bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Experimental Study of the Post-CHOPS Cyclic Solvent Injection Process
Authors: Du Zhongwei , Zeng Fanhua , Chan Christine 
Published: June 2013

Abstract
Cold heavy oil production with sand (CHOPS) has been applied successfully in many oil fields in Canada. However, only 5% - 15% of the original oil in place (OOIP) is recovered during cold production typically. Therefore, effective follow-up techniques are of great importance. Cyclic solvent injection (CSI), as a post-CHOPS process, has greater potential than continuous solvent injection to enhance heavy oil recovery. Continuous solvent injection results in early breakthrough due to the existence of wormholes; while in CSI process, the existence of wormholes can increase the contact area of solvent and heavy oil and the wormholes also provide channels that allow diluted oil to flow back to the wellbore.
In this study, the effects of wormhole and sandpack model properties on the performance of the CSI process are experimentally investigated using three different cylindrical sandpack models. The length and diameter of the base model are 30.48 cm and 3.81 cm, respectively. The other two models, one with a larger length (i.e. 60.96 cm) and the other with a larger diameter (i.e. 15.24 cm), are used for up-scaling study in the directions parallel and perpendicular to the wormhole, respectively. The porosity and permeability of these models are about 35% and 5.5 Darcy typically. A typical western Canadian oil sample with a viscosity of 4330 mPa · s at 15 °C is used. And pure propane is selected as the solvent. The experimental results suggest that (1) the existence of wormhole can significantly increase the oil production rate. The larger the wormhole coverage is, the better the CSI performance is; (2) a reservoir or well with wormholes developed at bottom is more favorable for Post-CHOPS CSI process; (3) the oil recovery factor is almost independent on the model diameter during the chamber rising phase; and the oil relative production rates in two different diameter models are close during the chamber spreading phase due to similar solvent dispersion rate; (4) the model length hardly affected the oil production rate comparing with the wormhole length; (5) the well with a horizontal wormhole is inclined to get a good CSI performance; (6) a relationship of oil production rate to drainage height is obtained and verified; (7) the mass transfer rate decreases verse time during the soaking period.
Kinetic Models for Low Temperature Oxidation Subranges based on Reaction Products
Authors: Khansari Zeinab , Kapadia Punitkumar , Mahinpey Nader , Gates Ian D. 
Published: June 2013

Abstract
In situ combustion (ISC) based enhanced heavy oil recovery is complex because there are numerous chemical reactions taking place simultaneously, in addition to mass transport and flow mechanisms, within the context where oil mobility is controlled largely by its temperature which in turn is controlled by heat transfer all occurring in a reservoir typically several hundred meters deep where geological heterogeneity is uncertain. From a reaction point of view, the complexity arises due to the immense number of components reacting through many different reaction paths in an underground system where the geology and heavy oil saturation vary spatially within the reservoir. It is known that there are four major classes of reactions taking place within an ISC process: low temperature oxidation (LTO), high temperature oxidation (HTO), thermal cracking (TC), and aquathermolysis. Within the reservoir, during ISC, LTO and TC reactions play a major role by providing fuel for HTO. In many documented reaction schemes in the literature, the LTO interval is considered as a single reactive zone spanning a single temperature range. In this work, a new reaction scheme is proposed based on analysis of thermogravimetric data where the LTO reaction temperature range has been separated into three temperature subranges each with their own dominant set of reaction products. The results demonstrate that models of LTO with a single range are inadequate for LTO modeling whereas multiple subranges were capable of representing the behavior of LTO effectively.
Closure Modeling Of Sub-grid-scale Effects For Well-drainage-scale Prediction Of CHOPS
Authors: VanderHeyden Brian , Ma Xia , Zhang Duan 
Published: June 2013

