Carbon Dioxide Processing at the Oil Refinery

Study of geological storage for a candidate CCS demonstration project in Tomakomai, Hokkaido, Japan

Flares are used for the safe, clean, and economical disposal of waste gases, whether in upstream oil production (solution gas flares), refineries, gas plants, or other chemical processing facilities. Elevated flares are exposed to a range of weather patterns; perhaps the most important being the crosswind. The CETC Flare Test Facility (FTF) was constructed to address the question of performance of solution gas flares, in response to limited field trials that indicated the possibility of very low combustion efficiencies under certain conditions. The FTF produces crosswind speeds up to 45 km/h with very low turbulence intensity, as designed. Model solution gases are produced from natural gas, propane, inert diluents (carbon dioxide and nitrogen), and volatile liquids. Atmospheric wind is a turbulent shear flow with an intensity of around 7﹪. To more closely replicate the turbulence properties of atmospheric wind, a range of turbulence intensities and integral length scales were imposed in the FTF by using grids. The flare flame efficiency is measured by the conversion of carbon in the solution gas to carbon dioxide. Efficiency is lowest for pure natural gas, and increases with the amount of propane. Conversion efficiency decreases significantly with the increase of turbulence intensity of the crosswind, which has implications for existing and novel strategies to improve flare performance. The primary product of incomplete combustion is methane, a significant greenhouse gas. The combined effect of inert diluents and turbulence intensity on flame stability shows that turbulence amplifies the destabilizing effect of fuel dilution. Introduction Flares are used for the safe, clean, and economical disposal of waste gases, whether in upstream oil production (solution gas flares), refineries, gas plants or other chemical processing facilities. Elevated flares are exposed to all the weather patterns; perhaps the most important is the crosswind. The flaring of solution gas (also called associated gas) was a common practice in upstream oil extraction. This gas is a mixture of light hydrocarbons, mostly methane but including possibly significant amounts of ethane, propane, butane, hydrogen, perhaps some inert gases (nitrogen and carbon dioxide), and sometimes hydrogen sulphide (sour gas). The composition and amount of solution gas can vary a great deal between production sites. Over 800 million m3 of gas was flared in Alberta in 2000, which is almost a 50﹪ reduction from 1996(1). The current global flaring rate is estimated between 100 and 126 billion m3 of solution gas each year(2). Strosher(3) conducted laboratory-scale investigations on an enclosed flare and an open-air flare, and on two commercial flares in the field. He found in the field investigations that combustion efficiency is typically about 70%, sometimes as low as 62﹪. The unburned portion consisted of methane, unsaturated hydrocarbons, light aromatics such as benzene, and polycyclic aromatic hydrocarbons (PAH). This work has led to much of the current interest in flare research by industry, government, academia, and the public. An important parameter in the flare flame behaviour is the ratio of the fuel jet momentum flux to the crosswind momentum flux.

The Potential for Storing Carbon Dioxide in the Rocks Beneath the UK Southern North Sea

Multi-objective optimisation of a carbon capture and sequestration supply chain under seismic risk constraints. A case study considering industrial emissions in Italy

Road vehicles, and in particular cars, are major contributors to air pollution. In the UK, road transport emits 24 per cent of carbon dioxide, 4 per cent of sulphur dioxide, 47 per cent of smoke, 53 per cent of oxides of nitrogen (NOx), 90 per cent of carbon monoxide, and 46 per cent of volatile organic compounds (VOC) (DOE, 1994). Emissions from oil refineries and the motor vehicle industry are indirectly produced by road transport. All these pollutants are the subject of concern about health and environmental impacts. Carbon dioxide is the principal anthropogenic greenhouse gas responsible for most of the UK contribution to global warming. Sulphur dioxide and NOx are acid species, believed to be responsible for much of the damage to building materials, as well as impacts on forests and aquatic ecosystems, observed in large parts of northern Europe. NOx and VOC react to form ozone, which damages both human health and crops. Many of the pollutants and their secondary products have been identified as potentially injurious to health. These impacts impose costs on society. Whilst impacts to the environment and human health are often considered as distinct from economic considerations, the advantages of expressing them in monetary terms (damages in our terminology) have been described elsewhere (see, for example, Pearce et al, 1989) and are quite widely accepted. In general, these monetary damages have been estimated at an aggregate level, typically as national estimates. Whilst this top-down approach provides some useful information for transport and environment policy, it does not allow for dependence on fuel, technology and source location, all of which can have profound effects on pollution. An alternative bottom-up approach requires estimation of marginal and site-dependent impacts attributable to pollution emissions. This has generally been held to be impractical to undertake. However, new studies of damages attributable to fossil fuel emissions from the electricity sector have established that such an approach is feasible (CEC, 1995; ORNL, 1994; Roweeia/., 1995).

