With the VAPEX process, combinations of vaporized solvents are injected into heavy oil and bitumen reservoirs for in situ recovery of the oil. The oil is diluted with the solvent, which reduces the viscosity so the oil drains by gravity to a horizontal production well. The VAPEX process has the potential to greatly reduce the greenhouse gas emissions for oil sands and heavy oil recovery since it is a non-thermal process that does not require the reservoir to be heated with, for example, steam. The Petroleum Recovery Institute (PRI) was the operator of a joint industry project of 16 participants with nine research performing organizations. During 1998, the project investigated the full project engineering and commercial scale economics for the VAPEX process. The supply cost economics for VAPEX oil production from the Athabasca oil sands, Cold Lake oil sands and Southeast Alberta heavy oil were determined. The work indicated that VAPEX has attractive economics and helped to define the critical field operations design issues that need to be addressed prior to proceeding with a substantial field pilot. The climate change advantages of the VAPEX process are described in the paper along with an overview of the integrated physical model, numerical simulation, facilities design, well specifications, production, transportation, and marketing work which led to calculation of the supply cost economics. Introduction The VAPEX (vapor extraction) process(1) is a non-thermal process that uses vaporized solvents that are injected into heavy oil or bitumen reservoirs. The solvent dissolves in the oil at the natural reservoir temperature, reducing the viscosity of the oil, which will then readily flow by gravity to a horizontal production well(2). The concept is described in several Canadian and USA patents(3, 4). As shown in Figure 1, twin horizontal wells are used for the recovery process. VAPEX gas is injected into the upper well where it dissolves in the oil, which then drains to the lower producer. The development of the VAPEX technology is shown pictorially in Figure 2. Since the initial patent in 1978, there has been basic and applied research and invention(2). In 1998, the PRI operated a project called "Development of Full Project Engineering and Economics for the VAPEX Process," with 16 participants and nine research performing organizations. The project continued in 1999 with Phase 2 for VAPEX operations design on "How to Operate VAPEX in the Field," which included conceptual design of two VAPEX pilot plants for an oil sands application and a heavy oil reservoir application with underlying water. The VAPEX process has several potential advantages and disadvantages for commercial scale economic oil production. The potential advantages are: no steam generation; no water processing/ recycle; lower fuel costs; greater energy efficiency; lower carbon dioxide emissions; may be advantageous in thin reservoirs or with bottom water, and potential in situ upgrading. The potential disadvantages are: solvent compression, solvent losses and potential sensitivity to reservoir heterogeneity. The advantages and disadvantages are reiterated in Tables 1 and 2.

The injection of non-condensable gases (NCG's) with steam in SAGD is a concept that has been much discussed in the literature, and tested via laboratory studies, and in a small number of field pilots, the most comprehensive being the UTF Phase B. There has been considerable discussion, both positive and negative, regarding the behaviour of these gases in the steam chamber, and their impact on ultimate bitumen recovery. Benefits to SAGD productivity have been suggested by some, while other authors have projected impacts on bitumen recovery. The authors have reviewed the results of methane injection in several projects, and used thermodynamic theory to develop a method to effectively model this behavior via simulation. While conventional simulators use the Peng-Robinson Equation of State, the effectiveness of EOS's become challenging at high temperature. In addition, the effects of recent developments in high temperature solution thermodynamics become significant with increasing temperature in SAGD. AOSC has developed a method of modeling the effects of NCG in a steam zone, via the development of a new set of equilibrium values for methane exchange between the oil/gas phase, water/gas phase and oil/water phases. This paper will present the results of these simulations and predicted impact of methane injection on SAGD performance, as well as implications for other NCG's. Introduction The simulation of the behaviour of non-condensable gases (NCG) in SAGD schemes has so far met with limited success. While methane, the main solution gas in Athabasca bitumen, can be modeled to some extent, greater difficulty has been encountered with the other two main produced gases in SAGD, carbon dioxide and hydrogen sulphide. These are not solution gases and must be introduced in some other way before they can be partitioned by simulator routines. Further, at high temperatures in a steam zone, neither has a significant solubility in Athabasca bitumen. Thimm 1a,b has suggested that gas production in SAGD is best understood in terms of dissolution of gases in the produced liquids. The commercial simulators do not account for this phenomenon, which is controlled by high temperature solution thermodynamics. In addition, literature reports suggest a wide difference in predictions from simulators on one hand, versus laboratory data and field results on the other, in the few cases where gas has been co-injected with steam. Background Some evidence has been published in the past to suggest that gases which accumulate in the steam zone tend to migrate to the top of the steam zone, and provide a barrier to heat loss to the overburden. Butler in 19972 was the first to propose this effect, largely on the basis of laboratory measurements and subsequent evaluation of the thermal data. Butler's primary concern appears to have been that conventional SAGD is most suitable for thick pay zones, and that the effective barrier to heat loss provided by a gas blanket would extend the economics of SAGD to thinner reservoirs. Evidently, Butler was also hoping for a Steam and Gas Push (SAGP) effect to improve production rates, and recommended the field testing of the SAGP scheme.

