bluuebunny/crossref_metadata_2025_split huggingface dataset:
Heavy-Oil Recovery in Naturally Fractured Reservoirs with Varying Wettability by Steam Solvent Co-Injection
Authors: Al Bahlani A. , Babadagli T. 
Published: October 2008

Abstract
In heavy-oil recovery, although steam injection has no alternative in many circumstances, it may not be an efficient process under certain reservoir conditions. These conditions include deep reservoirs, where steam injection may turn out to be ineffective hot-water flooding due to excessive heat loss, and oil-wet fractured carbonates, where steam channels through fractures without effectively sweeping the matrix oil.
Solutions for heavy oil recovery in consolidated/unconsolidated sandstones have been proposed and some of them are currently in the commercial phase, including steamflooding and its different versions. A more challenging case is heavy-oil fractured carbonates where the recovery is usually limited only to matrix oil drainage gravity due to unfavourable wettability or thermal expansion if heat is introduced during the process. Wettability alteration is usually thought to occur at elevated temperatures which are difficult to achieve in deep reservoirs. Thus, improvement of matrix oil recovery requires different methodologies. We propose a new approach to improve steam/hot-water injection effectiveness and efficiency for this type of reservoir.
Static imbibition experiments were run on Berea sandstone and carbonate cores with different wettabilities and for different oil viscosities ranging between 200 cp and 14,000 cP. For wettability alteration, cores were either aged or treated by a wettability altering agent. The experiments were conducted initially in imbibition cells in a 90 °C oven to mimic the matrix-fracture interaction in steam condensation zones. Due to its high boiling point, heptane was selected as the solvent and the core samples were exposed alternately to high temperature imbibition and solvent diffusion. The main ideas behind this process were to enhance capillary and gravity interaction by reducing viscosity (heat and solvent effect) and altering wettability (solvent effect). The results showed that further reduction in oil saturation due to s solvent diffusion process preceded by hot water is remarkably fast and the ultimate recovery is high. The magnitude of recovery depends on wettability and the amount of water existing in the core. It was also observed that solvent retrieval is a very fast process and may increase to 85-90% depending on core type, wettability, and saturation history.
Design and Optimization of Hybrid Ex Situ / In Situ Steam Generation Recovery Processes for Heavy Oil and Bitumen
Authors: Yang Xiaomeng , Larter Stephen Richard , Gates Ian Donald 
Published: October 2008

Abstract
Given the enormous capital costs, operating expenses, flue gas emissions, water consumption and handling conducted in thermal in situ bitumen recovery processes, improving overall efficiency by lowering energy requirements and environmental impact of these production techniques is a priority. Steam Assisted Gravity Drainage (SAGD) is a common thermal technique used in Athabasca reservoirs. Although SAGD is effective at producing bitumen, its energy efficiency can be poor due to enormous heat losses on the surface and in the wellbore. Given current attention to carbon dioxide emissions and water handling, there is a need to design and implement Reduced Emissions to Atmosphere Recovery (REAR) processes for heavy oil and bitumen extraction. One alternative is to generate steam in situ by in situ combustion (ISC) by injecting air or oxygen into the formation thus reducing or even avoiding transfer heat losses. In ISC, an energy generating oxidation zone propagates within the formation and generates heat which enables in situ steam generation from formation and injected water within the reservoir. In this research, design and optimization of hybrid in situ steam generation recovery processes are examined by using advanced three-dimensional reactive thermal reservoir simulation. Hybrid techniques combine the advantages of both ex situ steam and in situ steam generation processes in that it raises overall energy efficiency, lowers natural gas consumption as fuel, reduces overall gas emissions as well as water usage to generate steam, all on a per unit oil basis. The research here identifies steam-air based hybrid processes that use roughly 70% of the energy of conventional SAGD to recover the same amount of oil with substantial reduction of flue gas emissions and water use as viable REAR processes worthy of scaled physical model and potentially field testing.

