Browsing by Author "Maini, B. B."
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- ItemOpen AccessAnalytical and numerical modeling of the Cyclic ES-SAGD process(2019-04-25) Manfre Jaimes, Diego; Clarke, Matthew A.; Gates, Ian Donald; Maini, B. B.The world is still highly dependable on the energy that comes from oil. The current demand for energy has given importance to oil reservoirs that were normally overlooked in the past due to its properties. One example is found in the Canadian heavy oil sands. The amount of oil that is accumulated in these reservoirs represents the third largest accumulation of oil in the world. In these reservoirs, thermal processes such as Steam Assisted Gravity Drainage (SAGD), are used extensively as a production method. In SAGD, the injection of the steam into the reservoir reduces the viscosity of the oil, which moves downward by the effect of gravity until it reaches a production well. This research presents an alternative way of using SAGD in an efficient and profitable manner. One of the possible variations of SAGD that has shown positive results is the co-injection of a solvent in the injected stream. The idea behind this is to improve the effect of the reduction in the oil viscosity by the diffusion of this solvent in the oil. The amount and type of solvent injected as well as the amount that is recovered are key parameters in the performance of this process, particularly because these solvents are generally more expensive than oil. This work studied the co-injection of the solvent with the steam periodically. This means that in this case the solvent is co-injected through cycles instead of continuously. Some of the aspects that were evaluated are the type of solvent, its concentration and the duration of each of the solvent injection cycles. This study includes the derivation of an analytical model that is able to estimate the oil rate than comes from a cyclic solvent co-injection SAGD process and the use of numerical reservoir simulation to determine the principal recovery mechanisms of the process. One of the principal conclusions is that a similar positive result of the solvent co-injection could be achieved with less amount of solvent usage. This would considerably benefit the profitability of the process and the general performance of SAGD.
- ItemOpen AccessAnalytical Modeling of Steam Injection and Steam-Solvent Co-Injection for Bitumen and Heavy Oil Recovery with Parallel Horizontal Wells(2019-04-30) Keshavarz, Mohsen; Chen, Zhangxin; Harding, Thomas Grant; Chen, Zhangxin; Harding, Thomas Grant; Gates, Ian Donald; Maini, B. B.; Lines, Larry R.; Das, Swapan K.Steam-assisted gravity drainage (SAGD) is recognized as one of the most promising techniques for the commercial in situ recovery of bitumen reserves. The process, however, is energy intensive and is economically challenged in thin and low-quality reservoirs. Years of small-scale testing have shown that adding small amounts of hydrocarbon solvents to steam can yield large gains in oil output and reduced emissions over the conventional SAGD (Rassenfoss, 2012). The process has been referred to with different names in industry and academia such as expanding solvent-SAGD (ES-SAGD), solvent aided/assisted-SAGD (SA-SAGD), SAGD+TM, solvent aided process (SAP) and so on. High costs of solvents compared to bitumen requires their optimized use. The numerical simulation complexities and run times can make the filed-scale optimization exercise extremely costly. Therefore, analytical models can play an important role for such a purpose and to increase the confidence in performance forecasting. This dissertation starts with a review of the primary analytical models available for SAGD and co-injection and discussion on their limitations. Then, a new universal modelling approach is proposed that is applicable to the both processes. The breakthrough in the modelling approach is the robust coupling of mass balance, energy balance and fluid flow in porous media. This approach solves the heat and mass transfer problems at the stationary base of the steam chamber where the drainage to the producer happens. Combining material balance and Darcy’s Law, it then estimates the bitumen production rate and chamber shape. Then, energy balance is incorporated to estimate the steam requirements. In addition, the new modeling approach closes the material balance on all the components which allows for the estimation of solvent requirements for a particular set of key performance indicators. The developed model is intended to be simple enough for practical applications. After validation against numerical simulation results, its application to history-matching, forward prediction, pre-screening and uncertainty analysis is demonstrated through a number of field case studies.
- ItemOpen AccessApplication of In-situ Upgrading in Naturally Fractured Reservoirs(2021-01-22) Duran Armas, Jose Luis; Pereira-Almao, Pedro R.; Maini, B. B.; Aguilera, Roberto F.; Chen, Zhangxin; Mehta, Sudarshan A. Raj; Oldenburg, Thomas B. P.; Dalaï, Ajaỳ KumarThe persisting low oil price and the need for more environmentally-friendly energy sources have driven the latest development of new technologies for the sector and, in particular, for heavy oil exploitation. Among those technologies, In-Situ Upgrading Technology (ISUT) offers downhole processing, leaving undesired products underground, enhanced oil recovery and reducing the upgrading cost. ISUT is a thermal recovery process that uses hot fluid to transport catalytic nanoparticles, creating a reactor around the wellbore. Supporting the pilot test of ISUT, planned for the Aguacate field at the central Gulf Coast region of Mexico, this thesis focus on reinforcing many technical aspects for that pilot test. A kinetic model was developed for the Aguacate heavy oil and its vacuum residue at reservoir conditions. Ten sets of temperature and residence time, similar to those used for mild hydrocracking processes but in the presence of a carbonate rock core. Moreover, five pseudo components were assigned to model the reaction inside the porous carbonate medium. These results were all utilized to create the kinetic model specific for this pilot test. The products' characterization showed moderate temperatures and longer residence times improve product quality, translating into preferred temperatures below 350 oC with longer residence times. The used set-up for the kinetic analysis replicated the reservoir environment, using a matrix and a fracture where the fluid could flow. This work confirmed the catalytic hydrogenation process in ISUT by measuring molecular markers' conversion into other organic products, indicating limits of catalyst concentration to avoid adverse effects that may result in excess paraffinic compounds, eventually risking their precipitation subsequent operating instabilities in the media. Lastly, the hydrogen consumption in the ISUT process was studied using ten experimental conditions to create a statistical model to predict the hydrogen consumed in the process. The model showed that hydrogen consumption is linear vs. temperature and reaction time.
