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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

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All sourcesNASA NTRSDOE OSTI
DOE OSTI2022

Continuous hydrodeoxygenation of lignin to jet-range aromatic hydrocarbons

Sustainable aviation fuel (SAF) is essential to decrease the carbon footprint of the aviation industry. Although many strategies have been developed to provide the branched, aliphatic components of SAF, few viable strategies have been demonstrated to supply the aromatic and cycloalkane fraction of SAF at the necessary scale from bio-based feedstocks. Lignin is the largest natural source of renewable aromatic compounds, yet major challenges in deoxygenation have prevented its use as a feedstock for SAF. Here we report a continuous, two-stage catalytic process using molybdenum carbide to deoxygenate lignin from poplar into aromatic hydrocarbons with 87.5% selectivity towards aromatic hydrocarbons at 86% of the theoretical carbon recovery. This work demonstrates an effective approach to convert lignin into aromatic SAF blendstocks.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2024

Hydrogen storage and geo-methanation in a depleted underground hydrocarbon reservoir

Coupling of power-to-gas processes with underground gas storage could effectively allow surplus electricity to be stored for later use. Depleted hydrocarbon reservoirs could be used as stores, but practical experience of hydrogen storage in such sites is limited. Here we present data from a field trial that stored 119,353 m 3 of hydrogen admixed to natural gas in a depleted hydrocarbon reservoir. After 285 days, hydrogen recovery was 84.3%, indicating the process’s technical feasibility. Additionally, we report that microbes mediated hydrogen conversion to methane. In laboratory experiments studying mesocosms that mimic real reservoirs, hydrogen and carbon dioxide were converted to methane (0.26 mmol l —1 h —1 evolution rate) reproducibly over 14 cycles in 357 days. This rate theoretically allows 114,648 m 3 of methane per year to be produced in the test reservoir (equivalent to ~1.08 GWh). Our research demonstrates the efficiency of hydrogen storage and the importance of geo-methanation in depleted hydrocarbon reservoirs.

08 HYDROGEN↗
DOE OSTI2023

Methane foam performance in oil-wet unconsolidated porous media: A systematic experimental investigation at reservoir conditions

Methane foam performance was systematically evaluated using high-pressure and high-temperature experiments performed on oil-wet proppant packs. The sensitivities of foam performance to various key factors, including surfactant concentration, foam quality, total injection rate, salinity, operating pressure, and initial oil saturation were examined. The results showed that even though the foamability and foam strength in oil-wet proppant packs were adversely affected by wettability and presence of oil, the steady-state pressure drops across the proppant packs were insensitive to the quantity of oil initially present. The presence of oil above the critical oil saturation impeded the onset of foam generation. This suggested that the foamability of surfactants depends on the synergetic effects of surfactant’s ionic nature and foam parameters, such as foam quality and total injection rate, on their ability to reduce the oil saturation to a threshold value below which favorable bubble generation sites could be created. It was observed that, for low injection rate, anionic surfactant was ineffective at low salinity conditions, while amphoteric agent performed well at all salinities. Additionally, an increase in salinity resulted in enhanced pressure drop across the proppant packs for both anionic and amphoteric surfactants. Further, the results also established that too high operating pressures are somewhat detrimental to the foam strength and stability, irrespective of the ionic nature of foaming agents and the wettability of the porous medium. For the anionic surfactant, the increase in the total flow rate was found to mitigate the adverse effects of low salt concentration and operating pressure. Results from quality-sensitivity foam tests identified two regions for the foam behavior, named low-quality and high-quality regimes, separated by the transition foam quality. Finally, we discuss the implications of the results for the design and effective implementation of enhanced oil recovery (EOR) schemes that deploy hydrocarbon-based foams.

