bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pore Size Distribution of Porous Media and Displacement Experiments with Miscible Liquids
Authors: Klinkenberg L.J. 
Published: December 2007

Abstract
It is pointed out that the current concept of pore size distribution is not unequivocally defined and that different methods aiming at a determination of such a distribution therefore do not lead to the same results.
A pore size distribution should not be based on the idea that a core should, under all circumstances, behave as a bundle of straight non-interconnected capillaries of the same pore size distribution. This is illustrated by calculations and experiments on the displacement of miscible liquids.

Introduction
The introduction of the concept of pore size distribution has been an attempt to characterize the intricate geometry of the flow channels in porous media. As pores in a porous medium are interconnected it is impossible to describe exactly what is meant by a "pore" and, therefore, the term pore size distribution requires further amplification.
In the visual method for the determination of pore size distribution "the pore" is considered to be the hole between the grains as observed on thin sections or on a polished surface of the rock under a microscope.
In all other presently known methods, a displacement process is studied and it is ascertained what assemblage of straight cylindrical capillaries would show the same behavior. The distribution of the capillary diameters of this assemblage is said to represent the size distribution of the pores of the actual porous medium.
From the foregoing it is already apparent that it is useless to try to decide which process or which method of investigation leads to a "correct" pore size distribution. To illustrate this further a displacement process in which a fluid is displaced by another miscible with it will be discussed and the results will be interpreted in terms of a pore size distribution.

Displacement Experiments With Miscible Liquids of Nearly Identical Viscosity and Density

Interpretation in the Form of a Pore Size Distribution
If distilled water is displaced from a homogeneous unconsolidated sand pack by, for instance, a dilute solution of NaCl, the breakthrough recovery i.e., the amount of distilled water produced at the moment the first trace of NaCl can be detected in the effluent water, is between 95 and 100 per cent of the pore volume of the pack.
Fast, Approximate Solutions for 1D Multicomponent Gas-Injection Problems
Authors: Jessen Kristian , Wang Yun , Ermakov Pavel , Zhu Jichun , Orr Franklin M. 
Published: December 2007

Summary
This paper presents a new approach for constructing approximate analytical solutions for 1D, multicomponent gas displacement problems. The solution to mass conservation equations governing 1D dispersion-free flow in which components partition between two equilibrium phases is controlled by the geometry of key tie lines. It has previously been proven that for systems with an arbitrary number of components, the key tie lines can be approximated quite accurately by a sequence of intersecting tie lines. As a result, analytical solutions can be constructed efficiently for problems with constant initial and injection compositions (Riemann problems). For fully self-sharpening systems, in which all key tie lines are connected by shocks, the analytical solutions obtained are rigorously accurate, while for systems in which some key tie lines are connected by spreading waves, the analytical solutions are approximations, but accurate ones. Detailed comparison between analytical solutions with both coarse- and fine-grid compositional simulations indicates that even for systems with nontie-line rarefactions, approximate analytical solutions predict composition profiles far more accurately than coarse-grid numerical simulations. Because of the generality of the new approach, approximate analytical solutions can be obtained for any system having a phase behavior that can be modeled by an equation of state. The construction of approximate analytical solutions is shown to be orders of magnitude faster than the comparable finite difference compositional simulation. Therefore, the new approach is valuable in situations requiring fast compositional solutions to Riemann problems are required.
Scaling of Cocurrent and Countercurrent Capillary Imbibition for Surfactant and Polymer Injection in Naturally Fractured Reservoirs
Authors: Babadagli T. 
Published: December 2007

Summary
This study tests the existing capillary imbibition scaling formulations in literature and proposes modifications to them for surfactant- and polymer-injection applications. Laboratory tests were performed using Berea Sandstone cores with different shapes, sizes, and boundary conditions. Kerosene, engine oil, mineral oil, and crude oil were selected as the oleic phase. Brine and two different concentrations of surfactant and polymer solutions were the aqueous phases. The capillary imbibition recovery curves were then used to test the existing scaling formulations.
It was observed that the scaling groups were applicable with certain modifications to the cocurrent flow of surfactant and polymer solution-oil pairs as well as the brine-oil cases. In case of cocurrent flow, the gravity forces dominate recovery for low-interfacial tension (IFT) experiments, and modification to the gravity-scaling group for the boundary conditions is required. For countercurrent flow, however, the scaling groups were observed to be inapplicable even after the modifications.
Support-Operators Method in the Identification of Permeability Tensor Orientation
Authors: Silin Dmitriy B. , Patzek Tad W. 
Published: December 2007

