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.

Introduction Since the beginning of the Industrial Revolution anthropogenic activities in general, and fossil fuel combustion in particular, have contributed to an appreciable increase in atmospheric CO2 concentrations, among other greenhouse gases (GHGs)(1). With Canada's ratification of the Kyoto Protocol, the potential for sequestration of CO2 is worth serious consideration. This paper, which summarizes the results of a comprehensive three-volume study(2), provides an overview of the costs to capture, transport, and geologically sequester CO2 in Western Canada. In general sequestration means storing CO2 which has been removed either directly from anthropogenic sources or from the atmosphere, for geologically-significant time periods, if not permanently. Used herein sequestration refers to taking carbon dioxide which has been extracted from an exhaust or vented gas stream and placing it in long-term storage in depleted western Canadian oil and gas reservoirs, referred to as sinks. This study deliberately excludes CO2 used for enhanced oil recovery (EOR) projects, which may be economically attractive, but are volumetrically limited in comparison to pure storage projects. Methodology CERI used net discounted cash flow (DCF) models to estimate costs for CO2 capture, transportation, and storage. Discounted cash flow calculations generate the present value of a future stream of net cash flows. In this application. CERI models solve for a CO2 " price" that would make a CO2 capture. Transportation, and/or storage operation profitable. The model results therefore.; tre the prices that a company specializing in CO2 mitigation would have to charge per unit of CO2 sequestered to recover all of its costs including taxes and a return on investment. The methodology used to arrive al capture and sequestration costs analyzed CO2 sources and sinks in a similar way. Establishing the locations and characteristics of the major point sources and eligible sinks was a logical first step. However performing detailed cost analyses on every source and sink was not feasible. Instead, prototypes representing a range of different characteristics were selected for detailed analysis, from which the results were scaled to the remaining population. Unit costs for CO2 capture and storage were then generated from the population data using the economic (DCF) models. Finally to link the sources to the sinks, unit costs were developed for a common-carrier pipeline network in the basin. CO2 Capture Any large-scale CO2 capture program must first establish an inventory of potential capture candidates, including the volumes, characteristics, and locations of the most significant sources. For this study. CERI compiled an inventory of 192 discrete CO2 sources found at 115 sites throughout the Western Canadian sedimentary Basin, with total annual CO2 emissions of 141 Mt. Figure 1 illustrates the distribution of assessed emissions according to the industry from which they are emitted. The significance of coal-fired power plants in Western Canada's emission picture is evident. Oil sands mines and in situ projects contribute another large quantity, one that is expected to increase dramatically in the future. Based on projected emissions in 2005(3), CERI's inventory accounts for over 75% of industrial and power generation emissions in the four western provinces and 50% of total CO2 emissions.