Satellite Measurement of Methane Leakage and
Flaring: Comparisons of Vented and
Burned Methane: Oil Sector vs. Natural Gas Sector and Methane Mitigation Going Forward
Atmospheric methane has been measured continuously from
space since 2003, and new instruments have been put in orbit the last few years
to get more detailed measurements of point sources and regional sources. Future
satellite monitoring is expected to employ geostationary observations to get
higher resolutions in specific regions and to better understand daily
variations in methane output by natural sources like wetlands and manure. In
order to get more accurate quantification these efforts require comparisons
between top-down inverse analysis from satellite measurements and bottom-up construction
of emission inventories. However, since the Trump administration’s EPA pulled its
information request for companies to be required to develop their own methane
emission inventories through leak detection, the bottom-up inventories will only
be accurate for the companies that actually do it, which includes many of the oil
and gas majors and some independent operators who are perhaps anticipating that
the requirement will come back at some point.
In 2019 flaring of natural gas from oil wells in the U.S.
climbed to nearly 1.5 BCF/day, between 1.5 and 2% of all gas produced in the
U.S. The bulk of the flaring came from two regions: the West Texas/Eastern New
Mexico Permian Basin and the Bakken oil play in North Dakota. In addition to that,
combined methane leakage from upstream and midstream sectors, ie. from gas
wells, abandoned wells, pipelines, and facilities, is thought to be a similar
amount. However, that methane is not burned so it is significantly more potent
(in the short-term) than flared gas in climate effect. Downstream natural gas
distribution systems also leak methane at about 0.5%, so the total leaked from
the natural gas sector is a bit more than from the oil sector. At least that is
what the bottom up studies – adding predicted total emissions together –
suggest. Natural gas is dissolved in oil in varying amounts in different
hydrocarbon plays and fairways. Thus, natural gas also leaks from oil tanks,
condensate tanks, and other facilities. Quantifying how much leaks from each
sector and comparing is no easy task and requires a significant leak detection
effort. Flaring amounts are fairly well known in comparison.
A new estimate of total methane leakage collected from
satellite data over the Permian Basin indicates that actual leakage is more
than double what it was thought to be. This is concerning for several reasons.
Even though there is a bigger margin of error with satellite data, it is much
less than the increase. First it suggests that leakage is not being measured adequately
on the ground. Second it suggests that some companies could be venting more
than they say. Third, it suggests that this situation is not sustainable in the
long term.
Highest Rates Ever Recorded Over a Hydrocarbon
Field – Permian Basin
The newly estimated leakage rate from the Permian went from
1.2 teragrams to 2.7 teragrams. That would mean that 3.7% of total Permian gas
produced is leaking into the atmosphere. The new estimates come from a study by
Harvard atmospheric scientist Yuzhong Zhang as reported in the journal Science
Advances, with data obtained from the Tropospheric Monitoring Instrument,
on a European Space Agency satellite. Since flaring burns most of the methane
(98-99.8% typically) the data indicates that this is just leaking methane. The
same data over other hydrocarbon fields does not show high leakage rates. For example,
in the Appalachian shale gas areas the methane (including all sources:
wetlands, landfills, agriculture, and manure, etc.) is only elevated in a few
small areas which suggests that the low methane leakage rates reported in the
basin are close to accurate.
Methane Mitigation Going Forward
The following information comes from the Hart Energy article referenced below:
In 2019 Kairos Aerospace investigated methane leakage at 28,000 active wells and 10,000 mile of pipelines covering most of the New Mexico part of the Permian Basin. What they found was that less than 3% of the sites were leaking 70-80% of the methane. That is good news for mitigation. When companies estimate methane emissions they are relying on emission factor of their equipment rather than direct measurement. That means that their estimates are always going to be lower than the actuals. Finding out the causes for the bigger leaks is leading to real reductions:
"As an example, a client from the 2019 survey realized that a significant number of its large emissions were coming from a particular type of thief hatch that was not sealing properly."
Replacement of those hatches is expected to show significant reductions in emissions when the area is resurveyed.
"For one client, Kairos's work identified the root cause for a large portion of emissions was that line pressure was frequently too high in one of its midstream partner's gathering networks, causing venting (as intended) from the pressure relief valves on the tank batteries."
This type of emissions from gathering lines is more difficult to mitigate but can be prevented by better gathering design that reduces bottlenecks leading to high line pressures.
