We have studied the hydrocarbon production from oil shale reservoirs filled with diverse initial saturations of fluid phases by implementing numerical simulations of various thermal in-situ upgrading processes. We use our in-house fully functional, fully implicit, and non-isothermal simulator, which describes the in-situ upgrading processes and hydrocarbon recovery by multiphase-multicomponent systems. We have conducted two sets of simulation cases—five-spot well pattern problems and Shell In-situ Conversion Process (ICP) problems. In the five-spot well pattern problems, we have analyzed the effects of initial fluid phase that fills the single-phase reservoir and thermal processes by four cases—electrical heating in the single-phase-aqueous reservoir, electrical heating in the single-phase-gaseous reservoir, hot water injection in the single-phase-aqueous reservoir, and hot CO2 injection in the single-phase-gaseous reservoir. In the ICP problems, we have analyzed the effects of initial saturations of fluid phases that fill two-phase-aqueous-and-gaseous reservoir by three cases—initial aqueous phase saturations of 0.16, 0.44, and 0.72. Through the simulation cases, system response and production behavior including temperature profile, kerogen fraction profile, evolution of effective porosity and absolute permeability, phase production, and product selectivity are analyzed. In the five-spot well pattern problems, it is found that the hot water injection in the aqueous phase reservoir shows the highest total hydrocarbon production, but also shows the highest water-oil-mass-ratio. Productions of phases and components show very different behavior in the cases of electrical heating in the aqueous phase reservoir and the gaseous phase reservoir. In the ICP problems, it is found that the speed of kerogen decomposition is almost identical in the cases, but the production behavior of phases and components is very different. It is found that more liquid organic phase has been produced in the case with the higher initial saturation of aqueous phase by the less production of gaseous phase.

Grade of oil shale and reaction parameters of in-situ pyrolysis must be identified for the prediction of productivity before actual heating and production. Identification of oil shale grade and reaction parameters depends on laboratory experiments on core samples. However, laboratory-determined parameters can be different from those representing in-situ reservoir conditions. In this study, we use inverse modeling to determine oil shale grade and reaction parameters. The inversions are based on a forward model that simulates heat injection into a well. Temperature at the heating well is affected by a thermal skin effect as a result of a decrease of composite thermal conductivity around the heater due to the decomposition-induced porosity increase. Synthetic observations of heater temperature are generated from a forward simulation. Temperature difference and its derivative are used in synthetic inversions to estimate oil shale grade and parameters of active decomposition reactions with an error below 1%. The proposed methodology of inverse modeling is expected to successfully estimate the oil shale grade and reaction parameters without core sampling and subsequent surface experiments.

We investigate the productivity and product selectivity of diverse thermal in situ upgrading processes in oil shale reservoirs. In situ upgrading processes applying the ideas of Shell In situ Conversion Process, ExxonMobil Electrofrac, and Texas A&M Steamfrac are simulated by using sector models with the assumption of symmetric patterns. In-house fully functional simulator is used, which has been developed for the kerogen pyrolysis and hydrocarbon production. In the simulation cases, sensitivity analyses to the factors having major influence on the productivity and product selectivity are conducted. The effects of the temperature of vertical heaters, the spacing of hydraulic fractures, and the position of horizontal production wells are analyzed in the applied In situ Conversion Process, Electrofrac, and Steamfrac, respectively. In the applied In situ Conversion Process cases, hydrocarbon production increases with the increasing heater temperature. In the applied Electrofrac cases, hydrocarbon production increases with the increasing spacing of hydraulic fractures, even though longer time period for the process is needed. In the applied Steamfrac cases, the case of production well located at the same depth to the injection well shows the least hydrocarbon production. Among the processes, the applied In situ Conversion Process cases show the highest weight percentage of total hydrocarbon components in the produced fluid, and the applied Electrofrac cases follow it. The applied Steamfrac cases show far lower weight percentage of hydrocarbon production than the other methods. In terms of the mass ratio of produced hydrocarbon to decomposed kerogen, the applied Steamfrac cases show the largest value among the processes by aqueous phase sweeping liquid organic phase, but they also show the huge water oil mass ratio by the continuous injection of hot water. All the applied In situ Conversion Process cases and the Electrofrac case with the short spacing of hydraulic fractures show good heating efficiency by decomposing whole kerogen in the system.

We conduct numerical simulations of kerogen pyrolysis by the in situ upgrading process of Steamfrac, which entails the steam or hot-water injection into multistage transverse fractured horizontal well systems, by using a fully functional simulator developed to describe the in situ upgrading process. We first conduct simulation cases of a huff-n-puff method to analyze the sensitivity of temperature distribution of the reservoir to the positions of horizontal wells. Then, we conduct continuous hot-water injection and simultaneous fluid production cases, and analyze the productivity by applying two different irreducible saturations of aqueous phase in the rock matrix.

Reaction parameters significantly affect oil production from shales by means of heating and in-situ upgrading. In this study, we perform numerical simulations of two chemical reaction models, which are mainly used in the research of kerogen pyrolysis and subsequent hydrocarbon decomposition in organic-rich porous media. They are the Braun and Burnham model and Wellington model. In these forward numerical simulations, we present the influence of the two reaction models on hydrocarbon production. The Braun and Burnham reaction model shows more vigorous kerogen and subsequent decomposition reactions and more hydrocarbon production than the Wellington model. A local sensitivity analysis identifies the reaction parameters with the highest influence on productivity, and the most sensitive outputs. A data-worth analysis identifies the most valuable observation data to be measured for the best prediction of total hydrocarbon production. We find that the most valuable observation data is the cumulative production of heavy oil in the Braun and Burnham model and of light oil in the Wellington model, respectively. Once we determine the maximum allowable prediction uncertainty and the expected measurement uncertainty, the observation data to be measured for the minimization of prediction uncertainty can be obtained.

