A multi-well fracturing timing regulation asynchronous pressure drive process method offshore

Abstract

The application discloses a kind of offshore multi-well fracturing timing regulation asynchronous pressure drive process methods, comprising the following steps, pressure drive unit division and timing reference planning;Multi-well fracturing timing dynamic regulation model construction and parameter optimization;Modular electric drive fracturing equipment timing deployment and operation;Timing stable fracturing fluid configuration and segmented injection and fiber coordination monitoring;After pressure, segmented flowback and environmental protection treatment and timing monitoring.The application constructs fracturing timing dynamic regulation model, optimizes modular equipment timing operation strategy, develops timing stable fracturing fluid system, in combination with full life cycle distributed fiber coordination monitoring technology, realizes offshore complex reservoir multi-well asynchronous construction timing accurate control, equipment load balanced distribution, efficient construction and sand effective inhibition of seam network, provides reliable technical support for offshore platform equipment limited, large interlayer difference and medium-high permeability depleted sand development scene.

Description

Technical Field

[0001] This invention belongs to the field of fracturing and production enhancement technology in the later stage of oil and gas field development, and in particular relates to an asynchronous pressure drive process method with time-series control of fracturing in offshore multi-wells. Background Technology

[0002] In offshore oil and gas resource development, tight reservoirs and igneous intrusion reservoirs generally have low natural production capacity per well due to their inherent characteristics such as low porosity, poor permeability, and uneven distribution of geostress. Therefore, multi-well coordinated fracturing to create an artificial fracture network is necessary to achieve efficient reserve utilization. While medium-to-high permeability reservoirs have high initial production capacity, after long-term depletion-type extraction, reservoir energy dissipates rapidly. Initial permeability (10-100 mD) decreases by 20-40% with decreasing formation pressure, and porosity decreases by 2-5 percentage points, directly leading to a gradual decline in production capacity. Simultaneously, during production, formation particles are easily transported with fluids, forming sand, causing wellbore contamination and screen blockage, further exacerbating production losses. These types of reservoirs also urgently require targeted modification technologies.

[0003] Asynchronous pressure drive technology, as an important branch of multi-well synergistic production enhancement, has the core advantage of achieving precise fracture network connectivity by constructing multiple wells in a pre-set sequence and leveraging the temporal superposition effect of pressure fields. Compared to synchronous pressure drive, this technology can significantly reduce the simultaneous operating load of offshore platform equipment, perfectly adapt to scenarios with limited power supply capacity and deck space, and is more effective in precisely controlling fracture extension direction, suppressing sand production, and avoiding the risk of ineffective crossflow in high-permeability reservoirs with large inter-layer differences and depleted sand-producing reservoirs.

[0004] Current asynchronous pressure drive technology still faces four major technical bottlenecks when applied to marine applications: Firstly, traditional asynchronous processes adopt a fixed timing planning mode, which lacks the ability to dynamically predict the interference of inter-well fracturing timing. Due to unreasonable timing interval settings, the pressure field superposition is insufficient or excessively interfered, which ultimately leads to the failure of fracture network connectivity. The degree of vertical reservoir stimulation is generally less than 65%, and it is particularly unable to adapt to the physical property decay and sand production conditions of medium and high permeability depleted reservoirs.

[0005] Secondly, the modular integration of offshore platform fracturing equipment is low, the efficiency of switching parameters between wells is low during asynchronous construction, the timing control response is lagging, and it is difficult to adapt to the differentiated construction needs of reservoirs with different permeability (including medium and high permeability depleted reservoirs). The operation time efficiency is only 15%-20% higher than that of synchronous hydraulic drive, and the load adaptability advantage of asynchronous technology is not fully utilized.

[0006] Third, while existing fracturing fluid systems can generally adapt to high-temperature and high-salt environments, they lack a time-series stability design for asynchronous segmented injection and do not take into account the sand production control requirements of medium- and high-permeability reservoirs. They are prone to viscosity decay and sand-carrying capacity reduction due to construction intervals, which not only affects the construction effect but also exacerbates reservoir damage and sand production risks.

[0007] Fourth, existing monitoring technologies are mostly limited to local monitoring of the single-well fracturing process, lacking a collaborative monitoring scheme for the asynchronous whole process (time-sequence planning - segmented construction - cross-well superposition - flowback production), and cannot capture the sand production dynamics of medium- and high-permeability depleted reservoirs in real time, making it difficult to form a closed-loop system of "time-sequence control - effect feedback - parameter optimization".

[0008] For example, document CN119009876A discloses an onshore multi-well asynchronous fracturing process, which only plans the construction sequence through fixed time intervals and does not involve the load adaptation of offshore platform equipment, dynamic interference control of inter-well fracturing sequence, sand production response in medium- and high-permeability depleted reservoirs, and full-process collaborative monitoring technology. It cannot take into account the complex geological conditions and equipment constraints at sea. The conventional guar gum fracturing fluid system disclosed in CN117973212A is prone to significant viscosity decay within the segmented intervals of asynchronous construction, and its sand-carrying support performance is insufficient to cope with sand production conditions in medium- and high-permeability reservoirs, making it difficult to meet the requirements of long-term segmented injection. Existing distributed fiber optic monitoring technology is only used for single-well fracture trajectory tracking and cannot realize cross-well collaborative monitoring of pressure and temperature fields during multi-well sequential construction, nor can it identify sand production precursors in real time, making it difficult to support dynamic optimization of timing parameters.

