bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Performance of the Wasson Denver Unit CO2 Flood
Authors: Tanner C. S. , Baxley P. T. , Crump J. G. , Miller W. C. 
Published: December 2007

ABSTRACT
The Denver Unit, located in the Wasson Field of west Texas, is the world's largest Carbon Dioxide Enhanced Oil Recovery (EOR) project. Shell Western E&P Inc. initiated CO2 injection in the Denver Unit in 1983, utilizing CO2 from naturally occurring source fields in Colorado and New Mexico.
Production response to CO2 flooding has been impressive, with over half of the current daily oil production attributable to CO2 injection. In fact, oil production has substantially exceeded- original project performance predictions.
The project was- originally implemented with both a Continuous CO2 injection area and a Water-Altemating-Gas (WAG) CO2 injection area. A comparison of the performance of these two areas has clearly demonstrated the advantages of each injection method, and has led to the conversion of the the Unit to a "Denver Unit WAG" (DUWAG) injection process, which plays on the strengths of both injection schemes.
This paper will cover in more detail the observed production performance of the CO2 flood to date, present a comparison of the Continuous and Water-Altemating-Gas injection processes, and review the design and implementation of the Denver Unit WAG project. The paper will be of interest to companies who are either operating- or preparing to implement CO2 Floods.
Core Wettability Measurement by Dynamic Adsorption
Authors: Torske Lisa , Skauge Arne 
Published: December 2007

ABSTRACT
The standard methods for determination of the wettability of reservoir cores (Amott and USBM) involve displacement of water- or oil, in presence of both the wetting and non-wetting phases.The result may depend on fluid saturations as well as on experimental procedure, causing uncertainties of the measured wettability.
The paper presents an attempt to determine the wettability of the core material independent of the fluid saturations.The method involves contacting the core with a reagent that selectively adsorbs either to the oil-wet- or to the water wet sites of the pore wall.Adsorption tests with several compounds have led to the selection of n-heptanol and methylene-blue as agents for wettability measurements by dynamic adsorption.
The area of oil-wet sites measured by n-heptanol adsorption from brine, is found to increase for silanized cores.Correspondingly, the fractional water-wet area of the core measured by methylene blue adsorption is reduced for silane-treated Berea cores compared to untreated cores.Wettability measurements are also performed on various cores from North Sea oil reservoirs.
Numerical Simulation of Hot-Water and Flue-Gas Injection Under Typical North Sea Reservoir Conditions
Authors: Fossum Bjorn , Blaker Tore , Brendsdal Egil , Johansen Thormod , Throndsen Torbjørn 
Published: December 2007

ABSTRACT
This paper describes numerically simulated reservoir performance during the injection of hot water and flue gas at North Sea reservoir conditions. Studies of hydrocarbon/water phase behaviour at elevated temperatures and reservoir simulations showed that a hot water flood in a light-oil reservoir could increase the recovery by 3-9 % of the- original oil in place. A theoretical study of flue gas injection concluded that minimum miscibility pressure (MMP) for this gas was equal to MMP for an oil/nitrogen system. A nitrogen displacement was estimated to be immiscible at initial reservoir pressure and temperature, but miscibility would be developed at a slightly higher temperature.
The results predict that the combination of hot water and flue gas injection has a substantial potential for increasing the recovery from light-oil reservoirs.
Evaluation of Surfactants for CO2 Mobility Control in Dolomite Reservoirs
Authors: Kuehne D. L. , Frazier R. H. , Cantor Jeremy , Horn Willie 
Published: December 2007

