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.

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.

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.

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 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 relates to an inversion technology of fracture network, in particular to an inversion representation method for fracture network calibration and attribute after staged fracturing or volume fracturing. The inversion representation method includes the steps of 1), reading and entering main data and auxiliary data: (1), reading fracturing monitoring micro-seismic signals; (2), reading oil well yield data, fracturing construction parameters and reservoir information; 2), based on a fractal geometry system and combining with an integer programming method, generating fractal fracture network capable of satisfactorily matching with the micro-seismic signals in geometrical morphology; 3), performing quality check on the generated fractal fracture network on the basis of engineering parameters and construction parameters or a normal analysis method and adjusting fractal parameters controlling the geometrical morphology of fractures; 4), performing history matching on the basis of the yield data and combining a modified genetic algorithm and calibrating attributes of the fracture network by degrees. The inversion representation method is widely applicable to fracture network representation after hydraulic fracturing of oil wells.

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.

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 m_k 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 m_k 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 m_k of the local objective function. Finally, the calibrated model is used to develop the reservoir.