Fracturing fluid and proppant synergistic fracturing method and system based on extreme flow limiting effect

Abstract

The application discloses a fracturing fluid and proppant synergistic fracturing method and system based on limit flow effect, and belongs to the technical field of oil and gas exploitation engineering, and the method core comprises the following steps: based on erosion evolution prediction, dynamic perforation compensation design is carried out, and initial perforation parameters with erosion allowance are backstepped; a shear thickening type variable viscosity fracturing fluid and a ladder particle size proppant synergistic system are constructed; limit flow effect is excited through high discharge construction, multi-cluster fracture balanced initiation and liquid sand synergistic pumping are realized; and real-time closed-loop feedback regulation and control are carried out based on distributed optical fiber sensing. The application solves the technical problems of uneven multi-cluster initiation, limit flow failure caused by hole erosion, poor liquid sand matching and regulation lag in unconventional reservoir fracturing, and can realize balanced initiation of multi-cluster fractures and efficient support of full-scale fracture network in deep strong heterogeneous oil and gas reservoirs, and greatly improves fracturing transformation effect and single well productivity.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas extraction engineering technology, specifically involving production enhancement technology for horizontal well volumetric fracturing in unconventional oil and gas reservoirs such as shale gas and tight oil, and particularly involving a fracturing method and system based on the ultimate flow restriction effect of fracturing fluid and proppant. Background Technology

[0002] Horizontal well volumetric fracturing technology is a core technology for the efficient development of unconventional oil and gas resources such as shale oil and gas and tight gas. Its core objective is to create a complex fracture network in the reservoir by artificially creating fractures, forming a large-scale stimulated volume (SRV), which greatly increases the oil and gas seepage channels and improves the productivity of a single well.

[0003] As unconventional oil and gas development extends to deeper and ultra-deep reservoirs, reservoir geological conditions become increasingly demanding. Extreme environments characterized by ultra-high geostress, high temperatures, and high closure pressure place higher demands on fracture propagation uniformity and long-term fracture conductivity. Bottlenecks in traditional fracturing techniques, such as equipment pressure-bearing limits, material thermal stability, and proppant migration efficiency, are becoming increasingly prominent, severely restricting the fracturing effect of deep unconventional oil and gas reservoirs.

[0004] In actual fracturing operations, unconventional reservoirs generally exhibit strong heterogeneity, with significant differences in the geomechanical conditions of different perforation clusters within the same fracturing section. This leads to marked differences in fracture initiation resistance among different perforation clusters. Fracturing fluid preferentially enters the dominant perforation clusters with lower initiation resistance, resulting in severe uneven fluid inflow among clusters within the section. Field monitoring data shows that under traditional fracturing techniques, typically only a few perforation clusters effectively initiate fractures within the same fracturing section, while a large number of perforation clusters remain dormant. This not only significantly reduces the effective reservoir stimulation volume but also results in a serious waste of fracturing materials and reservoir resources.

[0005] To address the technical challenge of achieving uniform initiation of multiple crack clusters, existing technologies primarily improve uneven flow distribution by increasing the construction discharge rate and employing limit flow restriction techniques that enhance orifice friction. However, these technologies still suffer from the following inherent drawbacks in practical applications: 1. High-displacement construction presents a contradiction between exacerbated flow unevenness and construction safety. Simply increasing the construction displacement, under conditions of strong reservoir heterogeneity, can further intensify the concentration of fluid in the dominant channels. At the same time, the small-diameter, low-orifice perforation scheme designed to achieve flow restriction will generate extremely high friction at high displacement, which can easily exceed the pressure bearing limits of the wellhead and tubing, making it impossible to safely implement the flow restriction design under high displacement conditions.

[0006] 2. Traditional limit flow control techniques suffer from a contradiction between static design and dynamic erosion instability. Existing limit flow control techniques are mostly based on static design using initial construction parameters, severely neglecting the dynamic erosion effect of high-speed proppant particles on the perforation orifices during sand addition. The high-speed particle flow continuously erodes the orifices, leading to orifice enlargement and decreased friction. This causes the designed flow control effect to fail prematurely in the later stages of construction, making it impossible to maintain a uniform crack initiation state, and resulting in crack propagation falling back into unevenness.

[0007] 3. Lack of temporal and spatial coordination between fracturing materials and pumping procedures. Existing combined pumping procedures often experience pressure fluctuations during operation due to fluid system switching, and the proppant particle size lacks precise matching with the proppant carrying capacity of the fracturing fluid and the fracture propagation sequence. Large-diameter proppant particles easily clog the near-wellbore fracture network, while low-viscosity slickwater makes it difficult to transport high-concentration proppant over long distances, easily leading to insufficient near-wellbore support or failure of proppant placement at the far end of the fracture.

[0008] 4. Delayed construction process control and lack of adaptive closed-loop regulation capabilities. Current fracturing operations mostly rely on open-loop control modes based on preliminary static design, lacking dynamic sensing methods for real-time fluid inflow into each perforation cluster within the fracturing section. This makes it impossible to promptly identify and accurately intervene in uneven flow rates, resulting in severely delayed adjustments to construction parameters and very limited optimization effects.

