicates that the sand removal effect has occurred at the fracture tip. When the designed sand removal amount is reached, the construction of this stage can be ended.

[0091] ② The proppant used is low density (bulk density <1.4 g / cm³). 3 The proppant of three particle sizes, namely 70-140 mesh, 40-70 mesh and 20-40 mesh (or 30-50 mesh), is uniformly mixed in a ratio of 1:(0.7-1):(0.5-1), more preferably 1:1:1, and then injected with the mixed particle size.

[0092] (7) High-viscosity fracturing fluid significantly increases net pressure during the stage.

[0093] ① High-viscosity fracturing fluid is used for injection. The reference formula for high-viscosity fracturing fluid is 0.45%~0.50% SRFP~1 thickener + 0.2% SRFC~1 crosslinking agent + 0.3% SRCS~1 clay stabilizer + 0.1% SRCU~1 drainage aid. The fluid viscosity is 100mP·s~120mP·s, the pH value is 6~7, and the breaker is ammonium persulfate (APS) and capsules.

[0094] ② The injection rate of high-viscosity fracturing fluid is based on the optimization results of fracturing construction parameters, and is generally 70% to 80% of the maximum design rate. The injection volume of high-viscosity fracturing fluid in this stage is mainly determined based on the rise in wellhead pressure. When the net pressure calculated through the wellhead pressure in this stage is ≥ 2 times the original horizontal stress difference, the construction of this stage can be ended.

[0095] ③ The amount of fracturing fluid in this stage is 5% to 10% of the total fracturing fluid. During the injection of high-viscosity fracturing fluid, different concentrations of breaker are added according to the design requirements (based on the simulation results of the fracture temperature field) to ensure that the high-viscosity fracturing fluid can be completely and quickly broken up after the completion of this stage of construction.

[0096] (8) Low-viscosity fracturing fluid expansion of branch fracture stage

[0097] ① Use low-viscosity fracturing fluid to increase the flow rate and continue injection to extend and expand the already opened small-scale branch fracture system; when the injection volume in this stage reaches 10% to 20% of the total fracturing fluid volume, low-viscosity fracturing fluid carrying proppant is injected in a slug-type manner, with a reference sand-to-fluid ratio of 8% to 15%; the sand-to-fluid ratio can be gradually increased in a step manner.

[0098] ② In this stage, the fracturing fluid volume is 20% to 25% of the total fracturing fluid volume, and the injection displacement is 80% to 90% of the maximum design displacement;

[0099] ③ The proppant used is a proppant with two particle sizes: 70-140 mesh and 40-70 mesh. The two particle sizes are uniformly mixed at a ratio of 1:(0.7-1), more preferably 1:1, before being injected into the mixture. Each particle size proppant is further prepared at a low density (bulk density <1.4 g / cm³). 3 High density (bulk density > 1.8 g / cm³) and high density 3 The ratio of 1:(0.5 to 1) is preferred, and the mixture is more preferably mixed in a 1:1 ratio.

[0100] (9) Medium-viscosity fracturing fluid expansion of branch fracture stage

[0101] ① Use medium-viscosity fracturing fluid to carry 40-70 mesh proppant for injection to continue to extend and fill the branch fracture system; use slug or continuous proppant injection method, the fracturing fluid volume in this stage is 10% to 20% of the total fracturing fluid volume, the injection discharge rate is 80% to 90% of the maximum design discharge rate, and the reference proppant-fluid ratio is 15% to 25%.

[0102] ② The reference formula for medium viscosity fracturing fluid is: 0.25%~0.3% SRFP-1 thickener + 0.3% SRCS-1 clay stabilizer + 0.1% SRCU-1 drainage aid; liquid viscosity 30mP·s~40mP·s, pH value 6~7;

[0103] (10) Construction using high-viscosity fracturing fluid carrying large-diameter proppant

[0104] ① High-viscosity fracturing fluid carrying 20-40 mesh (or 30-50 mesh) proppant is injected to fill and support the main fracture system. In this stage, continuous proppant addition is adopted, with the fracturing fluid volume being 10% to 20% of the total fracturing fluid volume, the injection displacement being 90% to 100% of the maximum design displacement, and the reference proppant-fluid ratio being 20% ​​to 35%.

[0105] ② The proppant used is low density (bulk density <1.4 g / cm³). 3 Three types of proppant with particle sizes ranging from 20 to 40 mesh.

