bluuebunny/crossref_metadata_2025_split huggingface dataset:
Compositional Parametrization for Multi-phase Flow in Porous Media
Authors: Voskov D. V. , Tchelepi H. A. 
Published: April 2008

Abstract
In this work we generalize the Compositional Space Parameterization (CSP) approach, which was originally developed for two-phase compositional problems. The extension is valid for an arbitrary number of phases, regardless of the number of components. The compositional space is considered to be a high-dimensional simplex, and the phase behavior is represented using a low dimensional tie-simplex parameterization. For example, in the three-phase case, the space is parameterized using tie-triangles and tie-lines for three- and two-phase regions, respectively. This parameterization improves the accuracy of the phase behavior representation as well as the efficiency of various types of computation for compositional flow. One application of this approach is to speed up standard multi-component phase behavior computations. For general purpose compositional simulation, Compositional Space Adaptive Tabulation (CSAT) can be used to avoid most of the redundant Equation of State calculations. A Supercritical State Criteria algorithm, which is based on adaptive tabulation of the critical tie-simplex, is used to handle the super-critical region. Results of several challenging tests of practical interest indicate that the CSAT strategy is quite robust, and that it leads to an order of magnitude gain in computational efficiency. This strategy is valid for systems with any number of phases and components. Another application area for our CSP framework is to speed up standard thermodynamic computations for complex mixtures. For such systems, the methodology is generalized in terms of a multi-phase tie-simplex description, where one finds the closest tie-simplex and uses it as an initial guess for the computations. For better tie-simplex estimation, interpolation based on triangulation is used. For cases with wide variation in pressure and temperature, linear interpolation of the tie-simplex for these variables is adequate. The methodology is demonstrated using several challenging examples.
Upscaling of Capillary Trapping Under Gravity Override: Application to CO2 Sequestration in Aquifers
Authors: Juanes R. , MacMinn C. W. 
Published: April 2008

Abstract
We present a sharp-interface mathematical model of CO2 migration in saline aquifers, which accounts for gravity override and capillary trapping. The major differences with respect to previous investigations is that we model the shape of the plume during the injection period, we account for regional groundwater flow during the post-injection period, and we introduce rigorously the reduction in water mobility due to trapping of the CO2.
The model leads to a nonlinear advection-diffusion equation, in which the diffusive term is due to buoyancy forces, not physical diffusion. The three key dimensionless groups are the mobility ratio between the injected and initial fluids (M), the gravity number (Ng), and a newly defined trapping coefficient (Г). For the case of interest in geological CO2 storage, in which the mobility ratio is much smaller than 1, the solution is largely insensitive to the value of the gravity number. Under these conditions, the mathematical model can be simplified to a hyperbolic model.
We present a complete analytical solution to the hyperbolic model that includes the injection, early post-injection, and late post-injection periods. Despite the fact that the solution involves the interaction of a sharp imbibition front with a drainage rarefaction front, it admits a closed-form expression. The main outcome of the analytical developments presented here is a formula that predicts the ultimate footprint on the CO2 plume, and the time scale required for complete trapping. Both quantities depend strongly on the shape of the plume at the end of the injection period, which must—therefore—be modeled.
A second application of the analytical solution is a formulation for upscaling the capillary trapping coefficient from the laboratory scale to the basin scale. Explicit expressions are given for the megascopic and gridblock-effective trapping coefficients, as functions of the local trapping coefficient, the mobility ratio, and the grid resolution. Although the expressions derived are based on a one-dimensional sharp-interface model, we anticipate that they will have broader applicability to injection scenarios with unfavorable mobility ratio and dominated by gravity override.
In Situ Phase Pressures and Fluid Saturation Dynamics Measured in Waterfloods at Various Wettability Conditions
Authors: Brautaset A. , Ersland G. , Graue A. 
Published: April 2008

Abstract
During waterfloods of a total of six outcrop chalk core plug samples prepared at various wettabilities, simultaneous local pressures and in situ fluid saturation from Magnetic Resonance Imaging (MRI) intensities were measured. Complementary use of high spatial resolution fluid saturation imaging and phase pressure measurements allowed calculations of the relative permeability to water and the dynamic capillary pressure curves for the imbibition process. One objective was to validate the theory for relative permeability calculations based on data from the fluid phase pressures measured separately using semi-permeable discs and local in situ fluid saturation measurements. A second objective was to identify fluid saturation changes due to spontaneous imbibition and viscous displacement, respectively, to determine the local recovery mechanism and allowing local recovery factors and in situ Amott-Harvey indices to be measured.
The analysis of the experimental data from three of the core samples shows that the presented theory only applies for the saturation interval when the pressures are measured in the same phase. A new and improved experimental setup is therefore introduced for the remaining three cores in order to measure each of the dynamic phase pressure gradients separately using semi-permeable discs located at fixed pressure ports. The obtained data contributes to improved description and understanding of multi-phase fluid flow in porous media, including in situ measurements of relative permeabilities, capillary pressure curves, wettability distribution and local oil recovery mechanisms.
Mechanistic Interpretation and Utilization of Viscoelastic Behavior of Polymer Solutions for Improved Polymer-Flood Efficiency
Authors: Delshad Mojdeh , Kim Do Hoon , Magbagbeola Oluwaseun A. , Huh Chun , Pope Gary A. , Tarahhom Farhad 
Published: April 2008

