bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improvement of Sweep Efficiency of Miscible Displacement Processes in Heterogeneous Porous Media
Authors: Sajjadi M. , Azaiez J. 
Published: June 2014

Abstract
The viscous fingering phenomenon in displacement processes develops due to higher mobility of the injected fluid compared to that of the inhabitant fluid. It causes early breakthrough of the injected fluid and results in reduced sweep efficiency of the process. In addition to viscous fingering, heterogeneity of the porous medium can be a source of instability in displacement processes which has significant interactions with the viscous forces. The coupling between viscous fingering and heterogeneity induced channeling has been deemed to enhance the instabilities by increasing the growth rate of fingers formed inside the high permeable channels. This conclusion is questioned by the present work which investigates the effect of the injection velocity, diffusion coefficient, and width of the layers in a layered medium, on the coupling between the two named sources of instability. Numerical simulations and quantitative analysis of the instabilities show that the flow in heterogeneous media goes through four different regimes (initial diffusion, channeling, lateral dispersion, and viscous fingering) each dominated by a different flow mechanism that results in different growth rates of fingers. Based on these characterizations a method is suggested to design the process with an optimum injection rate such that the coupling between viscous fingering and heterogeneity attenuates the instability and results in improved sweep efficiency. Finding the optimum displacement parameters and improving the efficiency of the process helps to reduce the amount of solvent to be injected in the medium and therefore decreases the environmental effects of the recovery process.
Gasflooding-Assisted Cyclic Solvent Injection (GA-CSI) for Enhancing Heavy Oil Recovery
Authors: Jia Xinfeng , Zeng Fanhua , Gu Yongan 
Published: June 2014

Abstract
Cyclic solvent injection (CSI) process takes advantage of solution-gas drive and foamy oil flow for the oil production. However, it suffers from the solvent liberation during the production period. This results in an increased viscosity of the oil and its mobility loss. 0How to recover the partially diluted heavy oil becomes a key challenge for a CSI process. This paper first experimentally studies the conventional CSI processes with a one-well configuration, in which the solvent injector is alternately used the oil producer, and a two-well configuration, in which the solvent injector and oil producer are placed horizontally apart. It is found that during the one-well CSI test, some foamy oil that remains in the solvent chamber at the end of the production period of a previous cycle is pushed back by the injected solvent during the injection period of the next cycle. Such a back-and-forth movement of oil is not observed in the two-well CSI test. In addition, it is found that the oil saturation and oil relative permeability inside the solvent chamber are increased due to the foamy oil flow during the production period. Based on this fact, a new process, namely gasflooding-assisted cyclic solvent injection (GA-CSI), is proposed to enhance the performance of the CSI process. In this new process, a gasflooding slug is applied after the pressure depletion process to produce the partially diluted foamy oil in the solvent chamber. Results show that the GA-CSI process can increase the oil production rate by over 3 times, in comparison with the conventional CSI process.
Hybrid Thermal-Chemical Processes (HTCP) for Heavy-Oil and Oil-Sand Recovery
Authors: Taghavifar M. , Fortenberry R. , De Rouffignac E. , Sepehrnoori K. , Pope G. A. 
Published: June 2014

Abstract
For many shaley thin oil deposits, steam injection is not feasible. A hybrid process that involves moderate reservoir heating and chemical enhanced oil recovery is proposed, in which the same set of horizontal wells is used for injection of both energy and fluids. Simulations based on realistic Peace River field data were performed to investigate the performance of the proposed hybrid thermal-chemical process. Economic feasibility was established by optimization of the process.
Phase Behaviour Study of Butane / Athabasca Bitumen Mixtures Applicable for Thermal and Hybrid Solvent Recovery Processes
Authors: Nourozieh Hossein , Kariznovi Mohammad , Abedi Jalal 
Published: June 2014

Abstract
World production of heavy and extra-heavy oils has increased as the production of conventional crudes decline. However, the conventional oil recovery methods cannot effectively recover the heavy oil due to their high viscosities. The steam and/or solvent-based recovery processes can be considered as an efficient method for recovery of these resources. The performance of these techniques depends on the amount of solvent dissolved in the crude and the variation of oil viscosity with temperature. Thus, full understanding of the quantitative effects of the solvent on heavy oil viscosity and phase behaviours are crucial for feasibility studies, design and prediction of field-scale processes.
Phase behaviour study of bitumen diluted with heavy hydrocarbon solvents such as propane and butane have gained less attention in recent years. These solvents, as good candidates for recently developed recovery methods such as Expanding Solvent Steam-Assisted Gravity Drainage (ES-SAGD), would provide promising oil production rates. The aim of this research, thus, is the development of an understanding of the phase behaviour of butane / Athabasca bitumen systems. It deals with both vapor-liquid and liquid-liquid phase equilibriums over wide range of temperatures (up to 200°C) approaching the conditions of in situ steam processes and pressures up to 8 MPa.
Experimental results indicated that the vapor-liquid and liquid-liquid equilibrium formed over the studied temperature and pressure ranges. In the case of vapor-liquid equilibrium, the dissolved butane in bitumen leads to a significant oil viscosity reduction. The effect was higher at lower temperature and higher pressure. For liquid-liquid equilibrium, butane extracted light components from oil and formed a butane-enriched phase while the heavier constitutes such as asphaltene separated as second heavy liquid phase. Finally, the measured solubility and density data were adequately modeled with Peng-Robinson equation of state.
Asphaltene Precipitation Inhibitors and Phase Behaviour Control for Bitumen Recovery by Solvent Injection
Authors: Yakubov M. R. , Yakubova S. G. , Borisov D. N. , Romanov G. V. , Arbuzov A. E. , Yakubson K. I. 
Published: June 2014