[0106] ③ Due to its high viscosity, high-viscosity fracturing fluid is difficult to enter the branch fracture system. It is mainly transported and moved within the main fracture. It can advance and transport the small-diameter proppant that was retained in the main fracture in the previous stages to the far-well fracture zone or the branch fracture system, preventing it from blocking the conductivity of the main fracture in other parts of the fracture.

[0107] (11) Balanced replacement stage

[0108] The displacement stage employs an equal-volume displacement technique, using low-viscosity fracturing fluid to completely displace the proppant in the wellbore to the fracture opening. The amount of fracturing fluid used is the sum of the wellbore volume and the surface pipeline volume.

[0109] The effects of the invention

[0110] The method for increasing the fracturing volume in tight sandstone reservoirs proposed in this invention is simple in concept and easy to implement in the field. By optimizing the fracturing process and pumping method, and optimizing and rationally combining fracturing fluids, the net pressure within the fractures is continuously increased based on the full extension of the main fracture. This allows for the full opening and extension of micro-fractures and branch fractures connected to the main fracture, increasing the fracturing volume and the complexity of the fractures. Through the addition of sand using liquids of different viscosities and mixed particle sizes, effective support is achieved for the main fracture and branch fracture systems, improving the support efficiency of the entire fracture system and the effective conductivity of the fractures. Designing and constructing fracturing schemes for tight oil and shale oil reservoirs using this method can effectively solve problems such as poor long-term conductivity of the fracture system in these reservoirs, alleviating or resolving issues such as low initial production after fracturing, rapid production decline, and short stabilization periods, thereby improving the fracturing effect and reservoir utilization of these reservoirs.

[0111] The method and process described in this invention have been applied to the optimization design and testing of fracturing schemes in multiple tight oil reservoir areas in China. Field test applications have proven that the method is highly adaptable and targeted, has good operability, and has good effects on increasing and stabilizing production, resulting in considerable economic benefits. Detailed Implementation

[0112] The present invention will now be described in detail with reference to specific embodiments. It should be noted that the following embodiments are only used to further illustrate the present invention and should not be construed as limiting the scope of protection of the present invention. Some non-essential improvements and adjustments made by those skilled in the art based on the content of the present invention are still within the scope of protection of the present invention.

[0113] Example

[0114] The target fracturing interval for well A is (3589-3598.5, 9.8m / layer, layer H3VIII9). 2 The reservoir is a light gray, gravelly fine sandstone with a pressure coefficient of 0.93 and an oil layer temperature of 139.7℃. It is characterized by low porosity and low permeability (porosity of 5.78% and permeability of 2.5 × 10⁻⁶). -3 μm 2 The target reservoir was located at normal temperature and pressure. Considering the reservoir's geological conditions and wellbore status, it was determined that single fractures in the target reservoir would have limited production enhancement, while complex fractures would be more effective. Using the technology and methods described in this patent, and taking into account the high operating pressure in the area, a shallow tubing approach was adopted for the volumetric fracturing scheme design and pilot field test. The specific implementation methods and results are as follows:

[0115] (1) Optimization and selection of fracturing fluid

[0116] Low-viscosity, medium-viscosity, and high-viscosity low-damage polymer cleaning fracturing fluids are used to meet the process requirements of controlled fracturing, high-volume fracturing, temporary plugging of the fracturing end, and efficient sand carrying and addition.

[0117] ① Low viscosity fracturing fluid formulation: 0.15% SRFP ~ 1 thickener + 0.3% SRCS ~ 1 clay stabilizer + 0.1% SRCU ~ 1 drainage aid, liquid viscosity 12 mP·s, pH value 6 ~ 7;

[0118] ② Medium viscosity fracturing fluid formulation: 0.25% SRFP-1 thickener + 0.3% SRCS-1 clay stabilizer + 0.1% SRCU-1 drainage aid; liquid viscosity 35 mP·s, pH value 6-7;

[0119] ③ High viscosity fracturing fluid formulation: 0.45% SRFP ~ 1 thickener + 0.2% SRFC ~ 1 crosslinking agent + 0.3% SRCS ~ 1 clay stabilizer + 0.1% SRCU ~ 1 drainage aid, liquid viscosity 94 mP·s, pH value 6 ~ 7;

