106 results about "History matching" patented technology

The present invention, in one embodiment, is directed to a method and system for accelerating and improving the history matching of a well bore and / or reservoir simulation model using a neural network. The neural network provides a correlation between the calculated history match error and a selected set of parameters that characterize the well bore and / or the reservoir. The neural network iteratively varies a selection and / or the value of the parameters to provide at least one set of history match parameters having a value that provides a minimum for the calculated history matching error.

A method for forecasting performance for and characterizing the properties of a multilayer low permeability gas reservoir. The method includes a coupled well / reservoir predictive model that accounts for pressure drop between layers, allowing accurate, rigorous, and rapid forecasting of reservoir performance. The method provides estimates of individual layer properties such as in-situ permeability, skin factor, fracture half-length, fracture conductivity, drainage area, etc. by simultaneously history matching production data and production log data using the coupled well / reservoir predictive model.

A method for forecasting production from a hydrocarbon producing reservoir, the method includes defining an objective function and characteristics of a history-matched model of a reservoir and acceptable error E. At least one geological realization of the reservoir is created representing a probable geological setting. For each geological realization, a global optimization technique is used to perform history matching in a series of iterative steps to obtain acceptable models. Production of the reservoir is forecasted based upon simulation runs of the respective models.

A method utilizing genetic programming to construct history matching and forecasting proxies for reservoir simulators. Acting as surrogates for computer simulators, the genetic programming proxies evaluate a large number of reservoir models and predict future production forecasts for petroleum reservoirs.

A method, system and program storage device for history matching and forecasting of subterranean reservoirs is provided. Reservoir parameters and probability models associated with a reservoir model are defined. A likelihood function associated with observed data is also defined. A usable likelihood proxy for the likelihood function is constructed. Reservoir model parameters are sampled utilizing the usable proxy for the likelihood function and utilizing the probability models to determine a set of retained models. Forecasts are estimated for the retained models using a forecast proxy. Finally, computations are made on the parameters and forecasts associated with the retained models to obtain at least one of probability density functions, cumulative density functions and histograms for the reservoir model parameters and forecasts. The system carries out the above method and the program storage device carries instructions for carrying out the method.

A system and method is taught to substantially automate forecasting for a hydrocarbon producing reservoir through integration of modeling module workflows. A control management module automatically generates static and dynamic offspring models, with static and dynamic modeling software, until a performance objective associated with the forecasting of the reservoir is satisfied. The performance objective can include an experimental design table to determine a sensitivity of a particular parameter or can be directed towards reservoir optimization, i.e., ultimate hydrocarbon recovery, net present value, reservoir percentage yield, reservoir fluid flow rate, or history matching error.

Method for gradually modifying a geological model representative of an underground reservoir so as to respect fixed average proportions of these lithologic facies.A group of facies referred to as selection and a subgroup of facies referred to as association are selected. A transformation parameter is defined by the ratio between the average proportions of the facies of the association and those of the selection. Within the context of history matching, a difference between measured dynamic data values and values calculated by means of a flow simulator from the geological model is measured. An optimization algorithm is used to deduce therefrom a new value for the transformation parameter that minimizes this difference and this transformation is applied to the lithologic facies of the selection. The modification can be applied to the entire model or to a given zone.

A method of modifying a geological model representative of an underground reservoir is disclosed which respects average proportions of the lithologic facies imposed by a production data calibration process which has application to petroleum reservoir development. A geographical zone Z is defined within the geological model and an average proportion in zone Z allowing the production data to be calibrated is determined for k facies, with an optimization process. The proportions of these facies are modified using a block indicator cokriging method constrained by the average proportions to be respected. A new geological model constrained by the modified facies proportions is simulated and the development of the underground medium is optimized by the simulated model.

The invention relates to a method for history matching a facies geostatistical model using the ensemble Kalman filter (EnKF) technique. The EnKF is not normally appropriate for discontinuous facies models such as multiple point simulation (MPS). In the method of the invention, an ensemble of realizations are generated and then uniform vectors on which those realizations are based are transformed to Gaussian vectors before applying the EnKF to the Gaussian vectors directly. The updated Gaussian vectors are then transformed back to uniform vectors which are used to update the realizations. The uniform vectors may be vectors on which the realizations are based directly; alternatively each realization may be based on a plurality of uniform vectors linearly combined with combination coefficients. In this case each realization is associated with a uniform vector made up from the combination coefficients, and the combination coefficient vector is then transformed to Gaussian and updated using EnKF.

