bluuebunny/crossref_metadata_2025_split huggingface dataset:
Selective Conformance Control in Heterogeneous Reservoirs Using Unstable, Reactive
Authors: Thompson K.E. , Kwon O. 
Published: December 2007

Abstract
This paper examines a conformance control technique in which gel is placed into a heterogeneous porous medium by first injecting a high-viscosity uncrosslinked polymer solution and second, a low viscosity crosslinker. The latter step causes an unstable displacement to occur and allows the crosslinker to flow selectively into high-permeability strata. A visual flow cell was used to test the procedure, and complete fluid diversion was achieved in a dual-zone medium with a 4:1 permeability ratio. In addition, experiments and numerical simulations were used to study fundamental changes in viscous fingering due to the crosslinker-polymer reaction. When the crosslinking reaction is fast enough so that it occurs during injection, the viscous instability becomes somewhat damped, resulting in less distinct fingers and a nearly plug-flow displacement in some cases. The differences are because gelation causes a large pressure gradient to form just behind the displacement front, whereas unreactive fingering is characterized by the formation of a small pressure gradient within the fingering zone.
P. 195^
Effect of Pore Structure and Residual Oil on Polymer Bridging Adsorption
Authors: Zaitoun A. , Chauveteau G. 
Published: December 2007

Abstract
In a preceding study, we observed a new type of polyacrylamide flow-induced retention in core experiments simulating nearwellbore flow conditions. This retention is due to the bridging of pore throats by adsorption of macromolecules previously stretched under elongational flow. It was shown to occur at high shear rate only in low-to-medium permeability granular packs (up to k = 1200 mD in our test conditions) and lead to progressive but severe plugging. Further investigations on this polymer retention process are reported here. To study the effect of heterogeneity in the pore structure, we ran experiments with mixed-grain granular packs and with Berea sandstones. Heterogeneity is unfavorable for the bridging adsorption process, because the time for relaxation of stretched macromolecules between two elongational zones is increased. Moreover, when there is a sufficient fraction of pore throats too large to be bridged by stretched macromolecules, the process leads to maximum stable values for both mobility and permeability reductions above a critical injection rate. In Berea sandstones, bridging adsorption occurs first in the smallest pore channels. Then, as the injection rate increases, more and more pore channels get bridged up to the maximum level mentioned above.
The presence of residual oil in the core reduces the average size of the pore channels for the aqueous phase. It is thus a factor that enhances the bridging adsorption process. In granular packs, the onset of polymer bridging adsorption occurs at lower injection rate when residual oil is present in the core. Moreover, for a given injection rate, the intensity of core plugging is higher at than at 100% water saturation. Since Berea sandstones are strongly water wet, residual oil reduces drastically the hydrodynamic pore size. For low-permeability Berea at residual oil saturation and low injection rate, we observe progressive plugging due to polymer retention upstream pore throats whose effective size is smaller than macromolecule size. At higher injection rates, this hydrodynamic retention vanishes, and the bridging adsorption process becomes dominant. Bridging adsorption induces the same behavior as without residual oil, i.e. a progressive bridging of pore channels up to a maximum level due to the existence of very large pores that cannot be bridged by stretched macromolecules.
P. 209
Adsorption of Linear Flexible Polymers During Laminar Flow Through Porous Media:
Authors: Zitha P.L.J. , van Os K.G.S. , Denys K.F.J. 
Published: December 2007