Abstract
There are increasing laboratory and field evidences that the viscoelastic characteristics of polymer solutions help improve polymer-flood efficiency. Extensive rheological measurements and laboratory corefloods with partially hydrolyzed polyacrylamide polymers with very high molecular weight were carried out to delineate the role of their viscoelastic behavior in improving oil recovery from polymer flood. Different polymer solution's elastic contribution is modeled in the polymer's apparent viscosity in porous media, which is implemented in UTCHEM simulator for quantification of improved reservoir sweep.
As the application range of polymer flood is extended to recover more viscous oils with use of polymers at high concentrations and with very high molecular weights, a mechanistic understanding of polymer rheology in porous media and accurate numerical modeling are essential for successful field implementation of polymer flood.
Oscillatory and shear viscosity measurements and polymer flow coreflood experiments were carried out for different shear rates (and flow velocities and permeabilities in core), polymer concentrations, and molecular weights. The polymer's shear-thickening characteristic was correlated with the Deborah number via its molecular relaxation time, which is in turn determined from the rheological data. An apparent viscosity model that accounts for both shear-thinning and shear-thickening behavior of polymer in porous media was developed, which fit the laboratory data well. The model was then implemented in a compositional chemical flooding simulator and successfully history-matched published coreflood oil recovery experiment.
Through systematic rheological measurements and corefloods, and their use in the apparent viscosity model for simulation, the elastic contribution of different polymers in improving polymer-flood efficiency is quantified. Specifically, a polymer solution's shear-thickening behavior is characterized in terms of the molecular relaxation time determined from bulk rheology measurements.
Optimal Rate Control Under Geologic Uncertainty
Authors: Alhuthali Ahmed H. , Datta-Gupta Akhil , Yuen Bevan , Fontanilla Jerry P. 
Published: April 2008

Abstract
Waterflood optimization via rate control is receiving increased interest because of rapid developments in the smart well completions and i-field technology. The use of inflow control valves (ICV) allows us to optimize the production/injection rates of various segments along the wellbore, thereby maximizing sweep efficiency and delaying water breakthrough. A major challenge for practical field implementation of this technology is dealing with geologic uncertainty. In practice, the reservoir geology is known only in a probabilistic sense; hence, the optimization of smart wells should be carried out in a stochastic framework to account for geologic uncertainty.
We propose a practical and efficient approach for computing optimal injection and production rates accounting for geological uncertainty. The approach relies on equalizing arrival time of the waterfront at all producers using multiple geologic realizations. The main objective is to improve sweep efficiency and thereby improve oil production and recovery. We account for geologic uncertainty using two optimization schemes. The first one is to formulate the objective function in a stochastic form which relies on a combination of expected value and standard deviation combined with a risk attitude coefficient. The second one is to minimize the worst case scenario using a min-max problem formulation. The optimization is performed under operational and facility constraints using a sequential quadratic programming approach. A major advantage of our approach is the analytical computation of the gradient and Hessian of the objective function which makes it computationally efficient and suitable for large field cases.
Multiple examples are presented to support the robustness and efficiency of the proposed optimization scheme. These include 2D synthetic examples for validation and a 3D field-scale application. The role of geologic uncertainty in the outcome of the optimization is demonstrated both during the early stage and also, later stages of waterflooding when substantial production history is available.
A Combinatorial Approach for Identification of Performance EOR Surfactants
Authors: Morvan M. , Koetitz R. , Moreau P. , Pavageau B. , Rivoal P. , Roux B. 
Published: April 2008