- ItemOpen AccessApplication of Polymer and Nanomaterials for Improving Heavy Oil Recovery(2019-09-10) Aliabadian, Ehsan; Sundararaj, Uttandaraman; Chen, Zhangxin; Maini, B. B.; Dong, Mingzhe; Lines, Larry R.; Mohanty, Kishore K.Booming population growth and economic activity have contributed significantly to an increased demand for energy in the last few decades, specifically in Canada. A major source of energy is oil extracted from underground petroleum reservoirs. Utilizing current technology and equipment, only a small portion of oil can be produced and recovered. Steam-assisted gravity drainage (SAGD), used as a common technique to produce heavy oil in Canada (specifically in oil sands reservoirs), requires a lot of energy and negatively impacts the environment. Using environmentally friendly and cost-effective techniques instead of or combined with SAGD improves the extraction of oil from Canadian oil reservoirs. Reservoir pressure, which is a driving force for pushing oil toward production wells, reduces drastically in the early stages of oil production from underground resources. This leads to a significant decrease in oil production rate. To solve this problem, enhanced oil recovery (EOR) methods inject water, gas, or chemical solutions to maintain reservoir pressure. When water is injected (water flooding) into heavy oil reservoirs, it cannot push the viscous oil smoothly because of water’s lower viscosity as compared to oil. As a result, injected water tends to bypass the pores containing trapped oil and the flooding becomes inefficient. To overcome this problem, one method adds polymers to the injected water. The addition of polymers leads to a more uniform flooding by increasing the viscosity of the injected fluid. Unfortunately, this approach suffers seriously from degradation of polymers at high temperatures and precipitation of polymers due to interaction with ions like sodium and calcium in brine. To solve these problems, the addition of nanomaterials to a polymer solution is highly recommended. The main focus of this PhD dissertation is to evaluate the effect of surface chemistry and geometry of nanomaterial on creation of a network with large polymer molecules. In addition, to mimic the large deformations in converging and diverging pores in porous media, linear and nonlinear rheology were employed to characterize the mechanical and flow behaviors of these hybrid dispersions. Sandpacks were used as the porous media to simulate oil reservoirs. Different hybrid dispersions were injected into sandpacks and the yield of recovered oil was reported. Results of this work can pave the way for use of polymer/nanomaterial solutions for heavy oil recovery. This study also demonstrated that large deformation oscillatory shear tests can be employed to distinguish flow behavior of hybrid systems. It was also shown that interaction between polymer and nanomaterial affects network structure and, consequently, oil recovery. Furthermore, size of nanomaterial compared to pore size distribution of porous media is a significant parameter that should be considered. The outcomes of this study could be helpful in improving heavy oil recovery in thin oil formations such as the Cardium, Montney, and Ostracod formations. These formations are too thin to utilize processes like steam-assisted gravity drainage and solvent vapor extraction, making this technique significant for increasing oil recovery in Canadian heavy oil reservoirs.
- ItemOpen AccessCo-Injection of Non-Condensable Gas and Foam in SAGD using a Modified Well Configuration - A Simulation Study(2018-08-29) Zhang, Yushuo; Maini, B. B.; Sumon, Kazi Z.; Dong, Mingzhe; Sarma, Helmanta KumarThe objective of this research is to examine the feasibility of foam co-injection with steam in SAGD using modified well configurations using numerical simulation. The foam used in this project is a composition of water, non-condensable gas (NCG) and surfactant. The application of foam in this study is for achieving the gas mobility reduction and decreasing the residual oil saturation. The use of foam forms a more stable insulating layer below the top of formation, which results in lowered overburden heat loss and cSOR. To place the foam directly below the overburden rock, vertical steam injectors are implemented in this study. Simulation runs are created using CMG STARS (Thermal and Advanced Process Simulator) using Long Lake Pad 16 as the target location. These simulation results demonstrated substantial improvement in cSOR by co-injecting foam with steam using the vertical injectors. Non-flowing boundary condition was used in all simulations. The producer operational constraint is a combination of maximum live steam rate and minimum bottom hole pressure (BHP). The base case forecasts production from January 2017 to January 2027 in steam only SAGD operation. The base case showed approximately 75,000 m3 oil production in 10 years, with a cumulative Steam Oil Ratio (cSOR) of 6.19. The simulation results show that injecting the foam improved both cumulative oil production and cSOR. As expected, foam reduces the gas mobility and stabilizes the insulating blanket formed by high gas saturation at the top of the steam chamber. Injection of foam also increases the trapped gas saturation and reduces the residual oil saturation. The optimized simulation case with three vertical wells enabled the cSOR to be as low as 4.3 at 3,500 kPa operation pressure. However, the maximum allowed operating pressure at Long Lake is 2,600 kPa. The optimized case under lowered pressure of 2,500 kPa uses four injection-wells configuration, which gave cSOR of 4.25.
