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Summary In earlier work (Pathak et al. 2010, 2011), we presented the initial results for heavy-oil and bitumen recovery using heated solvent vapors. The heavy-oil- and bitumen-saturated sandpack samples of different heights were exposed to heated vapors of butane or propane at a constant temperature and pressure for an extended duration of time. The produced oil was analyzed for recovery, asphaltene content, viscosity, composition, and refractive index. Recovery was found to be very sensitive to temperature and pressure. The current work was undertaken to better understand the physics of the process and to explain the observations of the earlier experiments using additional experiments on tighter samples of different sizes, numerical simulation, and visualization experiments. The effects of temperature and pressure on the recovery were studied using a commercial reservoir simulator. Propane and butane were used as solvents. Asphaltene precipitation was also modeled. A qualitative history match with the experiments on different porous-media types was achieved by mainly considering the permeability reduction caused by asphaltene precipitation; pore plugging; the extent of interaction between the solvent and oil phases; and parameters such as model height, vertical permeability, and gravity. The effect of asphaltene deposition on models of varying permeabilities was also studied. To investigate the phenomenon further, visualization experiments were performed. 2D Hele-Shaw models of different dimensions were constructed by joining two Plexiglass sheets from three sides, or in some experiments, from all sides. The models were saturated with heavy oil and left open on one side (or all sides) and were exposed to different types of solvents. The setup was monitored continuously to observe fluid fronts and asphaltene precipitation. By use of this analysis, the mechanics of the process was clarified from the effect of solvent type on the recovery process. The optimum operating temperature for the hot-solvent process and the dominant mechanisms were identified. The dynamics of the asphaltene deposition and its effect on oil recovery were clarified through visual and numerical models.

Thermal and miscible methods are commonly used for in situ recovery of heavy oil and bitumen. Both techniques have their own limitations and benefits. However, these methods can be combined by co-injecting solvent with steam or injecting solvent into a pre-heated reservoir. The current work was undertaken to study the performance of solvents at higher temperatures for heavy oil/bitumen recovery. Glass bead packs and Berea sandstone cores were used in the experiments to represent different types of pore structures, porosity and permeability. After saturating with heavy oil, the samples were exposed to the vapor of paraffinic solvents (propane and butane) at a temperature above the boiling point of the solvent, and a constant pressure of 1500 kPa. A mechanical convection oven was used to maintain constant temperature across the setup. The setup was designed in such a way that a reasonably long sample (up to 30 cm) can be tested to analyze the gravity effect. The oil recovered from each of these experiments was collected using a specifically designed collection system and analyzed for composition, viscosity and asphaltene content. The final amount of oil recovered in each case (recovery factor but not extraction rate) was also analyzed and the quantity and nature of asphaltene precipitated with each of the tested solvents under the prevailing temperature and pressure of the experiment was reported. Optimal conditions for each solvent type were identified for the highest ultimate recovery. It was observed that recovery decreased with increasing temperature and pressure of the system for both solvents, and that the best results were found when experimental temperature is only slightly higher than the saturation temperature of the solvent used. It was also noticed that butane diluted the oil more than propane which resulted in lower asphaltene content and viscosity of oil produced with butane as a solvent.

Summary The majority of steam assisted gravity drainage (SAGD) development to date has been concentrated in the McMurray formation in the Eastern Athabasca fairway. More recently operators have identified projects with considerable resources located in shoreface sands of the Grand Rapids formation in the Wabasca area. Laricina Energy's Germain thermal project in Grand Rapids has associated basal water underlying much of the reservoir. In this paper the authors show that SAGD can be configured to maximize bitumen recovery for such reservoirs, based on laboratory and new simulation studies. The result is a SAGD configuration where the producers are placed at the base of porosity, within the basal water zone.

