The steam assisted gravity drainage (SAGD) process has been successfully tested in field pilots, and commercial applications are currently underway by a number of oil companies. The process yields higher oil rates and faster reservoir depletion, as compared to other in situ oil recovery processes. Current developments of the SAGD process are aimed at improving oil rates, improving oil-to-steam ratios "OSR," reducing energy, and minimizing water disposal requirements. In addition to SAGD, progress has been made in the development of solvent injection processes. These processes result in lower oil rates and energy, requirements as compared to SAGD. At the present time, limited field results are available for the solvent processes to allow for adequate evaluation of field performance. A novel approach for combining the benefits of steam and solvents in the recovery of heavy oil and bitumen has been undertaken at the Alberta Research Council (ARC). A newly patented Expanding Solvent-SAGD "ES-SAGD" process has been developed. The process has been successfully field-tested and resulted in improved oil rates, improved OSR, and lower energy and water requirements as compared to SAGD. The paper discusses the concept and laboratory testing of the ES-SAGD process. Introduction The most promising in situ thermal recovery technology is the SAGD process. In this process, two horizontal wells separated by a vertical distance are placed near the bottom of the formation. The top horizontal well is used to inject steam and the bottom well is used to collect the produced liquids (formation water, condensate, and oil). Following the success of the UTF project at Fort McMurray, Alberta, a number of field pilots are in progress in other heavy oil reservoirs in western Canada (Alberta and Saskatchewan), and around the world. These pilots tested the use of surface accessed horizontal wells and extended SAGD applications to problem reservoirs. These reservoirs often have lower permeabilities, are deeper, have bottom water transition zones, with initial gas-saturated "live" oil and top water/gas caps. In Alberta, the success of these pilots has led to a number of commercial SAGD projects that are currently underway. Current developments of the SAGD process at ARC are aimed at improving oil rates, improving OSR, reducing energy, and minimizing water disposal requirements. Progress has been made in the development of combined steam-solvent injection processes, a novel approach for combining the benefits of steam and solvents in the recovery of heavy oil and bitumen. A newly patented(1) Expanding Solvent-SAGD "ES-SAGD" process has been successfully field-tested, and has resulted in improved oil rates and OSR, and lower energy and water requirements as compared to conventional SAGD. The ES-SAGD concept and laboratory testing using the high pressure/high temperature experimental facilities at ARC are presented in this paper. The ES-SAGD Concept Figure 1 illustrates the ES-SAGD concept. In this concept, a hydrocarbon additive at low concentration is co-injected with steam in a gravity-dominated process, similar to the SAGD process. The hydrocarbon additive is selected in such a way that it would evaporate and condense at the same conditions as the water phase.

The uniqueness of the steam assisted gravity drainage (SAGD) recovery process lies in the salient role of moving condensing boundaries and counter-current flows. Process effectiveness depends on the balance between rising steam and draining oil-condensate emulsions. Reservoir permeability, well completion and effective drainage-pumping of oil-condensate emulsions can affect such balance. A new, non-steady state, laboratory steam-front dynamic tracking technique was used in measuring steam-liquid counter-current and co-current flows for different permeabilities and initial gas saturations. Steam chamber ceiling propagation rates (process initialization and growth) were determined for different injection and reservoir conditions. The paper highlights critical factors that control steam-oil emulsion counter-current flow and rate of propagation of the steam chamber. In addition, the CMG STARS numerical model was used to simulate SAGD counter-current flows and determine sensitivities to different parameters. Introduction The concept of the SAGD process was developed by Butler et.al.(1) In this concept, two horizontal wells are placed near the bottom of the reservoir and separated by a distance. Figure 1a illustrates the application of the SAGD process in very viscous oil (bitumen) reservoir. The top horizontal well (an injector) is located at a distance of about 5 m above the bottom well (the producer). The process consists of two distinctive phases. An initialization phase, where in most cases, conduction heating in the space between the two wells is chosen for initialization of gravity. FIGURE 1a: Illustration of the initialization and growth phases of the SAGD process in paired horizontal wells (Available in full paper) During this phase, steam is circulated in the tubing and out of the annulus. Initial breakthrough between the wells will generally occur in a localized region. Proper initialization procedures are required to bring the entire length of a well pair into active drainage. In general, the initialization phase is slow and oil rates during this phase are low. Nasr et. al.