Approximately 80% of the Canadian oil sands are too deep to be economically mined. SAGD, an in situ recovery technology, has come of age and is emerging as the technology of choice in exploitation of these resources. The current major challenge that SAGD faces is the use of expensive heat to generate steam. The authors have previously described an improvement to SAGD, Solvent Aided Process (SAP), that aims to combine the benefits of using steam with solvents. In SAP, a small amount of hydrocarbon solvent is introduced as an additive to the injected steam during SAGD. SAP holds the promise to significantly improve the energy efficiency of SAGD thus reducing the heat requirement. This paper describes field testing of SAP at EnCana's Christina Lake SAGD Project. In addition to dwelling on some of the important parameters of a SAP test, it outlines the design considerations for the pilot and associated facility modifications. The design duration of the experiment calls for an assessment of reservoir performance on a long-term basis. However, some preliminary observations and indications are discussed. Additionally, impact of timing of solvent initiation and the well pair spacing on process performance is also explored based on modelling exercises. Introduction In SAGD, oil viscosity is reduced by heating with steam(1, 2). In SAP(3, 4), solvent dilution is also taken advantage of to aid this viscosity reduction. The result is an enhanced rate of oil production and recovery leading to superior economics with lower energy intensity and impact on the environment. In the context of doing away with the heating requirement, VAPEX, a process similar to SAGD but employing only hydrocarbon vapour instead of steam, has been described in the literature(5–8). However, its development is awaiting a successful field trial. Use of solvent with steam for oil recovery is also discussed in the literature(9–12) with a focus on the enhancement of steam displacement or steam stimulation. Using solvent with steam in a SAGD context offers some practical advantages. The pressure in the vapour chamber does not need to be supported by a non-condensable gas, as would be required in some versions of VAPEX. This means that the progression of the vapour chamber in SAP does not get overwhelmed by the heat/mass transfer resistance at the vapour/oil interface. Recently, others(13, 14) have also discussed the benefits of using solvents with SAGD in a process similar to SAP. Nasr and his colleagues(13, 14) advocate the use of those solvents that match the condensation characteristics of steam at the operating conditions. Previous descriptions(3, 4) and data do not suggest such requirements for SAP. EnCana has been developing SAP since 1996 and first piloted the process at its Senlac Thermal Project in 2002. Encouraged by the results, EnCana is presently testing SAP for in situ bitumen extraction at its Christina Lake Thermal Project. In the Senlac SAP Pilot, some description of which has been given previously(4), solvent (butane) was co-injected in a well pair which was already in SAGD operation.

Gravity drainage processes, such as SAGD and VAPEX, aim at exploiting viscosity reduction of the target oil, either through thermal diffusion or dilution. Thermal diffusion being much faster than molecular diffusion, production rates from a steam process are expected to be higher than a solvent-alone process. Despite this apparent drawback, solvent-alone processes promise to be attractive owing to lower heat losses and energy requirements, lesser impact to the environment, possible downhole upgrading, etc. One is naturally led to thinking of combining the benefits of SAGD with that of the solvent-alone process. The resultant process, aimed to improve the performance of SAGD by introducing hydrocarbon solvent additives to the injected steam, is the subject matter of this paper and is called the " Solvent Aided Process" (SAP). With the combined potential benefits come the combined challenges of the two processes. Although substantial understanding has been developed around SAGD in recent years, a number of unknowns associated with solvent processes exist. This paper, drawing heavily from the authors' extensive investigation of SAP, dwells on the estimated benefits of SAP over SAGD, discussing possible mechanisms at work, optimal design of injectant (involving lighter alkane additives), and operational aspects and issues such as solvent retention, etc. Introduction The concept of adding solvents to the injected steam for improving the performance of steam-based recovery processes is not new. Various authors(1–8) have described and analyzed the benefits of adding hydrocarbon solvents to primarily steam flood processes. Their work mainly focused on the oil-recovery enhancements that solvent addition brings to steam-flood(1–3, 5–8) or steam stimulation(4). With the advent of SAGD(9, 10), exploitation of the vast heavy oil and bitumen resources of the Western Canadian Sedimentary Basin is now feasible. However, owing to a highly energy-intensive process and the nature of the target product (heavy oil), the economics of SAGD is very susceptible to fuel prices and heavy oil market forces. Use of solvents in place of steam in gravity drainage for heavy oil recovery(11–14) promises to be a more energy-efficient process but suffers from poor (estimated) rates of recovery(12,13). This is because molecular diffusion, the mechanism responsible for the dilution of heavy oil which reduces its viscosity in a solvent-alone process, is much slower than its counterpart, thermal diffusion, in the case of SAGD. Among other things, modification of the drainage geometry(15) has been suggested for providing a large contact area to compensate for a low rate of diffusion and to raise the rates of production. Given earlier efforts(1–8) to improve the steam-flood process with the use of solvents, the combination of solvents and steam in conjunction with the concept of gravity drainage seems to be a natural progression from SAGD and VAPEX. A few investigators, ncluding Butler and Yee(16) and Palmgren and Edmunds(17), have suggested the combination of thermal effects and solvent dilution. Viscosity reduction, as pointed out by Butler et al.(11), has a direct impact on the rate of production from a gravity drainage process.