Abstract The last few years have seen the end of the Athabasca land play and the revival of interest in Alberta's bitumen resources in carbonate reservoirs. Of these, the Grosmont Formation is the most promising in terms of resource size and concentration. It is also the best known, in terms of having been the subject of several in situ pilots operated in the late '70s and early '80s. The data recorded from these early pilots is priceless in terms of having a touchstone of reality for new process concepts. On the other hand, the interpretations written in those days ('before gravity') are not necessarily as helpful. This paper looks at the Grosmont in terms of facts and fundamentals, and presents the case for Grosmont exploitation. There is good evidence that the Grosmont has very high bulk permeability as a result of karst porosity development and fracturing. This bodes well for the use of modern gravity drainage methods in the Grosmont. Introduction Grosmont Piloting History The Grosmont Formation in north-central Alberta is a dolomitized, karsted and fractured platform carbonate containing a massive bitumen accumulation. An excellent historical summary of various Grosmont pilots was recently provided by Alvarez et al.(1) Cyclic Steam Stimulation (CSS), steam drive and forward combustion were all attempted in the Grosmont during the '70s and '80s. CSS was the most widely and successfully piloted method. The best well, at 10A-5-88-19W4, recovered about 100,000 bbls of oil over 10 cycles, with a cumulative steam-oil ratio (CSOR) of about 6. Results of other tests were mixed, as were the operating procedures; most of these were based on horizontal flooding concepts. However, responses to well-executed CSS first cycles were reasonably similar at a number of widely-spaced wells. Notably, steam injectivity was generally sufficient so that a few hundred tonnes/day could be injected at pressures that were significantly below overburden pressure (ruling out geomechanical enhancement of permeability). A degree of pessimism, or at least great caution, has been expressed with respect to the supposed complexity of the reservoir, and hence, prospects for commercial recovery. In particular, it is often said that the reservoir is very heterogenous, and that this explains the historical failure of attempted steam drive and fire flood processes. Review of the Unocal Buffalo Creek and McLean scheme reports(2, 3) suggest that much of this originates in the interpretations of the contemporary operators, who largely explored conventional EOR concepts involving horizontal displacement. They expected to recover oil by means of horizontal, radial flow. When this failed, it was natural to assume that the problem lay in a failure to maintain the 'radial' part of the prescription, due to permeability heterogeneity. Figure 1 presents the performance of the Buffalo Creek 10A-5 CSS test in perspective with a contemporary test and two modern-day, commercially-optimized CSS wells (the data is publicly available from the Alberta Energy Resources Conservation Board). It can be seen that the Grosmont well had comparable performance to a Clearwater CSS test of the same vintage.

With the decrease in conventional oil and gas reserves throughout the world and an ever-increasing demand for fossil-fuel based energy and resulting high oil prices, focus has been shifting to unconventional and heavy oil and bitumen. Grosmont carbonates in Northern Alberta have been estimated to contain at least 300 billion barrels of heavy oil or bitumen. However, recovering this oil is extremely difficult because of the complexity associated with carbonate reservoirs in general, e.g., the Grosmont unit is known to possess a triple porosity system – matrix, fractures and vugs, based on core studies. The second problem is the fluid itself, which is highly viscous bitumen, immobile at reservoir conditions. To extract this bitumen from very heterogeneous carbonate rock, both heat and dilution using solvents may be needed. This paper reports the results and analysis of hot solvent experiments conducted on original Grosmont carbonate cores. Three experiments were conducted using propane and one using butane as solvent. After heating the entire system containing the core sample, solvent gas was injected. The rock was allowed to soak in the hot solvent for a long time. The experimental temperature and pressure were decided on the basis of the results of our earlier work that suggested to be just above the saturation line of the particular solvent.. An attempt was made to keep the conditions close to the saturation conditions of the solvent being used to maximize the dilution and hence, the recovery. The oil produced was analyzed for viscosity and asphaltene content. The results in terms of recovery, the degree of dilution and upgrading achieved suggested that butane was a better solvent for this bitumen. Finally, the optimum conditions for operation of the hot solvent process were verified for Grosmont carbonates.

