bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Texas MEOR Application Shows Outstanding Production Improvement Due To Oil Release Effects On Relative Permeability
Authors: Akintunji Folami , Marcotte Brian , Sheehy Alan , Govreau Bradley 
Published: April 2012

Abstract
A Microbial Enhanced Oil Recovery (MEOR) application in the Big Wells Field located in Dimmit County, Texas has shown a significant improvement in production—both oil rate and water cut performance. As a result of a specific nutrient injection designed in the laboratory to stimulate in situ, naturally occurring microbes, for this San Miguel sandstone reservoir and its microbial ecology, a marked improvement was seen in the two producing wells to which the treatment was applied. The water cut in one well improved from fifty per cent to fifteen percent. The water cut in a second well improved from fifty-five to thirty-five percent.
Although previous field applications of this MEOR process had shown increases in oil production and decreases in water production, water production in this application was completely stopped for a brief time as a result of the treatment. This paper reviews the Big Wells producing well treatments and their results. A specific look at the oil release mechanism of this MEOR process offers an explanation as to how the oil released by these treatments impacts the relative permeability of fluids in the reservoir near the treated wellbores as demonstrated in the field producing well treatments. Similar benefits are seen during the treatment of water injection wells related to performance in adjacent producing wells.
The significance of this application is that field evidence supports that production improvements result from the release of oil in sufficient quantities to change the near wellbore relative permeability to both oil and water. Also, it demonstrates that this MEOR technology can be successfully applied to reservoirs in this geographical area and extends the lower threshold for formation permeability suitable for treatment. Having been successfully applied in other parts of North America, this is an important application of this MEOR technology in Texas.
Modeling of Foamed Gas Mobility in Permeable Porous Media
Authors: Balan H. O. , Balhoff M. T. , Nguyen Q. P. 
Published: April 2012

Abstract
In mechanistic modeling of foam in porous media, reduced gas mobility is attributed to viscous resistance of flowing foam lamellas to gas flow, while gas trapping significantly modifies relative permeability. By using pore-network models representative of real porous media, we previously developed a relationship between flowing gas fraction and pressure gradient for strong foam (high lamella density). In this study, we expand our model to describe the effects of foam strength and pore-scale apparent gas viscosity models on both relative gas permeability and effective gas viscosity. Dimensional analysis in scaling of these two rheological quantities with pressure gradient and lamella density is discussed.
One of our important findings is that relative gas permeability is poorly sensitive to total lamella density while it is a strong non-linear function of flowing gas fraction, opposing to most of the existing theoretical models describing the effect of gas trapping on relative gas permeability. This is consistently observed for all the pore-scale apparent gas viscosity models. It is also found that effective gas viscosity increases exponentially with flowing lamella density. This result implies that the use of the commonly used apparent gas viscosity model for straight capillary tubes is not accurate for foam flow in porous media. In addition, shear thinning foam flow is more obvious at high flowing lamella density while Newtonian flow becomes significant at relatively low flowing lamella density. Furthermore, scaling of effective gas viscosity with flowing lamella density depends on how the later quantity is defined. Both empirical and mechanistic pore-scale apparent gas viscosity models give almost the same functional relationship between flowing gas fraction and pressure gradient. This would facilitate scaling of flow rate with pressure gradient and testing a range of shear-thinning and yield-stress behavior in a simple format. Our results necessitate the need for further improving the existing mechanistic foam modeling methods with focus on process upscaling.
Low Salinity Waterflood at Reduced Capillarity
Authors: Spildo Kristine , Johannessen Annette Meland , Skauge Arne 
Published: April 2012

Abstract
A new generation EOR methods comes from combining techniques to make the overall process more efficient and minimize the retention or loss of chemicals. One of the hybrid EOR methods we are investigating combines low salinity brine and reduced capillarity by surfactants, which has potential to increase EOR oil and cost efficiency.
It is well documented that low salinity waterflooding may give improved recovery. Judging from published data, it is likely that more than one mechanism is contributing to the observed oil recovery. We have summarized that two of the main effects are destabilization and mobilization of oil layers, and fines migration due to destabilization of clays. The latter is believed to contribute to increased oil recovery by pore blocking and microscopic diversion. If capillary forces are high, the oil mobilized by either of these two mechanisms is easily re-trapped. However if the capillary forces are lowered by adding surfactant, re-trapping may be avoided.
The effect of decreasing interfacial tension was investigated in a series of constant rate, low salinity floods performed on crude oil aged Berea sandstone cores. The purpose is to explore the added benefit of the low salinity surfactant process over low salinity brine injection, and to investigate to which extent the capillary forces needs to be reduced to take advantage of the incremental recovery that may be obtained by combining the two processes. The results show that reduction of interfacial tension in low salinity waterfloods gives an increase in oil recovery which exceeds the expected performance of injecting a solution with the same reduction in interfacial tension but without the low salinity contribution.
The combined effect of low salinity brine and surfactant injection may have the potential to improve the economy of EOR operations. The desalination cost and logistic involved may in some cases limit the possibility for low salinity waterflood, but enhanced oil recovery by simultaneous lowering of interfacial tension giving a much higher additional oil recovery may improve the overall economy.
Development of a Novel and Computationally-Efficient Discrete-Fracture Model to Study IOR Processes in Naturally Fractured Reservoirs
Authors: Moinfar Ali , Varavei Abdoljalil , Sepehrnoori Kamy , Johns Russell T. 
Published: April 2012

