bluuebunny/crossref_metadata_2025_split huggingface dataset:
Air/O2 Fireflood: Comparison of Field-Scale Performances and Economics
Authors: Petit H. J-M. , Valentin E. P. , Desmarquest J-P. 
Published: December 2007

ABSTRACT
A comparison of oxygen and air fireflooding is presented from the technical and economic points of view for three specific applications produced by in--situ combustion.
In order to evaluate the economic interest of using of oxygen instead of air, a technico–economic assessment was made of the supplying of oxygen. In the three cases examined, supplying pure oxygen at wellhead pressure is always at least as economical as air compression with an equivalent oxygen flowrate. It is all the more advantageous as the flowrate is high and the injection pressure is low in the range examined (10 to 30 MPa) and considering the development strategies used in this study. However, the difference between the two techniques is sufficiently small to take into consideration the implementation conditions and performances of each type of gas in the recovery process itself.
3D field–scale combustion simulations and analytical calculations were carried out to evaluate the real technical advantages and disadvantages of the enriched–air combustion process for three idealized applications. This study includes the effect of CO2 dissolution (O2 combustion) and the water injection strategy (wet combustion, following water drive) on the sweep efficiency.
The technical part of the paper leads to the following main conclusions: For a thin heavy–oil reservoir, it has been demonstrated that it is not possible to use air in a 6.25 ha (15.4 acres) inverted five–spot because of the air injectivity limitation. Oxygen clearly has a technical advantage in this case.On the contrary, injection of oxygen instead of air is not recommended for waterflooded or steam–stimulated shallow reservoirs.Based on results for one inverted five–spot, it has been found that scavenging of the oxygen fill–up behind the burn–front is not detrimental to the oxygen fireflood process when followed by waterflooding. By comparison with wet oxygen combustion, this technique may lead to higher recovery factors at slightly higher technical costs.Regarding the field developments examined, O2 wet combustion (simultaneous O2 and water injection) is definitely the most efficient process for deep heavy–oil reservoirs.
Finally, the various processes and injection strategies applied to the three cases examined were compared from an economic point of view, which considers O2/air production costs, recovery and field costs including the additional costs of oxygen over air (safety, cleaning, completion).
This study gives a complete determination of key O2/Air fireflood parameters for the field of application covered by the cases examined.
Experimental Comparison of Rheology Models for Drilling Fluids
Authors: Okafor M. N. , Evers J. F. 
Published: December 2007

ABSTRACT
The shear stresses and frictional pressure losses that exist in a circulating system could be predicted through rheology models. This paper presents the experimental comparison of a relatively new rheology model called the Robertson-Stiff [1] model to widely used Ostwald-de Walle (Power Law) [2] and Bingham Plastic [3] models.
The models were used to predict shear stresses and frictional pressure losses in laboratory experiments using clay-water drilling fluids for flows through pipes and annuli. Two types of clay-water drilling fluids were used; one with a low yield stress and the other with a high yield stress.
The result of the research showed that the Robertson-Stiff [1] model predicted the best fit of the rheologic data for the two types of drilling fluids used. However, for fluid velocities greater than 2 ft/sce (0.61 m/sec) the frictional pressure losses predicted by the Robertson-Stiff [1] model differ from that of the Power Law [2] model by less than three percent.
Influence of Small-Scale Heterogeneities on Miscible Corefloods
Authors: Bahralolom I. M. , Heller J. P. 
Published: December 2007

