Oil and gas trade association IOGP’s new energy transition directorate is moving into a new phase to promote the adoption of technical documents, its Director Dr Faye Gerard said in a September 2024 webinar. Those documents include Report 647 for flare gas recovery systems (with a focus on continuous flaring), Report 673 on minimising and avoiding flaring, Report 675 on guidelines for minimising and avoiding venting and Report 661 on technologies to detect and quantify methane emissions.

Report 673 was originally published in January 2024, but reissued in December with additional recommendations about specifying corrosion-resistant materials for valves connected to flare gas. In the new version’s introduction, IOGP recommends it be used with the flaring management guidance in Report 467.

In the webinar, BP Vice President of Carbon Andy Best said: ‘I would encourage participants to not underestimate the prize if they really focus on emissions as they focus on oil and gas production and water management. What are your emissions technology limits for facilities, and how low can you get flaring? Of course there is a place for flaring for safety reasons, but we have found through optimisations what is low or no-cost by engaging with our operational teams, understanding our kit and processes. Within BP we have had really significant flaring reductions at minimal costs. I would encourage folks to focus on all flaring as a critical decarbonisation lever.’

He added later: ‘This is about adoption, adoption, adoption by members.’

‘I would encourage participants to not underestimate the prize if they really focus on emissions as they focus on oil and gas production and water management. Within BP we have had really significant flaring reductions at minimal costs. I would encourage folks to focus on all flaring as a critical decarbonisation lever.’ – BP Vice President of Carbon Andy Best

However, fellow presenter David Newman, BP Senior Advisor – Measurement & Analyser Systems, commented that the lack of methane measurement standards was hampering industry action. He said: ‘There are API standards, and some from the Energy Institute, but they are quite loose in a lot of ways in terms of what needs to be done. The sooner we get more standardised requirements for how to measure emissions in flaring and venting and regulations from governments, the better we will be able to control what we do, and take firm action in reducing emissions.’

Methane measurement standards are evolving rapidly, and the first of new batches will be developed over the next 18 months to two years, according to Peter Evans, BP Senior Engineering Product Owner, Methane Measurement and Reduction, speaking in a November 2024 technical webinar organised by Methane Guiding Principles (of which the Energy Institute is an associate signatory). The webinar explored the subject of downwind methane sensing equipment.  

Of the five levels of reporting precision in the UN Environment Programme’s OGMP 2.0 oil and gas methane project range, ‘best of all is reconciled data using site-level measurements’, Evans said. (See here for a description of the levels.)

Methane measurement starts with a sensor, he said, either a single sensor or a combined sensor for CO₂. He continued: ‘It’s important to note that there is a background concentration of methane in air.’ Their ability to discriminate higher methane levels from the background levels is what is key. Fortunately, as the industry matures, vendors are becoming more sophisticated. Those that are now ISO17025-accredited can state their sensor’s signal-to-noise ratio; those with ISO 9001 accreditation of their basic methodology know the limits of their method and don’t offer services beyond that. Evans summarised: ‘Calibration of the sensor is just step one and then needs to be rolled up into wider method issues.’

That sensor might be ground-level or mounted on a drone. Either way, it produces a point measurement. Inferring the total amount of methane released from that particular emitter is the job of dispersion models, he continued. ‘There are different ways to handle dispersion from a facility, and one is to model a classic Gaussian plume based on wind speed and dispersion, and then back-model where it came from and the rate. For larger drones, which measure concentrations upwind and downwind of the facility, you can look at mass balance. That’s a perfectly credible way to quantify methane, but like so many other things, there is no silver bullet here; no perfect solution fits all scenarios.’ Error with such dispersion models could be as large as 30%, he warned.

Alternatively, drones are used to build up a cloud of data from multiple flights, according to Camilla Fassio, Eni engineer. By flying drones in parallel paths at different heights, perpendicular to a plume, operators can assemble a vertical ‘wall’ of data, whose relative intensities will indicate the presence of a hot spot. Among other things, such results depend on suitable wind speeds: greater than 1–2 m/s so that a plume forms, and below 10–15 m/s so it is safe to fly.

That reasoning also assumes that emissions are continuous – which is not necessarily the case, particularly in offshore environments. She added: ‘The most important thing is knowing what to expect from the facilities, to choose a suitable technology for measurement, so when you go there you know what to expect. Also, talk to people on site, and understand what may be changing over time, and what is happening while you are monitoring.’

Emissions profiles are complex, Evans admitted. Still, he stressed that should not put off newcomers. He continued: ‘Knowing where to target limited resources is ultimately why we are doing this. Yes, it’s important to improve data quality. But first, we measure to know where finite resources should be targeted to achieve the most meaningful reduction against targets. The research can identify anomalies in the fleet.’

An example was shared in the webinar, in which top-down site measurements didn’t match with the bottom-up measurements of individual sources within the plant. The discrepancy warranted further investigation, and identified a previously-unaccounted-for component, a vent, that was emitting more than was reported.

Evans concluded: ‘Although there’s still work to be done in this area, and although we’re still learning how to do this, every measurement we take improves our understanding of facilities and measurement, and what are good measurements. If you are just starting out, even if your computation isn’t as good as it could be, measure, because it will tell you things about emissions and facilities, which is a pathway to mitigation.’

• Further reading: ‘What is needed to improve methane abatement in upstream oil and gas?’ The upstream oil and gas sector has the potential to halve its greenhouse gas (GHG) footprint with interventions that are cost-neutral or low-cost, according to McKinsey & Company. It suggests that, overall, the sector could cut up to 4% of global GHG emissions, although this would require worldwide cooperation among industry players and capital investors.
• Tracking and reducing methane emissions has long been stymied by outdated estimation methods and unreliable data, leading to widespread underreporting. Read more about the pressing need for more accurate and effective monitoring systems.