Abstract
This work describes an automated combinatorial process for selecting EOR surfactants. It is well known that low interfacial tension (IFT) required to mobilize oil corresponds to the appearance of middle phase microemulsions (Winsor III). Instead of systematic measurements of IFT, simple observation of phase behaviour in vials allows to select best formulations. As the number of parameters to be screened incorporate surfactants, co-surfactants, alkali and electrolytes, we have developed an automated method to accelerate the screening productivity. Among other requirements, critical issues we want to address concern compatibility with electrolyte, thermal stability and low cost.
Sample preparation is done in 48 well format using a robotic liquid handling platform that supports stirring and heating. In a first step, the brine concentration above which the surfactant is not soluble anymore is determined optically using a digital camera. In a second step, we take images of the phase behaviour of surfactant formulations in the presence of model oil (dodecane, vaseline). Image analysis is used to detect middle phase microemulsions. An estimate of interfacial tension can be derived from the volume of the middle phase microemulsion. Phase diagram observations can be recorded from room temperature up to 80°C. Results are in good agreements with classical methods used to measure low interfacial tension. An example study of phosphate esters will be discussed to illustrate the method.
This technique provides a powerful tool for testing formulations prior to more expensive core flood experiments.
Application of pH-Triggered Polymers in Fractured Reservoirs to Increase Sweep Efficiency
Authors: Lalehrokh Farshad , Bryant Steven L. , Huh Chun , Sharma Mukul M. 
Published: April 2008

AbstractWater and gas shutoff in naturally fractured reservoirs is traditionally achieved with cross-linked gels. Low sweep efficiency is also an important problem in waterflooding such reservoirs which can be treated with gel. In-depth placement of gels is the key to success, and this requires careful control of the cross-linking chemistry. This work examines the feasibility of an alternative gelation mechanism in fractured rock: pH-triggered polymer microgels. The microgel particles are small enough to pass through fractures but not pore throats in a matrix. The pH change occurs naturally and inevitably; it thus offers a simpler means of obtaining deep placement.When an acidic polymer solution is injected into the formation, several factors affect the pH: rock mineralogy, reactive surface area of the minerals, temperature and dilution due to mixing with residual water. The viscosity of the solution depends strongly on pH and upon polymer concentration and salinity of the polymer solution. The rate of pH increase relative to the rate of fluid advance determines the depth of placement.We used commercially available polymers which exhibit low viscosity at a pH below 3 but transform to gels at pH &gt; 4. Polymer solutions were injected through artificial fractures in outcrop cores. Both sandstone and carbonate rocks raise the polymer solution pH. The presence of acid-soluble minerals containing cations such as calcium can independently trigger viscosification by precipitating the polymer. After polymer injection, a shut-in time allows further reaction to increase the pH and thus affects the Permeability Reduction Factor (PRF), the ratio of original fractured core permeability to treated core permeability. The PRF was measured to be in the range of 200 to 5 during the various experiments. The gelation is faster and PRF is higher in carbonates than in sandstones. Because the neutralization capacity of a core is large, it is possible to approximate reactive transport in a reservoir by continuously re-circulating the polymer effluent. Experiments showed gellike characteristics after 30 pore volumes of recirculation in Berea sandstone.
An Innovative Approach to Evaluate Residual Oil Saturation in Insitu Condition
Authors: Hazra S. , Bhattacharya S. 
Published: April 2008

Abstract
Residual oil Saturation plays a big role in simulation study for forecasting oil production. Generally it is determined through core flood experiments under reservoir conditions in small core plugs which do not capture the actual reservoir heterogeneity. More over it uses dead crude oil after matching the reservoir oil viscosity. Due to this, it is often difficult to generate representative ROS distribution throughout the field. There are other methods reported in the literature having some inherent limitations.
Cased hole formation resistivity, a relatively new technology introduced in the industries to know the by passed oil in mature fields. It is mainly used for re-completion of old producing wells either through zone transfer or placement of horizontal wells. In this paper use of Cased hole formation resistivity in injectors having long injection history are conceptualized with the aim to get remaining oil saturation with respect to water injection in the formation. Due to prolong water injection / flushing it is expected that maximum water intake zone will show the oil saturation close to the residual oil saturation.
The present paper discussed the results of two injectors where Cased hole formation resistivity along with injection profile were recoded. The oil saturation in the maximum water intake zone was compared with the residual oil saturation determined through laboratory established correlation based on core flood studies.
The results indicate that the oil saturation is much lower than the core flood ROS in the reservoir area where maximum water has been injected. This adds a new dimension in determining the in-situ measurement of ROS. The interpretation issues like effect of injected water salinity etc are also illustrated in the paper.
EOR Potential of the Michigan Silurian Reefs Using CO2
Authors: Toelle Brian , Pekot Larry , Barnes David , Grammer Mike , Harrison William 
Published: April 2008