SummaryThe dependence of rock permeability on direction, or permeability anisotropy, is confirmed by numerous field examples. Therefore, the ability to carry out a numerical simulation of an anisotropic reservoir is very important. The support-operators method provides a conservative discretization scheme, allowing one to solve nonisotropic problems on a grid of practically arbitrary structure. Moreover, a discretization designed with the supportoperators method provides a natural and convenient way of deriving and solving the adjoint system for evaluation of the gradient and second-order differential in inverse problems.After a theoretical introduction into the support-operators method, we consider an illustrative parameter-identification problem. More specifically, we evaluate the orientation angle of a nonisotropic permeability tensor in a horizontal reservoir. We assume that the principal permeabilities near a cored or otherwise logged well are already known. To accomplish this task, we need pressure measurements in monitoring wells. We consider both rectangular and curvilinear grids. In either case, the orientation angle has been recovered with a high accuracy.
Applications of 3D Streamline Simulation To Assist History Matching
Authors: Milliken W. J. , Emanuel A. S. , Chakravarty A. 
Published: December 2007

Summary
The use of 3D streamline methodologies as an alternative to finite-difference (FD) simulation has become more common in the oil industry during the past few years. When the assumptions for its application are satisfied, results from streamline simulation compare very well with those from FD and typically require less than 10% of the central processing unit (CPU) resources. The speed of 3D streamline simulation (3DSM) lends itself not just to simulation, but also to other components of the reservoir simulation work process. This characteristic is particularly true of history matching.
History matching is frequently the most tedious and time-consuming part of a reservoir simulation study. In this paper, we describe a novel method that uses 3D streamline paths to assist in history matching either 3D streamline or FD models. We designated this technique Assisted History Matching (AHM) to distinguish it from automated history-matching techniques. In this manuscript, we describe this technique and its application to three reservoir simulation studies. The example models range in size from 105 to 106 gridblocks and contain as many as several hundred wells. These applications have led to refinements of the AHM methodology, the incorporation of several new algorithms, and some insights into the processes typically employed in history matching.
Mechanisms of Mudcake Removal During Flowback
Authors: Zain Zulkeffeli M. , Sharma Mukul M 
Published: December 2007

SummaryExternal filter cakes are used to minimize fluid loss and solids invasion to a formation from drilling and completion fluids. Subsequently, the cake must be removed to increase the flow area and minimize skins, especially for openhole and gravel-packed completions in horizontal and deviated wells. Experimental data is presented to show that the pressure required to initiate flow into the wellbore after building up a filter cake is affected by rock permeability; mud properties, such as particle size and cake yield strength; flowback velocity; and overbalance pressure.Mudcake liftoff tests, mud particle size, and rock pore-throat size distribution measurements were performed to understand the factors that contribute to cake removal. The mechanisms that control filter-cake removal are discussed.In this study, it is clearly shown that the flow-initiation pressure during flowback is controlled by solids and filtrate invasion (i.e., internal formation damage rather than by the external mudcake). Flow-initiation pressures show a minimum with increasing rock permeability caused by two competing effects. Larger pore sizes result in smaller flow-initiation pressures, ΔPfi; however, more solids invasion increases ΔPfi. Higher overbalance pressures also increase the internal formation damage and flow-initiation pressure. A simple model to calculate the flow-initiation pressure during flowback is proposed. The model correctly predicts the experimentally observed trends with rock permeability, mud particle size distribution, extent of solids invasion, and yield strength of the mudcake. The model provides a systematic method for designing fluids with low flow-initiation pressures. It is also shown in this study that low flow-initiation pressures do not imply complete cake removal. Cake removal is primarily controlled by the permeability of the cake and its mechanical properties.
Simplified Graphical Method of Determining Gas Compressibility Factors
Authors: Rice Leon 
Published: December 2007

Introduction
The composite gas compressibility graph was constructed by combining the data from the three graphs originally presented by Standing and Katz. In its original form, the following method was used to solve for compressibility factors.Graphically determine the pseudo-critical pressure and temperature for the gas in question.Calculate the pseudo-reduced pressure and temperature.Graphically solve for the compressibility (Z) factor.
By combining this original data, it was possible to construct a single composite graph which eliminates all intermediate calculations when solving for compressibility factors.