Abstract
Many naturally fractured reservoirs around the world have depleted significantly and improved oil recovery (IOR) processes are necessary for further development. Hence, the modeling of fractured reservoirs has received increased attention recently. Accurate modeling and simulation of naturally fractured reservoirs is still challenging owing to permeability anisotropies and contrasts. Non-physical abstractions inherent in conventional dual porosity and dual permeability models make them inadequate for solving different fluid-flow problems in fractured reservoirs. Also, recent technologies of discrete fracture modeling suffer from large simulation run times and the industry has not found applications for them yet, even though they give more accurate representations of fractured reservoirs than dual continuum models.
We developed a novel discrete fracture model for an in-house compositional reservoir simulator that borrows the dualmedium concept from conventional dual continuum models and also incorporates the effect of each fracture explicitly. In contrast to dual continuum models, fractures have arbitrary orientations and can be angled or vertical, honoring the complexity of a typical fractured reservoir. Likewise, the new discrete fracture model does not need mesh refinement around fractures and offers computationally-efficient simulations compared to other discrete fracture models. Examples of water-flooding and gas injection are presented in this paper to demonstrate the accuracy, robustness, and applicability of the developed model for studying IOR processes in naturally fractured reservoirs. Simulations show that favorable rock wettability along with capillary pressure contrasts between matrix and fractures causes noticeable incremental oil recovery in water floods. Likewise, simulations of gas injection demonstrate that high-permeability fractures not only expedite gas breakthrough, but also increase segregation of gas towards the top of the reservoir, leading to very low sweep efficiency. Furthermore, oil recovery from naturally fractured reservoirs is found to be sensitive to the fracture inclination angle.
The Influence of O2 Contamination on MMP and Core Flood Performance in Miscible and Immiscible CO2 WAG
Authors: Jiang Haifeng , Nuryaningsih Lily , Adidharma Hertanto 
Published: April 2012

Abstract
For a given oil and reservoir temperature, the CO2 Minimum Miscibility Pressure (MMP) is largely affected by the CO2 purity. A commonly found contamination gas in CO2 EOR is O2, the existence of which will influence the MMP and thus influence the CO2 Water Alternating Gas (WAG) performance.
Slim tube tests and core flood experiments are conducted in order to study the influence of O2 on the MMP and CO2 WAG performance. Both experiments utilize crude oil from South Slattery Field in Wyoming. The mole concentration of O2 in CO2 gas varies from 0 mol% to 5 and 10 mol% and the experimental temperature is set at 57 °C to mimic the reservoir condition. In the slim tube tests, the oil recoveries at gas breakthrough are used to interpret the MMP. All core flood experiments utilize Berea sandstone cores and synthetic brines. A pressure of 20% higher than the pure CO2 MMP is used to ensure miscible condition and a pressure of 50% of the pure CO2 MMP is used for the immiscible study. WAG is injected in the tertiary recovery mode and its parameters include a WAG ratio of 1:1, a half cycle slug size of 0.1 PV, and a total slug size of 2.0 PV. WAG performance, i.e., percent oil recovery, tertiary recovery factor, and CO2 utilization factor are determined.
Slim tube results show that the existence of O2 increases the CO2 MMP significantly. Five mol percent of O2 in CO2 gas increases its MMP by 20.88%, while 10 mol% of O2 increases it by 61.92%. Core flood results show that the existence of O2 in CO2 gas adversely influence the WAG performance. For miscible CO2 WAG flooding, the higher the O2 content, the lower the incremental recovery and tertiary recovery factor (TRF). The same results are also found in immiscible CO2 WAG with less significant effects.
Similar studies have been mainly focused on N2 and CH4, while the influence of O2 has never been experimentally investigated. This study is essential for better understanding the influence of CO2 contamination on WAG performance, which is a major concern in CO2 EOR utilizing unpurified CO2 gas sources.
ECO-GSAI "Gravity Stable Air Injection" Pilot Test, an Enhanced Oil Recovery Opportunity to be Implemented in Chichimene Field – Colombia
Authors: Ordoñez Aníbal , Trujillo Marta , Rodriguez Edwin , Belgrave John , Lobo Adriano , Fernández Fabián , Comas Juan , Bottia Hernando 
Published: April 2012

