bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Diluents on Interfacial Properties and SAGD Emulsion Stability: I. Interfacial Rheology
Authors: Nguyen Duy , Phan Jenny , Balsamo Vittoria 
Published: June 2013

Abstract
In SAGD (Steam Assisted Gravity Drainage) operations the produced fluids are a complex water-in-oil-in-water (W/O/W) emulsion. A diluent, which is a major operational cost item, is often added to the produced fluid to reduce the density and viscosity of the heavy crude, thereby facilitating oil and water separation. The variable quality of the diluent and various types of diluent can increase the emulsion stability and cause the dehydration of the oil to be more difficult as there are more surface-active agents added to the oil from the diluent stream. In this work, the effect of various diluents on interfacial films was studied by measuring interfacial elasticity and "dynamic" surface pressure isotherms and then correlated with emulsion stability and oil dehydration. Compressibility, crumpling film ratio (ratio of the compressed surface area to the original area at which the interface starts to collapse), and surface pressure were determined from the surface pressure isotherms.
When interfacial rheological measurements were conducted on fluids treated with the diluent, the system behaved as if a bidimensional gel near its gelation point had organized at the interface. In other words, adsorbed amphiphilic materials such as asphaltenes and resins had self-aggregated at the interface and formed a network, which presents all the rheological characteristics of a gel, acting as a stabilizing mechanism for produced emulsions. When the interface was aged for 20 hrs, its gel strength was nearly 70% higher than the fresh interface, suggesting an explanation why aged emulsions are more difficult to treat. As the surface area of an oil droplet submersed in water is reduced, asphaltene molecules adsorbed onto the interface are drawn closer together and resist compression. This gives information about how rigid the drop surface becomes. The software of interfacial rheological measurements can be set up to capture drop images during compression measurements, allowing us to observe the formation of rigid interfacial skins at the oil-water interface. The amount of skin formed at a droplet surface increased with increasing asphaltene concentration and varied in different diluents. Unlike elasticity and interfacial tension measurements, this method can predict emulsion stability in different diluents and at various asphaltene concentrations. A correlation exists between the interfacial compressibility, crumpling film ratio, and emulsion stability: the higher the crumpling film ratio and the lower the compressibility, the more stable the emulsion. This new test method gives more insights into mechanisms of emulsion stabilization caused by the diluent and asphaltene and potentially can be employed to study the structure and demulsifying performance relationships of EBs (emulsion breakers) and REBs (reverse emulsion breakers).
Waterflooding: Same Old, Same Old?
Authors: Alvarez J. M. , Sawatzky R. P. 
Published: June 2013

Abstract
Since the accidental discovery in the late 1800s of the benefits of injecting water into oil reservoirs to improve recovery, water has been the injection fluid preferred by the oil industry for use in recovery processes. Traditionally, waterflooding is considered an effective secondary recovery method for light and medium oil reservoirs. However, as production rates in these conventional reservoirs continue their decline, waterflooding is being considered, and used, more and more for the exploitation of more challenging heavy oil resources. Despite the unfavorable mobility ratio between injected water and more viscous heavy oils, many waterflood projects have been undertaken in heavy oil reservoirs around the world. However, the literature on heavy oil waterflooding is sparse. Those papers that have been published present a wide range of recovery factors for projects, and offer conflicting information on the theory and mechanisms involved in heavy oil waterfloods. The good news is that there is a long history in western Canada with waterfloods in heavy oil reservoirs, spanning more than 50 years. A vast amount of data and anecdotal information has been generated from these waterfloods. This could provide a key to raising the limits, in terms of reservoir conditions, under which waterflooding would be viable.
In this paper we will discuss lessons learned after 50 years of waterflooding in heavy oil reservoirs, identify gaps in the application of the process, and speculate about what the future may hold as this technology evolves.
Case Study: Thermal Enhance Bohai Offshore Heavy Oil Recovery by Co-stimulation of Steam and Gases
Authors: Sun Yongtao , Zhao Lichang , Lin Tao , Liu Haitao , Sun Yubao , Zhong Liguo , Dong Zhaoxia , Hou Jirui , Li Yiqiang 
Published: June 2013