- ItemOpen AccessComparative Simulation Study and Economic Analysis of Thermal Recovery Processes in Athabasca Reservoirs(2018-04-30) Iyogun, Christopher Omokhowa; Chen, Zhangxing (John); Chen, Shengnan; Maini, B. B.Simulation studies of three thermal recovery processes used in Athabasca reservoirs have been carried out for a 10-year production period. The recovery processes studied are Steam-Assisted Gravity Drainage (SAGD), Fast-SAGD, and Expanding Solvent-SAGD (ES-SAGD). Normal pentane (n-C5) was the solvent of choice used in ES-SAGD simulations with its molar concentration varied from 2% to 5.9%. The main objective of this study is to conduct an economic analysis of the three recovery processes with the goal of determining the most economically viable process. The economic indicator that will be assessed to ascertain the most viable recovery process is their Net Present Value (NPV.) 2D simulation studies based on homogeneous Athabasca reservoirs have been performed. Results obtained show that of the three recovery processes, Fast-SAGD had the lowest cumulative oil produced, followed by SAGD and ES-SAGD, the highest. The cumulative oil produced also increased with increasing molar concentration of n-C5. Furthermore, it was shown that as expected, the CSOR of ES-SAGD was the lowest of them while that of Fast-SAGD was the highest. The CSOR of the ES-SAGD processes reduced as the concentration of the n-C5 increased. The economic analysis showed that of the three recovery processes, ES-SAGD is the most economically viable process. Furthermore, the effect of solvent on the viability of ES-SAGD over the other recovery processes is dependent on the price regime of pentane. In this analysis, two extreme price regimes were chosen and the result showed that for a low price regime, varying the molar ratios of n-C5 had a significant effect on the NPV up to a point before its effect diminishes. In fact, increasing the molar concentration of n-C5 from 2% to 3.76% significantly increased the NPV while further increasing it from 3.76% to 4% and thereafter to 5.9% had no noticeable effect. However, it seems that increasing it from 3.76% to 5.9% had a diminishing effect especially after the 3-year period. Nevertheless, the significant NPV improvement ES-SAGD has over SAGD and Fast-SAGD diminishes once the price regime of pentane is more than 3 times that of oil. In fact, this high price regime showed that 5.9% molar concentration of n-C5 is no longer more viable than the SAGD counterpart. There is still some benefit up till about 4% molar concentration of n-C5 but this benefit is greatly diminished. In conclusion, ES-SAGD has been shown to be the best recovery process for Athabasca reservoirs based on economics but further research is needed to evaluate the molar concentration that will provide the most economic benefit for a real Athabasca reservoir.
- ItemOpen AccessConcentration Dependent Diffusion of Solvent in Heavy Oil(2020-01-20) Carril Naranjo, José Eduardo; Kantzas, Apostolos K.; Aguilera, Roberto; Maini, B. B.In recent years, solvent-based methods have arisen as a feasible alternative to thermal schemes for heavy oil recovery, owed to the diffusive solvent mass transfer effect on oil mobility. The increasing incorporation of significant diffusion physics to models describing the process will lead to successful field implementations. In this work, a numerical model that captures the solvent diffusion coefficient dependence, on its concentration in solvent – bitumen / heavy oil systems, was developed and tested. The interFoam solver was enabled to account for two phases and a miscible component diffusing between them. Then, one-dimensional diffusion simulations were conducted to validate its results against analytical solutions. Once the two phases and miscible component diffusion features were validated, the solvent diffusivity concentration dependence feature was added to the numerical model. This attribute was later evaluated against experimental measurements of solvent concentration evolution in heavy oil and bitumen. To this end, results from two experimental works were considered as reference. This study demonstrates that the diffusivities observed in the solvent – heavy oil / bitumen systems analysed can be numerically handled by the model presented. Additionally, the solvent concentration dependence feature makes of the model an important tool to evaluate its effect on viscous oil and it can potentially be implemented in pore scale models.
- ItemOpen AccessData-Driven Analytics for Oil and Gas Reservoir Production Forecasting(2018-10) Amirian, Ehsan; Chen, Zhangxing (John); Fedutenko, Eugene; Maini, B. B.; Moore, Robert Gordon Gord; Lines, Laurence R.; Lu, Qingye; Bahadori, AlirezaDetailed uncertainty analysis on numerical flow simulation models preserving a robust and reliable model of oil and gas reservoir is often deterministic, cumbersome and expensive (manpower and time consuming). Presence of a high-dimensional data space consisting of a large number of operational and geological parameters impedes practical decision making and future performance prediction of oil and gas recovery processes. Thus, the rise of uncertainty-based reservoir development scenarios has provoked reservoir engineers to look for substitute modeling techniques that are capable of being re-evaluated numerous times to examine the impact of specific variables or probing a range of scenarios on production profiles. Static (well logs and core analyses) and dynamic (injection and production history) data sets existing within oil and gas companies are extremely valuable sources of information which can aid operators for a better future field development planning. Petroleum data-driven analytics workflow, which integrates a comprehensive petroleum data analysis and machine learning methods, suggest an attractive alternate for explicit models of the underlying process that can be instantaneously reassessed. The current study incorporates a systematic data analysis alongside with numerical flow simulations to create a comprehensive data set for different recovery processes such as SAGD, waterflooding, ploymerflooding, and etc. It also entails different characteristics labeling reservoir heterogeneities and key pertinent oil and gas recovery operational constraints. The collected big-data set will then be used to design data-driven models which can forecast production performance of different oil and gas recovery processes. This dissertation has developed and implemented algorithms for the development of novel data-driven models for CMG-CMOST AI 2017.10 version within Proxy Dashboard. This is the unique contribution of this thesis. The presented results and performance characteristics associated with data-driven models which can be re-evaluated much faster than explicit models of the underlying process highlight the great potential of this modeling approach to be integrated directly into most existing reservoir management routines. This research provides a viable tool to overcome challenges related to dynamic assessment of uncertainties during history matching of recovery processes and signifies the ability of data-driven analytics in future performance prediction of various oil and gas reservoirs.
