The folded and thrusted Mesozoic clastic sequence of the Canadian Rocky Mountain foothills forms important hydrocarbon reservoirs. Understanding the distribution of natural fractures, their evolution, and timing of formation relative to the evolution of the fold-and-thrust system could potentially improve exploration and development outcomes in these otherwise tight unconventional reservoirs. However, the formation of fractures and their timing relative to folding and thrusting have remained unclear. I investigated the relation between folding and fracture formation in the Upper Cretaceous Cardium Sandstone by combining field structural observations and kinematic modeling of the fold-and-thrust belt evolution. I explored the relationship between fracture intensity and fracture strain with structural position by analyzing fracture spacing or frequency and aperture data collected along outcrop and micro-scanlines in the backlimb, in the forelimb close to the crest, and in the steeper dipping forelimb away from the crest of the Red Deer River anticline. Fracture frequency and aperture data collected both at the outcrop and micro scales indicate that variation in fracture strain is small across these three structural domains of the fold, with somewhat lower fracture intensity in the forelimb close to the crest. These fracture strain measurements are qualitatively consistent with calculated horizontal strain in the tectonic transport direction obtained through kinematic numerical models that simulate fold development associated with slip along the underlying Burnt Timber thrust. The models predict roughly similar amount of horizontal extension in both the back and forelimbs, and somewhat lower extension in the upper forelimb during early development of the Red Deer River anticline. Fracture formation early during fold development is consistent with the field structural observations of shear reactivation during later stages of folding. This combined kinematic modeling and field structural study demonstrates that deforming fold and thrust belts can undergo a complex evolution of bed-parallel extension in both space and time, resulting in spatially variable fracture formation in such structurally complex subsurface reservoirs. / text

To continue increasing the energy supply to meet global demand in the coming decades, the energy industry needs creative thinking that leads to the development of new energy sources. Unconventional gas resources, especially those in frontier basins, will play an important role in fulfilling future world energy needs. We must identify and quantify potential unconventional gas resources in basins around the world to plan for their development. Basin analog assessment is one technique that can be used to identify and quantify unconventional gas resources that is less expensive and less time consuming. We have developed a basin analog methodology that is useful for rapidly and consistently evaluating the unconventional hydrocarbon resource potential in exploratory basins. We developed software, Basin Analog System (BAS), to perform and accelerate the process of identifying analog basins. Also, we built a database that includes geologic and petroleum systems information of intensely studied North America basins that contain well characterized conventional and unconventional hydrocarbon resources. We have selected 25 basins in North America that have a history of producing unconventional gas resources. These are “reference” basins that are used to predict resources in frontier or exploratory basins. The software assists us in ranking reference basins that are most analogous to the target basin for the primary purpose of evaluating the potential unconventional resources in the target basin. The methodology allows us to numerically rank all the reference basins relative to the target basin. The accuracy of the results depends on the descriptions of geologic and petroleum systems. We validated the software to make sure it is functioning correctly and to test the validity of the process and the database. Finding a reference basin that is analogous to a frontier basin can provide insights into potential unconventional gas resources of the frontier basin. Our method will help industry predict the unconventional hydrocarbon resource potential of frontier basins, guide exploration strategy, infer reservoir characteristics, and make preliminary decisions concerning the best engineering practices as wells are drilled, completed, stimulated and produced.

