bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water Alternating High Pressure Air Injection
Authors: van Batenburg D. W. , de Zwart A. H. , Doush M. 
Published: July 2010

AbstractHigh Pressure Air Injection (HPAI) is a potentially attractive enhanced recovery method for deep, high-pressure light oil reservoirs. The clear advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas is its availability at any location. Although, the process has successfully been applied in the Williston Basin for more than two decades, the potential risks associated with the presence of oxygen in air are a significant hurdle for implementation in other locations.Thermal simulations that include combustion are required to quantify the incremental oil, the oxygen consumption and resulting oxygen distribution from the application of HPAI in a given field. Once such a simulation model is available, it can be used to optimize the injection strategy: strategies that have a good incremental recovery while reducing the amount of gas injected are key to a successful project. The injection rate is bounded by a technical lower limit and an economic upper limit: there is a minimum rate required to maintain the combustion and higher rates require larger compressors that are more expensive.This paper focuses on the optimization of the injection strategy for HPAI in a 3D model with realistic geological features. Numerical simulations with a thermal model that includes combustion were conducted for continuous versus alternating air injection. A critical assumption for alternating air injection is that the remaining oil spontaneously re-ignites.This study shows that water alternating air injection has a great potential to improve HPAI projects: project life can be extended and incremental recovery is improved when compared with continuous air injection. In addition, the variation in distribution of oxygen between different cycles is presented. This also illustrates that the numerical model can be used as an oxygen management tool. The effects of alternating air injection are comparable to the effects of alternating gas injection: the saturation in the swept areas changes due to the alternating (re-) invasion of gas, oil and water.This paper illustrates that modeling oxygen consumption is essential for the evaluation of potential risks and optimization of the HPAI process.
Enhanced Oil Recovery of Viscous Oil by Injection of Water-in-Oil Emulsion Made with Used Engine Oil
Authors: Fu Xuebing , Mamora Daulat 
Published: July 2010

AbstractWater-in-Oil (W/O) emulsion has been proven to be an effective driving fluid for viscous oil (&gt;100cp) recovery. However, finding an oil that is cheap and easily available to make the emulsion is a problem. In a recent patent, crude heavy oil was used to make W/O emulsions to recover the same oil in a sand pack flooding experiment, with almost 100% recovery achieved. This crude oil emulsion was stabilized by oleophilic nanoparticles without any surfactant required. However, its viscosity was unfavorably high: a 60% water content W/O emulsion is over 10 times more viscous than the original oil—far beyond the required level for mobility control, resulting in poor injectivity.This paper introduces a new idea of making W/O emulsion with a very common material— used engine oil. Over a billion gallons of engine oil are used in the US every year, and it has been a major contributor to pollution due to improper disposal. However this used engine oil could be a very good candidate to make W/O emulsions. First of all, the soot (organic carbons) from the breaking down of the engine oil provides perfect solid particles to stabilize the emulsion; secondly, its moderate viscosity permits an optimal viscosity to be achieved when making an emulsion. The detergent in the original engine oil and the acidity caused by oxidation of the oil may also help stabilize the W/O emulsions.In this research different types of used engine oil (mineral based, synthetic) were tested to make W/O emulsions simply by blending in brine. A series of stable emulsions were obtained with varied water contents from 40~70%. Viscosities of these emulsions were measured, ranging from 102~104 cp at low shear rates and ambient temperature. As a potential driving fluid, used engine oil emulsions can be targeted at various heavy oil reservoirs because of the wide viscosity range.
Preformed Particle Gel Transport through Open Fractures and its Effect on Water Flow
Authors: Zhang Hao , Bai Baojun 
Published: July 2010

Abstract
Transparent fracture models were constructed to visually track swollen preformed particle gel (PPG) propagation through open fractures and water flow through PPG placed in fractures. It was observed that PPG propagated like a piston along a fracture during PPG injection and a gel pack was formed in the fracture after gel placement and water broke through the particle gel pack to create several water channels to discharge water from the outlet during water injection after PPG placement. The factors that influence PPG injectivity and plugging efficiency have been investigated. Results show that PPG injectivity increases with fracture width and flow rate and decreases with brine concentration on which PPG swollen ratio is dependent. PPG can reduce the permeability of different width fracture to the same level. Full factorial experimental design was performed to rank the influence of injection rate, fracture width, and PPG swelling ratio on the response of pressure, resistance factor and injectivity.
The Influence of Salt Concentration in Injected Water on Low Frequency Electrical-Heating Assisted Bitumen Recovery
Authors: Bogdanov I. I. , Torres J. A. , Akhlaghi H. A. , Kamp A. M. 
Published: July 2010

