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At least 217 records · Page 12
All sourcesNASA NTRSDOE OSTI
NASA NTRS2012

Floating Oil-Spill Containment Device

Previous oil containment booms have an open top that allows natural gas to escape, and have significant oil leakage due to wave action. Also, a subsea pyramid oil trap exists, but cannot move relative to moving oil plumes from deepsea oil leaks. The solution is to have large, moveable oil traps. One version floats on the sea surface and has a flexible tarp cover and a lower weighted skirt to completely entrap the floating oil and natural gas. The device must have at least three sides with boats pulling at each apex, and sonar or other system to track the slowly moving oil plume, so that the boats can properly locate the booms. The oil trap device must also have a means for removal of the oil and the natural gas. A second design version has a flexible pyramid cover that is attached by lines to ballast on the ocean floor. This is similar to fixed, metal pyramid oil capture devices in the Santa Barbara Channel off the coast of California. The ballast lines for the improved design, however, would have winches that can move the pyramid to always be located above the oil and gas plume. A third design is a combination of the first two. It uses a submerged pyramid to trap oil, but has no anchor and uses boats to locate the trap. It has ballast weights located along the bottom of the tarp and/or at the corners of the trap. The improved floating oil-spill containment device has a large floating boom and weighted skirt surrounding the oil and gas entrapment area. The device is triangular (or more than three sides) and has a flexible tarp cover with a raised gas vent area. Boats pull on the apex of the triangles to maintain tension and to allow the device to move to optimum locations to trap oil and gas. The gas is retrieved from a higher buoyant part of the tarp, and oil is retrieved from the floating oil layer contained in the device. These devices can be operated in relatively severe weather, since waves will break over the devices without causing oil leaking. Also, natural gas is entrapped and can be retrieved. All designs can use sonar to locate the moving oil plume, and then be relocated by using boats or winches to move the oil trapping devices. These devices can be constructed of treated, non-permeable DuPont Kevlar cloth (or similar material).

Jones, Jack A.↗
NASA NTRS2006

System for Continuous Deaeration of Hydraulic Oil

A system for continuous, rapid deaeration of hydraulic oil has been built to replace a prior system that effected deaeration more slowly in a cyclic pressure/ vacuum process. Such systems are needed because (1) hydraulic oil has an affinity for air, typically containing between 10 and 15 volume percent of air and (2) in the original application for which these systems were built, there is a requirement to keep the proportion of dissolved air below 1 volume percent because a greater proportion can lead to pump cavitation and excessive softness in hydraulic-actuator force-versus-displacement characteristics. In addition to overcoming several deficiencies of the prior deaeration system, the present system removes water from the oil. The system (see figure) includes a pump that continuously circulates oil at a rate of 10 gal/min (38 L/min) between an 80-gal (303-L) airless reservoir and a tank containing a vacuum. When the circulation pump is started, oil is pumped, at a pressure of 120 psi (827 kPa), through a venturi tube below the tank with a connection to a stand-pipe in the tank. This action draws oil out of the tank via the standpipe. At the same time, oil is sprayed into the tank in a fine mist, thereby exposing a large amount of oil to the vacuum. When the oil level in the tank falls below the lower of two level switches, a vacuum pump is started, drawing a hard vacuum on the tank through a trap that collects any oil and water entrained in the airflow. When the oil level rises above higher of the two level switches or when the system is shut down, a solenoid valve between the tank and the vacuum pump is closed to prevent suction of oil into the vacuum pump. Critical requirements that the system is designed to satisfy include the following: 1) The circulation pump must have sufficient volume and pressure to operate the venturi tube and spray nozzles. 2) The venturi tube must be sized to empty the tank (except for the oil retained by the standpipe) and maintain a vacuum against the vacuum pump. 3) The tank must be strong enough to withstand atmospheric pressure against the vacuum inside and must have sufficient volume to enable exposure of a sufficiently large amount of sprayed oil to the vacuum. 4) The spray nozzles must be sized to atomize the oil and to ensure that the rate of flow of sprayed oil does not exceed the rate at which the venturi action can empty the tank. 5) The vacuum pump must produce a hard vacuum against the venturi tube and continue to work when it ingests some oil and water. 6) Fittings must be made vacuum tight (by use of O-rings) to prevent leakage of air into the system. The system is fully automatic, and can be allowed to remain in operation with very little monitoring. It is capable of reducing the air content of the oil from 11 to less than 1 volume percent in about 4 hours and to keep the water content below 100 parts per million.