Injecting CO2 into unconventional reservoirs to enhance oil recovery has been widely studied due to its potential to improve the profitability of these reservoirs. CO2 Huff-n-Puff is emerging as a promising method, but exploiting its full potential is challenging due to difficulties in optimizing its operations. The latter arises from the limited understanding of CO2 and oil transport in unconventional reservoirs. This dissertation used molecular dynamics simulations to study the storage and transport of oil and CO2 in unconventional reservoirs in single nanopores. The first study examined the modulation of oil flow in calcite pores by CO2. It is discovered that CO2 molecules adsorb strongly on calcite walls and can change decane permeability through 8 nm-wide pores by up to 30%. They impede decane flow at moderate adsorption density but enhance flow as adsorption approaches saturation. The second study investigated the CO2 transport in 4 nm-wide calcite pores during the soaking phase of Huff-n-Puff operations. CO2 entering the pore can become adsorbed on pore walls and diffuse on them or diffuse as free CO2 molecules. The accumulation of CO2 follows a diffusion behavior with an effective diffusivity ~50% smaller than bulk CO2. Two dimensionless groups are proposed to gauge the importance of surface adsorption and diffusion in CO2 storage and transport in nanopores. The third study examined the extraction of decane initially sealed in a 4 nm-wide calcite pore through exchange with CO2 and CH4 in a reservoir. The CO2-decane exchange is significantly driven by the evolution of adsorbed oil and gas initially, but a transition to dominance by free oil and gas occurs later; for CH4-decane exchange, the opposite occurs. The net gas accumulation and decane extraction follow the diffusive law, but their effective diffusivities do not always align well with the self-diffusion coefficients of CO2, CH4, and decane in the nanopore. The three studies identified the essential roles of gas/oil adsorption in their net transport in nanopores and, thus, unconventional reservoirs. Delineating these roles and formulating dimensionless groups to gauge their importance help develop better models for enhanced oil recovery from unconventional reservoirs by CO2 injection. / Doctor of Philosophy / Unconventional reservoirs are hydrocarbon-bearing formations with ultralow permeabilities, and they have emerged as a critical source of liquid petroleum production in the United States over the past decade. However, because oil is trapped in nanoscale pores in these reservoirs, the oil recovery rate is low. Therefore, many methods have been developed to enhance the oil recovery from unconventional reservoirs. One of the popular methods is to inject gas into reservoirs to enhance oil recovery. Improving this method's efficacy requires a fundamental understanding of the thermodynamic and transport phenomena underlying its operation is needed. This dissertation used molecular dynamics simulations to study the storage and transport of oil and CO2 in unconventional reservoirs at the single nanopore scale. Three series of studies have been performed to elucidate how CO2 modulates the flow of oil inside nanopores, how CO2 enters a nanopore filled with oil, and how oil is extracted from the nanopore by the ingression of CO2. These studies showed that when CO2 molecules adsorb strongly on a nanopore's walls, they can either enhance or impede the permeation of oil through the pore. The ingression of CO2 into an oil-filled nanopore and the concurrent oil extraction can be described by the same equation for the conduction of heat in one-dimensional objects. The CO2 ingression and oil extraction rates are heavily affected by the adsorption of CO2 and oil on the nanopore's walls. These results highlight the important effects of surface adsorption on the storage and transport of gas and oil in nanopores and, thus, unconventional oil reservoirs. Incorporating these effects into oil recovery models will improve their predictive power, and thus help model-guided optimization of oil recovery.

Geologic sequestration of CO2 into unmineable coal seams is proposed as a way to mitigate the greenhouse gas effect and potentially contribute to economic prosperity through enhanced methane recovery. In 2009, the Virginia Center for Coal and Energy Research (VCCER) injected 907 tonnes of CO2 into one vertical coalbed methane well for one month in Russell County, Virginia (VA). The main objective of the test was to assess storage potential of coal seams and to investigate the potential of enhanced gas recovery. In 2014, a larger scale test is planned where 20,000 tonnes of CO2 will be injected into three vertical coalbed methane wells over a period of a year in Buchanan County, VA. During primary coalbed methane production and enhanced production through CO2 injection, a series of complex physical and mechanical phenomena occur. The ability to represent the behavior of a coalbed reservoir as accurately as possible via computer simulations yields insight into the processes taking place and is an indispensable tool for the decision process of future operations. More specifically, the economic viability of projects can be assessed by predicting production: well performance can be maximized, drilling patterns can be optimized and, most importantly, associated risks with operations can be accounted for and possibly avoided. However, developing representative computer models and successfully simulating reservoir production and injection regimes is challenging. A large number of input parameters are required, many of which are uncertain even if they are determined experimentally or via in-situ measurements. Such parameters include, but are not limited to, seam geometry, formation properties, production constraints, etc. Modeling of production and injection in multi-seam formations for hydraulically fractured wells is a recent development in coalbed methane/enhanced coalbed methane (CBM/ECBM) reservoir modeling, where models become even more complex and demanding. In such cases model simulation times become important. The development of accurate simulation models that correctly account for the behavior of coalbeds in primary and enhanced production is a process that requires attention to detail, data validation, and model verification. A number of simplifying assumptions are necessary to run these models, where the user should be able to balance accuracy with computational time. In this thesis, pre- and post-injection simulations for the site in Russell County, VA, and preliminary reservoir simulations for the Buchanan County, VA, site are performed. The concepts of multi-well, multi-seam, explicitly modeled hydraulic fractures and skin factors are incorporated with field results to provide accurate modeling predictions. / Ph. D.

