bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Quantitative and Qualitative Comparison of Coarse Grid Generation Techniques for Numerical Simulation of Flow in Heterogeneous Porous Media
Authors: Qomi P. Mostaghimi , Mahani H. , Firoozabadi B. 
Published: February 2009

Abstract
Applying upscaling techniques is an undeniable demand in reservoir simulation, considering the difference between level of details in a geological model and level of details that can be handled by reservoir simulators. Upscaling reservoir model involves first constructing a coarse grid by employing gridding algorithms and then computing average properties for coarse grid blocks. Although various techniques have been proposed for each of these steps, one has to be aware of strengths and weaknesses of each technique before attempting to apply them. In this paper, we focus on different gridding methods and evaluate their performances. Three main grid generation techniques are considered: permeability-based (PB), flow-based (FB), and vorticity-based (VB) gridding. We apply all three methods to some 2D heterogeneous models and simulate two-phase flow on the constructed grids. Then we compare their obtained global and local results. Fluid cuts at producer is employed as global performance indicator and saturation distribution error as local indicator. We show that FB and VB gridding, which are dynamic methods, are superior to PB gridding, which is a static method. Based on this analysis, we then concentrate on FB and VB griddings and investigate their performances in greater details. While FB gridding uses fluid velocity as grid blocks density indicator, VB gridding combines velocity and permeability variation in gridding according to its definition and takes advantages of both. Therefore, although performance of FB and VB griddings are comparable in many cases, VB has benefit of producing coarse grid blocks with more uniform permeability and fluid properties distribution. This in turn yields more accurate global and local results and reduces application of sophisticated upscaling techniques and full-tensor permeability upscaling.
Studies of Robust Two Stage Preconditioners for the Solution of Fully Implicit Multiphase Flow Problems
Authors: Al-Shaalan Tareq M. , Klie Hector , Dogru Ali H. , Wheeler Mary F. 
Published: February 2009

Abstract
The solution of the linear system of equations for a large scale reservoir simulation has several challenges. Preconditioners are used to speed up the convergence rate of the solution of such systems. In theory, a preconditioner defines a matrix M that can be inexpensively inverted and represents a good approximation of a given matrix A. In this work, two-stage preconditioners consisting of the approximated inverses M1 and M2 are investigated for multiphase flow in porous media. The first-stage preconditioner, M1, is approximated from Ausing four different solution methods: (1) constrained pressure residuals (CPR), (2) lower block Gauss-Seidel, (3) upper block Gauss-Seidel, and (4) one iteration of block Gauss-Seidel. The pressure block solution in each of these different schemes is calculated using the Algebraic Multi Grid (AMG) method. The inverse of the saturation (or more generally, the nonpressure) blocks are approximated using Line Successive Over Relaxation (LSOR). The second stage preconditioner, M2, is a global preconditioner based on LSOR iterations for the matrix A that captures part of the original interaction of different coefficient blocks. Several techniques are also employed to weaken the coupling between the pressure block and the nonpressure blocks. Effective decoupling is achievedby: (1) an IMPES-like approach designed to preserve the integrity of pressure coefficients, (2) Householder transformations, (3) the alternate block factorization (ABF), and (4) the balanced decoupling strategy (BDS) based on least squares. The fourth method is a new technique developed in this work. The aforementioned preconditioning techniques were implemented in a parallel reservoir simulation environment, and tested for large-scale two-phase and three-phase black oil simulation models. This study demonstrates that a two-stage preconditioner based on balanced decoupling strategy (BDS) or ABF combined with Gauss-Seidel sweeps, that also incorporate nonpressure solutions for M,delivers both the fastest convergence rate and the most robust option overall without compromising parallel scalability.
Well Placement Optimization Using a Genetic Algorithm With Nonlinear Constraints
Authors: Emerick Alexandre A. , Silva Eugênio , Messer Bruno , Almeida Luciana F. , Szwarcman Dilza , Pacheco Marco Aurélio C. , Vellasco Marley M. B. R. 
Published: February 2009