Abstract
Steam injection is often not a good alternative for oil recovery from shallow bitumen reservoirs; for instance, the thin cap-rock creates the danger of steam breakthrough. For deeper reservoirs the heat losses from injection well may be prohibitive. A technology that may be better suited is oil recovery aided by electrical low frequency heating of the reservoir. This technology, well known for environmental remedial applications, has been recently field-tried, yielding promising results. The process uses electrical conductivity of connate water to propagate an alternating current between electrodes, inducing the Joule heating of the reservoir. An associated problem is the appearance of hot spots around the electrodes that may be relieved by water circulation. However, the water circulation may have a significant effect on the heating process because the electrical conductivity of the circulated water depends on its salt content.
In order to find out the influence of salt concentration on process efficiency we have studied the process of salt water recirculation around an electrode using numerical simulation. The physical properties and operational data for Athabasca bitumen have been collected from the literature. The model built with CMG STARS™ simulator and tested first with available analytical solutions, has been validated and the proper choice of the underlying grid and numerical tuning parameters has been verified. The process was also studied at field scale for a common pattern of electrodes and production wells. The salt turned out to penetrate into the reservoir, far beyond the major water circulation zone around the electrodes. This process increases the electrical conductivity in a large region between electrodes, which improves the heating of the reservoir. The single-electrode simulation studies using the different tools yielded similar results for a simple problem. More complex (and more realistic) field-scale simulations show that adding salt enhances finally the oil production. In practice an upper concentration limit is given by corrosion problems at the electrodes.
The reservoir simulation of bitumen recovery assisted by low-frequency heating is a challenging multiphysics problem. The understanding of the influence of salt concentration on the circulated water provided by this work is an important key in process design considerations.
Inaccessible Pore Volume of Associative Polymer Floods
Authors: Pancharoen M. , Thiele M. R. , Kovscek A. R. 
Published: July 2010

Abstract
Approximately half of current oil production is from waterfloods where a major concern is mobility control of the injected phase. Addition of polymer to the injection water decreases the mobility ratio leading to greater flood efficiency, especially for recovery of viscous oil. Of the various EOR polymer formulations, newly developed associative, water-soluble polymers show special promise. We investigate, experimentally and numerically, the inaccessible pore volume (IPV), permeability reduction (Rk), and interfacial tension characteristics of 3 different molecular weight associative polymers and, for reference, a conventional hydrolyzed polyacrylimide. Previous studies of these same associative polymers revealed good secondary and tertiary oil recovery efficiency for displacement of a viscous 140 cP oil. To our knowledge, this is the first study to observe and report IPV – Rk properties of these associative polymer solutions. New experiments were conducted by injecting polymer solutions through a roughly 12 Darcy sandpack and measuring the separation between effluent concentration profiles of the polymer and the salt used as the tracer. Results are interpreted from the effluent profiles using an analytical superposition model as well as a conventional finite difference formulation. The associative polymers yield moderate to large IPV (20 to 40%) and mild Rk (1.1 to 1.5) that increases with molecular weight. Brine salinity reduces both IPV and permeability reduction. Differences between the classical interpretation, the analytical interpretation, and the numerical implementation of IPV are discussed as is the adequacy of the conventional IPV-Rk description of the mobility control of polymer.
A New Process for Manufacturing and Stabilizing High-Performance EOR Surfactants at Low Cost for High-Temperature, High-Salinity Oil Reservoirs
Authors: Adkins Stephanie , Liyanage Pathma J. , Pinnawala Arachchilage Gayani W. , Mudiyanselage Thilini , Weerasooriya Upali , Pope Gary A. 
Published: July 2010

Abstract
An alcohol dimerization process known as the Guerbet reaction is used to create large alcohol structures for the production of the corresponding alkoxy sulfate surfactants. In the alcohol industry, Guerbet (dimer) alcohols are considered the "gold" standard for large, branched alcohols. These Guerbet alcohols tend to be more expensive than other alcohols when produced in high purity for various industrial applications. The high cost is mainly due to driving the reaction to completion and/or stripping-off of the unreacted monomer alcohol to produce high purity. However, inexpensive Guerbet alcohols (GA) can be prepared by aiming for less than quantitative conversion during the alcohol dimerization process. The resultant blend of 85-95% GA and 5-15% monomer alcohol is subsequently used in the alkoxylation process to add propylene oxide and/or ethylene oxide, followed by sulfation. Through the use of this new Guerbet process, these surfactants can be manufactured at low cost when made as sulfates as opposed to sulfonates. For example, a C32 GA can be produced from a C16 alcohol. These and other sulfate surfactants can be stabilized at high temperature with alkali. This is a surprising discovery that greatly increases the availability of low-cost, high performance surfactants for high temperature reservoirs.
A Microbial Enhanced Oil Recovery Field Pilot in a Brazilian Onshore Oilfield
Authors: Reksidler Rodrigo , Torres Volpon Antonia Garcia , Barbosa Luiz Cesar , Brasileiro Cláudio Guilherme , Nicolau Heitor Cesar , de Calasans José Augusto 
Published: July 2010