Anderson, Christopher W.↗
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↗
DOE OSTI2023

First Ever Field Pilot on Alaska's North Slope to Validate the Use of Polymer Floods for Heavy Oil EOR a.k.a Alaska North Slope Field Laboratory (ANSFL)

Alaska’s high viscosity oil resources that range between 20–30+ billion barrels represent about a third of known North Slope original oil in place (OOIP). These resources are primarily concentrated in the Schrader Bluff formation (also called West Sak on the Western North Slope) and Ugnu reservoirs and are categorized as “viscous oils” and “heavy oils” owing to their in-situ viscosities between 5–10,000 cP and up to a million+ cP respectively. The viscous oil deposits are relatively deeper (2,000 – 5,000 ft), whereas the heavy oils are somewhat shallower (2,000 – 4,000 ft). The typically shallow depths and the proximity to the continuous permafrost results in relatively lower formation temperatures and pressures, and consequently higher viscosities. The vertical depth vs. viscosity delineated in Paskvan et al. (2016) differentiates the viscous and heavy oils. As depicted in Paskvan et al. (2016), currently the main focus (referred to as “developing”) is on the viscous oils in the Schrader Bluff formation in the Milne Point Unit (MPU). Notwithstanding this Alaska North Slope (ANS) specific categorization, we use the industry adopted, all-inclusive term “heavy oil” for all high viscosity oils. Resource characterization and additional details can be found in topical publications of Paskvan et al. (2016) and Targac et al. (2005). Despite the vast resource base, the development pace, vis-à-vis the production of heavy oils has been very slow and limited due to multiple factors such as cost, logistics, challenging arctic environment, poor waterflood sweep efficiency due to mobility contrasts, and significantly high minimum miscibility pressures (MMP). Most importantly, typical or standard thermal methods that are commonplace elsewhere (Canada, California) are inapplicable due to the continuous permafrost. As a consequence, cumulative production of heavy and viscous oils is a little over 1% of OOIP slope wide and currently, there is hardly any production from Ugnu. However, on a broader level, these unfavorable factors are outweighed by the fact that (1) these resources, within the established infrastructure, are too large to ignore because of their strategic importance to the Nation and the State of Alaska and (2) Prudhoe Bay type diluent crude oil is still available for heavy oil transport through the Trans Alaska Pipeline System (TAPS). Similarly, from a reservoir standpoint, the following factors also are important offsets: (1) favorable rock characteristics of Schrader Bluff; (2) the promise demonstrated by the initial scoping studies (Seright 2010, 2011) suggesting significant increase of heavy oil recovery using polymer flooding; (3) successful field implementation in Canada, China and elsewhere in the world, and (4) availability of the existing pairs of horizontal injector-producer in Schrader Bluff The foregoing was recognized as the best readily available opportunity for significant investment by the US Department of Energy and the field operator Hilcorp Alaska LLC to conduct the first ever field scale experiment to test the polymer flooding technology to unlock the vast heavy oil resources on ANS. With this primary goal in mind, the research team embarked on a ~4.5 years long project that focused on the field polymer pilot complemented by supporting laboratory and simulation studies. As documented in this final report, over the course of the project, many lessons have been learned and valuable field and supporting laboratory data has been collected, which also is complemented by numerical reservoir simulations. We have been able to establish the injectivity of polymer solution, evidence of significant reduction in the water cut of previously waterflooded pattern, effective propagation of a hydrolyzed polyacrylamide (HPAM), benefits of low salinity water, provide practical guidance on handling of produced fluids containing breakthrough polymer, fit-for-purpose forecast-worthy history matched simulation model, polymer EOR benefit of 700-1000 bopd over waterflood, and most importantly a low polymer utilization factor of ~1.7 lb/stb. In summary this project is deemed as a scientific, technical and economic success, having met all objectives, fulfilled deliverables and within budget, providing impetus to apply polymer EOR throughout the Milne Point Field paving the way for even heavier viscosity oils in the Ugnu area, eventually extending the economic life of TAPS.