Abstract
Well placement optimization is a very challenging problem due to the large number of decision variables involved and the nonlinearity of the reservoir response as well as of the well placement constraints. Over the years, a lot of research has been done on this problem, most of which using optimization routines coupled to reservoir simulation models. Despite all this research, there is still a lack of robust computer-aided optimization tools ready to be applied by asset teams in real field development projects.
This paper describes the implementation of a tool, based on a Genetic Algorithm, for the simultaneous optimization of number, location and trajectory of producer and injector wells. The developed software is the result of a two-year project focused on a robust implementation of a computer-aided optimization tool to deal with realistic well placement problems with arbitrary well trajectories, complex model grids and linear and nonlinear constraints.
The developed optimization tool uses a commercial reservoir simulator as the evaluation function without using proxies to substitute the full numerical model. Due to the large size of the problem, in some cases involving more than 100 decision variables, the optimization process may require thousands of reservoir simulations. Such a task has become feasible through a distributed computing environment running multiple simulations at the same time.
The implementation uses a technique called Genocop III – Genetic Algorithm for Numerical Optimization of Constrained Problems – to deal with well placement constraints. Such constraints include grid size, maximum length of wells, minimum distance between wells, inactive grid cells and user-defined regions of the model, with non-uniform shape, where the optimization routine is not supposed to place wells.
The optimization process was applied to three full-field reservoir models based on real cases. It increased the net present values and the oil recovery factors obtained by well placement scenarios previously proposed by reservoir engineers. The process was also applied to a synthetic case, based on outcrop data, to analyze the impact of using reservoir quality maps to generate an initial well placement scenario for the optimization routine without using an engineer-defined configuration.
Efficient Simulation for Low-Salinity Waterflooding in Porous and Fractured Reservoirs
Authors: Wu Yu-Shu , Bai Baojun 
Published: February 2009

Abstract
Low-salinity brine injection has emerged as a promising, cost-effective improved oil recovery (IOR) method for waterflooding reservoirs. Laboratory tests and field applications show that low-salinity waterflooding could lead to significant reduction of residual oil saturation. There has been a growing interest with an increasing number of low-salinity waterflooding studies. However, there are few quantitative studies on flow and transport behavior of low-salinity IOR processes. This paper presents a general mathematic model (1) to incorporate known IOR mechanisms and (2) to quantify low-salinity waterflooding processes. In our mathematical conceptual model, salt is treated as an additional "component" to the aqueous phase, based on the following physical considerations: salt is transported only within the aqueous phase by advection and diffusion, and also subject to adsorption onto rock solids; relative permeability, capillary pressure, and residual oil saturation depend on salinity. Interaction of salt between mobile and immobile water zones is handled rigorously using a multi-domain approach. Fractured rock is handled using the multiple-continuum model or a discrete-fracture modeling approach. The conceptual model is implemented into a general-purpose reservoir simulator for modeling low-salinity IOR processes, using unstructured, regular, and irregular grids, applicable to 1-D, 2-D, and 3-D simulation of low-salinity water injection into porous media and fractured reservoirs. As demonstrated, the model provides a general capability for quantitative evaluation of low-salinity waterflooding in site-specific investigations.
Integrated Reservoir Simulation and Basin Models: Reservoir Charging and Fluid Mixing
Authors: Chen Zhangxin , Chen Hongsen , Carruthers Dan , Zhou Guoqiang 
Published: February 2009

Abstract
Perhaps the most important unconstrained aspect of petroleum systems analysis concerns the charging and emplacement of petroleum to a structure or prospect. Petroleum charge rates, leakage, and spill control petroleum residence time in a reservoir, which is fundamental for prediction of biodegration rates, seal integrity (failure), and oil quality, all of which are affected by fluid mixing processes. While forward models can estimate plausible charge rates based on thermal histories, there are no field data proxies for the charge rates that are necessary to constrain migration and charge models. To solve this problem, we are coupling high resolution, full physics reservoir simulation protocols to full 4D basin models such that gradients in petroleum compositions from models and from chemical analysis can be used to constrain charges rates. This new generation of hybrid reservoir simulator/basin models necessitates rapid high resolution fluid mixing solvers and multicomponent fluids.
This paper deals with the development of compositional fluid mixing simulators that can be coupled with basin modeling. These simulators will enable the forward simulation of detailed reservoir charging and fluid property evolution, coupling the effects of advection, diffusion, gravity segregation, and biodegration to predict the development of compositional gradients in petroleum columns that can be used to constrain reservoir charging and alteration processes. In this paper the effects of advection, diffusion, and gravity segregation are particularly studied. The traditional simulator for solving the isothermal gravity/chemical equilibrium problem is deduced as a special example of the simulators presented here. Numerical experiments to show these effects are given.
Field Development Optimization Applied to Giant Oil Fields
Authors: Litvak Michael L , Angert Patrick F 
Published: February 2009