Abstract
An onshore oilfield, located in the northeast of Brazil, is being submitted to a microbial EOR method to reduce problems associated with high permeability zones.
Ten water injection wells were selected to the field trial. The method consists in the dosage of nutrients and an electron acceptor in the injection water, in order to stimulate microorganisms to produce biomass and biopolymer to plug high permeability zones.
Pressure, flow rate and injectivity profile are being monitored. The results demonstrated that the process is effective. Five wells indicated the plugging of the high permeability zone, due the pressure increase and flow rate decrease. Only three of these wells were evaluated by injectivity profile, and two of them presented improvements on the vertical sweep efficiency.
Prediction of Three-Phase Gravity Drainage from Two-Phase Capillary Pressure Curves
Authors: Mirzaei Mohammad , DiCarlo David , Ashouripashaki Mandana , Dehghanpour Hasan , Aminzadeh Behdad 
Published: July 2010

Abstract
Gravity drainage of oil with gas and the migration of non-aqueous phase liquid (NAPL) spills in the unsaturated zone are two of the most common processes where the three-phase capillary/gravity equilibrium plays an important role. Although three-phase gravity drainage is highly effective for water-wet media, predicting the profiles and ultimate recovery for mixed and oil-wet media is essential as most reservoirs have a mixed-wet nature.
The three-phase capillary/gravity equilibrium is different from the two-phase equilibrium, similar to the difference between two-phase and three-phase relative permeability. For water-wet media and spreading oils, the profiles can be predicted from the two-phase pressure-saturation curves. However, the predictions are more complicated for mixed-wet media because of the difference in fluid configuration in pores. We propose a simple method for predicting the three-phase equilibrium saturation profile and test our method using the experimental data. The experimental method used in this study includes performing a series of two-phase capillary pressure measurements and three- phase gravity drainage tests in columns containing fractionally wet sands. The two-phase experiments are compared to experimentally measured three-phase drainage saturation profiles of the same wettability. The bottom of the column is supported by an aquifer such that no oil is produced.
The results show that the transition between single phase, two-phase and three-phase zones can be accurately predicted using the two-phase drainage capillary pressures. However, the proposed method is unable to predict the final residual saturation, especially in columns with faction of oil-wet sand exceeding 50%.
Because two-phase data for reservoir cores are more accessible than three-phase data, the results of this study are valuable for predicting the saturation distribution in a three- phase gravity drainage process in mixed-wet media, particularly in reservoirs with a wettability gradient. The results of the study may also be applicable to study of CO2 sequestration in aquifers.
Simulation of Expanding Solvent – Steam Assisted Gravity Drainage in a Field Case Study of a Bitumen Oil Reservoir
Authors: Akinboyewa John , Das Swapan K. , Wu Yu-Shu , Kazemi Hossein 
Published: July 2010

Abstract
With the increasing demand for energy around the world, more attention is directed to heavy oil and bitumen reservoirs for energy supply. Currently, these high viscosity heavy oil resources are produced primarily by steam. For instance, steam assisted gravity drainage (SAGD) is used widely for the exploitation of bitumen from relatively shallow reservoirs in Alberta, Canada. However, to increase the efficiency of SAGD operations and to improve economics, it has been proposed to add solvent to the injected steam.
With solvent injection, there is an increase in the production rate and a reduction in the required injected steam, resulting in a lower steam-bitumen ratio (SBR). Higher concentrations of injected solvent show additional enhancement in oil production rate including some of the solvents. Although simulation results show that the rates of solvent recovery vary depending on the concentration and the nature of solvent used. For optimal results, injection strategy needs to be adjusted depending on the geological conditions, solvent characteristics and reservoir properties.
The study presented in paper was motivated by observing promising results of a field test with solvent injection in a SAGD bitumen project. The study began with a compositional thermal simulator to quantify the benefits of solvent addition to the SAGD process (referred to as ES-SAGD) to produce bitumen more efficiently with lower energy requirements. A secondary objective was to determine the optimal and more cost-effective operational protocol for such solvent-steam injection projects.
The paper presents (1) the methodology used to model the ES-SAGD enhanced oil recovery process, and (2) reports the field and modeling results of the application of the ES-SAGD process to an oil sand project in Alberta, Canada.
Development of a Viscoelastic Property Database for EOR Polymers
Authors: Kim Do Hoon , Lee Seungjun , Ahn Chong Hyun , Huh Chun , Pope Gary A. 
Published: July 2010