CO2 injection has demonstrated significant potential for enhanced oil recovery techniques in unconventional reservoirs, but there exists many challenges in optimizing its operations due to the limited understanding of CO2-oil transport mechanisms in these systems. This dissertation addresses these challenges using molecular dynamics (MD) simulations by investigating the gas and oil transport behaviors and properties within single nanopores under reservoir conditions. The first study examines the exchange dynamics of decane with CO2 and CH4 in a 4 nm-wide calcite nanopore. It is shown that both gases form distinct adsorbed and free molecular populations upon entering the pores, leading to different extraction dynamics. Notably, CO2-decane exchange is initially driven by adsorbed populations, with a transition to free populations later; whereas CH4 -decane exchange follows the opposite pattern. Despite these differences, the transport of both gases apparently follows the same diffusive behavior, with CH4 exhibiting higher effective diffusivities. By calculating self-diffusivities at various relevant compositions, it is found they do not always align well with their effective diffusivities. The second study therefore focuses on Maxwell-Stefan (M-S) diffusivities as a more comprehensive framework to describe the diffusion of CO2-decane mixtures in the first study. It is found that D12 (CO2-decane interactions) remains relatively constant across compositions, unlike bulk mixtures, while D1,s (CO2-wall interactions) increases sharply with CO2 loading. In contrast, D2,s (decane-wall interactions) shows a nonmonotonic trend and, unexpectedly, becomes negative under certain compositions. These phenomena are linked to the strong adsorption of CO2, causing significant density heterogeneity and reduced mobility. Using a multi-task Gaussian process regression model, the M−S diffusivities can be predicted with a relative root mean square error below 10%, significantly reducing computational demand for their practical usage. The third study examines concentration gradient driven diffusio-osmosis of oil-CO2 mixtures within silica and calcite nanopores. Despite higher CO2 enrichment near calcite walls, diffusio-osmotic is only marginally stronger than in silica pores, which is attributed to the variations in interfacial fluid structures and hydrodynamic properties in different pores. Continuum simulations suggest that diffusio-osmosis becomes increasingly significant compared to Poiseuille flow as pore width decreases. The fourth study investigates the oil mixture (C10+C19) recovery from a 4 nm-wide calcite dead-end pore with and without CO2 injection. It was found that CO2 accelerates oil recovery and reduces selectivity for lighter components (e.g., C10) compared to the recovery without CO2. Such improvements are influenced by interfacial and bulk phenomena, including adsorption competition and solubilization effects. Together, these studies provide quantitative insights into CO2-oil transport mechanisms and properties in nanopores. Such insights can help develop better reservoir simulators to guide the optimization of CO2 injection-based enhanced oil recovery in unconventional reservoirs. / Doctor of Philosophy / Recovering oil from unconventional reservoirs—types of underground rock formations that trap oil in extremely tiny pores, much smaller than the thickness of a strand of hair—is one of the biggest challenges in the petroleum industry. The narrow pore size greatly increases the fraction of the oil flow, and many pores are not even connected, which stops oil to flow out on its own, making it much harder to extract from these reservoirs. Injecting gases into the reservoirs, like carbon dioxide (CO2), has become a promising solution. This method not only helps to push the oil out but also allows part of the injected CO2 to be stored underground, reducing its impact on the atmosphere. To make this process work better, we need in depth understandings of how oil and gas