US upstream struggles with flaring [NGW Magazine]

The US is struggling to address record levels of natural gas flaring, which are a consequence of the shale drilling boom. Indeed, flaring has increased so much in the US that the country is the main contributor to the first rise in global flaring volumes in five years. (See NGW Issue 13)

Since last year, flaring has continued to reach new highs. Consultancy Rystad Energy said in June that even with a slowdown in Permian oil production at the start of this year, gas output remained healthy and drove a rise in both flaring and venting. Rystad estimates that Permian gas production hit 13bn ft³/day in December, and is now approaching 14bn ft³/day. Flaring, meanwhile, averaged a new all-time high of 661mn ft³/day in the first quarter of 2019 according to the consultancy.

In the Bakken, which produces considerably less oil than the Permian, flaring volumes were still high, at around 500mn ft³/day in the first quarter of the year. This brings the two regions’ combined volumes of flared and vented gas to around 1.15bn ft³/day, which Rystad said exceeds the annual gas demand of Israel, Colombia and Romania. 

To the rescue?

The rise in flaring has prompted some response, with new takeaway capacity under construction. Progress is fairly slow, however, given the timeframes needed for new pipelines and processing plants to be built. For example, the next major gas pipeline project due to come online in the Permian Basin is Kinder Morgan’s Gulf Coast Express. The pipeline is estimated to cost $1.75bn and will carry up to 2bn ft³/day of gas from the Permian to the Agua Dulce hub in Texas.

Gulf Coast Express was initially proposed in 2017, construction started in May 2018, and the pipeline is expected to be in service in October this year. And even with the project starts up, it will not be enough to accommodate all of the region’s growing gas output.

Analytics firm RS Energy Group estimated in April that there was about 9.5bn ft³/day of gas pipeline capacity out of the Permian. The firm was not immediately available for comment to NGW on whether the figure may have changed since April, but no significant new gas pipeline project has come online in recent months. Thus, even 2bn ft³/day of additional takeaway capacity will not be enough to match ever-growing associated gas production in the Permian.

This is not to say that Gulf Coast Express will not be a welcome addition in the region, however. It will provide much-needed relief, and is expected to help prop up regional gas prices after the fell to record lows earlier this year, trading in negative territory. The pipeline is already fully subscribed.

More new gas takeaway capacity is also planned for the region, but it will not start up until late 2020, by which point the basin’s production will have grown further still. 

Under pressure

In the meantime, the industry will need to find other ways of addressing the flaring problem. Indeed, growing pressure globally on producers to be more proactive in addressing environmental issues could translate into greater momentum on tackling flaring, at least for some companies.

One way to address the problem is by curtailing production until new takeaway or processing capacity is available. Apache announced in April that it was deferring 250mn ft³/d of gross gas production from its Alpine High project in the Permian. The move was attributed by the company to “extremely” low prices at the Waha hub in West Texas. This curtailment, along with similar moves by other producers, helped push regional gas prices out of negative territory, to slightly above zero.

Others could still follow in Apache’s footsteps. Among them is super-major BP, which has set itself a target of zero routine flaring by 2030, and has stated that it is committed to reducing Permian flaring as part of this target.

BP has been identified by Rystad as one of the Permian producers with the highest percentages of gas flared, following its takeover of BHP’s assets in the basin. Rystad found that these assets burn or vent just over 15% of the gas they produce, compared to the Permian average of 5.1%.

A BP spokesman has said that since taking over BHP’s assets, the super-major has started building centralised facilities that are expected to reduce flaring when combined with some other emissions-reduction efforts. However, if these steps are not seen to be going far enough, it would not be surprising if BP considers slowing some drilling until new pipeline capacity is available. 

New direction

In the Bakken, meanwhile, at least one company is looking into ways of using North Dakota’s associated gas production within the state in an effort to reduce gas wastage. Bakken Midstream said in June that it had received an investment from the state of North Dakota to help the company build infrastructure projects that it says will create a “value-added” industry. This could potentially include fertiliser, plastics and other industries that use gas or natural gas liquids (NGLs) as a feedstock but require existing infrastructure before moving into a new region. The company has also recently completed an oversubscribed first round of funding.

Bakken Midstream did not respond to NGW’s request for comment. However, Bakken Midstream’s CEO, Mike Hopkins, has previously said that the company is considering at least 12 different projects in the region. It has said it could be ready to announce what some of its projects will be later this year.

Hopkins has said the company is taking inspiration from Alberta, which developed a value-added added industry to deal with its own excess gas production. While this is a strong model, as with pipeline projects, the development of new infrastructure aimed at using regional gas more efficiently will take time.

In the shorter term, meanwhile, pressure remains on producers to respond to the challenge of flaring. While regulations exist in both Texas and North Dakota to restrict flaring, exceptions can be granted to Permian flaring limits. And according to the Brookings Institution, in the Bakken, state flaring guidelines are “routinely waived”.

It is likely that if operators do act, it will be under the twin pressures of responding to gas price economics and demonstrating environmental credentials. Some such moves have already been made. More are likely to follow in the near term.