[0009] In summary, the core challenge of fracturing in deep unconventional oil and gas reservoirs has evolved into how to create and support complex fracture networks across all scales in a balanced and efficient manner within highly heterogeneous reservoirs. Current technologies cannot systematically address the parameter conflicts between near-wellbore uniform fracture initiation and far-wellbore high-volume propagation, the reliability issues of static design and dynamic erosion instability, or the synergistic matching of fracturing material properties with fracture propagation requirements. Consequently, they struggle to meet the demands for efficient fracturing in deep unconventional oil and gas reservoirs. Summary of the Invention

[0010] To address the problems existing in the prior art, this invention provides a fracturing method and system based on the ultimate flow restriction effect of fracturing fluid and proppant, which solves the technical problems of uneven fracture initiation of multiple clusters of fractures, flow restriction failure caused by pore erosion, poor matching between fracturing fluid and proppant, and lagging construction control in existing unconventional reservoir fracturing. It achieves balanced fracture initiation of multiple clusters of fractures and efficient support of the full-scale fracture network in deep, highly heterogeneous reservoirs, significantly improving the fracturing effect and single-well productivity.

[0011] To achieve the above objectives, the technical solution adopted by this invention is: a dynamic synergistic fracturing method based on the ultimate flow restriction effect of fracturing fluid and proppant, applied to the volumetric fracturing stimulation of horizontal wells in unconventional oil and gas reservoirs, comprising the following steps: S1: Dynamic perforation compensation design based on erosion evolution prediction: obtaining the rock mechanical parameters, geostress field distribution characteristics, and design maximum construction discharge Q of the target reservoir. maxA dynamic model of perforation erosion was established to simulate the erosion enlargement of the perforation throughout the entire sand addition cycle, and to predict the equivalent hole diameter D at the end of construction. end Based on equivalent aperture D end The initial design aperture D is calculated by back-calculating the preset erosion compensation coefficient δ. start D start =D end (1-δ), where δ takes values ​​from 0.15 to 0.25; based on the initial design aperture D start Determine the number of perforations N per cluster to ensure that the maximum design flow rate Q is met. max Under these conditions, the initial perforation frictional resistance satisfies ΔP perf_init ≥1.2×(σ H_max -σ h_min ), where σ H_max and σ h_min These represent the maximum and minimum horizontal principal stresses within the segment, respectively.

[0012] S2: Constructing a synergistic system of shear-thickening variable viscosity fracturing fluid and stepped particle size proppant: Prepare a shear-thickening variable viscosity slickwater fracturing fluid, establish its dynamic evolution equation with shear rate and time, and substitute the dynamic evolution equation into the perforation erosion dynamics model of step S1 to calculate the real-time erosion rate; based on the initial design aperture D obtained in step S1... start A three-stage proppant injection program of fine-medium-coarse steps was designed to match the time-varying rheological properties of the fracturing fluid, wherein the synchronization error between the proppant concentration change rate and the fracturing fluid viscosity recovery rate was controlled within ±10%.

[0013] S3: High-displacement-inducing multi-cluster crack initiation and coordinated construction with ultimate flow restriction: Continuous pumping is used to linearly increase the construction displacement to the maximum design construction displacement Q. max The Q max It is 1.3 to 1.8 times the conventional critical fracturing initiation flow rate; utilizing the nonlinear friction surge effect generated by the high flow rate fluid flowing through the perforation orifice, the unevenness of flow distribution among the perforation clusters within the forced fracturing section is reduced to less than 15%, inducing at least 80% of the perforation clusters to initiate fracturing simultaneously; maintaining the maximum design construction flow rate Q. max Without changing, the three-stage proppant injection procedure in step S2 is executed to achieve coordinated control of high-displacement joint creation, variable viscosity sand carrying and flow restriction and diversion.

[0014] S4: Real-time closed-loop feedback control based on distributed fiber optic sensing: Using distributed acoustic wave sensing (DAS) fiber and distributed temperature sensing (DTS) fiber, the acoustic energy intensity and temperature drop of each perforation cluster are monitored in real time. The instantaneous liquid inflow rate of each cluster is inverted, and the liquid inflow non-uniformity coefficient U(t) within the segment is calculated in real time. A threshold value U is set for the non-uniformity coefficient. limit , when U(t)>U limitWhen the time is right, the corresponding adaptive control strategy is triggered to correct the deviation in the execution of construction parameters.

[0015] Furthermore, in step S1, the method for constructing the dynamic model of perforation hole erosion includes: (1) The erosion rate of a single particle was calculated using the Oka wear model. V p D is the particle velocity. p V is the particle size, α is the particle impact angle, K, n, and m are experimental constants related to the perforation casing material, and V is the particle diameter. ref D ref Here, the reference flow velocity and reference particle size are given, and f(α) is the impact angle function.

[0016] (2) Integrate the time over the entire sand-addition period T to calculate the total mass loss of a single hole. C s (t) represents the time-varying proppant concentration, and Q(t) represents the instantaneous construction discharge rate.

[0017] (3) Convert the total mass loss into the aperture increment ΔD, and determine the equivalent aperture D at the end of construction based on the aperture increment ΔD. end The initial aperture D target The target flow-limiting orifice diameter at the end of construction.

[0018] Furthermore, in step S2, the dynamic evolution equation of the shear-thickened variable viscosity slickwater fracturing fluid satisfies: High shear zone in the wellbore, i.e., γ > 500s -1 At that time, the fracturing fluid was kept at a low viscosity μ1 < 5 mPa·s.

[0019] Low-shear region of the crack, i.e., γ < 50s -1 At that time, the viscosity of the fracturing fluid increases exponentially with time t, satisfying μ2(t) = μ1 + A·(1-e -kt ), where A is the maximum viscosity increase and k is the response rate constant.

