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Highlights • Generated P-T diagrams show the effect of pressure and heating rate on VLE. • Maximum oil yield at low vapor expulsion found with high pressure and heating rate. • Maximum oil yield at high vapor expulsion found with low pressure and heating rate. • Insignificant increase in oil yield with greater than 50% vapor expulsion. Abstract Separation of the products from the reacting organic matter is necessary to ensure product quality and reduce oil degradation to solid reside (coke) when considering conversion of oil shale to oil by in-situ processes. Many effects on yield and quality due to operational conditions may be explained by considering their role in volatilization. A five-reaction network with vapor–liquid equilibrium has been created in MATLAB to examine the effect of heating rate and pressure on volatilization. The model uses the Peng-Robinson equation of state, phase stability using the Gibbs tangent plane criterion, and Rachford-Rice flash calculations. Component compositions may be changed with automatically adjusting stoichiometry and species properties. A new feature is that dew and bubble point pressure calculations are performed at each calculation-step and plotted to show the phase behavior of the changing product composition with conversion. Product expulsion is represented as a mass fraction of generated vapor. The results indicate that for 10 °C/min and atmospheric pressure, 50% removal is enough to obtain a liquid yield that is 97% (977 mg/g TOC) of the maximum yield with 95% removal. The operational conditions with the lowest oil yield (127 mg/g TOC) are 0.001 °C/min and 500 psi with 5% vapor removed. Additionally, changing from high to low fractions of removed vapor move the maximum light oil yield from low pressure and low heating rate to high pressure and high heating rate. [ABSTRACT FROM AUTHOR]

Injection of carbon dioxide into saline aquifers is one the most promising methods for mitigating the increase in atmospheric CO 2 concentrations. Reactions of CO 2 with brine and formation rocks are important in determining the ultimate fate of CO 2 . Rates of reactions of the different relevant minerals are dependent on rate constants and mineral surface area. It is important to quantify the effect of surface area on reaction rates when different types of rock samples are employed in experiments. Batch experiments with different forms of the Berea sandstone were set up and performed at high pressure (2000 psi) and reservoir temperature (60 °C) for two-week under reservoir CO 2 sequestration conditions. Experiments were performed with markedly different samples (cores, rock chips, and powdered) with progressively increased surface areas. Experiments with the different forms of sandstones showed similar trends in major minerals dissolution with increase in cation concentrations of iron, magnesium, and calcium in the effluent brine. Under realistic aquifer pressure and temperature conditions, iron chemistry plays an important role in the dissolution reactions in the Berea sandstone. Reactivities increased leading to larger cationic concentrations in brine (as determined using ICP-MS) as the surface areas increased. Morphology of the reacted volume was viewed using QEMSCAN and Micro-CT for core plug samples. These experiments helped quantity the effect of surface area (higher surface area leading to more dissolution) and revealed that reactions appear to be limited more to the surface in Berea sandstone. It was shown that the factor used to obtain geometric surface area from a core decreased when samples with higher surface areas were used. This indicated that some internal surface area became available for fragmented (fractured), and powdered samples. Mineral dissolution caused the growth and expansion of pores in Berea sandstone and surface area measurements (BET) showed that the new porosity generated was characterized by a smaller pore size distribution in comparison to the unreacted one. [ABSTRACT FROM AUTHOR]

