Browsing by Subject "history matching"
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Item A New Method for History Matching and Forecasting Shale Gas/Oil Reservoir Production Performance with Dual and Triple Porosity Models(2012-10-19) Samandarli, OrkhanDifferent methods have been proposed for history matching production of shale gas/oil wells which are drilled horizontally and usually hydraulically fractured with multiple stages. These methods are simulation, analytical models, and empirical equations. It has been well known that among the methods listed above, analytical models are more favorable in application to field data for two reasons. First, analytical solutions are faster than simulation, and second, they are more rigorous than empirical equations. Production behavior of horizontally drilled shale gas/oil wells has never been completely matched with the models which are described in this thesis. For shale gas wells, correction due to adsorption is explained with derived equations. The algorithm which is used for history matching and forecasting is explained in detail with a computer program as an implementation of it that is written in Excel's VBA. As an objective of this research, robust method is presented with a computer program which is applied to field data. The method presented in this thesis is applied to analyze the production performance of gas wells from Barnett, Woodford, and Fayetteville shales. It is shown that the method works well to understand reservoir description and predict future performance of shale gas wells. Moreover, synthetic shale oil well also was used to validate application of the method to oil wells. Given the huge unconventional resource potential and increasing energy demand in the world, the method described in this thesis will be the "game changing" technology to understand the reservoir properties and make future predictions in short period of time.Item An efficient Bayesian approach to history matching and uncertainty assessment(Texas A&M University, 2007-04-25) Yuan, ChengwuConditioning reservoir models to production data and assessment of uncertainty can be done by Bayesian theorem. This inverse problem can be computationally intensive, generally requiring orders of magnitude more computation time compared to the forward flow simulation. This makes it not practical to assess the uncertainty by multiple realizations of history matching for field applications. We propose a robust adaptation of the Bayesian formulation, which overcomes the current limitations and is suitable for large-scale applications. It is based on a generalized travel time inversion and utilizes a streamline-based analytic approach to compute the sensitivity of the travel time with respect to reservoir parameters. Streamlines are computed from the velocity field that is available from finite-difference simulators. We use an iterative minimization algorithm based on efficient SVD (singular value decomposition) and a numerical ??????stencil?????? for calculation of the square root of the inverse of the prior covariance matrix. This approach is computationally efficient. And the linear scaling property of CPU time with increasing model size makes it suitable for large-scale applications. Then it is feasible to assess uncertainty by sampling from the posterior probability distribution using Randomized Maximum Likelihood method, an approximate Markov Chain Monte Carlo algorithms. We apply this approach in a field case from the Goldsmith San Andres Unit (GSAU) in West Texas. In the application, we show the effect of prior modeling on posterior uncertainty by comparing the results from prior modeling by Cloud Transform and by generalized travel time inversion and utilizes a streamline-based analytic approach to compute the sensitivity of the travel time with respect to reservoir parameters. Streamlines are computed from the velocity field that is available from finite-difference simulators. We use an iterative minimization algorithm based on efficient SVD (singular value decomposition) and a numerical Collocated Sequential Gaussian Simulation. Exhausting prior information will reduce the prior uncertainty and posterior uncertainty after dynamic data integration and thus improve the accuracy of prediction of future performance.Item Multiscale Spectral-Domain Parameterization for History Matching in Structured and Unstructured Grid Geometries(2012-10-19) Bhark, Eric WhittetReservoir model calibration to production data, also known as history matching, is an essential tool for the prediction of fluid displacement patterns and related decisions concerning reservoir management and field development. The history matching of high resolution geologic models is, however, known to define an ill-posed inverse problem such that the solution of geologic heterogeneity is always non-unique and potentially unstable. A common approach to improving ill-posedness is to parameterize the estimable geologic model components, imposing a type of regularization that exploits geologic continuity by explicitly or implicitly grouping similar properties while retaining at least the minimum heterogeneity resolution required to reproduce the data. This dissertation develops novel methods of model parameterization within the class of techniques based on a linear transformation. Three principal research contributions are made in this dissertation. First is the development of an adaptive multiscale history matching formulation in the frequency domain using the discrete cosine parameterization. Geologic model calibration is performed by its sequential refinement to a spatial scale sufficient to match the data. The approach enables improvement in solution non-uniqueness and stability, and further balances model and data resolution as determined by a parameter