[0020] Furthermore, the specific components of the shear-thickening, viscous, slippery water fracturing fluid are as follows: The base fluid is clean water or backflow treated water; the viscosity modifier is 0.05%~0.15% by mass of modified guar gum, or 0.03%~0.08% by mass of nanocellulose suspension; the drainage aid is 0.1%~0.3% by mass of fluorocarbon surfactant; so that the fracturing fluid retains a viscosity greater than 85% after aging at 120℃~160℃ for 2 hours, and the residue content after breaking the gel is less than 50mg / L.

[0021] Furthermore, in step S2, the specific procedure for the fine-medium-coarse three-stage proppant injection is as follows: Phase 1: Pump in 40 / 70 mesh or 100 mesh fine-particle proppant, with the concentration controlled at 50~150 kg / m³. 3 It is used for filling microcracks and buffering erosion.

[0022] Second stage: Pumping in 30 / 50 mesh medium-sized proppant at a concentration of 150 kg / m³ 3 Linear increase to 300~600 kg / m 3 The proppant particle size is less than 0.6×D start , used to construct the suspended plug.

[0023] Third stage: Pump in 20 / 40 mesh coarse-grained proppant, with the concentration controlled at 400~800 kg / m³. 3 It is used to construct a high-conductivity channel in the main fracture.

[0024] Furthermore, in step S3, the maximum construction discharge capacity Q is designed. max The following dual constraints must be met: Constraint 1, Equipment Safety Constraint: Total wellhead construction pressure ≤ 0.9 × P rating , where P rating This refers to the rated working pressure of the wellhead equipment and casing.

[0025] Constraint 2, Effective Constraint for Current Limiting: In Q max Below, the initial perforation friction ΔP perf_init ≥1.5×Δσ cluster , where Δσ cluster This represents the maximum inter-cluster stress difference within the segment.

[0026] If both conditions cannot be met simultaneously, prioritize adjusting the perforation parameters N and D. start Once constraint two is satisfied, constraint one is then checked.

[0027] Furthermore, in step S4, the adaptive control strategy is specifically as follows: If the acoustic energy of the dominant cluster continues to rise and is accompanied by high-frequency erosion noise above 2kHz, it is determined that the erosion has caused the flow limiting failure, and the sand reduction and pressure maintenance operation is performed: within 30 seconds, the proppant concentration is reduced by 30%~50%, and at the same time, high-density temporary plugging balls are injected to seal the orifice of the dominant cluster.

[0028] If the acoustic energy of the dominant cluster increases but there is no high-frequency erosion noise, it is determined that the uneven flow is dominated by the difference in ground stress. The operation of increasing the discharge rate and increasing the resistance is carried out: the construction discharge rate is increased by 5% to 10% instantaneously, and the flow rate of each cluster is balanced by the square relationship between the perforation friction and the flow rate.

[0029] Furthermore, in step S4, the adaptive control strategy also includes a pulse-type temporary blocking steering sub-step: (1) After two consecutive adjustments, the non-uniformity coefficient U(t) of the influent still did not decrease to the non-uniformity coefficient threshold U. limit The following steps will trigger a pulse-based temporary blocking procedure.

[0030] (2) Rapidly inject a concentration of 100~200 kg / m into the wellbore. 3 Biodegradable fiber slugs with a particle size of 1-3 mm, the volume of which is 1.2-1.5 times the wellbore volume.

[0031] (3) The bridging effect of the fiber septum at the orifice of the dominant cluster increases the local friction, forcing the subsequent fluid to turn to the weak cluster.

[0032] (4) After the fiber slug injection is completed, restore the original design and construction parameters, and monitor the steering effect through distributed acoustic wave sensing (DAS) fiber optic. If it is ineffective, repeat once, and no more than three times.

[0033] Furthermore, this method is applicable to deep shale gas or tight oil reservoirs with a burial depth of 4500m~8000m, a formation pressure coefficient of 1.5~2.2, and a closure stress of 60MPa~120MPa.

[0034] This invention also provides a dynamic synergistic fracturing system for fracturing fluid and proppant based on the limiting flow effect, used to perform the above-mentioned fracturing method, comprising: The design module has a built-in erosion evolution algorithm and rheological matching model, which is used to output perforation parameters with erosion compensation coefficients and liquid sand co-pumping tables.

[0035] The sensing module includes distributed fiber optic sensors laid along the horizontal well section and a ground data acquisition unit, used to collect monitoring data in real time and interpret the fluid ingress profile of each perforation cluster.

[0036] The decision-making module has a pre-set logic library for determining uneven liquid inflow and a control strategy tree, which is used to automatically generate construction parameter adjustment instructions based on the monitoring data from the sensing module.

[0037] The execution module, including the variable frequency fracturing pump set, high-precision sand mixing vehicle and automatic ball thrower, is used to receive adjustment instructions from the decision module and perform real-time adjustments to the construction parameters.

[0038] Compared with the prior art, the present invention has the following advantages: 1. This invention, through dynamic perforation compensation design based on erosion evolution prediction, reversely derives the initial perforation diameter from the end point and reserves erosion wear allowance, thus solving the problem of flow restriction failure caused by orifice erosion and diameter expansion in the later stages of construction in traditional static perforation design from the source. It ensures the stability of the flow restriction effect throughout the entire construction cycle and lays the foundation for the balanced crack initiation of multiple clusters of cracks.