02 PETROLEUM↗
DOE OSTI2016

Bio-oil Stabilization by Hydrogenation over Reduced Metal Catalysts at Low Temperatures

Biomass fast pyrolysis integrated with bio-oil upgrading represents a very attractive approach for converting biomass to hydrocarbon transportation fuels. However, the thermal and chemical instability of bio-oils presents significant problems when they are being upgraded, and development of effective approaches for stabilizing bio-oils is critical to the success of the technology. Catalytic hydrogenation to remove reactive species in bio-oil has been considered as one of the most efficient ways to stabilize bio-oil. This paper provides a fundamental understanding of hydrogenation of actual bio-oils over a Ru/TiO2 catalyst under conditions relevant to practical bio-oil hydrotreating processes. Bio-oil feed stocks, bio-oils hydrogenated to different extents, and catalysts have been characterized to provide insights into the chemical and physical properties of these samples and to understand the correlation of the properties with the composition of the bio-oil and catalysts. The results indicated hydrogenation of various components of the bio-oil, including sugars, aldehydes, ketones, alkenes, aromatics, and carboxylic acids, over the Ru/TiO2 catalyst and 120 to 160oC. Hydrogenation of these species significantly changed the chemical and physical properties of the bio-oil and overall improved its thermal stability, especially by reducing the carbonyl content, which represented the content of the most reactive species (i.e., sugar, aldehydes, and ketones). The change of content of each component in response to increasing hydrogen additions suggests the following bio-oil hydrogenation reaction sequence: sugar conversion to sugar alcohols, followed by ketone and aldehyde conversion to alcohols, followed by alkene and aromatic hydrogenation, and then followed by carboxylic acid hydrogenation to alcohols. Hydrogenation of bio-oil samples with different sulfur contents or inorganic material contents suggested that sulfur poisoning of the reduced Ru metal catalysts was significant during hydrogenation; however, the inorganics at low concentrations had minimal impact at short times on stream, indicating that sulfur poisoning was the primary deactivation mode for the bio-oil hydrogenation catalyst. Reducing the sulfur content in bio-oil could significantly increase the lifetime of the hydrogenation catalyst used. The knowledge gained during this work will allow rational design of more effective catalysts and processes for stabilizing and upgrading bio-oils.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2018

Production of high oil, transgene free Camelina sativa plants through genome editing

The objective of this project was to develop a Camelina sativa feedstock with significantly increased seed yield and oil content to maximize oil yields per acre. Camelina is an oilseed crop with high potential as a bioenergy feedstock due to its high oil content, low inputs for cultivation, frost tolerance, and short growth cycle (80-110 days). To accelerate market entry, a next generation technology was used to develop GMO free plants to provide an expedited path through regulatory approval. This is anticipated to significantly decrease the time and thus the costs of commercialization of these lines. For this program current Camelina lines were considered to yield, on average, 1500 lbs of seed per acre and possess a seed oil content of 40%. The program had two oil production benchmarks: (1) increase production of seed to 2500 lbs/acre with seed containing 45% oil, and (2) increase production of seed to 3500 lbs/acre with seed containing 60% oil. Hitting the first benchmark would significantly expand the potential of Camelina as a crop and would provide the profitability necessary to incent farmers to grow Camelina, resulting in the production of renewable feedstock for the biobased energy and chemical industries. The second benchmark (3500 lbs seed/acre with 60% oil content) would have a huge impact on the availability of renewable Camelina oil for the biodiesel and aviation fuel markets. The accomplishments of this program demonstrated that genome editing of multiple targets in Camelina is technically feasible, despite the complexity of the Camelina genome. It also demonstrated that it is possible to increase seed yield while maintaining seed oil content using genome editing. Genome edited lines achieving up to a 40% increase in seed yield were demonstrated in greenhouse growth studies. In separate experiments, the program also achieved increases of up to 38% in the seed oil content of individual seeds. This increased seed oil content was, however, often accompanied by a decrease in seed yield. These observations demonstrate that carbon flow in Camelina can be significantly shifted to seed oil production but that additional research is necessary to concurrently increase/or maintain seed yield. Yield10 plans to continue to build on these results after the BETO program. During the course of this program, Yield10 also demonstrated that lines with single edits, as well as lines with multiple edits, generated using genome editing technology can be designated as non-regulated by USDA-APHIS through their “Am I Regulated?” process. Two separate “Am I Regulated?” letters were submitted to USDA-APHIS and edited Camelina lines described in the letters were deemed non-regulated by the agency demonstrating a reduced regulatory path. The technology developed in this program contributes to the overall understanding of seed oil biosynthesis in oilseed crops and how seed yield and seed oil content can be improved using genome editing techniques. The technology is thus also relevant to increasing seed and oil yield in related oilseed crops, such as canola.