Abstract
In situ bitumen recovery directly depends on the reduction of bitumen viscosity. Solvent injection is an alternative to thermal bitumen recovery by steam injection. Injection of solvents containing n-alkanes like butane, propane and naphtha may lead to asphaltene precipitation and deposition in the porous media and a possible negative effect on the ultimate oil recovery. Addition of an asphaltene inhibitor (stabilizer) to solvents is a way to prevent asphaltene precipitation and deposition in a reservoir. Efficiency of an asphaltene inhibitor depends on the characteristics of the inhibitor and bitumen properties.In addition to aromatic hydrocarbons, various natural and synthetic polar heteroatom species can be used as asphaltene inhibitors. Results of the study show that deasphalted bitumen is an effective asphaltene inhibitor and it is of the same strength as environmentally hazardous aromatic hydrocarbons. Resins prevent asphaltene precipitation and are similar to expensive synthetic inhibitors. Addition of less than 8 vol. % of resins to low boiling point n-alkanes provides total asphaltene stabilizationin the process of bitumen recovery. When n-alkanes are used as solvents, it is important to know the amount of precipitated asphaltenes in the reservoir. To obtain such data, an experimental study has been conducted to simulate bitumen recovery. A specially designed experimental set-up was used in the study. The experiments allowed a set of chemical additives to be selected to improve colloidal stability of asphaltenes in bitumen.
Nanoparticle Stablized CO2 in Water Foam for Mobility Control in Enhanced Oil Recovery via Microfluidic Method
Authors: Nguyen Phong , Fadaei Hossein , Sinton David 
Published: June 2014

Abstract
Nanoparticle stabilized CO2 in water foam can overcome the low stability challenges facing surfactant foams in reservoir conditions. Foams are effective in mobility control against viscous fingering during gas injection in enhanced oil recovery. This study presents a microfluidic approach to image and quantify the stability of foam at pore scale and the dynamics of the oil recovery process during water flooding, CO2 gas flooding, and nanoparticle foam flooding. In addition to chip scale flooding visualization, micro-scale imaging reveals the mechanisms of the viscous fingering in gas flooding and the high sweep efficiency of foam; micro-emulsion size and distribution in gas and foam flooding. Coated silica nanoparticle CO2 foam is significantly more stable than sodium dodecyl sulfate (SDS) foam at both pore scale and bulk foam. Nanoparticle foam can improve oil recovery an additional 17% IOIP after water flooding, this is 10% IOIP more efficient than CO2 gas flooding as a result of high sweep efficiency and increase in effective viscosity.
Results of Field Operation of a Distributed Flux Burner in a Heater Treater in a Northern Canada Heavy Oil Field; Thermal Performance and Firetube Life
Authors: Bartz David , Gotterba James 
Published: June 2014

Abstract
Horizontal heater treaters are commonly used to separate oil/water emulsions from enhanced oil recovery in heavy oil reservoirs. Conventional burners used in these heaters can cause hot spots that result in coking of the viscous emulsion on the outer surface of the firetube. This coking layer acts as an insulator and results in high tube wall temperatures, leading to an early failure of the firetube. The problem may be exacerbated when using polymer injection in the recovery fluid due to increased viscosity of the fluid and thermal breakdown of the polymer which creates a thicker insulating layer along the firetube.
To prevent this coking and tube-failure process, an all radiant, distributed flux burner distributes the heat over a much larger area with a very uniform flame shape compared to a conventional burner. The distributed flux burner has a porous ceramic cylindrical surface that provides surface-stabilized premixed combustion, such that combustion characteristics at every point along the cylindrical burner surface are nearly identical. This significantly reduces peak heat flux surrounding the combustion zone, reducing likelihood of hot spots and potential for coking compared to conventional burners. At the same time, more heat is distributed further down the length of the firetube, increasing heat transfer in the rear section of the heater and improving its overall performance and efficiency. Firetube life is increased because of the lower peak wall temperatures, and because less heat is needed to achieve the required process throughput and water cut.
In this follow up paper to SPE 166261-MS presented in October 2013, key operating data is provided from a recent burner retrofit of a horizontal heater treater at the Canadian oil sands field in northern Canada. The retrofit was completed in a two day effort. Operating data presented includes heater firing rate and tube wall temperatures over time. Based on the recent field data, thermal analysis, and measurements made in lab tests, the distributed flux burner is compared to a conventional burner with respect to thermal efficiency, process throughput, oil/water separation performance, and tube wall temperatures.
Development of Electrical Joule's Heating Simulation for Heavy Oil Reservoirs
Authors: Lashgari Hamid R. , Delshad Mojdeh , Sepehrnoori Kamy , de Rouffignac Eric 
Published: June 2014