Abstract
A tractable, predictive modeling approach for Cold Heavy Oil Production with Sand (CHOPS) remains a significant practical challenge. In CHOPS, instabilities of oil-sand interactions lead to formation of meso-scale structures, such as wormholes or other defects. The sand stress concentration around these structures often leads to sand failure, and production of sand in the process. The failure and motion of sand alter the permeability, and hence affect the oil production. Because these structures result from the instability of the oil-sand interactions, sizes, shapes and locations of these structures are unpredictable. One can only describe them using the statistical methods. Furthermore, in typical well-drainage scale or multi-well-scale numerical simulations these mesoscale structures are typically below the level of resolution and must be modeled as sub-grid-scale effects. Rigorous well-drainage-scale averaged governing equations can be easily derived, but closure models for the sand stress and sand production cannot be adequately developed without proper description of the sub-grid effects.
The sub-grid momentum balance equation for sand demands that the divergence of the sand stress balances the gravity, pressure gradient and oil drag. Since gravity is a constant, and for a given mesoscale structure, the oil flow rate and hence the drag is determined by the imposed macroscopic pressure gradient, without information from sub-grid-scale pressure variation, we assert that the pressure gradient is the only independent variable affecting the stress and failure in sand. This leads to the proposition of closing the well-drainage-scale averaged governing equations in terms of the pressure gradient without explicitly involving the sand stress. Based on this proposition we derive a well-drainage-scale pressure diffusion equation without explicit representation of the sand stress.
To develop the closure models, we can extract information from both explicit full-physics simulations of the sub-grid-scale effects with resolved sand stress and from pilot scale production data. Full physics simulations using the multiphase material point method are shown to adequately model lab-scale wormhole experiments. History matched simulations at the well-drainage scale are shown to track transients in pilot data and are a measure of the success of the modeling approach.
Integrated Study of Foamy Oil Flow and Wormhole Structure in CHOPS through Transient Pressure Analysis
Authors: Xiao Lei , Zhao Gang 
Published: June 2013

Abstract
In this paper, a radial-composite CHOPS well model, integrating foamy oil flow and complex wormhole configurations, tends to investigate how wormholes and foamy oil can affect pressure responses of CHOPS wells simultaneously. Heavy oil starts containing dispersed gas and forming relatively continuous foamy oil when pressure drops below certain point. Such foamy oil with high compressibility and pressure-dependent properties makes the partial differential equations highly nonlinear and existence of wormholes makes them more difficult. Pseudo variables of pressure and time, introduced in this paper, aim at solving such nonlinear problems. Unsteady state problems of this model were solved semi-analytically using source and sink function methods. Generated type curves provide new transient pressure behaviours of mature CHOPS wells with wormholes and foamy oil flow. They show that effects of wormholes mainly dominate the early time flow period, while distinct fluid properties between foamy oil and original heavy oil zones start affecting late time flow period when pressure disturbance has reached the interface. Foamy oil compressibility can affect pressure responses significantly during late time flow period because it is very different from original heavy oil. With known foamy oil properties, this model provides new perspectives of transient pressure analysis of field pressure data to estimate wormhole coverages and drainage areas of foamy oil zones, which are very important in post-CHOPS development such as infill well drilling and EOR planning.
Stochastic Optimization of Hot Water Flooding Strategy in Thin Heavy Oil Reservoirs
Authors: Zhao David W. , Gates Ian D. 
Published: June 2013