move in these tiny rock spaces. Four studies have been conducted to elucidate the transport phenomena in CO2 injection-based enhanced oil recovery. The first study finds that the exchange between trapped oil and CO2 is significantly influenced by how oil and CO2 stick to the walls of these tiny pores. However, it is observed that commonly used characterization methods do not always work well in the prediction of recovery behavior, indicating the need for a better framework to describe this process. To address this problem, we have brought up a new framework in the second study, which considers both the interactions between oil and CO2 and the interactions with the pore wall. Given the high computational costs, a machine learning model is trained with the data collected to make future predictions faster and cheaper. The third study quantifies the strength of a new type of flow. This flow can be comparable in magnitude to pressure difference-driven flow in tiny pores. Lastly, the recovery of an oil mixture composed of light and heavy hydrocarbons is explored. It was discovered that gas injection not only increases the overall oil recovery rate but also decreases the selectivity toward lighter hydrocarbons. These discoveries pave the way for improved models and strategies to optimize the gas injection process to recover oil from these challenging reservoirs, ultimately meeting the energy needs while supporting efforts to reduce atmospheric CO2 levels.

Today everyone seems to agree that ultra-low permeability and shale reservoirs have become the potentials to transform North America's oil and gas industry to a new phase. Unfortunately, transient flow is of long duration (perhaps life of the well) in ultra-low permeability reservoirs, and traditional decline curve analysis (DCA) models can lead to significantly over-optimistic production forecasts without additional safeguards. Stretched Exponential decline model (SEDM) gives considerably more stabilized production forecast than traditional DCA models and in this work it is shown that it produces unchanging EUR forecasts after only two-three years of production data are available in selected reservoirs, notably the Barnett Shale. For an individual well, the SEDM model parameters, can be determined by the method of least squares in various ways, but the inherent nonlinear character of the least squares problem cannot be bypassed. To assure a unique solution to the parameter estimation problem, this work suggests a physics-based regularization approach, based on critical velocity concept. Applied to selected Barnett Shale gas wells, the suggested method leads to reliable and consistent EURs. To further understand the interaction of the different fracture properties on reservoir response and production decline curve behavior, a series of Discrete Fracture Network (DFN) simulations were performed. Results show that at least a 3-layer model is required to reproduce the decline behavior as captured in the published SEDM parameters for Barnett Shale. Further, DFN modeling implies a large number of parameters like fracture density and fracture length are in such a way that their effect can be compensated by the other one. The results of DFN modeling of several Barnett Shale horizontal wells, with numerous fracture stages, showed a very good agreement with the estimated SEDM model for the same wells. Estimation of P90 reserves that meet SEC criteria is required by law for all companies that raise capital in the United States. Estimation of P50 and P10 reserves that meet SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS) criteria is important for internal resource inventories for most companies. In this work a systematic methodology was developed to quantify the range of uncertainty in production forecast using SEDM. This methodology can be used as a probabilistic tool to quantify P90, P50, and P10 reserves and hence might provide one possible way to satisfy the various legal and technical-society-suggested criteria.

