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Surface Reactivity Analysis of the Crude Oil–Brine–Limestone Interface for a Comprehensive Understanding of the Low-Salinity Waterflooding Mechanism
Low-salinity waterflooding (LSWF) has proven to improve oil recovery in carbonate formations through rock wettability alteration, although the underlying mechanism remains elusive. Multivalent ionic exchange and calcite dissolution have usually been investigated using geochemical analysis in secondary coreflooding. In this work, coreflooding, in tertiary mode, coupled with a surface reactivity analysis approach was employed to investigate the interplay of wettability alteration mechanisms such as mineral dissolution, electrostatic bond attraction, and the effect of pH at in situ conditions. Improved oil recovery (IOR) in tertiary mode observed by coreflooding in Indiana limestone rocks showed an ionic strength dependence, that is, reducing brine ionic strength resulted in an increase in oil recovery. Coreflooding results showed that the seawater and low-salinity brines deprived of Mg 2+ ions resulted in the lowest IOR in tertiary mode, indicating the significance of Mg 2+ on IOR in limestone rocks. Similar results were observed through the contact angle measurement showing the limestone rock wettability state dependence on ionic strength and the effect of Mg2+ ions. Surface reactivity analysis showed an increase in solution pH, Ca 2+ and Mg 2+ ions concentration in the effluent solution from the coreflooding in tertiary mode using low salinity brines (about 40 and 20% increase in the effluent composition for Ca 2+ and Mg 2+ , respectively). These changes in solution composition were used to calculate the in situ oil–brine and rock–brine zeta potential using a validated surface complexation model, showing the changes of zeta potential as brine is injected into limestone rocks. The results show that using seawater-like brine in tertiary mode resulted in no mineral dissolution or ionic exchange. However, improved oil recovery (IOR) using such seawater-like brine was due to wettability alteration caused by reduced electrostatic bond attraction associated with Mg 2+ ions [from 2.6 × 10 –13 (mol/m 2 ) 2 for formation water salinity to 1.5 × 10 –13 (mol/m 2 ) 2 for seawater salinity]. Using low-salinity brines in tertiary mode improved oil recovery by mineral dissolution, resulting in oil desorption and an increase in solution pH. Finally, the increase in solution pH also resulted in reduced electrostatic bond attraction which lead to rock wettability alteration using low-salinity brines.
Alteration of flowrate through wellbore cement fractures due to crude oil leakage.
Abstract not provided.
A brief history of crude oil vapor pressure research at Sandia National Laboratories
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INVESTIGATION OF ROCK-FLUID INTERACTIONS USING GEOMATERIAL MICROFLUIDICS
Illite and Illite-Smectite clays are reportedly the Caney Shale's most prevalent clay minerals. The swelling and fines migration of clays may occur when water-based fluids contact the clay minerals. This may result in the reduction of pore space and permeability, and wettability alteration. Therefore, we quantified the swelling potentials, fines migration and wettability alteration of Illite and Illite-Smectite clays upon exposure to model brines and a produced water, and a model oil and a crude oil. We measured density, viscosity, pH, TDS, and interfacial tension as they are important in multiphase flow and displacement characteristics. Geomaterial microfluidics is recently being used to study physicochemical interactions of solid-fluid systems. It facilitates visualizing the surface behavior upon exposure to various fluids. This study includes preparation and characterization of Illite-Smectite clay-coated glass capillary tubes. Illite and Illite-Smectite clay-coated geomaterial microfluidic surfaces were prepared to investigate the effects of first contact fluid, brine salinity, and aging on wettability. In this work, advancing and receding contact angles of model brine-air, model oil-air, produced water-air, crude oil-air, model brine-model oil systems, and produced water-crude oil systems have been measured in the untreated, and clay-coated microfluidic channels of 1000 µm width and 50 µm depth. The aging effect was studied by retaining the non-aqueous and aqueous solutions in the corresponding microfluidic channels for approximately 24 h in the case of channels first contacted by aqueous and non-aqueous solutions, respectively. The advancing and receding contact angles of Caney shale-crude oil-produced water systems were also measured. The experimental findings indicate the swelling potential, fines migration, and wettability alteration of Illite and Illite-Smectite clays. The results signify the influence of first contact fluid, brine salinity, and aging on wettability of the untreated and clay-coated microfluidic surfaces. The experiments also demonstrate the wetting nature of the Caney shale samples from reservoir and non-reservoir zones.