Abstract
Although there is abundant heavy oil resource in Bohai oilfield, only limited oil production is obtained by non-thermal production technologies such as ESP in past. The practical challenging of thermal production technologies, for instance, CCS and SAGD is the difficulty to install the large conventional steam generator onto offshore production platform.
In order to recover offshore heavy oil in Bohai Oilfield, the largest offshore oilfield in China, at large oil production rate in the limited production platform lifetime, a portable steam and gas generator is developed to produce high temperature and high pressure steam, CO2 and N2 on production platform using diesel oil or natural gas as fuel. The temperature of produced steam could be regulated, usually 150 to 300, and the pressure is up to 20MPa. The components such as fuel tank, water treatment, air injection unit could be easily resembled on the production platform. The steam generated and exhausted CO2and N2 could be injected into oil well to stimulate offshore heavy oil reservoir in huff and puff or SAGP processes.
In past three years, there are 2 non-thermally completed heavy oil wells and 7 thermally completed heavy oil wells are successfully stimulated by co-stimulation with steam and flue gas generated by above generator. As a result, the gas generator is operated soundly, the engineering design and related implement techniques such as insulation, sand control and corrosion inhibition are feasible, and oil production rate increased obviously (more than 100 m3/day oil production rate obtained, it is up to 5 times than cold production), total increased heavy oil production compared to cold production per cycle is about 5000m3 to 10000m3. Primarily, it shows that co-stimulation is much effective and practical for offshore heavy oil production.
In this paper, cases of co-stimulation with steam and flue gas are introduced in detail, and related techniques and practices discussed as well.
Observations on the Mechanisms of Solvent-Additive SAGD Processes
Authors: Edmunds Neil R. 
Published: June 2013

Abstract
Solvent-additive processes (SAP) are a promising, but challenging technology. Perhaps the biggest challenge from an engineering point of view, is that simulators probably work some of the time, but not all of the time; and there is no information about where the line between occurs, or what the correct answer should be, after the line is crossed. Other serious problems are the many degrees of freedom in SAP process design, and the non-linear relationships between process inputs and economic results. There are too many possible designs to try randomly for even a single reservoir, and there is limited theory to interpolate or scale available experimental data.
This paper attempts to assemble some known pieces of the puzzle, and to explore how they may fit together to explain and predict SAP performance characteristics
First, some familiar PVT relationships are presented, with examples using temperature as the independent variable. This helps to clarify the choice of solvent, as a function of reservoir pressure, and also to understand the effect of the increasing solvent "dose". It is shown that SAP will create a double front, one where the water is condensed, and a second where the solvent is absorbed by, and drains with, the oil. A vapor blanket separates the two fronts.
Secondly, simple estimates are given for the temperature distribution in the vapor blanket (i.e. solvent-active zone). Together with PVT data for the same pressure, these allow the thickness of a vapor blanket to be estimated.
Finally, SAP mass transport limits are considered, by observing that the second front essentially constitutes VAPEX. The Butler-Mokrys theory is discussed, in view of its failure to predict certain experimental results; it is argued that this results from neglect of capillary pressure effects, which in fact are dominant at the front. A purely empirical correlation by Nenniger is introduced, which can be rearranged to predict the maximum solvent speed, also as a function of temperature.
Incorporating 4D Seismic Steam Chamber Location Information into Assisted History Matching for A SAGD Simulation
Authors: Hiebert A. D. , Kumar A. , Card C. , Close J. C. , Ha H. , Morrish I. C. , Sun F. , Porter S. 
Published: June 2013

Abstract
Modern assisted history matching tools allow an engineer to specify the uncertain parameters in a simulation dataset then perform an optimization to minimize the difference between observed field data and the corresponding simulation outputs. During this optimization, multiple simulations are run, with the uncertain parameters varying within the ranges specified by the engineer. The difference between the observed field data and the simulation output is measured by an objective function. Standard objective functions have been reported in the literature for the difference between observed and simulated production and injection rates, and for measurements in time and space done at observation wells. In this work we incorporate an additional objective function term that measures the difference between the observed and simulated steam chamber location and shape. In addition, the differences in 3D volumes were visualized, which lead to a better physical understanding of what parameters should be adjusted during a history match.
For a steam injection process like Steam Assisted Gravity Drainage (SAGD), 4D seismic may be used to determine where a steam chamber is located in a reservoir at a point in time. The objective function developed in this work measures the difference between an observed chamber's shape and location in the reservoir and the corresponding shape and location for the chamber indicated in the simulation output. The objective function is a binary mismatch function, checking each simulation grid block to see if the seismic chamber and the simulation chamber agree or disagree, and calculating the ratio of the total volume of disagreements over the total volume of agreements.
This steam chamber mismatch function was included in an assisted history match performed on a well pair from Suncor Energy's SAGD project at Firebag. The inclusion of this additional information added additional constraints to the simulation model, leading to a conceptually more dependable history match and a better geological and dynamic characterization of the reservoir.
Coupled Geomechanical and Thermal Simulation of SAGD Process
Authors: Bao X. , Chen Z. , Dong C. , Deng H. , Liu H. , Zhong H. 
Published: June 2013