The depositional setting of the McMurray Formation within the main Athabasca fairway has been extensively studied by industry and is well documented in the literature. Much crown land in this easternmost part of the Athabasca Oil Sands Area (AOSA) is currently being drilled and geologically characterised with the aim of in-situ thermal extraction methods, such as SAGD. Reservoirs in this region consist of tidally-influenced channel sands and open estuarine tidal sand bars. There are, however, new plays being discovered in the northwestern part of the AOSA that represent strikingly different depositional environments. Athabasca Oil Sands Corp. (AOSC) holds extensive oil sands assets in this western region of AOSA, and has discovered thick, good quality bitumen pay within the McMurray Formation. Depositional environments of the McMurray Formation in this region contrast significantly to those reservoirs located within the main fairway to the east. This paper will describe the depositional environment, the building of a numerical simulation model to represent this reservoir, and the results of simulation studies predicting the performance of SAGD behaviour in this particular depositional setting. Introduction Athabasca Oil Sands Corporation (AOSC) is a privately owned junior oil sand company located in Alberta, Canada, which was formed in mid 2006. By the end of 2007, it had acquired over 650,000 acres of contiguous oil sands leases in northwestern Alberta. Some of these leases were located in a relatively underexplored area, close to Fort McMurray. AOSC strategy was to focus on acquiring high quality contiguous leases of the McMurray-Wabiskaw clastic interval. Last winter saw AOSC drill 231 delineation wells over its assets in order to delineate the oil sands resource base. Geological results from the drilling program were very encouraging, but one asset in particular (Thickwood/MacKay) exhibits excellent reservoir quality over a large area. It was thus decided to "fast-track" in-situ development of this area. The Thickwood/MacKay leases cover 116,500 acres or 471 km2 (182 miles 2) of land and are located in Townships 88 to 91, Ranges 13 and 14 West of the 4th Meridian. These leases are located adjacent to Petro-Canada's MacKay River SAGD project; one of the best performing SAGD projects in Alberta. There were originally only 7 vintage stratigraphic wells located across the Thickwood/MacKay asset, but this number increased dramatically to 68 during the winter 2007/08 delineation program as AOSC drilled and logged 61 wells, 24 of which were cored through the McMurray Formation (Figure 1). These wells encountered a highly bitumen-saturated and clean McMurray reservoir which extends for more than 28 km in length and is up to 5km in width. Its lateral continuity and distinct reservoir facies distinguish it from the typical McMurray channel sand reservoirs. The exceptionally high quality of the McMurray reservoir has led AOSC to launch a pilot scheme to test the SAGD potential here. The pilot is designed to produce approximately 2,000 barrels per day bitumen, with start up anticipated in the second half of 2010.

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