Alteration in micro-mechanical characteristics of wellbore cement fracture surfaces due to fluid exposure
The stiffness of wellbore cement fracture surfaces was measured after exposing to the advective flow of nitrogen, silicone oil, and medium sweet dead crude oil for different exposure periods. The test specimens were extracted from fractured cement cylinders, where the cement fracture surfaces were exposed to the different fluids up to 15 weeks. A nanoindenter with a Berkovich indenter tip was used to measure load-indentation depth data, which was used to extract the elastic modulus (E) and nano-hardness (H) of the cement fracture surfaces. A reduction in the elastic modulus compared with an unexposed specimen were observed in all the specimens. Both elastic modulus and nano-hardness for the specimens exposed to silicone oil were lower than specimens exposed to nitrogen gas and varied with the period of exposure. The elastic modulus and nano-hardness of the specimens exposed to crude oil were the lowest with a significant decrement with the exposure period. The frequency distribution of the nanoindentation measurements shows that the volume-fraction ratio of the two types of cement hydrated nanocomposites for both the unexposed and test specimens is about 70:30%. Phase transformation beneath the indenter is observed for all of the specimens, with more obvious plastic deformation in specimens exposed to crude oil. Analytical measurements (SEM, EDS, FT-IR, and XRD) on exposed cement fracture surfaces reveal different levels of physical and chemical alteration that are consistent with the reduction in stiffness measured by nanoindentation. Furthermore, the study suggests that cement stiffness will decrease due to crude oil exposure, and the fracture will be sensitive to stress and pore pressure with time.
Incidence of chronic respiratory conditions among oil spill responders: Five years of follow-up in the Deepwater Horizon Oil Spill Coast Guard Cohort study
Background: Over ten years after the Deepwater Horizon (DWH) oil spill, our understanding of long term respiratory health risks associated with oil spill response exposures is limited. Here we conducted a prospective analysis in a cohort of U.S. Coast Guard personnel with universal military healthcare. Methods: For all active duty cohort members (N = 45,193) in the DWH Oil Spill Coast Guard Cohort Study we obtained medical encounter data from October 01, 2007 to September 30, 2015 (i.e., ~2.5 years pre-spill; ~5.5 years post-spill). We used Cox Proportional Hazards regressions to calculate adjusted hazard ratios (aHR), comparing risks for incident respiratory conditions/symptoms (2010–2015) for: responders vs. non-responders; responders reporting crude oil exposure, any inhalation of crude oil vapors, and being in the vicinity of burning crude oil versus responders without those exposures. We also evaluated self-reported crude oil and oil dispersant exposures, combined. Within-responder comparisons were adjusted for age, sex, and smoking. Results: While elevated aHRs for responder/non-responder comparisons were generally weak, within-responder comparisons showed stronger risks with exposure to crude oil. Notably, for responders reporting exposure to crude oil via inhalation, there were elevated risks for all sinusitis (aHR = 1.48; 95%CI, 1.06–2.06), unspecified chronic sinusitis (aHR = 1.55; 95%CI, 1.08–2.22), chronic obstructive pulmonary disease (COPD) and other allied conditions (aHR = 1.43; 95%CI, 1.00–2.06), and dyspnea and respiratory abnormalities (aHR = 1.29; 95%CI, 1.00–1.67); there was a suggestion of elevated risk for diseases classified as asthma and reactive airway diseases (aHR = 1.18; 95%CI, 0.98–1.41), including the specific condition, asthma (aHR = 1.35; 95%CI, 0.80–2.27), the symptom, shortness of breath (aHR = 1.50; 95%CI, 0.89–2.54), and the overall classification of chronic respiratory conditions (aHR = 1.18; 95%CI, 0.98–1.43). Exposure to both crude oil and dispersant was positively associated with elevated risk for shortness of breath (HR = 2.24; 95%CI, 1.09–4.64). Conclusions: Among active duty Coast Guard personnel, oil spill clean-up exposures were associated with moderately increased risk for longer term respiratory conditions.
