Expanding solvent steam assisted gravity drainage (ES-SAGD) is a hybrid steam−solvent oil recovery process that can be used to extract oil from heavy oil and bitumen reservoirs. It is a variation of the SAGD process in which only steam is used. In ES-SAGD, the mobilization of highly viscous oil is enhanced through a combination of heat and mass transfer processes, which results in significantly reduced volumes of water and natural gas needed to generate the injected steam, making ES-SAGD more energy efficient and environmentally sustainable relative to SAGD. Both SAGD and ES-SAGD use the same well configuration, and solvent co-injection in existing SAGD projects often requires limited facility modifications. This study investigates different aspects of ES-SAGD experimentally, based on typical Long Lake reservoir properties and operating conditions, using different concentrations of gas condensate. Furthermore, this study provides phase behavior insights to govern the selection of appropriate solvents for use in ES-SAGD. The performance of the gas condensate ES-SAGD cases in this study exceeded that of the baseline SAGD case in terms of oil production rates, energy efficiency, and postproduction water handling. These findings were instrumental in the design and implementation of a field pilot project by Nexen Energy ULC in the Athabasca Oil Sands that began in September 2014.

While polymer flooding has widely been used as a successful technology to improve mobility control and sweep efficiency in many oil reservoirs, its applicability under harsh temperature/salinity conditions and in low-permeability reservoirs has prohibitively remained a challenge. This study was aimed at investigating the feasibility of low-salinity polymer flooding in a very challenging reservoir located in Kuwait with low permeability (< 10 mD), high temperature (113°C), high salinity (~239,000 ppm), high hardness (~20,000 ppm), and carbonate mineralogy. The evaluation was conducted through a series of systematic laboratory studies including polymer rheology, thermal stability, and transportability using coreflood tests. Our results highlight that the common constraints may be overcome by careful selection of polymer/cosolvent/pre-shearing and appropriate design of low-salinity polymer flooding.

With a resurgence of chemical EOR opportunities throughout the world, high concentration surfactant design has re-emerged its uneconomic face. High concentration surfactant formulation is the micellar polymer design from the past that produced high oil recoveries in the lab but were uneconomic in the field. Formulation designs must consider factors beyond simply oil recovery for economic success and to minimize production issues in the field. Analysis and comparison of micellar polymer design projects from the 1970-1980s to current SP/ASP formulation designs are discussed. A simple formulation cost calculator is showcased, costs of all formulations are presented, and price per incremental barrel produced (chemical cost only) are shown assuming a 0.1 PV of incremental recovery. Analysis concludes the following: Micellar polymer floods were phased out because they were uneconomic. Key reasons are high cost of surfactant and emulsion problems faced when produced surfactant concentration exceed a certain threshold resulting in either greater production cost or disposal of produced oil in the form an unbreakable emulsion. Alkali can improve economics as a low-cost commodity product that can be used to reduce surfactant concentration required to attain high oil recoveries. Alkali is an order of magnitude lower cost per pound than the typical surfactant and can be used as an enhancing agent to improve the performance of other injected chemicals. Alkali is not a "silver bullet" that will save economics, and adds challenges and cost for water softening, which can be economically detrimental to field projects. Many high concentration surfactant formulation floods are being re-introduced to the industry. Not only are these designs un-economic but include multiple chemicals that add complexity and cost to the facilities and difficulty for facility personnel. A formulation that requires more than $20 of chemical per barrel of incremental oil is unlikely to be economic with $50/bbl oil. Key differences between laboratory results and field implementation results are discussed. Geologic uncertainty is addressed since it is the greatest challenge to field economic success. The industry is taking steps back to an uneconomic time of chemical EOR by obscuring the difference between designs meant to increase reserves (economic oil) versus those that serve an academic or research purpose. Operators are unwittingly paying the price to advance the science of chemical EOR when service companies provide formulations that are not economic. This paper is meant to remind the industry that high concentration surfactant formulations never were economic and certainly will not be economic in today's price environment.

This study investigates, by means of numerical modelling, the impacts of naturally occurring, as well as continuously coinjected and intermittently coinjected noncondensable gas (NCG), at different stages of the steam-assisted gravity-drainage (SAGD) process. The CMG Builder software was used to construct a homogeneous 2D baseline model based on generic Athabasca-type reservoir properties and well configuration. A fluid-component model was generated using the CMG WinProp package for modelling the phase behaviour and properties of reservoir fluids. This fluid-component model was modified to incorporate manually calculated K-values for the gas-water and the gas-bitumen phase equilibria. The modified fluid model was then incorporated into the baseline model and the CMG STARS thermal reservoir simulator.The simulation results of this study show that methane coinjection along with steam is generally not beneficial. Although it can reduce the heat loss to the overburden to some extent, the reduction in oil-drainage rate and total oil recovery negates the benefits of such heat-loss reduction. The poor performance of NCG addition to SAGD results from the tendency for the NCG to remain in the vicinity of the steam chamber and reduce heat transfer into the cold bitumen at the edges of the steam chamber, thereby impeding steam-chamber growth. Accurate modelling of NCG addition to steam in SAGD is highly dependent on the availability of appropriate gas-solubility data. NCG with steam may perform better compared with steam-only injection in SAGD if methane coinjection were investigated using a heterogeneous model in which SAGD is affected adversely by the presence of reservoir heterogeneities in the form of shale barriers, inclined heterolithic strata (IHS), and steam-thief zones. Reservoir-Simulation ModelModel Dimensions and Constraints. The baseline model was constructed using the CMG Builder software. It has physical di-

Summary Gases such as carbon dioxide, nitrogen, and methane that can be present in a steam-assisted gravity-drainage (SAGD) steam chamber (but do not condense into the liquid phase to any large degree at reservoir conditions) are referred to as noncondensable gases (NCGs). The coinjection of NCGs with steam during SAGD results in changes in production rate, total oil production, and the amount of steam required to mobilize the bitumen in place. To investigate the impact of NCGs on SAGD performance by means of numerical simulation, it is important to model gas solubility in both bitumen and water accurately. Also, the dependence of relative permeability on temperature needs to be accounted for to achieve reliable results. This study presents a systematic approach to predict the K-values for the gas/bitumen- and gas/water-phase equilibria over a wide range of pressures and temperatures.