Abstract
Polymer solutions for water control are usually injected at a relatively high concentration (i.e. the semi-dilute regime). During placement entangled polymer chains can be retained by a collective adsorption and bridging mechanism. This results in polymer loss near the face of the wellbore and in an inefficient reduction of water relative permeability.
The data on the effect of collective adsorption of entangled chains are scarce in literature. In this experimental study we are concerned with the influence of polymer concentration and permeability on the retention of high molecular weight non-ionic polyacrylamide (PAAm) during flow in granular porous media (packing of silicon carbide). Thus far we have made the following observations.
At low polymer concentrations (the dilute regime) polymer injection leads to a gradual increase in pressure drop. Finally the pressure drop levels off to a plateau indicating steady-state flow. It is known that the delay in the polymer displacement front is related to the amount of adsorbed polymer. At higher concentrations (semi-dilute regime), however, no steady state flow seems to be reached within the duration of the experiments. Furthermore the residual flow resistance, determined by water flow following polymer, increases with polymer concentration. These effects can be explained by a mechanism of collective retention of entangled chains, which are adsorbed and bridge over pore constrictions.
P. 225
Smart Foam to Improve Oil Recovery in Heterogeneous Porous Media
Authors: Tsau Jyun-Syung , Yaghoobi Hossein , Grigg Reid B. 
Published: December 2007

Abstract
The addition of surfactant in brine during a water alternating with CO2 (WAG) injection or co-injection with CO2 process has proven to produce foam that reduces CO2 mobility. Laboratory experiments have shown that some surfactants generate "smart" foam that selectively reduces mobility of CO2 by a greater fraction in lighter than in lower permeability cores. The occurrence of such an exciting property in foam displacement and its application to improving oil recovery in heterogeneous porous media are discussed in this paper.
In our latest work that experimentally simulated the heterogeneous characteristic of reservoirs, we used composite cores that contain coaxial zones of high and low permeability either in capillary contact or isolated from each other. Experiments were performed on core systems both with and without oil saturation. Smart foam was injected into these core systems and its performance was determined by the breakthrough time of CO2 and fluid recovery in each well-defined permeability region.
Our results demonstrate that smart foam is useful in correcting nonuniform frontal displacement due to the heterogeneity of a reservoir formation. Smart foam is also very effective in displacing the oil-a benefit frequently overlooked by researchers testing the foam aspects of mobility control.
P. 247
Effects of Foam Quality and flow Rate on CO2-Foam Behavior at Reservoir Conditions
Authors: Chang Shih-Hsien , Grigg Reid B. 
Published: December 2007

Abstract
This paper reports a series of steady-state CO2-foam flow experiments performed at reservoir conditions of 101 F and 2100 psig. The effects of foam quality and flow rate on foam flow behavior were investigated. The foam experiments were conducted by injecting CO2 and surfactant solution simultaneously into a core saturated with surfactant solution at various total flow rates and foam qualities (CO2 fractions). A commercial surfactant (Chaser TM CD 1045) was used at 2500 ppm concentration in a 4 wt% synthetic brine.
Our results have shown that the foam mobility (total mobility of CO2/surfactant solution) decreased with increasing foam quality ranging from 20% to 80% for flow rates of 4.2, 8.4, and 16.8 cc/hr. The foam resistance factor increased with increasing foam quality ranging from 33.3% to 80% for flow rates of 4.2, 8.4, and 16.8 cc/hr. A minimum foam resistance factor was found between foam qualities of 20% and 33.3% for flow rates of 8.4 and 16.8 cc/hr. The foam mobility increased with increasing flow rate ranging from 4.2 to 16.8 cc/hr for foam qualities of 20%, 33.3%, 50%, 66.7%, and 80%. Also, the resistance factor decreased with increasing flow rate ranging from 4.2 to 16.8 cc/hr for foam qualities of 20%, 33.3%, 50%, 66.7%, and 80%.
P. 265
Foam/Oil Interations at Reservoir Conditions
Authors: Mannhardt K. , Novosad J.J. , Schramm L.L. 
Published: December 2007