(2) reported results on two strategies for accelerating the initialization phase of the SAGD process: first, by using inter-well channels, and second, the injection of a hydrocarbon additive (naphtha) with steam. Following the initialization phase, after the oil in the inter-well region becomes mobile enough; the second phase (the growth phase) of the process can be started. During this phase, steam is injected into the top horizontal well and production fluids are obtained from the bottom well. Pressure drop along the horizontal well bore causes a slope in the steam chamber along the well as illustrated in Figure 1a. Improvement of the process during this phase requires improving the growth rate of the steam chamber and as a result improving oil drainage rates. Figure 1b shows a cross-section perpendicular to the well bores shown in Figure 1a and illustrating fluids flow in the steam chamber. Two types of flow exist. One at the ceiling of the steam chamber (ceiling drainage) and the other along the slopes of the steam chamber (slope drainage). Along the slopes of the chamber, mobilized oil accumulates in a progressively thicker layer. However, at the ceiling, oil moves away from the front immediately after mobilization.

A new heavy oil recovery process, Steam Alternating Solvent (SAS) process, is studied by lab experiments and corresponding numerical simulation. The SAS process involves injecting steam and solvent alternately, using well configurations similar to those in the SAGD process. This process is designed to combine the advantages of the SAGD and Vapex processes to minimize the energy input per unit oil recovered.Lab experiments were conducted using a 2-D highpressure/high-temperature model. One baseline SAGD test and one SAS test were performed using oil sample from Cold Lake region. Mixture of propane and methane was used as the solvent in the SAS test. The results showed that the energy input in the SAS process was 47% lower than that of the SAGD process, for recovering the same amount of oil. The post-run analysis revealed that asphaltene precipitation occurred in the porous medium. Numerical history matching of the test data using CMG's STARS reservoir simulator captured the main features of the process. PETROLEUM SOCIETY

The successful testing of a gravity drainage process, using the horizontal wells in the Underground Test Facility (UTF) in Alberta, Canada indicates that high recovery and economical oil-steam ratios are achievable. However, several major technical challenges must be resolved to extend this successful pilot experience to commercial operations and to the many different heavy oil and extra-heavy oil reservoirs. This paper provides a consistent package of experimental data on the development of gravity drainage using horizontal wellbores exposed to a variety of injection-production strategies. Critical parameters that control process performance such as initialization time, completion, reservoir permeability and initial oil mobility are highlighted. A 60×21×3 m section of a homogeneous field was scaled using Pujol and Boberg's criteria to a 2-D visualization cell (60×21×3 cm). One minute of experimental time represents 7 days of field time. The used scaling criteria offered adequate scaling of gravitational forces, fluid properties were preserved in the lab and the same initial conditions in the field and lab. Results demonstrate improvement of process performance by using different and novel injection strategies. Introduction A theory for the application of steam assisted gravity drainage (SAGD) in the recovery of extra heavy oil was developed by Butler and McNab and Butler and Stephen. In the original theory the major assumptions were that steam chamber starts over the entire vertical height of the reservoir and along the length of the horizontal well. Butler later introduced modifications to the theory using a TANDRAIN assumption where a tangent was drawn from the production point to the steam chamber interface. In addition, the modification took into account the rise of the steam chamber. The theory provides a useful tool for rapid, and approximate, assessment of oil drainage from homogeneous reservoirs. However, to describe the entire process (both initialization and drainage) and address the non-uniform distribution of steam along the well-bore as well as reservoir heterogeneities, other methods need to be developed. Field Application of The Gravity Drainage. The UTF phase A project, Edmunds, was the first field demonstration of the SAGD process. Three horizontal