[0009] In summary, existing technologies have technological gaps in four core dimensions of offshore asynchronous hydraulic fracturing: time-series dynamic control, equipment load adaptation, fracturing fluid time-series stability, and full-process collaborative monitoring. Furthermore, there is a lack of targeted solutions for the degradation of physical properties and sand production pollution in medium-to-high permeability depleted reservoirs. There is an urgent need to develop an asynchronous hydraulic fracturing process that is adaptable to complex offshore scenarios and balances load balancing with precise control to overcome existing technological bottlenecks. Summary of the Invention

[0010] The problem this invention aims to solve is to provide a method for asynchronous hydraulic fracturing with time-series control in multi-well offshore operations. This method constructs a dynamic control model for fracturing time, optimizes the time-series operation strategy of modular equipment, develops a time-stable fracturing fluid system, and combines it with full life-cycle distributed fiber optic collaborative monitoring technology to achieve precise time-series control, balanced equipment load distribution, efficient fracture network construction, and effective suppression of sand production in multi-well asynchronous operations in complex offshore reservoirs. This provides reliable technical support for development scenarios where offshore platform equipment is limited, reservoir interlayer differences are large, and sand production occurs due to medium-to-high permeability depletion.

[0011] To solve the above-mentioned technical problems, the technical solution adopted by the present invention is: a method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea, comprising the following steps: S1: Pressure drive unit partitioning and timing reference planning; S2: Construction and parameter optimization of a time-series dynamic control model for multi-well fracturing; S3: Sequential deployment and operation of modular electric-driven fracturing equipment; S4: Time-stable fracturing fluid preparation, staged injection, and fiber optic collaborative monitoring; S5: Post-pressurization staged return discharge and environmental protection treatment and timely monitoring.

[0012] Furthermore, in S1, based on the well network layout of the offshore platform, reservoir geological parameters, igneous rock distribution characteristics, and equipment rated load, 3-5 wells are divided into a pressure drive unit. According to the reservoir permeability classification and depletion state, the well construction sequence interval and initial pumping parameters are set to determine the construction sequence priority.

[0013] Furthermore, in S1, the well construction interval is set to 2-4 hours for low-permeability reservoirs; the initial state interval is set to 4-6 hours for medium-to-high permeability reservoirs; and the interval is set to 5-7 hours for medium-to-high permeability depleted and sand-producing reservoirs.

[0014] Furthermore, in S2, based on the reservoir data and equipment load data obtained in S1, an improved LSTM neural network model incorporating a time-series attention mechanism is constructed. Real-time pump pressure, discharge rate, formation response signals, microseismic data, distributed optical fiber monitoring data, and equipment operating load data are input to predict the pressure field superposition effect, fracture extension direction, inter-well interference level, and sand production precursors in real time. Based on the prediction results, the time interval and single-well pumping parameters are dynamically optimized.

[0015] Furthermore, in S3, modular equipment is started and stopped in a time-sharing manner and quickly switched between wells according to time priority, and the load of simultaneously operating equipment is controlled to not exceed 80% of the platform power supply threshold, and the switching time between wells is ≤30 minutes.

[0016] Furthermore, in S4, seawater is used as the preparation medium to prepare a time-stabilized fracturing fluid with hydroxypropyl etherified-enzymatic hydrolysis-crosslinked modified guar gum as the base fluid, and 0.3-0.5% organic cationic anti-swelling agent, 0.25-0.45% time-stabilizer and 0.05-0.1% delayed biodegradable breaker are compounded; the "single-well segmented injection + multi-well fiber optic collaborative monitoring" mode is adopted to invert the pressure field superposition range and fracture opening in real time.

[0017] Furthermore, the time-stabilized fracturing fluid maintains stable performance within a salinity range of 3-200,000 mg / L, with a viscosity retention rate of ≥85% within a maximum asynchronous construction interval of 6 hours. The breaker time of the delayed breaker is adjustable within a range of 4-8 hours, and the residue content is reduced by more than 60% compared to conventional guar gum fracturing fluid. Under conditions of 120-130℃ and salinity of 3-200,000 mg / L, the viscosity of the time-stabilized fracturing fluid is ≥30 mPa·s after standing for 6 hours, the viscosity decay rate is ≤15% after 2 hours of shearing, the filtration loss is ≤5 mL / min, and the core damage rate is ≤8%.

[0018] Furthermore, in S5, gradient backflow is initiated according to the priority of construction sequence, and the backflow compliance is determined based on fiber optic monitoring data. A supporting recycling and treatment system is used to realize the recycling of fracturing fluid, and solid waste is transferred to land for harmless disposal.

[0019] Furthermore, in S5, the segmented flowback strategy is optimized according to the reservoir and depletion state: initial flow rate of 5-6 m / s for low-permeability reservoirs. 3 / h, initial velocity of medium-high permeability reservoirs is 4-5m / h 3 / h, initial velocity of sand-producing reservoirs with medium to high permeability depletion is 3-4m 3 / h; the criteria for judging compliance with the backflow standard are a sudden temperature drop of ≥3℃, a pressure fluctuation of ≤0.5MPa, and a sand content of ≤0.1% in the backflow liquid.

