bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Relative-Permeability Modifier Treatments in a Sandstone-Layered System and
Authors: Dalrymple E. Dwyann , Brown David 
Published: December 2007

Abstract
By using chemical treatments in attempts to reduce the volumes of water produced from hydrocarbon-bearing strata, well operators face the risk of damaging productive intervals. To avert this problem, well operators often apply special placement techniques, (such as the use of the dual-injection technique and multiple-packer assembles) in attempts to focus water shutoff treatments into areas of interest. The special placement techniques require significant additional costs involving workover rigs, coiled-tubing units, multiple pumping units, tools, packers, and so on. Even when these precautions are taken, the chemical treatment may still enter the productive interval through any number of avenues, including the interzonal, communication, packer leaks or channels behind the pipe.
The oil and gas industry is inherently attracted to relative permability modifiers (RPMs) because they have the potential to reduce the relative risk factors involved when conformance water-management treatments are performed on active, hydro-carbon-producing wells. The term RPM has been misused at times by being used to refer to porosity-fill sealants (such as metal-complexed polyacrylamide systems). Although organic, water-based systems may preferentially achieve deeper penetration into water-saturated strata than into hydrocarbon strata, those systems still result in the forming of sealants. The ideal RPM should reduce the effective permeabilit6y to water with no effect on the effective permeability to oil.
The RPM materials available to the industry today are not ideal. These materials actually affect the effective permeability to both water and oil. The difference between and RPM and a sealant is that the RPM reduces the effective permeability to water more significantly than the effective permeability to oil.
This paper discusses the results of testing two currently available RPMs through porous rock media. The testing includes evaluation of the RPMs in a layered system(high-permeability streaks of water though hydrocarbon-bearing strata) and evaluations of the RPMs in a homogeneous system with varying degrees of water saturation (transition zone between oil and water-bearing strata).
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Large-Volume Foam-Gel Treatments to Improve Conformance of the Rangely CO2
Authors: Hughes T.L. , Wilson A. , Davies S.N. , Friedmann F. , Johnson D. , Hild G.P. 
Published: December 2007

Abstract
Large-volume foam-gel treatments can provide a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. The applicability and cost-effectiveness of the approach depends on the availability of a cheap source of gas, the efficiency with which the foam can be placed into the high permeability thief zone(s) and the effectiveness of the gelled foam barrier in diverting reservoir drive fluids to improve oil recovery.
This paper reviews progress in the application of large- volume CO2-foam-gel treatments to improve conformance in the Rangely Weber Sand Unit (RWSU), Colorado. The design, implementation, and evaluation of a series of 35,000-45,000 bbl injector well treatments is described. The first treatment was reported in SPE paper 38837. The objectives of this paper are to provide an update on the production response of the first treatment, to report on the status of the second and third treatments, and to describe new developments which increase the cost-effectiveness of the system.
We emphasize the importance of candidate well/pattern selection and evaluation to characterize the conformance problem and the main rapid communication trends between the injector and its associated producer wells. Prior to implementing the main treatment, a program of injector well tests is used to evaluate the flow characteristics of the thief zone(s), and the optimum foam injection strategy. The delayed gelation kinetics of the system are designed to optimize foam generation and placement, to ensure foam stabilization before the end of the pump period and to generate a strong and robust gelled foam barrier after placement.
The procedures used to determine treatment effectiveness are described. From the injector well viewpoint, changes in water and CO2 injectivity, and the extent and longevity of near well bore diversion after the treatment is given by a series of injection profile surveys and pressure fall-off tests. High frequency pre- and post-treatment production data are used to evaluate production response and incremental oil recovery. Finally, we discuss the cost-effectiveness of foam-gel treatments relative to polymer gels.
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Measurement of Three Phase Relative Permeability during Gravity Drainage using CT
Authors: Sahni Akshay , Burger Jon , Blunt Martin 
Published: December 2007