Large, potentially commercial geothermal resources exist in sedimentary rocks beneath high heat-flow basins of the United States. Geothermal reservoir modeling was performed to explore the available power density (MWe/km2) attributable to two general classes of reservoir: a multi-layered “sandwich” and single high permeability layer. Variations in reservoir temperature (i.e. conductive heat flow), permeability, and layer thickness were evaluated. The high permeability layers were assumed to be horizontal and laterally extensive. Production wells were assumed to be pumped at a constant rate, and all produced water was injected at 75°C after being cooled in a power plant. Modeling was undertaken using the STARS Advanced Process and Thermal Reservoir Simulator, Version 2010, by Computer Modeling Group. Five reservoir models were simulated: (1) Sandwich (base) reservoir model to test heat sweep for a reservoir-seal configuration with an average reservoir temperature of 200°C at 3km depth; the reservoir comprised four 25m thick layers with a permeability of 100mD. (2) Single layer reservoir with the same initial temperature and transmissivity of the sandwich reservoir. (3) Low temperature (150°C) sandwich reservoir model. (4) Low permeability sandwich reservoir model, involving lower permeability layers than the sandwich base model. (5) Short-circuit sandwich reservoir model where a high permeability layer results in a higher transmissivity than the base sandwich model. All models assumed isotropic permeability, uniform porosity (10%), and an initial thermally conductive vertical temperature gradient and hydrostatic pressure gradient. All models utilized a five spot pattern with a 500m well spacing, with the flow rate in producer and injector wells being 1000 gallons per minute. The base sandwich model, which may be representative of stratigraphic bedrock reservoirs beneath some basins of the Great Basin, has a power density 3–10MWe/km2 over a 30 year period. During 30 years of production and injection, production wells in the low permeability model each generated 140MWe-years of power compared to 65–90MWe-years per production well in the single layer and short circuit models. A consistent result from all the models was that vertically distributed reservoir layers allow a much greater fraction of heat to be swept from lower permeability seal units. In all models, the lateral pressure gradient induced between injectors ranged between 30 and 60bars, which is not unusual for geothermal developments. [ABSTRACT FROM AUTHOR]

Highlights: [•] Understanding variability in risk parameters in CO2 storage given the input uncertainties. [•] Response surface method used to calculate risk factors for constant mass or pressure injection. [•] Response surfaces validated with simulation results. [•] Overall risks of storage low. [•] Constant pressure injection has lower risk than constant mass injection. [ABSTRACT FROM AUTHOR]

Abstract: There are vast resources of oil shale in the western United States. Development of technically and economically effective technologies for the conversion of oil shale to liquid fuels will help provide a long-term and secure source of transportation fuels. Developing good understanding of the decomposition kinetics of oil shale to oil and other products, along with the oil compositional information are important regardless of the process used. Themogravimetric analysis combined with online mass spectrometry (TGA–MS) affords the opportunity to obtain compositional information while the decomposition is being measured quantitatively. In this work we provide data on the TGA–MS analyses of Green River oil shale from Utah. Compounds of about 300 atomic mass units were targeted in the mass spectrometric analyses. The weight loss results from the TGA part of the analysis and the subsequent kinetic parameters derived from the data were consistent with our prior work. The activation energies of decomposition were in the 90–230kJ/mol range with respect to conversion with uncertainty numbers of about 10%. Lighter hydrocarbons evolved slightly earlier and their amounts were higher in comparison to heavier hydrocarbons. Alkanes such as hexane and decane were detected at slightly lower temperatures than their equivalent carbon number aromatic compounds, but the differences were not significant. Higher heating rates generated more alkenes compared to respective alkanes and as the carbon number increased, this ratio decreased. Kinetics of the formation of naphtha group of compounds (C5–C12) were derived using the advanced isoconversion method. The activation energies in the range of 41–206kJ/mol were lower than for the entire decomposition process. However, because the compound evolution signals as detected by mass spectrometry are noisier than the overall weight loss data, the uncertainties in these measurements were much greater in certain conversion ranges. Similar principles can be used to derive single component evolution kinetics. [Copyright &y& Elsevier]

Abstract: Paraffinic waxes precipitate from bulk oil when oil temperatures are lower than the oil wax appearance temperature. The oil can form a gel if the temperature goes below the pour point, especially under quiescent conditions. The strength of the gelled waxy oil increases as temperature decreases further. Application of a mechanical shear deforms and fractures the gel. It is shown that this strength reduction in the gel is irreversible under isothermal conditions. In subsequent cooling, the prior fractured gel even showed much less yield stress than the gel from the shear-free condition at measured temperature. This study explored the gel strength behavior in water-in-oil (w/o) emulsion state. Three different model oils, water-free oil, 10wt.% w/o and 30wt.% w/o, were used to determine the yield stress using vane method. Both emulsified oils showed less yield stress values at temperatures between the pour points and ice temperature. Compared to water-free oil at temperatures below ice formation, the higher yield stresses were observed in 10wt.% w/o oil; however, the lower yield stresses in 30wt.% w/o oil. Subsequent cooling option after prior gel breakage was also examined. [Copyright &y& Elsevier]

