70 results about "Fracture conductivity" patented technology

The invention discloses a global fracture conductivity ultra-long-term prediction method and system, belongs to the technical field of crossing of oil and gas reservoir engineering and artificial intelligence, and is used for solving the technical problem that the calculation cost is high when an existing physical model is used for predicting fracture ultra-long-term conductivity. The method comprises the following steps: generating a global fracture conductivity evolution data set covering multiple working conditions through a numerical simulation system; constructing a multi-channel input tensor containing dynamic fracture conductivity and static proppant concentration distribution; using the data set to train a plurality of Fourier neural operator models for different prediction time scales; and based on a hierarchical time sequence aggregation strategy, iteratively calling trained models of different time scales, and realizing rapid prediction of fracture conductivity in a few years to tens of years in the future. According to the method, on the premise of ensuring the prediction precision, the calculation time consumption of ultra-long-term prediction can be remarkably reduced, and decision support is provided for crack design and production strategy optimization.

The application discloses a kind of acquisition methods, devices, media and electronic equipment of complex fracture conductivity, and its method includes: (A) extracting the specific form of complex fracture formed in stratum by hydraulic fracturing, calculating the average filling concentration of proppant in complex fracture;(B) complex fracture is divided into multiple simple straight fracture units, and the closure stress suffered by each fracture unit in stratum is calculated;(C) carry out simple straight fracture conductivity experiment, obtain the change curve of fracture conductivity with closure stress, and the relationship between fracture conductivity and closure stress is fitted;(D) the fracture conductivity corresponding to each fracture unit is calculated;(E) the fracture conductivity of each fracture unit is used to calculate the conductivity of the whole complex fracture.The application principle is reliable, simple to operate, and has strong practicability, can more accurately obtain the conductivity of complex fracture formed by hydraulic fracturing, and then provide effective guidance for hydraulic fracturing construction effect evaluation.

The present application relates to oil and gas exploration technology field, disclose a kind of fracture conductivity test method and device of formation condition simulation, the present application is based on similarity criterion selects and actual reservoir and similar material of surrounding rock as model raw material, then according to design size manufacturing surrounding rock model and reservoir model with fracturing fracture;Reservoir model and surrounding rock model are assembled to form reservoir surrounding rock model, and fixedly placed on triaxial loading unit;Reservoir surrounding rock model, triaxial loading unit and fluid injection and monitoring unit and displacement detection unit are connected to form fracture conductivity test experimental device, finally based on the experimental device carries out the fracturing fracture conductivity test experiment of reservoir surrounding rock model, and calculates the fracture conductivity coefficient of model.The present application can more accurately simulate the deformation law of fracture in actual reservoir, provide more accurate parameters for oil and gas reservoir numerical simulation model, so as to more accurately evaluate and calculate gas well productivity.

The application provides a method and system for calculating the conductivity of a sand-acid fracturing reservoir simulation system, which comprises the following steps: constructing a simulation parameter combination set around sand-acid fracturing operation parameters for reservoir types with sand-acid fracturing requirements; analyzing fracture acid erosion data of different reservoirs by using a preset fracture acid erosion calculation model, and analyzing the embedding depth and deformation data of the proppant in combination with the injection rate parameters and the proppant data; further analyzing the sand concentration of sand-acid fracturing, and setting a rough body simulation distribution coefficient in combination with the injection rate, so as to form a reservoir fracture model that presents a real fracturing state; analyzing the permeability state of the reservoir fracture model after fracturing based on the rough body simulation distribution coefficient and the reservoir closure pressure; and further calculating the corresponding conductivity in combination with the fracture width calculated according to the fracture acid erosion data, the embedding depth and deformation data of the proppant. The method solves the problem that the sand-acid fracturing conductivity cannot be quantitatively analyzed, and provides support for field acid fracturing design and productivity prediction.