Abstract
Stochastic optimization, based on a simulated annealing method, was done to determine the optimum hot water-flooding strategy for recovery of oil from thin (&lt;6 m) heavy oil reservoirs. The results reveal that high injection pressures are critical to a successful hot water flooding strategy. For water temperature during injection, the results show from a thermal efficienty point of view that that it is most efficient to adopt a temperature profile where the injection temperature starts high and ends at low water temperature. Multiple cycles of this profile might be beneficial depending on the reservoir conditions. The lower temperature injection at later stages of the recovery process partially recovers the heat stored in the reservoir matrix and therefore increases the overall heat utilization efficiency. A sensitivity analysis shows that the permeability distribution affects the performance of the hot water flooding process most significantly. The existence of a higher permeability zone in the lower part of the reservoir leads to earlier oil production and water breakthrough. The absolute permeability value has the largest effect on process performance. High permeability was found to lead to more oil and water production in the early stage of operation and achieved the best economic performance. The low permeability case was found to show a slow oil production. Although it has the lowest cumulative injected energy to oil produced ratio, poor oil production made the operation process uneconomic.
Keywords: thin heavy oil reservoirs, hot water-flooding, energy to oil ratio, stochastic optimization, simulated annealing
Understanding the Thermo-Hydro-Mechanical Pressurization in Two-Phase (Steam/Water) Flow and its Application in Low-Perm Caprock Formations in SAGD Projects
Authors: Ghannadi Sahar , Irani Mazda , Chalaturnyk Rick 
Published: June 2013

Abstract
Steam-assisted gravity drainage (SAGD) is one successful thermal recovery technique applied in the Albertan oil sand reservoirs. When considering in situ production from bitumen reservoirs, bitumen viscosity must be reduced to achieve the mobility required to flow toward the production well. Steam injection is currently the most promising thermal recovery method. While steam flooding techniques have proved to be commercially viable methods to extract bitumen from bitumen reservoirs, caprock integrity and the risk of losing steam containment can be a challenging operational problem. Since permeability is low in Albertan thermal project caprock formations the water trapped in pores undergo large pressure increases during heating. In addition, water undergoes a large volume increase as it flashes to steam and the resultant pore pressure causing profound effective stress reduction. Once this condition is established, pore pressure increases can lead to shear failure of the caprock, and to subsequent caprock integrity failure or casing failure. It is typically believed that low permeability caprocks impede the transmission of pore pressure from the reservoir, making them more resistant to shear failure (Collins, 2005, 2007). In cases of "thermo-hydro-mechanical pressurization", low permeability caprocks are not always more resistant. As the steam chamber rises into the caprock, the heated pore fluids may flash to steam. Consequently, there is a vapour region between the steam chamber interface penetrated into the caprock and water region within the caprock which is still at subcritical state.
This study develops the fluid mass and thermal energy conservation equations and presents analytical solution to evaluate the thermo-hydro-mechanical pressurization in low permeability caprocks and flow of steam and water after initiation of steam injection in SAGD process. Both short-term and long-term response are calculated. The evaluated thermal pressurization is compared for shallow and deep oil sand reservoirs, for similar transport properties. These results showed that the thermo-hydro-mechanical pressurization is larger in deep reservoirs; SAGD application can cause high pore-pressure and potential shear with the caprock resulting steam releases to surface and casing failures.
Surfactant-Steam Process: An Innovative Enhanced Heavy Oil Recovery Method for Thermal Applications
Authors: Zeidani K. , Gupta S. C. 
Published: June 2013

Abstract
Surfactant-steam process (SSP) is a novel and potentially cost-effective process that utilizes a small amount of surfactant co- injected with steam to enhance the oil recovery of steam assisted gravity drainage (SAGD) well pairs. The mechanism of this process involves interfacial tension (IFT) reduction, reservoir rock wettability alteration, oil relative permeability enhancement, and in-situ emulsification.
SSP is expected to result in oil rate acceleration, steam-to-oil ratio (SOR) reduction and enhanced ultimate oil recovery factor. Analogous enhancement is expected if the SSP is combined with other steam-based or steam-solvent processes. This paper provides an introduction to this concept and presents a unique protocol that has been developed for screening surfactants for co-injection with steam in SAGD process. In particular, the paper presents a scientific approach to surfactant selection for SSP applications, describes the conditions in which the surfactants needs to be deployed within the reservoir, and also predicts the potential synergies if use of different classes of surfactants is made. Novel experimental design on different aspects of surfactant-steam phase behavior indicates the optimum surfactant concentrations for field trial
applications. Lab testing of selected surfactants on typical Canadian oilsands sand packs shows an improved incremental oil recovery factor (RF) in the range of 6 to 16% (for different tested surfactants) compared to a SAGD base case.
SSP simulations were conducted for one of the surfactants that were tested in the lab. The simulation results indicate that this particular surfactant on average accelerated the oil rate by 15% in the first 30 months of SSP operation, increased the ultimate oil RF by 10%, and reduced the cumulative steam-to-oil ratio (CSOR) by almost 11% relative to a SAGD base case. In addition, a sensitivity analysis was conducted to investigate the effect of surfactant concentration co-injected with steam. The simulation results suggest that there is an optimum concentration for a given surfactant that needs to be explored through lab investigations and field trials.
It is evident that once the SSP is successfully developed, the use of surfactant promises to improve environmental performance and project economics of the in-situ oilsands recovery.
A Performance Comparison Study of Electromagnetic Heating and SAGD Process
Authors: Liu Manyang , Zhao Gang 
Published: June 2013