well pairs were used (in each pair, an injector was located 5 m above the producer). Conduction heating in the space between the two wells was chosen as the method for initialization of gravity. Steam was circulated in the tubing and out of the annulus. In the observation wells located just above the injection well, the temperature decreased along the length of the well and suggested that the far end of the well was probably not very hot. Initial breakthrough between the wells will generally occur in a localized region. Proper initialization procedures are required to bring the entire length of a well pair into active drainage. In addition, optimization of production control is essential for successful application of the process. Too much drawdown between the wells will produce large quantities of steam. For a small drawdown, liquid will continue to build-up between the wells. This will result in the injector being "drowned" and the height of the chamber decreased (impede drainage). The drowning mechanism is poorly understood at this stage. Heterogeneous Reservoirs. Joshi reported results on using SAGD with vertical and horizontal injectors. He found that vertical injectors with a horizontal producer gave faster recovery than using a horizontal injector/horizontal producer in reservoirs with shale barriers. He also indicated that vertical fractures perpendicular to a horizontal injector improved oil recovery rate as compared to a horizontal injector/horizontal producer. Yang and Butler studied two types of reservoir heterogeneities. First, reservoirs containing thin shale layers and secondly, reservoirs containing layers of different permeabilities (two layers reservoir). They found that a short horizontal barrier did not greatly affect the general performance of the SAGD process. P. 77^

As SAGD moves from pilot test to commercial operation, a number of issues need to be dealt with. These include diagnosing and solving operational problems and improving energy efficiency. One of the methods of improving energy efficiency is to prolong oil production after steam injection stops by using the energy remaining in place. The results of a laboratory experiment and corresponding numerical history matching are reported in this paper. The study showed that the hot chamber continued its expansion after steam injection was stopped and a gas injection was initiated. The continuous expanding period represented the most productive period in the gas injection wind-down process. A total of 12.5% of OOIP was recovered during wind-down. Successful history matching of both the oil production curve and temperature profiles at different times demonstrated that the numerical simulation could handle the gas/steam mixing phenomena. Gas concentration profiles from numerical simulation indicated that gas was concentrated at the region where oil saturation was experiencing big changes. Introduction The successful tests of the SAGD process at UTF(1, 2) and other pilot projects(3, 4) have established SAGD as a viable technology for in situ recovery of the huge heavy oil and bitumen resources in western Canada. A number of commercial SAGD projects in western Canada are in the operation, construction, or planning stages(5). However, the SAGD technology is still in a transition from pilot to commercial operation. Development of the technology is currently focusing on two areas. The first is to diagnose and solve operational problems. In field operations, many projects have encountered difficulties, such as lower than expected oil production rate, higher than expected steam-oil ratio (SOR), or premature production rate decline. In each case, the cause of the problem needs to be identified in order to develop methods to deal with the problem and avoid the problem in the future. The second area of SAGD development is to improve energy efficiency as the costs of fuel and associated water treatment account for a large portion of the oil production cost. These developments include hybrid processes using co-injection of steam and solvent(6 – 10), or steam and non-condensable gas(11). The hybrid processes take advantage of both heating by steam and dilution by solvent. The injection of non-condensable gas is intended to reduce heat loss to the overburden, and therefore, improve SOR. With this idea in mind, efforts have been directed to developing SAGD wind-down methods. At a certain stage of the SAGD operation, as instantaneous SOR increases, there is no economic benefit to continue pure steam injection. At this stage, a wind-down process can be started to utilize energy in place and continue oil production. A numerical simulation and economic evaluation study(12) showed that a co-injection of steam and non-condensable gas gave the best result. Recently, the results of co-injection of steam with flue gas into UTF Phase B as a wind-down process was reported(13). The key to achieve the best economics for a SAGD wind-down process is optimization.