identifiability metric. Second, a model-independent parameterization based on grid connectivity information is developed as a generalization of the cosine parameterization for applicability to generic grid geometries. The parameterization relates the spatial reservoir parameters to the modal shapes or harmonics of the grid on which they are defined, merging with a Fourier analysis in special cases (i.e., for rectangular grid cells of constant dimensions), and enabling a multiscale calibration of the reservoir model in the spectral domain. Third, a model-dependent parameterization is developed to combine grid connectivity with prior geologic information within a spectral domain representation. The resulting parameterization is capable of reducing geologic models while imposing prior heterogeneity on the calibrated model using the adaptive multiscale workflow. In addition to methodological developments of the parameterization methods, an important consideration in this dissertation is their applicability to field scale reservoir models with varying levels of prior geologic complexity on par with current industry standards.Item Optimal Reservoir Management and Well Placement Under Geologic Uncertainty(2012-10-19) Taware, Satyajit VijayReservoir management, sometimes referred to as asset management in the context of petroleum reservoirs, has become recognized as an important facet of petroleum reservoir development and production operations. In the first stage of planning field development, the simulation model is calibrated to dynamic data (history matching). One of the aims of the research is to extend the streamline based generalized travel time inversion method for full field models with multimillion cells through the use of grid coarsening. This makes the streamline based inversion suitable for high resolution simulation models with decades long production history and numerous wells by significantly reducing the computational effort. In addition, a novel workflow is proposed to integrate well bottom-hole pressure data during model calibration and the approach is illustrated via application to the CO2 sequestration. In the second stage, field development strategies are optimized. The strategies are primarily focused on rate optimization followed by infill well drilling. A method is proposed to modify the streamline-based rate optimization approach which previously focused on maximizing sweep efficiency by equalizing arrival time of the waterfront to producers, to account for accelerated production for improving the net present value (NPV). Optimum compromise between maximizing sweep efficiency and maximizing NPV can be selected based on a 'trade-off curve.' The proposed method is demonstrated on field scale application considering geological uncertainty. Finally, a novel method for well placement optimization is proposed that relies on streamlines and time of flight to first locate the potential regions of poorly swept and drained oil. Specifically, the proposed approach utilizes a dynamic measure based on the total streamline time of flight combined with static and dynamic parameters to identify "Sweet-Spots" for infill drilling. The "Sweet-Spots" can be either used directly as potential well-placement locations or as starting points during application of a formal optimization technique. The main advantage of the proposed method is its computational efficiency in calculating dynamic measure map. The complete workflow was also demonstrated on a multimillion cell reservoir model of a mature carbonate field with notable success. The infill locations based on dynamic measure map have been verified by subsequent drilling.Item Rapid assessment of redevelopment potential in marginal oil fields, application to the cut bank field(Texas A&M University, 2005-02-17) Chavez Ballesteros, Luis EladioQuantifying infill potential in marginal oil fields often involves several challenges. These include highly heterogeneous reservoir quality both horizontally and vertically, incomplete reservoir databases, considerably large amounts of data involving numerous wells, and different production and completion practices. The most accurate way to estimate infill potential is to conduct a detailed integrated reservoir study, which is often time-consuming and expensive for operators of marginal oil fields. Hence, there is a need for less-demanding methods that characterize and predict heterogeneity and production variability. As an alternative approach, various authors have used empirical or statistical analyses to model variable well performance. Many of the methods are based solely on the analysis of well location, production and time data. My objective is to develop an enhanced method for rapid assessment of infill-drilling potential that would combine increased accuracy of simulation-based methods with times and costs associated with statistical methods. My proposed solution is to use reservoir simulation combined with automatic history matching to regress production data to determine the permeability distribution. Instead of matching on individual cell values of reservoir properties, I match on constant values of permeability within regions around each well. I then use the permeability distribution and an array of automated simulation predictions to determine infill drilling potential throughout the reservoir. Infill predictions on a single-phase synthetic case showed greater accuracy than results from statistical techniques. The methodology successfully identified infill well locations on a synthetic case derived from Cut Bank field, a water-flooded oil reservoir. Analysis of the actual production and injection data from Cut Bank field was unsuccessful, mainly because of an incomplete production database and limitations in the commercial regression software I used. In addition