Another example involved a large crude oil gathering and processing facility where actual methane emissions were found to be much higher than estimated. Thus justified investing in a large vapor recovery system that will capture sellable product and allow the facility to stay within permitted emissions requirements.
Below is a graph of methane emissions by source from the Kairos New Mexico study:
Here we see that in the oil-rich Permian Basin most of the methane emissions are coming from well pad tanks 40% and gathering lines 30%. Dry gas areas such as much of (but not all) Pennsylvania do not have such tanks so that limits a major source of emissions compared to the oil fields.
Another very good hot off the press article in the June issue
of E&P magazine focuses on greenhouse gas emissions but mostly on methane
emissions. It gives some insight into evaluation and management and some very
interesting new technologies developed by service providers that are being adopted
by oil majors and independents. Below is a summary:
Companies may categorize methane emissions into two types: operational
– emissions that occur in accordance with equipment designs, and fugitive
emissions – mostly unintended leaks. They may require merging of data to assess
their own emissions sources effectively. Service providers specialize in such data
management. Operational emissions can often be reduced by replacement of equipment
with better equipment. Fugitive emissions most often must be detected and
repaired. There can be some overlap of operation and fugitive emissions for
example when a certain piece of equipment is leak-prone.
Another service provider specializes in developing a
GIS-based platform for mapping data involved in methane emissions management. The
company, Geosite, integrates different kinds of data like satellite imagery, sensor
locations, and drone data through map layers. This can be valuable in a number
of ways from characterizing emissions to aiding field ops in leak detection and
repair (LDAR) activities.
Flaring mitigation is another area where service providers
are offering different solutions. Flare mitigation often involves converting
the burning gas to electricity via gas turbine technology. The problem then often
arises that there are many point sources of power generation and no way to use
the electricity, especially in fields that are far from grids and power users.
One company offers a solution by using the flares to power high-usage data
center servers and computing applications like blockchain that are power
hungry. I’m not sure if they include the dubious and speculative blockchain usage
of cryptocurrency mining. Their process also involves building a grid to
connect the data centers together. Perhaps flares on several well pads could power
an electric frac job or provide power for drilling operations. I wouldn’t be surprised
if flares were adapted to charge batteries that could offer power regulation
and peak shaving for local power grids or some other distributed energy
application.
The Oil and Gas Climate Commission has a $1 billion fund to support
greenhouse gas reduction technology development. Part of that fund was used to
develop a technology to replace pneumatic controllers that run on compressed
methane which is vented in the process with pneumatics that run on compressed
air which is powered by burning natural gas or some other power source resulting
in a significant net reduction in greenhouse gas emissions. The company estimate
that pneumatic are responsible for 20% of methane emissions and that there are about
250,000 of such replaceable pneumatic devices in use in the U.S. which are responsible
for 14 million tons of CO2 equivalent.
A U.S. Oil-Producing Region is Leaking Twice as Much
Methane as Once Thought – by Carolyn Gramling, in Science News, April 22, 2020
Methane Destruction Efficiency of Natural Gas Flares
Associated with Shale Formation Wells – by Dan R. Caulton et al: Environmental
Science and Technology, 2014
Satellite Observations of Atmospheric Methane and
Their Value for Quantifying Methane Emissions – by Daniel J. Jacob et al., in Atmospheric
Chemistry and Physics, 16, 14371-14396, 2016
E&P Operator Solutions: Methane Measurement Understanding the Big Picture - by Ken Branson, Kairos Aerospace, in Hart Energy, May 28, 2020
Keeping a Lid On GHG Emissions - by Brian Walzel, Senior Editor, E&P Mag, Vol 93, Issue 6, June 2020
Logistical, Safety, and Environmental Issues of
Storing Excess Oil During This Oil Crash
With oil storage hubs nearly full and many more than usual full
tankers docked or in open ocean, storage solutions are actively being sought. The
main hubs such as the one at Cushing, Oklahoma are basically full. Plans to add
about 77MM barrels of oil to the Strategic Petroleum Reserve will help but are
not yet approved and it takes time to move that much oil there. The incentive for
storage companies is to buy oil at rock bottom prices and sell later at a significant
profit. But will there be costs to this storage overflow? Are these new and
makeshift oil storage facilities being managed adequately? Will there be spills
due to mismanagement? Will excess oil in storage above ground lead to more methane and VOC emissions?
