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Steam-based EOR methods for viscous oil recovery from fractured reservoirs have significant challenges in both cost and energy efficiency. In response, solvent-based methods have been of interest because of their low energy intensity, low greenhouse gas emissions, and no fresh water consumption. Injection strategies for viscous oil recovery by solvent include liquid extraction and vapor oil gravity drainage. Understanding the mechanisms in each phase is of great value for the successful application and optimization of solvent EOR processes. The work presented here studies the effect of solvent injection rate on viscous oil recovery by liquid extraction with n-butane in vertically placed sandstone cores with an artificial fracture. The oil production rate, ultimate recovery, and in situ deasphalting in different sections of the core are analyzed. The oil production rate increased with solvent injection rate until it leveled off as the injection rate exceeded a critical value. The ultimate recovery factor is nearly the same for all solvent injection rates below the critical value. However, it is significantly reduced at higher injection rates. A conceptual model based on convective mass transfer is proposed and the effect of mechanical dispersion is discussed. In situ deasphalting was observed in all cases. The cause of the unexpected changes in production rate was attributed to severe asphaltene deposition and remobilization in the fractured permeable rock. In such a medium, solvent injection rate seems to show an optimal value for maximizing oil production rate, ultimate recovery factor, and solvent efficiency.

Summary This fundamental research is part of a larger study in determining the capability of a solvent process, referred to as vapor/oil gravity drainage (VOGD), for enhancing gravity drainage of viscous oil in fractured reservoirs by the injection of solvent. The solvent can be designed to traverse the reservoir mostly in its vapor phase at the reservoir temperature and pressure. Heated solvent vapor can also be used to facilitate the propagation of solvent vapor in low-temperature reservoirs, taking advantage of both thermal- and solvent-recovery processes. The experimental setup and corresponding acquired data were previously introduced by the authors in Anand et al. (2018), in which the effects of temperature, solvent-injection rate, and solvent type [n-butane and dichloromethane (DCM)] were investigated. Results from Anand et al. (2018) indicated encouraging high oil rates and ultimate recoveries; results also demonstrated that the oil rates and recovery were affected by diffusion and dispersion (in the form of intrinsic gas rate), asphaltene precipitation, and capillary pressure. The intent of our present work is to further study the mechanisms behind VOGD—in particular, those related to operating pressure and solvent-vapor/oil capillary pressure. The results from this work show that the ultimate recovery and oil rate are positively correlated to the operating pressure; experiments conducted at 50 and 75% saturation pressure (Psat) yielded lower ultimate oil recoveries, ranging from 33 to 68% of original oil in place (OOIP), compared with the experiments conducted at 90% Psat (recovery of 70% OOIP). Moreover, n-butane performed better than DCM, and lower asphaltene precipitation was seen at lower Psat. The main drivers for these observations were found to be lower solvent solubility and larger capillary pressure values at lower values of Psat.

Viscous oil resources have great potential to help meet the future demand for petroleum products as conventional resources are depleted. Currently high temperature steam injection is the recovery process of choice, with high energy intensity and associated greenhouse gas emissions. The work presented here explores a low-temperature solvent-only injection strategy targeting fractured systems. The warm solvent is in the vapor phase when injected into the reservoir but will condense when it contacts the cold oil and reservoir rock (liquid extraction). After the system has reached the target operating temperature, the injected solvent remains in the vapor phase when it contacts the oil (solvent-enhanced gravity drainage). The experiments discussed in this work explore the key parameters (permeability, temperature/pressure, in situ injection rate, and solvent type) that influence each production mechanism. The primary impact of decreasing permeability is a proportional decrease in film gravity drainage rate. A decrease in temperature slows the mass transfer during the liquid extraction phase and decreases the drainage rate during the film gravity drainage phase. Increasing the in situ injection rate leads to improved liquid extraction because of higher concentration gradient in the solvent-rich liquid phase at the oil/solvent interface. Solvent type affects both mechanisms and changes the nature and amount of asphaltene precipitation. Pentane yields relatively less asphaltene precipitate than butane (18 wt % vs 11 wt % asphaltene content in residual oil). Residual oil saturation was observed to increase as permeability and/or temperature were decreased.

Summary Application of thermal and solvent enhanced-oil-recovery (EOR) technologies for viscous heavy-oil recovery in naturally fractured reservoirs is generally challenging because of low permeability, unfavorable wettability and mobility, and considerable heat losses. Vapor/oil gravity drainage (VOGD) is a modified solvent-only injection technology, targeted at improving viscous oil recovery in fractured reservoirs. It uses high fluid conductivity in vertical fractures to rapidly establish a large solvent/oil contact area and eliminates the need for massive energy and water inputs, compared with thermal processes, by operating at significantly lower temperatures with no water requirement. An investigation of the effects of solvent-injection rate, temperature, and solvent type [n-butane and dichloromethane (DCM)] on the recovery profile was performed on a single-fracture core model. This work combines the knowledge obtained from experimental investigation and analytical modeling using the Butler correlation (Das and Butler 1999) with validated fluid-property models to understand the relative importance of various recovery mechanisms behind VOGD—namely, molecular diffusion, asphaltene precipitation and deposition, capillarity, and viscosity reduction. Experimental and analytical model studies indicated that molecular diffusion, convective dispersion, viscosity reduction by means of solvent dissolution, and gravity drainage are dominant phenomena in the recovery process. Material-balance analysis indicated limited asphaltene precipitation. High fluid transmissibility in the fracture along with gravity drainage led to early solvent breakthroughs and oil recoveries as high as 75% of original oil in place (OOIP). Injecting butane at a higher rate and operating temperature enhanced the solvent-vapor rate inside the core, leading to the highest ultimate recovery. Increasing the operating temperature alone did not improve ultimate recovery because of decreased solvent solubility in the oil. Although with DCM, lower asphaltene precipitation should maximize the oil-recovery rate, its higher solvent (vapor)/oil interfacial tension (IFT) resulted in lower ultimate recovery than butane. Ideal density and nonideal double-log viscosity-mixing rules along with molecular diffusivity as a power function of oil viscosity were used to obtain an accurate physical description of the fluids for modeling solvent/oil behavior. With critical phenomena such as capillarity and asphaltene precipitation missing, the Butler analytical model underpredicts recovery rates by as much as 70%.