Heater treaters can be significant sources of “flash gas” from oil and gas production facilities. Flash gas is natural gas that is released from a wellstream when the liquid undergoes a pressure drop or when the liquid’s temperature is increased. In a heater treater, the crude oil/condensate and produced water experience a pressure drop and a temperature increase. The greater the pressure drop and operating temperature, the greater the amount of flash gas generated per barrel of oil throughput.

Figure of Typical Vertical Heater Treater

Heater treaters are heated, vertical or horizontal separators that are typically used for the following purposes:

  • Break up emulsions to separate the oil from produced water and inorganic salts
  • Solids (sediment) removal
  • Stabilize the crude oil or condensate by separating volatile, lighter hydrocarbon fraction (C1-C4) from the heavy, less volatile fraction (C5+) for safety reasons
  • Reduce the volatility (e.g., vapor pressure) of the oil

BS&W (basic sediment and water) present in most crude oil can be an emulsion of oil, water and sediment. Most crude oil purchasers have a maximum specification for BS&W content, usually less than 1 percent, although BS&W up to 3 percent can be common for transported crude oil/condensate.

Typical heater treater pressure and temperature operating conditions which affect flash gas release include the following.

  • Pressure: 20 to 80+ psig
  • Temperature: 160 to 250 °F

These parameters are dependent on many factors including pressure needed to send the oil to the storage tanks, emulsion type, API gravity of the oil, oil throughput and treatment needed (e.g., BS&W removal, stabilization).

The heat source for heater treaters can include indirect firetube heaters, water baths and waste heat recovery systems. For most onshore oil and gas facilities, natural gas firetube heater treaters are commonly used. For offshore platforms and larger processing plants, waste heat recovery systems (e.g., heat supplied by waste heat from engine/turbine exhaust) can be used.

Heater Treater Flash Gas

The flash gas generated in a heater treater will be high BTU gas ranging from 1500 to 2500+ BTU/SCF and so will have a very high VOC content (>60% by volume VOC). Also, the flash gas will contain methane (CH4), a greenhouse gas. This is important for compliance with air quality regulations and permits and reporting of greenhouse gases (GHG) under 40 CFR 98 Subpart W. Typically, higher VOC content gas will have more regulatory control requirements.

Flash Gas Destination

Air permits and GHG reporting for production facilities require companies to account for all emissions from their sites. If the flash gas is vented to the atmosphere, then the emissions of natural gas (VOCs and GHGs) must be accounted for in the facility’s air permit and GHG reporting.

Recovery of this gas reduces VOC and greenhouse gas emissions.

Many companies route this flash gas to the suction of a booster compressor, vapor recovery unit (VRU) or to a combustion device (ECDflare). This is done for economic, safety and air permitting reasons.

As a facility’s oil production rate declines with time, the heater treater may be changed to vent to the atmosphere based on heater treater design capacity – resulting in a new emission source of VOCs. A modification to the facility’s air permit may be required to vent the flash gas to the atmosphere.  A good management of change (MOC) system can be used to ensure that the heater treater flash gas is recovered or controlled (VCU, flare) and permitted within compliance with applicable regulations.

Quantification of Heater Treater Flash

Methods used to quantify the amount of heater treater flash gas produced include:

  • Direct measurement of gas with a flow meter (Cimarron IQR service)
  • Simulation using equations of state models (e.g., HYSYS, PROSIM, VGMSim)

The flash gas volume of VOCs and methane liberated from heater treaters can be at a very high rate and may exceed the amount of flash gas liberated from atmospheric storage tanks. This would be a function of the pressure drop occurring at the heater treater, operating temperature and throughput of oil.

Vent gas rates of 20,000 standard cubic feet per day (SCFD) or higher can be generated in a heater treater depending on operating conditions and oil throughput.

Periodic measurement of heater flash gas can yield valuable information especially after changes in production (new wells, natural decline). This information can help with decisions regarding process changes that affect profits (amount of gas recovered) and to ensure air permit compliance.

Vapor Recovery and Controls

As oil production increases or declines with time, a facility should reassess the methods used for recovery and/or control of the heater flash gas.

Flash gas that is currently combusted in a flare or enclosed combustor may be economic for recovery using a VRU. A VRU can boost the flash gas pressure high enough to send it to the gas handling system (e.g., low pressure suction of booster compressor). Recovering the flash gas rather than flaring reduces the facility’s greenhouse gas emissions since flaring gas results in CO2 emissions.

NOTE: a VRU that recovers the gas is process equipment and not emission control device according to federal EPA rules in NSPS OOOO/OOOOa.

Flash gas that cannot be recovered with a VRU or routed back to the gas handling system can be sent to a vapor combustion unit (ECD or flare).

The high BTU content of heater treater flash gas makes this gas stream of considerable value that increases facility profits when recovered and sent to sales. Companies looking to increase profits and reduce emissions will take step to quantify and recover this gas stream (IQR).

Cimarron Products and Services

Let Cimarron assist your company stay in compliance with EPA and state vent gas regulations. Our products and services include the following:

  • Vent gas measurement and leak detection using our IQR services
  • Tankless facilities
  • Vapor recovery units (VRU)
  • Vapor recovery towers (VRT)
  • Vapor combustion devices (ECD)
  • Flares
  • BTEX controls for glycol dehydrators
  • Field Service (VRU/VCU maintenance, tank seal inspection/replacement, leak detection)
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