Naturally fractured reservoirs (NFRs) hold a significant amount of the world's hydrocarbon reserves. Compared to conventional reservoirs, NFRs exhibit a higher degree of heterogeneity and complexity created by fractures. The importance of fractures in production of oil and gas is not limited to naturally fractured reservoirs. The economic exploitation of unconventional reservoirs, which is increasingly a major source of short- and long-term energy in the United States, hinges in part on effective stimulation of low-permeability rock through multi-stage hydraulic fracturing of horizontal wells. Accurate modeling and simulation of fractured media is still challenging owing to permeability anisotropies and contrasts. Non-physical abstractions inherent in conventional dual porosity and dual permeability models make these methods inadequate for solving different fluid-flow problems in fractured reservoirs. Also, recent approaches for discrete fracture modeling may require large computational times and hence the oil industry has not widely used such approaches, even though they give more accurate representations of fractured reservoirs than dual continuum models. We developed an embedded discrete fracture model (EDFM) for an in-house fully-implicit compositional reservoir simulator. EDFM borrows the dual-medium concept from conventional dual continuum models and also incorporates the effect of each fracture explicitly. In contrast to dual continuum models, fractures have arbitrary orientations and can be oblique or vertical, honoring the complexity and heterogeneity of a typical fractured reservoir. EDFM employs a structured grid to remediate challenges associated with unstructured gridding required for other discrete fracture models. Also, the EDFM approach can be easily incorporated in existing finite difference reservoir simulators. The accuracy of the EDFM approach was confirmed by comparing the results with analytical solutions and fine-grid, explicit-fracture simulations. Comparison of our results using the EDFM approach with fine-grid simulations showed that accurate results can be achieved using moderate grid refinements. This was further verified in a mesh sensitivity study that the EDFM approach with moderate grid refinement can obtain a converged solution. Hence, EDFM offers a computationally-efficient approach for simulating fluid flow in NFRs. Furthermore, several case studies presented in this study demonstrate the applicability, robustness, and efficiency of the EDFM approach for modeling fluid flow in fractured porous media. Another advantage of EDFM is its extensibility for various applications by incorporating different physics in the model. In order to examine the effect of pressure-dependent fracture properties on production, we incorporated the dynamic behavior of fractures into EDFM by employing empirical fracture deformation models. Our simulations showed that fracture deformation, caused by effective stress changes, substantially affects pressure depletion and hydrocarbon recovery. Based on the examples presented in this study, implementation of fracture geomechanical effects in EDFM did not degrade the computational performance of EDFM. Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns suggested by microseismic data. We developed a coupled dual continuum and discrete fracture model to efficiently simulate production from these reservoirs. Large-scale hydraulic fractures were modeled explicitly using the EDFM approach and numerous small-scale natural fractures were modeled using a dual continuum approach. The transport parameters for dual continuum modeling of numerous natural fractures were derived by upscaling the EDFM equations. Comparison of the results using the coupled model with that of using the EDFM approach to represent all natural and hydraulic fractures explicitly showed that reasonably accurate results can be obtained at much lower computational cost by using the coupled approach with moderate grid refinements. / text

Successful creations of multiple hydraulic fractures in horizontal wells are critical for economic development of unconventional reservoirs. The recent advances in diagnostic techniques suggest that multi-fracturing stimulation in unconventional reservoirs has often caused complex fracture geometry. The most important factors that might be responsible for the fracture complexity are fracture interaction and the intersection of the hydraulic and natural fracture. The complexity of fracture geometry results in significant uncertainty in fracturing treatment designs and production optimization. Modeling complex fracture propagation can provide a vital link between fracture geometry and stimulation treatments and play a significant role in economically developing unconventional reservoirs. In this research, a novel fracture propagation model was developed to simulate complex hydraulic fracture propagation in unconventional reservoirs. The model coupled rock deformation with fluid flow in the fractures and the horizontal wellbore. A Simplified Three Dimensional Displacement Discontinuity Method (S3D DDM) was proposed to describe rock deformation, calculating fracture opening and shearing as well as fracture interaction. This simplified 3D method is much more accurate than faster pseudo-3D methods for describing multiple fracture propagation but requires significantly less computational effort than fully three-dimensional methods. The mechanical interaction can enhance opening or induce closing of certain crack elements or non-planar propagation. Fluid flow in the fracture and the associated pressure drop were based on