New drive to end routine flaring

Gas Value North Dakota
The oil drilling boom in North Dakota's Bakken basin
Small-scale alternatives to burning off gas from oil production are moving centre stage

The catalysts and sources of climate change are attracting increasing attention, debate and concern. The flaring of natural gas associated with oil production is a highly visible example.

Approximately five per cent of world annual gas production is being flared or vented worldwide, noted Martin Layfield, gas segment director, DNV GL. “That is equivalent to about 110 to 140 billion cubic metres (bcm) of gas.[1] It equates to the combined gas consumption of Central and South America in 2013.”

The World Bank estimates that flaring 140bcm would cause more than 350 million tonnes (mt) of CO2 release into the atmosphere. If this could be harnessed for power, for example, it could produce 750 billion kilowatt hours per year, more than Africa’s entire annual consumption.

Zero flaring call

When this article was published in October 2014, the World Bank was planning to launch a ’Zero Routine Flaring by 2030’ initiative, calling on governments and companies to achieve that in the next 15 years.

New technologies – or smarter uses of existing ones – are one answer, but formidable, non-technical hurdles include investment, and regulatory and legal frameworks. However, the target is realistic, according to the Global Gas Flaring Reduction Partnership (GGFR), a World Bank-embedded organisation of about 30 governments and oil companies, including virtually all leading international oil companies.

“We believe it is achievable,” said Bjørn Håmsø, GGFR’s programme manager. “We have discussed the initiative in great detail with international and national oil companies and governments. Some already have flaring policies, but the initiative would shed additional light on their good work, and add impetus and scope to it.”

Success will depend on a substantial number of companies and governments endorsing it, Håmsø added. “We expect that to happen. It would level the competitive playing field for associated gas utilisation for new oil field developments, and create momentum to achieve the initiative’s goal.”

Using flare gas

The proposed initiative tries to focus governments, oil companies and development institutions on actions enabling economic utilisation of flared gas.

“In Nigeria, for example, part of the problem is a regulated gas price of about USD1 per one million British Thermal Units to power plants,” Håmsø said. “This is a small fraction of the price in the US and Europe. There is an obvious social aspect to domestic gas and electricity prices, but there are ways to target assistance more directly to vulnerable groups. If investments in making gas available for local energy markets are not forthcoming, everyone loses.”

In contrast, one business model in western Siberia, Russia, is to invest in a gas separation plant, shipping heavier components – propane, butane and natural gasoline – to market, while putting lighter ones, mostly methane, into a small power plant. Håmsø observed: “There are efficient reciprocating engines available for small-scale production of power from gas. This power can often be returned back to the oil production site.”

If a local electricity market is saturated and an operator is ‘stranded’ with gas far from larger markets, gas-to-liquids (GTL) solutions could come into play, Håmsø said.

“Liquids such as diesel, gasoline, liquid fertiliser and others are easily transportable. If the operation is near an oil pipeline, manufactured synthetic crude could be injected into the pipeline flow. The issue is to get costs and risks reduced in small-scale GTL plants: these are technically complex and require highly skilled staff, which often is an issue as well.”

He expressed optimism that such risks and costs will decrease: “A couple of years ago, we felt there were only a dozen or so [small-scale GTL plant] companies worth monitoring. Today, that number has doubled.” Innovation is driven particularly by the US shale oil boom and an associated boom in flaring, he observed.

The Bakken effect

The story of development in North Dakota’s Bakken basin, a shale oil play in America, illustrates this. Twentynine per cent of gas produced in the Bakken is flared at wells, according to the University of North Dakota’s Energy & Environmental Research Center (EERC). Nearly 50% of that is from wells connected to gas-gathering networks lacking capacity to handle more. As production grows though, so does the economics of infrastructure to handle associated liquids-rich gas from more accessible drilling areas.

New guidelines proposed by the industry in North Dakota earlier this year set targets for flaring at above 20% of all gas produced by January 2015. This reduces further by 2020 and, potentially, further again beyond that year.