ABSTRACT
Laboratory studies were conducted to find the best surfactant for generating CO2 foam in the presence of residual oil for two dolomite reservoirs. Conventional anionic and nonionic surfactants did not foam very well in core tests at reservoir conditions. The poor performance was attributed to the oil-wet nature of the dolomite cores. A new surfactant formulation was developed that alters wettability and has much better oil tolerance. CO2 foams were generated easily with the new formulation and were more stable. Field tests are planned to demonstrate improvement of sweep efficiency using the new surfactant.
Evaluation of surfactants for mobility control applications involved a series of tests that measured brine compatibility, bench foam height, flow resistance in corefloods, and adsorption on reservoir rock. Bench foam tests, often used for surfactant screening, were unable to predict the effects of oil in the corefloods. Even the low oil saturation remaining after immiscible- or miscible CO2 injection was detrimental to foam generation. The new surfactant formulation works over a wide range of brine salinities, controls CO2 mobility better than conventional surfactants, and has moderately low adsorption on dolomite rock.
Effects of Gas and Liquid Velocity on Steady-State Foam Flow at High Temperature
Authors: Osterloh W. T. , Jante M. J. 
Published: December 2007

ABSTRACT
Researchers have recently determined that capillary pressure plays a dominant role in controlling the texture, and hence the rheology, of foam flowing through a porous matrix. Of particular interest, the capillary pressure was found to reach a characteristic value, the limiting capillary pressure, at a relatively high fractional flow of gas, fg. If fg was increased further, the capillary pressure was reported to remain at the limiting value, the foam texture was coarsened, the liquid saturation remained constant, and the steady state foam pressure gradients were proportional to liquid velocity and independent of gas velocity.
The experiments in these recent reports were all performed at low temperatures. We report the results of foam flow experiments conducted at 150°C. The experiments were designed to characterize steady-state nitrogen foam flow by measuring pressure gradients in a 6.2 μm2 sandpack over a wide range of gas and liquid velocities and fractional flows.
We found that steady-state pressure-gradient responses, and hence foam rheology, could be divided into two distinct environments that were characterized by the value of fg. Interestingly, the pressure gradient response to gas and liquid velocity in one environment was exactly reversed in the other. In one environment, where fg was less than 0.94, the pressure gradient was dependent on gas velocity and was reasonably independent on liquid velocity. The pressure gradients were proportional to gas velocity to about the 0.31 power. In the other environment, where fg was greater than 0.94, the pressure gradients were dependent on liquid velocity and were reasonably independent on gas velocity. The pressure gradients were proportional to liquid velocity to about the 0.33 power. The transitions that occurred at fg of 0.94 likely correspond to the point at which the limiting capillary pressure was reached. The liquid saturation was low and nearly constant, about 0.06, in both flow environments.
At very high gas velocities, when fg was greater than about 0.998, steady-state flow was replaced by a chaotic-like flow in which the pressure gradient fluctuated and fell to very low levels in downstream sections of the sandpack.
Properties of Flowing Foam in Porous Media Containing Oil
Authors: Kristiansen T. S. , Holt Torleif 
Published: December 2007

ABSTRACT
The spreading characteristics of a gas/oil/surfac-tant solution system depend on the interfacial tensions involved. This work indicates that systems having interfacial tensions giving spreading oil act more deleterious to foam stability as compared to nonspreading oil systems. The effect was demonstrated for Berea sandstone by changing the oil when the type of surfactant was unaltered and by changing the type of surfactant when the oil used was the same. For a slightly oil-wet reservoir rock a similar trend in foam properties was observed when the type of oil was changed.
In an oil spreading system the flow resistance of foam was found to increase with increasing concentration of the surfactant solution.
Phase Behavior Modeling Techniques for Low-Temperature CO2 Applied to McElroy and North Ward Estes Projects
Authors: Fong W. S. , Sheffield J. M. , Ehrlich R. , Emanuel A. S. 
Published: December 2007