In this study, macro- and micro-geomechanical properties of shales were investigated at millimeter- and micrometer-scale using an example of the Woodford Shale. Geomechanical properties, such as uniaxial (unconfined) compressive strength and Young's modulus, were quantified at the millimeter-scale and compared with results from micro-compression testing experiments of FIB-SEM-nanofabricated micro-pillars. Size-scale and compositional/structural heterogeneity effect on elasto-plastic deformation and failure behavior of shales were investigated. Also, relationship between elemental/mineral composition and unconfined compressive strength and Young's modulus, at a micrometer-scale, was discussed. It was shown that geomechanical properties of shales are scale-dependent and are strongly affected by compositional/structural anisotropy. In particular, micro-compression testing experiments showed non-uniformly distributed compressive strength and Young's modulus within the investigated Woodford Shale rock samples. It was demonstrated, that geomechanical properties of shales, investigated at the micrometer-scale, tend to be affected by different minerals and/or pores, while the same properties, investigated at the millimeter-scale, are governed by different micro-facies (and/or micro-fractures) present within the rock. This shows that geomechanical properties of shales can be dramatically different depending on the scale of investigation and compositional/structural heterogeneity of these rocks, and therefore are not easily transferable across the scales. • Two novel millimeter- and micrometer-scale uniaxial compression testing procedures were developed and applied to study geomechanical properties of shales. • Geomechanical properties of shales are scale-dependent and are strongly affected by compositional/structural heterogeneity of these rocks. [ABSTRACT FROM AUTHOR]

Abstract Natural gas is widely abundant and relatively inexpensive. As such, large quantities are flared every year. This presents an opportunity to use natural gas as a chemical feedstock. Non-oxidative dehydroaromatization of methane, the major component of natural gas is proposed as an option to monetize natural gas. This study evaluates the economics of the methane to benzene process. A catalytic membrane reactor model written in MATLAB has been directly implemented in an Aspen Plus V9 process model using CAPE-OPEN interoperability. Minimum utility requirements and heat exchanger designs were identified in Aspen Energy Analyzer, and process economics for a variety of feed and product prices were assessed using Aspen Process Economic Analyzer. The results indicate that the venture is profitable (profitability index of 1.17, IRR of 35.5%, NRR of 18.2%). The capital cost was found to be $35,500 per daily standard barrel of benzene. Additionally, the process remains economically attractive so long as either the price of benzene remains above $470/ton, or the price of hydrogen remains above $0.8/kg. Highlights • Non-oxidative conversion of methane to benzene is reaction equilibrium-limited. • Techno-economic analysis of a process with catalytic membrane reactor was evaluated. • Thermal pinch analysis was used for energy targets and heat exchange network design. • The venture is profitable (profitability index of 1.17, IRR of 35.5%, NRR of 18.2%). • Price of benzene and hydrogen must be greater than $470/mt and $0.8/kg, respectively. [ABSTRACT FROM AUTHOR]

In the direct nonoxidative conversion of methane gas to liquid chemicals, it has been shown that continuous removal of produced hydrogen is a way to overcome the thermodynamic limit of low equilibrium methane conversion. A plug-flow, isothermal membrane reactor model was developed for the conversion of methane gas to aromatics over Mo/H-ZSM5 and integrated in an Aspen Plus process model using COCO (CAPE-OPEN to CAPE-OPEN) Simulator. Parameters such as reaction rate constants and equilibrium coefficients required by the model were obtained using experimental data. The reactor employs a simplified reaction network whose product distributions agree well with other models and published results. Damkohler number of 0.5 and a dimensionless hydrogen removal parameter δ of 10 were found to be the optimum parameters for benzene selectivity. The reactor model being embedded in the process allows for more detailed exploration of the impact of reactor parameters on the process as a whole. Methane conversion remains at 10.9% and 20% for each case with or without recycle. Benzene molar flow increases by 72% for the single pass configuration when Da = 0.5 and δ = 10 are used; however, naphthalene molar flow increases by 215%. [ABSTRACT FROM AUTHOR]