The invention relates to a nano tackifying fluid and supercritical CO2 fluid synergistic fracturing method. In the target stratum development area, nano tackifying fluid and supercritical CO2 fluid are adopted for collaborative fracturing, sand-carrying fluid and displacing fluid are combined to form a fracture network, and the corresponding relation between the construction parameter combination and the fracture flow conductivity and the corresponding relation between the construction parameter combination and the fracturing construction fluid amount are established; based on the corresponding relation, a multi-target optimization model with the fracture conductivity maximization and the fracturing construction liquid amount minimization as the target is constructed, and through population initialization, non-dominated sorting, crowding distance calculation, crossover variation selection and iterative updating, a construction parameter optimization result is output. The shale reservoir fracture flow conductivity and the fracture network complexity can be improved, the construction liquid amount is reduced, and the fracturing transformation effect and economical efficiency are improved.

The application provides a fracturing reconstruction method and application for ultra-deep high-stress reservoirs, and mainly aims to solve the problems of high fracture pressure, small reconstruction volume and low fracture conductivity of high-stress reservoirs. Specifically, the application analyzes the fracturing problems of the current ultra-deep high-stress reservoirs, points out the limitations of the current technical measures, and proposes a new fracturing reconstruction technology for high-stress reservoirs. The technology takes the pre-composite pressure reduction process, forced fracture expansion process and fracture effective support process as the core, solves the problems of difficult fracturing, difficult fracture expansion and difficult support of high-stress reservoirs, and has good application effect.

This invention discloses an optimization method for flowback nozzles in deep coal and rock gas formations, considering the influence of multiple factors, belonging to the field of coal and rock gas extraction technology. Addressing the challenge of flowback fluid velocity control in deep coal and rock gas development, this method establishes models for matrix and fracture seepage and two-phase flow within the wellbore. It comprehensively considers the migration of pulverized coal and proppant, as well as the influence of coal seam cleavage fractures, to optimize wellhead nozzle size, reduce the probability of pulverized coal clogging fractures, and improve fracture conductivity. Compared to traditional methods, this invention has significant advantages in improving fracturing efficiency and high-efficiency coal and rock gas extraction, providing an innovative solution for the scientific research and engineering applications of deep coal and rock gas.

The invention provides an offshore bottom water thin mutual reservoir fracturing parameter design method, and relates to the technical field of oil and gas exploitation, the method comprises the following steps: S1, determining vertical distribution of a reservoir section mud layer, a sandstone layer and a water layer according to logging data, and establishing a target well section crustal stress and rock mechanics profile; s2, acquiring the fracture toughness of rocks with different shale contents under different stresses to obtain a corrected fracture toughness profile; s3, according to the fracture half length, the fracturing displacement, the critical mudstone layer penetrating thickness corresponding to the fracturing fluid viscosity and the penetrating layer fracture height of the reservoir are initially calculated, and parameters needed for avoiding a water layer and fully transforming a thin interbed are obtained; s4, according to the fracture flow conductivity, the sand amount and the sand-carrying fluid amount are calculated initially; s5, the liquid efficiency is determined according to block fracturing historical data, the prepad fluid proportion range is initially calculated, and the prepad fluid amount is calculated; and S6, optimizing parameters through numerical simulation, and determining final fracturing parameters and a pump injection program. According to the method, the requirements of geological and offshore construction can be met, and the optimal fracturing scheme and the optimal pumping program can be rapidly determined.

The application discloses a method, device and equipment for determining reservoir fracture conductivity, wherein the method comprises the following steps: acquiring fracture data of a target reservoir; determining a fracture width distribution result of a support fracture in the target reservoir based on the fracture data, wherein the fracture width distribution result comprises a continuous distribution result of a fracture width of the support fracture along a fracture length and a fracture height direction of the support fracture; and determining a conductivity distribution of the target reservoir based on the fracture width distribution result and a pre-determined mapping relationship between the fracture width and the conductivity, wherein the conductivity distribution represents a distribution of the conductivity of the support fracture of the target reservoir along the fracture length and the fracture height direction of the support fracture. The application can obtain a more accurate and reliable conductivity distribution, and can predict the conductivity of the support fracture in multiple dimensions, so that the prediction of the conductivity distribution is more comprehensive.