ABSTRACT
This paper describes a technique to model the behavior of three phase low temperature CO2 systems using two phase PVT algorithms, and its application to two field CO2 projects.
An approximate tuning procedure has been developed for using a two phase equation of state to characterize the displacement behavior of CO2 in the three phase domain. This characterization technique results in good prediction of laboratory slim tube displacement tests and the minimum miscibility pressure (MMP) for both pure and impure CO2 streams. Laboratory corefloods and field scale displacements can also be modeled to a practical level of accuracy. With this pseudo two-phase representation, complex three-phase flash calculations and the need for four-phase relative permeabilities are avoided.
This approach was used in forecasting the North Ward Estes CO2 project. Volume of mixing effects characteristic of low temperature CO2 systems are modeled in a vertical, fine resolution geostatistical cross section with a compositional simulator. Reasonable agreement with observed field performance is obtained. An immiscible CO2 huff-n-puff test at the McElroy field was also modeled, using a 2-D radial, compositional model. The cross section was derived from geostatistics. The simulation also provided a good approximation of field observation.
A Numerical Model for Predicting Alkali Slug Migration in Chemical Processes
Authors: Labrid J. C. , Le Thiez Pierre , Minssieux Louis 
Published: December 2007

ABSTRACT
Use of alkaline agents in enhanced oil recovery is recommended in association with other chemicals such as surfactants and polymers, in- order to take benefit of synergistic effects which improve the cost efficiency ratio of chemical processes. One critical factor in these processes is to predict the transport of the alkali from the injection well to the production well. That is the aim of the flow model described in the paper.
The main physicochemical phenomena responsible for alkali consumption are taken into account in the model, i.e.
the reaction between alkali and acid components of crude oil,
the reactions of injected alkali with reservoir brine and minerals,including dissolution and ion exchange phenomena.
As far as dissolution processes are concerned, a previous work has shown that they are kinetically dependent, even at field scale, and that the thermodynamic equilibrium assumption is not valid. Kinetic equations are used that take into account the inhibiting effects of compounds formed during dissolution.
A methodology is developed to obtain the parameters needed for numerical simulation. This methodology is applied to natural consolidated sandstone rocks containing clay minerals. A satisfactory agreement is observed between simulation results and experimental data provided by batch tests and flow experiments. The model can be used to calculate the transport of the alkali slug at field scale and to help the selection of operating parameters such as type and concentration of alkali, and size of the alkaline slug.
Foam Treatment of Producing Wells To Increase Oil Production at Prudhoe Bay
Authors: Krause R. E. , Lane R. H. , Kuehne D. L. , Bain G. F. 
Published: December 2007

Abstract
Since May of 1989, the Prudhoe Bay oil field has been on decline. No longer limited by the capacity of the TransAlaska Pipeline- or state offtake restrictions, daily oil production is now restricted primarily by the amount of gas reinjection capability that currently exists at the North Slope.
This paper describes the results of several Prudhoe Bay field trials performed in 1991 in the Eastern Operating Area (EOA) by ARCO Alaska, Inc. The objective of these field trials was to assess the effectiveness of foamable EOR surfactants in preferentially reducing the gas production through direct treatment of high gas/oil ratio (GOR) producing wells. Three different methods of delivering the surfactant into the producing interval were tried. One method, the injection of foam, preformed at the surface using nitrogen, caused a significant GOR reduction which translated into an increase in oil production in the target well for a period of several weeks.
Work is ongoing in this area to determine the effectiveness and economic potential of these foam treatments.
Reduction of Oil and Water Permeabilities Using Gels
Authors: Liang J. , Sun H. , Seright R. S. 
Published: December 2007

