Liquid Storage tanks for Hydrocarbons
Updated: Aug 22, 2021
Storage vessels in the oil and natural gas sector are used to hold a variety of liquids, including crude oil, condensates, and produced water. Crude oil and condensate may be stored in fixed-roof, atmospheric pressure tanks between production wells and pipeline or truck transportation. In offshore fields, the storage tanks on production platforms, floating production, storage and offloading (FPSO) vessels and floating storage and offloading (FSO) vessels contain crude oil and/or condensate, produced from connected wells or coming from nearby platforms. Light hydrocarbons dissolved in the crude oil or condensate under pressure (i.e. unstabilized hydrocarbon liquids)—including methane and other volatile organic compounds (VOC), natural gas liquids (NGLs), hazardous air pollutants (HAP), and some inert gases—will flash (vaporize) from the liquid stored in the tank and accumulate in the vapours space between the liquid surface, the walls and roof of the tank. Fixed roof tanks can not contain any significant pressure above atmospheric pressure, and therefore these vapours must be vented.
Emissions from storage vessels are a combination of flash, working, and standing losses. Flash losses (the most significant of the three) occur when a pressurized liquid with dissolved gases is transferred from a well or vessel at higher pressure to a fixed roof, atmospheric pressure tank. The pressure drop causes gas to rapidly evolve from the liquid and/or vaporize (i.e., flash). Working losses refer to vapours above the liquid surface pushed out by rising liquid levels and agitation of liquids in tanks associated with circulation of fresh liquid through them. Standing losses refer to vapours expanding and venting associated with daily and seasonal temperature and barometric pressure changes. Onshore field production sites are generally designed and operated to push the liquid from a gas/liquid separator vessel at a higher pressure to the tank so that the liquid will fill the tank without the use of a pump. This results in some flashing emissions.
The volume of vapour emitted from a fixed-roof storage tank is dependent on several factors, most significantly the pressure in the gas/liquid separator and the oil or condensate flow rate from this separator into the tank. That is, the greater the differential in pressure between the separator and tank, the higher the flashing losses. Lighter crude oils (API gravity >36°) flash more hydrocarbon vapours than heavier crudes (API gravity <36°) at the same separator pressure. Additionally, in storage tanks where oil cycling is frequent and overall throughput is high, more working losses will occur than in tanks with low throughput and where oil is held for longer periods of time.
The composition of tank vapours varies based on the type of production and the types of hydrocarbons that are being produced from the reservoir. Often methane is the primary component of tank vapours(between 40 and 80 percent for crude oil and gas condensate), but other compounds may be present in lesser quantities, including more complex hydrocarbon compounds such as ethane, propane, butanes, pentanes, natural inert gases such as nitrogen and carbon dioxide, and hazardous air pollutants, like hydrogen sulphide, benzene, toluene, ethyl-benzene, and xylene.
At times, unintended methane emissions not associated with crude oil or condensate flashing may enter and vent from tanks. For example, if a gas/oil separator dump valve sticks open due to physical erosion of valve seats or solids plugging or liquids freezing in the valve that prevents the valve from closing, bulk gas can be entrained with the oil to the tank resulting in methane emissions exceeding calculated flashing losses. Because the source of emissions is not at the dump valve, and vent emissions from an unmitigated or malfunctioning mitigated tank is assumed to come from the separator liquid, fugitive emissions monitoring may not identify this through-valve leaking component: it is related to tank operations. Partners should identify this malfunctioning source during tank inspection and repair or report emissions under the Fugitive Component and Equipment Leaks source as part of the Directed Inspection & Maintenance (DI&M) programs.
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