101 results about "Fluid saturation" patented technology

The invention discloses an orthogonal fractured reservoir frequency variation AVO inversion and parameter prediction method, and relates to the technical field of exploration geophysics, and the method comprises the steps: deducing and reconstructing a fluid saturation horizontal-vertical orthogonal fractured medium rock physical model based on a multi-group fracture-pore medium Chapman model, realizing fluid saturation rock physical modeling containing two groups of orthogonal fracture media; based on an anisotropic reflectivity algorithm and a fluid saturation horizontal-vertical orthogonal fractured medium rock physical model, realizing frequency variation AVO forward modeling of the fractured reservoir, and calculating a frequency variation AVO reflection coefficient and a synthetic seismic record of the fractured reservoir under the interface reflection model; a frequency-varying AVO inversion theory based on a Bayesian framework is constructed by taking a forward modeling process of the frequency-varying AVO as a drive, and the frequency-varying AVO inversion based on the Bayesian inversion framework is realized and reservoir parameter prediction is carried out by utilizing pre-stack seismic AVO data and introducing a simulated annealing-particle swarm algorithm in an inversion process. The method provides a new method and a new means for fine description and prediction of the fractured reservoir.

The invention relates to the technical field of geological reservoirs, in particular to a reservoir microcosmic connectivity characterization method based on pore throat boundary intelligent identification, which comprises the following steps of: performing threshold segmentation processing on a rock casting body slice by using image analysis software, and depicting partition images of pore throats and skeleton particles; based on the partition image, combining image analysis software to measure and extract the diameter, perimeter and area of the pore throat, and calculating quantitative parameters of the pore throat structure; constructing a one-dimensional Gaussian distribution model of the nuclear magnetic logging of the reservoir; based on a one-dimensional Gaussian distribution model, establishing a Gaussian collaborative factor for pore structure evaluation; based on the quantitative parameters of the pore throat structure and the established Gaussian collaborative factors, establishing a multi-factor evaluation mathematical method to establish a multi-element evaluation model of the pore structure; and performing multivariate nonlinear fitting on the porous structure multivariate evaluation model, the nuclear magnetic movable fluid saturation and the reservoir pressure measurement fluidity, and constructing a quantitative characterization model for characterizing the reservoir microscopic connectivity. According to the method, the microscopic connectivity of the reservoir can be accurately, rapidly and quantitatively evaluated.

The embodiment of the invention provides an unconventional oil reservoir oil extraction contribution degree determination method and device, equipment and a medium. The method comprises the steps that the relation between the saturation degree of wet-phase fluid and capillary pressure in an oil reservoir is determined according to a plurality of reference capillary pressure curves; performing simulation analysis on the crack propagation direction and the seepage pressure in the oil reservoir volume fracturing process, and determining a three-dimensional propagation rule of the crack and artificial crack parameters; performing coupling processing on the three-dimensional fracture model and the matrix attribute model to obtain an oil reservoir geological engineering integrated model; establishing a numerical simulation model according to the relationship between the wet-phase fluid saturation and the capillary pressure and the reservoir geological engineering integrated model; performing numerical simulation on the oil reservoir development process through the numerical simulation model to obtain data simulation results of the oil reservoir in different development stages; the oil production contribution degrees of displacement and imbibition in different development stages of the oil reservoir are determined according to a data simulation result, and a theoretical basis and technical support are provided for oil reservoir exploitation.

A controlled rate of propagation of the fluid saturation front or thermal front is desired in may oil and gas and geothermal operations. Natural fractures and fractures created during hydraulic stimulation may have heterogeneous hydraulic properties resulting in uneven flow distributions, therefore leading to short-circuiting and breakthrough issues. The present invention relates to wellbores connected hydraulically by multiple fracture zones; methods are directed to control for even flow distribution among fractures, regardless of heterogeneities in fracture hydraulic properties, and to control propagation of saturation fronts and thermal fronts in subsurface reservoirs.

