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Exploring unconventional hydrocarbon reservoirs and enhancing the recovery of hydrocarbon from conventional reservoirs are necessary for meeting the society's ever-increasing energy demand and requires a thorough understanding of the multiphase interfacial and transport phenomena in these reservoirs. This dissertation performs pore-scale studies of interfacial thermodynamics and multiphase hydrodynamics in shale reservoirs and conventional oil-brine-rock (OBR) systems. In shale gas reservoirs, the imbibition of water through surface hydration into gas-filled mica pores was found to follow the diffusive scaling law, but with an effective diffusivity much larger than the self-diffusivity of water molecules. The invasion of gas into water-filled pores with width down to 2nm occurs at a critical invasion pressure similar to that predicted by the classical capillary theories if effects of disjoining pressure and diffusiveness of water-gas interfaces are considered. The invasion of oil droplets into water-filled pores can face a free energy barrier if the pressure difference along pore is small. The computed free energy profiles are quantitatively captured by continuum theories if capillary and disjoining pressure effects are considered. Small droplets can invade a pore through thermal activation even if an energy barrier exists for its invasion. In conventional oil reservoirs, low-salinity waterflooding is an enhanced oil recovery method that relies on the modification of thin brine films in OBR systems by salinity change. A systematic study of the structure, disjoining pressure, and dynamic properties of these thin brine films was performed. As brine films are squeezed down to sub-nanometer scale, the structure of water-rock and water-oil interfaces changes marginally, but that of the electrical double layers in the films changes greatly. The disjoining pressure in the film and its response to salinity change follow the trend predicted by the DLVO theory, although the hydration and double layer forces are not simple additive as commonly assumed. A notable slip between the brine film and the oil phase can occur. The role of thin liquid films in multiphase transport in hydrocarbon reservoirs revealed here helps lay foundation for manipulating and leveraging these films to enhance hydrocarbon production and to minimize environmental damage during such extraction. / Doctor of Philosophy / Meeting the ever-increasing energy demand requires efficient extraction of hydrocarbons from unconventional reservoirs and enhanced recovery from conventional reservoirs, which necessitate a thorough understanding of the interfacial and transport phenomena involved in the extraction process. Abundant water is found in both conventional oil reservoirs and emerging hydrocarbon reservoirs such as shales. The interfacial behavior and transport of water and hydrocarbon in these systems can largely affect the oil and gas recovery process, but are not well understood, especially at pore scale. To fill in the knowledge gap on these important problems, this dissertation focuses on the pore-scale multiphase interfacial and transport phenomena in hydrocarbon reservoirs. In shales, water is found to imbibe into strongly hydrophilic nanopores even though the pore is filled with highly pressurized methane. Methane gas can invade into water-filled nanopores if its pressure exceeds a threshold value, and the thin residual water films on the pore walls significantly affect the threshold pressure. Oil droplet can invade pores narrower than their diameter, and the energy cost for their invasion can only be computed accurately if the surface forces in the thin film formed between the droplet and pore surface are considered. In conventional reservoirs, thin brine films between oil droplet and rock greatly affect the wettability of oil droplets on the rock surface and thus the effectiveness of low-salinity waterflooding. In brine films with sub-nanometer thickness, the ion distribution differs from that near isolated rock surfaces but the structure of water-brine/rock interfaces is similar to their unconfined counterparts. The disjoining pressure in thin brine films and its response to the salinity change follow the trend predicted by classical theories, but new features are also found. A notable slip between the brine film and the oil phase can occur, which can facilitate the recovery of oil from reservoirs.

