bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Bayesian Networks for Predicting the Performance of Gel-Treated Wells in the Arbuckle Formation, Kansas
Authors: Ghoraishy S. M. , Liang J. T. , Green D. W. , Liang H. C. 
Published: April 2008

Abstract
Polymer-based gels have been used extensively to reduce water production and improve oil productivity in the Arbuckle formation in central Kansas. One of the most important steps required for successful gel-polymer treatments is to identify candidate wells. Traditionally, the selection of wells to be treated has been based on subjective screening guidelines which may result in inconsistent treatment outcomes and poor economic performance. The objective of this study was to develop a method to identify candidate wells in the Arbuckle for gel-polymer treatments using individual well data readily available to an operator.
The approach was to use Bayesian networks applied to a data set derived from a number of gel-treated wells in the Arbuckle. Bayesian networks (Belief Networks) are probabilistic graphical models that represent a set of variables and their probabilistic dependencies. For this study two different Bayesian networks, Naïve and Augmented, were trained using pre-and post-treatment well data from 45 wells. The trained networks were then used with pre-treatment data from 14 additional wells to predict the post-treatment well performance economics of those wells. Well performance was evaluated using a discounted cash flow and net present value (NPV) economic analysis.
The results indicate that both the Naïve and Augmented Bayesian networks can accurately predict post-treatment well performance economics. For the 14 wells for which predictions were made, the average accuracy in NPV prediction was 77% and 84% respectively for the two Bayesian methods used. The analysis identified completion thickness from the top of Arbuckle and water-oil ratio as the most important parameters for the success of gel treatments in the Arbuckle formation.
Compared to other methods of candidate-well selection, which either rely on complicated reservoir models or unreliable anecdotal screening guidelines, Bayesian networks are relatively easy to implement and can accurately predict the post-treatment well performance economics. Results from this study demonstrated that Bayesian networks can be a very powerful tool for candidate-well selection for gel treatments in the Arbuckle formation. The same concept can be applied in other areas where enough data are available to train the Bayesian networks.
Wettability Alteration of Fractured Carbonate Reservoirs
Authors: Gupta R. , Mohanty K. K. 
Published: April 2008

Abstract
Oil can be recovered from fractured, initially oil-wet carbonate reservoirs by wettability alteration with dilute surfactant and electrolyte solutions. The goal of this work is to study the effect of salinity, surfactant concentration, electrolyte concentration, and temperature on the wettability alteration and identify underlying mechanisms. Contact angles, phase behavior, and interfacial tensions were measured with two oils (one model oil and one field oil). There exists an optimal surfactant concentration for varying salinity and an optimal salinity for varying surfactant concentration at which the wettability alteration is the maximum for anionic surfactants. As the reservoir salinity increases, the extent of maximum wettability alteration decreases for a surfactant, but the surfactant concentration needed for the maximum wettability alteration decreases. IFT and contact angle were found to have the same optimal salinity for a given concentration of anionic surfactants. As the ethoxylation increases in anionic surfactants, the extent of wettability alteration increases. Wettability of carbonates can be altered by divalent ions at high temperature (90°C and above). Sulfate and calcium ions play a more important role in altering wettability than magnesium ions. Wettability alteration increases the oil recovery rate from fractured carbonates.
Anisotropic Relative Permeabilities for Characterising Heavy-Oil Depletion Experiment
Authors: Ezeuko C. C. , McDougall S. R. , Bondino I. , Hamon G. 
Published: April 2008