The invention relates to a fracture-cavity type oil deposit analyzing method for water-flooding development and application thereof. According to the method, history matching is conducted on a first geologic feature parameter of multiscale reservoir bodies constructing a multiscale reservoir body distribution conceptual model to obtain a second geologic feature parameter of the multiscale reservoir bodies constructing the finely drawn multiscale reservoir body distribution geologic model. In history matching, the independent representation multi-sided conductivity is adopted for dealing with the influence caused by connection position differences of different side fractures and caves on the oil water flowing rule; the virtual time step is adopted for reflecting the oil water replacement momentary balancing effect caused by oil water density difference; for anisotropy characters of the fractures, the tensor permeability of an arbitrarily fracture of the space is obtained by the adoption of conversion of a geodetic coordinate system and a space coordinates system. The fracture-cavity type oil deposit analyzing method for the water-flooding development is used for conducting fracture-cavity type oil deposit water-flooding development and decisions, the geologic model is more accurate, the flowing rule and the oil-displacement mechanism are more complete, and optimized decision through technologies and development effect predication are more accurate and reliable.

Device, medium and method for generating a multidimensional image of a subsurface of the earth. The method includes receiving data related to the subsurface of the earth; generating an ensemble of realizations associated with the subsurface based on the received data; applying wavelet re-parametrization to spatial properties of the members of the ensemble to calculate a set of wavelet coefficients; reconstructing the spatial properties of the ensemble based on a subset of the wavelet coefficients; applying a forward simulator to the reconstructed spatial properties of the ensemble for estimating one or more physical parameters of the subsurface; applying an ensemble-based optimization method to update the subset of the wavelet coefficients; and generating multidimensional image of the subsurface based on the updated subset of the wavelet coefficients.

Data from crosswell seismic surveys is processed to provide crosswell time-lapse data to map fluid changes in a reservoir where time-lapse or 4D seismic data is unavailable or unreliable, such as in onshore reservoirs. The resultant processing results provide quantitative information for history matching purposes using a probabilistic approach to take in account uncertainties in the geological model and reduce uncertainties in reservoir production forecasts.

An interface apparatus according to an embodiment of the invention includes: an operation detecting section configured to detect a device operation; a status detecting section configured to detect a status change or status continuance of a device or in the vicinity of the device; an operation history accumulating section configured to accumulate a operation detection result and a status detection result in association with each other; an operation history matching section configured to match a status detection result for a newly detected against accumulated status detection results, and select a device operation that corresponds to the status detection result for the newly detected; and an utterance section configured to utter as sound a word corresponding to the selected device operation.

The invention discloses a method for improving an oil reservoir exploitation effect by utilizing discrete fracture endpoint deformation numerical simulation. The method comprises the following steps of dividing an oil reservoir storage body into a continuous medium and a discrete medium according to a characteristic scale; deforming the end part of a discrete fracture from a square shape into a pointed shape to eliminate tiny grids, establishing rock stratum surface grids, and establishing three-dimensional oil reservoir grids; inputting measured oil reservoir parameters such as porosity, permeability and water saturation into a simulator, wherein a real value rather than a grid display value is used for the width of the discrete fracture; correcting the oil reservoir parameters by using a history matching method; and measuring and calculating the well productivity, residual oil and gas reserves and the distribution positions of residual oil and gas, and making a subsequent oil reservoir exploitation plan. According to the method, a discrete fracture numerical simulator can be prevented from measurement and calculation interruption and failures, the whole links of oil reservoir exploitation can be actually measured and calculated to improve the measurement and calculation accuracy of the well productivity and the residual oil and gas distribution of an oil reservoir, and a more effective development plan can be made to improve the oil reservoir exploitation effect.