The Texas Railroad Commission decided against mandatory production
curtailments as many companies are implementing voluntary curtailments. As long
as these makeshift storage facility owners are making storage available there
will be incentive to sell for those who must sell to survive. Oilfield water
storage tanks are being converted to store oil. Pipeline company Energy
Transfer LP is planning to fill their available pipeline capacity to store oil.
The return of oil demand in the near future is unlikely and
it could take a while before it moves much. Both road travel and air travel are
expected to stay down for the time being, especially air travel. Refineries do
not need it. In reality, the oil is safer in the wells but shutting in wells
can cause problems with the wells and add expense especially when resuming production.
There could even be reservoir damage. The International Energy Agency estimates that
global oil demand is down by a quarter. That also means that the announced
OPEC-plus production cuts won’t have the intended effect on prices. With real uncertainty
about re-openings of economies and planned gradual and careful re-openings,
demand is not expected to go near pre-coronavirus levels any time soon. Storage
overflow is expected to continue to be a problem even after some oil demand
resumes. Prices could collapse again to ‘negative on paper’ territory if production
is not slowed enough. The shortage in global storage guarantees it. A recovery
in the oil sector is not really expected till 2022 but in the meantime the level
and speed of demand return will dictate what happens.
Above ground and underground storage tanks, ASTs and USTs
respectively, are regulated at federal, state, and local levels. Spill
prevention, control, and countermeasure (SPCC) plans are required according to
the Clean Water Act (CWA). EPA and OSHA also have requirements for oil storage
management. Tanks must be made to certain specs. Those who operate transfer and
storage facilities also have training requirements dictated by regulators,
usually individual states, under EPA guidance.
References:
Wanted: Somewhere, Anywhere, to Store Lots of Cheap
Oil – by Rebecca Elliott, in The Wall Street Journal, May 11, 2020
The Hunt for Oil Storage Space is On – Here’s How it
Works and Why it Matters – by Sam Meredith, in CNBC, April 22, 2020
Breaking: Images of Fully Loaded Oil Tankers Stranded
At Sea – in Sahel Standard Magazine, April 29, 2020
Storage Tank Regulations – by Kaela Martins, Retail Compliance
Center, Retail Industry Leaders Association (rila.org), April 14, 2020
Oil Glut to Halve in May and Shrink to 6mbpd in June:
Rystad – by Carla Sertin, in Oil and Gas 360 (oilandgas360.com), May 3, 2020
The Absurdity of Attribution Science: Arguments Against the
Quantification of Blame
The headlines that say just 70, or 90, or however many
companies, are responsible for all the carbon emissions and should be somehow
punished show an ignorance and an anti-corporate bias. Of course, affordable
and readily available energy is the cornerstone of a successful modern economy
and society. That society demands affordable energy. Handicapping those who
provide it will not work. It will simply make that energy less affordable. That
is a good basic argument against large carbon taxation. The goal of carbon taxation
is to entice consumers to use less fossil energy. It should not be a means to
punish those who produce that energy. But it certainly can be.
One might say that since the advent of fracking in the U.S.
made electricity and gasoline significantly cheaper, then consumers should have
used their savings to buy renewable energy – rooftop solar and electric vehicles.
Some of us did but the overwhelming majority did not. Much of this is due to
the high initial investments required. This shows that due to cost renewable energy
will likely not be widely adopted without some sort of government requirement
to decrease the affordability of fossil fuels.
The attribution of blame for the carbon dioxide put in the
atmosphere is another example, this one being used by the IPCC and the UN in
attributing cost structure liabilities for different countries in the fight
against climate change. If blame is assigned value, then why not improvement?
The energy provided to cause those emissions triggered vast improvements in
human well-being. Should those not have a value put on them as well? I’m not
saying the whole valuation should be abandoned but that it should be reasonable
and not overly punishing to high-emitting countries. Often, such attribution,
is attribution of blame, and is used as a political tool. One reason the U.S.
is not so gung ho about the Paris Climate Accord is that the U.S. is punished
by having to pay a higher cost due both to its high historical emissions and
its high per capita energy use. That makes it very easy to group it as yet another
instance where a UN or world body requires the U.S. to pay proportionately more
than the Europeans and others. We pay more in other groups like NATO due to our
prosperity as payments often are set at % of GDP, while the Europeans more often
than us do not even meet those criteria. If the UN wants to get the US back in
the Paris Accord, then they should perhaps provide one clear incentive – a significant
discount – since some is better than none.