The invention provides a calibration method for a nuclear magnetic fluid signal conversion relation with shale as a carrier and application, and belongs to the technical field of unconventional oil-gas exploration and development. The method comprises the steps that shale samples are pretreated, and fluid saturation is conducted on the shale samples; the saturated shale is subjected to centrifugation and drying treatment, and T2 spectrogram testing is carried out by adopting nuclear magnetic resonance equipment in different treatment stages; and the conversion relation of the oil-water fluid in the shale is established by comparing the attenuation amount of the fluid in the shale pores at different stages with the T2 spectrogram signal difference value. The mass change caused by fluid loss in the closed coring shale is used as the verification basis of the conversion relation, and the reliability of the method is ensured. And then crude oil with different maturity degrees and formation water fluids with different mineralization degrees are adopted to repeat the operation, the calibration conversion relation of the crude oil with different maturity degrees and the formation water with different mineralization degrees is obtained, then the change rule of the calibration conversion relation is disclosed, and the accuracy and scientificity of the nuclear magnetic resonance technology in the aspect of shale fluid evaluation are improved.

The invention discloses a method for evaluating the crude oil utilization rate during shale oil in-situ heating modification exploitation, and is applied to the field of oil development. The method comprises the following steps: (1) constructing a three-dimensional grid model of shale oil reservoirs between two horizontal wells, and determining parameters such as initial temperature, initial fluid pressure, initial porosity, initial oil saturation, initial gas saturation, initial water saturation and initial dissolved gas volume of three-dimensional grid units of each reservoir; (2) determining the pressure of each reservoir three-dimensional grid unit when the fluid pressure is balanced according to the shale oil layer section bottom hole pressure and the reservoir displacement pressure gradient; (3) according to the characteristics of a temperature field, a pressure field and the like of the in-situ heating shale oil reservoir, obtaining three-dimensional grid unit temperature and instantaneous fluid pressure parameters of each reservoir, and determining porosity and fluid saturation at each time point; and (4) according to the instantaneous fluid pressure and the balanced fluid pressure of the three-dimensional grid unit of each reservoir, determining the oil, gas and water production quantity and the production rate of the grid unit of each reservoir in combination with the oil, gas and water saturation.

The invention belongs to the technical field of shale oil exploration and development, and particularly relates to a two-dimensional nuclear magnetic resonance logging fluid saturation calculation method and system. The calculation method comprises the following steps: acquiring attribute data of a reservoir; determining lithology sensitive parameters and shale indexes of the reservoir according to the attribute data; determining a reservoir type according to the attribute data, the lithology sensitive parameters and the shale index; determining a fluid identification model of the reservoir according to the reservoir type and the nuclear magnetic resonance response characteristics; and calculating the fluid saturation of the reservoir by using the fluid identification model. When reservoir fluid identification and fluid saturation quantitative calculation are carried out, multiple reference indexes are referred to at the same time, then the reservoir fluid saturation of the reservoir can be accurately calculated, and the identification accuracy is high.

The invention relates to the technical field of water flooding gas reservoirs, in particular to a rock core displacement fluid saturation testing method and a testing device thereof.The method comprises the steps that S1, the original formation pressure and temperature of a gas reservoir are obtained; s2, obtaining a rock core, and testing physical property data of the rock core; then carrying out nuclear magnetic testing on the rock core; s3, saturating the rock core with formation water, and then carrying out nuclear magnetic testing; s4, carrying out gas drive water seepage test on the rock core according to the data in the S1, and obtaining the drive water quantity; s5, performing nuclear magnetic test on the depleted rock core; s6, obtaining the irreducible water saturation of the depleted rock core according to the nuclear magnetic test results of the steps S2, S3 and S5; s7, the total irreducible water saturation of the rock core is obtained according to the rock core physical property data, the displacement water amount and the irreducible water saturation of the rock core after exhaustion; the device comprises a drying oven, a first container, a second container, a core holder, a confining pressure pump, a displacement pump, a back pressure assembly, a receiving container and an electronic balance. The accuracy of fluid saturation determination can be improved.