[0120] (2) Optimization of perforation location and parameters

[0121] Calculations of the target layer and interlayer stress profiles show that the stress shielding conditions of the interlayers above and below the target layer are limited. If the target layer is fully perforated, the fracture height will extend excessively into the interlayers above and below. To mitigate the excessive extension of fracture height, based on the GOHFER fracturing simulation results, a 102mm perforating gun with 127mm rounds was used to perforate the middle part of the target modified layer (3592.0m~3597.0m), which can effectively control the fracture extension height. The perforation method adopted is a spiral perforation method with a 60-degree phase angle and a perforation density of 16 holes / meter, for a total of 80 holes.

[0122] (3) Simulation of Fracturing Parameter Optimization

[0123] The ECLIPSE reservoir numerical simulation software was used to optimize fracturing parameters such as the half-length of the main fracture, fracture morphology (combination of main and branch fractures), proppant placement within the fracture, and proppant conductivity (constant conductivity and long-term conductivity). Simulations showed that the production of the target layer increased with increasing fracture half-length; the cumulative production increase slowed when the fracture half-length exceeded 220m, and considering all factors, the optimal fracture half-length was recommended to be 235m; increasing fracture complexity (forming complex fractures with interconnected main and secondary fractures) effectively improved production, with the production being optimal for complex fracture type III, reaching 1.36 times that of a single fracture; the proppant filling degree at the fracture height profile significantly affected production, with 80% proppant efficiency producing 1.22 times the production of 20% proppant efficiency; decreasing conductivity accelerated the rate of production decline, necessitating the maintenance of long-term conductivity effectiveness as much as possible.

[0124] (4) Simulation and optimization of fracturing construction process parameters

[0125] Based on the perforation location and parameter optimization of the target formation in Well A, and following the approach described in this patent, the GOHFER fracturing simulation software was used to identify the main controlling engineering factors affecting fracture parameters and proppant distribution. The optimal construction parameters and fracture profile were then optimized. The optimized result is: total fracturing fluid volume 800m³. 3 Among them, 515m of low-viscosity fracturing fluid 3 145m of medium viscosity fracturing fluid 3 90m of high-viscosity fracturing fluid 3 Total proppant volume: 52.4 m³ 3 The 70 / 140 mesh ceramsite proppant is 8.6m. 3 40 / 70 mesh ceramsite proppant 26.7m 3 20 / 40 mesh ceramsite proppant 17.1m 3 Minimum displacement 2.5m 3 / min, maximum displacement 6.0m 3 / min, sand-to-liquid ratio 4%–30%.

[0126] (5) Low-viscosity fracturing fluid stage for creating the main fracture

[0127] With 3.0m 3 / min~3.5m 3 / min injection 240m 3 Low-viscosity fracturing fluid was used, and 70-140 mesh proppant was added during injection using a slug-type proppant injection method. The initial proppant ratio was 4%, and the ratio was increased in stages (4%-6%), with a total of 4.0 μm of 70-140 mesh ceramic proppant added. 3 .

[0128] (6) Sealing stage of sand descaling joints around the main crack

[0129] With 4.0m 3 / min displacement injection 130m 3 Low-viscosity fracturing fluid was used, and during injection, low-density mixed-size proppant (70-140 mesh, 40-70 mesh, and 20-40 mesh proppants mixed in a 1:1:1 ratio) was added using a slug-type proppant addition method. The initial proppant ratio was 5%, and the ratio was increased in stages (5%-8%-10%), with a total addition of 3.2 μm of low-density mixed-size proppant. 3 ;

[0130] The density of the low-density proppant is 1.35 g / cm³. 3 .

[0131] (7) High-viscosity fracturing fluid significantly increases net pressure during the stage.

[0132] At 4.5m 3 / min displacement injection 50m 3 High-viscosity fracturing fluid.

[0133] The injection volume of high-viscosity fracturing fluid is determined based on the rise in wellhead pressure. When the net pressure calculated through the wellhead pressure in this stage is ≥ 2 times the original horizontal stress difference, the construction in this stage ends.