Technical and Economic Assessment and Gap Analysis of Advanced Nuclear Reactor Integration with a Reference Oil Refinery
Efforts to identify the most-economic methods to decarbonize several sectors of the U.S. economy are underway. Industrial processes such as crude-oil refining rely heavily on energy-dense and easily stored and transported fossil fuels for powering their operations. Refineries use large amounts of energy, primarily derived from fossil sources to separate crude-oil components, break down heavier hydrocarbons into lighter compounds, remove impurities, reform hydrocarbon molecules, and generate steam and electricity for pumps and compressors and other various auxiliary systems. Crude-oil refining operations such as distillation, cracking, desulfurization, reforming, utilities systems and some offsite facilities collectively account for most of the energy consumption. Other operations such as hydrocracking or hydrotreating also require hydrogen for developing hydrogenation reactions which involve substantial heating to keep the reactors at high-temperature and pressure levels. All heat and energy demands are typically provided by natural gas (NG), oil, or other fuels, which makes refinery industry one of the most-difficult sectors to decarbonize. Nuclear power is a viable and energy-dense source of clean electricity, heat, and hydrogen to provide the large, sustainable energy supply that the refining industry demands. The U.S. Department of Energy’s (DOE’s) Integrated Energy Systems (IES) program is working to perform research and development, design, economic siting, and risk analysis. This state-of-the-art work will enable the first on-site demonstrations and commercial deployments of advanced small modular nuclear reactors (SMNRs) integrated with industries such as chemical production, refining, iron and steel making, and more. IES seeks to demonstrate the ability of advanced nuclear reactors to meet the heat and power demands of these industries while reducing carbon emissions in a sustainable and cost-competitive way. The primary objective of this research effort is to analyze industrial-scale SMNR integration intended to decarbonize refining facilities. The foreseen outcome is the provision of reliable, cost-competitive, and sustainable clean energy, alongside a reduction of carbon emissions. Specifically, the focus of this work lies on meeting the reference facilities’ heat and electricity demands with nuclear power while also supplying clean hydrogen via integrated high-temperature steam electrolysis (HTSE). This report presents a comprehensive technical and economic assessment of the integration of advanced nuclear reactors into a reference refinery, leveraging financial incentives from the Inflation Reduction Act (IRA). The evaluation aims to explore the potential economic benefits and challenges associated with incorporating advanced nuclear reactors into refinery operations, particularly in terms of energy efficiency, economic implications and environmental impact. By examining both the technical feasibility and economic viability, this analysis seeks to identify existing gaps and propose solutions for successful nuclear integration implementation. The findings are intended to provide valuable insights for stakeholders considering the adoption of advanced nuclear reactors in the refining sector. A refinery reference-plant was developed, using an open-source refinery model, Petroleum Refinery Lifecycle Inventory Model (PRELIM) and expert assessment, as a base case for comparison with various nuclear integration options. The capacity of 100 kbd/day (KBD) of heavy crude-oil feed was selected to represent a general coking-type refinery with deep conversion capabilities (incorporating heavy-oil upgrading with FCC, coking, and associated hydrotreating process units), using a heavy crude-oil feed, which represents about 70% of U.S. refineries configurations. A summary of all cases considered in this study is shown in Table 1.
The Novel Charfuel® Coal Refining Process 18 TPD Pilot Plant Project for Co- Producing an Upgraded Coal Product, and Commercially Valuable Co- Products: Area of Interest #3 – Coal Beneficiation Pilot Plant Testing (Final Report)
Operation of Carbon Fuels, LLC’s (“CF”) existing, permitted 18 TPD pilot plant located in Golden, Colorado using two individually ranked (ASTM D 388) coal types (two campaigns), employing the novel Charfuel® coal refining process to produce an upgraded coal product and a number of high-valued organic and inorganic coproducts (for which there presently exists large commercial markets) in order to produce engineering and product data which will then be utilized toward the design of a commercial scale integrated facility (pre-feed document). Carbon Fuels, LLC has developed the Charfuel® Coal Refining Process which refines domestically abundant, raw coal (in the same manner as crude oil is refined) to produce the identical, high value co-products that are refined from crude oil. Thus, gasoline, jet fuel, “green diesel”, fuel oil, and marine fuels, as well as petrochemicals such as benzene, toluene, xylene, and methanol are refined from raw coal using this process. The Charfuel® Coal Refining Process is not a coal conversion process, like pyrolysis, or indirect liquefaction. Nor is it an alternative energy system. Rather it is a coal refining process that has the ability to economically produce products traditionally associated with the refining of crude oil but using only abundant, raw coal as the refinery feed stock. The Charfuel® Coal Refining Process is more economical than crude oil refining and is environmentally benign. Therefore, this value added process yields a return on investment well above 50% for a commercial facility. Furthermore, the Charfuel® process, unlike alternatives such as ethanol and hydrogen, can utilize the existing transportation, delivery, and other petroleum based systems. Hence, there is no need for new engines, pipelines, tankers, or product acceptance. As a result, the profitability of the process is increased. Objectives: (1) Operation of the integrated 18 tpd pilot plant, using two coal types (ranks); (2) Demonstration of process flexibility in being able to produce different products (gas, liquid, and char), as well as determination of operating parameters for identifying scale up criteria for two coal types (ranks); (3) Generation of engineering and design information (process specifications) for use in designing a commercial scale plant (scale-up); (4) Determination of important environmental issues surrounding the process and the products such as fate of trace elements (mercury and other heavy metals) and distributions of SO2, NOx, and CO 2 by analysis of effluent streams; (5) Production of sufficient product to allow reliable commercial economic evaluation of both the refined coal product and the coproducts; and, (6) Assessment of longer-term reliability of unit operations. Period 1: reconfiguration of the 18 TPD plant to meet specific FOA requirements and to qualify the facility for operation; and, Period 2: operation of the 18 TPD plant for two campaigns using two coals types (ranks) which are widely commercially used and abundant - the first being a subbituminous (Powder River Basin (“PRB”)) coal, and the second a bituminous (Illinois #6) coal.