Abstract
In recent years, the use of pore-scale network models has greatly advanced our understanding of solution gas drive processes by accounting for the complex dynamics operating at the microscopic scale. Moreover, it has also been demonstrated that a pore-network model, when suitably anchored to core material is able to provide both qualitative and quantitative descriptions of relative permeability and hydrocarbon recovery. In contrast, many so-called "experimental" depletion drive relative permeabilities are not measured directly but are generally obtained by history-matching laboratory production data with reservoir simulators, often resulting in very low gas relative permeabilities that are difficult to explain from a physical viewpoint. Although pore-scale network models have been successfully used in the past to match raw production data, the steady-state relative permeabilities calculated from such models commonly predict much slower gas saturation build-up than that found experimentally. Some previous authors have related this low gas saturation build-up to the difference in the definition of critical gas saturation between reservoir simulators and pore-network models. However, the dentritic nature of gas-cluster topology in network models, especially in the presence of other forces, such as gravity or strong viscous pressure gradients, clearly suggests that significant anisotropy may exist in relative permeability due to the balance of forces at this scale.
In the present work, we describe how the naïve process of scaling up steady-state relative permeabilities obtained from pore-scale network models to the laboratory scale may contribute significantly to the difficulty in history-matching experimental production. By considering the influence of the various forces (capillary, gravity, viscous) on the topology of the growing gas clusters and by accurately incorporating anisotropic network-model relative permeabilities, we show that high gas saturation build-up, consistent with experimental observations can be obtained from reservoir simulation.
Application of Coalbed Methane Water to Oil Recovery by Low Salinity Waterflooding
Authors: Pu H. , Xie X. , Yin P. , Morrow N. R. 
Published: April 2008

Abstract
Development and production of coalbed methane involves the production of large volumes of water. The salinities and sodium adsorption ratios of coalbed methane (CBM) water from the Powder River Basin range from 370 to 1,940 ppm and 5.6 to 69 respectively. Surface discharge of CBM water can create serious environmental problems; subsurface injection is generally viewed as economically nonviable. It has been shown that oil recovery from reservoir sandstones can be improved by low salinity waterflooding for salinities ranging up to 5,000 ppm. There may be both technical and regulatory advantages to application of CBM water to oil recovery by waterflooding. Thin section and scanning electron microscope studies of the mineral constituents and distribution of Tensleep and Minnelusa sandstones show they are typically composed of quartz, feldspar, dolomite and anhydrite cements but have very low clay content. The sands contain interstitial dolomite crystals in the size range of up to about 10 microns. Three sandstone cores from the Tensleep formation in Wyoming were tested for tertiary response to injection of CBM water. The cores were first flooded with high salinity Minnelusa formation brine of 38,651 ppm to establish residual oil saturation. Synthetic CBM water of 1,316 ppm was then injected. Tertiary recovery by injection of CBM water ranged from 3 to 9.5% with recoveries for all but one flood being in the range of 5.9 to 9.5%. Previous studies showed that the presence of clay was needed for response to low salinity flooding. As a test of the recovery mechanism, a Tensleep core was preflushed with 15% hydrochloric acid to dissolve the dolomite crystals. The treated core showed no tertiary recovery or pressure response to CBM water.
Residual Oil Saturation from Polymer Floods: Laboratory Measurements and Theoretical Interpretation
Authors: Huh Chun , Pope Gary A. 
Published: April 2008