02 PETROLEUM↗
DOE OSTI2022

Unique Role of GeO 2 as a Noninvasive Promoter of Nano‐Sized Zeolite Crystals

Abstract The synthesis of zeolites with nano‐sized dimensions is often limited to a narrow design space that conventionally relies upon the design of organics to direct hierarchical materials. Here, it is demonstrated that the addition of an inorganic modifier, germanium oxide (GeO 2 ), to a zeolite growth mixture directs the formation of crystals with ultrasmall dimensions. This effect is observed for zeolites ZSM‐11 and ZSM‐5 over a range of synthesis conditions wherein the role of GeO 2 in zeolite crystallization deviates from its typical function as a heteroatom. Notably, the final products contain trace amounts of Ge, which indicates the inorganic modifier does not compete for sites in the zeolite framework based on its formation of a discrete phase that enables GeO 2 recovery. Catalytic tests using the methanol‐to‐hydrocarbons reaction reveal significant enhancement in the performance of zeolite catalysts prepared with GeO 2 compared to reported examples of nano‐sized zeolites. These findings highlight a potentially generalizable and commercially viable synthesis method to reduce mass‐transport limitations in zeolites for diverse applications.

Chemistry↗
DOE OSTI2020

Mechanistic Approach to Analyzing and Improving Unconventional Hydrocarbon Production [Slides]

DOE research is developing the physical basis and tools needed to manage pressure effectively to increase recovery efficiency. By coupling fast, accurate physics with machine learning, DOE is producing science-based platforms any operator can use. DOE’s research portfolio is targeting hydrocarbon transport at multiple scales, with the goal of increasing recovery efficiency. DOE’s research has led to new, fast & accurate platforms for predicting gas production from fractured shales. Using data from the MSEEL-I site to calibrate our physics-based model, we have early results on pressure management. We have shown that both mechanical and chemical processes in the matrix can negatively impact production.

08 HYDROGEN↗
DOE OSTI2024

Simultaneous optimization of simulated moving bed adsorption and distillation for 2,3‐butanediol recovery

Abstract A combined simulated moving bed (SMB) and distillation separation scheme is developed to recover 2,3‐butanediol (BDO) from a dilute fermentation broth. The scheme was integrated into a lignocellulosic biorefinery that produces hydrocarbon fuels from corn stover with BDO as an intermediate. BDO recovery is one of the most challenging processes in this biorefinery; and given the high associated energy duties, direct distillation is considered cost‐prohibitive. An alternative separation is SMB adsorption in nanoporous materials, which can reject 90% of the water and reduce subsequent distillation costs. Rigorous models were used to optimize the SMB and distillation simultaneously. The separation can be added to the biorefinery while keeping the projected minimum fuel selling price (MFSP) below $0.66 USD (US dollars) per liter gasoline‐equivalent ($2.50/GGE, gallon gasoline equivalent). Finally, sensitivity analyses were conducted to assess the effects of cost and lifetime of the adsorbent, titer concentration, and BDO purity.

09 BIOMASS FUELS↗
DOE OSTI2023

Catalytic Upgrading of Carbohydrates in Waste Streams to Hydrocarbons: Paper Sludge to Fuel Project (PStF)

This research, funded by the Department of Energy Bioenergy Technologies Office (DOE BETO), aims to understand the barriers and assess opportunities for transforming carbohydrates in paper sludge, a solid lignocellulosic residue from the pulp and paper industry. The goal is to turn the paper sludge into a liquid hydrocarbon product that can be blended into jet fuel, both economically and sustainably. Research groups at North Carolina State University, National Renewable Energy Laboratory, and Yale University collaborated synergistically, leveraging their expertise in pulp and paper operations, biomass deconstruction, and catalytic upgrading to propose a pathway that efficiently captures the energy in paper sludge. Findings from this study could potentially contribute to advancing biomass conversion technologies, aligning with the efforts of the U.S. DOE BETO. This report documents the experimental and simulation results of a biochemical and catalytic pathway designed to transform paper sludge into a liquid hydrocarbon product. The process involves a sequence of seven steps, including ash removal, carbohydrate enzymatic hydrolysis, sugar dehydration, solvent recovery, aldol-condensation between furans and ketone, hydrogenation, and hydrodeoxygenation to obtain a hydrocarbon blend in the ~C10 range. The experimental efforts from the initiation of the project were guided by techno-economic analysis (TEA) and sensitivity analysis results including around seventy-eight operational parameters. This methodology facilitated the efficient use of resources over time. This study relies on detailed process simulations and TEA to determine the minimum fuel selling price (MFSP) for the hydrocarbon fuel product. Preliminary TEA results led to the evaluation of eight case studies considering alternative dehydration co-solvents, operational settings, and biorefinery layouts. Finally, the life cycle assessment of twenty-eight scenarios, comparing various dehydration co-solvents, fuel sources, chemical feedstock sources, side product utilization, and other process settings, was conducted. Landfilling scenarios with and without landfill gas recovery were also estimated, analyzed, and compared.