The embodiment of the invention provides a shale oil reservoir wettability judgment method and device, and belongs to the technical field of oil and gas development. The shale oil reservoir wettability judgment method comprises the following steps: acquiring the suction rate and / or suction fluid saturation when a rock sample spontaneously sucks fluid; according to the suction rate and / or the suction fluid saturation, the average wettability of the shale oil reservoir is judged; according to the signal intensity increment S1 of the rock sample in a saturated water state compared with a dry state under the same pore radius and the signal intensity increment S2 of the rock sample in a saturated oil state compared with the dry state, the hydrophilic and oleophylic capacities of the shale oil reservoir under the pore radius are judged; and judging the wettability of the shale oil reservoir according to the average wettability of the shale oil reservoir and the hydrophilic and oleophylic capabilities of the shale oil reservoir under different pore radiuses. According to the embodiment of the invention, the wettability of the shale oil reservoir is judged by integrating the average wettability and the hydrophilic and oleophylic capabilities of the shale oil reservoir under different pore radiuses, and the oil and water wetting characteristics of the shale oil reservoir can be reflected from multiple dimensions, so that the evaluation is more comprehensive.

The embodiment of the invention provides a surfactant synergistic flooding parameter optimization method based on core scale simulation, and the method comprises the steps: selecting a real core sample of a target oil reservoir, carrying out the preprocessing of the real core sample, and constructing a three-dimensional digital core model of the target oil reservoir; selecting a surfactant according to reservoir characteristics of the target oil reservoir; according to the synergistic flooding characteristic and the oil-water two-phase flow characteristic of the surfactant in the pore medium of the target oil reservoir, a surfactant synergistic flooding model under the rock core scale is established; carrying out iterative solution on the synergistic flooding model through parallel calculation to realize dynamic simulation of the synergistic flooding process under the rock core scale, and outputting distribution data of a pressure field, a fluid saturation field and a surfactant concentration field in the three-dimensional digital rock core model; and according to the distribution data, determining a target parameter combination for synergistic flooding of the surfactant. The effect of improving the use degree of crude oil is achieved.

The invention discloses a phase change sweating cooling non-equilibrium flow heat transfer numerical simulation method which comprises the following steps: after initialization assignment, obtaining physical property parameters of a liquid phase and a gas phase according to a fluid temperature, and calculating a mixing density, a hybrid viscosity, a mixing enthalpy, a convection term coefficient and a diffusion term coefficient; boundary conditions are given to the cooling fluid continuity equation, the cooling fluid momentum equation, the cooling fluid energy equation and the porous framework energy equation; solving a cooling fluid continuity equation and a cooling fluid momentum equation; various items in a cooling fluid energy equation and a porous skeleton energy equation are divided into an unsteady state item, a convection item, a diffusion item and a source item, the four items are expressed by compiling a UDF function and then loaded into a UDS equation in FLUENT, new mixing speed, new mixing pressure intensity, new mixing enthalpy and new solid phase temperature are solved, and the optimal mixing speed, the optimal mixing enthalpy and the optimal solid phase temperature are obtained. The difference value between the initial value and the corresponding initial value in the iteration is judged, if the requirement is met, calculation can be ended, and if not, iteration is conducted again after the solid phase temperature and the fluid saturation are updated.

The invention belongs to the technical field of geological exploration, and discloses a continental facies shale oil mobility geological control factor combined evaluation method and system.The continental facies shale oil mobility geological control factor combined evaluation method comprises the steps that a sedimentary structure type and an organic matter type are divided based on a rock sample; comprehensively dividing continental facies shale lithofacies by combining three-end-member lithofacies types; analyzing the saturation of the movable fluid according to the multiphase relaxation time spectrum of the rock sample, and evaluating the mobility of shale oil by using pyrolysis parameters; and analyzing the influence factors of the mobility of shale oil based on the geological control factors. According to the method, aiming at research requirements of continental facies shale oil mobility control factors, in order to solve the problem of how to comprehensively and completely evaluate the shale oil mobility control factors, a multi-scale multi-type qualitative observation technology and a quantitative test technology are combined, a plurality of influence factors of shale oil mobility are comprehensively considered, and a relatively comprehensive evaluation system is established.

