bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental and Modeling Study of the Transport of Chromium Acetate Solutions Through Carbonate Rocks
Authors: Chen F.. , McCool C.S.. S. , Green D.W.. W. , Willhite G.P.. P. 
Published: March 2010

Summary
Gelled polymer systems are applied to oil reservoirs to reduce water production and to increase sweep efficiencies in recovery processes. A common system consists of hydrolyzed polyacrylamide with a chromium (III) crosslinker. Transport of these chemicals through the reservoir rock is essential for a successful treatment. In carbonate reservoirs, dissolution of the carbonate raises the pH of the gelant to levels where chromium precipitates, robbing the gelant of crosslinker. The transport of chromium acetate solutions through dolomite rock material was studied by injecting various solutions through short cores and measuring Cr, Mg, and Ca concentrations and pH in the effluent. Chromium retention in the cores caused by precipitation was a rate-controlled process. A mathematical model was developed that described convection, dispersion, kinetic reactions of carbonate dissolution and chromium precipitation, and chemical equilibrium for reactions between aqueous components. Experimental data from this work and taken from literature were simulated by the model. One rate equation with one set of parameters described the steady-state values of chromium concentration exiting the cores after the breakthrough of the injected solutions.
A Mimetic Finite Volume Discretization Method for Reservoir Simulation
Authors: Alpak Faruk O. 
Published: March 2010

Summary
Accurate representation of complex reservoir geology using nonorthogonal meshes, upscaling of high-resolution geostatistical reservoir models including cross-flow effects, and strongly heterogeneous anisotropic permeable media such as cross-bedded sands and thin-bedded turbidite channels all individually or in combination give rise to simulation models with full-tensor permeability fields. Such anisotropic multiphase flow problems can be solved accurately on arbitrary nonorthogonal structured and unstructured meshes using the mimetic finite volume method. The discretization operator of the mimetic finite volume method satisfies conservation laws and theorems of vector and tensor calculus on nonorthogonal, smoothly and nonsmoothly distorted, structured and unstructured computational meshes.
In this paper, we demonstrate the formulation of a 3D variant of the mimetic finite volume method for corner-point geometry hexahedral meshes. We also discuss the results and issues associated with the implementation of the mimetic finite volume discretization operator in a parallel, fully implicit reservoir simulator developed using a general compositional formulation. Simulation results are presented for a variety of cases involving flow through geologically complex systems.
Appropriate Choice of Average Pressure for Upscaling Relative Permeability in Dynamic Flow Conditions
Authors: Nordbotten Jan M. , Nogués Juan P. , Celia Michael A. 
Published: March 2010

Summary
A new macroscale pressure definition is investigated through a series of upscaling calculations for two-phase flow in porous media. This definition is taken from previous theoretical work by the authors and aims at correcting for systematic subscale heterogeneities including those generated by nonlinear dependencies on (heterogeneous) saturation distributionsTraditional intrinsic phase- averaged pressure leads to nonmonotone and multivalued upscaled constitutive functions (e.g., discontinuous upscaled-relative-per- meabilities exceeding unity). Using both analytical and numerical calculations, the new macroscale pressure definition is shown to lead to better-behaved upscaled functions.
Alkaline/Surfactant/Polymer Processes: Wide Range of Conditions for Good Recovery
Authors: Liu Shunhua , Li Robert Feng , Miller Clarence A. , Hirasaki George J. 
Published: March 2010

Summary
Design of an alkaline/surfactant/polymer (ASP) process requires knowledge of the amount of soap formed under alkaline conditions from naphthenic acids in the crude oil. We show here for several crude oils that, when substantial acid is present, the acid number determined by nonaqueous-phase titration is approximately twice that found by hyamine titration of a highly alkaline aqueous phase used to extract soaps from the crude oil. This acid number by soap extraction should provide a better estimate than nonaqueous-phase titration because the extracted soap interacts with the injected surfactant to form surfactant films and microemulsion droplets during an ASP process.
In a previous paper (Liu et al. 2008), an unusually wide range of salinities of ultralow oil/water interfacial tensions (IFTs) was found for one alcohol-free crude-oil/anionic-surfactant system under alkaline conditions where naphthenic soaps were present. Solubilization results indicate that this favorable behavior exists with the same surfactant blend and another crude oil.
In the same paper, a 1D simulator for the ASP process was presented. Here, this ASP simulator has been used for various acid contents, injected-surfactant concentrations, slug sizes, and salinities to show that high recoveries of waterflood residual oil (&gt; 90%) can be expected for a wide range of near-optimal (Winsor III) and underoptimum (Winsor I) conditions for a constant-salinity process, even with relatively small slug sizes. A key factor leading to this good performance is development of a gradient in soap/surfactant ratio, which ensures that a displacement front with ultralow IFT forms and propagates through the formation. Similar high recoveries can be attained for certain Winsor II conditions but only for much larger slug sizes, owing to the tendency for surfactant to partition into the oil phase and become retarded. Large dispersion, such as might be expected for field conditions, can reduce recovery significantly for small surfactant slugs even for near-optimal and underoptimum conditions. However, this problem can be overcome by injecting the slug or drive at salinities below reservoir salinity, thereby creating a salinity gradient.
Effect of HCl Acid and Brines on Water-Swelling Packers
Authors: Al-Yami A.S.. S. , Nasr-El-Din H.A.. A. , Al-Humaidi A.S.. S. , Al-Arfaj M.K.. K. , Al-Saleh S.H.. H. 
Published: March 2010