Introduction
Two requirements of in situ heavy oil recovery processes must be met for successful performance: first, make the heavy oil or bitumen mobile, and second, move the mobilized oil to a production well. Since virgin viscosities of Athabasca bitumen generally exceed several million cP, especially near the base of the oil leg (Larter et al., 2006; Gates et al., 2008), the key to success is first measured by the process' ability to mobilize the heavy oil or bitumen. There are four main methods to accomplish this: heat, solvent dilution, solvent deasphalting, and in situ upgrading. An efficient source of heat is in situ combustion (ISC) which also provides combustion gases that could potentially aid movement of mobilized bitumen in the reservoir.
NCG Behavior in SAGD - A Numerical Simulation Analysis
Authors: Heron Caroline , Thimm Harald , Sullivan Laura , Atkinson Ian 
Published: October 2008

Abstract
The injection of non-condensable gases (NCG's) with steam in SAGD is a concept that has been much discussed in the literature, and tested via laboratory studies, and in a small number of field pilots, the most comprehensive being the UTF Phase B. There has been considerable discussion, both positive and negative, regarding the behaviour of these gases in the steam chamber, and their impact on ultimate bitumen recovery. Benefits to SAGD productivity have been suggested by some, while other authors have projected impacts on bitumen recovery.
The authors have reviewed the results of methane injection in several projects, and used thermodynamic theory to develop a method to effectively model this behavior via simulation. While conventional simulators use the Peng-Robinson Equation of State, the effectiveness of EOS's become challenging at high temperature. In addition, the effects of recent developments in high temperature solution thermodynamics become significant with increasing temperature in SAGD.
AOSC has developed a method of modeling the effects of NCG in a steam zone, via the development of a new set of equilibrium values for methane exchange between the oil/gas phase, water/gas phase and oil/water phases. This paper will present the results of these simulations and predicted impact of methane injection on SAGD performance, as well as implications for other NCG's.
Experimental and Numerical Modeling of Heavy-Oil Recovery by Electrical Heating
Authors: Hascakir B. , Babadagli T. , Akin S. 
Published: October 2008

Abstract
Electrical heating for heavy-oil recovery is not a new idea but commercialization and wider application of this technique require detailed analyses for determination of optimal application conditions. In this study, applicability of electrical heating for heavy-oil recovery from two heavy-oil fields in Turkey (Bati Raman and Camurlu) was tested experimentally and numerically. The physical and chemical properties of the oil samples for the two fields were compiled and measured. Then, core samples were exposed to electrical heating and oil recovery performances by the retort technique were determined for different conditions. Experiments with and without using iron powder were analyzed and in-situ viscosity reduction during the heating process was determined through a history matching process using the simulation of the laboratory experiments. Experimentally obtained oil recovery and temperature distributions were used in this history matching exercise. Iron powder addition to oil samples causes a decrease in the polar components of oil and the viscosity of oil can strongly be influenced by the magnetic fields created by iron powders. Therefore, three different iron powder types at three different doses were tested to observe their impact on oil recovery. Experimental observations showed that viscosity reductions were accomplished as 88% and 63% for Bati Raman and Camurlu crude oils, respectively, after 0.5% Fe addition, which was determined as the optimum type and dose for both crude oil samples. Different parameters (thermal diffusion coefficients, oil viscosity, and relative permeabilities) that are needed in numerical modeling as data were determined through experimentally validated numerical modeling study. Furthermore, field scale recovery was tested numerically using the parameters obtained from laboratory scale experimental and numerical modeling results. The power of the system, operation period and the number of heaters were optimized. Economic evaluation done using the field scale numerical modeling study showed that the production of one barrel petroleum costs about 5 USD and at the end of 70 days, 320 barrels petroleum can be produced. When 0.5% Fe is added, oil production increased to 440 barrels for the same operational time period.
Simulation of a SAGD Well Blowout Using a Reservoir/Wellbore Coupled Simulator
Authors: Vanegas P. J. Walter , Cunha Luciane B. , Worth Darren J. , Crepin Stephan 
Published: October 2008

Abstract
Under the expected operating conditions of a Steam Assisted Gravity Drainage (SAGD) pilot project, it is anticipated that both the injection and the production wells will be able to flow unassisted to surface should a loss of well control incident occur. Industry practice regarding the design of such flowing wells dictates that the well completion include double barriers in the production tubing string and the production casing annulus. Unfortunately, downhole equipment suitable for such a high temperature application does not currently exist. To help evaluate the comparative risk between a double and single barrier completion, a reservoir modeling study was conducted to investigate the flowing potential (flow rates, durations and composition of the fluids) of the SAGD pilot wells under various blowout scenarios.
This paper presents the results of this reservoir modeling study in terms of the coupled wellbore/reservoir behavior during the blowout condition. A commercial coupled wellbore/reservoir simulator was used along with a "custom" code developed to include a critical choke velocity constraint into the reservoir simulation considerations.
The various blowout scenarios investigated include flow through both the injection and the production wells, at three different points during the production life of the well pair (beginning of the steam injection phase, middle of the steam chamber development and end of the steam injection phase) and through three possible flow paths (through the tubing, through the tubing-casing annulus and through both the tubing and the annulus).
The reservoir modeling confirmed that both the injection and the production wells in this SAGD application have the potential for a blowout lasting for significant periods of times should a loss of well control occur, and with liquid rates that can be over 50 times the normal production liquid rates.
Geomechanics for Interpreting SAGD Monitoring Using Micro-Seismicity and Surface Tiltmeters
Authors: de Pater Hans , de Koning Johan , Maxwell Shawn , Walters Dale 
Published: October 2008