Abstract
Several previous researchers reported that polymers- or gels can reduce permeability to water more than to oil. However, a plausible explanation for the phenomenon is not yet available. This property is critical to the success of gel treatments in production wells if zones cannot be isolated during gel placement. We examined how different types of gels reduce oil and water permeabilities in Berea sandstone. The gel formulations that we investigated included (1) resorcinol-formaldehyde, (2) Cr3+(chloride)-xanthan, (3) Cr3+(acetate)-polyacrylamide, and (4) colloidal silica. Several new methods were applied to obtain a better understanding of why gels can reduce water permeability more than oil permeability. First, before gel placement in cores, multiple imbibition and drainage cycles were performed in both flow directions. Results from these studies established that hysteresis of oil and water relative permeabilities was not responsible for the behavior observed during our subsequent gel studies. Second, several gels clearly reduced water permeability significantly more than oil permeability. Whereas previous literature reported this phenomenon for polymers and "weak" polymer-based gels, we also observed the disproportionate permeability reduction with a monomer-based gel (resorcinol-formaldehyde), as well as with both "weak" Cr3+(chloride)-xanthan and "strong" Cr3+(acetate)-HPAM gels. In contrast, a colloidal-silica gel reduced water and oil permeabilities by about the same factor. Residual resistance factors for several gels were found to erode during multiple cycles of oil and water injection. In spite of this erosion, the disproportionate permeability reduction persisted through the cycles for most of the gels. Studies using both oil and water tracers provided insight into the fraction of the pore volume occupied by gel. The strongest gels appeared to encapsulate the- original residual oil saturation—thus rendering the residual oil inaccessible during subsequent oil flooding.
Comparison of Conventional Cyclic Steaming and Steamflooding in a Massive, Dipping, Midway Sunset Field Reservoir
Authors: Harrigal R. L. , Clayton C. A. 
Published: December 2007

ABSTRACT
Two thermally enhanced oil recovery methods, cyclic steaming and steamflooding, have been investigated by means of numerical modeling for a massive, dipping, Midway Sunset Field reservoir. Comparative economics have been evaluated for the development alternatives.
The results of the investigation indicate that ultimate recovery efficiency is not sensitive to the method of steam delivery to the reservoir. Cyclic steaming methods recovered the same percentage of- original oil in place as did steamflooding. The cyclic operations required several times longer than steamflooding to reach the same ultimate recovery efficiency.
On a steam utilization efficiency basis (oil to steam ratio), cyclic steaming with small steam slug volumes proved to be the most efficient recovery method. As the rate of steam injection increased, the steam utilization efficiency decreased, regardless of the manner in which steam was delivered to the reservoir.
Despite having the poorest steam utilization efficiency, steamflooding provided far superior economics as compared to conventional low- or moderate slug volume cyclic steaming. This is directly attributable to steamflooding having the fastest rate of increase in average reservoir temperature and therefore the greatest rate of net recovery as compared to the alternatives investigated. Steamflooding exhibited a much quicker payout of development capital and a greater present value return per dollar invested.
Development Strategies for a Heavy-Oil (3,500 cp) Reservoir at a Depth of 2,100 ft (ss)
Authors: Singh K. S. 
Published: December 2007

Abstract
The Cruse ‘E’ reservoir in the Guapo field is located at a depth of 2100 ft., in the Southern Deltaic Basin of Trinidad. The reservoir fluid is 14° API with a viscosity of 3500 cp. Production is by thermal stimulation encompassing several operating strategies which were adopted and evaluated. The context of the evaluation includes areal and vertical sweep efficiencies relative to recovery per unit time.
This paper therefore has as its objective, the discussion of the following strategies and their impact on production efficiency:
Well spacing and pattern size. Reservoir heating and pressure distribution. Injection rates and pressures. Economic phasing of investment. Energy losses due to high friction in production facilities.
Laboratory Studies of Parameters Involved in Modeling Microbial Oil Mobilization
Authors: Bryant R. S. , Bertus K. M. , Stepp A. K. , Chang Ming-Ming , Chase K. L. 
Published: December 2007