[0020] Furthermore, this includes post-production timeline collaborative monitoring and well abandonment timeline monitoring. The fiber optic monitoring system is retained, and a "timeline-pressure-production capacity" correlation model is constructed to dynamically assess the effectiveness of the fracture network and guide production parameter and timeline adjustments. When well conditions meet the well abandonment criteria, based on the distributed fiber optic monitoring system, monitoring is conducted for 30 days in segments according to the well construction timeline before well abandonment, with pressure fluctuations ≤0.2MPa as the formation stability standard. During well abandonment, cement slurry bonding quality is monitored through fiber optic temperature changes. After well abandonment, data is remotely collected quarterly for two years to ensure marine ecological safety.

[0021] The advantages and positive effects of this invention are: 1. Outstanding innovation in timing control: This invention pioneered a dual-core control model of "timing attention mechanism + pressure field superposition", breaking through the rigid limitations of traditional fixed timing planning, and realizing dynamic adaptive optimization of inter-well timing intervals and pumping parameters. Compared with the existing fixed timing asynchronous process, the reservoir utilization rate is improved by more than 20 percentage points, reaching more than 85% overall. The timing superposition of multi-well fracturing fields is precise and controllable, effectively solving two major technical problems: insufficient expansion of fracture network in low-permeability reservoirs and ineffective interference across wells in medium- and high-permeability reservoirs.

[0022] 2. Strong equipment load adaptability: This invention, through a time-sequential equipment operation strategy, strictly controls the load of equipment operating simultaneously on the platform within a safe threshold, perfectly adapting to offshore power supply capabilities and deck space-constrained scenarios; the efficiency of inter-well switching is improved by 50%, and the operation timeliness is improved by more than 40% compared with the traditional asynchronous process, completely breaking the constraint of equipment load on multi-well collaborative pressure drive.

[0023] 3. Excellent stability of fracturing fluid sequence: The composite modified fracturing fluid system developed in this invention specifically solves the problem of viscosity decay within asynchronous construction intervals. The viscosity retention rate within a 6-hour construction interval is ≥85%, and the delayed gel breaking characteristic can accurately adapt to the needs of asynchronous segmented injection. The reservoir damage rate is controlled within 8%, and the fracturing fluid recovery rate is ≥90%, taking into account both construction stability and green environmental protection requirements.

[0024] 4. Wide range of applications: This invention can be widely adapted to various development scenarios such as low-permeability, medium-high permeability, medium-high permeability depletion and sand production, tight reservoirs, igneous intrusion zones, and old well production enhancement. It is especially suitable for complex working conditions such as limited platform equipment load, large differences between reservoir layers, and sand production in medium-high permeability reservoirs. Through precise matching design of "time-series strategy - reservoir type - depletion state", it forms a special time-series control and fracturing fluid support scheme for medium-high permeability depleted sand production reservoirs. It can be further extended to the development of deepwater and ultra-deepwater oil and gas fields, with broad application prospects. Attached Figure Description

[0025] Figure 1 This is a schematic diagram of the overall process of an embodiment of the present invention. Detailed Implementation

[0026] The technical solution of the present invention will now be clearly and completely described with reference to the accompanying drawings. Obviously, the described embodiments are only some, not all, of the embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0027] The embodiments of the present invention will be further described below with reference to the accompanying drawings: like Figure 1 As shown, a method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea includes the following steps: S1: Pressure Drive Unit Division and Timing Baseline Planning. Specifically, based on the offshore platform well network layout, reservoir geological parameters (such as porosity, permeability, and geostress), igneous rock distribution characteristics, and equipment rated load, 3-5 wells are divided into a pressure drive unit. According to reservoir permeability classification and depletion status, the inter-well construction sequence interval and initial pumping parameters are set to determine the construction sequence priority.

[0028] Preferably, for low-permeability reservoirs, the focus is on enhancing the superposition of pressure fields and expanding the fracture network volume, with an inter-well construction interval of 2-4 hours; for medium-to-high permeability reservoirs (initial state), the focus is on suppressing cross-well interference and precisely controlling fracture extension, with an inter-well construction interval of 4-6 hours; for medium-to-high permeability depleted sand-producing reservoirs, the focus is on mitigating physical property decay, suppressing sand production, and stabilizing the fracture network, with an inter-well construction interval of 5-7 hours to meet the requirements for proppant placement and stabilization.

[0029] Preferred low-permeability reservoirs (permeability < 1 mD) have a discharge rate of 18-25 m³ / h. 3 / min, sand ratio 16-36%, viscosity 40-80 mPa·s; discharge rate of medium-high permeability reservoirs (initial state, permeability 10-100 mD) 12-18 m 3 / min, sand ratio 20-40%, viscosity 70-110mPa·s; medium-high permeability depleted sand-producing reservoirs (permeability 5-80mD) discharge rate 6-10m 3 / min, sand ratio 24-48%, viscosity 90-130mPa·s.

