Energy Transition #6: How the Upstream Industry Can Reduce GHG Emissions

One of the first steps of the Upstream Energy Transition is to improve efficiencies of current facilities and particularly to reduce Greenhouse Gas (GHG) emissions.  Decarbonisation was discussed previously so this article is particularly about reducing methane and volatile organic compound (VOC) emissions.  The Upstream industry has a corporate responsibility to reduce these emissions and deliver Safety, Environmental Stewardship, and Value Recovery.

The 2015 United Nations Framework Convention on Climate Change Paris Agreement identified pathways to reduce the atmospheric methane burden as part of the commitment to reduce Greenhouse Gas (GHG) emissions.  Methane is the second most important anthropogenic GHG[1] and it has a 100-yr global warming potential (GWP) of 28-36 compared to CO2.  (Sometimes methane emissions are quoted with the 20-yr GWP which is 84-87 compared to CO2.)  Methane only lasts about 10-12 years in the atmosphere, whilst CO2 lasts thousands of years.  Measures to mitigate methane emissions can therefore have a rapid positive effect on climate change due to their short life duration.  Anthropogenic sources of global methane emissions were estimated in 2017 to be 380 Tg CH4 yr−1 and of this total 84 Tg CH4 yr−1 was estimated to be from oil & gas fossil fuels.[2]  Agricultural and fossil fuel sources of methane emissions are roughly similar with agricultural sources (enteric fermentation and manure) about 115 Tg CH4 yr−1.

Methane and VOC emissions are critical as follows:

  • Safety – methane leaks can accumulate to critical levels and constitute fire and blast risks; and VOC leaks pose significant personal health risks to people;
  • Environment – as noted above, GHG’s directly impact climate change;
  • Value – every hydrocarbon molecule emitted and not contained is unable to be monetised.

Methane/VOC emissions can be several types:  (1) “fugitive”, e.g. from unplanned leaks; (2) “engineered”, e.g. where instrument gas is used in pneumatic controller devices; and (3) “maintenance practices”, e.g. blowdown of equipment or pipelines to prepare for some kind of work.  This article does not address combustion emissions.


Every connection, instrument, valve, static equipment (i.e. separators and piping), and rotating equipment (i.e. compressors and pumps) could develop integrity issues and start leaking hydrocarbons, often under pressure and temperature.


Instrument gas has been historically used to operate equipment and pneumatic controls near wellheads and other locations away from main facilities (e.g. along pipelines) where a source of instrument air and electric power may not be available.  Three types of gas driven pneumatic controllers were used[3].  (1) Continuous bleed pneumatic controllers with a continuous flow of gas to the device (i.e. level control, temperature control, pressure control) where the supply pressure was modulated by the process condition after comparison to relevant set points to adjust valve actuators.  Two types were common:  low bleed (≤6 std ft3/hour) and high bleed (>6 std ft3/hour) – imagine these emission rates times many hundreds of thousands of devices (e.g. >2,000,000 oil & gas wells in North America alone).  (2) Intermittent pneumatic controllers vented non-continuously, so less emissions.  (3) Zero bleed pneumatic controllers vented gas downstream to lower pressure piping or lines.  For the past 5 years, there has been a big industry push (in response to regulatory pressure) to switchover to zero bleed pneumatic controllers where possible, otherwise change the type of actuators (e.g. solar powered batteries, electro hydraulic actuators).

Similarly pneumatic pumps using instrument gas have also been used historically where electricity was not readily available.[4]  Gas pressure was used to drive a fluid, varying the pressure by means of positive displacement or rotating impellers.  Alternatives to gas-driven chemical injection pumps have been pursued to eliminate venting emissions.  Over 100,000 such pumps were estimated to be present in Alberta Upstream Oil and Gas Assets alone.[5]  The most common alternative has been solar chemical pumps (SCP) with solar PV panels, battery back-up, and an electrical pump.  Fuel cells have also been investigated.

An important benefit of solar-powered battery-backup systems is the ability to transmit data to remote or central control centres using Wireless HART or Wi-SUN field area network systems to allow more real-time analytics and optimisation of operating settings.  In this case, Digital Transformation can also help the Environment.


