• Energy Research

Abstract In the Expanding-Solvent Steam-Assisted Gravity Drainage (ES-SAGD) process, the mass transfer of the dissolved solvent in the steam chamber boundary is critical to the oil production performance. In this study, experimental and numerical simulation approaches are used to investigate the gravity-driven convective movement of solvent in the steam chamber boundary in ES-SAGD. The experiments are conducted in a two-dimensional (2-D) sandpack model, in which a sloping gas-liquid interface in a closed system is developed as an analog of the steam chamber boundary in ES-SAGD. Thus, the flow along the sloping gas-liquid interface is used to represent the flow in the steam chamber boundary in ES-SAGD. Solvent mass transfer is observed by its concentration variation in the direction perpendicular to the flow surface. Later, CMG STARS is used as the simulator to execute the numerical simulations, and the simulation successfully captured the experimental results. In this study, the findings demonstrate the existence of convective solvent movement along the sloping gas-liquid interface. Furthermore, the results show that there is accelerated solvent movement along the interface under high permeability, and slow movement along the interface under high flow rate and high fluid viscosity. Diffusion and dispersion are tested by varying the corresponding coefficients in the physical and numerical models, and results show that these phenomena have negligible effect on the transverse solvent mass transfer process. This study found that gravity-driven convection is the dominant mechanism of solvent mass transfer in the steam chamber boundary in ES-SAGD.

Abstract Several empirical models have been proposed by scholars to capture the temperature’s impact on relative permeability for a specific rock/fluid system, often using very limited dataset of measured relative permeability values, which makes these models inapplicable to a wider range of rock-fluid characteristics. The current study presents a new data-driven model to predict the two-phase oil/water relative permeability over a wide range of temperature in unconsolidated sand and sandstone formations. We found that the carbonate rock systems have different characteristics and the reported high temperature relative permeability data for them is limited, which prevented us from including them alongside the sand systems. For developing the model, the Least Square Support Vector Machine (LSSVM) in the form of a supervised learning approach was implemented, in which the coupled simulated annealing optimization technique was employed for calculation of LSSVM hyper-parameters. To gather a comprehensive dataset for constructing the model, 626 experimental oil relative permeability and 547 experimental water relative permeability data points were obtained from the open literature. To identify the doubtful data points (the outliers) the method of Leverage Value Statistics was applied. The temperature (ranging from 21 to 200 °C), water saturation, oil viscosity (ranging from 0.42 to 1190 cP), water viscosity (ranging from 0.136 to 1.1 cP), and the absolute permeability (ranging from 152 to 95,000 mD) were used as the independent variables in the model. The statistical analysis of the obtained LSSVM for prediction of relative permeability demonstrated that the coefficient of determination, root mean square error, and average absolute error were 0.9987, 0.0111, and 5.36% for oil relative permeability and 0.9991, 0.0056, and 8.40% for water relative permeability. The comparison of statistical parameters of this model with other reported relative permeability models showed that this model is more reliable for estimating the oil and water relative permeability including its dependence on temperature and therefore it can be used for reservoir simulation studies, when experimentally measured data are not available.

Abstract In this study, a new correlation for determination of effective diffusion/dispersion coefficients in the vapor extraction of heavy oil/bitumen (VAPEX) is introduced. This model takes into account the solvent concentration as well as the drainage height and permeability dependency of these coefficients. The concentration dependency in this model stems from the mixture viscosity changes, while the height dependency appears directly in the correlation. The correlation was obtained using the experimental results of the VAPEX experiments that were conducted with physical models of varying sizes and different permeability sand-packs. Estimation of a proper mass transfer coefficient has been a challenging issue for the analytical and numerical simulation of the VAPEX and other similar processes. Incorporating the effect of drainage height on dispersion with a concentration-dependent diffusivity model enables one to estimate the dispersion coefficient values involved in this process.

Steam-assisted gravity drainage (SAGD) is a thermal in situ recovery method for heavy oil and oil sands that has been employed to exploit the vast petroleum deposits in the Athabasca region of northern Alberta that are not amenable to surface mining. Nevertheless, in spite of its success in recovering highly viscous bitumen, SAGD remains a costly technology that requires large energy input in the form of steam for each barrel of produced oil. This requires large quantities of water and natural gas, resulting in sizable greenhouse gas (GHG) emissions and extensive postproduction water treatment. There are ongoing efforts to make SAGD more energy-efficient and environmentally sustainable by reducing steam consumption while maintaining favorable oil production rates and ultimate oil recovery. Such efforts include the coinjection of steam and solvent in a process called expanding solvent SAGD (ES-SAGD) wherein bitumen that is essentially immobile at initial reservoir conditions is made mobile by heating and m...