The authors have previously described a Solvent Aided Process (SAP) that aims to combine the benefits of SAGD and VAPEX. In SAP, a small amount of hydrocarbon solvent is introduced as an additive to the injected steam during SAGD. While steam is intended to be the main heat-carrying agent, the solvent will dilute the oil to reduce its viscosity over and above what is accomplished by heating alone. The overall effect should be an improved oil to steam ratio (or reduced energy intensity). Although promising based on the authors' calculations, the process has not been previously applied or tested on a field scale. This paper describes the implementation of a SAP pilot at Encana's Senlac Thermal Facility. In addition to dwelling on some of the important parameters of a SAP test, it discusses the design considerations for the field pilot and the necessary modifications to an existing SAGD plant, specifically in the area of boiler operations controls. Although the design calls for an assessment of reservoir performance results on a longer-term basis, initial results from this pilot look very encouraging. The oil rates have shown a substantial increase, and the steam-oil ratio has shown a corresponding decrease. This paper also discusses directional economics with SAP and its beneficial impact on the environment. Introduction Just as steam tackles the viscosity reduction of in situ oil in SAGD(1,2) by heating it, solvents(3–7) do this by diluting the oil. Although employment of both steam and solvent together has been discussed in the literature(8–15), these discussions have mostly focused on enhancement of steam-flood or steam-stimulation. In their discussion on the subject, Gupta et al.(16) described SAP as a process enhancement to SAGD where a small amount of a light alkane solvent, namely propane, butane, pentane, etc., or a mixture thereof, is added to the injected steam. They also suggested, with the help of lab experiments and numerical modelling, that SAP has the potential to substantially improve the performance of SAGD. Expected SAP Advantages Figure 1 shows a comparison of an expected numerically obtained oil rate profile from a SAGD application vs. one obtained similarly with the application of SAP in the same reservoir. It is assumed that SAP would start after the expiry of a certain initial period in the life cycle of SAGD to allow for the initial development of the chamber with steam. The units from the rate and time axes are omitted to emphasize the general nature of these profiles. The comparison of the rate profiles is provided in order to suggest that the bulk of the oil that would have been produced in the later period with SAGD can be produced sooner with SAP. The acceleration of production and the corresponding cash flow could lead to improved economics for the project. Apart from the improved economics as a consequence of production rate acceleration, the other expected advantages of SAP include reduced environmental impact, possible down-hole upgrading of the heavy oil, and a small increase in the ultimate recovery.

Summary This paper presents a case history of the Phase A steam-assisted gravity-drainage (SAGD) test conducted by the Alberta Oil Sands Technology & Research Authority (AOSTRA) at its underground test facility (UTF). Reservoir description, the recovery process, design of wells and other critical hardware, production operations history, and performance analysis are discussed. Phase A demonstrated a commercially viable combination of recovery, production rate, and steam/oil ratio (SOR). Completions design and production engineering progressed significantly. Phase B scaleup considerations and commercial economic projections also are discussed. Introduction The Athabasca oil sands of northern Alberta, Canada, are sometimes referred to as the greatest single accumulation of petroleum in the world. These sands are estimated to contain ˜ 1050 kg/m3 of bitumen. About 90% of this resource is buried too deeply to be recovered by mining and will require in-situ recovery methods. A number of pilot projects testing a wide array of potential technologies have been carried out over the past 60 years, but few have met with much technical success and none has been expanded to commercial production to date. The UTF. The AOSTRA UTF is 40 km northwest of Fort McMurray, Alta. The facility was constructed during 1985–87 and consists of two l85-m vertical shafts and > 1 km of underground tunnels driven into Devonian limestone that immediately underlies the McMurray formation. The 5-m-wide by 4-m-high tunnels are ˜ 15 m below the reservoir. Wells are drilled upward from the tunnels, starting at 15 to 20° angles above horizontal, then dropping to horizontal in the oil sand. Steam generation and production-handling facilities are on the surface. Production testing of individual wells was carried out underground by means of a Coriolis mass flowmeter and careful wellhead sampling. Ref. 1 gives a more complete review of the UTF history and physical plant.1 SAGD. The first process selected for testing at the UTF was SAGD. SAGD is a combined conduction/convection mechanism that is more like ablation (i.e., propagation of a melt front into a solid material) than displacement, which is the usual petroleum engineering paradigm for thermal recovery. Fig. 1 shows that conduction heats a thin layer of oil sand adjacent to the steam "chamber," mobilizing the bitumen. The density difference between the steam and bitumen causes the bitumen to drain to the bottom of the chamber along with the steam condensate that is formed as a result of the heat conduction ahead of the front. The steam gains access to new formation as the bitumen drains, causing the front to advance upward and outward. This continues as long as more steam and oil sand are available and as long as the draining bitumen and condensate are removed from the bottom of the chamber. The rate of drainage is controlled by permeability. Liquids within the steam chamber drain