The governor of New Jersey has stated that he would like to
collect money from these flimsy bogus lawsuits against companies like Exxon for
covering up climate science – mind you, in times when climate science was not
even moderately well-established among actual climate scientists – and use it
to further harm them. The lawsuits are patently ridiculous and should not even
be heard. Several cities have stated that they would like to sue and use the
proceeds to shore up climate change preparedness. Of course, cities and states
are huge consumers of fossil fuels. Preparedness against weather events is a
good idea but making others pay for it is not.
Another issue is that of groups of youths being encouraged
to file lawsuits against fossil fuel companies for possible future harm from
their emissions. It is a waste of time and resources and mainly a political
ploy to increase pressure. The future of such litigation probably rests on
whether sympathetic judges can be found. Proponents of the suits like to
compare them to litigation against tobacco companies for advertising and promoting
smoking. But smoking is a choice and in contrast, use of energy is a basic
necessity.
The problem with this attribution science is that it is not
really science. It is rather a means of attributing punishment value and a
means of economic redistribution. Fossil fuels are distributed unevenly around
the world and those endowed with them should not be punished simply for developing
what they have.
Essentially, attribution science is like any risk assessment
where risk is evaluated and quantified. Of course, quantification of risk is
highly debatable and requires scientific experts to estimate accurately. In
these litigation examples it is often the highly biased accusers doing the
assessment, aided by sympathetic judges and some experts, usually outspoken and
arguably biased ones.
Overall, I think this so-called attribution science is a
trend that is not sustainable, at least the way it is being done by bias and
activism. It is unsustainable and not viable as it is tainted by ideology. Any
true attribution or quantification of risk and harm would need to be as
unbiased as possible, perhaps done via scientific council of diverse groups of well-respected
authorities rather than ideological and biased groups with an agenda to punish.
So far, sanity has been maintained, as most of theses climate
lawsuits have been thrown out. Likely, they will continue to be dismissed but
will some eventually get through with sympathetic judges and governments? Let’s
hope not. There are better ways to address the issue.
References:
Climate Change Lawsuits Collapsing Like Dominoes – by Curt
Levey, in insidesources.com, March 5, 2020
Big Oil and Green Energy: A Long History of Collaboration, Recent Moves,
and Allocating Capital as a Hedge Against Future Contraction in the Oil &
Gas Industry
Big Coal vs. Big Oil
The U.S. coal industry has been in a state of decline, a
state of contraction, for several years now. Bankruptcies are common, coal use
continues to decline, few new mines have been opened, and no new coal-burning
power plants are likely to be built in the U.S. While there is some occasional
export growth in metallurgical coal, thermal coal continues to stagnate and
that is very unlikely to change. There is little upside potential for coal
companies to transition into companies with cleaner portfolios. Aside from a
few vague and thus far uneconomic opportunities to do things like deriving rare
earth elements from coal mine tailings or coal ash or to use coal ash to make
high-strength carbon materials there is little upside potential for company transitions.
On the other hand, oil majors have long been investing in green tech and
renewable energy. Such investment has waxed and waned through the years as
company profits have risen and fallen. Exxon has been developing algae-derived
biofuels for many years. Exxon was also instrumental in the development of the
lithium battery, especially through the work of employee John Goodenough, who led
the research and development of lithium battery technology.
The Long History of Big Oil and Green Energy
Collaboration
In the recent book, The Wizard and the Prophet: Two
Remarkable Scientists and Their Dueling Visions to Shape Tomorrow’s World, author
Charles C. Mann notes that at one point in the 1970’s the two biggest developers
and utilizers of photovoltaic solar panels were the Pentagon and Big Oil. The
main uses were military satellites and powering offshore oil platforms. Indeed,
70% of all solar panels were bought and deployed to power those platforms. Thus,
the collaboration between Big Oil and green energy goes back about half of a
century. The following paragraph from the book is a good summary:
“Realizing that
solar had become essential to oil production, petroleum firms set up their own
photovoltaic subsidiaries. Exxon became, in 1973, the first commercial manufacturer
of solar panels; the second, a year later, was a joint venture with the oil
giant Mobil. (Exxon and Mobil merged in 1999.) The Atlantic Richfield Company (ARCO),
another oil colossus, ran the world’s biggest solar company until it was
acquired by Royal Dutch Shell, the oil and gas multinational. Later the title
of world’s biggest solar company passed to British Petroleum (now known as BP).
By 1980 petroleum firms owned six of the ten biggest U.S. solar firms, representing
most of the world’s photovoltaic manufacturing capacity.”