In the chemical process industry, separation of mixtures into streams of high purity compounds is frequently necessary. Mixtures may originate from feedstock impurities, incomplete conversion of the reactants, and/or occurrence of undesirable side reactions. Feedstocks for the process industry are often complex mixtures such as mineral oil, coal, petroleum distillates, or vegetable fats. It is often desirable to separate the components of these mixtures prior to use. For the separation of mixtures a large number of processes and techniques have been developed. These are divided into two classes. The first is composed of separations based on differences in physiochemical properties, eg, boiling point in the case of distillation, and diffusivity in some membrane applications. The second class of separation is achieved by means of a selective chemical reaction. Examples include removal of acidic gases, carbon dioxide, and hydrogen sulfide, and hydrogen. This article discusses the second class with emphasis on contactor selection. The implementation of a chemical reaction is rarely simple. Reactor selection, regeneration of intermediate products, and possible degradation of the various components must be considered. The selection or design of a contactor is also complicated, even when the a classical contactor is used. For new processes, the various steps in the chemical reaction must be identified, eg, mass transfer, diffusion and chemical reaction, reaction schemes or networks, by product formation, etc, must all be considered. This identification is often too expensive to follow in commercial development so only partial knowledge of the elementary process may be obtained before proceeding. When more detailed knowledge of the reaction is available, selection or design of a special contactor exclusively devoted to the duty of the chemical separation process is possible. This article gives details for separation processes involving gas‐liquid systems, gas‐solid systems, and slurry contactors

Various implementations and various combinations of solvent deasphalting with the modern processes of deep oil refining are considered, and the ways of processing the separation products formed are demonstrated. Specific features of the main technologies used in Russia and other countries are discussed. Particular attention is paid to perspective technologies implementing the fuel direction of the process using both traditional hydrocarbon solvents and nontraditional solvents such as organic carbonates and carbon dioxide.

Plastics and climate change—Breaking carbon lock-ins through three mitigation pathways

Use of solvents and environmental friendly materials for applications in Green Chemistry

State of the art of biofuels from pure plant oil

Membrane gas-solvent contactor process for efficient carbon capture from multiple emission sources within an industrial complex

Self-Optimizing and Control Structure Design for a CO2 Capturing Plant

A team led by the Gulf Coast Carbon Center at the Bureau of Economic Geology, Jackson School of Geosciences at The University of Texas at Austin, has been funded by the National Oceanographic Partnership Program (NOPP) through and in cooperation with the U.S. Department of Interior (DOI), Bureau of Ocean Energy Management (BOEM) to generate a Best Management Practices (BMPs) document on sub-seabed geologic sequestration of carbon dioxide (CO2) below the U.S. outer continental shelf. The team consists of scientists, engineers, lawyers, and business managers from academia, private industry, and State of Texas government from the following institutions: (1) Gulf Coast Carbon Center at the Bureau of Economic Geology (BEG), (2) Det Norske Veritas (USA) Inc (DNV), (3) Wood Group Mustang and sister company Wood Group Kenny (Wood Group), (4) Texas General Land Office (GLO), (5) Harte Research Institute for Gulf of Mexico Studies at Texas A&M University-Corpus Christi (HRI), and (6) The University of Houston Law Center. Individual team members have expertise in carbon sequestration monitoring, CO2-pipeline design and construction, and domestic and international offshore environmental policy. The BMPs will be reviewed by external experts after it is generated and before being submitted to BOEM. The purpose of the BMPs will be to provide technical guidance to BOEM and BSEE (U.S. DOI Bureau of Safety and Environmental Enforcement) to establish regulatory guidelines for offshore components of future U.S. Carbon Capture and Storage, which is sometimes referred to as sequestration, (CCS) industry. Sub-seabed geologic sequestration (GS) is the process whereby CO2 captured from large volume industrial sources (e.g., power plants, oil refineries) will be (1) compressed to supercritical state and transported via pipeline to offshore injection wells, and (2) injected into geologic strata deep (thousands of feet) below the seafloor. Objectives of the CO2 injection will be for “pure sequestration” (i.e., long-term storage of CO2 in subseafloor saline reservoirs) or sequestration combined with enhanced oil recovery (EOR). Sub-seabed geologic sequestration is very different from ocean dumping (i.e. dissolution of CO2 into circulating seawater) or injection of CO2 into deep water, shallow sub-seabed sediments. Some researchers proposed in the past that shallow subseafloor depths (<; 1,000 ft) were sufficient for permanent CO2 storage in deep marine environments (>; 11,000 ft water depth) (e.g., House et al., 2006). However, the shallow sedimentary subseafloor environment could become unstable and allow release of CO2 into ocean water, the end result of which would be ocean dumping. One mechanism of seafloor instability could be the release of gas from hydrates owing to pressure and temperature perturbations that may be introduced by shallow drilling and CO2 injection. Furthermore, the logistics of transporting CO2 hundreds of miles offshore to areas with sufficient water depths for storage in shallow subsea sediments would probably not be economically feasible. We want to emphasize that subseabed GS of CO2 is not ocean dumping. One of the biggest concerns for onshore GS is the potential to impact shallow drinking water resources. Injecting CO2 deep below the seafloor will avoid this potential consequence. But there are sensitive marine environments of concern in offshore settings, protection of which is critical. Environmental monitoring of marine ecosystems (nearshore, along CO2 pipeline corridors, and outer continental shelf) and subseafloor geological strata in which CO2 will be injected will be a large component of the BMPs. Topics being included in the BMPs, a draft of which will be submitted to BOEM in June of 2013, are: (1) site selection and characterization, (2) risk analysis, (3) project planning and execution, (4) environmental monitoring, (5) mitigation, (6) inspection and auditing, (7) reporting requirements, (8) emergency response and contingency planning, (9) decommissioning and site closure, and (10) legal issues. Where possible, we are using existing regulatory, policy, and technical guidance documents as a starting point for the BMPs. We think the most likely location for initiation of U.S. offshore geologic sequestration of CO2 will be in the western or central sectors of the Gulf of Mexico where extensive offshore oil and gas infrastructure already exists. Academic members of our project team are actively working on criteria for site selection [1]. However, private industry is also assessing the feasibility of offshore geologic sequestration below the Atlantic seafloor [2].