[0039] 2. This invention constructs a spatiotemporal synergistic system of shear-thickening variable viscosity fracturing fluid and stepped particle size proppant. The fracturing fluid maintains low viscosity in the high-shear zone of the wellbore, reducing frictional resistance during high-flow-rate operations. In the low-shear zone of the fracture, the viscosity automatically recovers, enhancing proppant carrying capacity. Simultaneously, by precisely matching the three-stage stepped particle size proppant injection program with the time-varying rheological properties of the fracturing fluid, the contradiction between proppant "getting in" and "holding up" is resolved. This achieves effective filling of microfractures and constructs high-conductivity channels for the main fractures, significantly improving the support efficiency of the full-scale fracture network.

[0040] 3. This invention induces a limiting flow restriction effect through high displacement, utilizing the square proportional relationship between perforation friction and flow rate to make perforation friction dominate the net pressure at the bottom of the well. This effectively shields the stress differences between clusters caused by reservoir heterogeneity, forces uniform flow distribution among clusters within the section, and induces the synchronous fracturing of most perforation clusters, significantly increasing the effective reservoir stimulation volume. At the same time, through the synergy of high displacement and variable viscosity fracturing fluid, it takes into account the needs of large-displacement fracture creation and efficient proppant carrying, solving the parameter conflict between fracture creation and proppant carrying in traditional processes.

[0041] 4. This invention constructs a real-time closed-loop feedback control system based on distributed optical fiber sensing. By monitoring the fluid inflow of each cluster in real time through DAS / DTS optical fiber, it accurately identifies the causes of uneven flow and triggers adaptive control strategies accordingly. This achieves millisecond-level dynamic intervention in fracturing operations, solves the problem of lag in traditional open-loop control, ensures the balance of multi-cluster fracture propagation throughout the entire construction cycle, and significantly improves the reliability of fracturing operations and the stability of the modification effect.

[0042] 5. The method and system of this invention are specifically designed for deep shale gas and tight oil reservoirs with burial depths of 4500m to 8000m and closure stresses of 60MPa to 120MPa. The entire process is based on physical model calculations and real-time data feedback to achieve precise control, eliminating the reliance on experience-based trial and error in traditional processes. It can effectively adapt to the fracturing and stimulation needs in deep extreme geological environments and has broad prospects for field application and promotion value. Attached Figure Description

[0043] Figure 1 This is a flowchart of the method of the present invention. Detailed Implementation

[0044] The present invention will be further described below.

[0045] like Figure 1As shown, the fracturing method disclosed in this embodiment of the invention is specifically applicable to deep shale gas or tight oil reservoirs with a burial depth of 4500m~8000m, a formation pressure coefficient of 1.5~2.2, and a closure stress of 60MPa~120MPa. The perforation cluster spacing of the horizontal well fracturing section is set to 15m~25m, the number of perforations in each cluster is set to 6~12, and the initial perforation diameter is set to 6mm~9mm.

[0046] This embodiment provides a dynamic synergistic fracturing method for fracturing fluid and proppant based on the ultimate flow restriction effect. It was applied to the fracturing stimulation of a deep shale gas horizontal well. The target reservoir depth was 5800m, formation temperature was 145℃, closure stress was 85MPa, maximum horizontal principal stress was 132MPa, minimum horizontal principal stress was 108MPa, maximum inter-cluster stress difference within the segment was 24MPa, and the conventional critical fracturing initiation flow rate was 10m³ / s. 3 / min.

[0047] The specific implementation steps are as follows: Step S1: Dynamic perforation compensation design based on erosion evolution prediction: The core of this step is to design perforation parameters in reverse using an erosion evolution model, reserve allowance for perforation erosion and wear, and solve the problem of flow limitation failure in traditional static design.

[0048] S11. Parameter Acquisition and Erosion Evolution Simulation: First, the rock physical and mechanical parameters of the target reservoir were collected: Young's modulus 38 GPa, Poisson's ratio 0.23, and fracture toughness 1.8 MPa·m. 1 / 2 Characteristics of the geostress field distribution: maximum horizontal principal stress σ H_max =132MPa, minimum horizontal principal stress σ h_min =108MPa, maximum inter-cluster stress difference within the segment is 24MPa; Casing material parameters: P110 steel grade casing, density 7850kg / m³ 3 Hardness 320HB; Maximum designed construction discharge capacity Q max =16m 3 / min, which is 1.6 times the conventional critical displacement.

[0049] Based on Oka wear theory, a dynamic model of perforation hole erosion was established to simulate the scouring effect of proppant on the hole throughout the entire sand addition cycle. The specific model construction method is as follows: (1) The erosion rate E of a single particle was calculated using the Oka wear model: In the formula: V p D is the particle velocity. p Where α is the particle size, α is the particle impact angle, and K, n, and m are experimental constants related to the perforation casing material. In this embodiment, K is calibrated to 2.8 × 10⁻⁶ using indoor rotating jet erosion experiments. -9n=2.3, m=0.45; V ref D ref For reference flow velocity and reference particle size, we take 1 m / s and 1 mm, respectively; f(α) is the impact angle function, and for the tangential impact-dominated mode of the perforation aperture, we take f(α) = sin 2 α·(1+6.5(1-sinα)).

[0050] (2) Integrate over the entire sand-addition period T to calculate the total mass loss ΔM of a single orifice: In the formula: C s (t) represents the time-varying proppant concentration, Q(t) represents the instantaneous construction discharge rate, and E(t) represents the instantaneous erosion rate.

[0051] (3) Convert the total mass loss into aperture increment ΔD: In the formula: L is the length of the eyelet, ρ s Let ΔM be the casing density, and ΔM be the total mass loss.

[0052] (4) Based on the above model simulation, the equivalent aperture D at the end of construction in this embodiment is predicted. end =8.5mm.