The application provides a method and device for determining long-term conductivity of acid-etched fractures in carbonate rocks. The method comprises: obtaining rock mineral composition, porosity, permeability, formation Young's modulus, formation closure stress, formation Poisson's ratio, acid concentration and temperature; determining the damage factor of acid-etched fractures based on rock mineral composition, porosity, permeability, Young's modulus, acid concentration and temperature; determining the change in acid-etched fracture width after acid etching of the fracture surface based on formation Young's modulus, closure stress, Poisson's ratio and acid-rock reaction rate; determining the creep variable of acid-etched fracture conductivity based on the initial fracture width, Young's modulus, Poisson's ratio and damage factor; and finally, determining the long-term conductivity by the fracture width after acid etching and the formation creep variable. The method comprehensively considers lithology, formation physical properties, rock mechanics parameters, acid etching damage and creep effect, and can quickly and accurately determine the conductivity of acid-etched fractures.

The application provides a heterogeneous reservoir acid fracturing parameter design method and system, the method constructs an acidification reconstruction geometric model for a reservoir to be reconstructed, introduces required acidification section length and section thickness data to calculate acid liquid flow rates in fractures under different construction discharge capacities in combination with fracture attribute data, further considers acid etching reaction rates and mass transfer coefficients to calculate acid concentrations on inner walls of fractures reacted with a reservoir matrix, determines etching widths of natural fracture walls according to attribute parameters of the reservoir matrix, further calculates reservoir etching volumes corresponding to different construction acid amounts and acid etching fracture widths and lengths, finally decides corresponding acid etching fracture conductivity capacities according to a correction principle of an N-K model, and selects optimal acid injection parameters according to preset optimization conditions. By using the scheme, the problems of small calculation scales and complicated operations in the prior art are effectively overcome, analytical solutions are flexibly used in the calculation process, and an acid injection scheme with optimal acid etching effects and conductivity capacities is accurately and efficiently selected.

The application discloses a shale gas well flowback system optimization method based on distributed optical fiber data mining, and combines advanced distributed optical fiber (DTA / DAS) monitoring technology to "perceive" downhole temperature and "listen" to downhole sound; optical fiber monitoring results can quantitatively evaluate the fracturing reconstruction effect of a shale gas well and judge the gas production and liquid production profile distribution effect of the whole well section of the gas well. Through optical fiber data mining in the gas well flowback stage, the fracturing cluster efficiency and the artificial fracture conductivity are comprehensively considered to optimize the maximum flowback choke of the gas well, so that the gas well flowback system optimization work is realized.

The application provides a method for designing sanding concentration of a compact oil and gas reservoir fracturing fracture considering pressure sensitivity damage, comprising the following steps: step 1, obtaining the optimal conductivity of the compact oil and gas reservoir fracturing fracture by using a reservoir numerical simulation method; step 2, determining the conductivity of the compact oil and gas reservoir support fracture under different conditions, and establishing a relationship equation of the support fracture conductivity and sanding concentration and effective closure pressure; step 3, according to the maximum effective closure pressure formed in the fracturing fracture during the pressure reduction production process of the compact oil and gas reservoir and the optimal fracture conductivity obtained by numerical simulation optimization, and referring to the support fracture conductivity relationship equation, the sanding concentration of the fracturing fracture considering pressure sensitivity damage is designed. The method for designing the sanding concentration of the compact oil and gas reservoir fracturing fracture considering pressure sensitivity damage can provide a basis for designing a reasonable sanding concentration for the compact oil and gas reservoir hydraulic fracturing process, avoid the production capacity loss caused by the fracture pressure sensitivity during the pressure reduction production process, and further obtain a longer stable production period.