Abstract
Foam mobility reduction factors (MRF's) were measured through foam floods in Berea and North Sea sandstone cores with three conventional surfactants (Chaser GR-1080, Enordet X-2001, and Dow XSS-84321.05), either by themselves or mixed with a fluorinated surfactant (Fluorad FC-751), at 75 C and 13.8 MIPa. Several other experimental methods were also used to evaluate possible correlations in foam performance: bulk foam stability, etched-glass micromodel observations, and interfacial parameters.
The presence of oil reduced foam MRF's of different surfactants to different degrees. Excellent MRF's were still attained with Chaser and Enordet in the presence of residual oil, while Dow was ineffective. The addition of Fluorad enhanced the oil tolerance of Chaser and Dow foam, but did not provide any benefit to Enordet. MRF's measured in an oil-free North Sea reservoir core were lower than in Berea core, but were affected relatively less by oil. The tested foams exhibited oil transporting properties. Each foam adjusted to its own residual oil saturation and corresponding level of mobility reduction. Foam performance in core floods did not correlate in general with predictions based on the other experimental methods.
P. 287
A Feasible New Flue Gas CO2 Recovery Technology for Enhanced Oil Recovery
Authors: Iijima Masaki 
Published: December 2007

Abstract
Mitsubishi Heavy Industries, Ltd. (MHI) and The Kansai Electric Power Co., Inc. have been developing flue gas CO recovery technology since 1990 as a measure against Global Warming. As a result of the research and development efforts which have now been carried out for seven years, the new energy-efficient solvents KS-1 and KS-2 which are less corrosive and cause less degradation than those used previously, have been developed. In addition, a research has produced a new packing, KP-1, that can reduce the size of CO2 absorbers and the horsepower requirements of flue gas blowers. The pilot plant, which is located in Nanko Power Plant of The Kansai Electric Power Co., Inc. has been used for the pilot tests of The Central Electric Power Council targeted for all utility companies in Japan and MHI since the fiscal year of 1995. The newest developments are presented in this paper, as well as a cost study of power plants flue gas CO2 recovery and compression to evaluate application of the technology for enhanced oil recovery. This new flue gas CO2 recovery technology, in comparison with the conventional technology (Monoethanol Amine Process), dramatically reduces the CO2 recovery cost. A cost evaluation study reveals, if the power plant is located near the oil field (a couple of hundred kilometers), it is feasible to supply CO2 at 1 USD/MSCF or below, while if the fuel (gas or coal) cost is around 0.5 USD/MMBTU, CO2 recovery and compression cost can be reduced to 0.7 USD/MSCF. These CO2 delivery costs are equivalent to CO2 delivery cost in the United States for enhanced oil recovery.
P. 333
Bu Attifel Field (Libya): Improvement of the Microscopic Efficiency of Oil
Authors: Causin Emilio , Passucci Claudio , Rossi Elio , El-Ageli Ibrahim Salem 
Published: December 2007

Abstract
The Bu Attifel field is a giant reservoir located in the Sirte Basin in the Libyan desert. It was discovered in 1967 at an average depth of 4,200 m s.s.l. and produces volatile oil (41 API) from continental sandstone. The crude is paraffinic with wax content of 36.7% and high pour point temperature (39 C).
A water injection project was set up in 1974. Since water production has increased considerably in the last five years, the feasibility of an EOR tertiary process is being studied to improve the final oil recovery. The miscibility of three different gasses (carbon dioxide, lean gas and enriched gas) with the reservoir oil was evaluated through lab experiments performed at the average reservoir temperature (145 C). At the current reservoir pressure (40.5 MPa), the lean gas enriched with liquefied petroleum gas (LPG) appears to be the most efficient solvent.
This paper describes lab experiments carried out to evaluate the microscopic efficiency of oil displacement using enriched gas under current reservoir conditions.
Several tests were carried out using reservoir core plugs, selected on the basis of Nuclear Magnetic Resonance Imaging analysis. Three different reservoir conditions (residual oil saturation, intermediate oil saturation and irreducible water saturation) were simulated.
Most of the tests demonstrated the very high displacement efficiency of the enriched gas as regards final oil recovery. Gravitational forces slightly influenced oil recovery, while an important role was played by rock texture when samples at residual oil saturation were considered.
P. 343
Screening and Evaluation of Modified Starches as Water Shutoff Agents in Fractures
Authors: Barrufet Maria A. , Burnett David , Macauley Julian 
Published: December 2007