Abstract
A detailed analysis of the laboratory corefloods and their simulation matches, carried out earlier in our laboratory, show that, while a tertiary polymer flood cannot mobilize the waterflood residual oil, a secondary polymer flood can displace oil below the waterflood residual oil saturation observed in the same core. We show with a simplified pore-level modeling study that, when a viscoelastic polymer solution surrounds a mobile, funicular oil column in a chain of pores and slowly drains it, the breakage of the oil column into oil ganglia is delayed by the polymer's elasticity resisting the deformation of the oil/water interface.
The residual oil saturations from waterflood and a subsequent (i.e., tertiary) polymer flood were measured in homogeneous Berea sandstone cores and in Antolini sandstone cores with small-scale heterogeneity, by Wreath (1989) and Wang (1995). For the latter, the distributions of porosity/permeability in the core samples were measured with mini-permeameter and CAT scan, and were employed as input for the history-matching simulations. The residual oil saturations from waterflood and a secondary polymer flood in the same core were also measured in Berea and Antolini cores. For both Berea and Antolini cores, a tertiary polymer flood did not reduce the waterflood residual oil saturation. For nine Antolini cores, a secondary polymer flood reduced the residual oil saturation below the waterflood value by 0.02–0.22 in saturation units. To investigate whether the differences observed for the heterogeneous Antolini cores are due entirely to the improved volumetric sweep or due also to the true reduction in residual oil saturation, history-matching simulations have been carried out by Lu (1994). The secondary polymer flood results could be matched only when its residual oil saturation value is lower than that for waterflood. Therefore, the higher oil recovery from the secondary polymer flood is the result of combination of improved sweep and the reduction in residual oil saturation.
In order to model the delay of the oil column breakage into oil ganglia qualitatively, we consider a circular oil column surrounded by an annulus of a polymer solution in a circular tube. Assuming that the polymer solution can be modeled as a Maxwell fluid which has both viscous and elastic rheological character, the stability of the oil column is analyzed in terms of the fluid properties and the tube and oil column radii. While the interfacial tension between oil and polymer solution make a long oil column become unstable and break into oil droplets, the elasticity of the polymer solution resists the deformation of the interface. Calculation of the growth rate for the interfacial disturbance shows that, as the elastic modulus of the Maxwell fluid increases, the growth rate decreases, suggesting that the oil column could become thinner, thereby potentially decreasing the residual oil saturation.
Overview of the Illinois Basin's Sequestration Pilots
Authors: Frailey Scott M. , Finley Robert J. 
Published: April 2008

Abstract
As part of the DOE's Phase II and III Geologic Sequestration Partnership program, the Illinois State Geological Survey is leading the Midwest Geologic Sequestration Consortium (MGSC) in various field demonstrations. MGSC's Phase IMII is six sequestration pilots of which there are four EOR pilots, one S/ECBM pilot and one, large-scale brine-saturated formation injection pilot.
A small 43 ton single well, huff-and-puff has been designed, implemented and completed in the Loudon oilfield. The well was a single formation completion at 1500 ft at pressure and temperature considered immiscible. The well's initial oil response was 8x the pre-CO2 oil rate. The site selection, equipment layout, test results and background information will be presented.
Selection of a pattern flood is in the late part of the screening process. Because of the relative low reservoir temperatures and high fracture gradient, this pilot is being designed as a liquid CO2 flood. Model results suggest 6–8 months of continuous injection followed by 2–3 months of water injection are required to have a measurable response at this site. Finalization of pilot contract with oilfield operator and UIC permit application process is being initiated at this time. The plans for the remaining two EOR pilots are similar to the pattern flood except these sites will be screened for pressure and temperature conducive to immiscible and traditional miscible conditions.
The S/ECBM pilot is scheduled for injection in summer of 08. Presently two wells in the pilot have been drilled, cored and DST'd. DST permeability results were lower than expected and drilling was suspended in order to carry out additional pressure transient testing including two falloff tests and one pulse tests. Results of the PTA tests confirmed the DST results and subsequent suggest closer well spacing is required.
The deep saline formation test is scheduled to have the injection well drilled in spring 08. The UIC permit application has been submitted. This one million ton injection project is intended for the Mt. Simon sandstone in central Illinois; the Mt. Simon is the deepest sedimentary formation in the Basin.
Scaled Physical Model Experiments to Characterize the Gas-Assisted Gravity Drainage EOR Process
Authors: Sharma Amit P. , Rao Dandina N. 
Published: April 2008