[0030] Using a combination of well logging and microseismic monitoring technologies, the system collects data on reservoir thickness, natural fracture development patterns, and geostress gradient for each well. It focuses on collecting data on actual permeability (5-80 mD), porosity (2-5 percentage points lower than the initial value), and historical sand production data for medium- and high-permeability depleted reservoirs. Combined with the platform equipment load threshold, it accurately determines the segmented fracturing range, initial pumping parameters, and time sequence construction priority for each well.

[0031] S2: Construction and Parameter Optimization of Multi-Well Fracturing Sequence Dynamic Control Model. Specifically, based on the reservoir data and equipment load data obtained in S1, an improved LSTM neural network model incorporating a time-series attention mechanism is constructed. The input parameters include real-time pump pressure, discharge rate, formation response signals, microseismic monitoring data, distributed fiber optic monitoring data (temperature, strain), and equipment operating load data. This model predicts in real-time the pressure field superposition effect of multi-well sequential construction, fracture extension direction, inter-well interference level, and sand production precursors in medium-to-high permeability depleted reservoirs.

[0032] Based on the predicted results, the inter-well timing interval (adjustment range of ±0.5-1 hour) and single-well pumping parameters are dynamically optimized: for low-permeability reservoirs, the pressure superposition effect is enhanced by shortening the timing interval and increasing the flow rate of subsequent wells; for medium-to-high permeability reservoirs (initial state), ineffective interference is suppressed by extending the timing interval and reducing the sand ratio of subsequent wells (10-25%); for medium-to-high permeability depleted sand-producing reservoirs, the stability of fracture wall support is enhanced and sand production is suppressed by fine-tuning the timing interval to 5.5-6.5 hours, increasing the proppant sand ratio (20-40%), and optimizing the fracturing fluid viscosity (70-110 mPa·s), thus ensuring that the vertical modification degree of the reservoir is not less than 90%.

[0033] The preferred time-series dynamic control model strengthens the influence weight of preceding well construction on the pressure field of subsequent wells through a time-series attention mechanism, effectively improving the accuracy of cross-well time-series interference prediction with a prediction error of ≤3%. Compared to the traditional LSTM model, the time-series control response speed is improved by 40%, enabling minute-level time-series interval and pumping parameter adjustments. Simultaneously, it links with real-time equipment operating load data, achieving synergy between load and time-series control and eliminating the risk of equipment overload. For medium-to-high permeability depleted sand-producing reservoirs, this model can accurately identify sand-producing precursors through correlation analysis of fiber optic strain data and pump pressure changes, triggering parameter adjustment commands 0.5-1 hour in advance to enhance fracture wall support stability.

[0034] S3: Sequential Deployment and Operation of Modular Electric Fracturing Equipment. Specifically, a 25,000-horsepower fully electric fracturing system is adopted, enabling modular equipment to start and stop in a timed manner and to quickly switch between wells according to time priority. The equipment operating load is adjusted in real time through the onshore remote command center, controlling the load of simultaneously operating equipment to not exceed 80% of the platform's power supply threshold, thus avoiding the risk of overload. High-pressure corrosion-resistant quick-connect pipelines are used for interconnection between wells, strictly controlling the well switching time to within 30 minutes, and accurately matching the timing rhythm of asynchronous construction.

[0035] Preferably, the electric-driven fracturing system has passed the environmental certification of the classification society and can be used for offshore platform operations in water depths of ≤1500 meters. The energy consumption fluctuation of the equipment during timing switching is ≤10%, which is more than 25% lower than the energy consumption of traditional diesel-driven fracturing equipment. A single platform can achieve asynchronous collaborative construction of 4 wells through timing control, which greatly improves the efficiency of operation.

[0036] S4: Time-stable fracturing fluid preparation, staged injection, and fiber optic collaborative monitoring. Specifically, a temperature- and salt-resistant time-stability slickwater fracturing fluid system is configured, using seawater as the configuration medium (suitable for offshore freshwater scarcity scenarios, compatible with surface seawater with a salinity of 30,000-50,000 mg / L and formation water with a salinity of 150,000-200,000 mg / L). The base fluid uses guar gum modified by hydroxypropyl etherification-enzymatic hydrolysis-crosslinking (residue content ≤0.1%), which improves compatibility with seawater ions through molecular structure modification. It is compounded with 0.3-0.5% organic cationic anti-swelling agent (a compound of hexadecyltrimethylammonium chloride and betaine, with salt tolerance up to 200,000 mg / L), 0.25-0.45% time-stability stabilizer (a copolymer of amphoteric polyacrylamide and sulfonated phenolic resin, which has both salt resistance and long-term viscosity stabilization function), and 0.05-0.1% delayed biodegradable breaker (a composite system of ammonium persulfate and ethyl formate, with flexible controllable breaker delay time and salt resistance suitable for all sea conditions). For medium-to-high permeability depleted sand-producing reservoirs, the selection and ratio of proppant are optimized. A mixture of 0.425-0.85mm ceramic proppant and 5-8% fine-particle proppant (0.15-0.212mm) is used to improve the compactness of fracture wall filling and block formation sand migration. Under conditions of 120-130℃ and a salinity of 3-200,000 mg / L (covering the range from seawater to formation water), the viscosity of this system remains stable above 30 mPa·s for 6 hours after standing. After 2 hours of shearing, the viscosity decay rate is ≤15%, the filtration loss is ≤5 mL / min, and the core damage rate is ≤8%. Furthermore, there is no precipitation or stratification after mixing with seawater, allowing for direct preparation using nearby seawater from offshore platforms without additional desalination. This system is fully compatible with the needs of asynchronous staged injection at sea and the stimulation of medium-to-high permeability depleted sand-producing reservoirs.

