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Unconventional resources have been known to hold vast quantities of hydrocarbons. However, exploiting the oil and gas they hold was previously challenging due to their low permeabilities. Recent advances in horizontal well drilling and hydraulic fracturing have enabled oil and gas production from these reservoirs, leading to significant increases in energy supply to meet the growing energy demand. However, despite the relative technological success, considerable obstacles persist; oil production from unconventional wells often declines by more than 20% of their initial production rate within the first two years, leaving significant volumes of residual oil trapped in the formations. This overarching challenge warrants the need to develop techniques to improve recovery from these valuable resources. Enhanced oil recovery (EOR) from unconventional resources has been a primary subject of interest among the research community. Gaseous solvent injection has been touted as promising to enhance recovery from unconventional resources. Although several small-scale laboratory experiments and field-scale simulation studies have corroborated the efficacy of gaseous solvents in improving oil recovery, recent field pilot tests have failed to yield the expected improvement in oil production. Hence, the technique has not been widely adopted by industry players. A major contributing factor to this lack of adoption is the gaps in understanding the underlying multiscale (i.e., pore, core, and well scales) recovery mechanisms by gaseous solvents during the injection. Furthermore, there is an apparent knowledge gap in understanding the influence of critical operating parameters on oil recovery (and gas utilization), the variable interaction between these parameters, and their optimal settings at the well scale. This three-part project addresses some pertinent questions regarding gaseous solvent cyclic injection enhanced oil recovery in unconventional formations. The objective of the first part was vii to determine the efficacy of select gaseous solvents for EOR, determine the influence of critical operating parameters and the variable interactions with gas composition and miscibility conditions, and deduce the underlying dominant mechanisms during gaseous solvent cyclic EOR. To this end, core-scale experiments that simulate matrix fracture interactions were conducted using CO2 and ethane as gaseous solvents. The results showed that gaseous solvent huff-n-puff could achieve up to 87% recovery factor in small middle Bakken small core samples. The results also revealed the essential interactions of operating parameters with miscibility conditions and gas composition. Furthermore, the competition between diffusion and advection as a function of operating parameters was deduced from the results. The second part aimed to examine the pore scale displacement efficiencies and corroborate the underlying mechanism responsible for enhancing recovery during gaseous solvent EOR. Nuclear magnetic resonance relaxometry was used to measure the fluid-filled pore size distribution to assess the pore level displacement effectiveness of the gaseous solvent huff-n-puff. The results reveal that gaseous solvent huff-n-puff could displace fluids down to the micropores in tight core samples. They also revealed the influence of diffusion and advective force on pore-level displacement efficiency. The final phase consisted of well-scale studies to ascertain the large-scale effectiveness of gaseous solvents, the effects of the critical operating parameters and the interactions among them, and the optimization of these parameters for maximum recovery (and optimum gas utilization factor). Here, we leverage compositional reservoir simulation and response surface methodology (RSM) for this purpose. The result revealed the most important well-scale parameters for optimum recovery. Numerical optimization indicates that gaseous solvent huff-n-puff in the Bakken Formation can yield more than 7% incremental recovery with a gas utilization factor of viii more than 2 bbl/Mscf. We believe the findings in this work can better guide operators to design efficient gaseous solvent huff-n-puff strategies in the Bakken Formation and other unconventional reservoirs.

