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Revisiting a Major Methane Study

by Michael Levi
October 12, 2012

The ongoing fight over whether shale gas operations are leaking dangerous amounts of methane – a question that many have called critical to determining whether shale gas is good or bad – has suffered from a paucity of data. That’s why a much talked about study, authored by thirty scientists (mostly from NOAA) and published in early February, made such big waves: it was the first (and remains the only) study to estimate shockingly high emissions based on actual observations in the field (data was collected in Colorado in 2008).

In a new paper in press at the Journal of Geophysical Research (preprint here), the same journal that published the NOAA results, I explain why the NOAA estimates are unsupportable. (Short version: great data; wrong interpretation.) I then exploit some data that the NOAA team reported but did not use in their calculations to re-estimate methane leakage rates. I find methane leakage rates that are most likely between 1 and 2 percent, very similar to what previous careful estimates have consistently indicated, but far lower than the rates — as high as 7.7 percent — that the NOAA study claimed.

I might try to explain the technical issues involved in the analysis in a future blog post. (Summary: The original paper relied on a critical but flawed assumption; my paper does away with it.) For now, though, I want to focus on the big picture. It’s summed up in the figure below, which is taken from my paper.

The NOAA authors estimated emissions in two ways. The first was a traditional “bottom-up” method (second from the right) based on past observations of emissions from various gas-related processes. That yielded an estimate that about 1.7% of total production was leaking, with a possible range of 1.3-2.0%, similar to previous analyses. The second was the “top-down” method that generated such alarm (far right), which took observations of methane in air and used some simple calculations to infer estimates of how much methane was leaking from natural gas systems. That approach implied that 2.3-7.7% of produced gas was leaking, with a best guess of about 4.0%. Those are indeed massive numbers.

My new analysis of the top-down numbers paints a far less shocking picture. My paper reports its results in terms of absolute leakage, as the original paper does, but since people are more used to thinking about leakage rates, I’ll use those here. Using the same method for converting absolute leakage to percentage rates that the NOAA authors used, I find that leakage is most likely 1.5-1.7%, with a possible range (using a very conservative estimate of uncertainty) of 1.3-2.3% (far left in the figure). This is similar to what bottom-up estimates, not only from the NOAA authors but from places like the EPA, have found.

There are, of course, big limits to my own analysis. That’s in part because I’ve kept much of the original paper’s methodology (which that paper and mine both point out has limitations) intact. It’s in part because the underlying data that I’ve analyzed comes from only one region at one point in time. (Among other things, Colorado has imposed tough rules on methane emissions since the NOAA data was collected in 2008.) I’d still like to see more data, and am glad that people appear to be hard at work collecting it (kudos to EDF), but for now, I’m deeply skeptical of claims that massive amounts of methane are leaking.

Post a Comment 3 Comments

  • Posted by David B. Benson

    Except out of permafrost and the Arctic Ocean seabed.

  • Posted by Michael Berndtson

    Michael, you write above the following:

    “I might try to explain the technical issues involved in the analysis in a future blog post. (Summary: The original paper relied on a critical but flawed assumption; my paper does away with it.) For now, though, I want to focus on the big picture. It’s summed up in the figure below, which is taken from my paper.”

    I’m confused. Which paper makes a flawed assumption? NOAA’s or your original paper? What’s the critical, but flawed assumption?

    [ML: The NOAA paper is the original (i.e. first) one. It makes the flawed assumption about the ratio of methane to propane in vented gas.]

    Anyway, I’m kind of perplexed on this issue even after reading this post and both papers. Is bottom up fugitive emissions rate based on vapor samples collected at well heads, process piping and vessel for determining a mass balance? In other words, how much gas comes out of the well head is greater then what is determined downstream after manifolding and storage? And top down emissions rate is determined from atmospheric sampling? If so there seems to be a huge potential for variability – not only in sampling technique and analysis, but on per well PVT conditions, per well, per play and region basis. Most importantly, on whether a well is producing dry gas, wet gas or oil liquids with gas as a by-product. And most-most importantly, who tightened the flanges and did they forget a gasket. My experience leads me to believe a range is simply to be expected and should be published accordingly.

    After reading your paper (which is very good by the way – you’d make an excellent chemical engineer), I have to ask why is this an issue of concern. It doesn’t seem to be an O&G operating issue or really an environmental monitoring issue to me – as long as the sampling technique, conditions upon sampling and uncertainties are recorded somewhere.

    [ML: The issue is that if the NOAA team is right and you have as high as 8 percent methane leakage then you have a big climate change problem.]

    My cynical self seems to believe its more of a private sector versus government argument refereed by EDF. I’m already seeing your analysis cited in various blogs and comments sections with statements like: “here’s proof in a paper by Michael Levi that NOAA’s bad, private sector good, get the government off our backs.” (I made that up by the way.)

    [ML: As someone who works at a non-profit, I certainly don't see it that way.]

    Anyway, good stuff. I guess we’ll see what EDF et al find out next year. Thanks, Mike Berndtson

  • Posted by Michael Berndtson

    Michael, thanks for your comments and answers to my questions. I more carefully read (not skimmed) the papers and got a pretty good understanding of the sampling methodologies. Blog post commenting is a skill I have yet to master. As I understand it, the source of fugitive emissions are venting be it from the well head or pressure relief at vessels. In general, the predominant emissions sources. Per NOAA and you.

    I really can’t comment upon the analysis by either NOAA or you. Both use equations and assumptions found in chemical engineering books sitting in a box in my basement that I haven’t opened in 30 years. I’m fairly familiar with environmental media sampling be it solid, liquid or vapor from processes or ambient sources. Here’s some thoughts on the physics leading up to the math:

    The Colorado DJ basin in a pin cushion with oil and gas drilling starting in the early 20th century. Crazy reported recovery schemes like sinking 3 foot diameter mine shafts for deep sump pumping oil were attempted in the 1970s during the oil embargo. And of course the hydraulic fracking boom going on today. The point being is that the potential for gas leakage from wells and other drilled conveyances is very high. Offsetting the results between process bottom up sampling and top down atmospheric sampling.

    The DJ basin is still in the Front Range bowl sort of. So highly dependent upon wind and weather from day to day and sampling event to event. I’m not sure how NOAA took this into account beyond averaging and long-term duration sampling. Still a low pressure atmospheric system can greatly effect the rate of leakage from the subsurface simply by differential pressure gradients between atmosphere and subsurface.

    The DJ basin is shallow and ranges from a bit less than 4,000 feet bgs to a bit over 8,000 feet bgs depending on dip. Deep for water wells of course, but pretty shallow for fracking wells. This leads to an enormous range of potential for surface leakage either from wells or vertical fractures generated by hydraulic fracturing.

    Multi-phase fluid mass and volumetric flow rate measuring is highly variable. Basically the rule of thumb is the dryer the gas the more accurate the flow rate – with liquid mass measured upon separation. Most natural gas metering is done after liquids separation – and coincidentally a good place to look for fugitive gas leakage.

    This is what I’m getting at:

    There is probably a slim chance to ever have top down and bottom up measurement agreement as you already know. However, there is one thing that seems plausible for a shallow basin like the DJ. A difference between the two sampling methodologies could be due to natural gas escaping from vertical fractures that went “rogue”. This would be fractures from horizontal hydraulic fracturing that did not stop as intended, but blasted past the tighter rock formations and into the near surface more permeable rock and soil. This source would not be accounted for from bottom up monitoring. Only the top down measurement from air sampling. This gas would not be collected at the well since the path of least resistance is up.

    I’ll stop obsessing. This energy and climate change thing has kind of captured my attention. Great work, btw.

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