09 BIOMASS FUELS↗
DOE OSTI2019

Development and application of a machine learning based multi-objective optimization workflow for CO 2 -EOR projects

Carbon dioxide-Enhanced Oil Recovery (CO 2 -EOR) is known as one of techniques for hydrocarbon production improvement as wells as an important candidate to reduce greenhouse gas emissions. Thus, an ideal development strategy for a CO 2 -EOR project would consider multiple objectives including to maximize oil recovery, CO 2 storage volume and project economic outcomes. This work proposes a robust computational framework that couples artificial neural network (ANN) and multi-objective optimizers to optimize the aforementioned objectives in CO 2 -EOR processes simultaneously. Expert ANN systems are trained and employed as surrogate models of the high-fidelity compositional simulator in the optimization workflow. The robustness of the development optimization protocol is confirmed via a synthetic injection-pattern-base case study. Afterward a field implementation to Morrow-B formation to optimize the tertiary recovery stage of the field development is discussed. This work compares the optimum solution found using an aggregate objective function and the solution repository (Pareto front) generated by the multi-objective optimization process. The comparison indicates the existence of potential multi-solutions satisfying certain criteria in a CO 2 -EOR project designing, which cannot be found using traditional weighted sum method. The optimization results provide significant insight into the decision-making process of CO 2 -EOR project when multiple objective functions are considered.

02 PETROLEUM↗
DOE OSTI2020

Analysis of Transient Pressure and Rate Data in a Complex of Enhanced Oil Recovery Fields in Northern Michigan

The Midwest Regional Carbon Sequestration Partnership (MRCSP) was founded in 2003 as part of the U.S. Department of Energy’s (DOE’s) Regional Carbon Sequestration Partnership initiative. Since its founding, MRCSP has made significant strides toward making CCUS a viable option for states in the region. The public/private consortium, funded through the DOE Regional Carbon Sequestration Initiative, brings together nearly 40 industry partners and 10 states. Battelle, as the project lead, oversees research, development and operations and coordinates activities among the partners. The incremental, phased approach has built a valuable knowledge base for the industry and paved the way for commercial-scale adoption of CCUS technologies. From 2008 to 2020, MRCSP Phase III focused on the development of large-scale injection projects. This report is part of a series of reports prepared under the Midwestern Regional Carbon Sequestration Partnership (MRCSP) Phase III (Development Phase). These reports summarize and detail the findings of the work conducted under the Phase III project. A key activity of the MRCSP monitoring program was to continuously monitor the CO 2 injection and bottom-hole reservoir pressure in the injection wells and selected monitoring wells in the study reefs from 2013 through 2019. During the monitoring period, which varied from reef to reef, the reefs were undergoing one or more phases of development, such as CO 2 injection without hydrocarbon production, CO 2 injection with production Enhanced Oil Recovery (EOR), production without CO 2 injection, and idle (no injection or production) in pressure depleted condition. A multi-year record of reservoir pressure and injection rate data are available for one or more wells for each reef for analysis. This report discusses the methodology and results of various types of analyses performed with this data, with the primary objective of characterizing the in-situ permeability of the formation of interest.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2022

CO2 Enhanced Oil Recovery Improvement in Conventional Fields Using Rich Gas

Research Hypothesis: The injection of a blend of rich hydrocarbon gas and CO2 into an oil reservoir will reduce molecular weight (MW) selectivity, lower minimum miscibility pressure (MMP) and viscosity of the oil, and improve gas solubility, resulting in an overall improvement in enhanced oil recovery (EOR) performance.