Abstract
The Guelph Formation, historically known as the Brown Niagaran, is a Silurian age formation in the Michigan Basin containing hundreds of pinnacle reefs. These reefs, discovered primarily during the 1970s, have produced nearly half a billion barrels of primary oil. Over 700 reefs make up the northern trend and more than 300 reefs have been located in the southern portion of the basin, many of which have produced more than 5 MM bbls of oil. The EOR potential of these fields is believed to be significant. Few of these fields have been waterflooded and only five have experienced CO2 injection.
An ongoing US Department of Energy project is studying the use of CO2 in enhanced oil recovery operations at the Charlton 30/31 reef, which is located in Michigan's Otsego County. This field was discovered in 1974 by Shell and produced 2.6 million bbls of oil during its primary production phase from a reservoir that may be typical of the other reefs in these trends. The reservoir is composed of a limestone matrix with low porosity and low permeability that contains irregular dolomitized intervals. These dolomitized zones, with higher porosity and permeability, control the flow of fluids through these reservoirs. This project utilized 4D seismic, reservoir simulation and a new well drilled into the reef to provide greater understanding of the CO2 EOR potential for this and all of the Silurian reefs in Michigan.
Selection and Screening of Polymers for Enhanced-Oil Recovery
Authors: Levitt David B. , Pope Gary A. 
Published: April 2008

Abstract
A number of commercially available polymers have been tested for enhanced oil recovery based upon viscosity, filterability, and surfactant compatibility, and chemical and thermal stability testing has been carried out with some of these as well. Several high molecular weight polymers exhibited high viscosities at salinities up to 170,000 ppm NaCl and with greater than 17,000 ppm CaCl2 present. Polyacrylamide polymers hydrolyze at high temperatures and beyond a certain point are subject to precipitation by calcium. If calcium concentrations can be kept below about 200 ppm, the use of polyacrylamide polymers is feasible up to reservoir temperatures of at least 100°C. For higher concentrations of calcium, copolymers including AMPS moieties should be considered. Calcium tolerance can be improved with sodium metaborate or by using copolymers of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate (AMPS). The stability problems at elevated temperatures in the presence of iron can be mitigated by the use of chemicals such as sodium dithionite and sodium carbonate. The polymers tested did not lose viscosity after 220 days of aging at 100°C with dithionite present.
Designing for Mixed Wettability
Authors: Kumar M. , Senden T. J. , Latham S. , Sheppard A. P. , Knackstedt M. A. , Cinar Y. , Pinczewski W. V. 
Published: April 2008

Abstract
In this paper we describe a technique based on radio frequency plasma treatment in H2O vapour to reproducibly clean and modify the surface energy of clastic and carbonate core material allowing the establishment of well defined wettability conditions. We present micro-tomographic observations of the pore-scale fluid distributions in strongly water wet clastic and carbonate cores. We then establish mixed-wet states in the same cores using controlled hydrophobation. Micro-tomography is again used to reveal the three-dimensional geometry and topology of water and oil wet regions. The tomographic data shows that under water wet conditions at intermediate saturations larger pores are predominantly oil filled while smaller pores remain water wet. We perform displacement experiments using clastic and carbonate cores at well defined wettability conditions and report measurements of resistivity index. These methodologies may provide insight into the role of rock microstructure and surface energy variability in determining recovery and production characteristics of oil and gas reservoirs.
Pore-Scale Simulation of WAG Floods in Mixed-Wet Micromodels
Authors: van Dijke M. I. J. , Lorentzen M. , Sohrabi M. , Sorbie K. S. 
Published: April 2008

Abstract
In this paper the simulation is described of water-alternating-gas injection (WAG) flood cycles in 2-D etched glass mixed-wet micromodels, using a 3-D pore-scale network model for three-phase immiscible flow in porous media of arbitrary wettability. Although most network model input parameters can be explicitly derived from the experiments, the precise wettability parameters are not directly available. Therefore, a sensitivity study was carried out, using the network model in 2-D mode, to obtain the wettability characteristics, i.e. the contact angle values and distribution, and the fraction of water-wet pores. Good qualitative and quantitative agreement was found between the experimental and simulated recoveries over the various WAG cycles, and the final residuals were well reproduced (as well as some observed "random recovery jumps"). The simulated displacement statistics showed many so-called multiple displacement chains involving oil, up to around the third WAG cycle. The experimental and simulated fluid distributions were generally in good agreement in that (a) different gas fingers were observed during various gas floods, (b) oil movement was observed mainly during the first few WAG cycles, and (c) during water floods, significant amounts of gas were displaced. Additionally, previously described simulations of water-wet and oil-wet experiments are compared with the present mixed-wet simulations. There are close similarities between the mixed-wet and oil-wet cases, which both maintain some continuity of oil through wetting films, but these cases are quite different from the water-wet case, which has continuity of water through wetting films in all pores. This paper further validates the pore-scale mechanisms incorporated in a network model that is capable of predicting three-phase relative permeabilities and capillary pressures for complicated processes such as WAG.