to providing more accurate results than previous empirical and statistical methods, the proposed method can also incorporate other types of data, such as geological data and fluid properties. The method can be applied in multiphase fluid situations and, since it is simulation based, it provides a platform for easy transition to more detailed analysis. Thus, the method can serve as a valuable reservoir management tool for operators of stripper oil fields.Item Stochastic and Deterministic Inversion Methods for History Matching of Production and Time-Lapse Seismic Data(2013-08-26) Watanabe, ShingoAutomatic history matching methods utilize various kinds of inverse modeling techniques. In this dissertation, we examine ensemble Kalman filter as a stochastic approach for assimilating different types of production data and streamline-based inversion methods as a deterministic approach for integrating both production and time-lapse seismic data into high resolution reservoir models. For the ensemble Kalman filter, we develope a physically motivated phase streamline-based covariance localization method to improve data assimilation performance while capturing geologic continuities that affect the flow dynamics and preserving model variability among the ensemble of models. For the streamline-based inversion method, we derived saturation and pressure drop sensitivities with respect to reservoir properties along streamline trajectories and integrated time-lapse seismic derived saturation and pressure changes along with production data using a synthetic model and the Brugge field model. Our results show the importance of accounting for both saturation and pressure changes in the reservoir responses in order to constrain the history matching solutions. Finally we demonstrated the practical feasibility of a proposed structured work- flow for time-lapse seismic and production data integration through the Norne field application. Our proposed method follows a two-step approach: global and local model calibrations. In the global step, we reparameterize the field permeability het- erogeneity with a Grid Connectivity-based Transformation with the basis coefficient as parameters and use a Pareto-based multi-objective evolutionary algorithm to integrate field cumulative production and time-lapse seismic derived acoustic impedance change data. The method generates a suite of trade-off solutions while fitting production and seismic data. In the local step, first the time-lapse seismic data is integrated using the streamline-derived sensitivities of acoustic impedance with respect to reservoir permeability incorporating pressure and saturation effects in-between time-lapse seismic surveys. Next, well production data is integrated by using a generalized travel time inversion method to resolve fine-scale permeability variations between well locations. After model calibration, we use the ensemble of history matched models in an optimal rate control strategy to maximize sweep and injection efficiency by equalizing flood front arrival times at all producers while accounting for geologic uncertainty. Our results show incremental improvement of ultimate recovery and NPV values.Item The integration of seismic anisotropy and reservoir performance data for characterization of naturally fractured reservoirs using discrete feature network models(Texas A&M University, 2004-09-30) Will, Robert A.This dissertation presents the development of a method for quantitative integration of seismic (elastic) anisotropy attributes with reservoir performance data as an aid in characterization of systems of natural fractures in hydrocarbon reservoirs. This new method incorporates stochastic Discrete Feature Network (DFN) fracture modeling techniques, DFN model based fracture system hydraulic property and elastic anisotropy modeling, and non-linear inversion techniques, to achieve numerical integration of production data and seismic attributes for iterative refinement of initial trend and fracture intensity estimates. Although DFN modeling, flow simulation, and elastic anisotropy modeling are in themselves not new technologies, this dissertation represents the first known attempt to integrate advanced models for production performance and elastic anisotropy in fractured reservoirs using a rigorous mathematical inversion. The following new developments are presented: . ? Forward modeling and sensitivity analysis of the upscaled hydraulic properties of realistic DFN fracture models through use of effective permeability modeling techniques. . ? Forward modeling and sensitivity analysis of azimuthally variant seismic attributes based on the same DFN models. . ? Development of a combined production and seismic data objective function and computation of sensitivity coefficients. . ? Iterative model-based non-linear inversion of DFN fracture model trend and intensity through minimization of the combined objective function. This new technique is demonstrated on synthetic models with single and multiple fracture sets as well as differing background (host) reservoir hydraulic and elastic properties. Results on these synthetic control models show that, given a well conditioned initial DFN model and good quality field production and seismic observations, the integration procedure results in convergence of both fracture trend and intensity in models with both single and multiple fracture sets. Tests show that for a single fracture set convergence is accelerated when the combined objective function is used as compared to a similar technique using only production data in the objective function. Tests performed on multiple fracture sets show that, without the addition of seismic anisotropy, the model fails to converge. These tests validate the importance of the new process for use in more realistic reservoir models.