Much of the initial green energy investment by oil majors
was prompted as well by notions common at the time that oil was likely to run
out sooner rather than later. Peak oil production and resource depletion was a
serious concern in those times. Investments went up and down with the latest
reserve estimates as well as with the latest profits of the oil majors.
Revival of Green Energy Investment by Oil Majors, Particularly
European Oil Majors
Several of the multinational oil majors, particularly the
ones based in Europe, have indicated that they intend to move toward carbon
neutral operations by 2050. That plan includes more investment in renewable
energy companies as well as R & D. European oil and gas major in particular
have made recent acquisitions in solar and offshore wind. France’s Total has
controlling interest in major solar player SunPower and recently brought its renewable
energy portfolio to 5.1 gigawatts. BP, Galp, Eni, Equinor, Repsol, and Shell
also have large amounts of renewable assets. The biggest solar asset owner
outside of China is NextEra Energy with about 4.6 gigawatts but Total is
closing in with diverse solar assets spread across 15 countries. Total is
apparently focusing on solar in its goal to get 20% of its revenue from low
carbon businesses by 2040. Equinor is leading oil and gas sector investment in
wind, expected to be 4.6 gigawatts by 2025 while Shell projects 1.8 gigawatts
in wind investment by 2025. That would give Equinor and Shell about 6% of
global installed wind capacity by 2025. Total has also been moving into
offshore wind investment. Another collaboration is reviving the utilization of green
energy from onshore or offshore to power offshore oil platforms.
One reason European oil and gas companies have been
investing in renewables is shareholder pressure. Such pressure is less in the
U.S. so far but could increase. Companies like Exxon and Conoco are thought to
be readying for such a trend if it looks likely to happen. Aside from shareholder
demands, some form of carbon taxes could make oil and gas less profitable and
renewables more profitable so readiness could be important. Thus, in some ways
it could be seen as a hedge against possible future contraction in the
industry. With the coronavirus majorly impacting oil demand we can get a
glimpse of what a drop in oil demand can do and already the prospects are not
good. Oil majors may also hedge by focusing on downstream refining and
petrochemical production.
Big Oil and Renewable Energy R & D: New
Projects Include Green Hydrogen Development
Aside from investment in utility-scale solar, (mostly) offshore
wind, and associated infrastructure, there are a few other Big Oil R & D
projects worth noting. One is Shell’s project in developing so-called Green
Hydrogen. The project is only in feasibility phase but the plan is to develop
3-4 gigawatts of offshore wind capacity in the North Sea to power by 2030 to
make hydrogen, with dynamic, quick-start/quick stop, electrolyzers along the
coast of the Netherlands and offshore. Although less than 1% of hydrogen
currently comes from renewable energy that percentage is expected to grow quite
a bit this decade, eventually beginning to displace oil. If enough European renewable
energy is curtailed due to peak generation and peak demand imbalance then
prices for that excess drop. The dynamic electrolyzers could be set to quickly use
excess renewable generation, take advantage of low dynamic pricing, and help
wind and solar generators to sell excess at reduced rates rather than lose it. Hydrogen
can be stored in large tanks for later use, for industrial applications, or to
power fuel cells. However, in order for green hydrogen to be economic relative
to hydrogen made from fossil fuel, usually natural gas, the cost of renewables relative
to gas would have to drop by 2-3 times. That could happen by 2030 which would
be the bet. If carbon taxes get ratcheted up by then that is a pad for the bet.
Nonetheless, it is a risky endeavor at present. Even so, WoodMac notes that global
green hydrogen deployment, currently as 252 megawatts, is expected to grow to
3205 megawatts by 2025. That is a big jump. Economics are expected to improve by
2030.
References:
The Solar Industry’s New Power Player: Oil Majors – by Jason Deign, in
GreenTech Media, Feb. 26, 2020
Shell Exploring World’s Largest Green Hydrogen Project – by John
Parnell, in GreenTech Media, Feb. 27, 2020
The Wizard and the Prophet: Two Remarkable Scientists and Their Dueling
Visions to Shape Tomorrow’s World – by Charles C. Mann, (Alfred A. Knopf, 2018)
Could Green Hydrogen Become the New Oil? – by Stephen Lacy, in
GreenTech Media, Jan. 23, 2020
Energy Transition: The Future for Green Hydrogen – by Wood Mackenzie,
Oct. 25, 2019