Abstract
A new optimization technology has been demonstrated for giant oil and gas-condensate fields. Because of the very large number of wells involved, optimization is carried out on well patterns, well spacing in patterns, order of drilling different zones, etc. Earlier developed technology for the optimization of well placement, drilling schedule, well trajectories, and injection strategy has been extended for the optimization of field development schemes involving a very large numbers of wells.
The powerful optimization procedure is based on a global optimization technique such as the Genetic Algorithm and other mixed integer optimizers. Potential field development schemes that match field development constraints are identified. A global optimizer is then applied to determine the optimum field development scheme relative to pre-defined economic criteria and analysis. A statistical proxy procedure is utilized to reduce the number of optimization iterations and computing time required to solve this difficult optimization problem.
Economic indicators (e.g. net present value, incremental rate of return, capital efficiency, discounted payback, etc.) or oil/gas recovery are maximized subject to field development constraints. The multiple reservoir models representing uncertainties in reservoir geology are handled within the workflow and are represented in predicted results.
The applications of this optimization technology is clearly demonstrated to be a powerful and sufficiently general tool for analysis of most real world field development planning issues. Significant improvements (3-13 %) in oil/gas recovery and net present value are demonstrated in the optimum cases when compared with the best manually achieved reference field development case.
Equivalent Well Block Radius for Three Dimensional Flow
Authors: Dogru Ali H. 
Published: February 2009

Abstract
A new analytical expression has been developed for the equivalent well block radius for three dimensional (3D) flow. The new equation has the same structure as Peaceman's equation with two new parameters added. Therefore, implementation in a reservoir simulator is straight forward. Numerical experiments have shown that Peaceman's equation for two dimensional (2D) flow can cause high rate errors for the partially penetrating wells. The new formula reduces these errors to a few percent.
In this paper, derivation was presented for a vertical well, steady-state single phase flow with uniform and nonuniform grids. Multiphase, transient flow, horizontal wells and partial completion within a grid block is under development and will be presented in a new paper.
Black Oil Delumping: Running Black Oil Reservoir Simulations and Getting Compositional Wellstreams in the North Kuwait Jurassic Complex
Authors: Ghorayeb Kassem , Limsukhon Manoch , Dashti Qasem , Aziz Rafi Mohammad 
Published: February 2009

Abstract
The North Kuwait Jurassic Complex (NKJC) consists of five fields, each with three identified reservoirs within the naturally fractured Jurassic carbonate formation. These reservoirs contain multiple fluid types (gas-condensate and volatile oil) at near-critical conditions.
Multiple scenario production forecasts are required to prepare an optimal development plan for the complex. Current compartmentalization understanding based on geological and engineering data led to 24 isolated segments for which up to 24 separate simulation models can be potentially built. Because of global production targets and constraints, these models cannot be run in isolation. A multiple reservoir simulations coupling controller that dynamically apportions global production targets among different reservoirs is used for the purpose.
Compositions from different reservoirs are needed for surface facility design and operation. Compositional simulation is prohibitively computationally expensive for a multi-scenario production performance study for the NKJC. Black oil reservoir simulation is computationally far less demanding than compositional simulation. It does not, though, provide the detailed compositional information necessary for surface process modeling.
We demonstrate that using a black oil delumping method based primarily on the compositional information generated when simulating the laboratory depletion process (CVD, CCE, DL) overcomes the main limitation of black oil reservoir simulation in the NKJC. The method enables the composition and component molar rates of a producing well from a black oil reservoir simulation to be accurately reconstituted. Full computational advantages of black oil modeling are obtained while preserving the reservoir details required for an accurate prediction of well and reservoir behavior. Comparison of results obtained from a compositional model to those obtained from a black oil model using black oil delumping shows excellent agreement.
This study shows that black oil simulation with black oil delumping is a viable alternative to compositional simulation and fulfills the requirements for multi-scenario production forecasts in the NKJC.
History Matching Using a Hierarchical Stochastic Model with the Ensemble Kalman Filter: A Field Case Study
Authors: Zhang Yanfen , Oliver Dean S. 
Published: February 2009

