Sequestration of CO 2 into oil and gas reservoirs gains respect as an economically and environmentally convenient way of reducing emissions of greenhouse gas and increasing hydrocarbon production at the same time. Because the naturally fractured reservoirs (NFRs) constitute a great portion of current and potential CO 2 injection applications, it is essential to understand the matrix-fracture interaction during such applications to maximize the efficiency of the process, maximizing incremental oil production with maximum CO 2 storage. Visualization of the phase behavior and flow patterns to/from the fracture and from/to the matrix is critical in understating the process and discovering ways to co-optimize the oil production-greenhouse gas storage process. Hence, pore-scale behavior of the CO 2 -oil interaction was investigated experimentally using homo-and heterogeneous fractured micromodels. Glass-etched microfluidic models were employed to investigate the pore-scale interaction between the matrix and fracture. Models were prepared by etching homo-and heterogeneous microscale pore patterns with a fracture in the middle of the model on glass sheets bonded together and then saturated with colored n-decane as the oleic phase. CO 2 was injected at miscible and immiscible conditions. The focus of the study was on visual porescale analysis of miscibility, breakthrough of CO 2 , and oil/CO 2 transfer between the matrix and fracture under different miscibility conditions. More specifically, the CO 2 -oil interaction near the fracture region inside the matrix was visualized, and its impacts on the further transport of CO 2 inside the matrix by diffusion, transfer of oil from the matrix to the fracture and its flow in the fracture, and CO 2 storage inside the matrix during these processes were analyzed visually.

The Bakken is an extremely tight formation, with the oil contained mostly in siltstone and sandstone reservoirs with low porosity and permeability. In Saskatchewan alone, there could be an estimated 25 to 100 billion barrels of Bakken oil in place. At present, the combination of horizontal well drilling and the new multi-stage fracturing and completion technologies has been the key to economically unlocking the vast reserves of the Bakken formation. The primary recovery factor, however, remains rather low due to high capillary trapping. While waterflooding could result in unfavorable injectivity issues, carbon dioxide (CO 2 ) miscible flooding provides a promising option for increasing the recovery factor. Higher oil recovery factor can be achieved with CO 2 injection through multi-contact miscibility that results in vanishing interfacial tension, viscosity reduction, and oil swelling. This paper conducted a numerical simulation work as an effective and economical means of evaluating CO 2 flooding potential for enhanced oil recovery. Different strategies were tested to compare the effects on oil recovery of injection well pattern, continuous and cyclic injection, waterflooding and CO 2 flooding, injected gas composition, and heterogeneity. The simulation results show that CO 2 flooding presents a technically promising method for recovering the vast Bakken oil.

Summary CO2 injection has been applied in naturally fractured reservoirs (NFRs) for the purpose of enhanced oil recovery (i.e., the Wey-burn and Midale fields, Canada; the Wasson and Slaughter fields, USA; and the Bati Raman field, Turkey). The matrix part of these types of reservoirs could potentially be a good storage medium as well. Understanding the matrix/fracture interaction during this process and the dynamics of the flow in this dual-porosity system requires visual analyses. We mimicked fully miscible CO2 injection in NFRs using 2D models with a single fracture and oil (solute)/hydrocarbon solvent pairs. The focus was on the visual pore-scale analysis of miscibility interaction, breakthrough of solvent through fracture, transfer between matrix and fracture, and the dynamics of miscible displacement inside the matrix. First, matrix/fracture interaction was studied intensively using 2D glass-bead models experimentally. The model was prepared using acrylic sheets and glass beads saturated with oil as a porous medium while a narrow gap of 1-mm size containing filter paper served as a fracture. The first contact miscible solvent (pentane) was injected into the fracture, and the flow distribution was monitored using an image-acquisition and -processing system. The produced solvent and solute were continuously analyzed for compositional study. The effects of several parameters, such as flow rate, viscosity ratio (oil/solvent), and gravity, were studied. Next, the process was modeled numerically using a commercial compositional simulator, and the saturation distribution in the matrix was matched to experimental data. The key parameters in the matching process were the effective diffusion coefficients and the longitudinal and the transverse dispersivities. The diffusion coefficients were specified for each fluid, and dispersivities were assigned into gridblocks separately for the fracture and the matrix.

Summary Bitumen extraction in oil sands-ore water slurry systems was studied by using lipids and lipid derivatives such as biodiesel (BD) as surfactant additive to promote bitumen recovery efficiency. Performance of BDs (i.e., canola and tall oil, a by-product of pulp mills using the bleached Kraft process) fatty acids methyl ester and food-grade fatty acids monoglycerides were evaluated as surfactant additives. Experimental findings suggest that BDs such as fatty acids methyl esters could also be used as surfactant additives to increase the efficiency of bitumen recovery in thermal in-situ processes such as steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) processes. The required dosage for the surfactant additive is about 0.1% of bitumen by mass. Also, interfacial tension measurements between bitumen and process water (YB,W) and BD and process water (YBD,W) support the surfactant behavior of BD.