Abstract The heavy oil or bitumen trapped in subterranean formations in Canada and North America can be effectively produced and recovered using thermal enhanced oil recovery (TEOR) techniques, especially steam assisted gravity drainage (SAGD) processes. Heating the formation to a high temperature greatly reduces the oil viscosity, which increases the oil mobility in the reservoir. In the SAGD process, the steam injected through a long horizontal well creates a steam saturated zone, called steam chamber, around the well that gradually expands laterally and vertically within the reservoir. The edge of the growing steam chamber is where the oil is displaced by the steam. There is a large temperature gradient in the oil drainage zone with steam temperature at the edge of the steam chamber and close to the original reservoir temperature on the other side of the drainage zone. The fluid flow behavior, which is controlled by relative permeability, can be sensitive to the temperature in this transition zone. The objective of this study was to investigate the impact of temperature on two-phase bitumen/water relative permeability of sand over a wide range of temperature from 70 to 220 °C. In the present study, isothermal displacement experiments were conducted with an advanced experimental rig under the confining pressure of 1400 psi using Athabasca bitumen, deionized water, and clean silica sand at six different temperatures. All experiments were repeated to ensure that the results are repeatable and reliable. The JBN (Johnson, Bossler and Neumann) method was used to obtain the two-phase relative permeability. The effect of temperature on relative permeability for the bitumen system was found to be substantial and should be accounted for in simulation of SAGD processes. The endpoint water relative permeability can increase by two orders of magnitude in going from the reservoir temperature to the steam temperature. The endpoint oil relative permeability also increases, albeit more modestly and the residual oil saturation decreases. Besides the relative permeability tests, contact angle and IFT measurements at high-temperature, high-pressure conditions were conducted to evaluate the fluid-fluid and rock-fluid interactions and examine any changes in wettability. According to the contact angle results, the wettability of system was water-wet and shifted toward strongly water-wet at higher temperatures. In addition, the IFT displayed a decreasing trend with temperature and reached the minimum value of 18 mN/m in the temperature range of 125–155 °C.

Abstract In situ oil sands are dense uncemented fine-grained sands that contain substantial amount of methane and carbon dioxide gases in pore water and heavy oil. Gas evolves when the pore pressure drops to the bubble point pressure (liquid–gas saturation pressure) due to a decrease in confining pressure or fluid production. The volume and pore pressure changes in live oil-filled sand specimens due to decrease in confining pressure under undrained condition were examined in laboratory. A mechanistic model based on kinetics of gas bubble growth due to solute diffusion in supersaturated oil liquid was formulated and presented to interpret the observed time-dependent non-thermodynamic equilibrium behaviour of pore pressure and volume changes. It was found that the bubble sizes could be estimated indirectly by matching the pore pressure response of the live-oil filled system.

Abstract The diffusion coefficient of gaseous solvents in bitumen is an essential parameter in the design and evaluation of performance of solvent-assisted thermal recovery methods. Several analytical and numerical models have been developed as forward models for estimation of diffusion coefficient from experimental data based on various assumptions. However, many critical physical mechanisms such as swelling of the bitumen by solvent dissolution, the swelling-induced advective transport, and the mixture density change by solvent diffusion into the bitumen have not been considered in the previous studies. A simple analytical solution accounting for these mechanisms is lacking and the numerical solution with these mechanisms are computationally-intensive and prone to numerical dispersion. In this study, a novel analytical model is developed to determine the molecular diffusion coefficient of gaseous solvents into the bitumen, including all of the above-mentioned physical processes. The required experimental data for this analytical model are the swelling height (gas-liquid interface movement) with time, during the dissolution of a gaseous solvent at constant pressure in a liquid column. The diffusion coefficients predicted by the present model are compared with values reported in previous studies with different solvents and oil samples. The developed model is able to provide a simple and accurate estimation of the diffusion coefficient from the swelling data with the least number of assumptions. This study provides an improved methodology for estimating the diffusion coefficient of soluble gases in bitumen in systems that exhibit appreciable oil swelling and oil density change.

The SAGD process is among the most applicable thermal EOR methods (TEOR) in North American heavy oil reservoirs. In addition to improving the oil mobility through viscosity reduction, the high-temp...

Abstract For more than half a century, a large number of scholars have endeavored to delineate the effects of temperature on two-phase relative permeability curves using different oils and porous media. However, we still cannot predict how the relative permeability will change with temperature in a specific rock-fluid system. In fact, even a cursory review of the literature on the effect of temperature on oil/water relative permeability will show that a bewildering array of conflicting results have been reported. These inconsistent results are partly due to the likelihood that the effect of temperature is different in different rock-fluid systems and partly due to differences in the measurements techniques that can introduce varying experimental artifacts. The main objective of this study was to see whether some of the contradictions in the reported results would be resolved by examining the effects of temperature on relative permeability separately in different classes of rock-fluid systems. Another objective was to develop empirical correlations for estimating the value of oil/water relative permeability in different systems at higher temperatures. Reported results from a large number of experimental studies of the effect of temperature on relative permeability were collected to generate a large dataset of oil/water relative permeability curves. This dataset was partitioned into four parts representing four different classes of rock-fluid systems, namely: 1) light oil in unconsolidated sand, 2) heavy oil in unconsolidated sand, 3) light oil in consolidated sandstone and 4) heavy oil in consolidated sandstone. The effect of temperature on irreducible water saturation, residual oil saturation, the endpoint relative permeability to oil and water and the generalized Corey saturation exponents of oil and water were analyzed separately for each rock-fluid system. It was found that, although the scatter in reported data is large, some discernable differences are present in the effect of temperature in different rock fluid types. Separate correlations, in the form of generalized Corey saturation exponent model with temperature dependent parameters, were developed for oil/water relative permeability in different rock-fluid systems.

Abstract The dominant mechanism of enhanced heavy oil recovery by chemical flooding is studied by conducting various chemical slug injections in a two-dimensional physical model. In this study, a total of seven single-chemical-slug tests and another seven two-chemical-slug tests are conducted to test the contribution of alkaline, surfactant, polymer, and their combinations to enhanced heavy oil recovery. The relationship between the tertiary oil recovery and the pressure drop of the seven single-slug floods is analyzed, and it is discovered that the two have a good correlation. Comparison of the tertiary oil recoveries of different chemical slug tests shows that the improved waterflood for the heavy oil used in this study is mainly due to the reduction of water mobility. The results of two-chemical-slug tests show that after regular alkaline/surfactant/polymer flooding, the second polymer slug injection can recover more oil, if a water slug injection is applied between the two chemical slugs.