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Heavy oils with about 500 cp to 50,000 cP viscosity in unconsolidated sand reservoirs are commercially produced without heat injection, by a production method known as the Cold Heavy Oil Production with Sand (CHOPS). CHOPS reservoirs are generally about a kilometer wide and may range from 3 to 5 m thick sand blankets to 35 m thick sand channels which are between 0.5 to 5 Darcy permeability, 28 to 32% porosity, and have about 88% oil and 12% water saturations. CHOPS production is always coupled with the production of the dissolved gas, mostly CH4 and minor amounts of H2S and CO2, and sand production which causes formation of wormholes in the reservoir. Formation of wormholes in the initial phase of the reservoir life promotes oil migration and thus increases oil production; however, continued wormhole formation in long term operations reduces the oil production rate and harms the sweeping efficiency of the original oil in place, typically to less than 10%. Because of low sweeping efficiency, several Post-CHOPS process concepts have been investigated to recover the remaining oil in the reservoir. The objective of the present study is to increase the production and sweeping efficiencies of CHOPS and Post-CHOPS processes by altering the wettability of oil and reservoir sand as well as the wettability of oil and connate water and/or water injected into the reservoir. In this study, an oil-water emulsion sample produced by CHOPS process was centrifuged to separate the oil and water phases to avoid using chemical demulsifiers. The separated oil and water phases were physically and chemically characterized and the oil-water interfacial tension was determined using pendant drop method at a temperature range between 20 to 50 oC. The effects of solvent, surfactant, and pH on oil-water interfacial tension were independently investigated by either diluting the oil with pentane as a solvent additive (5% to 15% by mass of oil dosages), emulsifying biodiesel (fatty acids methyl esters, chemical formula: CnHm-COOCH3; m Results of these studies suggest that bitumen mobility and sweeping efficiency of CHOPS and Post-CHOPS processes could be improved by reducing the oil-water interfacial tension. The present experimental research demonstrates that oil-water interfacial tension could be reduced by either a basic or a nonionic surfactant additive. Implementation of these findings to CHOPS and Post CHOPS processes needs further understanding of the CHOPS reservoir characteristics. Laboratory test results are encouraging enough for further laboratory and field trials to increase the production and oil sweeping efficiencies of the CHOPS reservoirs.

In Alberta, Canada, bitumen production by surface mining followed by ore-water slurry based extraction processes is approaching 2,000,000 bbl/d capacity. The Clark Hot Water Extraction process developed in the 1930s is used at all commercial plants which use caustic NaOH as an additive to boost bitumen recovery efficiency. Use of NaOH as an extraction process additive increases process water salinity, specifically Na+ concentration, promotes dispersion of silt and clay size particles which results in greater production of toxic mature fine tailings. Increase in process water Na+ concentration detrimentally affects the performance of both bitumen extraction and tailings disposal processes. Existing mature fine tailings inventory stored in tailings ponds is exceeding 900x106 m3 and is predicted to grow alarmingly faster by the completion of new plants and by an increase in the production capacity of the existing plants. The Energy Resources Conservation Board of Alberta issued Directive 074 in February, 2009 urging oil sands plants to comply with a 50% reduction in mature fine tailings production. Proposed policies by the oil industry in response to Directive 074 have shown short fallings; which suggests that development of novel bitumen extraction and tailings management processes are needed. To reduce the mature fine tailings inventory, we studied production of nonsegregating tailings by treating a blend of cyclone underflow and thickened cyclone overflow with CaO additive. These tests were made using Albian Sands Muskeg River Mine tailings when the plant was operating at nonadditive and sodium citrate additive extraction modes and using Syncrude Canada Ltd.'s Aurora Mine tailings. Also, we studied the use of CaO as a bitumen extraction process additive replacing NaOH in the Clark Hot Water Extraction process; by which silt-clay size particles dispersion in the extraction process slurry is reduced and accumulation of Na+ in the process water is eliminated. Use of CaO as an extraction additive is considered as a fundamental and a new process alteration by the oil sands operators. Recently, to evaluate this new process the Canadian Oil Sands Innovation Alliance (COSIA) has requested NAIT-NARCOSS, an independent academic and industrial research laboratory, to perform a third party verification study for the use of CaO as a bitumen extraction process additive. The NAIT-NARCOSS test results are completed and are highly encouraging, confirming that use of CaO as an extraction process additive reduces dispersion of silt and clay size particles in the extraction process slurry without harming bitumen recovery efficiency. It also improves process water chemistry by eliminating accumulation of Na+ in the process water. It is concluded that a paradigm change is offered to the oil sands industry to reduce the adverse environmental impacts of oil sands plants in simple, cost effective and environmentally friendly manners; which is the simultaneous implementation of the use of CaO as additives in bitumen extraction and nonsegregating tailings production processes.

