Over the past 50 years, in-situ recovery methods for oil sands reservoirs have evolved and the patent literature is rich with different well designs, operating conditions, and recovery mechanisms. Here, the patent and literature has been analyzed to understand those features of in-situ recovery technologies that persisted through time. Over 250 hundred patents covering different well designs and injectants have been examined. A simple example of a persistent technology is the horizontal well: Steam-Assisted Gravity Drainage (SAGD) is enabled by horizontal well technology; the vertical equivalent of SAGD is not feasible as an economic recovery process. Cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) are now over two decades old since invention and at this point there are few new technologies on the table which are being researched or evaluated. Most new technologies, for example, thermal-solvent, electrical heating with solvents, and toe-toheel combustion are incremental adds on existing technology ideas proposed in the patent literature years to decades ago. Here, an analysis has been done to understand the evolution of in-situ oil sands recovery technology and what features have enabled economic recovery oil sands resources. The results reveal that a small number of features arising from the oil sands recovery process ideas dreamed, proposed, and developed over the past 50 years account for the success of current commercial oil sands recovery methods.

Expanding Solvent-Steam Assisted Gravity Drainage (ES-SAGD) was invented to enhance SAGD performance by reducing energy use while increasing oil production rates and recovery factor. ES-SAGD involves co-injection of solvent and steam. The majority of energy losses occur between the steam generator and sandface and at the top of the depletion chamber (to the overburden). ES-SAGD performance improvement is traditionally ascribed to oil phase dilution which in turn leads to oil phase viscosity reduction. However, the amounts of solvent added to the process are typically very small (< 5-6% by volume) thus it remains unclear how the solvent can lead to significant lowering of the steam-to-oil ratio (~25-50%) and large enhancements of the oil rate (~25 to 100%). Here, we report on how SAGD and ES-SAGD (hexane, heptane and octane solvents) can potentially perform in the presence of in-situ emulsification at steam chamber edge. We present a numerical approach which allows incorporation of emulsion modeling into SAGD and ES-SAGD simulations with commercial reservoir simulators via a two-stage pseudo chemical reaction. Numerical simulation results show excellent agreement with experimental data for low-pressure SAGD and ES-SAGD. Accounting for viscosity alteration, multiphase effect and enthalpy of emulsification appear sufficient for effective representation of in-situ emulsion physics during SAGD and ES-SAGD in very high permeability systems. Results also show that, in-situ emulsification may play a vital role within the reservoir during SAGD; increasing bitumen mobility thereby decreasing cSOR. It was concluded that traditional approach to numerical ES-SAGD simulation can significantly over-predict incremental oil recovery. Results from this work extend understanding of ES-SAGD by examining its performance improvement over traditional SAGD in terms of multiphase behavior at the edge of the chamber, thermal efficiency and incremental recovery. Results reveal that dynamics at the edge of the chamber is more complex than simple solvent dilution model.

The creation and evolution of point bar systems is well understood in meandering river deposits. A large fraction of Athabasca oil sands deposits are ancient point bar systems characterized by bedded, sandstone-dominated strata with interbedded siltstone layers. The recovery process of choice for these deposits is the Steam-Assisted Gravity Drainage (SAGD) process due to the high viscosity of the oil, low solution-gas ratio, and often caps rock not sufficient to with stand injection pressures of Cyclic Steam Stimulation. However, because of the presence of siltstone interbeds, these reservoirs commonly have lateral and vertical lithological heterogeneity which interfere with the formation of uniform steam chambers along SAGD wellpairs. Other units in point bar deposits that impact SAGD chamber development within the formation include remnant channel succession and channel lag. The objective of this research is to construct a detailed threedimensional point bar model to determine how its heterogeneity impacts SAGD performance. Here, the point bar model is based on the Lower Cretaceous Middle McMurray Formation in the Athabasca oil sands deposit in Alberta, Canada. Single SAGD wellpair submodels at different locations and orientations were extracted from the point bar model. The results of the reservoir models simulation suggest that attention must be paid to SAGD wellpair placement in point bar systems.

With the decline of conventional oil production, developing and producing heavy oil resources efficiently is becoming more important. The Liaohe Heavy Oil Field steam operation is unique – it started with cyclic steam stimulation (CSS) operation that transitioned into a continuous steam-assisted gravity drainage (SAGD) operation. With respect to oil production in China, this field is considered critical for heavy oil production and technology development. Cyclic steam injection was initially done through vertical wells. This had the benefit that it provided a good start-up of depletion chambers in the reservoir. These chambers then grew under gravity drainage after continuous steam injection (through the vertical wells) and continuous production through a set of horizontal wells was started. Controlled and deliberate transition from CSS to a gravity drainage process with the objective of optimizing energy intensity (GJ injected per unit volume oil produced) with control enabled through production and thermocouple data is a smart field operation which we refer to as a Reservoir Production Machine (RPM). In this paper, as a first step to understand the operation and its impact on the reservoir, we have history matched the CSS operation based on the injection and production data from field. The use of vertical steam injection wells (formerly the CSS wells) in combination with horizontal production wells operated in a SAGD mode of operation is explored. The history-matched model can be used to develop automated RPM technologies to optimize not only energy intensity but also emissions intensity.

In SAGD, steam is injected into a bitumen bearing oil sands formation. Steam temperature ranges from about 200 to 260°C and at these temperatures, bitumen undergoes aquathermolysis yielding acid gases such as hydrogen sulphide and carbon dioxide. SAGD simulation models in the literature often account for spatial heterogeneity of the geology and oil composition and heat transfer, multiphase flow, gas solubility effects, and viscosity variations with temperature, however, none account for the chemistry of SAGD. Here, we consider aquathermolysis reactions to understand the reactive zones in the SAGD process and how the process generates acid gases via aquathermolysis. The results show that SAGD is both a physical and chemical-reactive process.