[0134] (8) Low-viscosity fracturing fluid expansion of branch fracture stage

[0135] At 4.5m 3 / min~5.0m 3 / min displacement injection 120m 3 Low-viscosity fracturing fluid was used, and during injection, a mixed-size proppant (70-140 mesh and 40-70 mesh proppant mixed in a 1:1:1 ratio, with each size further mixed in a 1:1 ratio of low-density to high-density proppant) was added using a slug-type proppant addition method. The initial proppant ratio was 10%, increasing in stages (10%-13%), with a total addition of 6.9 μm of mixed high- and low-density proppant.3 .

[0136] The density of the low-density proppant is 1.35 g / cm³. 3 ;

[0137] The density of the high-density proppant is 1.81 g / cm³. 3 ;

[0138] (9) Medium-viscosity fracturing fluid expansion of branch fracture stage

[0139] With 5.0m 3 / min~5.5m 3 / min displacement injection 145m 3 Low-viscosity fracturing fluid was used, and 40-70 mesh proppant was added during injection using a long slug injection method. The initial proppant ratio was 15%, increasing in stages (15%-18%-21%-24%), with a total proppant content of 22.2 m³. 3 .

[0140] (10) Construction using high-viscosity fracturing fluid carrying large-diameter proppant

[0141] At 5.5m 3 / min~6.0m 3 / min displacement injection 90m 3 High-viscosity fracturing fluid was used, and 20 / 40 mesh proppant was continuously added during injection. The proppant ratio was initially set at 25%, and then increased in stages (25%–28%–30%), with a total proppant content of 16.1 m³. 3 .

[0142] (11) Balanced replacement stage

[0143] At 6.0m 3 / min pumping capacity 25.0m 3 Low-viscosity fracturing fluid was used for equilibrium displacement. After displacement, the pump was stopped and the pressure drop was measured for 2 hours before the well operation was terminated.

[0144] (12) Post-pressure analysis and evaluation

[0145] Well A underwent volumetric fracturing according to the above pumping scheme. Post-fracturing interpretation and evaluation showed that: the fracture profile created by post-fracturing fracture inversion was ideal (fracture height 15.8m, proppant height 9.1m), and well temperature logging interpretation showed that 80% of the fracture height extended within the longitudinal range of the reservoir; the proppant in post-fracturing fracture inversion was all added within the effective range of the reservoir, ensuring good proppant support efficiency in the reservoir; after the first plugging during fracturing, the net pressure increased from 6.2MPa to 11.0MPa, an increase of 4.8MPa, indicating effective plugging; fracturing curve analysis and post-fracturing fitting analysis reflected obvious multi-scale fracturing characteristics during fracturing, and the multi-particle size combination and mixed particle size proppant addition method were reasonable and effective. The initial fluid flowback efficiency reached 90% after fracturing, and the fracturing fluid flowback rate and oil breakthrough time were better than those of adjacent wells in the adjacent area. The initial production capacity reached 6.2t / d, and the later stable production was 4-4.5t / d.

[0146] Comparative example:

[0147] In adjacent wells at the same level, conventional fracturing and fracturing methods for creating long fractures are used. The fracturing flow rate is relatively constant. There are few measures to control the fracture height, taking into account factors such as sweet spot, perforation location, fluid viscosity, and flow rate. A high-viscosity guar gum fracturing fluid is generally used. Small-particle-size (70-140 mesh) and large-particle-size (20-40 mesh) proppant are generally used. Conventional slug or continuous proppant addition is used.

[0148] The production of well A in Example 1 is 2 to 3 times that of wells in the same stratum in the adjacent area.