The invention discloses a device and method for detecting saturation pressure through a near-infrared technology, and relates to the field of fluid saturation pressure detection. The device for detecting the saturation pressure through the near-infrared technology comprises a moving unit, a storage unit and a detecting unit, wherein the storage unit moves through the moving unit; the detection unit comprises a detection frame, a pressure adjusting mechanism, a clamping mechanism and an observation mechanism. According to the device and method for detecting the saturation pressure through the near-infrared technology, when the device is used, the output end of a driving air cylinder stretches, so that a clamping mechanism automatically clamps a storage unit, after clamping is completed, a pressure adjusting mechanism automatically completes gas circuit connection with the storage unit, an observation mechanism can be automatically in place and prepare for observation, and after detection is completed, the storage unit can be automatically adjusted. Along with the contraction of the output end of the driving cylinder, the clamping mechanism and the pressure adjusting mechanism are separated successively, then the observation mechanism is reset, and the moving unit automatically replaces the storage unit, so that the whole detection process is full-automatic, more convenient and time-saving.

The invention discloses a numerical simulation method and device for a low-permeability reservoir, and the method comprises the steps: dividing the low-permeability reservoir into a plurality of small units, and building a mathematical model suitable for the numerical simulation of the low-permeability reservoir, so as to solve the flowing of a fluid. In the solving process, the pressure and the fluid saturation of the grid nodes are continuously updated until the convergence condition is met. And considering the change of the permeability along with the pressure, and selecting a proper formula to calculate the permeability according to the difference between the current pressure and the initial pressure of the grid nodes. Introducing a seepage model considering the starting pressure gradient, setting a starting pressure gradient threshold to judge whether the fluid starts to flow or not, and calculating the flow velocity according to the starting pressure gradient threshold. And solving an improved mass conservation equation by combining the permeability and the flow velocity. And solving the pressure equation and the saturation equation, and determining the saturation of the fluid. The problem of how to establish a model capable of accurately describing the fluid flow rule in the low-permeability reservoir so as to effectively promote the development and utilization of the low-permeability reservoir is solved.

Example methods and systems for wellbore fluid saturation mapping are disclosed. One example method includes obtaining, from a resistivity logging tool and during a process of drilling a wellbore in a reservoir formation, resistivity data of the reservoir formation in a first multiple azimuthal directions. Fluid saturation of the reservoir formation in the first multiple azimuthal directions is determined based on the resistivity data. A three-dimensional (3D) model of fluid saturation around the wellbore is determined based on the fluid saturation of the reservoir formation in the first multiple azimuthal directions. One or more steering commands for steering a drill bit during the process of drilling the wellbore is generated based on the 3D model of fluid saturation around the wellbore. A downhole drilling assembly is steered during the process of drilling the wellbore, based on the one or more steering commands.

The invention discloses a fluid identification method based on earthquake-electromagnetic combination, and aims to improve the identification precision of underground fluid, and the method comprises the steps: firstly, constructing and calibrating a forward model based on well data and a rock core experiment, and guaranteeing the theoretical support for the physical property of a stratum; afterwards, AVO inversion is carried out to obtain stratum elastic parameters, and meanwhile, electromagnetic inversion is utilized to obtain spatial distribution of resistivity. Afterwards, the elastic parameters and the resistivity obtained through inversion are substituted into a rock physical model, a joint objective function is constructed, and the difference between observation data and model prediction is quantified. And finally, through combination of global and local optimization algorithms, successive approximation to an optimal solution and inversion, lithology, porosity and fluid property parameters are obtained, fluid saturation is further deduced, and high-precision identification of the underground fluid is realized. The method can be widely applied to the geological engineering fields of oil-gas exploration, underground water resource evaluation and the like, and provides effective theoretical and practical support for accurate estimation of fluid saturation.