- ItemOpen AccessDiffusion of Vaporized Solvents in Bitumen at High Temperatures(2020-04-27) Meng, Lin; Maini, B. B.; Dong, Mingzhe; Yarranton, Harvey W.; Hassanzadeh, Hassan; Leung, Juliana Y.; Nowicki, Edwin PeterThe diffusion coefficient of vaporized solvents in bitumen is an essential parameter in the design and performance evaluation of solvent-assisted thermal recovery methods. The reported measurements of solvent diffusion coefficient are relatively scarce, especially at the high temperatures. In this study, a new constant-pressure experimental technique for one-dimensional diffusion tests, which accounts for the bitumen swelling and density change, was developed. The experimental rig enables measurement of diffusion coefficient of vaporized solvents in bitumen at high temperatures encountered in solvent-assisted thermal recovery methods. The technique involves accurate monitoring of the swelling height during isothermal and isobaric dissolution of a vaporized solvent in a liquid column of the oil. Several analytical and numerical models have been reported as forward models for estimation of diffusion coefficient from experimental data based on various assumptions. However, an important physical mechanism, the swelling-induced advective transport has not been considered in the previous studies. In this study, an analytical model is developed to determine the molecular diffusion coefficient of gaseous solvents into the bitumen, including the swelling effect, density change and advective transport. The required experimental data for determining the diffusion coefficient with this analytical model are the swelling height (gas-liquid interface movement) with time, during the dissolution of a gaseous solvent at constant pressure and temperature in a liquid column. The diffusion coefficients of propane, butane, pentane, hexane and heptane, were measured at temperatures varying from 90 C to 195 C. A modified correlation of diffusion coefficient with bitumen viscosity and solvent-bitumen mixture viscosity was developed based on the experimental results from this study and reported data from other studies. The new correlation provides a simple and reliable estimation of the diffusion coefficient of vaporized solvents in heavy oils and bitumen.
- ItemOpen AccessDiffusivity, Solubility, and Swelling in Solvent-Heavy Oil Systems: Experimental and Modeling Study(2019-04-25) Fayazi, Amir; Kantzas, Apostolos K.; Dong, Mingzhe; Maini, B. B.; Lines, Larry R.; Gu, YonganSolvent-based processes have shown great potential for enhancing the heavy oil/bitumen recovery as an alternative to thermal recovery methods duo to upgrading the oil phase and their lower energy consumption. Mass transfer is the underlying mechanism in solvent-oil interactions. Therefore, determination of the involved parameters (diffusion coefficient, solubility, swelling, etc.) by reliable and practical techniques is essential in process design and recovery estimations. Molecular diffusion coefficient controls the rate of mass transfer between the solvent and oil phase. When using gaseous solvents, solubility determines the ultimate capacity of the liquid phase to dissolve gas and swelling is a measure of volume change due to gas dissolution. In this study, 1-D Magnetic Resonance Imaging (MRI) is used to evaluate the diffusivity of liquid and gaseous solvents (toluene, dimethyl ether, propane, ethane, and carbon dioxide) in heavy oil. Diffusion tests are conducted for the studied solvents under constant pressure and temperature inside a closed PVT cell. Spatial and temporal signal amplitudes are acquired during the diffusion tests and are converted to concentration profiles for estimation of concentration-dependent diffusion coefficients. This conversion is achieved by creating samples with known concentrations of solvent-heavy oil and measuring their response in the same environment and parameter settings. For gaseous solvents, a moving mesh technique which accounts for concentration dependency of both density and diffusion coefficient is used to model the solvent diffusion into oil and the subsequent swelling of the oil phase.
- ItemOpen AccessEffect of Solvent Co-Injection on Residual Oil Saturation in SAGD Steam Chamber(2019-09-11) Rengifo Barbosa, Fernando Javier; Maini, B. B.; Sarma, Helmanta Kumar; Chen, ShengnanSteam Assisted Gravity Drainage (SAGD) process has been applied over wide area of the Province of Alberta, boosting the Canadian oil reserves to the position of third highest in the world. A key performance indicator of SAGD thermal efficiency is the steam-oil-ratio (SOR) that is the volume of water converted to steam and injected into the formation for each unit volume of produced oil. Even though several cost-saving advances have been made in this technology, SAGD remains expensive in terms of both the oil production cost and the environmental cost associated with greenhouse gases (GHG) emissions. Several kinds of additives have been proposed for improving the thermal efficiency of the process and decreasing the SOR while increasing the cumulative oil recovery. Solvent addition in SAGD is one alternative that improves the performance by decreasing the oil viscosity by dilution and thereby by decreasing the required amount of heat per produced oil barrel. In solvent enhanced SAGD, a part of steam volume is replaced by hydrocarbon solvent, in order to take advantage of not just heat but also of dilution for viscosity reduction. At the same time, solvent injection reduces heat losses by reducing the operating temperature. The combination of reservoir characteristics and operational constraints influence the choice of solvent as well as its concentration and timing. No systematic study of residual oil saturation (Sor) in solvent enhanced SAGD has been reported in the literature. This project tested four solvents (Pentane -C5H12, Hexane -C6H14, Cracked Naphtha and Natural Gas Condensate) at different concentrations using linear sand-packs that simulated SAGD gravity drainage to quantify their impact on the recovery performance during the injection process and on the residual oil saturation. The addition of all tested solvents to steam increased the rate of oil drainage and reduced the residual oil saturation. Amongst the single component solvents, 15 vol% hexane gave the fasted recovery and lowest residual oil saturation. However, the multicomponent solvents performed even better. Addition of 15 vol% cracked naphtha gave the lowest residual saturation and fastest oil recovery. The performance of gas condensate was also impressive. At 5 vol% concentration it was able to outperform 10 vol% cracked naphtha and 15 vol% hexane in terms of the rate of oil recovery and residual oil saturation.