The invention discloses an automatic history matching method and system based on an automatic encoder and multi-objective optimization. The automatic encoder is used for reducing the dimension of static parameters of a high-dimensional reservoir to realize the bidirectional mapping between the static parameters of the high-dimensional reservoir and a low-dimensional data space, and then the static parameters of the reservoir with the dimension reduced are optimized by using a multi-objective algorithm to realize analog automatic history matching of a reservoir numerical value to obtain a reservoir numerical model close to an actual geological model. According to the automatic history matching method and system disclosed by the invention, the automatic encoder based on depth learning and the multi-objective algorithm are applied to the history matching problem of the reservoir, thereby greatly reducing the search spaces of optimization parameters, improving the calculation efficiency and precision and making the optimized reservoir numerical value be closer to the actual geological model.

The invention provides an oil reservoir numerical simulation method and apparatus based on high water-cut period monitoring data constraints. The oil reservoir numerical simulation method includes acquiring the data of a production well, an injection well and an oil reservoir, and determining the dynamic parameters and static parameters of the wells and the oil reservoir; generating water logging three dimensional characteristics at different time based on the logging interpretation data in the static parameters; generating the residual oil distribution rules at different time based on the inspection well coring data in the dynamic parameters; establishing a geological model based on the static parameters of the oil reservoir, and initializing the geological model based on the original formation pressure distribution or the relation of pressure and depth, and rock and fluid properties; historically matching the initialized geological model to generate a history matching result; and historically matching the oil reservoir numerical simulation based on the water logging three dimensional characteristics, the residual oil distribution rules, and the history matching result. The oil reservoir with different water logging and residual oil distribution characteristics at the high water-cut stage is numerically simulated in high precision.

The invention provides a method for adjusting the variable flow line vector of thick-bed oil reservoirs. The method for adjusting the variable flow line vector of thick-bed oil reservoirs includes: step 1, conducting reservoir heterogeneity research; step 2, establishing a numerical simulation model, and Carry out history matching; step 3, conduct research on the distribution of remaining oil saturation; step 4, carry out the design of the well pattern variable flowline adjustment scheme; step 5, use numerical simulation technology to predict the ultimate recovery of the variable flowline scheme, according to Then optimize the variable streamline scheme; step 6, optimize the water injection parameter vector, and use numerical simulation technology to predict the final recovery factor of the vector water injection parameter optimization scheme. The variable streamline vector adjustment method for thick-bed reservoirs is highly practical, and can effectively slow down the production decline and water-cut rise of thick-bed reservoirs during the ultra-high water cut period, and improve the water flooding development effect.

The invention discloses a method for measuring a polymer flooding relative permeability curve. The method comprises the following steps: first carrying out a polymer core flooding experiment to obtain production experiment data at different moments, then establishing a fitting target function and a polymer flooding relative permeability curve model by taking the obtained production experiment data as fitting data, and finally continuously regulating a parameter of the relative permeability curve model by virtue of an automatic history matching algorithm through a numerical simulator until a value of the fitting target function reaches an allowable error range, so as to obtain the optimal polymer flooding relative permeability curve. The method is simple and easy to operate, and help may be provided for research on polymer flooding permeability rules.

The invention provides a method and a device for determining history matching adjustment parameters in numerical reservoir simulation. The method comprises the following steps of determining a function relation of oil production and water yield of an oil well and a water injection rate of a connected well layer according to reservoir data in the numerical reservoir simulation; carrying out multiple linear regression analysis on the function relation of the oil production and the water yield of the target oil well and the water injection rate of the connected well layer, and determining a multiple linear regression formula of the oil production of the target oil well and the water injection rate of the connected well layer; and determining the to-be-adjusted history matching parameters of the target oil well according to regression coefficients of the determined multiple linear regression formula of the oil production of the target oil well and the water injection rate of the connected well layer. By adopting a method of multivariate statistics, relation is established between the water absorbing capacity of each layer of a water injection well and the yield of a production well, which are obtained through analog computation, and through analyzing the influence of each water absorbing layer on the yield of the oil well, the layer position is judged and adjusted, the parameters of the corresponding small layer are adjusted and modified, and the history matching is guided, so that the purpose of detailed history matching is achieved.