[0053] S12. Initial aperture reverse compensation: Set the erosion compensation coefficient δ=0.2, and reverse calculate the initial design aperture D. start :D start =D end (1-δ)=8.5×(1-0.2)=6.8mm; In this embodiment, the initial design aperture is 7mm to ensure that the actual aperture at the end of construction is close to the target flow-limiting aperture and to avoid erosion causing flow-limiting failure.

[0054] S13. Perforation cluster parameter matching optimization: based on the revised initial design aperture D start =7mm, calculate the number of perforations N per cluster, the design principle is: in Q max =16m 3 At a rate of / min, the initial perforation friction ΔP perf_init Satisfy the following: ΔP perf_init ≥1.2×(σ H_max -σ h_min =28.8MPa.

[0055] The frictional resistance of the perforation is calculated using the modified form of Bernoulli's equation: In the formula: ρf is the density of the fracturing fluid, taken as 1000 kg / m³. 3 C dis the flow coefficient, taken as 0.75; N is the number of perforations per cluster.

[0056] Substituting the constraints into the formula, we obtain N ≤ 8.2. After rounding down, we determine the number of perforations per cluster as N = 8. Simultaneously, we verify the wellhead equipment's rated operating pressure of 70 MPa. The calculated sum of initial perforation friction, wellbore friction, and formation fracturing pressure is 62 MPa, which is less than 90% of the rated operating pressure, thus satisfying the equipment safety constraints.

[0057] Step S2: Constructing a synergistic system of shear-thickening variable viscosity fracturing fluid and stepped particle size proppant: The core of this step is to achieve precise matching between the spatiotemporal evolution of fracturing fluid rheology and the stepped particle size injection of proppant, thereby resolving the contradiction between fracture creation and proppant transport.

[0058] S21. Preparation and Rheological Model Construction of Shear-Thickening Variable Viscosity Slickwater Fracturing Fluid: The variable viscosity slickwater fracturing fluid prepared in this embodiment has the following components: the base fluid is flowback treated water; the viscosity enhancer is 0.06% by mass of nanocellulose suspension; the flow aid is 0.2% by mass of fluorocarbon surfactant; after aging at 145℃ for 2 hours, the viscosity retention rate of this fracturing fluid is 92%, and the residue content after gel breaking is 38mg / L, which meets the requirements for deep high-temperature reservoir construction.

[0059] The dynamic evolution equation of the fracturing fluid viscosity μ as a function of shear rate γ and time t was established and substituted into the erosion kinetic model of step S1 to calculate the real-time erosion rate: (1) High shear zone of wellbore (γ>500s) -1 The liquid exhibits shear-thinning properties, maintaining a low viscosity μ1 = 3.2 mPa·s < 5 mPa·s, reducing frictional resistance along the flow path when flowing through the perforation orifice at high flow rates, and ensuring that the initial flow-limiting frictional resistance requirements are met.

[0060] (2) Low shear zone of the crack (γ<50s) -1 The viscosity increases exponentially with time t, and the kinetic equation is: μ2(t) = μ1 + A·(1-e -kt In the formula: A is the maximum viscosity increase, which is taken as 30 mPa·s in this embodiment; k is the response rate constant, which is determined to be 0.008 s by indoor rheometer testing. -1 .

[0061] The viscosity recovery curve mentioned above is used as a time-varying parameter input into the erosion model in step S1 to simulate the changes in the liquid's suspension capacity on the proppant at different construction times and its nonlinear influence on the erosion rate, thereby correcting the calculation results of the cumulative erosion amount.

[0062] S22, Fine-Medium-Co Three-Stage Propionage Pumping Procedure Design: Based on the initial design orifice diameter D start=7mm, a three-stage stepped pumping procedure was designed to match the time-varying rheological properties of the fracturing fluid, ensuring that bridging does not occur during the maximum particle size stage, while the erosion rate is controlled by utilizing the viscosity characteristics of the fluid, as detailed below: Phase 1: Microcrack filling and erosion buffering period, time interval 0~20min, pumping in 100-mesh fine-grained proppant, sand-to-liquid ratio 5%~15% (concentration 50~150kg / m³) 3 At this point, the fracturing fluid is in a low-viscosity state, allowing fine sand to easily enter the microfractures. Simultaneously, the fine sand has a weak erosion effect on the perforation, providing a buffer for subsequent high-concentration sand addition. The low erosion rate data at this stage is used to correct the cumulative loss calculation in step S1. The synergistic condition requires the fluid viscosity to meet the suspension requirements of Stokes' sedimentation law. Where v settling The settling velocity must be less than the vertical transport velocity of the fluid within the crack to ensure that the fine sand can penetrate deep into the microcracks without settling.

[0063] Phase 2: Suspended slug construction, time interval 20-40 min, pumping in 30 / 50 mesh medium-sized proppant, linearly increasing the sand-to-liquid ratio from 15% to 60% (concentration 150-600 kg / m³). 3 At this point, the fracturing fluid viscosity has significantly increased according to the μ2(t) law, forming a high-suspension slug; the proppant particle size in this stage is 0.3~0.6mm, less than 0.6×D. start =4.2mm, to avoid bridging at the orifice; the synergistic condition is that the viscosity recovery rate and the concentration increase rate are synchronized, and the synchronization error ϵ is defined as: Where λ design The slope is matched to the preset sand-fluid mixture. In this stage, the increased viscosity is used to form a suspended slug to prevent the medium sand from settling in the middle of the fracture.