Abstract
In the electrical joule's heating process, the reservoirs are heated in situ by electrical energy to reduce the viscosity. In principle, electrical current passes through the reservoir fluids due mostly to the electrical conductivity of saturated fluids such as saline water. The flow of electrical current through the reservoir leads the heat in the reservoir and thereby drastically reduces the oil viscosity.
In this process, electrical current can flow between electrical potential sources (wells) and generate the joule's heat. Therefore, the regions around the electrodes in (or around) the wells are extremely heated. Because the wells act as line sources for the electrical potential, greater heating takes place near the wellbore causing possible vaporization of water in that region. Since steam has very low electrical conductivity, it can reduce the efficiency of this process significantly. In this process electrical conductivity plays a very important role. In order to increase efficiency of this type of heating process, the presence of optimum saline water saturation is an essential design factor.
In order to simulate a challenging multiphysics problem, we use three Maxwell classical electromagnetism equations. These equations are simplified and assumed for low frequency to obtain the conservation of electrical current equation and Ohm's law. The conservation of electrical current and Ohm's law are implemented using a finite difference method in a four phase chemical flooding reservoir simulator (UTCHEM). The joule's heating rate due to electrical current is calculated and added as an energy source to the energy balance equation.
A typical reservoir model is built and constant electrical potential with alternating current (AC) is applied to this model to study the efficiency of the electrical joule's heating process in the presence of water saturated fracture and evaluate this efficiency at, above, and/or below the water boiling point. Results illustrate that water saturation in the presence of fracture and electrical conductivity of saturated rock have an important effect on the joule's heating process. In this paper, we show that since, steam is a non-conductive electrical phase, this process should be designed to keep the temperature below the boiling point by circulating water. This can prevent the evaporation leading to an increase in the process efficiency.
Electrical conductivity of water can also be easily increased by injecting high salinity water into the reservoir and increasing the amount of heat substantially. This is highly beneficial and the main advantage of the electrical joule's heating process that can obtain high recovery in comparison to other thermal recovery methods. In this paper the understanding of the influence of saline water and steam forming is a key finding in order to economically optimize the process to unlock heavy oil reservoirs.
SAGD Vacuum Insulated Tubing vs. Bare Tubing – Concentric and Eccentric Configurations: A Comparative Thermal Computational Fluid Dynamics Study
Authors: Karra Shashank , Chudiak Mike , Sinha Apoorv , Greg Boser 
Published: June 2014

Abstract
In a typical injector string in SAGD operation, steam is injected through tubing placed inside a casing. Heat losses through the string and casing can result in lower quality steam being injected into the formation, and hence reduce the productivity of a SAGD operation. An ideal SAGD operation would be one where no heat losses happen inside the tubing and all the latent heat is released inside the formation to heat up the heavy oil. Several methods have been used to reduce heat losses in the injector tubing. One of the methods is the usage of a vacuum insulated tubing (VIT) placed inside the casing. VIT consists of specially manufactured tubing with a getter coating to maintain vacuum between ID and the OD of the tube. This helps in preventing heat losses compared to normal bare steel tubing.
In an effort to demonstrate the benefits of VIT compared to bare tubing injector string, a comparative 3D Computational Fluid Dynamics (CFD) study was carried out. The objective of the study is to provide a comparison of heat loss in both VIT and bare tubing concentric and eccentric configurations. The simulation accounts for frictional and heat losses throughout the tubing and most importantly, condensation of steam inside the tubing as result of heat loss. The consideration of condensation inside the tubing is a critical component of the simulation as it in turn affects the heat loss through the tubing. The other significant aspect of the study is the consideration of eccentric and concentric placement of tubing string inside the casing and its effect on heat loss. This study uses an Euler-Euler Multiphase flow based approach which accounts for the fluid-fluid interactions such as drag, turbulent dispersion etc. between steam and water inside the tubing. The thermal phase change model in ANSYS CFD accounts for the condensation of steam into water.
The computed results successfully demonstrate the benefits of vacuum insulated tubing over bare tubing in maintaining steam quality in the vertical section of the wellbore. Also, the study shows reduction in steam quality for eccentric position of the bare tubing compared to concentric position. Most importantly this study demonstrates the capability of CFD to solve industrial scale complex problems and provide engineers with an insight into some of the challenging physics associated with a SAGD operation in the field.
Steam-Surfactant-Foam Modeling in Heavy Oil Reservoirs
Authors: Lashgari Hamid R. , Lotfollahi Mohammad , Delshad Mojdeh , Sepehrnoori Kamy , de Rouffignac Eric 
Published: June 2014