Scale of response

Global oil and gas operator Hess Corporation, a large producer in the Bakken, has continually expanded its local Tioga Gas Plant. It recently doubled Tioga’s near 100 million standard cubic feet per day (mmscfd) operational capacity to produce propane, methane, butane, natural gasoline and industrial feedstock ethane.

Hess said the percentage of natural gas flared at its Bakken wells had fallen from about 25% before Tioga was expanded, to 15%–20% today, nearly a year after the revamped plant became fully operational. Tioga was processing about 120mmscfd this spring. Hess estimated that combining its own and third-party gas would raise that soon to at least 250mmscfd, with potential to exceed 300mmscfd. It is working on four new gas gathering projects.

Tioga is a large-scale solution made viable by substantial gas supply within relatively easy reach and with robust markets for its products. Many remoter locations and poorer economies with weak markets for gas or gas liquids need cheaper, more compact answers.

“Existing solutions are mature for largescale applications, but most flaring is very small-scale,” said Martin Layfield. “We need innovation in applying associated gas to energy intensive processes, such as air separation and water desalination, though some solutions might be immature for near-term implementation.”

A DNV GL team has talked to providers to update understanding of technologies then work up commercially viable concepts for gas capture in real locations and conditions on- and offshore.

“We are covering a range of flow rates, gas compositions, geographical locations and so on,” said Robert Rawlinson-Smith, director of technology programmes, DNV GL. “The different combinations represent current flaring situations and require very diverse technology solutions. We are also considering how to make processing plants modular and flexible, allowing them to be used at different locations as wells deplete.”

Innovation in action

EERC has a database of vendorprovided information on small-scale gas use technologies capable of impacting flare reduction.

It has also assessed some current technologies and their economics for small-scale gas processing to recover Natural Gas Liquids (NGLs), and for using associated gas for power production, transportation fuel and chemical production.

It concluded that “innovative approaches to effective implementation” were needed. Some are already being deployed, tested or proposed.

An example on the processing side is Dow Chemical Company’s adsorbent-based technology, UCARSORB, which removes NGLs from wellhead gas.[2] “This has potential to provide a relatively smaller and mechanically simpler technology, compared to compression and refrigeration, to process gas at small scale,” EERC senior research manager Chad Wocken said.

Alternative use of gas in the Bakken is illustrated by operator Statoil. “It is taking advantage of its bi-fuel equipped [diesel and natural gas] drilling rigs by combining well site gas-processing equipment (GE’s CNG In A Box) and local compressed natural gas distribution through Ferus Natural Gas Fuels (Denver, US) to get stranded gas to drilling sites with high fuel demand,” said John Harju, EERC associate director for research.

“This allows valuable NGLs to be recovered and marketed. It also creates a methane stream better suited for bi-fuel engines and alleviates the need for temporary gas lines from producing locations to drilling locations.” Across all operators, as many as 80 drilling rigs in the Bakken may have bi-fuel technology, Harju estimated.

Joined-up thinking needed

Tackling flaring is not just about technology. Bjørn Håmsø, programme manager at the Global Gas Flaring Reduction Partnership (GGFR) stresses a need to win over policy makers and foster collaboration with industry and governments.

“In the US, state governments and companies are working together to address flaring,” he observed. “The US government is a GGFR partner, so is the government of Alberta, Canada. Many GGFR partner countries have sent teams to Alberta for training, or have received experts from Alberta to help develop gas flaring solutions.”

GGFR is better positioned to make a difference when governments are unable to manage their energy sectors, particularly through effective regulation, he added.

“Traditionally, the World Bank has focused on the power sector,” he said. “With the flaring initiative, it will also look further upstream to secure efficient utilisation of a country’s energy resources.” 

1 Satellite data from US National Oceanic and Atmospheric Administration analysed by the World Bank
2 ‘Removal and recovery of Natural Gas Liquids using UCARSORB™ NGL adsorbents’, Dow Chemical Company technical note, Jan 2014

Bjørn Håmsø, programme manager, Global Gas Flaring Reduction Partnership