Abstract
Partially hydrolyzed polyacrylamide (HPAM) and related polymers are widely used as mobility control agents in all chemical EOR applications, and an accurate characterization of their apparent viscosity in the reservoir rock is crucial for design and performance evaluation of these processes. Their apparent viscosity in porous media generally decreases as flow velocity increases; however, beyond a certain critical velocity, the apparent viscosity sharply increases, showing shear-thickening behavior. A procedure to predict both the shear-thinning and shear-thickening apparent viscosities, from the rheometer-measured shear and oscillatory viscosities, has been developed earlier and validated with corefloods (Delshad et al., 2008). In addition to the shear viscosity database developed earlier (Lee et al., 2009), a database of the oscillatory viscosities of the EOR polymers was therefore developed for wide ranges of polymer concentration, NaCl salinity and calcium content, and temperature. The generalized Maxwell model (GMM) is employed to estimate the relaxation time of the polymer solution, by making non-linear fitting of the measured G' and G" data to GMM. Empirical correlations were developed to predict the relaxation time, which is subsequently used to quantify the shear-thickening portion of the apparent polymer viscosity under different process conditions. The apparent viscosity estimated matches reasonably with the available coreflood data.
Low-Cost, High-Performance Chemicals for Enhanced Oil Recovery
Authors: Yang Hyuntae , Britton Christopher , Liyanage Pathma J. , Solairaj Sriram , Kim Do Hoon , Nguyen Quoc , Weerasooriya Upali , Pope Gary A. 
Published: July 2010

Abstract
The ability to select low-cost, high-performance surfactants for a wide range of crude oils under a wide range of reservoir conditions has improved dramatically in recent years. We have developed surfactant formulations (surfactant, co-surfactant, co-solvent, alkali, polymer, electrolyte) using a refined phase behavior approach. Such formulations nearly always result in more than 90% oil recovery in both outcrop and reservoir cores when good surfactants with good mobility control are used. Chemical flood residual oil saturations are typically less than 0.04 and surfactant retention between 0.01 and 0.1 mg/g with these formulations using as little as 0.2% surfactant concentration and 30% pore volume ASP slugs. We describe some of the advances that have improved the performance, reduced the cost, increased the robustness, and extended the range of reservoir conditions for these formulations. There are thousands of possible combinations of the chemicals that could be tested for each oil and each chemical combination requires many observations over a long time period at reservoir temperature for proper evaluation, so it would take too long, cost too much and in many cases not even be feasible to test all combinations. In practice we use our scientific understanding of how to match up the surfactant/co-surfactant/co-solvent characteristics with the oil characteristics, temperature, salinity, hardness and so forth. We have synthesized and tested new surfactants with much larger hydrophobes and more branching than previously available. We have tested new classes of co-solvents and co-surfactants with superior performance. These new developments have enabled us to develop good formulations for both oils that react with alkali to make soap and oils that do not. We have significantly lowered the chemical cost needed for waxy crudes with very high equivalent alkane carbon numbers. We have good results for oils with API gravities as low as 17, high temperature, high salinity, and high hardness brines. Many of these developments are synergistic and taken together represent a breakthrough in reducing the cost of chemical flooding and thus its commercial potential in both sandstone and carbonate reservoirs.
Bayesian Decision Networks for Optimal Placement of Horizontal Wells
Authors: Rajaieyamchee M. A. , Bratvold R. B. , Badreddine A. 
Published: July 2010

Abstract
A systematic decision analytic methodology for providing insight into horizontal well placement decisions is presented. These decisions require access to real-time data and to input from subject-experts on the team and from the decision-maker. The available information and outcomes of alternatives are associated with uncertainty. Furthermore, the decision-maker may have multiple objectives, such as future productions, wellbore configuration, and drilling costs. The methodology uses Bayesian decision networks, also known as influence diagrams, to frame, analyze, and support operational decisions.
Influence diagrams are compact graphical representations of decisions and are based on decision and probability theories. They rigorously illustrate the interrelationships among decisions, key uncertainties, and value functions. Furthermore, they allow incorporating sensor readings, sub-surface model outputs, and experts&apos; knowledge, which enables probabilistic inference and decision support in real-time contexts. Finally, the influence diagrams models may be used to calculate value of information and of control.
In this paper, we focus on supporting well placement decisions involving multiple objectives. We explore the feasibility and suitability of using two potential extensions of the influence diagrams: (1) multiple-attribute utility influence diagram and (2) multiple-objective influence diagram. Using the methodology, the example shows that both extensions have the potential to improve the decision-making process within the multi-disciplinary team. They can provide further insight into decisions by ranking the value of information for key uncertainties from the perspective of different sub-groups of the drilling team.
Following a systematic decision analytic methodology, in particular, decision analysis cycle, and applying influence diagrams in drilling operations would create value by reducing losses (materials and drilling/completion processes&apos; downtime) and increasing future production through optimized well placement while drilling.