ABSTRACT
The behavior of miscible displacement patterns at laboratory scale is strongly affected by the structure of the porous medium. This report covers both the experimental and mathematical approaches employed to investigate the effect of small scale heterogeneity on miscible flood tests. Experimental computerized techniques have been used to measure the detailed variation in rock sample properties. The experimental results indicate that there are significant nonuniformities in permeability and porosity at small scale level. The results showed that the spatial variability of permeability and porosity values has a clear impact on the miscible displacement performance.
The interaction of the nonuniformity of rock properties and dispersion can be mathematically described by a set of isoconcentration surfaces that move through the porous rock. This paper presents the analysis of the growth and decay rates at which the irregularities of these surfaces change as a function of the spatial variability of rock properties and the fluid diffusivity. Based on the experimental and theoretical observations, the conventional one-space dimensional models of miscible displacement cannot properly describe laboratory corefloods. In this paper, a new alternative model is proposed, based on the correlation length and overall variance (the major geostatistical descriptors of the variability of rock properties). A major consideration for a proper interpretation of the impact of nonuniformity of rock properties on mixing in the porous medium is the relative importance of correlation length and core dimensions.
Measuring Minimum Miscibility Pressure: Slim-Tube or Rising-Bubble Method?
Authors: Elsharkawy A. M. , Poettmann F. H. , Christiansen R. L. 
Published: December 2007

Abstract
Measurements of carbon dioxide minimum miscibility pressures (MMP) using a slim tube apparatus were compared with those using a rising-bubble apparatus (RBA). MMPs were measured for twelve different oils, with gravities varying from 34° API to 51° API. The results were found to compare very well when using a specific criterion for the slim-tube MMP. Although the slim tube method is often referred to as the industry standard, there is no standard design, no standard operating procedure, and no standard criterion for determining MMPs with the slim tube. It is shown that the RBA is faster and more reliable than the slim tube for determining MMP. Bubble behavior is described for both the vaporizing and condensing gas processes.
Late Results of a Polymer Pilot Test: Performance, Simulation Adsorption, and Xanthan Stability in the Reservoir
Authors: Littmann Wolfgang , Kleinitz Wolfram , Christensen B. E. , Stokke B. T. , Haugvallstad Torunn 
Published: December 2007

ABSTRACT
A polymer flood pilot project had been performed in the Eddesse-Nord sandstone reservoir (Germany) with a depth of 350 m, a temperature of 22 °C, an average permeability of about 1/μm2, and a thickness of 5 m. The clay content in the sandstone was about 10 %.
A xanthan-solution with a concentration of 800 ppm was injected from 1985 until 1988 into 2 wells. The xanthan was provided as a 2 % fermentation broth.
In mixing of the polymer and during injection of the polymer solution no severe problems were encountered. There was no plugging tendency in the wells observed, which is attributed to a thorough laboratory quality testing.
A response in the production wells occurred earlier than predicted by reservoir simulation and the incremental oil production was somewhat higher than the predicted 6 % of the- original oil in place.
Several simulation studies have been performed using 2 different numerical simulation models. Good history matches could be obtained with respect to production performance during the water flood phase and flow of tracers in the reservoir. The different salinities of the injected and the- original reservoir water were used as tracers, as well as the polymer and the formaldehyde, which was used as biocide.
Polymer was produced in significant amounts in one well. The produced xanthan as well as the xanthan that was injected were analysed for molecular weight, chemical composition, and solution properties. The xanthan molecules were also examined by electron microscopy.
The polymer project can be regarded as successful in terms of injection and production performance. Reservoir simulation results as well as laboratory studies have shown an adsorption of xanthan of 30-40 μ g/g. The xanthan produced in one well, after it had been in the reservoir for about three years, showed no degradation, neither chemical nor bacterial.
Alkaline-Surfactant-Polymer Flood of the West Kiehl, Minnelusa Unit
Authors: Meyers J. J. , Pitts M. J. , Wyatt Kon 
Published: December 2007