Abstract
We measured three phase relative permeabilities for gravity drainage using a dual-energy medical CT scanner modified to scan vertical cores. Independent measurements of two saturations as a function of time and distance along the length of the core were made from which relative permeabilities were found. Three phase (air/oil/water) gravity drainage experiments were performed on systems with different spreading coefficients and at different initial conditions. Experiments were run on both consolidated and unconsolidated porous media. The results were compared to measurements of three phase flow in capillary tubes, micromodels and to predictions from network modeling.
We find that at low oil saturation kro for hexane and octane as the oil phase. This functional form of relative permeability is consistent with the drainage of oil layers. wedged between the water and gas in crevices of the pore space. For decane, which is non-spreading, the layer drainage regime was not observed. At higher oil saturations kro with a for spreading and non-spreading systems. Within the scatter of the experimental data, oil and water relative permeability are functions only of their own saturations and independent of initial conditions.
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Relative Permeability Curves: The Influence of Flow Direction and Heterogeneities.
Authors: Crotti M.A. , Rosbaco J.A. 
Published: December 2007

Abstract
This paper presents results that highlight some aspects not often considered when dealing with experimental relative permeability curves in heterogeneous media, a very common situation in natural sandstone samples.
When comparing curves obtained from the same core sample as a result of horizontal and vertical floodings, they show a large difference in residual oil values and in the general displacement performance. The information thus gathered indicates a systematic tendency towards notably lower residual oil in the case of vertical floodings.
These results are significant because of the large number of cases of vertical flooding occurring throughout the productive life of a reservoir, such as crossflow among strata of different permeabilities, predominantly segregate flow, expanding gas cap, flow from basal aquifers, etc. This is the reason for contesting the standard procedure of always using the same single set of relative permeability curves that, in practically all cases, are determined by horizontal flow.
Based on the results presented herein, it is suggested that the end points used in order to describe the different reservoir flow and production models be obtained using horizontal and vertical flooding, as well as by imbibition and capillary pressure tests.
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Foam Flow in Heterogeneous Porous Media: Effect of Crossflow
Authors: Bertin H.J. , Apaydin O.G. , Castanier L.M. , Kovscek A.R. 
Published: December 2007

Abstract
Previous studies of foam generation and transport were conducted, mainly, in one-dimensional and homogeneous porous media. However, the field situation is primarily heterogeneous and multidimensional. To begin to bridge this gap, we have studied foam formation and propagation in an annularly heterogeneous porous medium. The experimental system was constructed by centering a 5.0 cm diameter cylindrical Fontainebleau sandstone core inside an 8.9 cm acrylic tube and packing clean Ottawa sand in the annular region. The sandstone permeability is roughly 0.1 d while the unconsolidated sand permeability is about 7 d. Experiments with and without crossflow between the two porous media were conducted. To prevent crossflow, the cylindrical face of the sandstone was encased in a heat-shrink Teflon sleeve and the annular region packed with sand as before. Nitrogen is the gas phase and an alpha olefin sulfonate (AOS 1416) in brine is the foamer. The aqueous phase saturation distribution is garnered using X-ray computed tomography.
Results from this study are striking. When the heterogeneous layers are in capillary communication and cross flow is allowed, foam fronts move at identical rates in each porous medium as quantified by the CT-scan images. Desaturation by foam is efficient and typically complete in about 1 PV of gas injection. When cross flow is prohibited, foam partially plugs the high permeability sand and diverts flow into the low permeability sandstone. The foam front moves through the low permeability region faster than in the high permeability region.
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Foam Propagation on Semi-Reservoir Scale
Authors: Vassenden F. , Holt T. , Solheim A. 
Published: December 2007