09 BIOMASS FUELS↗
DOE OSTI2016

Bio-Oil Separation and Stabilization by Near-Critical Propane Fractionation

Bio-oils produced by thermal process are promising sources of sustainable, low greenhouse gas alternative fuels. These thermal processes are also well suited to decentralized energy production due to low capital and operating costs. Algae feedstocks for bio-oil production are of particular interest, due in part to their high-energy growth yields. Further, algae can be grown in non-arable areas in fresh, brackish, salt water, or even waste water. Unfortunately, bio-oils produced by thermal processes present significant stability challenges. These oils have complex chemical compositions, are viscous, reactive, and thermally unstable. Further, the components within the oils are difficult to separate by fractional distillation. By far, the most effective separation and stabilization method has been solvent extraction. However, liquid phase extraction processes pose two main obstacles to commercialization; they require a significant amount of energy to remove and recover the solvent from the product, and they have a propensity for the solvent to become contaminated with minerals from the char and ash present in the original bio-oil. Separation and fractionation of thermally produced bio-oils using supercritical fluids (SCF) offers the advantages of liquid solvent extraction while drastically reducing energy demands and the predisposition to carry over solids into the extracted phase. SCFs are dense fluids with liquid-like solvent properties and gas-like transport properties. Further, SCF density and solvent strength can be tuned with minor adjustments in pressure, co-solvent addition, or gas anti-solvent addition. Catalytic pyrolysis oils were produced from Scenedesmus dimorphus algae using a fluid catalytic cracking catalyst. Bio-oil produced from catalytic fast pyrolysis (CFP) was separated using critical fluids. Propane extraction was performed at 65 °C at a fluid reduced pressure of 2.0 (85 bar) using an eight to one solvent to feed ratio by weight. Extraction of catalytic fast pyrolysis oil with near critical propane produced an oil extract that was physically and chemically different from and more stable than the original oil. The propane extract displayed lower viscosity and lower average molecular weight. The species present in the propane extract were likely the less polar that would be expected from using a non-polar solvent (propane). Carbonyl containing species in the extract were likely ketones and esters. The raffinate contained a higher amnount of OH bonded species along with the more polar more polar acids, amides, and alcohols. The higher concentration of nitrogen in the raffinate may confirm the presence of amides. Viscosity of the propane extract increased only half as much as that of the CFP bio-oil. Further, In situ NMR aging studies showed that the propane extract was more stable than the raw oil. In conclusion, propane extraction is a promising method to decrease the nitrogen content of bio-oils and to improve the stability of bio-oils obtained by the catalytic pyrolysis of algae based biomass.

09 BIOMASS FUELS↗
DOE OSTI2017

Screening improved recovery methods in tight-oil formations by injecting and producing through fractures

Tight-oil reservoirs exhibit two characteristic behaviors that limit potential for improved recovery: (i) limited fluid movement from the unfractured matrix limits the potential to sweep additional oil towards the production wells with injection of a displacing fluid, (ii) the wettability of these reservoirs tend to be oil-wet which holds oil in relatively smaller pores, as compared to gas or water, making it difficult to mobilize that trapped oil. Primary oil production from these formations can decline to half of initial rates in the first year due to low permeability in the unfractured reservoir matrix, and a large amount of unrecovered oil remains in smaller pores that is not able to move out. To address these challenges, this study investigates the potential to improve oil recovery from tight-oil reservoirs by a method that includes injecting a fluid into the fractured reservoir to produce hydrocarbons from adjacent fractures intersecting the same wellbore. The injection and production through fractures has a potential economic advantage over huff-n-puff scheme such that there is no lag-period between injection and production. We compare the estimates of incremental oil recovery obtained by injecting water, immiscible CO 2 , and surfactant over the oil recovered by primary depletion (with no injection). The results suggest that injection of fluids may not always improve recovery from tight-oil reservoirs, especially in a heterogeneous reservoir (having different rock types) whose average matrix permeability is lower than 0.01 mD. In cases where recovery is improved over primary depletion, water flood and surfactant flood perform almost equally well with no noticeable difference between the two. Although, surfactant results in favorable fluid properties to mobilize oil, the reason surfactant did not perform well in tight-oil formation studied here is because the unswept oil is inaccessible due to small permeability, and not because of high capillary pressure.