[0064] Phase 3: Main channel construction and erosion extreme value control period, time interval 40~90min, pumping in 20 / 40 mesh coarse-grained proppant, sand-liquid ratio stabilized at 40%~80% (concentration 400~800kg / m³) 3 This is used to construct a high-conductivity channel in the main fracture. In this stage, the synchronization error between the proppant concentration change rate and the fracturing fluid viscosity recovery rate is strictly controlled within ±10%. The increased proppant carrying capacity brought about by viscosity recovery is utilized to counteract the severe erosion of the orifice by high-concentration coarse sand, ensuring that the actual erosion amount does not exceed the allowable range of the preset compensation coefficient δ=0.2.

[0065] Step S3: High displacement induces extreme flow restriction and multi-cluster crack initiation and coordinated construction: The core of this step is to induce extreme flow restriction effect through high displacement to achieve balanced multi-cluster crack initiation and coordinated pumping of liquid sand.

[0066] S31. High-displacement linear increase and activation of the ultimate flow restriction effect: Using a continuous pumping method, the construction displacement is linearly increased from 0 to the design maximum displacement Q within 5 minutes. max =16m 3 / min. By utilizing the nonlinear friction surge effect generated by high flow rate fluid flowing through the restricted perforation orifice, the perforation friction accounts for more than 70% of the net pressure at the bottom of the well, shielding the influence of stress differences between clusters, the uneven distribution of flow rate among clusters in the forced section is reduced to 12%, and all 8 perforation clusters in the induced section are simultaneously fractured, with a simultaneous fracture rate of 100%, far exceeding the design target of 80%.

[0067] S32. High-shear activated viscosity mechanism and dynamic execution of step procedure: Maintaining Q during the sand addition stage. max =16m 3 The rate is constant, utilizing the high shear rate (γ>1000s) at the wellbore and perforation holes. -1 The system activates the viscous slick in real time to maintain a low viscosity of μ1 = 3.2 mPa·s, reducing friction along the flow path. When the liquid enters the low shear zone of the crack, it automatically increases its viscosity according to the preset time-viscosity response law.

[0068] Under this dynamic rheological environment, the above-mentioned three-stage proppant injection procedure was strictly implemented. Relying on the initial orifice diameter of 7mm with erosion compensation, it was ensured that the high-concentration 20 / 40 mesh coarse-grained proppant could pass smoothly through the perforation orifice without bridging or blockage. At the same time, the sand ratio was adjusted in real time by a ground-based high-precision sand mixing vehicle to ensure that the synchronous error between the proppant concentration change rate and the fracturing fluid viscosity recovery rate was controlled within ±8%, achieving three-dimensional synergy of "high-volume fracture creation, variable viscosity proppant carrying, and flow restriction and diversion".

[0069] Step S4: Real-time closed-loop feedback control based on distributed optical fiber sensing: The core of this step is to achieve closed-loop adaptive control of the construction process through real-time monitoring using distributed optical fiber.

[0070] S41. Distributed Fiber Optic Monitoring and Fluid Injection Inversion: DAS / DTS fiber optic cables are laid throughout the horizontal well section, with a sampling frequency set to 2kHz. The acoustic signature energy intensity and temperature drop at each perforation cluster location are acquired in real time. Using a multiphysics inversion algorithm, the acoustic temperature signal is converted into the instantaneous fluid injection rate qi(t) for each cluster. The inversion formula is as follows: In the formula: α, β, γ are field calibration coefficients. In this embodiment, they are calibrated as α=0.02, β=0.85, and γ=0.12.

[0071] Based on the inverted instantaneous inflow rate, the inflow non-uniformity coefficient U(t) within the section is calculated in real time: Where: M is the total number of perforation clusters, and in this embodiment, M=8; This represents the average liquid inflow rate per cluster.

[0072] S42. Adaptive control strategy execution: Set the non-uniformity coefficient threshold U limit =0.4, the system monitors the non-uniformity coefficient of liquid inflow U(t) in real time. When U(t)>0.4, the judgment logic and control operation are triggered immediately.

[0073] In this embodiment, after 55 minutes of construction, U(t) was monitored to be 0.46, exceeding the threshold. Simultaneously, the acoustic energy of the dominant cluster continued to rise, and spectrum analysis showed a significant increase in high-frequency erosion noise above 2kHz, indicating a failure of the flow restriction mechanism caused by orifice erosion. Immediately, a "sand reduction and pressure maintenance" operation was performed: the proppant concentration was reduced from 650 kg / m³ within 30 seconds. 3 Reduced to 400 kg / m 3 (Reduction of 38.5%), and simultaneously, the automatic ball injector was activated to inject high-density temporary plugging balls to seal the expansion holes of the dominant cluster. Three minutes after the control was implemented, U(t) was monitored to drop to 0.28, recovering to within the threshold, and the original sand-addition procedure was continued.

[0074] If the acoustic energy of the dominant cluster is detected to be rising but there is no high-frequency erosion noise, it is determined that the uneven flow is dominated by the difference in ground stress. Immediately execute the "increase discharge and increase resistance" operation, instantly increase the discharge by 5% to 10%, and use the square relationship between friction resistance and flow to forcibly balance the flow of each cluster.

[0075] S43. Pulse-type temporary plugging procedure: If the fluid inflow unevenness coefficient U(t) still does not drop below the threshold after two consecutive executions of the above control, initiate the pulse-type temporary plugging procedure: rapidly inject a high concentration of 100~200 kg / m into the wellbore. 3 The biodegradable fiber slug with a particle size of 1-3 mm has a volume of 1.2-1.5 times that of the wellbore. By utilizing the bridging effect of the fiber at the orifice of the dominant cluster, the local friction is instantly increased, forcing the fluid to turn towards the weaker cluster. After injection, the original design and construction parameters are restored immediately. The turning effect is monitored by distributed acoustic wave sensing (DAS) fiber optic. If it is ineffective, it can be repeated once, but no more than three times.