Abstract
Foam propagation in co-injection is studied in a 10 m long flow apparatus, equipped with pressure ports and fluid sampling valves for every 1 m. The data are compared to the result of a foam flooding experiment in a core scale flooding experiment with the same porous medium. The core scale experiment was simulated with a numerical foam simulator model.
The propagation experiments on the 10 m scale revealed that the foam front propagated significantly slower than the injected fluid front. It appeared that foam propagation was not limited by surfactant transport, but was delayed due to segregation of gas and surfactant solution, and by the presence of oil in the porous medium.
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A Promising Hydrophobicaly-Modified Guar for Completion Applications
Authors: Young N.W.G. , Williams P.A. , Meadows J. , Allen E. 
Published: December 2007

Abstract
Current demands for greater well productivity require development of less damaging completion and stimulation fluids. This paper examines a hydrophobically modified hydroxybutyl guar (HMHBG) which shows improved properties over native guar, hydroxypropyl guar (HPG) and hydroxybutyl guar (HBG). HMHBG possesses I-2(w/w)% CI6 alkyl chains randomly distributed. The average molecular weight of the HMHBG is 2.2 million compared with 1.6 million, 2.0 million and 2.7 million for guar, HPG and HBG respectively. This paper presents the shear and extensional flow behaviour and viscoelastic characteristics of the four polymers in solution, and in the presence of the anionic surfactant sodium dodecyl sulphate (SDS).
Experimental results showed that the extensional viscosity of HMHBG was up to 100 times greater than the corresponding shear viscosity. The zero shear viscosity is 8 times greater for HMHBG and 3 times greater for HBG compared to native guar. Addition of SDS resulted in a 10 fold increase in solution viscosity of HMHBG at intermediate surfactant concentrations, however, the non hydrophobically modified polymers solutions showed no observed change. This was attributed to the promotion of intermolecular associations due to the preferential binding of the surfactant to the hydrophobic regions.
These results indicate that greater viscosity control can be achieved by use of hydrophobically modified guars which may have advantages over native guars for completion and stimulation applications.
The high extensional viscosity of HMHBG may reduce leakoff, thus reducing potential formation damage in gravel packing and hydraulic fracturing applications. The higher viscosities at low shear rates can improve solids transport. Furthermore the hydrophobically modified polymers minimize the problem of shear degradation because the intermolecular associations, although broken down by high shear conditions, are reformed when the shear stresses return to lower values. Since the molecular weight and the actual hydrodynamic volume are much smaller than for traditional polyacrylamide and scleroglucan molecules, these polymers should also minimize pore clogging, and thus give improved cleanup and return permeabilities.
P. 463
Matrix-Fracture Mass Transfer
Authors: Gabitto Jorge F. 
Published: December 2007

Abstract
An important mechanism in oil recovery from fractured reservoirs is multicomponent gas-liquid mass transfer. A model is presented to study effect of multicomponent, multiphase mass transfer from a porous matrix to fractures including the effects of capillarity and interfacial tension gradients. A custom made two dimensional simulator has been developed for this purpose. The simulator has allowed us to study mass transfer from a matrix block to a fracture when transport occurs: within single phase, across a partially immiscible phases along a single tie-line and across several partially immiscible tie-lines. The effects of enrichment, gravity orientation, capillarity and residual water saturation on recovery have been studied. Our results show that diffusion alone cannot explain the extent of recovery.
P. 471
A Model for Tracer Flow in Heterogeneous Porous Media
Authors: Numbere D.T. , Erkal A. 
Published: December 2007

Abstract
A tracer model utilizing scale dependent dispersion coefficient applicable to heterogeneous porous media is presented. Being a fractal model, it integrates the effects of the many length scales of heterogeneities and can be used for the prediction of fluid flow and mixing during tracer and unit mobility miscible displacements. A random field theory was used to describe the dispersion coefficient in terms of a scaling parameter. The resulting convection-dispersion equation with the scale-dependent dispersion coefficient was solved numerically by a Dual Reciprocity Boundary Element (DR-BEM) technique to generate type-curves of tracer concentration with time. This can be used in conjunction with data from field tracer tests, to determine the characteristic value of representative of a field. A simple equation is provided to calculate the dispersion coefficient at any length scale in terms of the so determined and the field velocity correlation function. The accuracy of the model was tested by comparing its results for a range of values representing asymptotically Fickian dispersion with analytical results and excellent agreement was obtained.
P. 37
Uncertainty Handling Through Scenario-Based Reservoir Modelling
Authors: Bentley M. R. , Woodhead T. J. 
Published: December 2007