42 ENGINEERING↗
DOE OSTI2015

Feasibility of observing small differences in friction mean effective pressure between different lubricating oil formations using small, single-cylinder motored engine rig

Here, the feasibility of using a motored single-cylinder 517 cc diesel engine to observe small frictional differences between oil formulations is investigated. Friction mean effective pressure (FMEP) is measured and compared for an SAE 10W-30 and an SAE 5W-20 oil in three stages of production: base oil, commercial oil without a friction and wear reducing additive, and fully formulated commercial oil. In addition, a commercial SAE 5W-30 engine oil is investigated. Friction mean effective pressure is plotted versus oil dynamic viscosity to compare the lubricant FMEP at a given viscosity. Linear regressions and average friction mean effective pressure are used as a secondary means of comparing FMEP for the various oil formulations. Differences between the oils are observed with the base oil having higher friction at a given viscosity but a lower average FMEP due to the temperature distribution of the test and lower viscosities reached by the base oil. The commercial oil is shown to have both a higher FMEP at a given viscosity and a higher average FMEP than the commercial oil without a friction and wear reducing additive. The increase in friction for the oil without a friction and wear reduction additive indicates that the operational regime of the engine may be out of the bounds of the optimal regime for the additive or that the additive is more optimized for wear reduction. Results show that it is feasible to observe small differences in FMEP between lubricating oil formulations using a small, single-cylinder motored engine.

33 ADVANCED PROPULSION SYSTEMS↗
DOE OSTI2015

Pt-based Bi-metallic Monolith Catalysts for Partial Upgrading of Microalgae Oil

Valicor’s proprietary wet extraction process in conjunction with thermochemical pre-treatment was performed on algal biomass from two different algae strains, Nannochloropsis Salina (N.S.) and Chlorella to produce algae oils. Polar lipids such as phospholipids were hydrolyzed, and metals and metalloids, known catalyst poisons, were separated into the aqueous phase, creating an attractive “pre-refined” oil for hydrodeoxygenation (HDO) upgrading by Stevens. Oil content and oil extraction efficiency of approximately 30 and 90% respectively were achieved. At Stevens, we formulated a Pt-based bi-metallic catalyst which was demonstrated to be effective in the hydro-treating of the algae oils to produce ‘green’ diesel. The bi-metallic catalyst was wash-coated on a monolith, and in conjunction with a high throughput high pressure (pilot plant) reactor system, was used in hydrotreating algae oils from N.S. and Chlorella. Mixtures of these algae oils and refinery light atmospheric gas oil (LAGO) supplied by our petroleum refiner partner, Marathon Petroleum Corporation, were co-processed in the pilot plant reactor system using the Pt-based bi-metallic monolith catalyst. A 26 wt% N.S. algae oil/74 wt % LAGO mixture hydrotreated in the reactor system was subjected to the ASTM D975 Diesel Fuel Specification Test and it met all the important requirements, including a cetane index of 50.5. An elemental oxygen analysis performed by an independent and reputable lab reported an oxygen content of trace to none found. The successful co-processing of a mixture of algae oil and LAGO will enable integration of algae oil as a refinery feedstock which is one of the goals of DOE-BETO. We have presented experimental data that show that our precious metal-based catalysts consume less hydrogen than the conventional hydrotreating catalyst NiMo Precious metal catalysts favor the hydrodecarbonylation/hydrodecarboxylation route of HDO over the dehydration route preferred by base metal catalysts, and consumes less hydrogen, if methanation can be mitigated. Our methanation data on Pt and Rh indicate effective suppression of methanation. Our data also show that our catalysts are less susceptible to coking; and unlike NiMo and CoMo, precious metal catalysts are not deactivated by water, a by-product of HDO of algae oil. Finally, our catalysts do not need to be sulfided to be active. A rigorous techno-economic analysis of our process for commercial scale production of 10,000 barrels per day of hydrotreated algae oil, with nutraceuticals co-product claiming only 0.05% of the raw algae oil, indicates an estimated plant gate price of ~$10/gal. Sensitivity analysis shows that critical parameters affecting sale price include (1) algae doubling time (2) biomass oil content (3) CAPEX, and (4) moisture content of post extracted algae residue. Modest improvements in these areas will result in enhanced and competitive economics. Based on a life cycle assessment for greenhouse gas emission, we found that if algae oil replaced 10% of the US consumption, this would result in a CO2e reduction of 210,000 tons per day. Improving the drying process for animal feed by 50% would result in further significant reduction in CO2e.