[0037] Specifically, the time-stable fracturing fluid is specifically designed to enhance its compatibility with offshore seawater and its salt tolerance: through cross-linking modification and molecular chain modification, the system maintains stable performance within a salinity range of 3-200,000 mg / L. It can be directly configured using readily available offshore water sources such as surface seawater and platform production runoff, significantly reducing freshwater transportation and storage costs, which is suitable for the construction conditions of offshore platforms where space is limited and freshwater is scarce. The viscosity retention rate is ≥85% within the longest interval of asynchronous construction (6 hours), and the delayed breaker can flexibly adjust the breaking time according to the construction sequence requirements (4-8 hours). Moreover, the breaking efficiency is stable in high-salt environments, effectively avoiding premature breaking that leads to a decrease in proppant carrying capacity. Its residue content is reduced by more than 60% compared to conventional guar gum fracturing fluids, and the residue particles are not easy to aggregate in high-salt environments, significantly reducing the risk of reservoir damage and the difficulty of flowback.

[0038] Distributed fiber optic monitoring systems are pre-installed in the target reservoirs of each well (selected by casing external bonding, internal wall placement, or open hole placement according to the well completion type) to collect temperature and strain field data from multiple wells in real time. The pressure field superposition range is inverted by temperature changes, and the fracture aperture is quantitatively calculated (controlled within 0.8-1.2 mm) by strain data. The system focuses on capturing strain anomalies caused by sand production in medium-to-high permeability depleted reservoirs, and dynamically adjusts injection parameters and construction sequence based on feedback from time series models.

[0039] S5: Post-fracturing staged flowback and environmental treatment, along with timely monitoring. After fracturing operations are completed, based on distributed fiber optic monitoring data and a time-series control model, staged gradient flowback is initiated according to the construction sequence priority. Optimized flowback strategies are applied for reservoirs with different permeability and depletion states: low-permeability reservoirs employ a "slow-fast-stable" flowback strategy (initial rate 5-6 m / s²). 3 / h), to avoid premature fracture closure; for medium-to-high permeability reservoirs (initial state), a "steady-slow" flowback strategy (initial rate 4-5m) is adopted. 3 / h), to suppress interlayer crossflow; for medium-to-high permeability depleted sand-producing reservoirs, a "low-velocity stable discharge" strategy (initial rate 3-4m / h) is adopted. 3 / h), combined with fiber optic strain data to regulate the return flow rate, to prevent proppant backflow and secondary migration of formation sand.

[0040] Specifically, during the flowback process, the temperature and pressure changes along the wellbore are monitored in real time using a fiber optic system. Combined with the analysis results of flowback fluid sampling (sand content, viscosity, and residue content), the flowback efficiency, residue transport patterns, and sand production dynamics are analyzed. When a section of the well experiences a sudden temperature drop of ≥3℃, pressure fluctuation ≤0.5MPa, and a flowback fluid sand content ≤0.1%, the flowback for that section is deemed to have met the standards. The flowback priority is then adjusted to optimize the overall flowback efficiency. A supporting fracturing fluid recovery and treatment system, through an integrated process of "filtration-sand removal-ion adjustment-viscosity compensation," specifically enhances the sand removal module's processing capacity, removing over 99.5% of formation sand and proppant debris, achieving a fracturing fluid recovery rate of ≥90%. The recovered fluid can be directly recycled for subsequent operations. Solid waste generated during the operation is uniformly transported to land for harmless disposal, fully complying with offshore environmental regulations.

[0041] After the pressure-driven operation is completed, the production phase begins. The distributed fiber optic monitoring system continues to operate, collecting real-time data on reservoir temperature, pressure, and strain from multiple wells. Combined with production data such as wellhead productivity, water cut, and sand production, a "time-pressure-productivity-sand production" correlation model is constructed to dynamically assess the effectiveness of the asynchronous pressure-driven fracture network, formation energy changes, and sand production risks in medium-to-high permeability depleted reservoirs. Optimized control strategies are implemented for different reservoirs: for low-permeability reservoirs, strain data is used to monitor fracture closure rates, guiding the timely, segmented replenishment of weak gel fluid to maintain fracture effectiveness; for medium-to-high permeability reservoirs (initial state), abnormal temperature field fluctuations (sudden rise / fall ≥2℃) provide early warning of water and gas channeling risks, allowing for timely adjustments to production parameters and timing; for medium-to-high permeability depleted sand-producing reservoirs, abnormal strain data fluctuations provide early warning of sand production rebound, allowing for timely reduction of production volume and optimization of injection-production timing to ensure a production stability rate ≥90%.