Abstract
Quantitative forecasts of sub-surface productivity underpin prospect appraisal and development planning, yet the uncertainties intrinsic to those forecasts are difficult to predict. Moreover, the uncertainties invariably remain commercially significant throughout the field life cycle. This paper supports a case for the application of process-based logic to uncertainty handling, expressed in terms of independent, deterministically designed, concept-based development scenarios. Case studies of scenario-based logic are given, applied to 3-D reservoir modelling and simulation for a new, ‘greenfield’ site in Oman and a mature, ‘brownfield’ asset in Thailand. In both cases, uncertainty ranges are generated which provide a quantitative link between subsurface unknowns and commercial decisionmaking.
Application of Lévy Random Fractal Simulation Techniques in Modelling Reservoir Mechanisms in the Kuparuk River Field, North Slope, Alaska
Authors: Gaynor Gerard C. , Chang Eric Y. , Painter Scott L. , Paterson Lincoln 
Published: December 2007

Abstract
Incorporating a suitable level of heterogeneity into reservoir simulations is necessary for accurate prediction of production rates and final recoveries. Spatial correlation of petrophysical properties, particularly permeability extrema, exerts a profound influence on flow underlying reservoir displacement and depletion processes. Common modelling techniques are founded on Gaussian assumptions for statistical distributions. Such Gaussian-based approaches can inadequately model the permeability extrema that can dominate reservoir performance. However, optimal reservoir management strategies at the Kuparuk River Field require that significant efforts be made to correctly model reservoir behaviour.
This study utilises a new method, Lévy fractal simulation, for interpolating permeability at a former gas injection area now being targeted for oil production. The main producing interval is a diagenetically and mineralogically complex clastic unit. The diagenetic complexity causes difficulties in the lateral modelling of large changes in petrophysical properties observed in near-vertical wells, particularly permeability. Prior efforts at modelling the movement of gas, at typical interwell scales, have met with limited success. In this study, the Lévy technique employs automatic calibration with log and core data for the interwell interpolation of the spatially complex reservoir properties. The Lévy fractal simulations preserve the sharp jumps in reservoir properties observed at stratigraphic boundaries and within reservoir sub-zones. The spatially correlated petrophysical properties are consistent with geologic experience.
A fine-scale permeability model incorporating well conditioning data was built using the Lévy fractal interpolation technique. This model encompassed not only the gas injection area but drillsite patterns immediately adjacent. The model preserves the geometry of the reservoir units so that truncation and onlap relationships are preserved. The permeability extrema in the model are characterised by lateral continuities extending over many grid blocks away from control locations. Porosity was modelled using sequential Gaussian simulation (SGS) in which well porosity logs were used as the primary conditioning data, and the modelled permeability used as secondary conditioning data. The fine-scale model was then used as input in an upscaled dynamic simulator built to test reservoir mechanisms. The model was also useful for prognosing porosity and permeability at proposed well locations. Early drilling results indicate that substantial quantities of producible oil remain in the former gas injection area.
A New Method for the Fast Estimation of Reservoir Performance
Authors: Kuhn J.C. 
Published: December 2007