In response to Governor Brown’s January 2016 state of emergency proclamation regarding the Aliso Canyon gas leak, SB 826 (Leno, 2016) requested that the California Council on Science and Technology (CCST) provide the State with up-to-date information on all currently operating underground natural gas storage fields in California. CCST was instructed to provide an independent technical assessment answering three key questions about: The risks California’s underground gas storage facilities pose to health, safety, environment, and infrastructure; Whether California needs underground gas storage to provide for energy reliability through 2020; and How implementation of California’s climate policies changes the future need for underground gas storage. From a statewide field of leading energy researchers, CCST selected Jens T. Birkholzer, PhD, and Jane C.S. Long, PhD, to serve as co-chairs of the 12-member CCST Report Steering Committee – which supervised 21 Report Authors with expertise spanning hydrogeology and reservoir engineering, risk assessment, public and occupational health, greenhouse gas (GHG) emissions, and energy analysis and economics. Each report chapter was subject to a peer review process by independent experts, while another independent expert served as Report Monitor to oversee the process, ensuring that peer review comments were sufficiently addressed in the final report. An additional Oversight Committee reviewed the entire process, including conflict-of-interest declarations. The report’s findings and conclusions are based on a review of published literature and official and voluntary databases, which the Report Authors compiled between January through September 2017, and delivered to the California Public Utilities Commission in January 2018. Key findings and conclusions include: Safety: The risks associated with underground storage (UGS) facilities can be managed, and, with appropriate regulation and safety management, may become comparable to risks in other types of energy facilities found acceptable in California, such as oil refineries and natural gas power plants. At each UGS facility, the State should ensure timely and thorough implementation of the new regulations coming into force in 2018 set by the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR). Those regulations emphasize new and safer well completions, risk and safety management plans, and requirements for well integrity testing and monitoring. The report recommends that the State go further and require more quantitative risk assessment activities, including consideration of human and organizational factors affecting risk. The State should also implement an independent and mandatory review program to evaluate the effectiveness of these new regulations and the rigor of their application in practice, with opportunity for public comment and public dissemination of the review results. Facility-by-Facility Evaluation: Any industrial operation involves some risk to health, safety, and environment. This report assessed various risk-related characteristics across UGS facilities in California, and found a small list of facilities had relatively higher potential risk compared to others. Reliability of Natural Gas Supply: California’s energy system currently requires natural gas and UGS facilities to run reliably, primarily because many residential and commercial buildings in California rely on natural gas for heating during the winter, and because natural gas provides electricity when solar and wind power are not available. The peak demand for natural gas during the winter currently exceeds the ability of pipelines to bring natural gas into the State of California, so natural gas must be stored during periods of low demand in order to have it available to meet peak demand. Near-Term Alternatives to UGS: Closing any or all UGS facilities in the near term would involve replacing UGS facilities with new pipelines or natural gas storage capacity, and require very large investments. Such new natural-gas-related infrastructure would bring its own risks and would further obligate the State to the use of natural gas for decades. The risks, costs, and benefits associated with alternatives to UGS storage should be evaluated accordingly. Long-Term Need for Underground Gas Storage: California’s climate policies in future decades could still necessitate the continued use of natural gas. Also, energy systems that meet the climate goals may require underground storage of natural gas, biogas, or hydrogen, as well as sequestration of carbon dioxide. The State should develop a more complete and integrated plan to understand how the role of natural gas might evolve; assess possible energy portfolios that both meet GHG emission constraints and achieve energy reliability; and consider the potential need for UGS facilities in the future.

Development of Carbon Dioxide Microbubble Sequestration into Saline Aquifer and CO2-EOR Reservoirs