Unconventional resources have led to a new abundance of natural oil and gas supply all over the world over the past decade and are expected to play a vital role in the future of this industry. Despite tremendous growth of extraction technologies which increased the production of these reserve significantly, knowledge and understanding of flow and phase behavior of the fluid in unconventional resources has remained insufficiently explored. Accurate understanding of phase behavior of fluids trapped in the extremely small pores of these resources, especially shale reservoirs, is the center of attention for a lot of scholars globally. Although numerous mathematical and theoretical studies are available to explain phase behavior of confined fluids, limited number of studies attempted to explore this effect experimentally. Experimental data are invaluable in providing the deep insight needed to explain this effect, validate available models, and introduce methods of characterizations that would help with optimization of production plans. The present work is an attempt to enhance the understanding of fluid phase behavior in tight formations through experimental investigations. Microscopic effects and their macroscopic consequences that plays a crucial role in adding to the complexity of fluid phase behavior in these reservoirs are explored and explained prior to discussing modeling and experimental works. Fundamental knowledge of phase behavior and thermodynamic principals that are essential for exploring this effect and for comparing the shortcomings of established experimental approaches in phase behavior studies of conventional reservoirs are covered. A thorough review on the existing theoretical and experimental studies on the topic, considering their results and predictions, is conducted to shed more light on the need for further experimental investigation of phase behavior alterations in tight gas condensate formations. Isochoric method is an indirect high-precision way of phase transition point determination which is commonly used in other disciplines where a clear non-visual determination of phase transition of a fixed volume of fluid is needed. The present work provides an insight into using this approach in determining dew pint pressure (DPP) for gas mixtures inside and outside of the porous media. A semi-automated apparatus for measuring and monitoring equilibrium conditions along with fluid properties is designed based on the isochoric method. The apparatus provides constant volume, variable pressure (0 to 1500 psi), and variable temperature (290 to 410 K) experimental conditions. Pressure and temperature measurements are used to detect the phase transition point along the constant-mole-constant-volume line based on the change in the slope of this line at the transition point. A packed bed of BaTiO3 nanoparticles, providing a homogenous porous medium with pores of 1 to 70 nm is used as a representative nano-scale porous medium. The synthesized porous medium is very helpful in uncoupling the effect of pore size from the effect of mineralogy on the observed deviations in behavior, providing a volume more than 1000 times larger than typical nano channels. The result is a set of Isochoric lines for bulk and confined sample, plotted on the phase envelope to demonstrate the change in saturation pressure. Phase envelopes (P-T diagrams) of the same mixture using different equations of state are constructed and the accuracy of each of these equations of state in providing an experimentally detected DPP is discussed. Many attempts in explaining the shift in saturation pressures of the reservoir fluid confined in the narrow pores of unconventional reservoirs compared to those of the bulk can be found in the literature. However, there are some contradictions between the predicted behavior using different mathematical approaches. Experimental data could be substantially helpful in both validating models and improving the understanding of the fluid behavior in these formations. Contrary to what many published models predict, the results of the present work show that confinement effects shift the DPP towards higher values compared to the bulk for a fixed temperature in the retrograde region. In the non-retrograde region, however, this shift is towards lower dew point pressure values for the confined fluid compared to the bulk. Capillary condensation is identified to be the main source of the deviations observed in the behavior of fluids inside nanopores. We evaluated published models, including those based on EOS modifications, by comparing it to experimental results to provide a quantification of their accuracy in estimating saturation pressure values for the confined mixture. Future applications of the present work for directing it towards an all-inclusive theory for all reservoir fluids in unconventional formations are clearly outlined.

Understanding the mechanisms that govern hydraulic fracturing applications in unconventional formations, such as gas-bearing shales, is of increasing interest to the petroleum upstream industry. Among such mechanisms, the geomechanical interactions between hydraulic fractures and pre-existing fractures on one hand, and simultaneous multiple hydraulic fractures on the other hand are seen of high importance. Although the petroleum engineering and related literature contains a number of studies that discusses such topics of hydraulic fracture interactions, there still remain some aspects that require answers, validations, or further supporting data. Particularly, experimental evidence is fairly scarce and keenly needed to solidify the understanding of such complex applications. In this work, the investigation methodology uses a series of hydraulic fracturing laboratory tests performed on synthetic rocks made of gypsum-based cements such as hydrostone and plaster in various experimental set ups. Those laboratory tests aim to closely investigate hydraulic fracture intersection with pre-existing fractures by assessing some factors that govern its outcomes. Specifically, the roles of the pre-existing fracture cementation, aperture, and relative height on the intersection mode are examined. The results show dominant effect of the cement-fill type relative to the host-rock matrix in determining whether hydraulic fracture crossing the pre-existing interface may occur. Similarly, hydraulic fracture height relative to the height of the pre-existing fracture may dictate the intersection results. However, the intersection mode seems to be insensitive of the pre-existing fracture aperture. Moreover, simultaneous multi-fracture propagation is examined and found to be impacted by the interference of the stresses induced from each fracturing source on neighboring fracturing sources. Such stress interference increases as the number of the propagating hydraulic fractures increase. While hydraulic fractures initiating from fracturing sources located in the middle of the fracturing stage seem to have inhibited propagation, outer hydraulic fractures may continue propagating with outward curvatures. Overall, the experimental results and analyses offer more insights for understanding hydraulic fracture complexity in unconventional formations.