Enhanced geothermal system (EGS) is often envisioned to consist of at least two wells spaced sufficiently apart and connected by hydraulic fractures that serve as flow paths. All the flow paths must be utilized efficiently to ensure the system is operated at its highest potential. However, building an efficient and sustainable EGS is a complicated process as the fluid always chooses the path of least resistance, which can lead to uneven flow distribution. This study focuses on several critical parameters related to well designs, which can potentially allow for optimized flow distribution. An analytical model (written in Python) is developed based on Kirchhoff's law to calculate the flow distribution in any doublet EGS. Wellbore perforations, the completed wellbores and the fractures are simulated as resistance while the fluid is simulated as a current analog. The model solves the pressure at each node, analogous to voltage, using pipe flow equations and Darcy's law. Three different doublets EGS designs (parallel, anti-parallel and non-parallel) were simulated using the model, and a detailed sensitivity study was performed. Anti-parallel doublet systems perform the best in terms of better fluid distribution and at a lower frictional loss. It was also observed that the flow distribution in a doublet system can be affected by fracture permeability, perforation size and flow rate. Higher permeability fracture leads to poor fluid distribution. Smaller perforation size improves the fluid distribution, but it leads to huge frictional losses. Low flow rates also help with optimized fluid distribution but would eventually lead to low heat output. [ABSTRACT FROM AUTHOR]

Abstract: The accuracy and hence the validity of reservoir simulation results largely depend on the grid system used in the simulation. It is observed that when there is a large difference in permeability between two adjacent layers, conventional grid systems do not accurately predict reservoir behaviors. Grid refinement is used near the well bore and fractures to better resolve the fluid flow between grid blocks. Logarithmically refined grids are commonly applied near the well bore region as there are large changes in pressure and saturation in this zone. Grid refinement must be applied even more carefully when dealing with the production of condensates. Effects of grid refinement on simulation results such as cumulative gas, cumulative oil, condensate–gas ratio (CGR) or gas–oil ratio (GOR), and planar pressure distribution were studied using a generic reservoir model with one horizontal well and one vertical planar fracture for wet gas, gas–condensate and black oil fluids. These results were generated using a full-feature compositional simulator. The results from these studies were used to develop empirical relationships between the dimensionless fracture conductivity and the grid size necessary to achieve converging results. [Copyright &y& Elsevier]

Unconventional reservoirs (e.g., shales) remain poorly understood, compared to conventional reservoirs, due to their complex compositional and structural anisotropy. These heterogeneities profoundly influence petrophysical and geomechanical properties of shales. Current advances in correlative multi-scale and multi-modal 2D/3D imaging provide a tremendous opportunity to image and characterize shales across multiple length scales – from core-to pore-scale. In this study, a Mancos Shale rock sample was characterized across multiple length scales – from a few centimeters to a few nanometers via digital rock analysis using correlative micro 3D X-ray computed tomography (micro-CT), micro 3D X-ray microscopy (micro-XRM), light microscopy (LM), scanning electron microscopy (SEM), and focused ion beam (FIB) – SEM (FIB-SEM) image datasets. These multi-scale/-modal 2D/3D image datasets were then correlated with each other and used to reconstruct digital rock 2D/3D models from which petrophysical properties (porosity and mineralogy) were quantified. Additionally, the SEM/FIB-SEM imaged porosity was compared with bulk porosity measured with the traditional laboratory technique of helium porosimetry. The micro-CT, LM, and (low-resolution) SEM indicated that the investigated Mancos Shale rock sample consisted of interlaminated silt- and mud-rich laminae. The silt-rich laminae were characterized further using micro-XRM, whereas mud-rich laminae were characterized in great detail using high-resolution SEM and FIB-SEM. The SEM and FIB-SEM showed the presence of various fine-grained minerals (clay) and micrometer- and nanometer-sized pores within the mud-rich laminae, whereas micro-XRM showed coarse-grained minerals (quartz) cemented with the mud-rich nanoporous matrix within the silt-rich laminae. Furthermore, the results indicated that micro-fractures significantly contributed to the porosity of the investigated core-plug rock sample. Correlative multi-scale (core- to pore-scale) and multi-modal 2D/3D imaging of shales. Image 1 • A correlative multi-scale/-modal 2D/3D imaging workflow was developed and applied to study structural and compositional heterogeneity of shales. • Correlative X-ray, light, and electron microscopy 2D/3D image datasets were used for qualitative/quantitative image analysis. • Digital rock 2D/3D models were used for characterization of shale petrophysical properties, such as porosity and mineralogy. [ABSTRACT FROM AUTHOR]