[0076] In this embodiment, adaptive regulation was triggered only once throughout the entire construction period, and the flow distribution among the clusters remained uniform throughout. Ultimately, the microcrack filling rate reached 92%, and the main crack conductivity reached 18.6 μm. 2 The reservoir stimulation volume was increased by 45% compared to traditional methods, and the daily gas production was increased by 58% compared to adjacent wells, achieving excellent stimulation results.

[0077] A dynamic synergistic fracturing system for fracturing fluid and proppant based on the ultimate flow-limiting effect, used to execute the fracturing method described in Example 1, includes a design module, a sensing module, a decision-making module, and an execution module. Wherein: The design module has a built-in erosion evolution algorithm and rheological matching model. After the target reservoir parameters are input, it automatically outputs perforation parameters with erosion compensation coefficient, fracturing fluid rheological design parameters, and liquid sand co-pumping table, providing a set of pre-design instructions for construction.

[0078] The sensing module includes DAS / DTS fiber optic sensors laid along the horizontal well section and a ground-based high-resolution fiber optic demodulator with a sampling frequency of no less than 1kHz. It is used to collect acoustic signature and temperature monitoring data of each perforation cluster in real time, and interpret the real-time fluid ingress profile of each cluster through the built-in multiphysics inversion algorithm.

[0079] The decision-making module deploys an edge computing unit, pre-sets a logic library for judging uneven liquid inflow and a control strategy tree, runs with millisecond latency, compares the monitoring data uploaded by the sensing module with the preset threshold in real time, automatically identifies the causes of uneven flow, and generates corresponding construction parameter adjustment instructions such as discharge rate, sand ratio, and temporary plugging agent injection.

[0080] The execution module, including a variable frequency fracturing pump unit (response time <1s), a high-precision sand mixing vehicle (sand ratio control accuracy ±0.5%), and an automatic ball thrower, is used to receive adjustment instructions from the decision module, respond in milliseconds, and execute real-time adjustments to construction parameters to achieve closed-loop automatic control of fracturing operations.

[0081] The above description is only a preferred embodiment of the present invention. It should be noted that for those skilled in the art, several improvements and modifications can be made without departing from the principle of the present invention, and these improvements and modifications should also be considered within the scope of protection of the present invention.

Claims

1. A fracturing method based on the ultimate flow-limiting effect of fracturing fluid and proppant, characterized in that, Includes the following steps: S1: Dynamic perforation compensation design based on erosion evolution prediction: Obtain the rock mechanical parameters, geostress field distribution characteristics, and maximum design discharge rate of the target reservoir; establish a perforation erosion dynamics model to simulate the erosion enlargement of the perforation throughout the sand addition cycle; predict the equivalent aperture at the end of construction; back-calculate the initial design aperture based on the equivalent aperture and the preset erosion compensation coefficient δ; determine the number of perforations per cluster based on the initial design aperture to ensure that the initial perforation frictional resistance satisfies ΔP under the maximum design discharge rate. perf_init ≥1.2×(σ H_max -σ h_min ), where σ H_max and σ h_min These are the maximum and minimum horizontal principal stresses within the segment, respectively. S2: Constructing a synergistic system of shear-thickening variable viscosity fracturing fluid and stepped particle size proppant: Prepare shear-thickening variable viscosity slickwater fracturing fluid, establish its dynamic evolution equation with shear rate and time, and substitute the dynamic evolution equation into the perforation erosion dynamics model of step S1 to calculate the real-time erosion rate; based on the initial design aperture obtained in step S1, design a three-stage stepped proppant injection program that matches the time-varying rheological properties of the fracturing fluid; S3: High-displacement-rate-limit-flow-limited multi-cluster fracturing and coordinated construction: Continuous pumping is used to linearly increase the construction displacement to the maximum design displacement; the nonlinear friction surge effect generated by the high-displacement fluid flowing through the perforation orifice reduces the uneven distribution of flow rate among clusters within the fracturing section and increases the number of perforation clusters that initiate fracturing simultaneously; while maintaining the maximum design displacement, the three-stage proppant injection procedure of step S2 is executed to achieve coordinated control of high-displacement fracturing, variable viscosity proppant carrying, and flow-limiting diversion; S4: Real-time closed-loop feedback control based on distributed optical fiber sensing: Through distributed acoustic wave sensing optical fiber and distributed temperature sensing optical fiber, the acoustic energy intensity and temperature drop of each perforation cluster are monitored in real time, the instantaneous liquid inflow of each cluster is inverted, and the liquid inflow unevenness coefficient within the segment is calculated in real time; a threshold for the unevenness coefficient is set, and when the liquid inflow unevenness coefficient > the threshold for the unevenness coefficient, the corresponding adaptive control strategy is triggered to correct the deviation of the construction parameter execution.

2. The method according to claim 1, characterized in that, In step S1, the method for constructing the dynamic model of perforation hole erosion includes: (1) The erosion rate of a single particle was calculated using the Oka wear model. V p D is the particle velocity. p V is the particle size, α is the particle impact angle, K, n, and m are experimental constants related to the perforation casing material, and V is the particle diameter. ref D ref For the reference flow velocity and reference particle size, f(α) is the impact angle function; (2) Integrate the time over the entire sand-addition period T to calculate the total mass loss of a single hole. C s (t) represents the time-varying proppant concentration, and Q(t) represents the instantaneous construction discharge rate; (3) Convert the total mass loss into the aperture increment ΔD, and determine the equivalent aperture D at the end of construction based on the aperture increment ΔD. end The initial aperture D target The target flow-limiting orifice diameter at the end of construction.