The invention belongs to the technical field of oil and gas field development and oil and gas reservoir transformation, and particularly relates to a sand fracturing method for achieving a compact limestone reservoir dominant flow guide channel. The method mainly comprises the following steps: (1) a multi-viscosity prepad fluid fracture forming stage; (2) a multi-viscosity multi-particle-size sand carrying stage; and (3) a low-viscosity displacing fluid displacing stage. The high-viscosity prepad fluid is used for making a main crack, then the mode that the medium-viscosity prepad fluid and the low-viscosity prepad fluid are alternately injected is adopted for continuously expanding the main crack, and branch cracks and communication micro cracks are made. According to the viscosity difference of different sand-carrying fluids, the lower-viscosity sand-carrying fluid enters the higher-viscosity sand-carrying fluid to form viscous fingering, so that the large-particle-size proppant is located in the middle of the small-particle-size proppant, a dominant flow guide channel is formed, and the fracture flow conductivity is effectively improved.

The invention discloses an acid-etched fracture conductivity testing device and a testing method thereof, the acid-etched fracture conductivity testing device comprises an acid liquid storage tank and a diversion chamber, and an acid storage chamber and a driving chamber are arranged in the acid liquid storage tank; the acid storage chamber is connected with a liquid supplementing container through a pipeline, a gas cavity and a liquid cavity are formed in the liquid supplementing container, the gas cavity is connected with a high-pressure nitrogen gas source, acid liquid is arranged in the liquid cavity, and the liquid cavity is connected with the acid storage chamber; the bottom end of the driving chamber is connected with a constant-flux pump through a pipeline, and the input end of the constant-flux pump is connected with a driving liquid pool; ports at two ends of the flow guide chamber are respectively connected with an output port of a preheater and a discharge pipeline; an input port of the preheater is connected with an acid storage chamber, and an input end pipeline of the preheater is connected with a gas cleaning pipeline; the gas cleaning pipeline comprises a gas cylinder, a buffer tank and a one-way valve; a pressure regulating valve is arranged at the output end of the gas cylinder, a one-way valve and a buffer tank are sequentially arranged at the output end of the gas cylinder in series, and the output end of the buffer tank is connected with the input end of the preheater.

The application discloses a kind of gas-water co-production tight gas reservoir fracturing horizontal well pseudo-steady state productivity calculation method, the application considers gas-water two-phase flow simultaneously by superposition principle, establishes the productivity equation of pseudo-steady state stage of multi-section fracturing horizontal well, analyzes the influence of factors such as fracture number, fracture half-length, production gas-water ratio, starting pressure gradient, slip effect, effective permeability and fracture conductivity on initial open flow capacity of gas well.The specific productivity equation construction steps are as follows: S1, establish single fracture single-phase gas productivity equation;S2, ignore the difference between fracturing cracks to establish single-phase gas well total productivity equation;S3, two-phase pseudo-pressure is introduced into gas well productivity equation to obtain gas-water two-phase fracturing horizontal well productivity equation;S4, slip factor, starting pressure gradient nonlinear factor two factors are introduced into two-phase fracturing horizontal well productivity equation.

The present application relates to the technical field of petroleum engineering, and particularly relates to an acid fracturing parameter optimization method based on full-fracture acid etching fracture conductivity simulation, comprising the following steps: S1: obtaining basic parameters, and establishing a single-well geological feature model of a target area; S2: combining the construction parameters with the single-well geological feature model, and performing acid fracturing simulation calculation to obtain fracture dynamic environment parameters; S3: calibrating a reference position in the acid fracturing fracture, and obtaining dynamic changes of the environment parameters at different positions; S4: using a multi-field coupling acid etching model to carry out local acid etching simulation at different positions; S5: based on the simulation results in S4, using an acid etching fracture conductivity calculation model to obtain the full-domain acid etching fracture conductivity distribution characteristics; and S6: based on the acid etching fracture conductivity in S5, judging whether the acid etching fracture parameter requirements are met according to the target reservoir requirements. The present application can carry out acid etching simulation calculation at different positions in the fracture domain, so as to obtain the full-domain acid etching fracture conductivity distribution characteristics.