Abstract
SAGD (steam assisted gravity drainage) is a coupled geomechanical problem because continuous steam injection changes reservoir pore pressure and temperature, which can alter the effective stress in-situ, resulting in the dynamic changing of porosity and permeability. A conventional modeling approach remains difficult in capturing the Flow-Stress interactions, as well as in modeling surface deformation during injection and production. Therefore, to optimize SAGD operating strategy and minimize the environmental risk, a coupled geomechanical simulation that solves the flow and stress equations simultaneously is the solution. In addition, thief zone SAGD performance is very sensitive to the high injection pressure, which may cause the great heat loss due to steam breakthrough into thief zones.
Flow-stress coupling (STARS+Geomechanics) using a modular coupled approach is investigated in this paper. The iterative coupling between the thermal simulator and stress model has the advantage of flexibility and computational efficiency, where pressure and temperature changes occurring in the reservoir simulator are passed to the geomechanical simulator to compute the changing of stress and strain, and update porosity and permeability simultaneously. A generalized hyperbolic constitutive model for oil sands that approximates the dominant mechanism is implemented; the failure envelope is defined by a Mohr-Coulomb relation controlled by the friction angle. Coupled geomechanical simulation results demonstrate the permeability enahncement and surface heave, caused by dilation and thermal expansion, associated with the steam injection.
A control volume and K-value based multiphase multicomponent thermal simulator (FATS) is utilized aiming to investigate the detrimental effect of thief zones (top water and top gas). Results have been validated by STARS, demonstrating that the steam chamber has been shifted into thief zones after steam breakthrough under high injection pressure.
Synergistic Interactions Between Different Components on Blending
Authors: Kailey Ishpinder , Behles Jacqueline , Blackwell Catherine 
Published: June 2013

Abstract
Chemical demulsification is the most widely used method for breaking water-in-diluted bitumen emulsions in oil sands processing. In this paper, the properties and the performance of six intermediates and three blends were investigated. The intermediates and blends were characterized by their relative solubility number (RSN). The results showed that the RSN is an additive property. The dehydration efficiency of the blends was higher than the individual components at the same dosage, indicating there were synergistic interactions among the components on blending. The performance of the demulsifiers was correlated to the interfacial tension (IFT), yield stress of underflow, and bitumen loss to tailings. The equilibrium IFT results did not illustrate any correlation with the performance of the demulsifiers. The yield stress of the underflow, which included settled solids, water, and a rag layer increased with increasing dosage of either intermediate or blend. In addition, the bitumen loss to underflow increased with increasing dosage of either intermediate or blend. The yield stress and bitumen loss to underflow reduced on blending the intermediates. The bitumen loss to underflow increased the size of the aggregates present in the underflow, increasing their immobility and constriction to flow, and eventually a higher yield stress.
Challenges of Multiphase Flow Metering in Heavy Oil Applications
Authors: Viana Flavia , Mehdizadeh Parviz , Owston Rebecca A. , Supak Kevin R. 
Published: June 2013

Abstract
Multiphase flow metering has become very important to the development of marginal oil and gas fields, since the economics of producing these fields do not justify the construction of new platforms; instead, they are tied back to existing infrastructure. In such cases, several fields are tied back to common facilities requiring each unprocessed stream to be measured prior to comingling. Multiphase flow metering is also a promising alternative to traditional test separators in those cases where having a large vessel is not feasible, and in the production of heavy oils where separation represents a big challenge.
The increasing need for energy, combined with depleting worldwide light oil resources, has generated substantial interest in heavy oil reserves. Heavy oil applications involve low API gravity oils which are also very viscous. The production, transport, metering, and processing of heavy oils present a number of challenges associated with the increased resistance to flowing given the high-viscosity characteristics of heavy oils and the tendency to form emulsions. The hydrodynamics of high-viscosity oils presents various challenges in multiphase flow metering, including dependence of the discharge coefficient on the viscosity of the oil at low Reynolds numbers on Venturi-type meters used in commercially-available multiphase flow meters (MPFMs). Other issues are also related to the tendency of heavy oils of forming emulsion and the effect of complex fluids on the performance of the meters.
This paper presents a review on heavy oil, multiphase flow metering, and the challenges faced by multiphase flow meters in heavy oil applications. The purpose of this review paper is to provide relevant information that can be used in the selection of multiphase flow meters for heavy oil applications. While other studies on the subject have focused on one specific problem or flow metering technology, this paper provides a general overview of the various issues across existing flow metering technologies. Special focus is given to in-line multiphase flow meters, since they provide some advantages over other types of MPFMs in heavy oil applications. In-line MPFMs have the ability to measure the oil, water, and gas flow rates directly in the multiphase flow stream without separation of the phases. The inherent characteristics and physical properties of heavy oils impose additional constraints to MPFMs, as well as the enhanced recovery methods employed for the production of heavy oils. The main issue is associated with the tendency of heavy oil to form complex mixtures (emulsions, foam, etc.) as they can lead to inaccurate measurement of phase fraction and flow rates. The additional water or steam added to the reservoir to increase recovery rates can result in flow instabilities, high water cuts, and changes on the continuous phase. Thermal production methods can also cause inaccurate readings and compromise the integrity of the meters.
Polymer/Gel Enhanced Foam Flood for Improving Post-Waterflood Heavy Oil Recovery
Authors: Zhou Wei , Dong Mingzhe , Wang Xiaoqi 
Published: June 2013