Abstract
An alkaline-surfactant-polymer flood was initiated in September 1987 in the Minnelusa Lower "B" sand at the West Kiehl Unit. Subsequent to unitization, two producing wells were drilled outside the Unit boundary. While this extended the productive geologic interpretation of the field, it did not effect the Unit interpretation of the alkaline-surfactant-polymer flood. Production from primary and chemical injection into State 31-36 through November 1991 resulted in 517,521 barrels of oil (82,279 m3) from the Unit wells, of which 456,361 barrels (72,555 m3) were from the area swept by injection into State 31-36. The two Kottraba wells (north of the Unit) have produced 180,686 barrels of oil (28,727 m3) as of November 1991. The- original average oil saturation in the gross swept area was 71.8% PV (69.0% PV in stock tank barrels). The gross swept pore volume of the Unit is 1,294,800 barrels (205,857 m3). The oil recovery efficiency in the gross swept area as of November 1991 is 51.1% OOIP. Projected ultimate production from the gross swept area is 541,158 barrels of oil (86,037 m3)- or 60.6% OOIP.
Projected ultimate production from the Unit is 602,318 barrels of oil (95,761 m3). This compares with a primary plus waterflood oil recovery estimate of 39.9% OOIP recovery for the West Kiehl Unit gross swept area. Comparison of the oil recovery efficiency of the West Kiehl with other Minnelusa waterfloods and polymer floods suggests the West Kiehl has out performed these other Minnelusa floods. Using the Slider technique, the displacement efficiencies of the areas swept by the State 32-36 and State 42-36 in the Unit and Kottraba Federal 2515 were 71.3%, 52.7% and 58.1%, respectively. Comparative efficiency factors for a waterflood in the Hamm Unit and a polymer flood in the OK Field are 28.5% and 45.6%. The West Kiehl, OK Field, and Hamm Unit are all Lower "B" Minnelusa Fields. A total of 184,794 incremental barrels of oil (29,380 m3) are projected for the Unit at an incremental cost of $393,458- or $2.13 per incremental barrel of oil ($13.40 per m3). No injected chemical production has been observed in the Unit wells- or the Kottraba wells as of November 1991. No changes in the Hall plot slopes were observed once a stable slope was achieved until water break through occurred at State 32-36. Alkali plus surfactant plus polymer was injected without damage to the Minnelusa formation.
Performance Review of a Large-Scale Polymer Flood
Authors: Weiss W. W. 
Published: December 2007

ABSTRACT
In December 1980 Oryx Energy Company implemented a commercial polymerflood at their Eliasville Caddo Unit (ECU) located in Stephens County, Texas. During a 34-month period, about eight million pounds of hydrolyzed polyacrylamide polymer were injected into 54 wells. The planning and early performance of the project were detailed in paper SPE/DOE 12637. This follow-up paper reviews the injection and production response on a fieldwide basis since 1984.
Because of injectivity problems, not all patterns received equal polymer slugs. An analysis of the effect of polymer slug size by pattern on incremental oil recovery is presented and suggests that a minimum amount of polymer is required to improve recovery efficiency. The polymer content of the water produced from each well was monitored monthly through April 1986. By material balance, polymer retention in this carbonate reservoir is 50 lb/acre-ft.
An estimate of incremental oil from the commercial project was made by comparing the ECU production performance to nearby Caddo units. Another estimate was made by comparing the performance of each well prior to polymer injection to performance after polymer injection. The results of the two analytical methods is 25 bbl/acre-ft of incremental oil.
An Innovative Polymer Flooding Simulator Based on Advanced Concepts in Polymer Physics
Authors: Lecourtier Jacqueline , Rivenq Richard , Delaplace Philippe , Lemonnier P. , Hagry J. P. , Lefevre D. 
Published: December 2007

ABSTRACT
Basic concepts in physics of polymer flow through porous media have been incorporated in a new three-phase three-dimensional multi-component reservoir simulator. This paper describes the main features of the model and especially the consistent set of physical laws designed to enable a complete description of polymer flooding in a large variety of field cases.
The characteristics of the macromolecules in solution and their interactions with the porous media are introduced in an- original polymer package. This package provides all the macroscopic parameters required by a numerical simulation accounting for the local properties of porous media and effects of salinity changes on all basic properties of the polymer.
The polymer package is coupled with a new three-phase multi-component simulator. Equations are written in compositional form with transport and diffusion-dispersion of any number of polymer, ion and tracer components in the water-phase. That allows to simulate the influence of industrial products of wide molecular weight distribution, with a polymer represented by several pseudocomponents of different molecular weights. Rheology, including permeability reduction and viscosity grading is treated from the local distribution of polymer components.
Competitive chromatographic effects of adsorption and pore wall exclusion which are both molecular weight dependent are included.
Simulations of laboratory polymer flooding experiments are presented together with a polymer flooding injection in a layered reservoir with polymer dissolved in an injection water having a salinity different from the brine in place. The results illustrate both the chromatographic and the salinity effects on polymer rheology. A field study is also presented.
Surfactant-Polymer Flooding with Anionic PO/EO Surfactant Microemulsions Containing Polyethylene Glycol Additives
Authors: Osterloh W. T. , Jante M. J. 
Published: December 2007