The invention relates to a fracture conductivity measuring system and a fracture conductivity measuring method, a shale self-supporting fracture morphology colloid block under each confining pressure is obtained by splitting a plunger core and injecting glue, the colloid block is uniformly scanned by using a three-dimensional digital scanner after the measurement is finished, the width of a self-supporting fracture is obtained through numerical calculation, and the thickness of the self-supporting fracture is measured. The fracture permeability is measured through the displacement fluid, finally, the fracture conductivity is calculated according to the fracture width and the permeability, the result is accurate and reliable, and therefore whether the stratum is suitable for fracturing exploitation or not is judged according to the fracture conductivity.

The application belongs to the technical field of oil fracturing reconstruction, and particularly relates to a fracturing fluid preflush for strengthening in-situ self-grown proppant strength and morphology and application, which is used to solve the problems of insufficient strength and irregular morphology of generated in-situ proppant crystals. The fracturing fluid preflush is suitable for calcium-rich reservoirs, and is composed of clean water, phosphate, and pH adjuster and Ca 2+ The content of the phosphate is 5-7 parts by weight, the volume molar concentration of the pH adjuster is 1-2 M, the volume molar concentration of the chelating agent is 0.001-1 M, and the content of the doping element is 1 part by weight, relative to 100 parts by weight of clean water. 2+ The application strengthens the in-situ self-grown proppant strength and optimizes the crystal morphology, improves the supporting effect of the in-situ self-grown proppant in the formation micro-cracks, improves the fracture conductivity, and improves the oil and gas fracturing stimulation effect.

The invention discloses a method and a device for measuring non-uniform distribution flow conductivity of an acid-etched fracture, and relates to the technical field of oil-gas exploration. The method comprises the following steps: drilling a plunger rock core from an underground rock core, performing half-and-half seam cutting, dividing the rock core into a rock core A and a rock core B, and drying the rock core A and the rock core B; s3, the rock core seam length L and the rock core cross section diameter D are measured, and the opposite seam faces of the rock core A and the rock core B are scanned, S3, a cushion block is arranged between the rock core A and the rock core B, and the rock core A and the rock core B are combined into a whole; the combined rock cores are loaded into a clamping device, the clamping device is heated to the formation temperature, and acid liquid displacement is carried out; removing the cushion block from the rock core subjected to acid etching and cooling, drying and scanning; performing line cutting on the rock core subjected to acid etching, re-measuring the length and the diameter of a seam, re-combining the rock core without sticking to a cushion block, loading the rock core into a holder, and testing the flow conductivity of the rock core under different confining pressures; according to the invention, the rock core can be cut off and segmented as required after acid etching to measure the flow conductivity at different extension depths, the operation is convenient, and the data is more real and reliable.

The present application provides a shale gas infill adjustment well productivity prediction model, method, device and medium. The establishment method comprises the steps of establishing a physical model, establishing a seepage model, deducing a point source solution and establishing a horizontal well group productivity prediction model, wherein in the step of establishing the horizontal well group productivity prediction model, the influence of long-term fracture conductivity is considered. The prediction method is realized based on the established model. The device comprises a processor and a memory storing instructions for executing the above method. The storage medium stores program instructions. The method proposed in the present application can calculate the productivity of shale gas infill adjustment wells considering inter-well pressure interference and long-term conductivity, and the calculation result is more accurate than existing methods. The method improves the accuracy of shale gas infill adjustment well productivity prediction and has a wide application prospect.

The invention discloses an intelligent regulation and control system and method for coal bed gas exploitation and CO2 storage through variable-component flue gas drive, and belongs to the technical field of coal bed gas exploitation and CO2 storage. The system comprises a variable component injection module, a multi-parameter distributed sensing network, an extraction and utilization module, a digital twinborn model, an AI intelligent regulation and control engine and a safety interlocking and emergency response module. The component-variable injection module is used for realizing adjustment of CO2 / N2 proportion, pressure, flow, temperature and humidity; the sensing network realizes high-frequency panoramic monitoring of the whole injection-extraction process through a plurality of sensors; the digital twinborn model is coupled with permeability evolution, adsorption and fracture diversion models to realize real-time inversion of key parameters; the AI engine outputs an optimal injection strategy based on LSTM prediction and a PPO reinforcement learning algorithm; and the safety interlocking and emergency response module triggers emergency response at a millisecond level during overrun. According to the system, collaborative optimization of the coalbed methane recovery rate, the CO2 storage rate and the operation energy consumption is achieved, and normal form transformation from blind injection to intelligent regulation and control is completed.