Abstract
In the past, starch hydrocolloids have not been effective alternates to partially hydrolyzed polyacrylamides, copolymers and xanthan gum polymers as water shutoff agents in fractures and in matrix flow configurations. Poor injectivity and questionable stability have prevented their use in profile control applications. However, chemically modified starches have properties suitable for improved recovery technology. They do not hydrolyze in harsh saline environments, are made more resistant to biodegradation, and because of their wide spectrum of molecular weight distributions can be tailored to specific lithologies. The development of new materials with superior functionality and reliability has been among the most important technological advances that can significantly increase oil and gas reserves and reduce production costs.
Chemically and/or physically modified starch polymer samples were subjected to preliminary screenings involving rheological tests, sedimentation tests, and stability tests at varying pH and temperature. The samples passing these tests were selected for core flow testing.
The functionality of a new generation of modified starches was evaluated for profile control applications in matrix and in fracture flow configurations.
A new type of fractured core cell was designed and constructed for testing the polymer samples. The device allows the aperture of the fracture to be set independently during the experiment.
Results to date in the evaluation of modified starches are very encouraging. Specific materials have been identified that have the necessary stability under reservoir conditions for extended time periods. Testing in porous media indicate that certain types of the polymers have sufficient injectivity to allow propagation out into the reservoir matrix. Crosslinked polymer gel systems indicate that the modified starches may offer an alternative to currently used polyacrylamide, particularly for lower temperature systems, because of lower reaction times and adequate retention properties in porous media and in fractured core systems.
P. 363
Role of Diffusion Mass Transport in Design of Profile Correction Methods Based on
Authors: Lakatos I. , Lakatos-Szabo J. , Kosztin B. 
Published: December 2007

Abstract
The diffusion of different component of self-conforming phases injected sequentially into the reservoir may influence significantly the efficiency of profile correction in the vicinity of wells. Unfortunately, the possible role of diffusion in such procedures either is not detailed in the literature or itis considered as a negative of mechanism. Therefore the laboratory studies were focused on analysis of diffusion transport of Cr(III) and Cr(VI) ions in polymer/silicate gels used routinely for water shut-off treatment at the Hungarian oil fields. The effective diffusion coefficient, break-through time and ion retention capacity were determined as a function of the geometry, temperature and composition of gel. It was found that the effective diffusion coefficients were very close to the value characteristic in aqueous solutions and they are proportional with the radii of hydrated ions. The high retention of Cr(III) ions in gels was attributed to in-situ chemical reactions. mechanical entrapment and sorption. The diffusion mass transport of chromium ions could be described by the Fick's I. law in the equilibrium state.
It was found that the diffusion coefficient decreases, while the break-through time and ion retention increase with the solid content of gel. The relative effect of polymer is greater by an order of magnitude than that of the silicate content. The influence of gel components can be interpreted by a diffusion model elaborated originally for porous systems. It was also shown that the polymer concentration is mostly effective in increasing the tortuosity, while in case of silicate content both the porosity and the tortuosity must be considered. The laboratory experiments provided valuable information and data to design efficient profile correction and containment technologies in enhanced oil recovery and environmental protection.
P. 375
Polymer Transport and Rheological Properties for Polymer Flooding in the North Sea
Authors: Osterloh W.T. , Law E.J. 
Published: December 2007