Claims

1. A method for increasing the fracturing volume in tight sandstone reservoirs, characterized in that... The method includes: By optimizing the selection of fracturing fluid system and proppant, combining fracturing and proppant creation technology that increases fracture complexity with sand addition methods, we can fully utilize and open potential natural fractures and branch fractures, fully explore the reservoir potential within a limited thickness range, form a more complex multi-scale fracture system, increase the fracturing stimulation volume, and improve the support efficiency and conductivity of the fracture system. (1) Evaluation of key reservoir parameters; (2) Parameter optimization; (3) Low-viscosity fracturing fluid is used to create the main fracture; Low-viscosity fracturing fluid carrying proppant was injected via a slug injection method. The low-viscosity fracturing fluid has a viscosity of 10 mP·s to 15 mP·s and a pH value of 6 to 7. The displacement is 50% to 60% of the maximum design displacement; (4) Seal the sand-loosening joints around the main crack; Low-viscosity fracturing fluid carrying proppant was injected via a slug injection method. The proppant has a bulk density of <1.4 g / cm³. 3 Low-density proppant; The proppant is a combination of three particle sizes: 70-140 mesh, 40-70 mesh, and 20-40 mesh, or a combination of three proppant sizes: 70-140 mesh, 40-70 mesh, and 30-50 mesh. (5) High-viscosity fracturing fluid significantly increases net pressure; The viscosity of the high-viscosity fracturing fluid is 90 mP·s to 120 mP·s, and the pH value is 6 to 7. The injection volume of high-viscosity fracturing fluid is determined based on the rise in wellhead pressure. When the net pressure calculated through the wellhead pressure in this stage is ≥ 2 times the original horizontal stress difference, the construction of this stage ends. (6) Low-viscosity fracturing fluid expands branched fractures; When the injection volume of low-viscosity fracturing fluid in this stage reaches 10% to 20% of the total fracturing fluid volume, slug injection carrying proppant is carried out. The proppant uses a combination of proppants with two particle sizes: 70-140 mesh and 40-70 mesh. The ratio of the two particle sizes of proppant is 1:(0.7~1). The ratio of low-density proppant to high-density proppant in each particle size proppant is 1:(0.5~1). (7) Expanding branched fractures with medium-viscosity fracturing fluid; Medium-viscosity fracturing fluid carrying 40-70 mesh proppant is injected using a slug or continuous proppant injection method. The medium-viscosity fracturing fluid has a viscosity of 30 mP·s to 40 mP·s and a pH value of 6 to 7. (8) High-viscosity fracturing fluid carrying large-diameter proppant during construction; The viscosity of the high-viscosity fracturing fluid is 90 mP·s to 120 mP·s, and the pH value is 6 to 7. (9) Replacement stage.

2. The method as described in claim 1, characterized in that: In step (2), the parameter optimization includes: optimization of perforation location, optimization of fracture parameters, and optimization of fracturing construction parameters.

3. The method as described in claim 1, characterized in that: In step (3), the volume of fracturing fluid is 30% to 35% of the total fracturing fluid volume; The particle size of the proppant is 70-140 mesh; the sand-liquid ratio is 4%~6%.

4. The method as described in claim 1, characterized in that: In step (4), The sand-to-liquid ratio is 5%–15%; The volume of the fracturing fluid is 5% to 15% of the total fracturing fluid volume, and the discharge rate is 60% to 70% of the maximum design discharge rate.

5. The method as described in claim 4, characterized in that: In step (4), the ratio of the three particle sizes of proppant is 1:(0.7~1):(0.5~1).

6. The method as described in claim 1, characterized in that: In step (5), The displacement of high-viscosity fracturing is 70% to 80% of the maximum design displacement.

7. The method as described in claim 1, characterized in that: Step (6), The sand-to-liquid ratio is 8%–15%; The volume of fracturing fluid is 20% to 25% of the total fracturing fluid volume, and the injection rate is 80% to 90% of the maximum design rate.

8. The method as described in claim 7, characterized in that: In step (6), The low-density proppant has a bulk density of <1.4 g / cm³. 3 ; The high-density proppant has a bulk density >1.8 g / cm³. 3 .

9. The method as described in claim 1, characterized in that: In step (7), For medium-viscosity fracturing, the volume of the fracturing fluid is 10% to 20% of the total fracturing fluid volume, the discharge rate is 80% to 90% of the maximum design discharge rate, and the sand-fluid ratio is 15% to 25%.

10. The method as described in claim 1, characterized in that: In step (8), High-viscosity fracturing fluid carrying 20-40 mesh or 30-50 mesh proppant is injected via a continuous proppant addition method; the bulk density of the proppant is <1.4 g / cm³. 3 The sand-to-liquid ratio is 20%–35%. The fracturing fluid volume is 10% to 20% of the total fracturing fluid volume, and the injection displacement is 90% to 100% of the maximum design displacement.

11. The method as described in claim 1, characterized in that: In step (9), The displacement stage employs an equal-volume displacement technique, using low-viscosity fracturing fluid to completely displace the proppant in the wellbore to the fracture opening. The amount of fracturing fluid used is the sum of the wellbore volume and the surface pipeline volume.

12. The application of the method as described in any one of claims 1 to 11 in oil extraction.