Basic Data and Equations
Fig. 1 is a plot of the pseudo-critical temperature vs specific gravity of natural gases, as originally presented by Standing and Katz. For a given specific gravity, the actual temperature in degrees Fahrenheit is related to the reduced temperature as follows.
or
.............................(1)
Fig. 1 also includes a plot of pseudo-critical pressure vs gas gravity. For all practical purposes, this can be considered a straight line defined by
.............................(2)
and the reduced pressure is, by definition,
............................(3)
or
............................(4)

Construction of Composite Compressibility Chart
The basic premise on which the chart was constructed is that, for any given pseudo-reduced pressure and temperature, all gases have the same compressibility (Z) factor regardless of gas gravity. To satisfy this condition, a basic graph was constructed with the left-hand portion being a group of straight-line plots of actual temperature vs pseudo-reduced temperature for various gas gravities ranging from 0.56 to 1.00 in 0.02 increments. The right-hand portion was then constructed as three straight-line plots of actual pressure vs pseudo-reduced pressure for gas gravities of 0.60, 0.70 and 1.00. Using Standing and Katz's "Compressibility of Natural Gases" graph, the basic graph was then completed by plotting and connecting equal values of Z, using a 0.70 gravity as a base.
JPT
P. 1081^
Residual Gas Saturation Revisited
Authors: Kantzas Apostolos , Ding Minghua , Lee Jong 
Published: December 2007

Summary
The determination of residual gas saturation in gas reservoirs from long spontaneous and forced-imbibition tests is addressed in this paper. It is customarily assumed that when a gas reservoir is overlaying an aquifer, water will imbibe into the gas-saturated zone with the onset of gas production. The process of gas displacement by water will lead to forced imbibition in areas of high drawdown and spontaneous imbibition in areas of low drawdown. It is further assumed that in the bulk of the reservoir, spontaneous imbibition will prevail and the reservoir will be water-wet. A final assumption is that the gas behaves as an incompressible fluid. All these assumptions are challenged in this paper. A series of experiments is presented in which it is demonstrated that the residual gas saturation obtained by a short imbibition test is not necessarily the correct residual gas saturation. Imbibition tests by different methods yield very different results, while saturation history and core cleaning also seem to have a strong effect on the determination of residual gas saturation. It was found, in some cases, that the residual gas by spontaneous imbibition was unreasonably high. This was attributed to weak wetting conditions of the core (no water pull by imbibition). It is expected that this work will shed some new light on an old, but not-so-well-understood, topic.
Well Index in Reservoir Simulation for Slanted and Slightly Curved Wells in 3D Grids
Authors: Aavatsmark I. , Klausen R. A. 
Published: December 2007

Summary
A new, accurate method for computing the well index (WI) for a well that is oriented in an arbitrary direction in a 3D grid is presented. The method is simple and seminumerical and takes well direction and neighboring gridblocks into account. It is assumed that the medium is homogeneous. The method can be applied for any grid or discretization. However, only Cartesian grids with a seven-point stencil are used here. Properties of the seminumerical WI are investigated for both synthetic and field examples. The investigated properties are convergence rate and dependency on well direction, well location, grid geometry, and anisotropy. The new method shows the importance of taking the neighboring gridblocks into account.
A Coupled Model To Predict Interformation Flow Through an Abandoned Well
Authors: Striz Elise A. , Wiggins Michael L. 
Published: December 2007

Summary
This paper presents a novel approach for predicting flow between two formations coupled by an abandoned well. A steady-state, abandoned-well model is derived analytically and applied with a "series of steady states" to create the transient flow response. The model is verified by comparison to the results of a transient, analytical, interformation well model for a single injector given by Avci. This model is the first to include true pressure losses in the abandoned wellbore calculated from established equations for turbulent or laminar pipe flow, plugs, and a casing perforation. The model can also predict flow behind pipe through an open or plugged annulus or a fracture in the annular plug. Finally, the model is the first to incorporate the effect of pressure variations on well flow caused by production or injection in the overlying formation.
Application of the model in a single-phase simulation demonstrates the impact of location and condition, rock and fluid properties, initial pressures, and well operations in the coupled formations on the abandoned-well flow. Evolving pressure distributions in the coupled formations may move flow up or down the hole. Pressure losses in the wellbore or behind pipe (through plugs) are shown to preclude flow. The model is also applied to a field case to demonstrate its use as a prediction tool for abandoned-well flow. As opposed to the limited analytical solutions or complex numerical-simulation methods currently available, the new abandoned-well model provides a simple means to determine flow for realistic field conditions.
A New NMR Method of Fluid Characterization in Reservoir Rocks: Experimental Confirmation and Simulation Results
Authors: Freedman R. , Lo S. , Flaum M. , Hirasaki G.J. , Matteson A. , Sezginer A. 
Published: December 2007

