This diary follows up on the matter of the increased ambient methane concentrations detected in an aircraft sampling study in the Uintah Basin, discussed by DK Diarist Fishoutofwater the other day.
FishOutofWater's diary reports on this research by the National Atmospheric & Oceanic Administration and cooperating institutions in which an aircraft measured an increase in the methane concentration of about 8% in Uintah Basin downwind of the large number of gas and oil development compared to upwind concentrations.
Take a hawk's eye view of the thousands of oil and gas well exploration and production sites here using Google satellite for close up views.
I've not yet had a chance to read the complete paper, but the authors describe back calculating through a conservation of mass model the amount of basin emissions that would have had to occur at ground level in order to generate the 8% increase in downwind methane concentrations.
The researcher ultimately concluded in their one day exercise that 60 tons per hour of methane emissions would have had to occur to result in the 8% increase in aircraft-detected methane concentrations. Everyone agrees that the 60 ton/hour rate of methane emissions would be considered a high rate of emissions.
There is a considerable interest in the NOAA research because of ongoing work by EPA to measure and model emissions for inventory and emission factor determination purposes. EPA reduced its emission factor determinations for natural gas well completions in 2013.
The discovery in the Uintah basin methane problem, together with previous air monitoring showing unusual excursions of the National Ambient Air Quality Standards (NAAQS) for ozone during winter snow cover conditions, indicate that the Uintah basin oil and gas industry is likely using process technology having uncontrolled or poorly controlled methane, volatile organic compound (VOC) and hazardous air pollutants (HAP) emissions.
If Utah is allowing uncontrolled methane/VOC/HAP emission sources in the Uintah Basin, then it would be a mistake to assume that the NOAA Uintah Basin study results are predominately reflective of oil and gas industry conduct, facilities and operations elsewhere (in the absence of detailed emission inventory information).
Here is a randomly selected natural gas well production pad:
http://goo.gl/...
The casing wellhead appears to be in the upper middle of the pad. The rectangular unit in the upper right is probably a glycol dehydrator and the tank in the lower right is probably for condensate or natural gas liquids. The small tank-like structure in the upper right is probably a knock-out pot (process for removing entrained liquid aerosals from field gas streams).
The one thing I don't see here is a flare control device to address destruction of hydrocarbon gases generated by the condensate tank.
Gases generated in the natural gas liquids/condensate tank have to be addressed in some manner. Such condensate tanks are charged with hydrocarbon liquids incidental to the production of natural gas. When gas is produced in a natural gas well, methane will be present in any such liquids that are produced. Since the liquids come from a process in which such liquids are under pressure, produced liquids are unstable (i.e. they will fizz like soda) when such liquids are no longer maintained at the pressure of the casing wellhead. The fizzing of produced liquids in the condensation tank leads to large methane emissions from an uncontrolled tank headspace vents.
The only two process approaches available are to either manage the tank at the same pressure as the casing wellhead (pressure vessel approach on the tank without vent)...or to manage the NLG liquids tank at near atmospheric pressure with a vent to discharge tank breathing losses and displacement vapors.
If the facility is managed without pressure vessel control of the produced liquids tank, it must either have some type of an atmospheric vent for uncontrolled process discharge or such a tank head-space vent must be directed to a closed vent emission control system, such as a flare manifold.
However, no flare control units to address condensate tank emissions are visible for the displayed pad and most others nearby. If there isn't any flare control stack visible, then uncontrolled tank emissions from thousands of well pads at very high rates as detected in the aircraft sampling NOAA report are probable.
Under EPA's final national rules, tanks having annual emissions of 6 tons or more of VOCs will have to have a closed vent control system using either a flare or vapor recovery unit. Note that methane and ethane are not VOCs under EPA's rules and definitions. If flare control is used, methane will also be destroyed along with the VOC process emissions. However, if vapor recovery units are used, then the VOC emissions will be controlled, but any methane emissions will not be controlled to the same degree (as would be provided by a flare) because methane is a non-condensible gas under typical process conditions.
3:50 PM PT: I should also add these links for EPA's emission factors for petroleum and natural gas process emission factors:
http://www.epa.gov/...
and
http://www.epa.gov/...