Abstract
The Captain field in the North Sea UKCS is a highly viscous crude accumulation produced via waterflooding with extended reach horizontal wells. Captain's high oil-water mobility ratio and exceptional reservoir quality make it an ideal candidate for improved oil recovery by polymer augmented waterflooding. Polymer storage tanks and subsea polymer flowlines were included in the design and build of the Captain facilities to simplify future implementation of a polymer flood pilot.
Offshore logistical considerations led to the selection of liquid hydrolyzed polyacrylamide (HPAM) as a basis for the polymer flood design. We report in this paper the methods and results obtained from a series of laboratory studies undertaken to identify HPAM's that could be used at Captain and to provide data for reservoir simulation input. This work, conducted by the Operator and two polymer vendors, included coreflood tests, scaled polymer mixing tests, and polymer shear degradation tests.
Although good viscosity yield, low polymer retention, and good coreflood oil recoveries were obtained with HPAM's, the solutions caused face plugging of Captain cores. Using a membrane filtration method to quickly screen new products, both vendors developed improved HPAM's that were judged suitable for use in the Captain reservoir. Results of the shear degradation experiments indicated that shear degradation should be insignificant in tubulars at field design flowrates, but possibly substantial at the sandface.
P. 385
A Study of the Chemical Interactions Between Brine Solutions and Dolomite
Authors: Zou B. , McCool C.S. , Green D.W. , Willhite G.P. 
Published: December 2007

Abstract
Injecting gelant to change the flow characteristics of a reservoir is a viable improved oil recovery technique. Many gel systems are affected by the solution pH in that gel time is pH dependent. The treatment of carbonate reservoir rock is of particular concern because 1) fluid-rock interaction can alter the pH of the injected solution, moving the pH away from the design value and 2) dissolution of carbonate can increase the divalent ion concentration which can affect the gel behavior.
In this study, the interaction between injected potassium chloride brine and dolomite was investigated through displacement experiments in dolomite cores and mathematical modeling based on equilibrium thermodynamics. Parameters varied were pH of the injected solution, flow rate, and the common ion effect through variation of the calcium and magnesium ion concentrations in the injected solution. Core effluent values of pH and concentrations were measured. A geochemical model was used to predict equilibrium pH and concentrations, as well as the amount of dolomite dissolved. The model was compared to the experimental displacement data for the conditions wherein equilibrium was achieved. All model parameters were obtained from literature equilibrium data and were not dependent on curve fitting of the experimental data. Experiments at different flow rates established conditions in which equilibrium was achieved in the core.
The injected solution pH was varied between values of 2.6 and 11. The corresponding measured effluent pH values and simulated results could be divided into three stages. When the injected solution pH was less than 4, the effluent pH was much higher than the injected pH and increased with increasing injected pH. For injected pH values between 4 and 10, the effluent pH was almost constant at a value of 10. At injected pH values above 10, the effluent values were nearly equal to the injected values. At the lowest pH stage, effluent concentrations of Ca and Mg decreased exponentially as pH was increased. In the middle stage, the divalention concentrations were almost constant and not a strong function of pH.
When Ca and Mg were present in the injected solution, the dissolution of dolomite was depressed and effluent pH was lower compared to the cases where Ca and Mg were not in the injected solution. For a specified total divalent ion concentration in the injected solution, the presence of both Ca and Mg had a larger effect on equilibrium pH than did either species individually.
Pressure measured along the core during the displacement showed that dissolution of dolomite had an insignificant effect on rock permeability for the conditions of these experiments.
P. 397
Understanding Injectivity in Heterogeneous Reservoirs
Authors: Pizarro Jorge O.S. , Lake Larry W. 
Published: December 2007

Abstract
This paper introduces a novel approach to quantify the dependence of injectivity on the heterogeneity and auto correlation of the reservoir permeability distribution. The mathematical formulation of the problem was derived for two geometries representing a vertical cross section and a five-spot pattern. The heterogeneity is modeled by stochastically generated permeability distributions. The scaling of the governing equations, by inspectional analysis, generates a minimal set of dimensionless groups that is able to describe fracture-free injectivity in heterogeneous permeable media. The scaling procedure was validated against available analytical solutions and the importance of each dimensionless group on the dimensionless injectivity evaluated with an extensive set of numerical experiments. The results obtained provide a better understanding of how vertical well injectivity depends on heterogeneity and gives insight into why injectivity calculated from a core permeability average is frequently different from the injectivity manifested by the well in question.
P. 421