SummaryThis paper introduces a new magnetic resonance fluid (MRF) characterization method. The MRF method is based on two key ingredients—a new microscopic constituent viscosity model (CVM) and a new multifluid relaxation model. The CVM provides a link between nuclear magnetic resonance (NMR) relaxation times and molecular diffusion coefficients in hydrocarbon mixtures such as crude oils. The multifluid relaxation model accounts for the T2 decay of spin-echo signals that arises from intrinsic spin-spin interactions, surface relaxation, and attenuation due to molecular diffusion of fluid molecules in a magnetic field gradient. The MRF method exploits the fact that the molecular diffusion coefficients of brine, oil, and gas molecules typically have values that are well separated from one another. Thus, the diffusion attenuation of a suite of measured NMR signals contains sufficient information to allow differentiation of brine, oil, and gas. The method involves the simultaneous inversion of a suite of spin-echo measurements with the new MRF multifluid relaxation model.The application of the MRF method to magnetic resonance logging data can provide a detailed formation evaluation. The information provided includes total porosity, bulk volume of irreducible water, brine and hydrocarbon saturation, hydrocarbon-corrected permeability, and oil viscosity.This paper discusses the theory underlying the CVM and validates the model by testing its predictions on hydrocarbon mixtures including live and dead crude oils. The robustness and accuracy of the multifluid inversion is demonstrated by a Monte Carlo simulation of a model carbonate rock that contains brine, oil, gas, and oil-base mud filtrate (OBMF). The MRF method is applied to suites of spin-echo measurements acquired in the laboratory on partially saturated rocks and shown to provide accurate fluid saturation and oil viscosity estimates.Since the completion of this work, field test results have shown that the MRF method provides a powerful and unique new formation evaluation tool.
Openhole Stability and Sanding Predictions by 3D Extrapolation from Hole-Collapse Tests
Authors: Ewy R. T. , Ray P. , Bovberg C. A. , Norman P. D. , Goodman H. E. 
Published: December 2007

Summary
Wellbore failure is best simulated in the laboratory by subjecting a model hole to simulated in-situ stresses. A jacketed, thick-walled, hollow cylinder is subjected to increasing pressure on the outer surface until hole collapse occurs. This provides a direct measure of the stress required to cause hole failure in that particular formation interval. To extrapolate to the downhole situation, a 3D analytic model is presented that is applicable to both stability and sanding of open wellbores. This model uses a Modified Lade failure criterion that properly accounts for the effect of the intermediate principal stress on rock failure. The Modified Lade rock-strength parameters are extracted from the measured hole-collapse strength (HCS) and are then combined with the in-situ stresses and formation pore pressure to determine the required mud weight for stability while drilling and the allowable drawdown pressure for prevention of sand production.
Restoration of Uranium In-Situ Leaching Sites
Authors: Hill A. D. , Silberberg I. H. , Walsh M. P. , Breland W. M. , Humenick M. J. , Schechter R. S. 
Published: December 2007

Abstract
In recent years in-situ leach mining has emerged as a new technology for the recovery of uranium from strata that cannot be mined economically by other means. Because the ore bodies lie within groundwater aquifers, a significant determinant in the process' viability is the requirement that such aquifers be protected from contamination. Since ammonia is one of the constituents of the leach solutions now being field tested, one environmental problem to be resolved is the removal of ammonia at the end of mining. A second related question is the fate of the ammonia that is not removed by the restoration procedure.
This paper considers the displacement and migration of ammonium cations in a flowing electrolyte with concomitant ion exchange. The ion exchange is an important feature since, during the solution mining phase, ammonium cations adsorb onto the mineral exchange sites and must be removed from these sites. A mathematical model is used to simulate this process, and the model is tested against the results of laboratory experiments. It is found that the simulations are adequate if an appropriate selection of parameters is made.
The model then is used to simulate restoration procedures and to determine the rate of migration of unrecovered ammonium in the groundwater. It is concluded that ammonium removal can be accomplished best using high concentrations of a cation that is exchanged selectively relative to ammonium cation.