We recognize that reducing air emissions from our operations is crucial to maintaining our license to operate. Please see the discussion of our air emissions performance for further details of our emissions reduction performance.
Emissions Reporting Methodology
To determine the overall greenhouse gas (GHG) emissions across our drilling, completions and production operations, we inventory a range of emissions sources, including flares, storage tanks, fugitive emissions from equipment leaks, engines, liquids unloading, pneumatic devices and electricity usage.
We report our direct emissions (Scope 1) and indirect emissions (Scope 2) as defined by the IPIECA/API/IOGP Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions on an operated basis. We calculate Scope 1 direct emissions from U.S. facilities using EPA’s Greenhouse Gas Mandatory Reporting Rule. We calculate emissions in our facilities in Equatorial Guinea using the API Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry. Our Scope 2 indirect emissions are calculated based on purchased electricity consumption using EPA’s eGrid (Emissions & Generation Resource Integrated Database) emission factors.
Air Emissions Performance
Marathon Oil actively works to reduce our environmental footprint and has a history of taking elective measures to reduce emissions, such as becoming a founding member of The Environmental Partnership. This voluntary group of U.S. oil and natural gas companies has a mission to continuously improve the industry’s environmental performance by taking action, building knowledge and fostering collaboration among stakeholders. We participate in the partnership’s environmental performance programs aimed at reducing emissions of methane and volatile organic compounds:
- Phase-out of high-bleed pneumatic controllers,
- Monitoring manual liquids unloading operations to minimize emissions, and
- Leak detection and repair.
Reducing the GHG emissions intensity of our operations is a central pillar of our climate risk mitigation strategy. We track operational performance through our overall GHG emissions intensity and methane emissions intensity. Intensity metrics are measured as CO2e emissions per thousand barrels of oil equivalent of all hydrocarbon produced. We believe the intensity rate is a more comparable measurement over time because it takes into account our overall activity level, including portfolio changes from acquisitions and dispositions. We initially prioritized methane intensity given its outsized impact on the environment.
In 2019, our global GHG intensity increased approximately 21% compared to 2018. Although we remained in compliance with applicable flaring regulations, the increase was primarily due to higher flaring in our North Dakota Bakken asset, where we rely on third-party gas gathering companies to collect and transport natural gas production. Gas capture performance is therefore highly dependent on midstream performance and constraints on transport outside the region. Regardless of these challenges, we expect Bakken gas capture to materially improve to about 90% in the second half of 2020. This step change is driven by the completion of critical pipeline infrastructure by our midstream provider with a strong proactive assist from our Bakken asset team, which took the lead in securing right-of-way in a timely manner.
There was also an increase in emissions from additional compression and flaring in the Eagle Ford in 2019; however, we’re on track to reverse this trend and reduce emissions in 2020 as a result of enhanced coordination of equipment maintenance. Gas capture dramatically improved in our Permian asset during 2019, approaching 95% by year-end as a result of improved development planning, midstream coordination and additional infrastructure capacity.
In response to this overall increase in emissions intensity, Marathon Oil is actively evaluating the commercial viability of a number of emissions reduction technologies that address the specific needs and constraints of each asset. We expect these measures taken in the Bakken and across our portfolio to reverse the trend in increased emissions intensity in the second half of 2020. With the marked improvement in Bakken gas capture, we expect our overall enterprise gas capture to trend positively toward about 98% in the second half of 2020 compared to just over 94% for 2019.
Our methane intensity decreased 19% in 2019. To manage methane emissions intensity, we eliminated high-bleed pneumatic controllers from all our operations, implemented the use of emission-free controllers and pumps and used ultra-high efficiency flares. In addition, we reduced flash emissions by installing vapor recovery towers (VRT) and vapor recovery units (VRU) where feasible.
- ᵃ Greenhouse gas (GHG) carbon dioxide equivalent (CO₂e) emissions are based on carbon dioxide, methane and nitrous oxide from Marathon Oil-operated facilities only
- ᵇ Permian asset acquired in 2017
- ᶜ UK assets divested in 2019
- ᵃ Permian asset acquired in 2017
- ᵇ UK assets divested in 2019
Emissions Reduction Strategies
In accordance with ROMS, we apply our emission reduction management strategies at each stage of activity: well planning, facility design and engineering, equipment selection, and, ongoing maintenance. Under the ROMS process, our assets report their emissions reductions each year, along with proposed emissions reductions measures, which are then evaluated for implementation. By taking this proactive approach, we are able to share learnings and successful emissions reduction initiatives across our assets, while also prioritizing efforts with the highest impact across our portfolio.
Highlights of our air emissions mitigation strategies include:
These combust gas more efficiently than traditional flares, destroying more than 99% of flare gas, leading to lower methane, carbon monoxide (CO) and VOC emissions.
We use ultra-high efficiency flares in the Bakken, Permian and Eagle Ford assets. This has resulted in substantially lower VOC and CO emissions. Specific regulatory and operating conditions in Oklahoma result in very little flaring, limiting the utility of ultra-high efficiency flares in that asset.
A VRU recovers vapors in crude oil or condensate tanks. A VRT is a tall pressure vessel installed between the production separators and liquid storage tanks to capture pressurized gas that would otherwise be sent to the tanks.
VRUs and VRTs are used at many of our new facilities, where appropriate, to capture additional natural gas and reduce the likelihood of emissions from tank thief hatches.
Weighted Thief Hatches with High-performance Gaskets
Adequately weighting thief hatches reduces the likelihood that vapors will escape from inside storage tanks. Gasket materials that hold up to the elements also reduce the likelihood of tank emissions.