[0042] Preferably, the system also includes time-series monitoring during the well abandonment phase. When the well condition meets the abandonment criteria, a distributed fiber optic monitoring system is used to monitor the well for 30 days in segments according to the well construction sequence before abandonment, with a pressure fluctuation of ≤0.2MPa as the formation stability standard. During the well abandonment operation, the integrity of the cement slurry bonding is accurately verified through fiber optic temperature change curves to ensure cementing quality. The cement slurry bonding quality is monitored through fiber optic temperature change during well abandonment. After well abandonment, data is collected remotely on a quarterly time-series basis and continuously monitored for 2 years to ensure marine ecological safety.

[0043] The present invention will be further illustrated below with specific embodiments: Example 1

[0044] The KL3-2 oilfield multi-well asynchronous pressure drive technology upgrade project addresses the issue that the reservoir in this oilfield is medium-to-high permeability sandstone. Due to the influence of igneous rock interlayers, there are significant differences in permeability between the layers, limiting the power supply load of the platform. Traditional synchronous pressure drive is prone to equipment overload and shutdown, while conventional asynchronous processes have limited capacity improvement due to rigid timing control. Therefore, it is urgent to adopt the technology of this invention to achieve efficient development. The specific implementation steps are as follows: S1: Pressure Drive Unit Division and Timing Benchmark Planning: Wells A21, A22, and A23 in the KL 3-2 oilfield are divided into one pressure drive unit. The reservoir permeability is 40-70 mD. Based on the standard for medium-to-high permeability reservoirs, the inter-well construction sequence interval is set at 5 hours, and well A21 is identified as the priority well for construction. Through combined logging and microseismic monitoring, the target reservoir thickness is determined to be 10-14 meters, and the geostress gradient is 2.4 MPa / 100m. Combined with the platform equipment load threshold, the initial pumping parameters are set as follows: flow rate 6-10 m³ / h. 3 / min, sand ratio 15-25%, fracturing fluid viscosity 60-80mPa·s, and the load of equipment operating simultaneously is strictly controlled within 75%.

[0045] S2: Construction and Parameter Optimization of Temporal Dynamic Control Model: An improved LSTM model incorporating a temporal attention mechanism was constructed, incorporating real-time pump pressure, discharge rate, microseismic signals, and distributed fiber optic monitoring data from three wells. Two hours after well A21 was drilled, the model predicted that its pressure field would spread towards well A22, posing a risk of intrusion into igneous interlayers. Therefore, the drilling interval for well A22 was dynamically extended to 5.5 hours, while the sand ratio of well A22 was reduced to 18%. During the drilling phase of well A23, the model detected insufficient superposition of pressure fields between wells, so the drilling interval was shortened to 4.5 hours, and the discharge rate was increased to 16 m³ / h. 3 / min, to ensure effective connection of the cross-well fracture network.

[0046] S3: Time-based deployment and operation of equipment: Deploy a 25,000-horsepower fully electric fracturing system, including four 5,000-horsepower electric fracturing skids, two 130-barrel electric sand mixing skids, and one centralized integrated control center. The equipment is started and stopped in stages according to the time-based construction priority. During the construction of well A21, two fracturing skids are started, and the equipment is operating at 70% load. When switching to well A22, one fracturing skid is shut down, and the sand mixing skid parameter switching module is started. The inter-well pipeline connection and parameter adjustment are completed within 30 minutes, and the equipment load is stabilized at 72%, with no risk of overload throughout the process.

[0047] S4: Fracturing Fluid Preparation, Segmented Injection, and Fiber Optic Co-monitoring: A time-stabilized fracturing fluid was prepared using surface seawater from the Bohai Sea (mineralization 35,000 mg / L) as the preparation medium. The base fluid was a 0.2% composite modified guar gum solution, with the addition of 0.4% organic cationic anti-swelling agent, 0.35% time-stabilizing agent, and 0.08% delayed breaker. Indoor experiments showed that, under conditions of 120℃ and mineralization of 35,000 mg / L (seawater) and 180,000 mg / L (formation water), the viscosity of this fracturing fluid after 5 hours of standing was 32 mPa·s and 31 mPa·s, respectively. After 2 hours of shearing, the viscosity decay rate was ≤12% for both, the breaker delay time was 6 hours, the core damage rate was 7.2%, and after mixing with seawater and standing for 24 hours, there was no sedimentation or stratification, fully meeting the requirements for offshore operations. All three wells were pre-installed with externally bonded distributed fiber optic monitoring systems for the target reservoirs. During injection in well A21, fiber optic monitoring detected a strain value of 190 με at a depth of 1050 m, indicating a fracture aperture of 0.9 mm, which met design requirements. During the construction of well A22, the injection rate was adjusted to 14 m³ / s by inverting the pressure field superposition range using fiber optic temperature field data. 3 / min, effectively avoiding interference with the fracture network that has formed in well A21.