- ItemOpen AccessEffect of Temperature on Two-phase Oil/Water Relative Permeability under SAGD Conditions(2020-06-25) Esmaeili, Sajjad; Maini, B. B.; Sarma, Hemanta Kumar; Dong, Mingzhe; Kantzas, Apostolos; Wong, Ron; Srinivasan, Sanjay; Harding, Thomas GrantThe successful implementation of any thermal recovery process in heavy oil reservoirs for the enhanced oil recovery requires some indispensable information related to the multi-phase fluid flow characteristics under high-temperature and high-pressure conditions. The relative permeability is an essential element which is required to model the flow performance within porous media. The two- and three-phase relative permeability affect the fluid flow velocity as well as the pressure gradient profile and saturation profile within the oil reservoir during the water flooding or steam and gas flooding. In order to predict the flow performance in thermal recovery processes, in which the temperature changes with position and time, the change of two- and three-phase relative permeability with temperature should be considered. Although numerous researchers have previously studied the variation of relative permeability with temperature since mid-fifties, this issue is still unresolved and remains challenging. Moreover, many contradictory results associated with the temperature’s impact on relative permeability reported in the literature and the relative scarcity of available data points for heavy oil and bitumen systems under thermal recovery conditions make this issue very critical for a reliable analysis. The aim of this research was to comprehensively investigate the effect of temperature on two-phase oil/water relative permeability in different rock-fluid systems, especially for Athabasca bitumen. In this regard, a reliable rig was developed to include the necessary elements to measure the steady- and unsteady-state relative permeability of two-phase systems in unconsolidated sand more accurately. This study was carried out in four phases. As per our objectives, the empirical correlations for two-phase oil/water relative permeability curve characteristics as a function of temperature in different rock-fluid systems were proposed first based on data reported in the literature. In addition, a new data-driven model for two-phase oil/water relative permeability in heavy oil/sand systems was also developed based on the experimentally measured data points. In the second phase, the impact of temperature on two-phase oil/water relative permeabilites was assessed over a wide range of temperatures from 23o to 200 °C in a clean viscous oil/sand system using the unsteady-state approach. In the third phase, the clean viscous oil phase was replaced by an ultra-heavy viscous oil, Athabasca bitumen. In this system, the effect of temperaturet on the two-phase relative permeabilites was evaluated using several core flooding experiments within a temperature range of 70-220 °C under the SAGD pressure (i.e., 2760 kpa). Both steady-state and unsteady-state relative permeability measuring techniques were utilized. In the final phase of this research, a solvent-aided system was employed for the relative permeability measurement at high temperatures to assess the effect of temperature on relative permeability of a diluted Athabasca bitumen/water/sand system in the same temperature range that was used for the unaltered Athabasca bitumen/water systems. Moreover, interfacial tension (IFT) and contact angle measurements were carried out for all systems at different temperatures to evaluate any change in fluid-fluid and rock-fluid interactions with temperature. The history matching of displacement tests was conducted using a reservoir simulator developed in-house. The experimental results revealed that the relative permeability curves in a clean viscous oil/deionized water/sand were practically independent of temperature, even though the viscosity ratio dramatically reduced at higher temperatures. Furthermore, the reduction of IFT to less than one order of magnitude and a small variation in contact angle at higher temperatures were not enough to alter the relative permeability. In contrast to this clean system, the unsteady-state relative permeability to Athabasca bitumen and water was a strong function of the temperature. At higher temperatures, the endpoint relative permeability to water considerably increased as well as the true residual oil saturation decreased significantly. Moreover, the irreducible water saturation slightly increased and endpoint relative permeability to oil also revealed an increasing trend. The steady-state relative permeability curves demonstrated the same behavior as the unsteady-state relative permeability curves at higher temperatures. A reduction in IFT and contact angle (i.e., a shift towards increased water-wetness) were also observed for this system with increasing temperature. The results obtained from several isothermal core flooding experiments using diluted bitumen at different temperatures confirmed that the two-phase relative permeability curves were still temperature-sensitive; however, the effect of temperature on relative permeability was less pronounced in diluted bitumen systems containing 9 wt. % of n-hexane, in comparison with unaltered bitumen systems. Again, a reduction in IFT and contact angle of a smaller level compared to the unaltered bitumen was captured at increased temperatures in this study. Since commercial reservoir simulators often consider the relative permeability curves to be insensitive to temperature, we anticipate that the temperature-dependent relative permeability model developed in this research can assist reservoir simulators to more effectively predict the flow performance in TEOR processes, especially for Canadian bitumen in the future.
- ItemOpen AccessEmulsion Based Oil Sands Reservoir Conformance Control(2020-04-07) Ding, Boxin; Dong, Mingzhe; Kantzas, Apostolos K.; Maini, B. B.; Cheng, Y. Frank; Wei, MingzhenIn many currently operated Steam-Assisted Gravity Drainage (SAGD) projects, heterogeneity in either water saturation or permeability has been encountered. Such heterogeneities have been recognized to have detrimental effects on the propagation of steam, thereby resulting in increased water loss, difficult pressure control, and high steam oil ratio. It is expected that the use of an emulsion-assisted geomechanical dilation process would provide a potential approach to achieve conformance control in heterogeneous oil sands and promote a fast and uniform steam distribution within the formation, thereby enhancing SAGD performance and boosting the bitumen recovery. Before such is available, the emulsification, characteristics and flow features of O/W emulsion should be determined. In this thesis, emulsion-based conformance control treatment is proposed and investigated through carefully designed laboratory experiments, mathematical modeling and numerical simulation. Experimental study comprehensively consists of optimum emulsion system generation, physicochemical properties determination and dynamics of emulsion flow in porous media from single sandpack (1-D flow), parallel-sandpack (1.5-D flow) to heterogeneous two-dimensional sandpack (2-D flow). Different factors, including emulsion characteristics (emulsion quality, oil-water interfacial tension (IFT), droplet size and oil viscosity), injection conditions (injection rate, injection pressure, emulsion slug size and temperature) and sandpack permeability, were experimentally evaluated their effects on emulsion flow behavior in porous media. On the basis of the comprehensive analysis on experimental findings, mathematical models have been proposed, developed, and successfully employed to capture the experimentally monitored emulsion flow features, by fully incorporating with the emulsion characteristics, injection conditions and sandpack permeability. The proposed emulsion flow model is compatible with a standard reservoir simulator, providing a potentially efficient and useful method to predict emulsion flow adequately at the field-scale for designing and controlling the reservoir conformance. A design procedure to obtain an optimal emulsion system for an appropriate conformance control is proposed for the corresponding heterogeneity of oil sands reservoir. To conclude, emulsion-based conformance control treatment is a promising candidate to solve conformance problems in heterogeneous oil sands and thus to improve SAGD start-up performance.