When designing facilities, Marathon Oil considers thief hatch weight and gasket material and selects products that reduce the likelihood of emissions from thief hatches. Using the data captured through LDAR, we’ve been installing and/or upgrading to the latest lower-leak thief hatch models in new facilities across our assets where data indicates it is warranted.
Additional Emission Mitigation Strategies
Infrared Cameras for Leak Detection
Infrared camera inspections detect temperature differences that can indicate equipment gas leaks. In 2019, Marathon Oil recorded a methane leak rate of less than 0.1% across the more than 1.75 million components surveyed at our facilities. We completed over 1,600 surveys at more than 800 locations in 2019.
We repair leaking equipment as soon as practicable, often on the same day the leak is found. Infrared camera monitoring, along with maintenance and operating practices, helps us minimize air emissions from company facilities. Training for infrared camera operators includes certification on thermal contrast, gas plume motion, camera distance limitations and camera adjustments for varying environmental conditions.
All four U.S. business units use infrared cameras to detect leaks at new facilities. The scope and frequency of our leak detection programs are driven by regulatory requirements and risks such as facility size and production throughput. In addition to repairing leaks, we use the data obtained through LDAR to apply technological solutions and make strategic investments to prevent leaks.
Audio, Visual and Olfactory (AVO) Inspections
AVO inspectors use their senses of hearing, sight and smell to help determine if a facility is operating normally. A trained inspector can detect gas leaks.
To mitigate the risks associated with gas leaks, qualified individuals conduct routine AVO inspections of our production locations. A program to survey, prioritize, address and verify is applied with regulations dictating the frequency of inspections.
Field employees are trained to perform AVO inspections for possible leaks as a part of their overall competency training. New employees must demonstrate competency in safety and operating requirements before conducting field work without the supervision of more experienced employees.
Reduced Emissions Completions (REC)
This practice captures gas produced during well completions and workovers following hydraulic fracturing. Portable equipment is brought on site to separate the gas from the solids and liquids produced during the high-rate flowback. The gas can then be delivered to the sales pipeline or routed to a control device instead of being vented. RECs help reduce methane, volatile organic compounds (VOC) and hazardous air pollutants (HAP) emissions during well cleanup. Routing gas to a sales line can eliminate or significantly reduce the need for flaring.
Pneumatic Controllers, Emission-less Controllers and Pumps
Pneumatic controllers help control different process variables, such as pressure, temperature or fluid levels in tanks or vessels. Low-bleed or intermittent-bleed, gas-driven pneumatic controllers emit less gas than high-bleed pneumatic controllers. Pneumatic-driven pumps are used in a variety of applications, but are frequently used for chemical injection needs. Using air instead of gas-powered pneumatic devices to operate pneumatic controllers and pumps also reduces GHG emissions. Electric/mechanical driven, solar-powered controllers may be used in non-emergency service control applications when grid electricity is not feasible. The application is dependent upon specific service and power needs for the drive mechanisms.
Our active program installing or replacing pneumatic-operated controllers has resulted in the elimination of high-bleed pneumatic controllers in our U.S. assets. For example, in our Oklahoma asset over 640 electric/mechanical controllers have been installed on new wellpads, which has significantly contributed to the reduction in emissions. Our central facilities in Eagle Ford all operate on instrument air, which has significantly decreased emissions where there is access to electric power lines. Conversion to instrument air controllers in the Permian is being evaluated to both increase reliability and reduce emissions.
Replacing diesel generators with natural gas-fired generators reduces emissions.
Eagle Ford removed 106 diesel generators for rod pumps from 2014 through 2019. The only diesel generators remaining in the asset are emergency generators at some central facilities.
In the Permian Basin, we removed all diesel-fired generators and replaced them with natural gas-fired units in early 2018. The asset continues to install natural gas-fired units to reduce associated emissions on a per horsepower basis.
Where available, Oklahoma switched from diesel generators used during flowback operations to natural gas generators in 2018, reducing GHG and particulate emissions.
We also began piloting the use of dual-fuel (diesel and natural gas) drilling rigs and fracturing fleets in 2019 to further reduce diesel use.
Reducing Emissions from Liquids Unloading
Artificial lift is a production technology that is used to remove the buildup of liquids that can impede the flow of natural gas through the well.
This includes plunger lifts that use the reservoir’s natural energy to build up pressure and allow the well to flow, reducing the number of times the well must be vented or “unloaded.” Other methods employed for liquids unloading include pumping surfactant/foam down the well to reduce the gas velocity needed to overcome liquids in the well, which often helps to reduce the amount of venting.
Approximately 0.07% of our emissions are from liquids unloading and we use several methods to further minimize emissions associated with unloading liquids from the well. While many factors contribute to the decision to use various forms of artificial lift, including the rate at which liquids accumulate in the wellbore, use of artificial lift can limit the need to manually unload a well. In Oklahoma, we installed 29 plunger lifts in 2019.
We typically rely on artificial lift methods where economic and feasible. In cases where manual unloading is required, we monitor 100% of manual unloading operations to minimize emissions from the process.
Natural Gas Liquids (NGL) Removal Units
These units reduce volumes of gas flared by condensing NGLs from the gas stream that would otherwise be flared due to either a lack of gas connection or gas takeaway capacity constraints. NGLs are condensed from the gas stream to a liquid, which is then transported via truck for sale.
We are deploying NGL units to recover a portion of gas in the Bakken. Approximately five units on average were operating in the Bakken throughout 2019, processing over 1 BCF of gas.
Bitcoin Computer Mining Centers
Utilization of stranded gas to provide electricity generation for computer mining centers.
Bakken piloted the use of stranded gas to provide electricity for bitcoin computer mining centers. Specific conditions are required, and we are looking for additional installations where the application is feasible.
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