[0048] S5: Post-compression staged flowback and environmental treatment: Flowback operations were initiated according to the construction sequence priority. Well A21 adopted a "steady-slow" flowback strategy for medium-to-high permeability reservoirs, with an initial flowback rate of 4.5m. 3 / h. When fiber optic monitoring detected a sudden temperature drop of 3.2℃ and a pressure fluctuation of 0.3MPa in the 1040-1060m well section, it was determined that the flowback in that section met the standards, and the flowback rate was immediately adjusted to 6m / h. 3 / h. After being treated by the recycling and treatment system, 75% of the waste fracturing fluid is recycled for the construction of well A23, and 25% is discharged in compliance with standards. The solid waste from the operation is uniformly transferred to land for incineration and harmless disposal. It has successfully passed the special acceptance inspection for marine environmental protection, and the overall return efficiency reaches 89%.

[0049] In this embodiment, after the asynchronous pressure drive operation of the three wells was completed, the vertical transformation degree of the reservoir reached 91%, the average production capacity of a single well increased by 55% compared with the traditional asynchronous process, the operation cycle was shortened by 38% compared with the plan, and the equipment operating load remained stable at 70-75% throughout the process, with no overload shutdown. In the later production stage, continuous monitoring through distributed optical fiber showed no risk of layer crossing within 6 months, and the production capacity stability rate reached 92%. Before the well was abandoned, monitoring through the optical fiber system for 30 days showed that the formation pressure fluctuation was 0.18MPa, meeting the stability standard, and the cement slurry bonding integrity met the standard with no leakage risk. This fully verified the reliability and technical superiority of the process of this invention in offshore medium and high permeability reservoirs and equipment load-limited scenarios. Example 2

[0050] This invention is applied to the production enhancement and renovation of three old wells. These wells, completed using screen pipes, are located in medium-to-high permeability sandstone reservoirs. After 12 years of depletion-type extraction, the initial permeability (25-50 mD) has decreased to 15-35 mD, and the porosity has dropped from 31% to 27%. The screen pipes show minor damage, and sand production has led to a production reduction of over 70%. Furthermore, fracturing fluid channeling and screen pipe blockage are prone to occur. The specific steps of this invention are as follows: Three wells were divided into one hydraulic fracturing unit, with an initial time interval of 6 hours. An optimized scheme was implemented to address sand production requirements: the fracturing fluid viscosity was adjusted to 75-90 mPa·s, and 0.425-0.85mm ceramic particles were mixed with 7% fine-particle proppant, with a sand ratio controlled at 20-28%. A time-series dynamic control model, combined with real-time monitoring of sand production precursors using fiber optic strain data, was used to dynamically fine-tune the inter-well time interval to 5.5-6.5 hours, balancing fracture network support and sand production suppression requirements. After the operation, the single-well productivity recovery rate reached 86%, a 42% increase compared to traditional methods. Within six months of production, sand production was controlled below 0.05%, with no screen blockage. The fracturing fluid recycling rate was 93%, fully meeting the requirements for low-damage, anti-cross-flow, and sand-suppressing stimulation of old offshore wells with medium-to-high permeability depletion.

[0051] The advantages and positive effects of this invention are: 1. Outstanding innovation in timing control: This invention pioneered a dual-core control model of "timing attention mechanism + pressure field superposition", breaking through the rigid limitations of traditional fixed timing planning, and realizing dynamic adaptive optimization of inter-well timing intervals and pumping parameters. Compared with the existing fixed timing asynchronous process, the reservoir utilization rate is improved by more than 20 percentage points, reaching more than 85% overall. The timing superposition of multi-well fracturing fields is precise and controllable, effectively solving two major technical problems: insufficient expansion of fracture network in low-permeability reservoirs and ineffective interference across wells in medium- and high-permeability reservoirs.

[0052] 2. Strong equipment load adaptability: This invention, through a time-sequential equipment operation strategy, strictly controls the load of equipment operating simultaneously on the platform within a safe threshold, perfectly adapting to offshore power supply capabilities and deck space-constrained scenarios; the efficiency of inter-well switching is improved by 50%, and the operation timeliness is improved by more than 40% compared with the traditional asynchronous process, completely breaking the constraint of equipment load on multi-well collaborative pressure drive.

[0053] 3. Excellent stability of fracturing fluid sequence: The composite modified fracturing fluid system developed in this invention specifically solves the problem of viscosity decay within asynchronous construction intervals. The viscosity retention rate within a 6-hour construction interval is ≥85%, and the delayed gel breaking characteristic can accurately adapt to the needs of asynchronous segmented injection. The reservoir damage rate is controlled within 8%, and the fracturing fluid recovery rate is ≥90%, taking into account both construction stability and green environmental protection requirements.

[0054] 4. Wide range of applications: This invention can be widely adapted to various development scenarios such as low-permeability, medium-high permeability, medium-high permeability depletion and sand production, tight reservoirs, igneous intrusion zones, and old well production enhancement. It is especially suitable for complex working conditions such as limited platform equipment load, large differences between reservoir layers, and sand production in medium-high permeability reservoirs. Through precise matching design of "time-series strategy - reservoir type - depletion state", it forms a special time-series control and fracturing fluid support scheme for medium-high permeability depleted sand production reservoirs. It can be further extended to the development of deepwater and ultra-deepwater oil and gas fields, with broad application prospects.

[0055] The foregoing has provided a detailed description of one embodiment of the present invention, but this description is merely a preferred embodiment and should not be construed as limiting the scope of the invention. All equivalent variations and modifications made within the scope of the claims of this invention should still fall within the patent coverage of this invention.