- ItemOpen AccessExperimental Analysis of Displacement Characteristics and Production Potential for Marginal Resources in Highly Developed Reservoirs(2020-11-17) Liu, Chang; Chen, Zhangxin; Maini, B. B.; Pereira-Almao, Pedro R.Waterflooding has become a common method for improving oil recovery in conventional oil reservoirs all over the world. Indeed, because most of the earlier exploited oilfields with large reserves have entered a development stage where high water cuts are present, new replacement resources are crucial so that conventional oilfield development will continue to meet increasing worldwide energy demands. The term – a marginal resource refers to those layers that have resource identification but cannot meet the criteria to be considered true reserves under the U.S Securities and Exchange Commission (SEC) standards. In this research, the properties and displacement characteristic are experimentally investigated and huge amounts of data, which was provided by CNPC, is analyzed to show the feasibility of economic production of marginal resources. First, a property data collection was analyzed, which can be used to have basic understanding of marginal resources. 104 cores are selected to finish six experiments to get more understanding about the uniqueness of properties. CT test results provided by CNPC are also analyzed to realize a correlation between clay mineral content and production efficiency. Finally, the feasibility of production is shown by a previous development test result. The test and analysis results show that compared to reserves layers, a marginal resource has abundant clay mineral, whose average is 5.5%, which results in a more water-wet rock and more formation damage during a displacement process. On the other hand, its producible oil amount is less than those from conventional sand reservoirs layers. A combined development plan passing a CNPC economy audit shows that the marginal resource can be economically produced.
- ItemOpen AccessExperimental and Numerical Modelling of Hybrid Steam In-Situ Upgrading Process for Immobile Oil(2020-09-08) Wills Lopez, Violeta Carolina; Pereira-Almao, Pedro R.; Chen, Zhangxin; Maini, B. B.; Mehta, Sudarshan A. Raj; Salahub, Dennis R.; Ovalles, CésarThe Canadian oil sands constitute the third largest accumulation of oil in the world. Various in situ recovery technologies are applied to extract the bitumen, most of them rely on steam injection which requires a large amount of energy while releasing a considerable amount of carbon dioxide. Because the bitumen produced from the Oil Sands is not pipeline transportable at surface conditions, it is necessary to improve its characteristics by lowering the viscosity and increasing the API gravity. An integrated concept for recovering and upgrading is presented by the In-Situ Upgrading Technology (ISUT), which partially replaces the injection of steam with a hot catalytic mixture that includes the heaviest fraction of the bitumen and hydrogen. ISUT is an alternative option for enhancing the recovery and upgrading the oil in the reservoir to produce a synthetic crude oil that meets the pipeline requirements reducing costs, environmental emissions, while eliminating diluent. In this work, a version of ISUT, which involves steam and hot nano-fluid injection, was evaluated by performing experiments in a vacuum insulated core-holder with a well arrangement similar to SAGD using the typical Athabasca reservoir properties and operating conditions of 450psig, 350⁰C and 8 hours of reaction-residence time. In-situ upgrading was assessed by performing comprehensive analyses such as viscosity, API gravity, simulated distillation, micro carbon residue, sulphur, and stability (P-value) of the products plus detailed characterization of the porous media after running the experiments. The main results indicated that the injection of the hot catalytic mixture enhanced the bitumen recovery and upgrading of the Athabasca vacuum residue. The occurrence of hydrogenation reactions allowed the production of upgraded products while coke formation was avoided.