An oil and gas facility could contain equipment and piping systems containing various amounts, pressures, and temperatures of liquid and gas hydrocarbons.  Prior to any maintenance work, the systems would need to be made safe and ready to be opened up to atmospheric conditions.  This usually meant isolating the necessary systems and then relieving their contents through flare or vent blowdown systems.  It meant that some quantity of methane and VOG’s would have been released to the atmosphere with this procedure.

With better awareness of the consequences of GHG releases, alternate means of making these systems safe for maintenance needed to be developed and it happened.  Identifying higher frequency intervention locations during development would allow better positioning of manual isolation valves to isolate the subject equipment or piping system requiring maintenance.  Then special vacuum / compressor units (e.g. TPE’s ZEVAC) could use compressed air to suction out remaining hydrocarbons and compress the gas into adjacent piping (outside of the isolated section).  This is an emission-free operational procedure which could be used to avoid unnecessary releases of GHG in this maintenance scenario.

Methods of Detection

Fortunately we have a number of good technologies and tools to detect methane and VOC emissions.  Two types of quantification methods are used[6]:  Bottom-Up (using individual site measurements and reports) and Top-Down (using satellite, aerial, and drone sensor measurements across large areas).  Bottom-Up methods can help identify specific locations of emissions within a particular facility but may not be as accurate on a larger scale (due to under/lack of reporting for individual sites).  Top-Down will capture better overall quantification and can rapidly identify “super-emitters” (who may be known or unknown) to the responsible parties and regulators.

To better appreciate the challenge of finding leaks, it is good to review some North American industry statistics. Carbon Limits analysed data from 4,378 Leak Detection and Repair (LDAR) surveys.[7]  From these surveys, 58,181 emission sources were identified.  Emission points were classified into (1) leaks (unintended emission points) and (2) vents (engineered emission points).  Note that the facilities surveyed were regularly surveyed, so that other facilities without regular surveys may have higher numbers of emission points.  In average six (6) leak points were identified in each survey.[8]  There was a wide scatter of results with a small number of facilities having up to 267 leaks (at a gas plant).  Some positive news was that ~64% of the leaks detected (and ~50% of the leak rate) could be repaired without needing a shutdown.  About 6% of the leak locations (representing ~50% of emissions) emitted more than 1 ft3/min and were classified as “super-emitters” and these kinds of leaks need rapid identification and mitigation.

The Climate and Clean Air Coalition (CCAC) Oil & Gas Methane Partnership (OGMP) developed a list of nine “core” sources of methane emissions[9] which should be used to help plan potential emission point surveys:

Bottom-Up Detection Technologies

They can be fixed and/or mobile IoT sensors including the following:

  • Distributed Pressure/Flow monitoring with imbalances identified (potentially Edge processed);
  • Optical leak imaging – infrared (IR) cameras (typical detection limit ~0.8g/hr for methane);
  • Laser Leak Detector – An example is a Remote Methane Leak Detector (RMLD).[10]  Detector uses a tuneable diode-infrared laser at a frequency absorbed by methane, allowing it to detect any methane present in a gas plume from a maximum distance of 30 meters.  When the laser beam from the RMLD passes through a gas plume and is reflected back to the camera, it would detect if there was any methane present in the beam path by comparing the strength of the outgoing and reflected beams.  The device reading does not convert to quantity of gas leakage – it only detects if there is a leak along (or near) the beam path;
  • Sampling – “sniffing” devices, either Organic Vapor Analysers (OVAs) or Toxic Vapor Analysers (TVAs);
  • Acoustical – ultrasonic leak detectors for the acoustical signal when gas under pressure escapes (high or low frequency);
  • Miscellaneous devices – i.e. turbine meters, calibrated vent bags, vane anemometer, hotwire anemometer, high volume sampler (air suction pump with combustible hydrocarbon concentration measurement devices);
  • Mobile sensors – aerial drones and ground based robotic devices (carrying optical, sampling, or acoustical sensors) – they can be manually directed or else programmed to autonomously follow prescribed routes and gather emission (and background) readings for structured input into analytical databases;
  • More sophisticated fixed sensor systems have been developed for safety critical valves.[11]  Leak detection ports can be open (with any leaks as shown only detected by infrequent LDAR surveys) or plugged (where leaks are above secondary packing which is energised and subject to wear (from valve cycling) and integrity risks develop as a result).  An automatic detection system is possible as shown – IMI CCI developed[12] a mass micro-flowmeter with intelligent logic which detects any leakage flow and if rates exceed pre-set limits, the leak port valve is closed, the secondary packing energises, and notification is sent (via HART, Foundation Fieldbus or Profibus protocols) to Maintenance to schedule remedial work on the valve primary packing.
Top-Down Detection Technologies