Can a Nuclear-Assisted Biofuels System Enable Liquid Biofuels as the Economic Low-carbon Replacement for All Liquid Fossil Fuels and Hydrocarbon Feedstocks and Enable Negative Carbon Emissions?
This report integrates the results of a series of studies and workshops to address the question: Can a nuclear-assisted biofuels system enable liquid biofuels as the economic low-carbon replacement for all liquid fossil fuels and hydrocarbon feedstocks and simultaneously enable negative carbon emissions? “Economic” is defined as economically competitive relative to other low-carbon replacement options for crude oil. “All” refers to the capability to replace the 18 million barrels of oil per day used by the United States. “Nuclear-assisted” refers to the provision of massive quantities of low-carbon heat and hydrogen at the refinery to fully utilize the carbon content of the cellulosic biomass feedstocks for liquid hydrocarbon production. A system is proposed that decarbonizes about half of the U.S. economy while improving long-term soil productivity and sequestering carbon from the atmosphere. In the U.S. almost half the energy consumed by the final customer is in the form of liquid hydrocarbons produced from crude oil. Liquid hydrocarbons are used as (1) an energy source, (2) a method for daily-to-seasonal energy storage, (3) a chemical feedstock, (4) a chemical reducing agent, (5) a method to enhance high-temperature heat transfer in many furnaces and industrial processes and (6) other purposes. As a consequence, the U.S. consumes ~18 million barrels of crude oil per day to produce liquid hydrocarbons. While there are substitutes for liquid hydrocarbons for some applications, our assessment is that the costs and difficulty will dramatically increase if liquid hydrocarbon use goes much below the equivalent of 10 million barrels per day of crude oil. New uses of liquid hydrocarbons to partly replace coal and natural gas could increase demand beyond the equivalent of 10 million barrels of oil per day. One can produce and burn liquid hydrocarbons from biomass without any net addition of carbon dioxide to the atmosphere. Plants grow by removing carbon dioxide from the atmosphere; thus, burning biomass does not result in any net addition of carbon dioxide to the atmosphere. Biomass is typically 40% oxygen. To remove this oxygen to create hydrocarbon liquids, there are two options. The first option is to use biomass as (1) a feedstock, (2) an energy source to operate the process and (3) a supply of carbon to remove the biomass oxygen as carbon dioxide. The second option is to use external heat and hydrogen to remove the oxygen as water and produce liquid hydrocarbons. The use of massive quantities of external heat and hydrogen for hydrocarbon liquid fuels production reduces the biomass feedstock per unit of liquid hydrocarbon product by more than a factor of two reducing land use by more than a factor of two. Many cellulosic feedstocks unsuitable for liquid hydrocarbon production are viable feedstocks with external heat and hydrogen inputs. As a result, there is sufficient cellulosic feedstocks to meet U.S. and global liquid fuels hydrocarbon demand without significant impacts on food and fiber prices. The heat and hydrogen (heat plus electricity) are produced using base-load nuclear power plants—the most economic form of nuclear energy. If low-price natural gas, there is also the option of producing hydrogen from natural gas with sequestration of the carbon dioxide. The biomass is locally processed in depots to produce commodity feedstocks that can be shipped long distances to large biorefineries (250,000 barrels per day, oil equivalent) similar to existing refineries except modifications of front-end processes. The depot system enables local recycle of nutrients back to the soil. The biorefinery can produce variable quantities of liquid hydrocarbon fuels and carbon dioxide for sequestration enabling removal of carbon dioxide from the atmosphere. Preliminary estimates are that the liquid hydrocarbon costs are equivalent to crude oil at between $60 and $70 per barrel. The largest cost is for hydrogen with biomass feedstocks and refinery costs a smaller fraction of the total cost.