Using ambient pressure XPS (APXPS), we explored carbon dioxide (CO2) adsorption and CO2 hydrogenation on Pt(1 1 1) single crystal surface to observe the activation of CO2 and the subsequent reaction mechanism. In pure CO2, we observed CO adsorbates and adsorbed oxygen on Pt(1 1 1) derived from CO2 dissociation at room temperature. The introduction of H2 (at a pressure ratio of 1:1 (H2:CO2)) increased the production of CO across all temperatures by facilitating the removal of surface oxygen. As a consequence, the surface could expose sites that could then be utilized for producing CO. Under these conditions, the reverse water–gas shift (RWGS) reaction was observed starting at 300 oC. At higher H2 partial pressure (10:1 (H2:CO2)), the RWGS reaction initiated at a lower temperature of 200 oC and continued to enhance the conversion of CO2 with increasing temperatures. Our results revealed that CO2 was activated on a clean Pt(1 1 1) surface through the dissociation mechanism to form adsorbed CO and O at room temperature and at elevated temperatures. Introducing H2 facilitated the RWGS as adsorbed oxygen was consumed continuously to form H2O, and adsorbed CO desorbed from the surface at elevated temperatures. This work clearly provides direct experimental evidence for the surface chemistry of CO2 dissociation and demonstrates how hydrogen impacts the RWGS reaction on a platinum surface.

Characterizing the faults and fractures that provide flow pathways for efficient geothermal energy production is critical for design of sustainable geothermal energy production. Both natural faults and stimulated fractures in enhanced geothermal systems (EGS) are difficult to image and map by seismic methods because hot brine filling the fractures and faults does not create a strong seismic property contrast relative to surrounding rock. We investigate here the technical feasibility of using supercritical CO2 (scCO2) injection into faults in a single-well push-pull scenario to characterize the hydraulic properties of the fault zone by emplacing scCO2 that can serve as a contrast fluid for seismic monitoring. We develop a conceptual and numerical reservoir model of two intersecting faults based on the Dixie Valley geothermal system in Nevada, USA. The 2D conceptual model consists of a system with a main fault and an intersecting conjugate fault. The corresponding numerical model is discretized using irregular grid blocks with fine discretization around the slip plane, gouge, and damage zones. We perform forward modeling along with sensitivity and data-worth analyses of scCO2 push-pull to investigate the CO2 distribution in the fault gouge during 30 days of push (injection) and 30 days of pull (production). Formal sensitivity analysis is conducted to determine the most controlling unknown parameters in the fault zones. Using the selected set of unknown parameters and output responses, we perform data-worth analysis to reveal the most valuable output response to be measured for the best prediction of CO2 distribution in the fault zones and its uncertainty. From the results of data-worth analysis, we determine the optimal properties to target in monitoring, their locations, and the minimum observation time. Our results provide information on the optimal design of scCO2 push-pull testing in a conjugate fault system modeled after Dixie Valley that can be used to enhance monitoring by active seismic and well-logging methods to better characterize the transmissive fault(s).

Converting carbon dioxide (CO₂) into liquid fuels and synthesis gas is a world-wide priority. But there is no experimental information on the initial atomic level events for CO₂ electroreduction on the metal catalysts to provide the basis for developing improved catalysts. Here we combine ambient pressure X-ray photoelectron spectroscopy with quantum mechanics to examine the processes as Ag is exposed to CO₂ both alone and in the presence of H₂O at 298 K. We find that CO₂ reacts with surface O on Ag to form a chemisorbed species (O = CO₂^δ-). Adding H₂O and CO₂ then leads to up to four water attaching on O = CO₂^δ- and two water attaching on chemisorbed (b-)CO₂. On Ag we find a much more favorable mechanism involving the O = CO₂^δ- compared to that involving b-CO₂ on Cu. Each metal surface modifies the gas-catalyst interactions, providing a basis for tuning CO₂ adsorption behavior to facilitate selective product formations.

With the goal of detecting and characterizing faults and fractures in enhanced geothermal systems (EGS), a new technology involving CO2 push-pull testing, active-source geophysical imaging, and well logging has recently been proposed. This technique takes advantage of (1) the contrasting properties of supercritical CO2 and water which cause CO2 to appear distinct from surrounding brine in seismic and other geophysical logging approaches, (2) the non-wetting nature of CO2 which keeps it localized to the faults and fractures to create contrast potentially sufficient for active seismic and well-logging approaches to image faults and fracture zones at EGS sites. In this study, we evaluate the feasibility of using pressure transient monitoring during CO2 push-pull tests to complement active seismic and wireline well logging for EGS characterization. For this purpose, we developed a 2D model of a prototypical geothermal site (Desert Peak, NV) that includes a single fault. The fault zone consists of a slip plane, fault gouge, and damage zone, and is bounded by the surrounding matrix of the country rock. Through numerical simulation using iTOUGH2, we found that the pressure transient at the monitoring wells in the fault gouge shows unique traits due to the multiphase flow conditions developed by CO2 injection, and varies sensitively on the arrival of the CO2 plume and the degree of CO2 saturation. A sensitivity analysis shows the pressure transient is most sensitive to the fault gouge permeability, but also depends on multiphase flow parameters and the boundary conditions of the fault. An inversion study reveals that the fault gouge permeability can be best estimated with the pressure transient data, whereas additional CO2 saturation data do not improve the accuracy of the inversion significantly.