the lubrication theory. Fluid flow in the horizontal wellbore was treated as an electrical circuit network to compute the partition of flow rate between multiple fractures and maintain pressure compatibility between the horizontal wellbore and multiple fractures. Iteratively and fully coupled procedures were employed to couple rock deformation and fluid flow by the Newton-Raphson method and the Picard iteration method. The numerical model was applied to understand physical mechanisms of complex fracture geometry and offer insights for operators to design fracturing treatments and optimize the production. Modeling results suggested that non-planar fracture geometry could be generated by an initial fracture with an angle deviating from the direction of the maximum horizontal stress, or by multiple fracture propagation in closed spacing. Stress shadow effects are induced by opening fractures and affect multiple fracture propagation. For closely spaced multiple fractures growing simultaneously, width of the interior fractures are usually significantly restricted, and length of the exterior fractures are much longer than that of the interior fractures. The exterior fractures receive most of fluid and dominate propagation, resulting in immature development of the interior fractures. Natural fractures could further complicate fracture geometry. When a hydraulic fracture encounters a natural fracture and propagates along the pre-existing path of the natural fracture, fracture width on the natural fracture segment will be restricted and injection pressure will increase, as a result of stress shadow effects from hydraulic fracture segments and additional closing stresses from in-situ stress field. When multiple fractures propagate in naturally fracture reservoirs, complex fracture networks could be induced, which are affected by perforation cluster spacing, differential stress and natural fracture patterns. Combination of our numerical model and diagnostic methods (e.g. Microseismicity, DTS and DAS) is an effective approach to accurately characterize the complex fracture geometry. Furthermore, the physics-based complex fracture geometry provided by our model can be imported into reservoir simulation models for production analysis. / text

Reservoir characterization is one of the most important problems in petroleum engineering. It involves forward reservoir modeling that predicts the fluid behavior in the reservoir and inverse problem that calibrates created reservoir models with given data. In this dissertation, we focus on two problems in the field of reservoir characterization: depth of investigation in heterogeneous reservoirs, and history matching and uncertainty quantification of channelized reservoirs. The concept of depth of investigation is fundamental to well test analysis. Much of the current well test analysis relies on analytical solutions based on homogeneous or layered reservoirs. However, such analytic solutions are severely limited for heterogeneous and fractured reservoirs, particularly for unconventional reservoirs with multistage hydraulic fractures. We first generalize the concept to heterogeneous reservoirs and provide an efficient tool to calculate drainage volume using fast marching methods and estimate pressure depletion based on geometric pressure approximation. The applicability of proposed method is illustrated using two applications in unconventional reservoirs including flow regime visualization and stimulated reservoir volume estimation. Due to high permeability contrast and non-Gaussianity of channelized permeability field, it is difficult to history match and quantify uncertainty of channelized reservoirs using traditional approaches. We treat facies boundaries as level set functions and solve the moving boundary problem (history matching) with the level set equation. In addition to level set methods, we also exploit the problem using pixel based approach. The reversible jump Markov Chain Monte Carlo approach is utilized to search the parameter space with flexible dimensions. Both proposed approaches are demonstrated with two and three dimensional examples.

The petroleum engineering literature clearly shows that large proppant volumes and concentrations are required to effectively stimulate low-permeability gas sands. To pump large proppant concentrations, one must use a viscous fluid. However, many operators believe that low-viscosity, low-proppant concentration fracture stimulation treatments known as ??waterfracs?? produce comparable stimulation results in low-permeability gas sands and are preferred because they are less expensive than gelled fracture treatments. This study evaluates fracture stimulation technology in tight gas sands by using case histories found in the petroleum engineering literature and by using a comparison of the performance of wells stimulated with different treatment sizes in the Cotton Valley sands of the East Texas basin. This study shows that large proppant volumes and viscous fluids are necessary to optimally stimulate tight gas sand reservoirs. When large proppant volumes and viscous fluids are not successful in stimulating tight sands, it is typically because the fracture fluids have not been optimal for the reservoir conditions. This study shows that waterfracs do produce comparable results to conventional large treatments in the Cotton Valley sands of the East Texas basin, but we believe it is because the conventional treatments have not been optimized. This is most likely because the fluids used in conventional treatments are not appropriate or have not been used appropriately for Cotton Valley conditions.