On a more macro scale, across large areas (i.e. fields, regions, states, nations), emission estimates are needed to help evaluate the challenge and identify progress (or the lack thereof).  Super-emitters need to be identified and high level surveys are typically able to identify these sites.  Satellite and aerial surveys can detect GHG emissions over large areas.  NASA has compared satellite imaging (Hyperion spectrometer on Earth Observing-1 (EO-1) satellite) with high altitude aerial surveys (Airborne/Infrared Imaging Spectrometer (AVIRIS) imager onboard ER-2 aircraft) to confirm that individual methane leaks can be successfully detected.[13]

Methane emissions can come from agricultural, transportation, and power plants as well as oil & gas developments, but the map below easily identifies most of the well known oil & gas areas.[14]  Satellite data can be processed to estimate rates, concentrations, and amounts of methane emissions.  Weather data (e.g. wind) is correlated to help identify probable source locations for more detailed ground (or drone) inspection and mitigation activities.


A range of potential emission mitigations or repairs is possible depending on the nature of the unintended leak:

Repair Type (Relative occurrence)Description
Reseal (~15%)Open the connection, apply sealing material, re-tighten
Replace seal / gasket (~10-15%)Remove the old seal or gasket, and replace with new, re-tighten
Tightening (~20-30%)Simply tighten the joint/thread/connection
Replace whole component (<5%)Replace the leaking component with a brand new one
Service the componentRemove the component, service it and re-install it
Shut-in or disconnect the componentTake the component out of service by shutting in or disconnecting
Welding or patchingPerform welding or patching at the leaking point

Computerised Maintenance Management Systems (CMMS) are useful tools to help plan and execute this work.  Results from Asset Integrity Monitoring (AIM) programs should be capturing observations of recorded emission points, root causes, and the associate repair type.  Using this kind of database within a single facility (or across a portfolio of similar facilities) it would be possible to identify maintenance priorities which can be captured in the CMMS and planned for implementation.  Each type of leak found could be used to help identify where to look for similar leaks.  Where work does not require a shutdown or other disruption of operations, it could be scheduled any time that maintenance resources were available on site.  Otherwise, shutdown critical work would try to be scheduled during regularly scheduled shutdown periods.

Emissions Management and Stakeholder Reporting

International Petroleum Industry Environmental Conservation Association (IPIECA) is the global oil and gas industry association for environmental and social issues, particularly for communication with the United Nations and other multinational stakeholders.  IPIECA works with the Upstream industry to develop, share, and promote good practice and knowledge to help improve environmental performance including Emissions Management.[15]  A key part of these efforts is Sustainability reporting guidance which includes the Risk management processes and Emission metric targets.[16]  IPIECA also publishes an Environmental management report that provides additional best practice advice.[17]

IPIECA specifically provides “CCE-4 Greenhouse gas emission” reporting guidance in accordance with The GHG Protocol Corporate Accounting and Reporting Standard 2015, developed by the World Resources Institute (WRI) and the World Business Council on Sustainable Development (WBCSD).[18]  This standard classifies GHG emissions as either direct or indirect based on three categories:  Scopes 1, 2 and 3:

  1. Scope 1 emissions are reported as Direct GHG emissions from equipment or other sources owned (partially or wholly) and/or operated by the company;
  2. Scope 2 emissions are where a company operation purchases energy already transformed into electricity, heat, or steam by others, with the GHGs emitted to produce this energy reported as Indirect GHG emissions from imported energy;
  3. Scope 3 emissions are Other indirect emissions related to the company’s value chain; these are more complicated to estimate, so IPIECA published additional estimating guidance.[19]

Stakeholders are increasing wanted to see all three Scope emissions, especially Shareholders and Regulators.  Structured data collection systems from distributed IoT devices connected into a Cloud Data Platform can help produce the values needed for these reports.