Abstract
In order to improve the oil production and recovery in Chichimene heavy oil field, an air injection process is planned to be implemented: GSAI (Gravity Stable Air Injection). The first step is to conduct a pilot test in the field with a startup planned for 2013. Laboratory work and analysis with analytical and numerical models indicated that the process can achieve of around 30% of additional recovery factor over primary production.
Chichimene is one of the Ecopetrol S.A heavy oil fields, located 50 km south of Villavicencio city, Meta. The field has been in production since 2002 from the T2 formation using vertical wells with conventional casing (approximately 20 wells), drilled on 40 acre spacing and without water production so far, API gravity of 10 °API and viscosity of 150 cp at reservoir conditions (185° F and 3600 psia). At such a reservoir conditions the crude has good mobility making it a good candidate for ECO-GSAI technology. A similar opportunity, but less favorable in Suplacu of Barcau (Romania), has shown improvement in the recovery factor of 9% to over 50%.
This paper presents the screening, reservoir characterization, laboratory work, numerical simulation, and other design considerations for planning and justification of the pilot.
Development of Thermally and Chemically Stable Large-Hydrophobe Alkoxy Carboxylate Surfactants
Authors: Adkins Stephanie , Arachchilage Gayani Pinnawala , Solairaj Sriram , Lu Jun , Weerasooriya Upali , Pope Gary 
Published: April 2012

Abstract
The Guerbet reaction produces large, branched hydrophobes through the dimerization of linear alcohols. High-performance, low-cost enhanced oil recovery (EOR) surfactants are produced by carboxylation (carboxymethylation) of large Guerbet alkoxylates. Alkoxy groups such as propylene oxide (PO) and ethylene oxide (EO) are incorporated as extenders to the Guerbet alcohol, followed by carboxylation to make the anionic surfactant. Previously, the use of low-cost Guerbet alkoxy sulfate surfactants for EOR applications at high temperatures was established by enhancing their thermal stability when the pH is maintained at 10–11. Alternative thermally and chemically stable anionic surfactant structures are highly desired, especially for application under conditions where alkali usage is prohibitive. These novel large-hydrophobe carboxylate surfactants meet this need. In addition, the Guerbet alkoxy carboxylate structure can be tailored to fit the specific EOR requirements. These surfactants are stable at elevated temperatures both with and without alkali, and furthermore they can be used in environments of high salinity and high hardness (high concentration of divalent ions). Carboxylate surfactants have been used in formulations to produce ultra-low interfacial tensions with low microemulsion viscosities for a wide variety of crude oils under a large range of reservoir conditions. A parallel paper titled "Novel Large-Hydrophobe Alkoxy Carboxylate Surfactants for Enhanced Oil Recovery" will discuss the application of these surfactants. Thus, the advent of this class of cost-effective surfactants greatly broadens the application of chemical EOR.
Novel Large-Hydrophobe Alkoxy Carboxylate Surfactants for Enhanced Oil Recovery
Authors: Lu Jun , Britton Christopher , Solairaj Sriram , Liyanage Pathma J. , Kim Do Hoon , Adkins Stephanie , Arachchilage Gayani W. , Weerasooriya Upali , Pope Gary A. 
Published: April 2012

Abstract
A new class of surfactants has been developed and tested for chemical enhanced oil recovery that shows excellent performance under harsh reservoir conditions. These novel Guerbet alkoxy carboxylate surfactants fulfill this need by providing large, branched hydrophobes, flexibility in the number of alkoxylate groups, and stability in both alkaline and non- alkaline environments at temperatures up to at least 120 °C. The new carboxylate surfactants perform better than previously available commercial surfactants, they can be used under harsh reservoir conditions, and they can be manufactured at a lower cost from widely available feedstocks. A formulation containing the combination of a carboxylate surfactant and a sulfonate co-surfactant resulted in a synergistic interaction that has the potential to further reduce the total chemical cost. Both ultra- low interfacial tension with the oils and a clear aqueous solution even under harsh conditions such as high salinity, high hardness and high temperature with or without alkali can be obtained using these new large-hydrophobe alkoxy carboxylate surfactants. Both sandstone and carbonate corefloods were conducted with excellent results. Formulations have been developed for both active oils (contains naturally occurring carboxylic acids) and inactive oils (oils that do not produce soap/carboxylic acid) with excellent results. The new class of surfactants is a major breakthrough that greatly increases the commercial potential of chemical enhanced oil recovery.
Optimal Injection Design Utilizing Tracer and Simulation in a Surfactant Pilot for a Fractured Carbonate Yates Field
Authors: Cheng A. M. , Kwan J. T. 
Published: April 2012

