Flaring solutions in spotlight as research calculates cost of inaction

Amid mounting evidence that routine flaring of natural gas from upstream operations causes as much of a financial burden as an environmental one, the industry’s reluctance to tackle this issue is due in part to a lack of familiarity with technological solutions, experts have told Upstream Intelligence.

Spatial distribution of natural gas flaring in 2012 (Source: Methods for Global Survey of Natural Gas Flaring from Visible Infrared Imaging Radiometer Suite Data, Christopher D. Elvidge et. al., Energies, December 2015)

Related Articles

At least 19 solutions exist for capturing natural gas. Some of these are more suited to onshore operators because they require access to grids and pipelines, and others cater more to offshore operators. But often the barrier to trialling solutions “is simply the appetite of the operators to explore the possibilities,” said Martin Layfield, head of DNV GL’s gas segment.

About 143 billion cubic meters of natural gas was released into the atmosphere from oil and gas operations in 2012, translating to 3.5% of total worldwide natural-gas consumption that year, according to data collected by NASA and NOAA (National Oceanic and Atmospheric Administration) from infrared imaging and published in the Energies scientific journal in December 2015.

Ninety percent of the flared-gas volume was found to have come from upstream operations. The United States ranked sixth in volume behind Russia, Iraq, Iran, Nigeria and Venezuela, but was a clear first for the number of sites that flared gas - accounting for about one-third of the worldwide total of 7,467 (an anomaly due, at least partially, to the high number of production sites in the country). If all the world’s flared gas were captured, it could be used to power 74 million vehicles in the US per year, based on an average of 25 miles per gallon of gasoline and 13,476 miles per year, the report concluded. 

One problem, many technologies

DNV GL has conducted research on the different solutions, and believes the optimal technology depends on the type of operation.

There are a number of issues to look at before deciding on a solution, Layfield said, such as: “What is the distance to market? Are there any gas-treatment requirements to reach a market specification for the gas? What are the key commercial aspects, such as local royalty payments, gas-price assumptions, etc.?”

One of the more mature technologies turns captured gas into liquids such as propane and butane which can then be sold separately. This technology added considerable economic value to the extraction process when oil and gas prices were higher but “since the decline in oil and oil-product prices the economic incentive has been lost”, said Chad Wocken, a senior researcher at the University of North Dakota’s Energy and Environmental Research Center.

Top 20 countries for upstream flaring in 2012 (Source: Methods for Global Survey of Natural Gas Flaring from Visible Infrared Imaging Radiometer Suite Data, Christopher D. Elvidge et. al., Energies, December 2015)

Another key consideration in choosing a technology is the amount of gas that can be captured, otherwise referred to as the flow rate, said Layfield. “Small scale LNG [liquefied natural gas], for example, might be deemed viable at higher flow rates but the techno-economic feasibility has been explored less at very micro-volume ranges.

“We considered flow rates from less than 1 million standard cubic feet per day (MMscfd) to 30-plus in real case scenarios around the world, onshore and offshore. The main difference in the viability between the two is often simply distances to market and therefore the cost associated with achieving a revenue stream from the captured gas.”

Estimate flared gas volumes for 7467 gas flares, worldwide, including upstream, downstream and LNG terminal flare (Source: Ibid.)

For flow rates of 10 MMscfd of lean gas case, options that have been shown to generate positive cash flow include: compressed natural gas (CNG), pure methanol, gas-to-liquid fuels such as diesel, absorbed natural gas (ANG) for vehicle fuel, and gas to wire (which means onsite power generation by produced gas).

A newer technology which is showing a lot of promise is storage of energy in battery form for back-up power but this remains largely untested in the field. In Europe, SBM Offshore and CompactGTL are developing a technology which can be used in ultra-deep water where gas re-injection may be expensive and may reduce ultimate recoverable reserves.

Reining them in

US shale-oil operations contribute more to flared-gas volume than their counterparts in the Gulf of Mexico but offshore operators have been slower to address flaring, according to Wocken. Onshore operators have addressed the issue in some states, such as North Dakota, because of specific local regulations, he said.

In January, the US Department of Interior’s Bureau of Land Management introduced new rules clamping down on flaring on federal and tribal lands. And a World Bank campaign to reduce flaring to zero by 2030 has received the backing of 47 governments, companies and organizations, including Russia, California, BP, Shell, Total and Eni, but excluding the United States government and the three major American producers ExxonMobil, Chevron and ConocoPhillips.

The World Bank initiative encourages oil companies to seek economically viable solutions to eliminate ongoing “legacy” flaring as soon as possible, and to ensure than when new oil fields are developed, plans include gas-utilization solutions that do not involve routine flaring or venting.

Given the way the political winds are blowing, it appears likely that if concern for the bottom line does not force operators’ hands on natural gas flaring, regulations eventually will.

By Vanya Dragomanovich