Development of Algal Biomass Yield Improvements in an Integrated Process (Final Report)
This project built on the success of Global Algae Innovations Algae Biomass Yield Phase 1 project to accelerate the commercialization of algal biofuels through development of an integrated, economical, photosynthetic, open raceway system to produce algal oil. Two parallel pathways to a biofuel were investigated. In the algal crude oil pathway, highlighted in blue, the dewatered algal biomass slurry is used as a feed to hydrothermal liquefaction to produce an algae crude oil and recycle aqueous stream. In the algal lipid oil pathway, highlighted in green, the algal biomass slurry is dried, and the oil is extracted to produce an algal lipid oil biofuel intermediate and a high protein algae meal co-product. Upgrading to drop-in fuels has been demonstrated for the biofuel intermediates in both pathways. Since the algal lipid oil pathway requires lipid accumulation, the productivity is generally lower than the algal crude oil pathway, but the required productivity for economical algal biofuel production is also lower because the coproduct value is greater. The outdoor cultivation was performed at the Kauai Algae Farm. The project team has expertise across the full breadth strain development, advanced algal cultivation, open raceway contamination control, CO 2 supply, harvesting, dewatering, extraction, hydrothermal liquefaction, technoeconomic analysis and life cycle analysis: Hildebrand laboratory at Scripps Institution of Oceanography – diatom strain development. Mayfield laboratory at UCSD - green algae strain development. TSD Management Associates- CO 2 supply, algal harvesting and dewatering, and algal drying and extraction. Qualitas - large-scale test site for algal harvesting technology. Texas A&M University - algal drying and extraction technology. Pacific Northwest National Laboratory - hydrothermal liquefaction technology. GE Water and Power - membrane technology. National Renewable Energy Laboratory - algal techno-economic analysis. Phase 1 of the project resulted in tremendous productivity and pre-processing improvements in an integrated, large-scale, low-cost cultivation and pre-processing process that moved algal technology closer to economic viability for biofuels than ever before. Phase 2 accomplishments further facilitate development of a commercial algal biofuel industry by adding: several top performing strains and strain development tools including breeding; open-pond cultivation innovations that achieved a 30% improvement in overall productivity, an 83% reduction in cost, and a 95% reduction in energy use relative to conventional technology; further improvements in harvesting that led to the Zobi harvester ® as a universal, economical, low energy, commercially available microalgae harvesting solution; breakthroughs in drying and extraction including a new low energy drying process and several new low energy extraction unit operations that together with the Zobi harvester ® achieve a 90% reduction in cost and 97% reduction in energy use relative to conventional technology. These improvements are sufficient to enable economical production of algae biofuel and protein meal co-product if the process were scaled up to a commercial-scale 5,000-acre algae farm.
Evaluation of a Robust, In-Situ Surface Treatment for Pipeline Solids Deposition Mitigation in Flowing Systems
Abstract The formation/precipitation and deposition of pipeline solids, such as gas hydrates, asphaltenes, and waxes have long plagued production fields. Given the vast differences in chemistries of these solids, any current prevention or mitigation strategy, particularly for cases where multiple issues are a concern, is likely to involve an extensive assortment of undefined chemical additives that are both costly and add complexity to the system. Surface treatments (coatings), on the other hand, present a relatively new viable option for management strategies. A chemically and physically robust surface treatment with the ability to address deposition issues for multiple pipeline solids could not only decrease the operating expenditures for a field through material cost savings and obviation of downstream separation, but could also simplify produced fluids by eliminating additional chemicals from the mixture. The purpose of this study is to explore the feasibility of a particular surface treatment as part of a solids management strategy. This work utilizes an omniphobic surface treatment to probe its effects on gas hydrate, asphaltene, and wax deposition. Specifically, high pressure rocking cells are employed to study gas hydrate nucleation and deposition. A bench-scale flowloop filled with crude oil and heptane is used to quantify the deposition of crude oil and asphaltenes after a set time period. Lastly, a mechanical shear device measures the adhesion force of wax deposits on untreated/treated surfaces. The gas hydrate rocking cell tests demonstrate an increase in induction time and occasional elimination of hydrate nucleation with the surface treatment. Moreover, the same apparatus indicates that the critical shear to avoid hydrate deposition may be lowered in the presence of the surface treatment compared to untreated pristine carbon steel coupons. A custom-built asphaltene flowloop then establishes that this surface treatment is effective in dramatically reducing the deposition of the aliphatic components of a crude oil, with a moderate reduction in the asphaltene fraction. Finally, mechanical adhesion force measurements for solidified paraffin wax display trends in agreement with the asphaltene results. The surface treatment on both pristine and corroded surfaces is able to reduce the adhesion of wax deposits to values below a pristine, untreated surface.