99 GENERAL AND MISCELLANEOUS↗
DOE OSTI2021

Catalytic degradation of waste rubbers and plastics over zeolites to produce aromatic hydrocarbons

Catalytic conversion of waste rubbers and plastics into aromatic hydrocarbons is a promising approach to waste management and energy recovery. In the present study, acidic HY zeolites were supported by cobalt, iron, and zirconium, and the catalysts were characterized by powder X-ray diffraction, nitrogen adsorption-desorption, ammonia temperature programmed desorption, X-ray photoelectron spectroscopy, and pyridine-Fourier transform infrared spectroscopy. Here, the catalytic degradation of waste polybutadiene rubbers (BR) was conducted to investigate the degradation mechanism and evaluate the catalytic activity of supported zeolites. Experimental results indicated that HY loaded by zirconium and iron led to a higher content of Lewis acid sites as opposed to cobalt supported one. Compared with the non-catalytic pyrolysis of BR, the zirconium supported HY (Zr/HY) led to a 10-fold increase in aromatic hydrocarbons production with a distinctively high selectivity of 97.9%. A series of waste polymers including waste tires (WT), polyethylene (PE), polycarbonate (PC), and BR, were subjected to catalytic pyrolysis to explore the effects of polymer type on aromatic hydrocarbons generation, and BR was the most effective substrate, with yield enhancement reaching 2.4 over Zr/HY. Catalytic co-pyrolysis of waste rubbers and plastics was conducted to probe the effect of polymer structure on aromatic hydrocarbons formation, where a significant synergistic effect was observed in the PE co-fed with PC run.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2022

Measurement and modeling of methane diffusion in hydrocarbon mixtures

Methane (CH 4 ) dissolution and diffusive mass transfer in liquid hydrocarbon mixtures is of key interest in the context of enhanced oil recovery from tight shales. In this paper, we have studied CH 4 dissolution and diffusion in normal alkane mixtures at a temperature of 50 ⁰C and at pressures of ~8 MPa. For the measurement of CH 4 dissolution/diffusion in bulk liquid hydrocarbon mixtures, we have utilized a high pressure and temperature, constant-volume diffusion (CV-D) setup. Here, we have studied CH 4 diffusion in mixtures with three long-chain normal alkanes: decane (C 10 ), dodecane (C 12 ) and hexadecane (C 16 ). We have measured CH 4 solubility and diffusion in its binary mixtures with each of these three normal alkanes, as well as in ternary and quaternary mixtures. During the experiments, the swelling of the liquid mixture due to CH 4 dissolution was measured in situ via a cathetometer and was subsequently integrated into the data analysis. A key conclusion from this study is that the solubility and transport properties of the multicomponent mixtures can be predicted accurately from binary mixture measurements using an appropriate Equation of State (EOS) and Wilke’s simplification of the classical Maxwell-Stefan (MS) diffusion theory. This observation can facilitate accurate prediction of diffusive mass transfer in more complex liquid hydrocarbon mixtures.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2022