Abstract
We have modeled the warm-up phase of a SAGD project using a coupled reservoir simulator and stress model. We matched the injection pressure by adjusting the reservoir permeability. A fair match between data and model was obtained. Micro-seismic monitoring indicated localized injection at the toe, which was used in the model. Also, the seismic signature indicated strike slip and possibly overthrust fault slippage or casing failure as cause of the seismicity. This confirms the reservoir and stress model used in the interpretation. While most of the steam was injected at the toe, the uplift was largest at the heel of the well. This can be best explained by reservoir heterogeneity, which implies that surface heave measured with tiltmeters can best be interpreted using a geomechanical model. The matched coupled model can be used for optimizing the completion and injection process.
In-situ Water Vaporization Improves Bitumen Production During Electrothermal Processes
Authors: Wang Jie , McGee Bruce , Kantzas Apostolos 
Published: October 2008

Abstract
Thermal methods for heavy oil and bitumen recovery include the injection of steam as in the SAGD (Steam Assisted Gravity Drainage), CSS (Cyclic Steam Stimulation), and steam flooding processes. Thermal energy increases the temperature of the oil, reducing its viscosity and thereby allowing it to flow efficiently towards a production well. The electro-thermal process is an alternative (possibly a compliment) to steam injection processes. With ever-increasing natural gas prices, or corresponding reduction of natural gas supply, electro-thermal processes can be economically competitive compared to other thermal methods. An optimized electrothermal process can bring over 75% of heavy oil or bitumen to the surface as demonstrated by a recent field pilot in the Athabasca oil sands.
This study aims at optimizing electrothermal processes by vaporizing water in-situ. The Computer Modeling Group (CMG) reservoir simulation software is used to perform a series of preliminary simulation studies of electro-thermal heating in the Athabasca oil sands. First of all, the incremental oil recovery by vaporization is estimated based on a three block conceptual model. Secondly, a field scale model is set up to evaluate the effect of electrode spacing, water injection rate and electrical heating rate on the ultimate bitumen recovery. A statistic tool is used to analyze the simulation results in order to spot the optimum condition for maximizing bitumen production with water vaporization in-situ.
Simulation results showed that the incremental recovery brought by the water vaporization could be as high as 25% OOIP for Athabasca oil sands reservoirs based on the conceptual model. A sensitivity study on the field scale model, showed that the combination of medium electrical heating rate, low water injection rate, and small electrode spacing can maximize bitumen production economically with mild water vaporization in-situ.
The study demonstrated a promising technique for the future heavy oil / bitumen production. It also showed that electro-thermal processes could be operated independently and produce considerable amount of bitumen economically.
Preconditioning Methods to Improve SAGD Performance in Heavy Oil and Bitumen Reservoirs with Variable Oil Phase Viscosity
Authors: Gates I. D. , Larter S. R. , Adams J. J. , Snowdon L. , Jiang C. 
Published: October 2008

Abstract
The majority of the world's petroleum resources are contained in heavy oil and oil sand reservoirs. Average recoveries from heavy oil and oil sand reservoirs are typically low ranging from 5 to 15 percent for cold heavy oil production and from 30 to 85 percent for steam-based in situ processes. There are two reasons for this: first, geological heterogeneity in the form of variable porosity and permeability properties and secondly, fluid heterogeneities in the form of variable saturations, fluid compositions and thus viscosity. Geological heterogeneities refer to spatial variations of porosity, permeability, relative-permeability curves, shale and mud layers, etc. Fluid heterogeneities refer to spatial variations of the fluid composition and properties such as viscosity and density. Given that the permeability often varies by less than an order of magnitude whereas the oil viscosity varies by up to two orders of magnitude in a bitumen reservoir, the controlling variable on recovery of these resources is often fluid compositional variations. Due to the large viscosity contrast between oil and water at native reservoir conditions water is often the most mobile phase within a bitumen reservoir. This research identifies preconditioning techniques that can be used to alter reservoir or fluid (oil or water) properties prior to thermal recovery reducing adverse reservoir factors and improving recovery, environmental impact and process economics. We describe here a simulation study of one application related to modifying the variation of oil viscosity in the reservoir prior to steam injection. The methods make use of mobile water within the reservoir, to distribute viscosity-reducing agents before steam injection, and represent another means of geotailoring recovery processes to the features of the reservoir. The main benefit is that recovery process performance, both in terms of oil production rate and thermal efficiency, is improved.
Accurate Numerical Simulation of Reaction-Diffusion Processes for Heavy Oil Recovery
Authors: Govind Pradeep Ananth , Srinivasan Sanjay 
Published: October 2008