- ItemOpen AccessAn Experimental Approach to Investigating Permeability Reduction Caused by Solvent Induced Asphaltenes Deposition in Porous Media(2020-01-27) Kordestany, Amin; Abedi, Jalal; Maini, B. B.; Moore, Robert Gordon Gord; Sarma, Helmanta KumarUtilizing hydrocarbon solvents such as propane, butane, pentane, hexane, and heptane has shown to be a promising method for reducing the amount of energy required for exploiting the underground heavy oil reservoirs. However, there is an unintended consequence of using the aforementioned solvents in heavy oil recovery processes. The interaction between oil and the aforementioned solvents results in the precipitation of a solid material called asphaltenes. Asphaltenes are the most common solid material dissolved in oil. It belongs to a solubility class that is soluble in light aromatics such as benzene and toluene but insoluble in lighter paraffins. Precipitated asphaltenes can deposit inside porous media and restrict the flow of oil. Reservoir engineers rely on reservoir simulation software to calculate the permeability reduction that results from solvent induced asphaltenes deposition in underground heavy oil reservoirs. Two questions must be answered in order to calculate the permeability reduction. First, how much asphaltenes is deposited in each section of the porous media and second, how much is the reduction in permeability associated with the asphaltenes deposition. This research strives to answer these questions by conducting laboratory experiments and computer simulation. Most of the published literature considers the asphaltene-related permeability reduction to be similar to formation damage by fine particles invasion. This approach does not capture the physics of asphaltene deposition during solvent flooding, since during solvent injection the asphaltene particles form and deposit inside the porous medium whereas during the fine particle invasion process, solid particles have already formed outside porous medium before injection. In this study, the deposition of asphaltene in porous media has been investigated in a way that allows the asphaltene particles to form and deposit within the porous medium. More importantly, a procedure has been developed that allows one to simultaneously measure the changes in asphaltene deposition and the resulting reduction in permeability along the flow path. This had not been accomplished before. Although the reversibility of asphaltenes deposition has been experimentally investigated by a number of researchers, the procedure developed in this work is unique in the sense that, for the first time, reversibility of asphaltenes deposition has been investigated during flow through realistic porous media. Reversibility of asphaltenes deposition was evaluated and it was found that maltene can totally re-dissolve asphaltenes if temperature is above 80°C. Due to the lack of experimental data in the literature, the numerical simulation studies have assumed an ad hoc value for the deposition rate of asphaltenes during a solvent injection process. In this work, values for the deposition rate of asphaltenes has been obtained by history matching the experimental data with a numerical simulator.
- ItemOpen AccessExperimental Evaluation of Surfactant Assisted SAGD Process(2019-11) Xie, Yun; Maini, B. B.; Dong, Mingzhe; Chen, Shengnan; Hejazi, HosseinUsing a surfactant as a steam additive for improving SAGD performance has been an intriguing idea for several decades. Some positive laboratory and field results on the Surfactant SAGD (S-SAGD) have been mentioned, yet very limited information has been revealed in the public domain literature. The primary mechanism responsible for improving the performance in S-SAGD also remains unclear. In this study, experiments under SAGD operating conditions were used to evaluate the adaptability of selected surfactants for S-SAGD. Oil recovery improvement was investigated using a one-dimensional sand-pack apparatus at SAGD conditions. Experimental results show that the majority of tested surfactants can achieve a higher initial recovery rate, but only three out of seven tested surfactants increased the final oil recovery factor. The surfactants reduce the interfacial tension (IFT) between the aqueous and oil phase at the steam temperature of 200°C. However, the impact of reduced IFT on recovery is limited, since ultralow IFT (0.001 mN/m) was not achieved. The improvement in oil recovery appears to be related to changes in wettability and relative permeability. The successful surfactants appear to increase the oil relative permeability and reduce the residual oil saturation. In view of considerably higher initial oil production rate and a 10.8% increase in the final recovery factor, the thermally stable Novel 6-2 is recommended for further evaluations as an additive for S-SAGD.
- ItemOpen AccessExperimental Study of Effect of Initial Mobile Water Saturation on Solvent Mixing with Bitumen in ES-SAGD(2018-08-31) Chang, Jinghuai; Dong, Mingzhe; Maini, B. B.; Hassanzadeh, Hassan; Shor, Roman J.Steam-assisted gravity drainage (SAGD) is a commercially successful enhanced oil recovery technology. However, the process is energy intensive. One way to reduce the energy cost is through adding solvent in the vapor phase. In solvent-based processes, like Expand-solvent steam assisted gravity drainage (ES-SAGD), the mixing of a solvent and bitumen at the chamber edge warrantsinvestigation. Given that initial water is often mobile in the reservoir, it is important to examine its effect on solvent transportation and mixing with bitumen. The study aims to evaluate the effect that different initial mobile water saturations have in solvent-bitumen mixing. Varying mobile water saturations were generated in linear sand-packs to experimentally examine how mobile water affects the propagation of solvent in the bitumen zone. Solvent was injected into sand-packs containing a small mobile water saturation at slow rates. The pressure drop was recorded; the produced fluid was collected and analyzed. Experimental and simulation results show that the solvent fingers through the bitumen zone by displacing part of the mobile water saturation and appears at the production end very quickly. The bitumen content in the produced fluid sample was found to be small, decreasing during the progress of the flooding. This suggests that the solvent fingers became thicker by leaching out the bitumen. Such a rapid penetration of solvent in the bitumen zone, as a result of displacing mobile water, can greatly enhance solvent-bitumen mixing. Therefore, mixing solvent with bitumen in solvent-based processes needs to be modeled as a two-dimensional convection-diffusion process, instead of the diffusion/dispersion model that has been frequently reported in literature.