Abstract
The growth in the application of optimization in reservoir management has placed greater demands on the application of history matching to produce models that not only reproduce the historical production behavior, but also preserve geological realism and quantify forecast uncertainty. Geological complexity and limited access to the subsurface typically result in a large uncertainty in reservoir properties and forecasts. There is, however, a systematic tendency to underestimate such uncertainty, especially when rock properties are modeled using Gaussian random fields. In this paper, we address two sources of uncertainty: uncertainty in regional trends by introducing stochastic trend coefficients and uncertainty in variogram model by treating correlation length or range as a stochastic variable instead of a well-determined variogram parameter. The hierarchical parameters including trend coefficients and heterogeneities can be estimated using ensemble Kalman filter (EnKF) for history matching.
Hierarchical or multi-scale heterogeneities are generally poorly represented, especially in deepwater reservoirs. We developed a hierarchical description of heterogeneities that introduced new variables into the reservoir description. We tested our method for updating these variables using production data from a deepwater field whose reservoir model has over 200,000 unknown parameters. The match of reservoir simulator forecasts to real field data using a standard application of EnKF had not been entirely satisfactory, as it was difficult to match water cut in one of the wells. None of the realizations of the reservoir exhibited water breakthrough using the standard method. By adding uncertainty in trends of reservoir properties, the ability to match the water cut and other production data was improved substantially.
The results indicate that an improvement in the generation of the initial ensemble and in the variables describing the property fields give an improved history match with plausible geology. It reduces the tendency to underestimate uncertainty while still providing reservoir models that match data.
History Matching of Hydrate Formation and Dissociation Experiments in Porous Media
Authors: Phirani J. , Pitchumani R. , Mohanty K. K. 
Published: February 2009

Abstract
Gas hydrates are crystalline, ice-like compounds of gas (e.g., methane) and water molecules that are formed under high pressure and low temperature. Many of the transport properties of porous media containing hydrates are unknown and difficult to measure experimentally. The goal of this work is to match laboratory experiments of hydrate formation and dissociation in cores to estimate some of these transport properties. An implicit, thermal, compositional simulator is used which accounts for four components (hydrate, water, methane and salt) and five phases (hydrate, aqueous, gas, ice, and salt precipitate). The transformation of methane and water to hydrate is modeled by a reaction with the kinetics controlled by the hydrate surface area. The key unknown is the variation of permeability within the core. Permeability and its spatial variation are used as parameters to match the experimental results.
Advanced Reservoir Management Workflow Using an EnKF Based Assisted History Matching Method
Authors: Seiler A. , Evensen G. , Skjervheim J. -A. , Hove J. , Vabø J. G. 
Published: February 2009

Abstract
This paper demonstrates the potential and advantages of the Ensemble Kalman filter (EnKF) as a tool for assisted history matching, based on its sequential processing of measurements, its capability of handling large parameter sets, and on the fact that it solves the combined state and parameter estimation problem.
A method and a thorough workflow for updating reservoir simulation models using the EnKF is developed. In addition, we present a method for updating relative permeability curves, as well as an improved approach for updating fault transmissibility multipliers.
The proposed workflow has been applied on a complex North Sea oil field. The EnKF successfully provides an ensemble of history matched reservoir models. A significant improvement in the history match is obtained by updating the relative permeability properties in addition to porosity and permeability fields and initial fluid contacts. Fault multipliers are estimated, and it is shown how the use of transformations, which handles non-Gaussian model variables, makes it possible to determine if a fault is open, closed, or partially closed with respect to flow.
The presented method is an innovative contribution to reservoir management workflows, which show growing interest in real time applications and fast model updating. Sequential data assimilation provides an updated reservoir model conditioned on the most recent production data. The updated ensemble is used to predict the uncertainty in future production and it is demonstrated that the EnKF leads to improved predictions with reduced uncertainty.
Modeling Well Inflow Control with Flow in Both Annulus and Tubing
Authors: Neylon K. , Reiso E. , Holmes J. A. , Nesse O. B. 
Published: February 2009

Abstract
We present a model for well inflow control devices (ICDs) that includes the effects of an annulus in which the flow between the ICDs is open or partially obstructed by the presence of packers, and we describe the application of this model in a full-field simulator. Flow in an open or partially obstructed annulus requires looped flowpaths to be modeled within the well. We describe the extension to the formulation of the well model together with considerations to ensure that the resulting equations have a Jacobian matrix that is invertible and explain the necessary modifications to the techniques used to solve the resulting linear system.
The effect of simulating flow in both the annulus and the tubing was investigated in two case studies involving ICDs: a synthetic case and a sector of a North Sea field model. Results showing significant differences between the inflow profiles of horizontal wells with and without packers in the annulus are presented.