Abstract
Many examples of reaction-diffusion processes are encountered in enhanced heavy oil recovery applications. A typical instance of such a process is when a chemical diffuses through a fluid column and then undergoes reaction with another chemical species. The reaction products further diffuse through the porous media. The challenges involved in modeling these processes are accurate representation of the propagation of the reaction front which is very localized and accurate depiction of diffusion which is one of the main transport mechanisms. We evaluate a simulation model for the displacement of carbon dioxide in a simultaneous injection of carbon dioxide and elemental sodium in a heavy oil reservoir. The main objective of using sodium in this process is the highly exothermic reaction of sodium with the in-situ water that results in the liberation of heat that in turn reduces the oil viscosity. Another important advantage of this process is the formation of sodium hydroxide that reduces the interfacial tension at the bitumen interface.
The modeling of the mechanism of transport of sodium to the reaction interface through diffusion and the subsequent displacement of the reaction zone was attempted using the commercial software STARS™. When sodium suspended in liquid carbon dioxide is injected into the reservoir, it has to diffuse through the carrier phase and then interact with water. This mechanism has to be adequately captured at the scale of the simulation grid blocks. A random walk diffusion algorithm with reactive dissipation is implemented to more accurately represent reaction/diffusion processes and to study their scaling characteristics.
Potential Use of Produced Oil Sample Analysis to Monitor SAGD Performance
Authors: Li Z. , Wollen C. , Yang P. , Fustic M. 
Published: October 2008

Abstract
Bitumen is too viscous to be produced by conventional recovery methods and significant amounts are too deep to be recovered by mining, necessitating enhanced in-situ oil recovery techniques. The majority of operating and planned in-situ bitumen projects employ thermal techniques to lower the bitumen's viscosity, allowing it to be produced. The viscosity characteristics of the bitumen consequently have a significant effect on production rates and recovery. Bitumen viscosity and chemical composition variation with depth within a single reservoir column has been reported for many heavy oil and oil sand reservoirs in the Western Canadian Sedimentary Basin and elsewhere in the world.
This study investigates, through reservoir simulation, the effects of viscosity variation with depth on the SAGD process and the resulting produced oil characteristics. Oil characteristics, including chemical component and viscosity profiles were built into a variety of reservoir simulation models. The simulation results indicate that the produced oil viscosity and component concentration vary as the steam chamber develops. The trend of the produced oil characteristics is related to the original in-situ profiles of and the reservoir flow barriers. In conjunction with oil rate, surface heave, or other available data, the produced oil characteristics may be used to suggest steam chamber development and the presence of barriers or baffles. The presented approach has potential to become a useful technique for SAGD steam chamber growth monitoring and production optimization.
Applicability of CO2-Based Vapex Process to Recover Athabasca Bitumen
Authors: Badamchi-Zadeh A. , Maini B. B. , Yarranton H. W. 
Published: October 2008

Abstract
Employing CO2 as the non-condensable gas in the Vapex process is an attractive option that could provide environmental benefits of CO2 sequestration along with improved Vapex performance. Mixtures of CO2 and a hydrocarbon such as propane allow the solvent to be tailored to different reservoir conditions. To test potential solvent mixtures, the phase behavior and physical properties and physical model experiments are required. We have previously reported on the phase behavior, viscosity and density of the CO2-propane-Athabasca Bitumen systems (Badamchizadeh et al., 2008a,b). These results confirmed the ability of carbon dioxide and propane mixtures to sufficiently reduce Athabasca bitumen viscosity and were used to design the solvent compositions utilized in the physical model tests reported here.
The experimental approach used in these tests was to use a fixed composition of the CO2 and propane mixture as the Vapex solvent. The objective of this work was to evaluate the performance of this solvent in recovering the Athabasca bitumen. The experiments were carried out at room temperature in a physical model. In-line measurements of the density and viscosity of the produced oil were used to gain further insight into the mechanisms involved in the process.