IPIECA publishes additional guidance on “CCE-5 Methane emissions” with methane described as a short-lived climate forcer (SLCF) with a significantly higher global warming potential (GWP) than CO2.[20]  Companies are encouraged to provide overviews of their strategic management plans for methane, including estimating, quantifying, and mitigating emissions.  The information contained in this article would help provide input to such a strategic overview.  Quantitative data should be provided in line with the same criteria as Scopes 1 to 3 mentioned above.

Stakeholders associated with Funding and Finance would need to see GHG emissions data as part of their review of Environment Social and Governance (ESG) criteria.[21]  Without this data being available, it is likely that commitment for funding and finance would not be successful and companies would face difficulties to obtain the necessary financial support.

Elimination of Flaring

Last month the World Bank estimated that the Upstream industry flared ~150 billion cubic meters of gas in 2019 during oil and gas extraction.[22]  That represents about $10-20 billion dollars of lost revenue (value=fn(gas price)).  This is approximately the same emission volume as from incomplete combustion, venting, and leaking combined.  Clearly it is important to reduce this flaring as much as possible due to the CH4 GHG contribution but, with disrupted energy markets, the lost value is material and could help companies deal with otherwise challenged economics.

The top 4 gas flaring countries (Russia, Iraq, USA, and Iran) account for 45% of the total flaring for the past 3 years.

An interesting statistic is “Flaring Intensity” which is cubic metres of gas flared per barrel of oil produced.  For this statistic Syria, Cameroon, Venezuela, Gabon, Democratic Republic of Congo, and Yemen lead this list.[23]  This statistic means inefficient production methods and minimal efforts to capture the gas to market it or reinject it.  In contrast countries like Nigeria have progressing flaring reduction projects and have dropped out of the top flaring list.

The carbon intensity of natural gas is ~50% lower than coal and ~25% lower than liquid hydrocarbon fuels.  That means natural gas should be part of the Energy Transition on the path to increased Renewables.  Gas has value and capturing it to be monetised means reducing “methane slip” emissions during flaring.  With gas typically being produced during oil production and processing, it means that existing facilities may be able to be used to help capture and monetise this gas.  Flare gas capture projects are well suited for decarbonisation investments from ESG investors. To get to Net Zero by 2050, it is not possible to just rely on Renewables in the next 20-30 years – conventional hydrocarbon energy production will continue to be needed as Renewables and Energy Storage capability ramps up, so eliminating flaring is needed now.  Flare capture projects have included zero-flare LPG facilities, gas reinjection (maintaining reservoir pressure and therefore oil recovery), waste gas captured and compressed to export pipelines.[24]  Other projects include flare gas recovery systems (to treat and condition adverse gas compositions to power generation ready fuel).[25]  Some operators are able to use gas for Enhanced Oil Recovery (EOR) applications in certain types of tight oil reservoirs.[26]  An obvious use for flare gas is to use as much as possible for onsite power generation and, if adjacent to local electrical grids, to consider selling surplus power.  Normal emergency flaring systems (e.g. blowdowns of a facility in case of fire or blast events) are to be expected, but routine flaring for convenience needs to be ended.

Greenhouse Gas (GHG) emissions including methane are environmentally harmful and can be mitigated through reasonable changes to Upstream industry facilities and work practices.  The value captured from eliminating these emissions can help cover the mitigating costs in a reasonable time period and can add significant value.  In addition to meeting regulatory requirements, this is just good corporate citizenship.
















[16], p. 84




[20], p. 89







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