09 BIOMASS FUELS↗
NASA NTRS2010

Detection of Natural Oil Seeps in the Atlantic Ocean Using MODIS

Natural oil seepage is the release of crude oil into the ocean from fissures in the seabed. Oil seepage is a major contributor to the total amount of oil entering the world s oceans. According to a 2003 study by the National Academy of Sciences (NAS), 47 percent of oil entering the world s oceans is from natural seeps, and 53 percent is from human sources (extraction, transportation, and consumption). Oil seeps cause smooth oil slicks to form on the water s surface. Oil seeps can indicate the location of stores of fossil fuel beneath the ocean floor. Knowledge of the effect of oil seepage on marine life and marine ecosystems remains limited. In the past, remote sensing has been used to detect oil seeps in the Gulf of Mexico and off of the coast of southern California. This project utilized sun glint MODIS imagery to locate oil slicks off of the Atlantic coast, an area that had not previously been surveyed for natural oil seeps using remote sensing. Since 1982, the Atlantic Ocean has been closed to any oil and gas drilling. Recently, however, the U.S. Minerals Management Services (MMS) has proposed a lease for oil and gas drilling off the coasts of Virginia and North Carolina. Determining the location of seepage sites in the Atlantic Ocean will help MMS locate potential deposits of oil and natural gas, thereby reducing the risk of leasing areas for petroleum extraction that do not contain these natural resources.

Reahard, Ross↗
DOE OSTI2022

Technology, technology, technology: An integrated assessment of deep decarbonization pathways for the Canadian oil sands

As a party to the Paris Agreement, Canada has an ambitious climate target of net-zero emissions by 2050. The country also holds the world's third largest oil reserves in the Alberta oil sands. Given increasing emissions from the oil sands sector, achieving Canada's net-zero target requires significant oil sands decarbonization. If, while phasing out fossil fuels, there is still a demand for Canadian oil sands, then the decarbonization of the resource production process becomes crucial. In this study, we use an enhanced version of the Global Change Analysis Model (GCAM) with a detailed unconventional oil sector for Canada, including mining and in situ resources. We ask, what is the future of the oil sands sector in deeply decarbonized global and Canadian economies? We address this question under four mitigation scenarios with varying global net-zero GHG emissions constraints, three additional representative lower carbon extraction technologies available for the oil sands sector, as well as global direct air capture (DAC) deployment. We find that lower carbon technology deployment allows a 20%–44% increase in oil sands production by 2050 for scenarios with net-zero GHG emissions in 2100 or 2075. DAC helps maintain oil sands production in the most ambitious global decarbonization scenario (net-zero GHG by 2050), without which low international oil demand makes Canadian oil sands production uncompetitive. Canadian oil sands production thus depends highly on the availability of lower carbon extraction technologies and international oil demand, which to a certain extent relies on the availability and global deployment of negative emissions technologies.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2014

Source Term Modeling for Evaluating the Potential Impacts to Groundwater of Fluids Escaping from a Depleted Oil Reservoir Used for Carbon Sequestration