Findings on Subtask 3.1 - Bakken Rich Gas Enhanced Oil Recovery Project

Total in-place oil for the Bakken petroleum system (BPS) (which includes the Bakken and Three Forks Formations) has been estimated to be 600 billion barrels (bbl). However, BPS wells have decline rates as high as 85% over the first 3 years of their lives, and primary recovery factors typically range from 3% to 10% of original oil in place. Given the low initial recovery rates, even small incremental productivity improvements could dramatically increase technically recoverable oil in the BPS. One potential solution is enhanced oil recovery (EOR) using gas injection, such as carbon dioxide (CO2) or hydrocarbon (HC) gases. While commonly used in conventional reservoirs, CO2 EOR in unconventional tight oil reservoirs has been limited to pilot tests. EOR using rich gas (mixture of methane, ethane, and propane) has also been employed in numerous pilots in several unconventional plays and has recently been successfully applied in the Eagle Ford play. If successful, large-scale gas-based EOR in the BPS could dramatically increase oil productivity and recovery factors and extend the life of the play for decades. While CO2 may be a technically suitable working fluid for EOR in the BPS, supplies are limited and costs for using CO2 in EOR pilots are prohibitively high. Meanwhile, produced gas flaring has presented challenges for BPS operators in North Dakota. Analysis conducted by the North Dakota Pipeline Authority indicates that the current gas-gathering infrastructure in North Dakota is insufficient to accommodate all of the associated gas that is produced from the BPS. The geographically isolated location of North Dakota relative to large natural gas markets, combined with suppressed natural gas prices, has made it economically challenging for industry to invest capital in expanding gas-gathering infrastructure in the state. These circumstances led to a research program conducted by the Energy & Environmental Research Center (EERC) in partnership with Liberty Resources Management Company LLC (LR) to examine the potential to use rich gas injection for EOR and mitigate flaring. A rich gas EOR pilot test was designed and executed by LR at its Stomping Horse development area in Williams County, North Dakota. From July 2018 through May 2019, a total of 160 million standard cubic feet (MMscf) of rich produced gas was injected into the BPS using five different wells in a sequential injection strategy. LR’s Leon–Gohrick drill spacing unit (DSU) was used as the test site. Regulatory oversight was provided by the North Dakota Industrial Commission (NDIC). Technical support was provided by the EERC through a series of laboratory, modeling, and field-based activities, and additional post-pilot research activities incorporated learnings from the test, developed new laboratory data, improved fracture modeling methods, and developed machine learning and big data analytics. The results from the Stomping Horse rich gas EOR pilot activities indicate that developing an effective, economical EOR approach for the BPS will require more field tests. Another key lesson learned from the Stomping Horse tests is that detailed pre- and posttest data on reservoir conditions and fluids production are essential. Robust reservoir characterization provides information that is crucial to creating realistic geomodels and conducting valid dynamic simulations of potential EOR scenarios. A detailed understanding of the completions and production history of offset wells is also necessary for valid test result interpretations. This knowledge is essential to designing the operational parameters of injectivity tests and interpreting the results. A conformance control strategy is also essential to success. Laboratory-based examinations of rich gas interactions with reservoir fluids and rocks were conducted, with an emphasis on determining the ability to mobilize oil in the tight reservoir rocks and shales of the BPS. Injection fluid composition was shown to have a positive impact on reducing reservoir oil minimum miscibility pressure (MMP), reducing interfacial tension (IFT), and altering wettability. IFT and contact angle measurements demonstrated that wettability can be altered in the presence of rich gas, suggesting the potential to improve oil recovery. Iterative modeling of surface infrastructure and reservoir performance using data generated by the various project activities was conducted. A geologic model of the Stomping Horse area was built; history-matched oil, gas, and water production was used in simulations of various EOR scenarios. Early programmatic modeling results were used to support LR’s design and operation of the EOR pilot and to provide insight regarding optimization of future commercial-scale BPS EOR design and operations. Post-pilot modeling focused on alternative methods of understanding complex fracture networks and accelerating simulation time. These led to improved simulation run times and provide excellent history-matching results. Several of these iterative models were used as the bases for developing algorithms into machine learning and big data analytics. History matching in reservoir simulation is time-consuming and computer processing-intensive. Machine learning algorithms were created, and an automated history-matching tool was developed. A large set of synthetic reservoir simulations were created to generate well responses (oil, gas, and water production, well bottomhole pressure [BHP], and tracer or propane breakthrough) for a set of EOR operating parameters that included offset well status (open or closed), injectate (rich gas or propane), injection rate, and injection well BHP. A user interface was developed to provide real-time visualization. Machine learning-based models were developed to provide rapid forecasting of well performance given a set of user-defined EOR operating parameters. These predictive models allow the user to modify the offset well status, injection rate, and injection well BHP and rapidly forecast future production performance. The combination of real-time visualization tools with real-time forecasting tools provides a framework for real-time control—operational changes that the EOR site operator can enact (e.g., changing gas injection rates) to affect the observed performance and potentially improve the EOR outcome. There is great reason to be optimistic about the future of EOR in the Bakken. The results of the laboratory studies suggest significant potential for high rates of oil mobilization using produced field gas injection under the right conditions. The results of the lab studies, combined with rigorous statistical analysis of well production data and associated modeling efforts, confirm the notion that fluid mobility within the reservoir is controlled by fractures. As more knowledge is gained about the nature and distribution of fracture networks in the Bakken, the industry will be in a better position to predict and, ultimately, influence fluid mobility. New field tests are necessary to develop a more complete understanding of those conditions. Thoughtful and creatively engineered field tests within a well-characterized geologic setting will yield the fundamental knowledge needed to take Bakken oil production to the next level. This subtask was cofunded through the EERC–U.S. Department of Energy Joint Program on Research and Development for Fossil Energy-Related Resources Cooperative Agreement No. DE-FE0024233. Nonfederal funding was provided by the North Dakota Industrial Commission’s Oil and Gas Research Program and Computer Modelling Group.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2024