Abstract
The year 2006 marks the first time the gas injection EOR production has surpassed that of steam injection processes in the US, signifying the growth of gas injection as a mature technology. In order to control the rising tendency of injected gas in horizontal floods, the water-alternating-gas (WAG) process has generally been the mode of operation in many fields. In spite of its wide application, the WAG process has not lived up to its expectations with reported recoveries in the range of 5–10% OOIP. In order to improve recoveries, we have been attempting to develop the gas-assisted gravity drainage process at LSU. This paper summarizes the effort of conducting scaled physical model experiments in a visual glassbead-packed model aimed at discerning the influence of some scaled dimensionless parameters, such as the capillary number, Bond number and gravity number, on the GAGD process performance.
A 2-D physical model, of 16″ X 24″ X 1″ dimensions, packed with uniform glass beads, was used to conduct visual experiments. These experiments were so designed as to mimic the dimensionless parameters observed in some field projects. The secondary mode GAGD floods yielded recoveries up to 80% OOIP. Additionally, the recoveries displayed a semi-logarithmic relationship with gravity number (ratio of gravity to viscous forces). Interestingly, this relationship was observed to hold good for the high-pressure GAGD corefloods and even the field production data from gravity-stable gas injection projects conducted in pinnacle reefs. A multi-variable regression analysis of the laboratory as well as field data indicated that the Bond number, being the ratio of gravity to capillary forces, had a greater influence on GAGD performance than other parameters. In addition to the observed high recoveries, our attempts to relate the model run times to field project durations, through dimensionless time considerations, have indicated reasonably good rates of production when GAGD process is implemented in field projects.
Full Field Streamline Tracing in Complex Faulted Systems with Non-Neighbor Connections
Authors: Jimenez Eduardo A. , Datta-Gupta Akhil , King Michael J. 
Published: April 2008

AbstractFull field flow simulators utilize a variety of cell geometries ranging from simple rectangles to complex corner point systems. One of the benefits of corner-point cells is the ease with which we may represent faulted reservoirs. Each face of a cell may be juxtaposed to two or more cells, depending on the fault throw and the lateral displacements of adjacent cells. Conventional finite-difference approaches routinely include the flux between these cells as "non-neighbor" connections. Other examples of non-neighbor or non-standard connections occur at the boundary of local grid refinement (LGR) or local grid coarsening (LGC) regions where two computational grids come into juxtaposition. In each of these instances, the velocity across the non-standard faces of a cell will be unevenly distributed according to the non-neighbor fluxes. In contrast, the standard streamline velocity interpolation model (Pollock's scheme) used within a cell assumes that the flux be evenly distributed on each cell face, inconsistent with the non-neighbor connection fluxes. Streamlines traced with such an approach do not have sufficient degrees of freedom to be consistent with the finite-difference fluxes, and consequently will not follow a physical flow path.We propose a strategy that provides a consistent representation for streamlines and velocities near faults and non-neighbor connections. Our approach is based on a simple local (boundary layer) refinement construction that can be used to honor the fluxes at each face, without impacting the representation of flow within the cell or on any other cell face. The local refinement construction is the simplest extension to three dimensions for faulted reservoir cells which provides consistency with the finite difference flux calculation. Several examples will be presented for a single pair of cells juxtaposed across a fault and at LGR boundaries to illustrate the difficulties in conventional tracing algorithms and the benefits of our approach. The practical utility of our algorithm is demonstrated in a structurally complex and heavily faulted full field model. The reservoir geometry includes multiple cells with complex fault juxtaposition and several non-neighbor configurations in different faces. This treatment is contrasted with the usual approach and the implications for reservoir scale fluid flow tracing by streamlines is examined
Investigation of Field Scale Dispersion
Authors: John Abraham K. , Lake Larry W. , Bryant Steven L. , Jennings James W. 
Published: April 2008