The present application discloses a method and apparatus for determining the settling rate of proppants in hydraulic fracturing. The method comprises: acquiring the target mesh size of the proppant; obtaining the bulk density of the proppant, and the density and viscosity of the carrier fluid under reservoir conditions; retrieving the proppant concentration (sand ratio) during injection; and applying a pre-established predictive model specific to the selected mesh size. The model inputs include proppant bulk density, carrier fluid density, reservoir-temperature viscosity, and sand ratio, and the output is the estimated settling velocity. This method effectively addresses the technical challenge of predicting proppant transport behavior under downhole conditions, thereby enhancing proppant placement accuracy and improving fracture conductivity in low-permeability formations.

This invention provides a high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity, comprising the following steps: Step 1, determining the water breakthrough type of each water-bearing and water-flooded well in the well group; Step 2, simplifying the dominant fracture channel into a rectangular equivalent model and calculating the plugging agent dosage; Step 3, injecting water into the well group for testing, clearing and pre-treating the fracture channels to be plugged, and recording the water intake indicator curve and pressure drop curve of the corresponding injection well in the well group to be profiled; Step 4, deep composite plugging agent injection operation; Step 5, monitoring the injection pressure rise during the plugging agent injection process and testing after completing the designed injection volume of plugging agent; Step 6, completing the test and resuming water injection production. The high-strength, long-lasting, deep composite plugging method for reducing fracture conductivity provided by this invention can solve the problems in existing technologies that make it difficult to achieve high-strength, long-lasting plugging of deep formation fractures, affecting the plugging effect of injection wells and the release of water-flooded production capacity.

The present application relates to the technical field of fracturing aids, and is a temperature-controlled variable-density high-pressure-resistant proppant and a preparation method thereof.The raw materials of the temperature-controlled variable-density high-pressure-resistant proppant include a proppant, a surface modifier, a temperature-controlled polymer, an initiator and an organic solvent.The temperature-controlled variable-density high-pressure-resistant proppant is prepared by first modifying the surface of the proppant to obtain a modified proppant, then grafting and polymerizing the modified proppant with the temperature-controlled polymer, and finally post-treating the final product.The temperature-controlled variable-density high-pressure-resistant proppant can reduce the density under the response of the bottom-hole temperature, so that it is more easily transported to the deep part of a complex fracture network and uniformly laid, has a low breakage rate, can well support the fractures and promote the flow of oil and gas in the fractures.Meanwhile, the temperature-controlled variable-density high-pressure-resistant proppant still has high pressure resistance after swelling, so as to avoid being crushed to reduce the fracture width and block the seepage channel and reduce the fracture conductivity.

The invention discloses a method for determining the effective acid etching fracture length of a carbonate reservoir, and relates to the technical field of petroleum engineering. The method includes the following steps that a hydraulic fracture model is obtained through an acid fracturing simulator, the acid fracturing simulator is used again for simulating acid liquid pump injection, and the time, temperature and acid liquid concentration of acid liquid flowing through different fracture lengths in the acid injection process are obtained; carrying out acid etching experiments on the cracks at different crack length positions to obtain acid etching cracks; carrying out an acid-etched fracture conductivity test experiment to obtain the acid-etched fracture conductivity under the effective closed stress, drawing an acid-etched fracture conductivity curve at different fracture positions, and setting a conductivity threshold value so as to determine the effective length of the acid-etched fracture; according to the method, the influence of the actual reaction time of the acid liquor and the crack on the flow conductivity and the change of the flow conductivity of the acid-etched crack in the crack length direction are considered, and the effective distance of the acid-etched crack is determined through the lowest threshold value of the flow conductivity, so that the prediction result is more accurate, real and reliable.