Experimental and numerical investigation of fracture conductivity between non-smooth rock surfaces with and without proppant

The enhancement of fracture conductivity is vital for the efficient recovery of subsurface resources, such as geothermal energy and petroleum hydrocarbons. Proppants, granular materials injected into hydraulic fractures to maintain their conductivity, have been studied primarily in the context of smooth fractures (i.e., fractures between smooth rock surfaces). However, non-smooth fractures (i.e., fractures between rough rock surfaces) are common in geoenergy reservoirs and thus require further investigations. In this study, we conducted laboratory measurements of fracture conductivity on shale slabs with non-smooth surfaces and carried out numerical simulation using the lattice Boltzmann (LB) method, which aimed to investigate the conductivity of non-smooth fractures with and without proppants placement. When ceramic proppant with an areal concentration of 2 lb/ft 2 was placed in the fracture, the conductivity was enhanced by roughly 3-8 times compared to fractures without proppant. In fractures with proppant, gas-measured conductivity was higher than that measured with water due to proppant embedment caused by water. The experiments demonstrate the advantages of using proppant in fractures, even if the rock surface roughness can provide certain fracture conductivity via the self-propping mechanism. For fractures without proppants, high rock surface roughness is not necessarily favorable for enhancing fracture conductivity because the self-propping mechanism requires shear slip along the fracture surface. If there is no shear slip, high rock surface roughness can cause a detrimental effect on the fracture conductivity due to the interlocking effect. Utilizing advanced experimental equipment and LB modeling, this research explores the interplays between proppant placement, fracture geometry, and stress conditions to develop a comprehensive understanding of the productivity in non-smooth fractures. Further, the outcomes of this investigation indicate the importance of creating fractures with surface roughness during hydraulic fracturing and will contribute to the development of more efficient stimulation techniques for subsurface energy extraction.

15 GEOTHERMAL ENERGY↗
DOE OSTI2026

Closing the loop on plastics: Biological and hybrid routes for converting plastic waste to polyhydroxyalkanoates

Polyhydroxyalkanoate (PHA) production from plastic-derived substrates offers a promising route to mitigate plastic pollution while reducing dependence on conventional PHA feedstocks. Plastic waste represents an abundant carbon source for microbial fermentation, but efficient conversion remains limited by incomplete deconstruction, inhibitory intermediates, low carbon recovery, and challenges in process integration. Plastic-derived streams contain diverse compounds, including fatty acids, hydrocarbons, fatty alcohols, aldehydes, esters, and aromatic compounds generated during depolymerization. These intermediates can be metabolized by selected microorganisms, particularly Pseudomonas species with versatile fatty-acid and hydrocarbon pathways, as well as Cupriavidus necator and mixed microbial cultures. Unlike reviews that address plastic upcycling or PHA biosynthesis separately, this review focuses on the deconstruction–fermentation interface that governs plastic-to-PHA conversion. It consolidates current progress in plastic deconstruction, substrate conditioning, microbial metabolism, fermentation control, polymer recovery, and techno-economic and life-cycle considerations. Here, by emphasizing substrate composition, biological compatibility, plastic‑carbon recovery, and final polymer quality, the review identifies priorities for scalable and environmentally sustainable PHA production from plastic-derived substrates.