ABSTRACT
We report the results of laboratory experiments designed to test the efficacy of polyethylene glycols, PEGs, in reducing the adsorption of optimized propoxy-lated/ethoxylated alkyl sulfates, PO/EO surfactants, onto clay. We also report the results of experiments designed to determine if the PEG additives can improve the cost-effectiveness of PO/EO surfactant/polymer flooding. A PO/EO surfactant blend was designed for a reservoir with a high salinity connate brine, 190 000 mg/L total dissolved solids, a moderate temperature, 117°F, and a light crude oil, 33°API.
The addition of PEG-1000 to the PO/EO surfactant microemulsion reduced the static adsorption of the surfactant on kaolinite to undetectably low levels. In dynamic adsorption experiments, the addition of PEG-1000 to the surfactant microemulsion reduced adsorption on Berea sandstone by a factor of four. Oil recoveries in Berea cores were substantially improved when PEG-1000 was added to the PO/EO surfactant microemulsion. Most importantly, high recoveries were achieved using small pore volumes of microemulsion. Based on oil recovery results and estimates of chemical prices, the microemulsion chemical cost per barrel of tertiary oil is lowered by as much as a factor of four when PEG-1000 is added to a PO/EO surfactant microemulsion.
Quantification and Optimization of Viscoelastic Effects of Polymer Solutions for Enhanced Oil Recovery
Authors: Ranjbar Mohammad , Rupp Juergen , Pusch Guenter , Meyn Ruediger 
Published: December 2007

ABSTRACT
This paper presents the results of an extensive study aimed at describing the viscoelastic properties of polymer solutions for enhanced oil recovery. Using natural and artificial cores and polymer solutions with different storage factors, core floods were performed to examine the influence of viscoelasticity of polymer solutions on flow behaviour and oil recovery.
From the experimental results, it appears that beyond a critical injection rate the viscoelasticity of polymer solutions is reflected by increasing of effective viscosity. This critical injection rate is dependent on the concentration and degree of hydrolization (HPAA), molecular weight of polymers, core permeability, salinity and temperature. Therefore the viscoelastic core flow behaviour of polymer solutions can be adjusted to specific reservoir conditions by variation and optimization of these parameters.
To describe and quantify the viscoelastic effects by means of experimental results, a model based on Maxwell-Fluid-Relation is applied. Using the proposed model, the model index É can be determined, which represents the viscoelastic behaviour of polymer solutions in porous media.
It is found that not the relaxation time, but the model index É is the parameter which should used for quantifing this viscoelastic behaviour of polymer solutions in porous media.
New Methodology for Prudhoe Bay Miscible Gas Distribution
Authors: Cockin A. P. 
Published: December 2007

ABSTRACT
This paper presents a new methodology, based on field performance data, for optimally distributing miscible gas to the 70 patterns under water alternating gas flood in the Prudhoe Bay Miscible Gas Project (PBMGP). In addition the new approach controls the timing of the miscible flood expansion to a further 60 waterflood patterns. The guiding philosophy of this approach is to maximize the efficient use of the miscible injectant (MI) by minimizing its wastage.
This methodology was implemented in the field in 1991 and is expected to increase by 50% the current volume of oil being mobilized by the Ml.
The projected ultimate recovery of 410 - 480 mmstb of oil from the expanded PBMGP is equivalent to the reserves of a major oil field. For comparison the PBMGP reserves are larger than most North Sea projects currently under development. For this reason it is clearly vital to effectively manage a project of this magnitude.
Application of Improved Oil Recovery in the Soviet Union
Authors: Mamedov Y. G. , Bokserman A. A. 
Published: December 2007