This invention provides a method for diagnosing fracturing fracture parameters by combining adjacent well fiber optic strain and construction pressure. The method includes: deploying distributed fiber optic sensors in the adjacent wellbore to monitor strain signals; deploying pressure sensors in the fracturing well to monitor pressure changes; comparing and processing fiber optic strain data and pressure data on the same time axis to identify the correlation between pressure fluctuations and fiber optic strain, and identifying the strain signal at the fracture front; establishing a strain-fracture geometry parameter inversion model by combining fiber optic strain and pressure fluctuations to obtain fracture geometry parameters at different times; verifying the accuracy of the strain-fracture geometry parameter inversion model; substituting the fracture parameters obtained from the strain-fracture geometry parameter inversion model into the Barree conductivity model to obtain the fracture conductivity; and obtaining the three-dimensional geometric morphology and dynamic change process of the fracture based on the obtained fracture geometry parameters and fracture conductivity. This invention can obtain more accurate fracture parameters.

The invention provides a method for constructing a fracture conductivity model considering hydration and Brinkman flow. The method mainly comprises the following steps: 1) establishing a relational expression between fracture conductivity and fracture width; (2) carrying out an experiment of fracture conductivity test to test the conductivity loss condition of the rock core which is hydrated by introducing the KCl solution at different stress loading times; 3) establishing the relational expression between the hydration time of the deep coal rock and the fracture conductivity. The method is reasonable in conception, can accurately predict the change of the fracture conductivity, and can accurately capture the complex coupling relation between the hydration effect and the fracture conductivity as well as between the hydration effect and the effective stress, so that a scientific decision basis is provided for actual engineering.

The application discloses a kind of based on dynamic monitoring determination shale gas well optimum choke, equipment and medium, wherein method includes: using inclination data, establish well trajectory model;Based on the size of inclination angle in drilling process, in combination with the build-up of inclination, inclination in horizontal section drilling process, establish a variety of well trajectory change model;Using distributed optical fiber monitoring means, record the gas production and water production of each perforation cluster in horizontal section;Calculate the gas production ratio and water production ratio of each cluster;According to the cluster efficiency of each cluster gas production, water production condition determines;Combining a variety of well trajectory change model, get cluster efficiency change condition when different choke size;Calculate the artificial fracture conductivity in the process of different choke up-regulation;Establish the relationship curve between choke size and artificial fracture conductivity change, the relationship curve between choke size and cluster efficiency change, the intersection of two curves is the optimum choke size considering artificial fracture conductivity and cluster efficiency.The application can realize production optimization.

This invention discloses a layered collaborative characterization method for hydraulic fracturing fractures based on multi-source monitoring data assimilation, comprising the following steps: acquiring geomechanical parameters, fracturing operation parameters, and multi-source monitoring data of the target reservoir; dividing the hydraulic fracturing fracture characterization objects into damaged fractures and effective conductivity fractures, and performing feature extraction, spatial mapping, and normalization processing on the multi-source monitoring data to generate monitoring indicators for spatial units; calculating the dynamic fusion weight of each monitoring data based on physical correlation factors, construction stage factors, data quality factors, and residual consistency factors; fusing the monitoring indicators of each spatial unit to calculate the characterization scores of damaged fractures and effective conductivity fractures; updating the fracture propagation state using a data assimilation method based on a fracture propagation prediction model and multi-source monitoring data; generating characterization results for damaged fractures and effective conductivity fractures respectively, and determining the fracture conductivity effectiveness evaluation result based on the difference between the two. This invention can distinguish between activated damaged fractures and effective conductivity fractures, reducing the risk of misclassifying damaged fractures as effective conductivity fractures, and can provide a basis for fracturing parameter optimization and fracture network control.