Abstract
Due to its low cost, excellent injected performance and good blocking capacity for high permeability zones, polymer/gel enhanced foam flood has been proven as an efficient method to improve oil recovery. This paper presents an optimization study of the slug size of polymer enhanced foam (preformed foam) and a study of gel-enhanced foam on oil recovery and high permeability zone blocking for a Saskatchewan heavy oil. A series of sandpack tests with different slug sizes are conducted to investigate the oil recovery performance of polymer enhanced foam flood. The experimental results indicate that, by considering the foam flood efficiency, the optimal slug size of polymer enhanced foam flood is 1.5 PV in this study. For gel enhanced foam flood, the single-sandpack tests suggest that the gel enhanced foam flood and extended waterflood can still significantly improve the oil recovery (up to 24.1%) after polymer enhanced foam flood; the parallel-sandpack test indicates that gel-foam can efficiently promote the oil recovery in the lower permeability layer by modifying the injection profile. In summary, gel enhanced foam can be used as the fourth recovery method for heavy oil reservoirs after initial waterflood and polymer enhanced foam flood.
An Integrated Practical Approach to Forecasting Multi-well SAGD Production using Analog, Analytical, and Numerical Modeling Techniques
Authors: Adesimi Yomi , Wang Jin 
Published: June 2013

Abstract
There are many challenges in making rigorous economic decisions for capital intensive SAGD projects. Among those challenges is the need for reliable production forecasts. The traditional forecasting techniques of analogy, numerical simulation, and analytical methods are each burdened with their own drawbacks. The resulting production forecasts can vary to such a degree that the validity of the results obtained from each approach is questionable. When used in isolation, the individual forecasting techniques yield a significantly different result from each other, making economic decisions an imposing task.
This paper presents an integrated ternary approach which draws on the strengths of each methodology. A database of 70 SAGD well pairs from Suncor's MacKay River property is used to obtain analogs. It captures the variations in reservoir quality, reservoir thickness, and well design. In addition, an internally developed Monte-Carlo analytical tool, based on fundamental physics (i.e. material/energy balance, gravity drainage theory), is used to generate a probabilistic range of oil and SOR forecasts. This tool utilizes statistical distributions of static and time- dependent variables. Finally, numerical simulation models are also generated in conjunction with Suncor's geostatistical modeling process. The simulation input parameters are obtained through validation of multi-well simulation models against a long period of historical field data in MacKay River project area. The integration of these methodologies is presented in detail in this paper.
This integrated approach provides a basis for comparing relevant SAGD performance indicators, such as oil rate and SOR. The results generated from the integrated approach have served to increase confidence in the robustness of the associated business decisions.
Got Steam? Understanding ESP Steam Handling Capabilities in the Centrifugal Pump
Authors: Noonan S. G. , Baugh A. , Klaczek W. , Wonitoy K. , Wilson L. 
Published: June 2013

Abstract
The successful development and implementation of high temperature Electric Submersible Pump (ESP) technology for Steam Assisted Gravity Drainage (SAGD) applications has allowed operators to reduce their flowing bottom-hole pressures and achieve higher production rates. However, operating under these conditions brings the Pump Intake Pressure (PIP) closer to the saturation pressure of steam, which can result in live-steam production through the pump. The effect that live-steam has on pump performance is not particularly well understood, and has been a key challenge for operators when designing and optimizing ESP systems for SAGD applications.
In early 2011, ConocoPhillips, Baker Hughes and C-FER Technologies embarked on an experimental test program to determine the consequences of producing live-steam through a centrifugal pump. This new program was meant to build on multi-phase work that had begun over a decade ago at the University of Tulsa (TU), where researchers had focused on experimentally measuring the two-phase flow performance of ESP stages with air and at moderate temperatures [Pessoa and Prado 2001]. The TU work ultimately resulted in a wave of new technology aimed at increasing ESP gas handling capabilities. Following a similar testing and ESP instrumentation philosophy, this new collaboration looked to build upon the TU experiments and expand the test fluids to include live-steam, water, and air at higher temperatures.
This ultimately involved the design and construction of a unique high temperature Steam Flow Loop that allows for live-steam injection into a centrifugal pump, while monitoring both head and performance degradation. This paper will reveal some of the unique test results collected with the first pumping system, including snapshots of the stage-by-stage pressure contributions captured in real-time as air or air and steam migrates through the ESP being tested. These results also demonstrate the impact the presence of other gases can have on steam flashing and how it is important to consider both the gas and steam vapor effects in SAGD ESP designs.