Abstract
Downhole electrical heating has proven as an attractive alternative of lowering the oil viscosity by raising the temperature in the formation. Because reservoirs with characteristics such as extremely low permeability, very thin pay-zone, and extra-heavy oil are generally not feasible for steam injection based Enhanced Oil Recovery (EOR) techniques, and the application of low- frequency Electrical Resistance Heating (ERH) has been demonstrated to limit the heating rate as well as the production rate. Hence, high frequency Electromagnetic Heating (EMH) has been chosen as a potential candidate to a reservoir for which other thermal recovery techniques are not suitable. This study presents both an oil single phase radial flow and oil-gas two-phase linear flow EMH model with COMSOL. Result shows that EM heating is practicable and cost effective under certain constraints in the real field. Parametric study indicates that the cumulative oil production achieved by EMH can be enhanced by a similar EOR approach called Single Well Steam Assisted Gravity Drainage (SW-SAGD) simulated in STARS for reservoirs with the above mentioned characteristics.
Specifics and Challenges of Heavy oil Production in Northen Siberia Illustration Based on Biggest Heavy Oil Project in Russia
Authors: Aksenov M. , Lachugin D. , Nukhaev M. , Rymarenko K. , Telkov V. , Gaidukov L. , Vologodskiy K. , Khramov D. 
Published: June 2013

Abstract
Russkoye heavy oil field is located in the northern part of Siberia. The field was discovered in 1968. It is characterized by the huge reserves: more than 1.3 billion tonn of oil in place and remote location (the field is located to the north from the polar circle). Main challenges for the field development are: unconsolidated formation, gas cap, high heterogeneity of formation, permafrost zone and heavy oil.
This paper covers latest experience (2007-2012) obtained during field development pilot project implementation at the representative part of the Russkoye field. Pilot stage results will be used for the further field development strategy building. Effectiveness of different approaches has to be estimated, considering specifics of the field. Traditional field instrumentation did not provided reliable data for the analysis. New technologies (such as fiber optic distributed temperature sensors, specifically adopted multiphase metering etc.) were implemented for the building of the proper data acquisition system. During the pilot stage specific injection schedules, cold and hot water injection, various well completion applications were implemented. Depletion rate estimation based on real production data, determination of critical drawdown and numerous well testing activities including conventional buildup/drawdown pressure transient analysis and interference testing were made. Special attention is paid to the comparison of the cold and hot water injection and to the methods of control/monitoring of the well production. Monitoring and effectiveness estimation of the tested technology should be based on flow rate measurements data (MPFM), distributed pressure and temperature sensors (DP/TS) in horizontal production wells. Numerous new technologies were used for the pilot project. Paper describes approaches for integrated data acquisition implementation; development techniques comparison and new technologies adaptation workflow to the specific field conditions. New technologies application allowed to see specific field behavior and to estimate effect of various field development and management approaches tested.
The results obtained during the pilot project will be used for the Russkoye field development planning, technical solutions will be implemented for the field monitoring and managing. Successful development of the first biggest heavy oil field should lead to initiation of development of other numerous challenging heavy oil fields in Russia.
Data-Driven Modeling Approach for Recovery Performance Prediction in SAGD Operations
Authors: Amirian Ehsan , Leung Juliana Y. , Zanon Stefan , Dzurman Peter 
Published: June 2013