Claims

1. A method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea, characterized in that: Includes the following steps, S1: Pressure drive unit partitioning and timing reference planning; S2: Construction and parameter optimization of a time-series dynamic control model for multi-well fracturing; S3: Sequential deployment and operation of modular electric-driven fracturing equipment; S4: Time-stable fracturing fluid preparation, staged injection, and fiber optic collaborative monitoring; S5: Post-pressurization staged return discharge and environmental protection treatment and timely monitoring.

2. The asynchronous hydraulic fracturing process method with time-controlled multi-well fracturing at sea according to claim 1, characterized in that: In S1, based on the well network layout of the offshore platform, reservoir geological parameters, igneous rock distribution characteristics, and equipment rated load, 3-5 wells are divided into a pressure drive unit. According to the reservoir permeability classification and depletion state, the well construction sequence interval and initial pumping parameters are set to determine the construction sequence priority.

3. The method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea according to claim 2, characterized in that: In S1, the well construction interval is set to 2-4 hours for low-permeability reservoirs; the initial state interval is set to 4-6 hours for medium- and high-permeability reservoirs; and the interval is set to 5-7 hours for medium- and high-permeability depleted and sand-producing reservoirs.

4. A method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea, as described in any one of claims 1 to 3, characterized in that: In S2, based on the reservoir data and equipment load data obtained in S1, an improved LSTM neural network model incorporating a time-series attention mechanism is constructed. Real-time pump pressure, discharge rate, formation response signals, microseismic data, distributed optical fiber monitoring data, and equipment operating load data are input to predict the pressure field superposition effect, fracture extension direction, inter-well interference level, and sand production precursors in real time. Based on the prediction results, the time interval and single-well pumping parameters are dynamically optimized.

5. A method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea according to any one of claims 1 to 3, characterized in that: In S3, modular equipment is started and stopped in a time-sharing manner and quickly switched between wells according to time priority, and the load of the equipment running at the same time is controlled to not exceed 80% of the platform power supply threshold, and the switching time between wells is ≤30 minutes.

6. A method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea according to any one of claims 1 to 3, characterized in that: In S4, seawater is used as the preparation medium to prepare a time-stabilized fracturing fluid with hydroxypropyl etherified-enzymatic hydrolysis-crosslinked modified guar gum as the base fluid, and 0.3-0.5% organic cationic anti-swelling agent, 0.25-0.45% time-stabilizer and 0.05-0.1% delayed biodegradable breaker are added; the "single-well segmented injection + multi-well fiber optic collaborative monitoring" mode is adopted to invert the pressure field superposition range and fracture opening in real time.

7. The method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea according to claim 6, characterized in that: The time-stabilized fracturing fluid maintains stable performance within a salinity range of 3-200,000 mg / L, with a viscosity retention rate of ≥85% within a maximum asynchronous construction interval of 6 hours. The rupture time of the delayed breaker is adjustable within a range of 4-8 hours, and the residue content is reduced by more than 60% compared to conventional guar gum fracturing fluid. Under conditions of 120-130℃ and salinity of 3-200,000 mg / L, the viscosity of the time-stabilized fracturing fluid is ≥30 mPa·s after standing for 6 hours, the viscosity decay rate is ≤15% after 2 hours of shearing, the filtration loss is ≤5 mL / min, and the core damage rate is ≤8%.

8. A method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea according to any one of claims 1 to 3, characterized in that: In S5, gradient backflow is initiated according to the construction sequence priority, and the backflow compliance is determined based on fiber optic monitoring data. A supporting recycling and treatment system is used to realize the recycling of fracturing fluid, and solid waste is transferred to land for harmless disposal.

9. The asynchronous hydraulic fracturing process method with time-controlled multi-well fracturing as described in claim 8, characterized in that: In S5, the segmented flowback strategy is optimized according to the reservoir and depletion state: initial flow rate of 5-6 m / s for low-permeability reservoirs. 3 / h, initial velocity of medium-high permeability reservoirs is 4-5m / h 3 / h, initial velocity of sand-producing reservoirs with medium to high permeability depletion is 3-4m 3 / h; the criteria for judging compliance with the backflow standard are a sudden temperature drop of ≥3℃, a pressure fluctuation of ≤0.5MPa, and a sand content of ≤0.1% in the backflow liquid.

10. A method for asynchronous hydraulic fracturing with time-controlled multi-well fracturing at sea according to any one of claims 1 to 3, characterized in that: It also includes post-production time-series collaborative monitoring and well abandonment time-series monitoring, retains the fiber optic monitoring system, constructs a "time-pressure-capacity" correlation model, dynamically evaluates the effectiveness of the fracture network, and guides production parameters and time-series adjustments; When the well conditions meet the conditions for well abandonment, a distributed optical fiber monitoring system is used to monitor the well for 30 days in segments according to the well construction sequence before abandonment, with a pressure fluctuation of ≤0.2MPa as the formation stability standard; during well abandonment, the cement slurry bonding quality is monitored by optical fiber temperature change; after well abandonment, data is collected remotely in quarterly sequence and monitored continuously for 2 years to ensure marine ecological safety.

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