very rapidly relative to the speed of frontal advance so that chamber gas saturations are high and the water and oil saturations are close to residual values. Cumulative oil production is nearly proportional to the steam-chamber volume. Refs. 2 through 4 provide a more complete discussion of SAGD mechanisms. The Phase A Test. Regardless of well control and petrophysical data available, the extreme heterogeneity of the McMurray pay makes a priori forecasting of SAGD performance problematic because interbedded sand lenses can form tortuous but continuous paths that are not discernible from delineation wells. The main objective of the Phase A test was to resolve this uncertainty by direct measurement of the SAGD rate in a minimal volume of reservoir. Phase A consisted of three pairs of horizontal wells (Fig. 2). Each well pair had a producer completed low in the pay zone and an injector parallel to and ˜5 m above the producer. The well pairs were nominally spaced 25 m apart, and the effective length of the completions was 55 m. The pattern also contained 26 temperature, pressure, and geotechnical observation wells drilled vertically from surface. Pilot Geology. Ref. 5 describes the geology of the Phase A site. Fig. 3 is a cross section through the middle of the pilot, and Table 1 lists some key petrophysical parameters for the UTF site that are typical of the McMurray formation throughout the Athabasca region. Units E and G, comprising most of the bottom half of the pay, were high-quality, essentially continuous sand bodies that were highly saturated with bitumen. The top half of the pay, Unit D, was interbedded and bioturbated sand, silt, and claystones. The sand lenses were all well-saturated. Unit F consisted of muds and silts that were interbedded with sand lenses and heavily bioturbated. This unit separated the injectors and producers for two of the well pairs, Pairs Al and A3. The other pair, Pair A2, was deliberately drilled so that both wells were above this partial barrier. At the cold initial reservoir temperature (7°C), bitumen is extremely viscous and connate water is immobile. Mobility in the reservoir is so low that superficial oil-phase velocities can be measured in feet per year, even under huge pressure gradients. This precludes direct convective heating as in a classic steamflood displacement. Completions. Completions design6 was considered critical to the success of the Phase A test. Massive sand influx into the wellbore had been encountered by previous operators in the region and was considered the most likely cause of possible test failure. In addition, the liners had to be large enough to prevent large pressure gradients, especially in the injection well, because excessive pressure gradients in the wells also appear in the steam chamber and interfere with gravity stabilization of drainage over the length of a well pair.7 All wells were completed with l4-cm liners, made up of alternating sections of blank casing and sand control screens, run into open hole (Fig. 4). Conventional wire-wrapped screens were used in two well pairs, and a steel-wool-filter design was used in the third pair. Tubing strings were landed near the end of each liner to provide circulation of hot fluids throughout the length of each well. p. 119–124

The steam-assisted gravity-drainage (SAGD) process is used widely to recover heavy oil and bitumen from formations in which no other recovery method has proved to be economical. It is an energy-intensive process, and because of economic and environmental reasons, solvents as additives to the injected steam are being explored currently to reduce the energy and emissions intensity of SAGD. The solvent-aided process (SAP), tested in the field and described in the literature, is one such attempt.In the SAP, a small amount of hydrocarbon solvent is introduced as an additive to the injected steam. Thus, the viscosity of the oil is also reduced because of solvent dilution in addition to heating. The SAP can improve the energy efficiency of SAGD significantly, thus reducing the heat requirement, as shown in field trials discussed elsewhere. However, on the use of the right amount of solvent that can result in best overall performance, there is very little discussion in the literature. Because of the high cost of such solvents, there is incentive to optimize their use in SAGD. Recently, various authors have attempted to address the subject with, for example, arbitrary time-dependent schemes of solvent injections, assessing their impact on results or by treating the internal reservoir dynamics as a black box and using optimization methods, such as genetic algorithms (GAs), to estimate the optimal amount of solvent. While these approaches orient us to the problem in a context-specific manner, it is believed a generalized treatment to estimate optimal use of solvent requires a mechanism-based understanding.The approach presented in this paper is aimed at estimating the optimal solvent in the context of SAGD. It combines the existing Butler's oil-drainage analytical models (Butler 1985(Butler , 1988(Butler , 1994 for SAGD and vapor extraction (VAPEX), which deal with heating effect and solvent-dilution effect one at a time, into one. Then, it calculates the time-dependent steam rates to maintain the predicted oil rates in conjuction with solvent rates and, thus, estimates the solvent/steam ratio (SSR) and the steam/oil ratio (SOR). The results are discussed for a few light-alkane solvents. In the process of this exercise, it is discovered that to obtain reasonable SSR and SOR, a significant amount of oil has to drain from a diffuse layer, which has a varying temperature, solvent concentration, and gas saturation (from maximaum gas saturation at the injection end to zero at the vapor/liquid interface). Gravity Drainage of Oil Under the Influence of Both Heating and Solvent DilutionThe following mathematical framework is developed with the aim of tabulating SORs and oil rates for a given reservoir, a given