Abstract
Yates Field is a large, naturally fractured, carbonate reservoir in west Texas. The estimated recovery after 84 years of production since 1927 is about 35% after primary depletion, water and gas injections. Laboratory and field production data indicate that Yates is an oil-wet reservoir system. Consequently, it is expected that wettability alteration can improve Yates recovery by changing to more favorable water-wet condition. A field pilot with one injector and one producer using a new, anionic surfactant was performed in Yates to determine if the surfactant can improve oil production via lower interfacial tension and wettability alteration mechanisms. This paper shows a field case study of an integrated use of a geological model, reservoir simulator, tracer test data, and laboratory results to design a surfactant pilot in the fractured carbonate Yates Field. Reservoir simulation models were calibrated by matching the bromide tracer test results. The models were used to quantify the fracture properties and study different injection scenarios. The optimal schedule was to inject multiple cycles of a 3% surfactant, at a rate of 500 b/d for 12 hours, and then shut-in the injector for 12 hours. A total of 50,000 lb of surfactant was injected into the pilot area.
The Impact of Microemulsion Viscosity on Oil Recovery
Authors: Walker Dustin L. , Britton Christopher , Kim Do Hoon , Dufour Sophie , Weerasooriya Upali , Pope Gary A. 
Published: April 2012

Abstract
The physical structure of microemulsions and the degree to which ultra-low IFT is achieved is dependent on a number of parameters including the types and concentrations of surfactants, co-solvents and alkali, crude oil composition, brine composition, temperature and to a lesser extent, pressure. Modifying any one of these variables creates a microemulsion with different properties. The rheological properties of the microemulsion must be adjusted appropriately to achieve good performance under practical reservoir conditions. Two microemulsion properties of primary concern are undesirably high viscosity relative to oil viscosity and non-Newtonian behavior. The broader implications of injecting microemulsions with high viscosities or non-Newtonian behavior in the field include high surfactant retention, unsustainably high pressure gradients, reduced sweep efficiency and microemulsions that stagnate in the field due to high viscosity at low shear rates. The most common ways to reduce microemulsion viscosity are to optimize the surfactant formulation with a good co-solvent and/or by adding more branching to the surfactant hydrophobe. Adding co-solvent in appropriate concentrations makes a microemulsion much less viscous. However, co-solvents increase the cost and complexity and also tend to increase the IFT. A less conventional solution involves increasing the temperature of the injection water thereby lowering both the oil and microemulsion viscosity. This approach has been tested successfully in core floods using both surrogate and reservoir cores.
Recovery Mechanisms and Relative Permeability for Gas/Oil Systems at Near-miscible Conditions: Effects of Immobile Water Saturation, Wettability, Hysteresis and Permeability
Authors: Fatemi S. Mobeen , Sohrabi Mehran , Jamiolahmady Mahmoud , Ireland Shaun 
Published: April 2012

Abstract
Near-miscible gas injection represents a number of processes of great importance to reservoir engineers including hydrocarbon gas injection and CO2 flood. Very little experimental data is available in the literature on displacements involving very low-IFT (interfacial tension). In this paper, we present the results of a series of two-phase and three-phase gas injection (drainage) and oil injection (imbibition) core flood experiments for an gas/oil system at near-miscible (IFT= 0.04 mN.m‒1) conditions. Two different cores; a high-permeability (1000 mD) and a lower permeability (65 mD) core were used in the experiments and both water-wet and mixed-wet conditions were examined.
The results show that despite a very low gas-oil IFT, there is significant hysteresis between the imbibition and drainage oil and gas relative permeabilities (kr) curves in the 65mD core. Hysteresis was less for 1000mD core (compared to the 65 mD core) but it still could not be ignored. Near-miscible kr hysteresis was significant for both water-wet and mixed-wet systems. Presence of immobile water in the water-wet cores improved oil relative permeabilities but reduced gas relative permeabilities in both imbibition and drainage directions. As a result, oil recovery for gas injection experiments improved when the rock contained immobile water. Both oil and gas relative permeabilities reduced when the rock wettability was altered to mixed wet from water wet and as a result, oil recovery by gas injection in the mixed-wet rock was less than that obtained under water-wet conditions. We offer explanations for these observations based on our understanding of the pore-scale interactions and mechanisms, the distribution of fluid phases and their spreading bahaviour.
The results help us better understand the impact of some of the important parameters pertinent to kr and its hysteresis especially in very low IFT gas-oil systems and mixed-wet rocks. Understanding these effects and behavior is important for improved prediction of the performance of gas injection and water-alternating gas (WAG) injection in oil reservoirs.