42 ENGINEERING↗
DOE OSTI2021

Reactivity of CO 2 with Utica, Marcellus, Barnett, and Eagle Ford Shales and Impact on Permeability

We report that in order to reduce greenhouse gas emissions while recovering hydrocarbons from unconventional shale formations, processes that make use of carbon dioxide to enhance oil recovery while storing carbon dioxide (CO 2 ) should be considered. Here, we examine samples from three shale basins across the United States (Utica and Marcellus Shales in the Appalachian Basin, Barnett Shale in the Bend Arch-Ft. Worth Basin, and Eagle Ford in the Western Gulf Basin) to address the following questions: (1) do changes from reaction with CO 2 and fluids at the micrometer and nanometer scale alter flow pathways and, in turn, impact hydrocarbon production, CO 2 storage, and seal integrity and (2) can CO 2 or fluid reactivity be predicted based on physical or chemical properties of shale formations? Experiments were conducted at 40 °C and 10.3 MPa to characterize the interaction between CO 2 and shale using X-ray diffraction (XRD), carbon and sulfur analysis, in situ Fourier transform infrared spectroscopy (FT-IR), feature relocation scanning electron microscopy coupled with energy-dispersive spectroscopy (SEM-EDS), mercury (Hg) intrusion porosimetry, and Brunauer-Emmett-Teller (BET) surface area and pore size analysis coupled with density functional theory (DFT) methods. Changes in mechanical, physical, and flow properties of shale cores due to CO 2 exposure were addressed using a New England Research Autolab 1500 and Xenon X-ray computed tomography (CT) scanning. Results showed that CO 2 did not promote significant reactivity with the shale if water was not present; only shales with swelling clays or residual interstitial pore water reacted with dry CO 2 to promote reactivity in shale. When water was added as a reactant, CO 2 formed carbonic acid and reacted with the shale to dissolve carbonate pockets, etched and pitted the shale matrix surfaces, and increased the microporosity and decreased nanoporosity. Porosity and permeability increased appreciably in core shale samples after exposure to CO 2 saturated fluid due to dissolution of carbonate. Shale mechanical properties were not altered. Trends were not observed that could tie CO 2 or fluid reactivity to physical or chemical properties of the shale formations at the basin scale from the samples we examined. However, if the shale contained significant amounts of carbonate and water was available to react with the CO 2 , pore sizes were altered in the matrix and permeability and porosity increased.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2020

Impacts of Mixed-Wettability on Brine Drainage and Supercritical CO 2 Storage Efficiency in a 2.5-D Heterogeneous Micromodel

Geological carbon storage (GCS) involves unstable drainage processes, the formation of patterns in a morphologically unstable interface between two fluids in a porous medium during drainage. The unstable drainage processes affect CO 2 storage efficiency and plume distribution and can be greatly complicated by the mixed-wet nature of rock surfaces common in hydrocarbon reservoirs where supercritical CO 2 (scCO 2 ) is used in enhanced oil recovery. Here, we performed scCO 2 injection (brine drainage) experiments at 8.5 MPa and 45°C in heterogeneous micromodels, two mixed-wet with varying water- and intermediate-wet patches, and one water-wet. The flow regime changes from capillary fingering through crossover to viscous fingering in the micromodels of the same pore geometry but different wetting surfaces at displacement rates with logCa (capillary number) increasing from –8.1 to –4.4. While the mixed-wet micromodel with uniformly distributed intermediate-wet patches yields ~0.15 scCO 2 saturation increase at both capillary fingering and crossover flow regimes (–8.1 ≤ logCa ≤ –6.1), the one heterogeneous wetting to scCO 2 results in ~0.09 saturation increase only at the crossover flow regime (–7.1 ≤ logCa ≤ –6.1). The interconnected flow paths in the former are quantified and compared to the channelized scCO 2 flow through intermediate-wet patches in the latter by topological analysis. At logCa > –6.1 (near well), the effects of wettability and pore geometry are suppressed by strong viscous force. Both scCO 2 saturation and distribution suggest the importance of wettability on CO 2 storage efficiency and plume shape in reservoirs and capillary leakage through caprock at GCS conditions.