The invention relates to a T2 cut-off value determination method, and belongs to the technical field of oil-gas field development, and the method comprises the steps: determining a model coefficient based on a free fluid permeability model; obtaining movable porosity and bound water porosity based on the core porosity, the nuclear magnetic porosity, the second permeability and the model coefficient; and obtaining a T2 cutoff value based on the logging T2 spectrum, the movable porosity and the bound water porosity. According to the method and the system for determining the T2 cut-off value, the T2 cut-off value is determined through core physical property measurement porosity, permeability and irreducible fluid saturation data when there is no core nuclear magnetic resonance experiment data. Conventional rock core information is easy to obtain and low in cost, the number of coring data points is large, more T2 cut-off value and data matched with the logging T2 spectrum can be accumulated, and a morphological method or a regional experience T2 cut-off value can be established.

The invention discloses a shale oil reservoir CO2 huff and puff miscible-phase region dynamic discrimination method. The method comprises the steps that nuclear magnetic resonance testing is conducted on a target oil reservoir core sample; the method comprises the following steps: scanning a target oil reservoir core sample, constructing a three-dimensional core pore structure model, introducing nuclear magnetic resonance data to calibrate initial fluid saturation, and establishing a dynamic displacement numerical simulation model in combination with a CO2-crude oil phase equation, an interfacial tension model and a core permeability heterogeneity parameter; designing a plurality of groups of huff and puff experiments, simulating a CO2 injection process, monitoring nuclear magnetic resonance signal changes of the rock core in a displacement process in real time, correcting fluid saturation, a pressure field and interfacial tension parameters in a dynamic displacement numerical simulation model, and dividing a miscible-phase region; and selecting an optimal development parameter combination based on mixed-phase region distribution under different transfer injection opportunities, soaking time and throughput turns. According to the method, accurate division and dynamic discrimination of the CO2 huff and puff mixed-phase region are realized.

The invention discloses a rock pore fluid saturation determination method and device based on multi-nuclear magnetic resonance, and relates to the technical field of oil-gas exploration. A first nuclear magnetic resonance experiment is carried out through the first element, a second nuclear magnetic resonance experiment is carried out through the second element, the saturated water / saturated oil volume and the pore total volume of the rock sample are determined, and the saturation degree of the rock pore fluid is determined in a multi-nuclear magnetic resonance mode. The problem that oil and water signals in the magnetic resonance relaxation spectrum are overlapped to calculate the oil-water saturation inaccurately is effectively solved, and the oil-water saturation calculation precision is correspondingly improved.

The invention relates to the technical field of shale exploitation, and discloses a shale reservoir wettability dynamic determination method, which comprises: S1, selecting a shale plunger core, carrying out supercritical CO2 cleaning and vacuum drying, and carrying out high pressure saturation by using simulated crude oil to obtain an initial oil saturation; and S2, the saturated rock core is loaded into a high-temperature and high-pressure rock core holder, and under the simulated formation temperature and pressure condition, simulated formation water containing the paramagnetic contrast agent is injected at the constant flow speed for displacement till the water content of the outlet end reaches 98%. According to the invention, dynamic and three-dimensional space representation of wettability is realized: three modal data of nuclear magnetic resonance, resistivity and sound wave are synchronously acquired in the displacement process, so that the limitation of a traditional static method is overcome, and the dynamic process of the wettability changing along with the fluid saturation state can be captured in real time; and finally, a high-resolution three-dimensional wettability distribution map is generated, and non-uniform distribution of wettability in the core is visually revealed.

The invention relates to the technical field of reservoir evaluation in petroleum geological exploration sedimentary reservoirs, in particular to a method for calculating shale movable oil saturation based on a nuclear magnetism-centrifugation principle, which comprises the following steps: processing to obtain a sample after oil washing; based on the underground real gas-oil ratio, crude oil and natural gas are used for sample preparation, and prepared crude oil is obtained; pressurizing and saturating the prepared crude oil to obtain an oil-saturated rock core sample; calculating the total pore volume V of the rock core under the real underground temperature and pressure condition; obtaining the total volume V1 of the oil-saturated rock core sample at normal temperature and normal pressure, and calculating the oil saturation S1 of the light hydrocarbon lost part at room temperature; the ground movable fluid saturation S2 is obtained through calculation, and finally the real movable oil saturation S of the shale is obtained through calculation. By means of the method, the gas-oil ratio closer to the real geological condition is recovered, the viscosity of crude oil can be reduced, the viscosity is closer to the real condition, the experimental error is reduced to the maximum extent, and the calculation result is more accurate.