Reservoir management strategies traditionally attempt to combine and balance complex geophysical, petrophysical, thermodynamic and economic factors to determine an optimal method to recover hydrocarbons from a given reservoir. Reservoir simulators have traditionally been too large and run times too long to allow for rigorous solution in conjunction with an optimization algorithm. It has also proven very difficult to marry an optimizer with the large set of nonlinear partial differential equations required for accurate reservoir simulation. A simple capacitance-resistance model (CRM) that characterizes the connectivity between injection and production wells can determine an injection scheme maximizes the value of the reservoir asset. Model parameters are identified using linear and nonlinear regression. The model is then used together with a nonlinear optimization algorithm to compute a set of future injection rates which maximize discounted net profit. This research demonstrates that this simple dynamic model provides an excellent match to historic data. Based on three case studies examining actual reservoirs, the optimal injection schemes based on the capacitance-resistive model yield a predicted increase in hydrocarbon recovery of up to 60% over the extrapolated exponential historic decline. An advantage of using a simple model is its ability to describe large reservoirs in a straightforward way with computation times that are short to moderate. However, applying the CRM to large reservoirs with many wells presents several new challenges. Reservoirs with hundreds of wells have longer production histories – new wells are created, wells are shut in for varying periods of time and production wells are converted to injection wells. Additionally, ensuring that the production data to which the CRM is fit are free from contamination or corruption is important. Several modeling techniques and heuristics are presented that provide a simple, accurate reservoir model that can be used to optimize the value of the reservoir over future time periods. In addition to optimizing reservoir performance by allocating injection, this research presents a few methods that use the CRM to find optimal well locations for new injectors. These algorithms are still in their infancy and represent the best ideas for future research. / text

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Bitumen recovery by the water-based extraction process produces waste streams known as tailings. When discharged into the tailing ponds, the coarse solids in the tailings stream settle out quickly, while the fine solids accumulate over years of settling to a solids content of 30-35% by weight. The formed fluid fine solids sludge, known as mature fine tailings (MFT), traps 1-3% by weight hydrocarbons within its stable slurry structure. The remediation of these mature fine tailings is one of the major challenges facing the oil sands industry. This study was intended to investigate the recovery of residual hydrocarbons in the MFT by froth flotation process. Using a laboratory Denver flotation cell operated in a batch mode, the effect of MFT dilution ratio by process water or tap water, the flotation hydrodynamics and aeration rate on hydrocarbon recovery kinetics was studied. It was found that at 1:2 dilution by weight of the MFT with process water, increasing aeration rate has a more favourable effect on recovering more than 85% of the hydrocarbons from the MFT. The hydrocarbon-rich froth produced was treated by naphtha and was found to produce a hydrocarbon product similar to diluted bitumen obtained in bitumen extraction process, suitable for upgrading. Similar approach was applied to the hydrocarbon-rich tailings from the Tailings Solvent Recovery Unit of paraffinic froth treatment. Satisfactory recovery of hydrocarbons from the MFT was obtained using a flotation column operated in a continuous mode, confirmed the results obtained from the batch tests. The tailings produced from the continuous flotation experiments were treated with polymer flocculants such as Magnafloc-1011 and Al-PAM to study the effect of hydrocarbon recovery on the remediation of the MFT. The results from initial tests showed that both flocculants were not as effective on flocculating MFT solids following the recovery of hydrocarbons by froth flotation. / in Chemical Engineering

The objective of reservoir management is to maximize a key performance indicator (net present value in this study) at a minimum cost. A typical approach includes engineering analysis, followed by the economic value of the technical study. In general, operators are inclined to spend more effort on the engineering side to the detriment of the economic area, leading to unbalanced and occasionally suboptimal results. Moreover, most of the optimization methods used for production scheduling focus on a given recovery phase, or medium-term strategy, as opposed to an integrated solution that allocates resources from discovery to field abandonment. This thesis addresses the optimization of a reservoir under both technical and economic constraints. In particular, the method presented introduces a life cycle maximization approach to establish the best exploitation strategy throughout the life of the project. Deterministic studies are combined with stochastic modeling and risk analysis to assess decision making under uncertainty. To demonstrate the validity of the model, this document offers two case studies and the optimal times associated with each recovery phase. In contrast with traditional depletion strategies, where the optimization is done myopically by maximizing the net present value at each recovery phase, our results suggest that time is dramatically reduced when the net present value is optimized globally by maximizing the NPV for the life of the project. Furthermore, the sensitivity analysis proves that the original oil in place and non-engineering parameters such as the price of oil are the most influential variables. The case studies clearly show the greater economic efficiency of this life cycle approach, confirming the potential of this optimization technique for practical reservoir management. / text