58 GEOSCIENCES↗
DOE OSTI2022

Using Natural Gas Liquids to Recover Unconventional Oil and Gas Resources (Final Report)

This document presents final technical findings for the project Using Natural Gas Liquids to Recover Unconventional Oil and Gas Resources (FE0031782). The project is part of the U.S. Department of Energy Oil and Gas Program to develop and advance technologies that can significantly improve the recovery efficiencies of unconventional oil and gas resources. The overall objective of this project is to improve the ultimate recovery from unconventional oil and gas (UOG) resources in the United States by developing a method for using unrefined natural gas liquids (NGLs) as treatment fluids to improve hydrocarbon production. Horizontal extended-lateral drilling coupled with high volume hydraulic fracturing has significantly increased production from UOG resources in the U.S. However, the recovery efficiency is low compared to the estimated oil and gas in place. Recent data indicate that less than 10% of the oil in the liquid-rich UOG reservoirs is produced. Alternative completion methods using NGLs could increase production (Battelle, 2016; Wan et al., 2013; Wan, 2013; Downey et al, 2021); however, field validation tests are needed to develop an approach that is economical, efficient, and compatible in the UOG setting to advance towards commercial deployment. This project aims to develop and field test a method to improve recovery of oil resources in UOG shale plays by using Y-Grade NGLs, or a similar combination of NGLs, as treatment fluids. Refined NGLs have been used as a hydraulic treatment fluid in UOG plays for decades and are shown to be particularly effective because their miscibility with oil allows oil to flow more freely; however, the use of Y-Grade (unrefined) NGLs has not been studied. The use of Y-Grade NGLs would be advantageous over refined NGLs because Y-Grade NGLs do not require infrastructure or investment in refining and are already being produced from many UOG reservoirs. The concept was tested and monitored in the field at a commercial well site owned by project partner Hopco, Ltd. The project team, which consists of multiple oil and gas operators, Linde Gas North America LLC (Linde) and the Ohio Division of Geological Survey (ODGS), has extensive experience with oil and gas production in the Appalachian basin and the ability to work together quickly to solve technical issues and research needs. A key part of the proposed work was the use of existing wells for field testing and monitoring. A total of four wells (three vertical and one horizontal) were available for this project. One of the vertical wells was utilized as the test well for the NGL treatment test. A nearby vertical well was used for microseismic monitoring. The remaining vertical well and the horizontal well provided a baseline for typical UOG production in the oil window of the Utica/Point Pleasant (UPP). Major technical tasks of the project include characterization of the geotechnical properties of the UPP with an emphasis on the field site; design and planning for the NGLs testing; field testing and monitoring; analysis and integration of field data; and economic and resource/reserve assessment. The Shoman monitoring well and Doughty NGL treatment well were successfully plugged back during September-October 2020 in preparation for treatment and monitoring. A nitrogen diagnostic fracture injection test (DFIT) was completed on the Doughty well on July 22, 2021, consisting of 133,000 scf (91 Bbl.) of nitrogen. A nitrogen foam frac was completed in the Utica-Point Pleasant interval on August 17, 2021 with funding from outside sources. A microseismic monitoring array was installed in the Shoman well and monitored microseismic activity during the Doughty well frac job. Y-Grade NGL injection commenced on August 26, 2021. A total of 215 Bbl. was injected but the job was shut down due to a small leak on the suction hose on the pump truck. The Y-Grade treatment resumed on August 27, 2021 and an additional 726 Bbl. of Y-Grade NGL was injected at a well head pressure of 3850 psi. Total volume of injected Y-Grade over the two days of injection was 941 Bbl. The well was shut-in for 17 days following injection to allow the Y-Grade NGLs to soak on the formation. Y-Grade treatment flow back commenced on 9/13/2021 on a weekly basis. Production data, including surface pressures, oil, nitrogen, natural gas, and flow times was measured and recorded. Periodic gas samples were collected and analyzed to determine composition of flowback gas. As of July 2022, the treatment well had produced 726 Bbl of oil and 2,888 mcf gas. In August 2022, tubing and packer in the well were removed and a pump was installed to enhance oil recovery. Currently, the operator is producing the well about 2 days a week for a few hours. The performance of the NGL treatment test was evaluated based on reservoir simulations of the treatment process, processing of well testing data, analysis of micro seismic monitoring data, and production data analysis. This analysis suggested that oil production in the small test would continue through 2025. Upscaling the treatment to a horizontal Utica Point-Pleasant well would allow more oil recovery, but the process would involve more investment, services, and operational support. An economic analysis was conducted for scenarios aimed at upscaling the NGL treatment process for more typical horizontal UPP wells in the Appalachian Basin.

02 PETROLEUM↗