Summary
Achieving successful zonal isolation during well completion is critical to minimize early water production. Currently, cementing is the only method used in Saudi fields to provide zonal isolation. However, in horizontal sections, cementing becomes a challenge and excessive water production can occur because of channeling. Another method for zonal isolation is to use a rubber elastomer bonded onto a base pipe. The rubber swells in water and provides a seal between the base pipe and the open hole.
This paper will outline the step-by-step qualification testing that was carried out in Saudi Aramco facilities in an attempt to improve zonal isolation in horizontal and multilaterals wells.
In this study, we present laboratory evaluation of elastomers at 190°F using brines of different ionic strengths and pH values. The evaluation involved examining the effect of salinity and pH on elastomer swelling rate. Also, the study investigated the effect of 15 wt% hydrochloric acid (HCl) on swollen elastomers and whether the exposure to water after acid would restore their sizes. To the best of the authors' knowledge, no previous work has been performed to examine the impact of these factors on the swollen packers.
The elastomer bonded onto pipes was tested in autoclaves. The pressure drop across the pipes was measured as a function of time. The influences of pH and divalent cations on water-swelling packers were investigated using elastomer samples. Swelling was related to fluid characteristics.
Some water-swelling packers withstood pressures up to 5,000 psi at 190°F after placing the elastomers in brines with salinities up to 200,000 mg/L. However, the swollen elastomers shrank in 15 wt% HCl. A calcium chloride (CaCl2) completion fluid, a common fluid used in Saudi Aramco fields, at 72 lb/ft3 (pcf) failed to swell the elastomers. Re-exposure of shrunken coupons to water did not restore their initial swollen volume before acid soaking. This paper discusses the advantages and limitations of water-swelling elastomers and gives recommendations for successful field applications.
Simplified Modeling of Turbidite Channel Reservoirs
Authors: Alpak Faruk O. , Barton Mark D. , van der Vlugt Frans F. , Pirmez Carlos , Prather Bradford E. , Tennant Steven H. 
Published: March 2010

Summary
Effective properties can represent fine-scale geologic heterogeneities in simple full-field reservoir models without having to model them explicitly. A comprehensive simulation study tests the sensitivity of dynamic connectivity in turbidite channel reservoirs to a large number of stratigraphic and engineering parameters. Simulations performed using geologically realistic sector models at multiple levels of stratigraphic resolution show that dynamic connectivity is governed by large-scale architectural parameters, such as meander-belt size, net-to-gross ratio, degree of depositional-storey amalgamation, and stratigraphic parameters that describe the shale architecture at multiple scales (e.g., shale-drape coverage and shale-drape frequency of occurrence).
We demonstrate how to rapidly generate effective properties at multiple geologic scales, incorporating the effect of channel architecture and reservoir connectivity into simple dynamic models. Use of simple dynamic models in conjunction with effective properties, principally geologically based pseudorelative permeabilities, accelerates the simulation workflow significantly. We show that a statistical distribution of the recovery factor (RF) can be produced within hours instead of days by the combined use of Monte Carlo simulation and a simple dynamic model with effective properties. Recovery factors estimated with our simplified modeling method agree well with observed RF distributions of turbidite channel reservoirs with significant production history.
Measurement of Nonwetting-Phase Trapping in Sandpacks
Authors: Pentland Christopher H. , Itsekiri Endurance , Al Mansoori Saleh K. , Iglauer Stefan , Bijeljic Branko , Blunt Martin J. 
Published: March 2010