Methods and systems are provided characterizing a formation traversed by a wellbore, wherein the formation includes at least a flushed zone and an uninvaded zone, which involve obtaining well log data based on plurality of different well log measurements of the formation at multiple depths in the wellbore. The well log data is used to a computational model that solves for a set of petrophysical parameters that characterize a portion of the formation corresponding to the multiple depths in the wellbore, wherein the set of petrophysical parameters include a cementation exponent, a saturation exponent, and a flushed zone water resistivity. The solved-for set of petrophysical parameters can be used to determine a value of water saturation of the uninvaded zone for the portion of the formation corresponding to the multiple depths in the wellbore.

The invention provides a horizontal well fluid holdup inversion interpretation method and system based on a complex impedance method, and relates to the field of fluid holdup inversion, and the method comprises the steps: obtaining complex impedance frequency spectrums of oil-water stratified flow under different holdups, and extracting characteristic parameters reflecting the water holdup; constructing a data set by using the simulation data, and performing fitting research by using an RBF neural network to obtain a relationship between the characteristic parameters and the water holdup; measuring the oil-water two-phase flow by using a fluid holdup measurement system developed based on a complex impedance method to obtain current data of the oil-water two-phase flow; and processing the acquired current data and extracting characteristic values, and performing inversion by using the trained RBF neural network to obtain the fluid holdup. The method has the advantages that the training set is established through simulation to train the neural network model, the oil-water two-phase flow holdup is measured through the fluid holdup measuring system developed on the basis of the complex impedance method, and reliable inversion explanation is provided for measuring the horizontal well fluid holdup through the complex impedance method.

The present disclosure relates to an experimental device and method for simulating shale oil elastic production and CO2 huff and puff, specifically by soaking the pressure-maintained sealed shale core in a simulation liquid to spontaneously escape gas, simulating the elastic production stage, then through the method of high-temperature and high-pressure CO2 huff and puff combined with nuclear magnetic resonance test, simulating the shale oil reservoir gas injection energy supplement production process after the end of the elastic production stage, through the above simulation, the component change of the gas produced by the core in different depletion development stages can be reflected, and the recovery degree of shale oil in the elastic development stage can be calculated, and the change of nuclear magnetic resonance T2 spectrum of shale before and after huff and puff can be tested in situ, giving the movable fluid saturation of shale, realizing the evaluation of the oil production capacity of shale under the original condition, thereby truly reflecting the oil production capacity of the shale reservoir, and effectively solving the problem that the existing technology lacks an experimental device and experimental method for simulating the whole life cycle of shale oil from elastic production to gas injection energy supplement production.

The invention discloses an ion matching fine water-gas alternating drive microscopic visual simulation method based on a reverse micelle effect. The method comprises the following steps: S101, carrying out a contact experiment on CO2, saline water and crude oil to form a reverse micelle structure cluster on an oil-water interface, and separating to obtain reverse micelle-removed crude oil; s102, extracting a pore throat structure of the rock core sample through CT scanning and image processing, and making a microscopic model containing the pore throat structure; and S103, designing and building a microscopic visual experiment platform, respectively carrying out ion matching fine water-gas alternating flooding experiments on the crude oil in the step S101 and the reverse micelle-removed crude oil in the microscopic model in the step S102, and observing multi-phase fluid flow under the pore scale. According to the method, dynamic characteristic development, wettability change and fluid saturation distribution are dynamically monitored in the process, the synergistic advantage of ion matching water drive and CO2 drive is explained from the pore scale, and a theoretical basis is provided for popularization and application of ion matching fine water-gas alternating drive.