ABSTRACT
Microbial methods for increasing oil recovery are potentially cost-effective even at relatively low crude oil prices. Microbial formulations can be applied in a variety of methods including permeability modification treatments and microbial-enhanced waterflooding. The flexibility and potential cost-effectiveness of the technology make it attractive, but further understanding of the transport mechanisms of microorganisms and the development of a sound engineering methodology for optimizing microbial formulations and injection strategies are needed to realize its potential.
Work on this project has included the continuing development of a three-dimensional, three-phase, multiple-component numerical model to describe microbial transport phenomena in porous media. Laboratory data were used to develop correlations and mathematical models for specific phenomena; linear coreflooding data were used to test the simulator in an iterative process. The simulator development and laboratory testing aspects of this project were coordinated so that the results could be used to design other laboratory experiments to clarify and quantify certain physical and chemical effects. An accurate reservoir simulator for MEOR methods can best be developed through an integrated program of acquisition of laboratory and field data with the feedback loop being the reservoir simulation model.
From our concepts of the hydrodynamics, physics, chemistry and microbiology of MEOR processes, microbial parameters incorporated into the microbial transport model include: (1) microbial growth and decay; (2) microbial deposition; (3) chemotaxis; (4) diffusion; (5) convective dispersion; (6) tumbling; and (7) nutrient consumption. Laboratory experiments were conducted to obtain actual data for the simulator regarding microbial growth and decay, nutrient consumption, microbial deposition, convective dispersion, and diffusion. Unsteady-state relative permeability measurements using microbial formulations were made to determine the effects of microbial metabolites on fractional fluid flow in porous media. Mechanisms considered to be important for oil recovery include changes in microscopic properties such as interfacial tension, wettability, and adsorption that govern oil mobilization and affect fractional flow and relative permeabilities. Other oil recovery, mechanisms traditionally associated with fluid flow changes include polymer and biomass production by microorganisms. This paper describes the laboratory investigations conducted in our ongoing efforts to incorporate oil recovery mechanisms by microorganisms into the simulator. Computer tomography studies demonstrated that gas production by microorganisms can reduce residual oil saturation in porous media. After conducting field-scale numerical simulation studies using data from relative permeability experiments, it was determined that microbial treatment could improve oil recovery over waterflooding alone.
New Field Simulation Strategy With Detailed Element Models and Flux Boundary Conditions: Statfjord Field Case Study
Authors: Aadland Atle , Henriquez Adolfo 
Published: December 2007

Abstract
Full field reservoir simulation has been adequate for reservoir management purposes for more than a decade long production history of the Statfjord Field in the North Sea. At the present stage, the beginning of production decline, the simulation strategy needs to be changed. A full field model would be unmanageably large if the geological detail needed to understand the issues relevant to further recovery enhancement is included. Most of the remaining reserves will be recovered by sidetracking and infill drilling. The remaining oil has then to be mapped carefully using both the geological information obtained during these years together with a reliable history matching. In this paper, a methodology has been developed for history matching regions with very detailed geology, while taking into account the interaction with the whole reservoir. The method involves writing to a history file the fluxes between the cells at the boundaries of the regions of interest and the rest of the reservoir. This methodology has been tested for the Statfjord Field. The CPU-time was reduced by 35 percent compared to a conventional method. The insights obtained were achieved in a shorter time. The fluid flow processes are better represented and the reservoir description obtained is more representative. Furthermore, the element model is now run in prediction mode as a tool for reservoir management and planning well activities. Thus a new simulation strategy, based on history matched, geologically detailed element models and preserving the interaction with the whole reservoir, has been proved useful.
Interactive Visualization of 3D Complex Geological Structures
Authors: Pajon J-L. , Rainaud J-F. 
Published: December 2007

AbstractThe aim of this paper is to show how simple computer graphics tools can be used to visualize complex geological configurations. Once that a geologist has modeled various geometries by assembling structured grids, these tools offer him the possibility to explore them in various interactive ways. Different visualization modes give a faithful representation of these data, and direct manipulation with a mouse of the most important parameters that govern this representation allows a fast, easy, attractive and enriching dialogue between the user and its simulation. Some tools for determining and visualizing the intersection of two grids are also available.
Hypertext-Based GUI for Reservoir Engineering Software
Authors: Blanc Georges , Givaudan Abel , Betoin J-P. , Van Den Zande Didier , Vives Eric 
Published: December 2007

Abstract
This paper describes the development of two software tools:
A Graphical User Interface (GUI) based SCREEN MANAGER; A HYPERTEXT based Language;
to be used to build PRE and POST processors of reservoir engineering software.