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.
References:
Satellite Data Show ‘Highest Emissions Ever Measured’ from U.S. Oil and Gas Operations – Environmental Defense Fund, accessed in phys.org, April 23, 2020
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
No comments:
Post a Comment