Abstract: This paper (SPE 141950) was accepted for presentation at the SPE Reservoir Simulation Symposium, The Woodlands, Texas, USA, 21–23 February 2011, and revised for publication. Original manuscript received for review 15 December 2010. Revised manuscript received for review 12 May 2011. Paper peer approved 15 July 2011. Summary Subsurface geology is highly uncertain, and it is necessary to account for this uncertainty when optimizing the location of new wells. This can be accomplished by evaluating reservoir performance for a particular well configuration over multiple realizations of the reservoir and then optimizing based, for example, on expected net present value (NPV) or expected cumulative oil production. A direct procedure for such an optimization would entail the simulation of all realizations at each iteration of the optimization algorithm. This could be prohibitively expensive when it is necessary to use a large number of realizations to capture geological uncertainty. In this work, we apply a procedure that is new within the context of reservoir management—retrospective optimization (RO)—to address this problem. RO solves a sequence of optimization subproblems that contain increasing numbers of realizations. We introduce the use of k -means clustering for selecting these realizations. Three example cases are presented that demonstrate the performance of the RO procedure. These examples use particle swarm optimization (PSO) and simplex linear interpolation (SLI)-based line search as the core optimizers (the RO framework can be used with any underlying optimization algorithm, either stochastic or deterministic). In the first example, we achieve essentially the same optimum using RO as we do using a direct optimization approach, but RO requires an order of magnitude fewer simulations. The results demonstrate the advantages of cluster-based sampling over random sampling for the examples considered. Taken in total, our findings indicate that RO using cluster sampling represents a promising approach for optimizing well locations under geological uncertainty.

Abstract: We simulate flow and transport directly on pore-space images obtained from a microcomputed-tomography (micro-CT) scan of rock cores. An efficient Stokes solver is used to simulate lowReynolds-number flows. The flow simulator uses a finite-difference method along with a standard predictor/corrector procedure to decouple pressure and velocity. An algebraic multigrid technique solves the linear systems of equations. We then predict permeability, and the results are compared with lattice-Boltzmannmethod (LBM) numerical results and available experimental data. For solute transport, we apply a streamline-based algorithm that is similar to the Pollock algorithm common in field-scale reservoir simulation, but which uses a novel semianalytic formulation near solid boundaries to capture, with subgrid resolution, the variation in velocity near the grains. A random-walk method accounts for molecular diffusion. The streamline-based algorithm is validated by comparison with published results for Taylor-Aris dispersion in a single capillary with a square cross section. We then predict accurately the available experimental data in the literature for the longitudinal dispersion coefficient for a range of Peclet numbers (10 to 10). We introduce a characteristic length on the basis of the ratio of volume to pore/grain surface area that can be used for consolidated porous media to calculate the Peclet number.

Abstract: Efficient and robust phase equilibrium computation has become a prerequisite for successful large-scale compositional reservoir simulation. When knowledge of the number of phases is not available, the ideal strategy for phase-split calculation is the use of stability testing. Stability testing not only establishes whether a given state is stable, but also provides good initial guess for phase-split calculation. In this research, we present a general strategy for twoand three-phase split calculations based on reliable stability testing. Our strategy includes the introduction of systematic initialization of stability testing particularly for liquid/liquid and vapor/liquid/liquid equilibria. Powerful features of the strategy are extensively tested by examples including calculation of complicated phase envelopes of hydrocarbon fluids mixed with CO2 in single-, two-, and three-phase regions.

Abstract: The drift velocity of a gas bubble penetrating into a stagnant liquid is investigated experimentally in this paper. It is part of the translational slug velocity. The existing equations for the drift velocity are either developed by using the results of Benjamin (1968) analysis assuming inviscid fluid flow or correlated using air-water data. Effects of surface tension and viscosity usually are neglected. However, the drift velocity is expected to be affected with high oil viscosity. In this study, the work of Gokcal et al. (2009) has been extended for different pipe diameters and viscosity range. The effects of high oil viscosity and pipe diameter on drift velocity for horizontal and upward inclined pipes are investigated. The experiments are performed on a flow loop with a test section 50.8, 76.2 and 152.4 mm ID for inclination angles of 0o to 90o. Water and viscous oil are used as test fluids. New correlation for drift velocity in horizontal pipes of different diameters and liquid viscosities is developed based on experimental data. A new drift velocity model/ approach are proposed for high oil viscosity valid for inclined pipes inclined from horizontal to vertical. The proposed comprehensive closure relationships are expected to improve the performance of two-phase flow models for high viscosity oils in the slug flow regime.

Abstract: This paper (SPE 135357) was accepted for presentation at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 20–22 September 2010, and revised for publication. Original manuscript received for review 2 September 2010. Revised manuscript received for review 27 September 2011. Paper peer approved 10 October 2011. Summary Phase-behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension (IFT) with a specific dead paraffinic crude oil at specific salinities. The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion-screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1,100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus, a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase-behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead-crude corefloods with a live-crude coreflood. A control experiment pressurizing oil with nitrogen at the same condition, 1,100 psi, did not show enhanced relative surfactant solubility in the oil phase.