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At least 199 records · Page 11
All sourcesNASA NTRSDOE OSTI
DOE OSTI2022

Dissolving Nonionic Surfactants in CO 2 to Improve Oil Recovery in Unconventional Reservoirs via Wettability Alteration

CO 2 injection is a promising method for enhanced oil recovery (EOR) in unconventional shale reservoirs. Here, in this work, we postulate that CO 2 EOR may be improved by the dissolution of surfactants into CO 2 . Although CO 2 is a relatively good solvent for oil, we show that CO 2 and Eagle Ford oil are immiscible at compositions above 70 wt % CO 2 , even at pressures as high as 62 MPa. The presence of a CO 2 –oil interface at reservoir conditions indicates that the addition of a surfactant has the potential to improve oil recovery–via wettability alteration from oil-wet to CO 2 -wet, CO 2 –oil interfacial tension (IFT) reduction, or both. Three nonionic surfactants (branched tridecyl ethoxylate Indorama SURFONIC TDA-9, branched nonylphenol ethoxylate Indorama SURFONIC N-100, and linear dodecyl ethoxylate Indorama SURFONIC L12-6) were evaluated for CO 2 -solubility, shale wettability alteration, effect on CO 2 –oil IFT, ability to generate CO 2 –oil foams, and ability to increase oil extraction from Eagle Ford, Mancos, and Bakken shale cores. Each surfactant dissolved in CO 2 up to 1 wt % at pressures and temperatures commensurate with CO 2 EOR. CO 2 -dissolved surfactants did not significantly affect CO 2 –oil IFT or generate CO2–oil foams, but they did induce a dramatic change in the contact angle of an oil droplet on an oil-aged shale chip in CO 2 from strongly oil-wet (11°) toward intermediate CO 2 –oil wettability (82°) (at 80 °C, 27.6 MPa). The branched tridecyl ethoxylated surfactant, SURFONIC TDA-9, afforded the highest oil recovery in core soaking experiments–75%, compared to 71% by pure CO 2 . Analysis of oil extracts by gas chromatography revealed that heavier oil components were produced when the surfactant was added to CO 2 . These results indicate that CO 2 -dissolved surfactants may increase oil recovery from shale by wettability alteration from oil-wet toward CO 2 -wet.

04 OIL SHALES AND TAR SANDS↗
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↗