Abstract
Recent advances in applications of geostatistics to reservoir characterization have produced increasingly sophisticated geological models which have put considerable demands on the engineer's ability to do rapid reservoir performance evaluation. With this motivation in mind, a new method for fast reservoir simulation based on an unconventional formulation has been developed. This formulation has flux-based unknowns, in contrast to more conventional approaches which typically have pressure-based unknowns. For a useful range of conditions, the flux-based unknowns experience little or no variation over time throughout most of the reservoir domain, enabling fast simulations of fluid movement in the reservoir. In conjunction with iterative solvers that dynamically adapt to conditions in the reservoir, this formulation has been used to create a new simulator, designated as FMF (for Flux-based Multi-phase Flow). The FMF algorithm includes a rigorous mass conservation scheme that maintains accurate material balance throughout the entire simulation. Studies of overall accuracy and computational efficiency for a series of case studies have been carried out with the simulator. These studies are based on comparisons with Eclipse, with all computations done on a common platform to facilitate CPU timing studies. For the cases considered, these studies have revealed that the FMF algorithm is approximately one order of magnitude faster than Eclipse, and produces similar results.
P. 171
Modeling Non-Equilibrium Mass Transfer Effects for a Gas Condensate Field
Authors: Wu Wei , Wang Peng , Delshad Mojdeh , Wang Chong , Pope Gary A. , Sharma Mukul M. 
Published: December 2007

Abstract
To assess the effect of non-equilibrium mass transfer on the productivity of a single well producing from a gas condensate field, a model incorporating non-equilibrium mass transfer effects was implemented into an equation-of-state (EOS) compositional reservoir simulator developed at The University of Texas at Austin.
A correlation from the literature was used to account for the effect of variables such as gas velocity and diffusion coefficients on the mass transfer coefficient. However, no mass transfer data were available for gas condensates, so a sensitivity study on the mass transfer coefficient was performed. Several simulations have been performed to evaluate the effects of the non-equilibrium mass transfer on the flow behavior in the region near the wellbore. The results from these runs were compared with those obtained under the local equilibrium assumption. Such comparisons reveal that non-equilibrium phase behavior lead to a reduction in the condensate saturation in the region near the wellbore. The mole fractions for light and heavy components in the oil phase are noticeably different. In the high velocity layers, these differences become more significant. In general, non-equilibrium effects lead to slower reductions in well productivity due to the fact that condensate dropout was reduced near the wellbore.
P. 203
Pitfalls of Injection/Falloff Testing in Coalbed Methane Reservoirs
Authors: Hopkins C.W. , Frantz J.H. , Flumerfelt R.W. , Spivey J.P. 
Published: December 2007

Abstract
Analysis of numerous injection/falloff tests in the field, primarily on coalbed methane wells, has led to a better understanding of the requirements for proper injection/falloff testing. Because most of the formations do not flow prior to testing, test design is difficult and many of the testing procedures must be modified during the test itself. If a testing program is not carefully designed and implemented, erroneous results for permeability and skin factor can be obtained, even though the analysis results appear reasonable.
This paper outlines some general guidelines for injection/falloff testing of coalbed methane and other low permeability reservoirs. Using several field-based examples, potential analysis pitfalls are highlighted including 1) injection above fracture pressure, 2) non-stable reservoir pressure prior to testing, and 3) a poor connection between the wellbore and reservoir. Any of these conditions may result in pressure responses which appear analyzable, but which give misleading or erroneous results.
P. 197
Laboratory Investigation of Injectivity Losses During WAG in West Texas Dolomrites
Authors: Kamath J. , Nakagawa F.M. , Boyer R.E. , Edwards K.A. 
Published: December 2007

Abstract
This study reports injectivity data for the different flow zones present during a Water-Alternating-Gas (WAG) flood. The experiments were carried out on four rock types sampled from the Grayburg dolomite formation in West Texas. We used liquid CO-water, toluene-liquid CO-water and crude oil-liquid CO-water systems to isolate mechanisms and to address wettability concerns.
We found that the injectivity of the chase water zone was comparable to the initial waterflood injectivity, and increased as the trapped CO dissolved. The injectivity of the CO-rich zone was significantly higher than the initial waterflood injectivity. Ambient condition toluene tests and reservoir condition crude tests gave similar results for the water and CO zones. However the crude oil, even prior to any CO injection, exhibited a strong tendency to plug the core samples. We were unable to restore permeability in the plugged up core samples by continuous flushing of different solvents.
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