The invention provides a genetic algorithm-based auxiliary automatic oil-reservoir history matching method, belonging to the field of numerical simulation of oil reservoirs. The method comprises the steps of: by taking a mean value of matched evaluation of estimates of oil, gas and water as the degree of adaptability, performing operations by using a single-objective genetic algorithm; and setting a file to record Pareto solutions of the matched evaluation estimates of oil, gas and water generated during the whole process based on the genetic algorithm. By adopting the single-objective genetic algorithm, results superior to those of a multi-objective genetic algorithm can be obtained, and meanwhile, a group of solutions rather than a solution can be provided for users, so that the automatic oil-reservoir history matching efficiency is improved. In addition, the invention provides a novel oil-reservoir history matching evaluation function, which can effectively improve the automatic oil-reservoir history matching efficiency.

The invention relates to an oil deposit numerical value simulation parameter sensibility analysis device and method. The technical scheme of the oil deposit numerical value simulation parameter sensibility analysis device is that the oil deposit numerical value simulation parameter sensibility analysis device comprises a parameter acquisition device, a model construction device, a solving device and an analysis device, wherein the parameter acquisition device, wherein the parameter acquisition device is used for connecting with an oil deposit numerical value simulator and obtaining the parameter and the data field of a simulation result; the model construction device is use for constructing an adjoint model of which the adjoint variable is independent of a simulation calculation variable and constructing the coefficient matrix of the adjoint model according to a simulator solving result; the solving device is used for solving the adjoint variable and utilizing the obtained adjoint variable to solve a sensitivity coefficient matrix, which relates to a model control variable, of the target function; and the analysis device carries out parameter sensitivity performance analysis according to an obtained result. The device has the beneficial effects that efficiency for oil deposit engineers to carry out history matching can be greatly improved, a high-quality matching result is obtained, a fitting period is obviously shortened, the oil deposit engineers do not need to focus energy on earlier stage complex reservoir physical property parameters, and therefore, personnel cost is lowered.

A computer implemented method can include selecting a first flow rate model for a well, providing reservoir data to the first flow rate model, providing production history data to the first flow rate model, computing a solution to the first flow rate model and comparing the solution to production history data. A method can include implementing dual, triple or quad porosity models of a reservoir and history matching a model against actual well production data. A method can include comparing one or more models and determining whether a parameter has a unique solution. A system can include a computer readable medium having instructions stored thereon that, when executed by a processor, cause the processor to perform one or more methods.

In one method, the permeabilities are obtained by correcting the geometric factor derived from combining the FRA analysis and buildup analysis. In a second method, the permeabilities are obtained by combining the spherical permeability estimated from buildup analysis and the geometric skin factor obtained from history matching the probe-pressure data. In other methods, horizontal and vertical permeabilities are determined by analysis of pressure drawdown made with a single probe of circular aperture in a deviated borehole at two different walls of the borehole.

A method, system and program storage device for history matching and forecasting of subterranean reservoirs is provided. Reservoir parameters and probability models associated with a reservoir model are defined. A likelihood function associated with observed data is also defined. A usable likelihood proxy for the likelihood function is constructed. Reservoir model parameters are sampled utilizing the usable proxy for the likelihood function and utilizing the probability models to determine a set of retained models. Forecasts are estimated for the retained models using a forecast proxy. Finally, computations are made on the parameters and forecasts associated with the retained models to obtain at least one of probability density functions, cumulative density functions and histograms for the reservoir model parameters and forecasts. The system carries out the above method and the program storage device carries instructions for carrying out the method.

A method of developing a petroleum reservoir from a reservoir model and optimized history matching is disclosed having application for petroleum reservoir characterization. A global objective function measuring the differences between the measured historical data and the simulated historical data is defined according to M parameters. The global objective function is then decomposed into a sum of k local objective functions. Each local objective function measures the differences on a geographic region from mk parameters, selected from among the M parameters, and having a significant impact on the historical data of the region. The region is determined by minimizing this number mk of parameters. The model is then modified by minimizing the global objective function by a gradient method wherein the derivatives of the local objective functions are estimated by means of a parameter perturbation technique. For each local objective function, the perturbation matrix has a rank equal to the number of parameters mk of the local objective function. Finally, the calibrated model is used to develop the reservoir.