Abstract
Steam foam is a hybrid and novel method of the thermal and chemical flooding to improve the sweep efficiency of steam for producing heavy crude oils. Steam injection is a mature process to substantially reduce the oil viscosity in heavy oil reservoirs to increase its mobility. Steam flooding is an unstable displacement since the gravity of steam causes poor vertical sweep efficiency due to the gravity override in thick high permeability pay zones and poor areal sweep efficiency in high permeability channels with high connectivity. On the other hand foam reduces the mobility of steam by stabilizing the liquid lamellae that cause some or all of the steam to exist as a discontinuous phase. Therefore, foam plugs large pores to divert the flow into the low permeability zones and controls gravity override. Foam increases the pressure gradient slightly in the steam swept regions and leads to heating oil more efficiently when steam diverts into the cold unswept regions. Furthermore, surfactant mobilizes the high viscous oil by emulsification and reduction of interfacial tension. The synergy of steam, surfactant, and foam has the potential to greatly improve the recovery of heavy oil reservoirs.
Based on a literature survey, steam foam injection has been conducted in both laboratory corefloods and few field pilots. On the other hand, existing numerical simulators have not been able to capture the mechanisms involved in such a process. In this paper, we present the development and implementation of a new robust steam formulation in a four phase chemical flooding reservoir simulator (UTCHEM) to model and understand the contribution of each mechanism such as viscosity reduction, emulsification, and foam for mobility control. Results illustrate that the steam foam process controls the mobility of steam to avoid incomplete vertical sweep due to gravity segregation. Formation of the emulsion phase by condensing steam along with the presence of water leads to an increase in the emulsion viscosity and thereby decreases water production. The presence of surfactant and emulsification of oil either as water in oil or oil in water emulsions can also impact the displacement and propagation of viscous oil.
The mechanistic understanding of steam foam process and improvement of the heat transfer compared to conventional steam flooding is a key finding in this research to optimize the technology that unlocks heavy oil reservoirs with favorable economics.
Modeling the Diffusion Controlled Swelling and Determination of Molecular Diffusion Coefficient in Propane-Bitumen System Using a Front Tracking Moving Boundary Technique
Authors: Etminan S. Reza , Maini Brij B. , Chen Zhangxin John 
Published: June 2014

Abstract
Accurate estimation of molecular diffusion coefficient is necessary for the design and modeling of solvent-assisted recovery techniques for exploitation of heavy oil and bitumen resources. Several studies on molecular diffusion measurement have been conducted using various pure gaseous solvents but there are very few diffusivity measurements available for the propane-bitumen system. The scarcity of these data is due to the complexities arising in the modeling of dissolution of propane in bitumen. These include high solubility of propane in bitumen and subsequently, dramatic volume change of the diluted oil, drastic reduction of bitumen viscosity during dilution and the possibility of asphaltene precipitation.
In this work, a rigorous numerical model is developed to model the diffusivity of propane in bitumen based on real data. This model accounts for bitumen solution density change (swelling) as a result of dilution. A front-tracking moving boundary algorithm and numerical procedure is proposed which accounts for volume change of each grid at each time step. Those grids which experience diffusive flux, change sizes based on non-ideal mixing data available from measurement of solution density versus concentration. Finally, the Levenberg-Marquartd method was applied to estimate the propane diffusion coefficient based on laboratory measured gas-oil interface movement. A constant-pressure diffusion measurement experimental technique was used to measure mass of gas dissolved and solution height change in a propane-bitumen diffusion experiment at 413.7kPa (60 psia) and 827 kPa (120 psia) both in 24°C.
The experimental results show that the "no-swelling" simplifying assumption often used in diffusion measurement modeling studies, cannot be generalized to all gaseous solvents because based on our experiments, the bitumen solution volume can be increased by 50% due to propane dissolution. The estimated diffusion coefficient is compared with the results of other mathematical techniques available in the literature. It is shown that the no-swelling simplifying assumption used in unidirectional modeling of gas diffusion in bitumen leads to estimation of erroneous parameters when propane is the gas and oil density and oil volume change is neglected.