The present application relates to the technical field of reservoir evaluation in petroleum geological exploration and deposition reservoir, in particular to a method for calculating shale movable oil saturation based on nuclear magnetic-centrifugal principle, comprising: obtaining a sample after oil washing; based on real gas-oil ratio in the ground, using crude oil and natural gas to configure, obtaining configured crude oil; pressurizing and saturating the configured crude oil to obtain a saturated oil core sample; calculating the total pore volume V of the core under real underground temperature and pressure conditions; obtaining the total volume V1 of the saturated oil core sample under normal temperature and pressure, calculating the oil saturation S1 of the light hydrocarbon loss part under room temperature conditions; calculating the ground movable fluid saturation S2, and finally calculating the real movable oil saturation S of the shale. Through the method, the gas-oil ratio under the geological real conditions is recovered, the crude oil viscosity is reduced, the real situation is closer, the experimental error is minimized, and the calculation result is more accurate.

The present invention belongs to the field of rock physics and geophysics, and discloses a method and system for evaluating the relaxation rate of rock pore surface in low-field nuclear magnetic resonance experiment. A low-temperature nitrogen adsorption experiment is carried out on one core to obtain the specific surface area S; a pressurized saturated fluid experiment is carried out on another core to determine the total pore volume V0 of the sample by using the mass difference method of the sample before and after saturation; a nuclear magnetic resonance T2 spectrum experiment is carried out on the core in the saturated fluid state to determine the total nuclear magnetic signal N0 and the T2 average value T of the saturated core. 2LM0 After drying the saturated fluid core at different temperatures, the T2 spectrum of the core at each saturation was tested, and the fluid saturation f was determined based on the change in core mass or the total NMR signal. i , and the average value of NMR T2 T 2LMi The method of the present invention is not affected by human factors, and the evaluation result is more objective. . The conventional method of the present invention uses the average value of saturated nuclear magnetic T2 and the method of low-temperature nitrogen adsorption and mercury intrusion pore size distribution to calibrate the surface relaxation rate.

Implementations described and claimed herein provide systems and methods for developing a reservoir. In one implementation, a reservoir model is received. The reservoir model includes a static model and a dynamic model. The static model includes one or more clusters of a three-dimensional volume of the reservoir and an uncertainty quantification generated using a neural network. The dynamic model includes pressure values and fluid saturation values propagated across the three-dimensional volume through a nodal connectivity of neighboring clusters. A set of input features is generated from the static model and the dynamic model. The set of input features is related to a drilling attractiveness of a target region of the reservoir using a set of rules executed by a fuzzy inference engine. A quantification of the drilling attractiveness is generated. A recommendation for drilling in the reservoir is output based on the quantification of the drilling attractiveness.

A controlled rate of propagation of the fluid saturation front or thermal front is desired in may oil and gas and geothermal operations. Natural fractures and fractures created during hydraulic stimulation may have heterogeneous hydraulic properties resulting in uneven flow distributions, therefore leading to short-circuiting and breakthrough issues. The present invention relates to wellbores connected hydraulically by multiple fracture zones; methods are directed to control for even flow distribution among fractures, regardless of heterogeneities in fracture hydraulic properties, and to control propagation of saturation fronts and thermal fronts in subsurface reservoirs.

The invention provides a method for predicting formation pressure of tight oil steam drive expansion energy enhancement, comprising the following steps: step 1, calculating the expansion coefficient and compression coefficient of the crude oil in the tight oil reservoir at different temperatures; step 2, calculating the average oil saturation of the crude oil in the tight oil reservoir; step 3, calculating the steam drive expansion energy enhancement formation pressure of the tight oil reservoir at different steam temperatures considering different fluid saturations according to the results of step 1 and step 2; the method only requires basic physical parameters such as the compression coefficient, expansion coefficient, steam temperature and water saturation of the crude oil and formation water at different reservoir pressure temperatures, and uses the established theoretical calculation formula to achieve accurate prediction of the formation pressure, thereby providing a basis for the design of key parameters such as the temperature, velocity and dryness of the steam injected on the ground.