Summary
We measure the trapped nonwetting-phase saturation as a function of initial saturation in sandpacks. The application of the work is for carbon dioxide (CO2) storage in aquifers, where capillary trapping is a rapid and effective mechanism to render the injected fluid immobile: The CO2 is injected into the formation followed by chase-brine injection or natural groundwater flow that displaces and traps it. Current models to predict the amount of trapping are based on experiments in consolidated media; while CO2 is likely to be injected at depths greater than approximately 800 m to render it supercritical, it may be injected into formations that tend to have a higher porosity and permeability than deep oilfield rocks. We use analog fluids—water and refined oil—at ambient conditions. The initial conditions are established by injecting oil into vertical or horizontal sandpacks 0.6 m long at different flow rates and then allowing the oil to migrate under gravity. The packs are then flooded with water. The columns are sliced, and the residual saturation is measured with great accuracy and sensitivity by gas chromatography (GC). This method allows low saturations to be measured reliably. The trapped saturation initially rises linearly with initial saturation to a value of approximately 0.13, followed by a constant residual as the initial saturation increases further. This behavior is not predicted by the traditional Land (1968) model but is physically consistent with poorly consolidated media where most of the larger pores can be invaded easily at relatively low saturation and there is, overall, relatively little trapping. The best match to our experimental data is achieved with the Aissaoui (1983) and the Spiteri et al. (2008) trapping models.
Use of X-Ray CT to Measure Pore Volume Compressibility of Shaybah Carbonates
Authors: Siddiqui Shameem , Funk James J. , Al-Tahini Ashraf M. 
Published: March 2010

SummaryThe Lower Cretaceous Shu'aiba formation (Shaybah field) in southeastern Saudi Arabia is a heterogeneous carbonate formation with various facies because of diagenetic alteration of the original rock fabric. Preliminary laboratory rock-mechanics studies indicated that the Shu'aiba carbonates are mechanically weak, with the majority of the rocks tested yielding very low strength values (less than 3,000 psi) when compared to samples from other carbonate reservoirs (Salamy and Finkbeiner 2002). On the basis of laboratory-derived rock-strength data from triaxial tests, the formation appears to behave in a plastic manner that strengthens the wellbore. To understand the stress behavior of the Shaybah rocks better, a set of pore volume compressibility tests was conducted in which the changes taking place within the samples were observed and quantified using an X-ray computerized-tomography (CT) scanner. A new technique involving dual-energy CT scanning was used to obtain the pore volume compressibility values, which were compared against the conventional triaxial-cell-generated data and published results by Harari et al. (1995) on cores taken from the same reservoir. Although the magnitude of the pore volume compressibility was the same between different setups, visual data showed some interesting behavior of the Shaybah cores including movement of grains in an irreversible manner even for a relatively low imposed effective stress of 2,000 psi. Some of the advantages of the new CT-based analysis technique include the generation of multiple pore volume compressibility curves from the same plug (a band of data, each at a different slice location), the "visualization" of the changes, the possibility of using either hydrostatic or triaxial cells to make the test more case-specific, and the possibility of measuring permeability under different stress conditions before, during, and after the test.
Modeling Foam Displacement with the Local-Equilibrium Approximation: Theory and Experimental Verification
Authors: Chen Q.. , Gerritsen M.G.. G. , Kovscek A.R.. R. 
Published: March 2010

Summary
The gas-mobility-control aspects of foamed gas make it highly applicable for improved oil recovery. Gas-bubble size, often referred to as foam texture, determines gas-flow behavior in porous media. A population-balance model has been developed previously for modeling foam texture and flow in porous media. The model incorporates pore-level mechanisms of foam-bubble generation, coalescence, and transport. Here, we propose a simplified foam model to reduce computational costs. The formulation is based on the assumption of local equilibrium of foam generation and coalescence and is applicable to high- and low-quality foams. The proposed foam model is compatible with a standard reservoir simulator. It provides a potentially useful, efficient tool to predict foam flows accurately at the field scale for designing and managing foamed-gas applications.
There are three main contributions of this paper. First, foam-displacement experiments in a linear sandstone core are conducted. A visualization cell is employed to measure the effluent foam-bubble sizes for a transient flow as well as to estimate the in-situ foam-bubble sizes along the length of the core during steady-state flow. These appear to be the first measurements of foam-bubble texture in the entrance region of a core. Additionally, the evolution of aqueous-phase saturation is monitored using X-ray computed tomography (CT), and the pressure profile is measured by a series of pressure taps. Second, the population-balance representation of foam generation by gas-bubble snap-off is modified to extend the capability of the population-balance approach to predict foam-flow behaviors in both the so-called high-quality and low-quality regimes. Third, a simplified population-balance model is developed and implemented with the local-equilibrium approximation. Good agreement is found between the experimental results and the predictions of the simplified model, with a minor mismatch in the entrance region.
An Approach for Characterization and Lumping of Plus Fractions of Heavy Oil
Authors: Rodriguez I.. , Hamouda A.A.. A. 
Published: March 2010