ABSTRACT
This paper summarizes the results of field application of EOR techniques in the former Soviet Union. 175,000 barrels of incremental oil per day were produced in 1991 due to their implementation in different geological and environmental conditions. 55% of total production- or 96,500 BOPD were produced with the application of chemical methods, 64,500 BPD- or 37% were produced due to thermal and the rest - due to gas injection methods.
The hydrodynamic improved oil recovery methods based on waterflooding technique and reservoir management brought another 600,000 BPD additional oil.The future of enhanced oil production depends on wide application of both conventional and nonconventional advanced methods tested in laboratories and in field sites and provided for their high efficiency.
The outlook of wide application of EOR and IOR techniques by the years 2000 and 2010 at different economical conditions is presented.
Carbonated Water Imbibition Flooding: An Enhanced Oil Recovery Process for Fractured Reservoirs
Authors: Perez J. M. , Poston S. W. , Sharif Q. J. 
Published: December 2007

ABSTRACT
Water imbibition studies were conducted on core plugs at confining pressures of 2,000 psi. Water was enriched with CO2 at different carbonation pressures, ranging from 50 to 500 psi. Conventional displacement as well as Nuclear Magnetic Resonance (NMR) methods were used to study the effects of carbonated water imbibition on oil recovery rate and ultimate recovery.
The major factors influencing oil recovery by carbonated water imbibition displacement appear to be:
An increase in oil mobility. An increase in core permeability in carbonate cores A reduction in the operating pressure below the
bubble point pressure after the core had been allowed to imbibe the carbonated water induced a solution gas drive effect which substantially increased recovery.
Carbon dioxide dissolved into the water being imbibed by the rock was found to accelerate oil recovery rates and increase ultimate oil recovery when compared to unadulterated water imbibition. Recovery rate and ultimate recovery increased as a function of the amount of CO2 dissolved into the imbibed water. Recovery time was reduced to one third when the gas liberation process was applied cyclically. This new method holds promise to increase oil production rates and oil reserves from fractured, low matrix permeability, low gas-oil ratio, oil reservoirs.
Electric Preheating in Low-Injectivity Tar Sand Deposits
Authors: Glandt C. A. , Hsu Chia-Fu 
Published: December 2007

ABSTRACT
Lack of steam injectivity is one of the most serious obstacles in the thermal recovery of tar sands and oil shale deposits. Electric heating offers a technically viable option which has been the subject of studies and field tests in the last 10 years. This paper discusses the application of electric heating to reservoirs with electric resistivities ranging from 100 ohm-m (tar sands) to 10,000 ohm-m (oil shales). A numerical model is constructed to solve Maxwell's electromagnetic field equations.
The model is used to study the electric preheating of a tar sand reservoir using horizontal electrodes to develop steam injectivity. After preheating, electrodes are converted into conventional injection/ production wells to be used in a subsequent steam recovery process.
A Procedure for Scaling Heavy-Oil Combustion Tube Results to a Field Model
Authors: Marjerrison D. M. , Fassihi M. R. 
Published: December 2007

Abstract
Combustion tube experiments are conducted in the laboratory to determine the burning characteristics of a particular oil in a rock matrix. These characteristics include fuel laydown, air-fuel ratio, H/C ratios and the adiabatic combustion temperature. The combustion tube experiment can then be numerically modeled so that a suitable reaction scheme and other data necessary for field simulation can be determined. The data obtained from history matching the tube experiment cannot be used directly for field simulation. Grid blocks used for a tube simulation are on the- order of inches thick, while grid blocks for a field simulation will be 100 to 1,000 times larger. Also, the estimated kinetics data from a combustion tube history match are time and temperature dependent and will not produce similar results in large grid blocks. This paper outlines a new method of history matching the results of a semi-adiabatic combustion tube experiment and scaling them to a form that can be used for field simulation. The shortcomings of current thermal simulators and the suggested remedies also are discussed in this paper.