Abstract
Quantitative ranking of different operating areas and assessment of uncertainty due to reservoir heterogeneities are crucial elements in optimization of production and development strategies in oil sands operations. Although detailed compositional simulators are available for recovery performance evaluation for SAGD, the simulation process is usually deterministic, cumbersome, expensive (manpower and time consuming), and not quite suitable for real-time decision making and forecasting.
In this paper, Artificial Neural Network (ANN) is employed as a data-driven modeling alternative to predict SAGD recovery performance in heterogeneous reservoirs, an important application that is lacking in existing literature. In this study, numerical flow simulations are performed to construct a training data set consists of various attributes describing characteristics associated with reservoir heterogeneities and relevant production/injection parameters with the corresponding recovery factor as output. The network is trained using the data set to identify all significant patterns and relationships that exist between these attributes and the output parameters. The model is then tested using a verification data set (cases that have not been used at the training stage). Sensitivity studies on network configurations are also investigated. In addition, new modifications are proposed to identify and reduce extrapolations in predictions, which are often considered as major drawbacks in most data-driven modeling approaches.
The approach described in this paper can be integrated directly into most existing reservoir management routines. In addition, the technique can be used as a viable tool for analyzing large amount of competitor data efficiently. Given that robust forecasting and optimization of heavy oil recovery processes is a major challenge faced by the industry, the proposed research has great potential to be applied in other recovery projects such as solvent-additive steam injection.
Experimental Measurement of CO2 Solubility in heavy Oil and Its Diffusion Coefficient calculation at both Static and Dynamic Conditions
Authors: Kavousi Ali , Torabi Farshid , Chan Christine 
Published: June 2013

Abstract
With population growth, increasing world energy demand and depletion of conventional oil resources, exploiting heavy and extra-heavy oil reservoirs seems one of the promising options in supplying world oil request. However, there are several barriers to the rapid growth of production from such reservoirs.
CO2-based enhanced oil recovery (CO2-EOR) techniques are among processes utilized to enhance heavy oil and bitumen production. The design and modeling of CO2-EOR require extensive knowledge about the solubility and diffusivity of CO2 in heavy oil. Hence the primary objective of this research was to identify the main mechanisms involved in the static and dynamic mass transfer of CO2 into the heavy oil systems.
This experimental study commenced by allowing CO2 to be in contact at static condition with two different types of heavy oil having viscosities of 5000 and 20000 cP at 298 K. Experiments were conducted at three different initial pressures (1.73, 3.10, 4.49 mPa) and pressure decay concept was used to determine the CO2 solubility for each individual case. The experiments then were extended using a Mini-bench top reactor (PARR-4560) from Parr Instrument Company to repeat similar tests in dynamic condition. Using the reactor's stirrer, the oil was agitated at the velocity of 30 rpm; thereby a semi-flowing condition was generated leading a convection effect in the oil bulk phase. For both dynamic and static conditions, the proper mathematical model were proposed and solved numerically to determine the diffusion coefficient value at each specific operating condition.
Results showed that the solubility of CO2 at initial pressure of 1.73 mPa for 5000cP oil is 0.04015, and 0.04195 g/100cc for static and dynamic conditions, respectively. The diffusion coefficient value at static and dynamic condition for the same experimental condition is 4.531×10-10 m/s2 and 4.852×10-10 m/s2. Experimental and mathematical interpretations of other cases showed similar behaviour. From the results at both conditions it can be obtained that the initial pressure has significant effect on reaching the stability condition and longer time is required for higher pressures. Moreover, diffusion coefficient is more sensitive to oil viscosity rather than ultimate solubility value.