Abstract Operational optimization is the key to maximize the heat extraction efficiency of Enhanced Geothermal Systems (EGS). Injection/production flowrate is one of the operational parameters that can be easily manipulated to produce desired amount of energy. In this study, the effect of different flow schemes on the rate of heat production is analyzed over a period of 30 years. Seven flow schemes (four continuous functions namely constant flow, linear flow, exponential flow, mirror exponential flow, and three step functions with step sizes of six months, three years and ten years) developed on the basis of mathematical functions were examined. A doublet EGS model with a single fracture was simulated using a commercial thermal reservoir simulator. The reservoir and well data were obtained from the FORGE (Frontier Observatory for Research in Geothermal Energy) site at Milford Utah. The results were analyzed on the basis of their temperature decline curves for the produced water and the total amount of heat extracted over the entire period. The exponential flow scheme is the optimum case considering the rise in energy demand over the next 30 years. The amount of heat extracted per unit volume of water decreases with increase in total water volume circulated. Highlights • A doublet well system based on data from the FORGE site near Milford, Utah, USA is studied. • Seven different injection schemes are explored to optimize the heat recovery from EGS. • Exponential flow is the optimized water injection scheme in maximizing heat recovery in 30 years. • This study is useful for development and sustainable operation of geothermal power plant. [ABSTRACT FROM AUTHOR]

Silica based crack-free monoliths having the same pore size range as the oil and gas producing north-american shales were synthesized using a new synthesis procedure. Crack-free monoliths were synthesized by controlling the evaporation rate. Evaporation rate of 0.4 g/cm 2 was found optimal for making monoliths in cylindrical enclosures of different sizes for experimentation. The focus of this work was to understand the effects of nano-sized porous media on the saturation pressures of a hydrocarbon mixture of methane and decane. The physicochemical properties of the synthesized monoliths were measured using X-ray diffraction (XRD), nitrogen adsorption/desorption isotherm (BET), pore size distribution curve, transmission electron microscopy (TEM), and scanning electron microscopy (SEM). Differential scanning calorimetry (DSC) and thermogravimetric analysis (TGA) of decane in saturated monoliths revealed different boiling points in comparison to pure decane. The experimentally measured saturation pressures at two different temperatures of the bulk hydrocarbon mixture (decane-methane) matched well with the simulated results. The bubble point pressures of a hydrocarbon mixture in the nano-sized monolith were lower (about 18%) than those in the bulk. [ABSTRACT FROM AUTHOR]

The Vaca Muerta Shale in Argentina is the first major commercial shale oil/gas play outside of North America. High-resolution 2D/3D imaging of shale rocks for the purpose of establishing their mineralogy, total, and connected porosities has become more and more sophisticated. In this paper, nanoscale-resolution focused ion beam (FIB)–scanning electron microscopy (SEM) nano-tomography was used to obtain images of pore structures within two organic-rich regions of interest (ROIs), selected based on correlative SEM and automated mineralogy maps. Advanced machine learning classification tools were used to segment the images and assign porosities and other components. Pore size distribution and pore connectivity analyzes revealed that about 95% of all the pores, present within the two ROIs, had a diameter of less than approximately 75 nm, and that most of these pores were poorly connected. In a similar fashion, the flow rate distribution analysis showed that pores with diameters of about 150–330 nm contributed to over 50% of the flow capacity of the connected pore systems. These results suggest that although most of the pores typically found in shales have pore diameter smaller than about 100 nm, most of the hydrocarbon production may be carried by a relatively small number of larger connected pores with pore diameter greater than about 150 nm. This study implies that a large portion of the organic-hosted pores (with diameter typically smaller than about 100 nm) may not provide permeable flow pathways for the oil and/or gas migration, and hence may have very little contribution to the hydrocarbon production. [ABSTRACT FROM AUTHOR]