Summary
Heavy-oil fluids contain large concentrations of high-molecular-weight components, including a large content of the plus fractions, such as C7+.
Different approaches have been developed to characterize the petroleum plus fractions to improve prediction of the pseudocomponents properties by equations of state (EOSs).
A method is developed in this work to split the plus fraction into single carbon numbers (SCN), generating the mole fraction and the respective molecular weight. The developed method is based on the relationships between three-parameter gamma (TPG) distribution, experimental mole fraction, molecular weight, and SCN data obtained from the literature and industrial contacts. TPG is used to fit the trend of the compositional analysis. The characterized mole distribution as a function of SCNs is generated by integrating the TPG between the limiting molecular weights (LMw). The limiting molecular weights are determined simultaneously during the integration process by fitting the characterized and experimental mole fractions.
The developed method is easy to use. In addition, the approach is not dependent on the assumption that only normal carbon numbers exist in the composition resulting on fixed molecular weights for each single carbon number.
There are several correlations generated to predict physicochemical properties as a function of SCNs. Those correlations have been originally developed to work with light oil. Our approach is combined with some of the correlations and is tested for heavy-oil samples to identify the ranges in which they can be applied. Two lumping schemes are used to group the SCNs into pseudocomponents. The properties for each pseudo-component in this work are used to predict pressure/volume/temperature (PVT) data, constant volume depletion, using the Peng-Robinson EOS (PR-EOS), and the PVTP™ commercial simulator.
An Innovative Methodology for Designing Cement-Sheath Integrity Exposed to Steam Stimulation
Authors: Garnier A.. , Saint-Marc J.. , Bois A.-P.. -P. , Kermanac'h Y.. 
Published: March 2010

Summary
Heavy-oil production is one of the new challenges the oil and gas industry faces today, with trillions of barrels of reserves around the planet. To extract heavy oils, the viscosity has to be reduced to gain mobility and start the oil flowing. Of all the possible techniques, steam stimulation is, today, the most promising.
Steam is injected through the well down to the reservoir to warm it to a temperature of up to 250°C, inducing extreme thermal stresses in the well (especially when the temperature gradient through its components is maximum, as it is during initial steam injection or during workover when the well has to be quickly cooled down and heated up again to restart production rapidly).
To avoid zonal-isolation failure and steam release at the surface, new rules need to be considered in designing the barriers of a well exposed to steam stimulation, especially in very shallow fields. Where conventional rules may be applied for casing design, pioneering rules should be considered for designing the cement sheath.
This paper presents an innovative methodology for designing robust cement sheaths in very shallow conditions. First, stresses in the field are assessed with a rock-mechanics simulation. Then, the thermal gradient in the well components during the heating process is evaluated with a thermal simulation of the well. Both results are entered into Total's dedicated software to determine the mechanical properties the cement should have to withstand the thermal stresses. Different cement systems from service companies are evaluated in a cell, reproducing the field conditions to validate the simulation results.
This methodology was applied successfully to the Joslyn field wells, in Canada, where a resilient cement system with low Young's modulus and high tensile strength was selected and pumped. Because the results were positive, the methodology has been extended to other Total fields around the world where steam simulation is being considered.
A New Algorithm for Rachford-Rice for Multiphase Compositional Simulation
Authors: Okuno R.. , Johns R.T.. T. , Sepehrnoori K.. 
Published: March 2010

Summary
Flash calculations for use in compositional simulation are more difficult and time-consuming as the number of equilibrium phases increases beyond two. Because of its complexity, many simulators do not even attempt to incorporate three or more hydrocarbon phases, even though such cases are important in many low-temperature gasfloods or for high temperatures where hydrocarbons can partition into water. Multiphase flash algorithms typically use successive substitution (SS) followed by Newton's method. For NP-phase flash calculations, (NP–1) Rachford-Rice (RR) equations are solved in every iteration step in SS and, depending on the choice of independent variables, in Newton's method. Solution of RR equations determines both compositions and amounts of phases for a fixed overall composition and set of K-values. A robust algorithm for RR is critical to obtain convergence in multiphase compositional simulation and has not been satisfactorily developed, unlike the traditional two-phase flash. In this paper, we develop an algorithm for RR equations for multiphase compositional simulation that is guaranteed to converge to the correct solution independent of the number of phases for both positive and negative flash calculations.
We derive a function whose gradient vector consists of RR equations. This correct solution to the RR equations is formulated as a minimization of the nonmonotonic convex function using the independent variables of (NP–1) phase mole fractions. The key to obtaining a robust algorithm is that we specify nonnegative constraints for the resulting equilibrium phase compositions, which are described by a very small region with no poles. The minimization uses Newton's direction with a line-search technique to exhibit superlinear convergence. We show a case in which a previously developed method cannot converge while our algorithm rapidly converges in a few iterations. We implement the algorithm both in a standalone flash code and in UTCOMP (Chang et al. 1990), a multiphase compositional simulator, and show that the algorithm is guaranteed to converge when a multiphase region exists as indicated by stability analysis.