In recent years depleted oil reservoirs have received special interest as carbon storage reservoirs because of their potential to offset costs through collaboration with enhanced oil recovery projects. Modeling is currently being conducted to evaluate potential risks to groundwater associated with leakage of fluids from depleted oil reservoirs used for storage of CO2. Modeling results reported here focused on understanding how toxic organic compounds found in oil will distribute between the various phases within a storage reservoir after introduction of CO2, understanding the migration potential of these compounds, and assessing potential groundwater impacts should leakage occur. Two model scenarios were conducted to evaluate how organic components in oil will distribute among the phases of interest (oil, CO2, and brine). The first case consisted of 50 wt.% oil and 50 wt.% water; the second case was 90 wt.% CO2 and 10 wt.% oil. Several key organic compounds were selected for special attention in this study based upon their occurrence in oil at significant concentrations, relative toxicity, or because they can serve as surrogate compounds for other more highly toxic compounds for which required input data are not available. The organic contaminants of interest (COI) selected for this study were benzene, toluene, naphthalene, phenanthrene, and anthracene. Partitioning of organic compounds between crude oil and supercritical CO2 was modeled using the Peng-Robinson equation of state over temperature and pressure conditions that represent the entire subsurface system (from those relevant to deep geologic carbon storage environments to near surface conditions). Results indicate that for a typical set of oil reservoir conditions (75°C, and 21,520 kPa) negligible amounts of the COI dissolve into the aqueous phase. When CO2 is introduced into the reservoir such that the final composition of the reservoir is 90 wt.% CO2 and 10 wt.% oil, a significant fraction of the oil dissolves into the vapor phase. As the vapor phase moves up through the stratigraphic column, pressures and temperatures decrease, resulting in significant condensation of oil components. The heaviest organic components condense early in this process (at higher pressures and temperatures), while the lighter components tend to remain in the vapor phase until much lower pressures and temperatures are reached. Based on the model assumptions, the final concentrations of COI to reach an aquifer at 1,520 kPa and 25°C were quite significant for benzene and toluene, whereas the concentrations of polynuclear aromatic hydrocarbons that reach the aquifer were very small. This work demonstrates a methodology that can provide COI source term concentrations in CO2 leaking from a reservoir and entering an overlying aquifer for use in risk assessments.

carbon sequestration, scCO2, crude oil, benzene, B↗
DOE OSTI2017

Results of the International Energy Agency Round Robin on Fast Pyrolysis Bio-oil Production

An international round robin study of the production of fast pyrolysis bio-oil was undertaken. Fifteen institutions in six countries contributed. Three biomass samples were distributed to the laboratories for processing in fast pyrolysis reactors. Samples of the bio-oil produced were transported to a central analytical laboratory for analysis. The round robin was focused on validating the pyrolysis community understanding of production of fast pyrolysis bio-oil by providing a common feedstock for bio-oil preparation. The round robin included: •distribution of 3 feedstock samples from a common source to each participating laboratory; •preparation of fast pyrolysis bio-oil in each laboratory with the 3 feedstocks provided; •return of the 3 bio-oil products (minimum 500 ml) with operational description to a central analytical laboratory for bio-oil property determination. The analyses of interest were: density, viscosity, dissolved water, filterable solids, CHN, S, trace element analysis, ash, total acid number, pyrolytic lignin, and accelerated aging of bio-oil. In addition, an effort was made to compare the bio-oil components to the products of analytical pyrolysis through GC/MS analysis. The results showed that clear differences can occur in fast pyrolysis bio-oil properties by applying different reactor technologies or configurations. The comparison to analytical pyrolysis method suggested that Py-GC/MS could serve as a rapid screening method for bio-oil composition when produced in fluid-bed reactors. Furthermore, hot vapor filtration generally resulted in the most favorable bio-oil product, with respect to water, solids, viscosity, and total acid number. These results can be helpful in understanding the variation in bio-oil production methods and their effects on bio-oil product composition.

09 BIOMASS FUELS↗
DOE OSTI2021

Comparison of Spectroscopic Techniques for Determining the Peroxide Value of 19 Classes of Naturally Aged, Plant-Based Edible Oils

The peroxide value of edible oils is a measure of the degree of oxidation, which directly relates to the freshness of the oil sample. Several studies previously reported in the literature have paired various spectroscopic techniques with multivariate analyses to rapidly determine peroxide values using field portable and process instrumentation; those efforts presented “best-case scenarios” with oils from narrowly defined training and test sets. The purpose of this paper is to evaluate the use of near- and mid-infrared absorption and Raman scattering spectroscopies on oil samples from different oil classes, including seasonal and vendor variations, to determine which measurement technique or combination thereof is best for predicting peroxide values. Following peroxide value assays of each oil class using an established titration-based method, global and global-subset calibration models were constructed from spectroscopic data collected on the 19 oil classes used in this study. Spectra from each optical technique were used to create partial least squares regression calibration models to predict the peroxide value of unknown oil samples. A global peroxide value model based on near-infrared (8 mm optical path length) oil measurements produced the lowest RMSEP (4.9), followed by 24 mm optical path length near infrared (5.1), Raman (6.9) and 50 µm optical path length mid-infrared (7.3). However, it was determined that the Raman RMSEP resulted from chance correlations. Global peroxide value models based on low-level fusion of the NIR (8 and 24 mm optical path length) data and all infrared data produced the same RMSEP of 5.1. Global subset models, based on any of the spectroscopies and olive oil training sets from any class (pure, extra light, extra virgin), all failed to extrapolate to the non-olive oils. However, the near-infrared global subset model built on extra virgin olive oil could extrapolate to test samples from other olive oil classes. This work demonstrates the difficulty of developing a truly global method for determining peroxide value of oils.

