Statoil field-tests new laser monitoring technology for methane emissions
February 22, 2017
Statoil is deploying new laser monitoring technology for methane emissions at US shale sites. Ros Davidson speaks with researchers to find out more
Carbon dioxide might be the most high-profile greenhouse gas (GHG) that politicians and industry are seeking to address, but methane is certainly the more potent. Roughly 30 times more effective at trapping heat in the atmosphere, it also has a tendency to combine and react with numerous other molecules in the air. So-called “fugitive” methane is therefore not just a localised issue for oil and gas operators, but a global one. In Texas, Norwegian NOC Statoil is currently field-testing an innovative low-cost laser technology that continuously detects methane leaks. So far, it looks to be accurate and on track to be priced enough to be deployed.
The methane sensor – which is solar powered – could indeed conceivably become a standard part of a “smart” well pad. It works remotely, and sends data wirelessly and securely to a cloud-based system. The sensor technology was developed rapidly, in just four years through the Methane Detectors Challenge (MDC), – a partnership between the US Environmental Defence Fund (EDF), oil and gas companies, US technology developers and other experts.
No alternative There is as yet no widely available method for the 24/7 detection of methane in at oil and gas sites, even though it is the main component of natural gas and is regulated. An estimated 25% of today’s climate warming is driven by emissions of methane from multiple sources, including oil and gas development, according to EDF. There are economic reasons too – from a commercial perspective, any leaked methane is also a waste of resource and therefore lost cash.
In the US, methane is emitted across the oil and gas supply chain at an estimated rate of more than 9.8 million metric tonnes per year. Globally, the oil and gas industry loses about US$30 billion of natural gas a year from leaks at dispersed sites (the loss in the US is around US$2 billion annually). At production sites, common locations for fugitive emissions are – according to the US Environmental Protection Agency – at the site of pneumatic devices, tank batteries and processing equipment.
Current testing methods include hand-held infrared cameras – deployed perhaps twice yearly to a site by a field team often of two people, says Desikan Sundararajan, a senior researcher in Statoil’s shale oil and gas R&D team. It can take three to four hours to perform one test. Hand-held ‘sniffers’ have to be held close to a leak. It is labour intensive, and the monitoring is not possible 24/7. “The leak may start the next day [after such a calendar-based model] and we won’t know for the next six months, EDF’s Aileen Nowlan, manager of the MDC, told InnovOil. Such testing is typically also qualitative, not quantitative, adds Statoil’s Andrea Carolina Machado Miguens, also with Statoil’s shale oil and gas R&D team. In areas such as oilsands, operators may literally place a ‘flux chamber’ or large hood over a tailings pond or above a mine to capture and measure emissions, including methane, but again the method is not perfect. Refineries too have their own methods, often using costly devices used inside equipment that is not suitable for field deployment.
Quanta innovation Statoil’s latest approach uses sensing technology by Colorado start-up Quanta3, a company founded specifically to participate in the MDC. The technology was initially tested at the Southwest Research Institute in San Antonio, where it performed well, said EDF’s Nowlan, and has now been deployed at a production well site in Karnes County, in the Eagle Ford formation in south Texas. The sensor can measure concentration, flow rate and location with a 5-10% accuracy, Dr Sundararajan told InnovOil. According to Quanta3, the sensor can detect 0.5 cubic feet (0.001 cubic metres) per minute from a distance of 130 feet (40m), although Dr Sundararajan said that it could be placed even farther away and still perform.
The ‘smoke detector’ technology is around 7-8 feet (2.1-2.4 metres) tall, and includes a 12” x 18” x 18” casing (305mm x 457mm x 457mm) that contains the laser, as well as a solar panel and an anemometer to measure the wind, which of course affects the flow of methane. With a minimal footprint, it can be placed within the perimeter of a well-site without causing disruption or additional safety issues. Sample air is drawn though a port in the casing and analysed. When the laser passes through the air sample, the methane absorbs energy at a specific point in the spectrum. Thus a ‘signature’ can be obtained from a reflector. The resulting data is recorded in real time, transmitted to the cloud and analysed on a weekly basis by Statoil and Quanta3 in Austin, Texas.
Weatherproof When the pilot study started, in mid-January, the weather was quite rough, and the sensor remained accurate, the researchers said. Prevailing winds are typically fairly stable, meaning the sensor can be easily placed where the plume of a leak might occur, aiding accurate measurement.
The current testing will help researchers establish an operational baseline for atmosphere and emissions – there is already background methane in the atmosphere, and ensuring the detector does not pick up false positives is important. A team is also conducting a site inspection, to gather more data and so that the overall accuracy of the sensor can be gauged. “It’s the first time we have had 24/7 data,” Dr Machado explained to InnovOil.
On the more practical side, the device is also being tested for ruggedness, and to see how the algorithms and data analysis stand up. The pilot will continue until about mid-April, after which more sensor units might be deployed elsewhere, with up to two in the Eagle Ford and perhaps two in the Bakken formation in North Dakota. The cost challenge, under the MDC programme, is to find a sensor which is deployable for about US$1,000 per site per year. The sensor unit itself is ultimately expected to cost only US$5,000 per unit, once it has been commercialised. The current cost is “significantly higher” right now, says Dr Machado, but with scaling up she believes that this should come down.
Moreover, that cost may not be associated with extra spend. Nowlan reiterated that “lost methane equals lost money,” and EDF notes that according to studies, natural gas leaks can be reduced by at least 40% for an average cost of about one penny per thousand cubic feet of gas produced. With proven results from monitoring trials, the team expects the technology to be useful at production, processing, transmission or gathering sites.
Statoil in particular is seeking to become the most carbon-efficient oil and gas producer. Regardless of one’s perception of that message, participation in schemes like the MDC is having an effect – the company’s methane emissions have decreased by about 10%, from 40.6 thousand tonnes in 2014 to 36.3 thousand tonnes in 2015, according to its 2015 Sustainability Report. Other companies that have worked with the MDC include Royal Dutch Shell, Anadarko Petroleum, Noble Energy and Southwestern Energy, said Nowlan. The team are also confident that recent moves by President Donald Trump’s administration to roll back environmental regulations, such as for methane emissions, would not affect the usefulness of the technology. Nowlan cautioned: “Nobody voted for dirty air or dirty water. There’s a difference between campaign rhetoric and governing.”