- ItemOpen AccessExperimental Study of Heavy Oil Recovery Mechanisms during Cyclic Solvent Injection Processes(2019-03-22) Plata Sanchez, Maria Alejandra; Kantzas, Apostolos K.; Bryan, Jonathan Luke; Maini, B. B.; Aguilera, Roberto F.In recent years, the Cyclic Solvent Injection (CSI) process has shown to be a promising method for enhanced heavy oil recovery in Canada. CSI laboratory studies work for only 2 to 3 cycles due to low incremental oil in subsequent cycles whereas field pilots continue for years over multiple cycles This experimental study is intended to capture the production mechanisms responsible for heavy oil production in CSI. Primary production and CSI tests were conducted using physical sandpack models saturated with live heavy oil of 9,530 mPa.s viscosity. The experiments were conducted in horizontal and vertical mode injection at high- and low-pressure depletion rates using two solvent mixtures of CH4 and C3H8. The sandpack was Computed Tomography scanned after every cycle to analyze the evolution of gas and oil saturations. Three cores were used to study the effect of gravity forces, depletion rate, solvent composition, and initial oil saturation (dead/live oil systems) on the performance of CSI processes. CSI after primary in horizontal systems produced negligible incremental oil for both slow and fast drawdown rates due to the large void space and high free gas saturation inhibiting the pressure build up to push the solvent-diluted oil. These CSI experiments were only successful in dead oil systems, where the initial oil saturation was high and pressure gradient was generated through fast depletion rates until conditions of high void space and gas channels were reached. When the sandpack was flipped vertically, CSI cycles exhibited higher incremental oil recovery per cycle. Slow depletion cycles were more efficient in terms of pressure and incremental recovery per cycle, however, faster depletion cycles performed better as a function of time. The higher C3H8 content solvent mixture exhibited better performance in comparison to the lower C3H8 content as higher volume of diluted oil was drained out of the core. These results demonstrate the importance of gravity drainage in the CSI process and its significance on successful oil recovery rates. This study illustrates the limitations of previous horizontal laboratory tests and shows an improved test configuration for modelling and prediction of the improved response observed in CSI pilots
- ItemOpen AccessThe Impact of Surface Modified Nanoparticles on the Performance of Polymer Solutions for Heavy Oil Recovery(2019-08-13) Corredor Rojas, Laura Milena; Maini, B. B.; Husein, Maen M.; Sarma, Helmanta Kumar; Jalel, AzaiezThe use of polymer flooding as an enhanced oil recovery (EOR) method to achieve a more uniform volumetric sweep of the reservoir has increased over the past ten years. However, chemical, thermal and mechanical degradation of the polymers reduce their viscosity, which affects their performance. Nanoparticles (NPs) have been proposed as additives to make polymer flooding economical in challenging reservoirs or harsh conditions. NPs in polymer solutions (nanopolymer sols) are, nevertheless, an emerging class of materials. A more structured approach is needed to properly understand the physical and chemical interactions between the NPs and the polymer solutions. In the first stage of this study, nanopolymer sols were prepared by adding silicon oxide (SiO2), aluminium oxide (Al2O3), and titanium oxide (TiO2) NPs, and in-situ prepared iron hydroxide (Fe(OH)3) NPs to polymer solutions of partially hydrolyzed polyacrylamide (HPAM) and xanthan gum (XG). In the second stage, the surface of the NPs were modified by chemical grafting with carboxylic acids, silanes, and polyacrylamide. The modified NPs were characterized using transmission electron microscopy (TEM), Fourier-transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), and energy-dispersive X-ray spectroscopy (EDX). All prepared nanopolymer sols were evaluated to determine their effectiveness in improving heavy oil recovery by studying their rheological properties at different shear rates and NP concentrations, colloidal stability, interfacial tension (IFT), and contact angle. Finally, a selected set of nanopolymer sols were evaluated by conducting oil recovery tests in a Hele-Shaw cell and linear sand-packs. According to the observations in Hele-Shaw cell, the fingering patterns of XG and XG/1.0-2.0wt% of NPs were characterized by the formation of branched structures (at earlier growth stage) which by merging and coalescing formed stable interfaces. However, HPAM and HPAM/1.0-2.0wt% of NPs exhibited different fingering patterns with tip-splitting or suppressed tip-splitting and side-branching. Only XG polymer solutions, modified with 1.0 and 2.0 wt.% of unmodified NPs improved areal sweep efficiency between 5 - 7%. For the displacements in the linear sand-pack, the NP concentration was reduced from 1.0 wt.% to 0.2 wt.% to improve the transport of the NPs into the porous media. The incorporation of 0.2 wt.% of unmodified and modified SiO2 NPs increased the viscosity of the XG solution at all salinities, whereas the high XG adsorption onto the surface of the Fe(OH)3, Al2O3, and TiO2 NPs reduced the viscosity. Adsorption of the NPs, SDS molecules, NP-SDS complexes and NP-polymer-SDS complexes onto the oil-nanofluid interface reduced the IFT of the XG solutions. Also, the NPs changed the wettability of the glass from oil-wet to intermediate-wet. The NPs increased the cumulative oil recovery of the salt-free XG solution between 3 and 9%. At 1.0 wt% NaCl, the NPs reduced oil recovery by XG solution between 5-12%, except for Fe(OH)3 and TiO2 NPs. These NPs increased the oil recovery between 2-3% by virtue of reduced polymer adsorption caused by the alkalinity of these nanopolymer sols. Additionally, the surface properties of SiO2, TiO2 and Al2O3 NPs were improved by polymer grafting. The HPAM nanopolymer sols exhibited lower IFT and ability to alter the wettability of the glass substrate from oil-wet to intermediate-wet. The thickening behavior of the HPAM solution was improved by the addition of 0.2 and 0.4 wt % TiO2-PAM NPs at all salinities. The displacement experiments demonstrated that the addition of TiO2-PAM NPs increased the cumulative oil recovery by 2% while the addition of SiO2-PAM and Al2O3-PAM NPs reduced it between 3 and 7% at 1.0 wt.% NaCl. At higher concentration, TiO2-PAM NPs can enhance oil recovery between 5 and 7%, independent of the salinity. It was also observed that the surface modified SiO2 NPs with silanes and carboxylic acids cannot improve the performance of the HPAM solutions. To conclude, the HPAM/TiO2-PAM, the XG/Fe(OH)3 and XG/TiO2 nanopolymer sols exhibited the best performance in displacing viscous oil in the linear sand-pack tests. The original contributions to knowledge from this research are 1) development of new polymer nanohybrids which enhanced heavy oil recovery, 2) formulation of new synthesis routes for polymer nanohybrids which improved the dispersivity of the NPs into the polymer solutions and the resistance of the polymer solutions to salinity and temperature, and 3) better understanding of the mechanisms contributing to the success of nanohybrids in chemical flooding.