36 MATERIALS SCIENCE↗
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 OSTI2023

HPTLC Analysis and Chemical Composition of Selected Melaleuca Essential Oils

Tea tree oil (TTO) is a volatile essential oil obtained by distillation, mainly from the Australian native plant Melaleuca alternifolia (Maiden & Betche) Cheel (Myrtaceae). In this study, a comparative analysis of the chemical constituents of seven tea tree oils (M. alternifolia) and four other Melaleuca spp. oils (M. cajuputi, (M Ca ), two chemotypes of M. quinquenervia, (M Ne and M Ni ), and M. ericifolia (M Ro )) was carried out using gas chromatography–mass spectrometry (GC-MS) and high-performance thin-layer chromatography (HPTLC). Among the seven TTOs, terpinen-4-ol (37.66–44.28%), γ-terpinene (16.42–20.75%), α-terpinene (3.47–12.62%), α-terpineol (3.11–4.66%), and terpinolene (2.75–4.19%) were the most abundant compounds. On the other hand, the most abundant compounds of the other Melaleuca oils varied, such as 1,8-cineole (64.63%) in M Ca oil, (E)-nerolidol (48.40%) and linalool (33.30%) in M Ne oil, 1,8-cineole (52.20%) in M Ni oil, and linalool (38.19%) and 1,8-cineole (27.57%) in M Ro oil. HPTLC fingerprinting of Melaleuca oils enabled the discrimination of TTO oils from other Melaleuca spp. oils. Variation was observed in the profile of the R f values among EOs. The present study shows that HPTLC is one of the best ways to identify and evaluate the quality control in authenticating TTOs, other Melaleuca EOs, or EOs from other species within the Myrtaceae.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2018

Effectiveness of supercritical-CO 2 and N 2 huff-and-puff methods of enhanced oil recovery in shale fracture networks using microfluidic experiments

Current oil recovery methods in hydraulically fractured shale reservoirs have a low recovery efficiency of about 10%. The objective of this work is to investigate the effectiveness of nitrogen and supercritical carbon dioxide in the huff-and-puff method for enhanced oil recovery as a means to re-energize reservoirs and improve recovery rates. Here, we conduct direct visualization experiments with a microfluidic system to reveal the mechanisms and to quantify the recovery rates of oil from fracture networks. We compared the effectiveness of water, nitrogen and supercritical carbon dioxide at reservoir conditions in a process mimicking the huff-and-puff method in both dead-end and connected fracture systems. The microfluidic chips were made of glass and placed in a confining pressure system pressurized to 10 MPa, 50 °C. The system was allowed to equilibrate, and then depressurized to simulate huff-and-puff oil recovery. Fluorescence microscope images were continuously taken to visualize and calculate residual oil saturation as a function of pressure drawdown. As the system was depressurized from 10 MPa, gas exsolution from the oil liquid phase, including bubble nucleation, growth, and coalescence, appeared to be the main driver for mobilizing oil from the fracture networks. Injection of supercritical CO 2 resulted in the highest recovery rate with an average end-point recovery of about 90% in the connected fracture network and 60% in the dead-end fracture network. N 2 has lower solubility in oil and hence showed a lower recovery rate of 40% in the connected fracture network and 25% in the dead-end fracture network. Injection of water had no effect on oil mobilization since water is insoluble, immiscible and incompressible. The main mechanism of enhanced recovery was gas exsolution from the liquid phase as pressure was decreased below the bubble point pressure. Because the gas was distributed throughout the oil phase, bubble nucleation, growth, coalescence, and elongation occurred throughout the fracture network. Expansion of the gas forced oil out of the network through piston displacement in continuous oil areas and film flow in the dispersed oil areas. Bubbles began as spheres and grew until they touched the fracture walls where they elongated along the fracture length. The bubble growth rate depended on local mass transfer from liquid to gas phase and gas volume expansion due to pressure drop. The efficiency of the huff-and-puff process is dependent on the solubility and miscibility of the injection fluid with oil. High gas solubility allows for more bubble nucleation, growth and expansion during the depressurization cycle.

58 GEOSCIENCES↗