In Alberta, Canada, over 80% of oil sand reserves are suitable for thermal in-situ processes such as the steam assisted gravity drainage (SAGD) process. SAGD recovery is contingent on reducing the viscosity of bitumen, which is immobile at reservoir temperature, to increase its mobility, thus increasing recovery efficiency. Processes based on the co-injection of solvent and steam targeting further reduction of bitumen viscosity have been extensively investigated. These studies generally ignore the potential role of bitumen-water interfacial tension on bitumen mobility and bitumen recovery. In this study, we propose a new analytical model approach to analyze flow characteristics of injected steam in a bitumen containing reservoir and to clarify the physics of the displacement process during SAGD. The thickness of the chamber front where viscosity reduction occurs is defined for different injection and reservoir conditions and flow patterns are created for different fluid (viscosity and interfacial tension) and reservoir properties (thickness). This model shows how bitumen-water interfacial tension affects bitumen mobility and thereby influences both SAGD displacement efficiency and ultimate bitumen recovery. A composite set of models including the effects of interfacial tension between the bitumen and water in addition to viscosity reduction are developed. Finally, the observations obtained through analytical model studies are compared against SAGD field observations accumulated over the last two decades. The focus of this comparison is on the advancement rate of the chamber front and its growth characteristics. By understanding the bitumen to water interfacial tension effects, it will be possible to make a better prediction of the relative benefits of solvent or surfactant to accelerate the recovery rate and improve ultimate recovery.

In Alberta, Canada bitumen is commercially produced by in-situ processes at about 830,000 bbl/d capacity, production capacity is projected to exceed 5,000,000 bbl/d in the next two decades. Steam assisted gravity drainage (SAGD) process is one of the in-situ bitumen recovery processes; the economics and efficiency of which would be improved by reducing the steam to bitumen ratio. For this purpose, the addition of light hydrocarbon solvents into steam as a solvent to reduce bitumen viscosity has been studied; however, several decades of research efforts has resulted in only limited commercial success. More recently, as an alternative to solvent addition, the use of biodiesel (fatty acid methyl esters) with steam as a surfactant additive reducing bitumen-water interfacial tension was proposed and studied experimentally (Babadagli et al, 2009; Babadagli and Ozum, 2010). In the present study, experiments were performed at typical reservoir pressure conditions to evaluate the performance of solvent (pentane) addition with steam to reduce viscosity and biodiesel addition with steam to reduce bitumen-water interfacial tension to improve bitumen recovery efficiency. The results showed that bitumen recovery efficiency may decrease with the addition of hydrocarbon solvent if the solvent is added after a certain period of steam injection. Solvent addition to the steam was tested at 5% and 15% of bitumen mass dosages. Steam assisted bitumen recovery tests with biodiesel addition under 2-g/kg-bitumen dosage showed an increase in bitumen recovery efficiency. To further investigate the reasons behind the lowered recovery with solvent addition, an analytical model was developed to predict heat transfer and pressure fields in the reservoir causing Darcy flow, and therefore, bitumen mobility. The distribution of the aqueous and solvent phases injected in time and space considering the phase change (steam and solvent condensation) effect with respect to steam chamber were clarified for different injection conditions and scenarios. The results and observation will be useful in defining the appropriate application conditions for both solvent as a viscosity reducer and biodiesel as an interfacial tension reducer additive in SAGD operations.