Abstract
Dispersivity data compiled over many lengths show that values at typical interwell distances are about two to four factors of ten larger than those measured on cores. Such large dispersivities may represent significant mixing in the reservoir or they may be a result of convective spreading driven by permeability heterogeneity. The work in this paper uses the idea of flow reversal to resolve the ambiguity between convective spreading and mixing. We simulate flow reversal tests for tracer transport in several permeability realizations using particle tracking simulations (free from numerical dispersion) on three-dimensional, high resolution models at the field scale.
We show that convective spreading, even without local mixing, can result in dispersion-like mixing zone growth with large dispersivities because of permeability heterogeneity. But for such cases, the dispersivity estimated on flow reversal is zero. With local mixing (diffusion or core scale dispersion) the dispersivity value on flow reversal is non-zero and also much larger than typical core values. Layering in permeability, while increasing the convective contribution to transport, also enhances mixing by providing larger area in the transverse direction for diffusion to act. This suggests that in-situ mixing is an important phenomenon affecting the transport of solutes in permeable media even at large scales. Dispersivity values increase with scale mainly because of the increase in the correlation in the permeability field but they could also apparently appear to do so because the Fickian model fails to capture the mixing zone growth correctly at early times.
The results and approach shown here could be used to differentiate between displacement and sweep efficiency in field scale displacements, to ensure accurate representation of dispersive mixing in reservoir simulation and to guide upscaling workflows. The flow reversal concept motivates a new line of inquiry for lab and field scale experiments.
Development of High-Performance Surfactants for Difficult Oils
Authors: Zhao Ping , Jackson Adam C. , Britton Chris , Kim Do Hoon , Britton Larry N. , Levitt David B. , Pope Gary A. 
Published: April 2008

Abstract
We present results for high molecular weight internal olefin sulfonate (IOS) surfactants that show excellent performance when tested using several crude oils with characteristics such as high wax content and viscosity that have made it very difficult to achieve high oil recovery with most surfactants used in the past. High carbon number internal olefin sulfonates when used with appropriate co-surfactants, co-solvents and alkali show the type of phase behavior and ultra-low interfacial tension needed for almost 100% oil recovery in cores. This work shows how the performance of both surfactant-polymer and alkaline-surfactant-polymer flooding can be dramatically improved at the same or lower cost than with conventional surfactants and applied over a wider range of reservoir conditions. High carbon number internal olefin sulfonate surfactants gave good performance at low concentrations and were found to be compatible with both polymers and alkali such as sodium carbonate when used with appropriate co-solvents. The extremely efficient and effective approach for finding high performance surfactants that we previously presented for light crude oils has now been successfully extended to heavier crude oils. The identification of high-performance surfactants suitable for high-temperature and/or paraffinic oil applications opens up the potential to recover a vast amount of additional oil outside the range of conditions considered practical in the past.
Modelling CO2 Injection: IOR Potential after Waterflooding
Authors: Berenblyum R. , Calderon G. , Kollbotn L. , Surguchev L. M. 
Published: April 2008

Abstract
This paper combines the knowledge and experience accumulated at the International Research Institute of Stavanger (IRIS) over a number of years, based on several case studies involving the Tjelbergodden CO2 value chain, modelling of CO2 injection at the Ekofisk field (fractured chalk reservoir) and Gullfaks CO2 injection compositional study.
The paper discusses the importance of correctly representing the physical effects when modelling miscible or immiscible CO2 injection in sandstone and carbonate reservoirs. The following aspects were evaluated:
Transfer of CO2 from fractures to matrix involving diffusive, gravitational and capillary forces; Viscous effects; Formation of low and high concentration liquid hydrocarbon phases; Compositional effects such as miscible displacement and oil swelling; Chemical interaction between CO2, formation or injection water and reservoir rock.
The sensitivity and importance of these effects were studied on several simplified mechanistic models and later applied to actual field cases.
An overview of viscous fingering effects is presented. Results from mechanistic studies of the CO2 matrix-fracture transfer are shown and physical effects are discussed. The paper also presenets critical aspects of Equation-Of-State (EOS) modelling and PVT experiments necessary for a CO2 flood simulation study. From our experience we suggest a "cooking recipe" for building reservoir simulation models for CO2 based IOR process evaluations. Case studies of the CO2 and CO2-WAG IOR methods for reservoirs on the Norwegian Continental Shelf (NCS) are presented and oil recovery potentials of these IOR processes are discussed.