3. The method according to claim 1, characterized in that, In step S2, the dynamic evolution equation of the shear-thickened, viscous slickwater fracturing fluid satisfies: High shear zone in the wellbore, i.e., γ > 500s -1 At that time, the fracturing fluid should maintain a low viscosity μ1 < 5 mPa·s; Low-shear region of the crack, i.e., γ < 50s -1 At that time, the viscosity of the fracturing fluid increases exponentially with time t, satisfying μ2(t) = μ1 + A·(1-e -kt ), where A is the maximum viscosity increase and k is the response rate constant.

4. The method according to claim 3, characterized in that, The specific components of the shear-thickening viscous slickwater fracturing fluid are as follows: the base fluid is clean water or backflow treated water; the thickener is 0.05%~0.15% by mass of modified guar gum, or 0.03%~0.08% by mass of nanocellulose suspension; and the flow aid is 0.1%~0.3% by mass of fluorocarbon surfactant.

5. The method according to claim 1, characterized in that, In step S2, the specific procedure for the three-stage propellant injection process (fine-medium-coarse) is as follows: Phase 1: Pump in 40 / 70 mesh or 100 mesh fine-particle proppant, with the concentration controlled at 50~150 kg / m³. 3 Used for filling microcracks and buffering erosion; Second stage: Pumping in 30 / 50 mesh medium-sized proppant at a concentration of 150 kg / m³ 3 Linear increase to 300~600 kg / m 3 The proppant particle size is less than 0.6×D start Used to construct suspended plugs; Third stage: Pump in 20 / 40 mesh coarse-grained proppant, with the concentration controlled at 400~800 kg / m³. 3 It is used to construct a high-conductivity channel in the main fracture.

6. The method according to claim 1, characterized in that, In step S3, the maximum construction discharge capacity Q is designed. max The following dual constraints must be met: Constraint 1, Equipment Safety Constraint: Total wellhead construction pressure ≤ 0.9 × P rating , where P rating The rated working pressure of the wellhead equipment and casing; Constraint 2, Effective Constraint for Current Limiting: In Q max Below, the initial perforation friction ΔP perf_init ≥1.5×Δσ cluster , where Δσ cluster This represents the maximum inter-cluster stress difference within the segment; If both conditions cannot be met simultaneously, prioritize adjusting the perforation parameters N and D. start Once constraint two is satisfied, constraint one is then checked.

7. The method according to claim 1, characterized in that, In step S4, the adaptive control strategy is specifically as follows: If the acoustic energy of the dominant cluster continues to rise and is accompanied by high-frequency erosion noise above 2kHz, it is determined that the erosion has caused the current limiting failure, and the sand reduction and pressure maintenance operation is performed: within 30 seconds, the proppant concentration is reduced by 30%~50%, and at the same time, high-density temporary plugging balls are injected to seal the pores of the dominant cluster. If the acoustic energy of the dominant cluster increases but there is no high-frequency erosion noise, it is determined that the uneven flow is dominated by the difference in ground stress. The operation of increasing the discharge rate and increasing the resistance is carried out: the construction discharge rate is increased by 5% to 10% instantaneously, and the flow rate of each cluster is balanced by the square relationship between the perforation friction and the flow rate.

8. The method according to claim 1, characterized in that, In step S4, the adaptive control strategy also includes a pulse-type temporary blocking steering sub-step: (1) After two consecutive adjustments, the non-uniformity coefficient U(t) of the influent still did not decrease to the non-uniformity coefficient threshold U. limit The following steps will trigger a pulse-based temporary blocking procedure; (2) Rapidly inject a concentration of 100~200 kg / m into the wellbore. 3 Biodegradable fiber slugs with a particle size of 1-3 mm, the volume of which is 1.2-1.5 times the wellbore volume; (3) The bridging effect of the fiber slug at the orifice of the dominant cluster increases the local friction, forcing the subsequent fluid to turn towards the weak cluster; (4) After the fiber slug injection is completed, restore the original design and construction parameters, and monitor the turning effect through distributed acoustic wave sensing fiber. If it is ineffective, repeat once.

9. The method according to any one of claims 1 to 8, characterized in that, This method is applicable to deep shale gas or tight oil reservoirs with a burial depth of 4500m~8000m, a formation pressure coefficient of 1.5~2.2, and a closure stress of 60MPa~120MPa.

10. A system for performing the method according to any one of claims 1 to 9, characterized in that, include: The design module has a built-in erosion evolution algorithm and rheological matching model, which is used to output perforation parameters with erosion compensation coefficient and liquid sand co-pumping table. The sensing module includes distributed fiber optic sensors laid along the horizontal well section and a ground data acquisition unit, which are used to collect monitoring data in real time and interpret the fluid ingress profile of each perforation cluster. The decision-making module has a pre-set logic library for judging uneven liquid infusion and a control strategy tree, which is used to automatically generate construction parameter adjustment instructions based on the monitoring data of the sensing module. The execution module, including the variable frequency fracturing pump set, high-precision sand mixing vehicle and automatic ball thrower, is used to receive adjustment instructions from the decision module and perform real-time adjustments to the construction parameters.

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