Thermal and miscible methods are commonly used for in-situ recovery of heavy oil and bitumen. Both techniques have their own limitations and associated shortcomings, often times yielding an inefficient process. The most common thermal method is steam injection, which is highly energy intensive. Steam generation costs and water production affect the economics of the thermal technique adversely. On the other hand, miscible methods are energy effective but their economics depends on the solvent retrieval. Various combinations of these two techniques such as co-or alternate injection of steam and solvent have been proposed as a solution, but no optimum method has yet been developed. Thermal and miscible methods can be combined by co-injecting solvent with steam or injecting solvent into a pre-heated reservoir. Current work was undertaken to study the performance of solvents at higher temperatures for heavy oil/bitumen recovery. Glass bead packs and Berea sandstone cores were used in the experiments to represent different types of pore structures, porosity and permeability. After saturating with heavy oil, the samples were exposed to the vapor of paraffinic solvents (propane and butane) at a temperature above the boiling point of the solvent, and a constant pressure of 1500 kPa. A mechanical convection oven was used to maintain constant temperature across the setup. The setup was designed in such a way that a reasonably long sample (up to 30 cm) can be tested to analyze the gravity effect. The oil recovered from each of these experiments was collected using a specifically designed collection system and analyzed for composition, viscosity and asphaltene content. The amount of oil recovered in each case was also analyzed and the quantity and nature of asphaltene precipitated with each of the tested solvents under the prevailing temperature and pressure of the experiment was reported. Optimal conditions for each solvent type were identified for the highest ultimate recovery. It was observed that recovery decreased with increasing temperature and pressure of the system. It was also noticed that butane diluted the oil more than propane which resulted in lower asphaltene content and viscosity of oil produced with butane as a solvent.

Abstract World-wide experience indicates that thermal methods are the only effective methods for the in-situ recovery of heavy oils. Furthermore, the steady progress within horizontal well technology increases the applicability of thermal methods in conjunction with horizontal wells. The steam-assisted gravity drainage (SAGD) process is the prominent example of the synergism of horizontal wells with steam injection. The major portion of the dollar per barrel operational cost for steam injection is currently attributed to the generation of steam and water handling requirements. In the future, more stringent environmental regulation might further prohibit the use of water for the recovery of heavy oils. Naptha is present at the site as a diluent for pumping and pipe line transport of the produced heavy oil. The injection of naptha vapour instead of water vapour combines an effective thermal process with the diluent mechanism of the naptha. We present the results of simple analytical calculations, demonstrating the applicability of naptha-assisted gravity drainage (NAGD) compared to the SAGD process. Numerical simulations have been performed on a two-dimensional cross section perpendicular to the horizontal well pair. We discuss in detail the reservoir mechanisms present during NAGD. For the conditions studied naptha circulation rates are some 14 times the bitumen production rate. Evaluation of the process shows that it will be economic with naptha recycling and by minimising the naptha remaining in the reservoir. Introduction Heavy oil and bitumen resources can more than double the earth's hydrocarbon reserves. Unfortunately, most heavy oil and bitumen accumulations cannot be produced economically with current in situ recovery technology. Canada owns some 40 per cent of these unrecoverable resources. The emergence of horizontal wells allowed a larger reservoir exposure, which increases productivity, accelerates recovery, and reduces coning tendencies. For example, horizontal wells are used, at present, for the primary recovery of heavy oil and bitumen in Canada. The combination of thermal methods and horizontal wells for heavy oil recovery increases the potential for more economic operations. In the SAGD process, heat is injected in the form of saturated steam through a horizontal injector. The injector is located above and more or less parallel to a horizontal producer. The distance between the two is dictated by early-time communication considerations. The SAGD process has proven successful at the UTF site in Alberta, Canada. As shown at the UTF site, an optimised process demands that the wells are regulated in such a way as to let the drainage mechanism operate freely. Hence, fluids need to be produced when they arrive at the producer, and injection rates need to satisfy the heat demand of an expanding steam zone. At the same time, a liquid level has to be established above the producer to limit the production of steam. Butler has given a basic description of the SAGD process. P. 475