Every year, people in the gas, LNG and hydrogen sectors meet at the Gastech conference to hear about the latest innovations in natural gas technology. At this year’s event in Dubai, there was a big focus on how technologies can monitor and reduce unnecessary emissions gas companies are trying to get a handle on.
For years, one of the trickiest types of unnecessary emissions has been methane from flaring – burning the excess gas emitted from gas wells, petroleum refineries, chemical plants and natural gas processing facilities because the highly flammable gas would otherwise be dangerous.
Approximately 145 billion cubic metres of gas per year is flared in oil and gas operations around the world, accounting for 2% of global methane emissions from oil and gas production, according to the industry coalition Methane Guiding Principles. According to the International Energy Agency (IEA), methane emissions are the second-largest cause of global warming. It is a frustratingly high amount for what is essentially wasted gas, and most of it is because of error: it comes from incomplete or inefficient flaring operations.
The IEA says most oil and gas methane emissions could be avoided at net-zero cost, and yet this has not happened. The main problem is that oil and gas companies do not have a good understanding of when and where these leaks are happening. Critics say they have never shown much interest in dealing with the problem – even as flaring intensity has actually increased over time.
Not only are oil and gas companies contributing to climate change by not tackling the leaks, they are also burning money – letting gas go that could be put to other uses for a profit. Various solutions have been proposed, including mandated government targets – the US and EU last month pledged to cut global methane emissions by at least 30% by 2030 – or certifying the methane emissions performance of oil and gas assets. However, that also requires a better knowledge of where and when the leaks are happening.
Energy Monitor spoke to Rami Qasem, executive vice-president at technology company Baker Hughes , one of the world’s largest oilfield services companies, who was at the Gastech conference presenting a new technology to monitor these emissions, to get a full understanding of when and where they occur.
The technology was originally launched in 2017 to support downstream operations, but an upgrade involving the type of leaks it can detect means it can now also be used by upstream operators to monitor their flaring emissions. Using the data, operators can improve flare combustion efficiency and reduce emissions by working with the Baker Hughes subsidiary Panametrics . The system can use existing sensors already at the facility or new sensors can be installed.
What is flaring and what has made it so difficult to get a grip on?
Flaring is burning unwanted gas, but the efficiency of flaring today is between 70% and 80%. The objective for everyone is to reduce the share of gas being burned, and to move to more efficient monitoring.
Flaring has decreased over time – there are technologies where the excess natural gas is reused or reinjected – but we still have a huge amount of it. Flaring is a major source of methane, but there are technologies today that customers are using to try to get 90%-plus flaring efficiency. These could significantly reduce methane through remote monitoring and better flare performance.
What is the technology update you have developed to curb methane emissions from upstream oil and gas operations?
It is called flare.IQ. It uses sensors to allow real-time monitoring of methane emissions from gas flares. One of the key operators we are working with is BP. They are using this digital connectivity to help them reduce their methane emissions by 50%. Today we are testing it in a couple of their facilities.
The operator will be able to take that gas [that is not flared] and either reinject it or adjust some of their operation, including some of the steam being generated [to reduce the flare].
What kind of partnership and communication with operators is needed to make this work?
Historically you had segregated operations within the industry. Today it is all about partnerships, between technology providers like Baker Hughes and users like BP, and at the same time within the operation itself.
Take the flare or methane emissions: operators need to understand this part of their overall operation when it comes to the steam, the fuel gas – all of this has to be connected. More and more, we see lots of terabytes of data, and people are asking, what do we do with this data? In order to make the right decision there is now seamless connectivity between the operator and various other departments [within an oil and gas operation].
We are working with BP. They want accurate monitoring, they consider it a first step in analysing their true emissions, and then they will look at how they can use that data with their [facility] operator to improve flare combustion efficiency and reduce emissions.
What role do data and analytics play in reducing flaring emissions?
We all recognise the pandemic accelerated the need for remote operation. Everyone now understands the need for AI and data processing. That will transform the energy and industrial sector. It will play a role in allowing operators to run with minimum outages and maximum efficiency. We need to enable more efficient remote working. The industry is going to go through rapid progress toward net zero, cleaning up current operations.
Over the last two to three days here at Gastech, we have had lots of discussion about how digital services can help the oil and gas industry transform. We also see increased demand for remote operation. There is lots of discussion around the health and viability of these industrial assets. Everyone wants to find a better way to navigate the energy transition. How can I do a better job based on what I have today? How can I be safer but also move forward in the energy transition?
Are there particular markets where technological solutions are harder to implement than others?
I do not believe anything is impossible to apply. I believe the minimum requirements for operators to implement some of these [flaring reduction] technologies are available everywhere – but in some instances, it may be harder. Some upstream flares do not have any measurement devices in place, for instance, so you would first need to install sensors.
However, it is not tied to geographic location, it is more about how rapidly the system can be built.
This article originally appeared on Energy Monitor.