With the spectacular rise of hydraulic fracturing in the US, it was inevitable that concerns about the effects of the process would arise. The Wall Street Journal recently reported that one in 20 Americans now live within a mile of a fracing site. One of the most hotly contested issues surrounding fracing involves air emissions resulting from the flaring of natural gas at new wells.

In April 2012 the US Environmental Protection Agency (EPA) issued its first-ever federal rules for fracing wells, requiring that companies fully phase in control measures to capture targeted emissions by January 2015. These control measures are called reduced emission completions or “green completions.” Green completions primarily involve using portable equipment to capture and separate the mixed gases, liquids, and other substances that flow from new wells. This takes place primarily early during the flowback period when fracing chemicals and water injected into the ground return to the surface along with newly released gas. The captured natural gas can then be reinjected, used onsite, or sold.

Thinking local

Two states, Colorado and Wyoming, already require control measures. Nonetheless, states and local communities in Colorado, Pennsylvania, New York, and Ohio have continued to push for even greater oversight and regulation through lawsuits and ballot measures. And the trend is likely to continue.

Even in a “pro-drilling” state like North Dakota, where the Bakken and Three Forks shale formations spurred record production highs this year, local residents and newspapers are calling for a harder line on natural gas flaring. Roughly 29% of all North Dakota natural gas is flared, with volumes having doubled over the past two years. In a surprising twist, some North Dakota landowners have actually filed class-action lawsuits against oil companies, seeking millions of dollars in allegedly lost royalties due to the flaring rather than capturing of natural gas during production, according to Blank Rome.

Contested projections

Historically, industry groups such as the American Petroleum Institute (API) have resisted flare gas regulation, citing infrastructure, equipment supply, and cost issues. The infrastructure for bringing recaptured natural gas into the power grid is often lacking, particularly in remote areas. However, green completions using portable processing equipment can resolve the infrastructure problem. Nonetheless, the API raised concerns about the equipment availability should new rules be phased in too quickly. API’s greatest concern focused on the cost of green completions, which it initially estimated at US $180,000 per well.

Other organizations argue that green completions are neither complex nor expensive. Both the EPA and the Natural Resources Defense Council (NRDC) point out that green completions rely on readily available, validated technologies that are already widely deployed and that offset the cost of compliance. NRDC’s Leaking Profits report stated that green completions and other pollution control measures could increase industry revenues by up to $2 billion per year through recovered natural gas. Similarly, a recent Ceres report, Flaring Up, estimated the value of flared gas in North Dakota at $1.2 billion for 2012 – about $3.6 million per day. These groups also note that in the years after standards were implemented in Wyoming and Colorado, drilling did not slow – in fact, Colorado drilling permits more than doubled.

Companies finding silver lining

It’s not just environmentally oriented groups making these claims. According to FBR Capital Markets analyst Benjamin Salisbury, the EPA rule struck a balance: “Given sufficient ramp-up time, the cost of green completions is expected to be manageable or even positive net of revenue from selling captured methane.”

And when the EPA rules were announced, Bloomberg News found several major companies with green completion systems in place that considered them “both practical and profitable.” Mark Boling, president of Southwestern Energy’s V+ Development Division, told Bloomberg, “Reduced emissions completions in our wells don’t cost us any more than just venting the gas into the atmosphere.” Southwestern’s initial cost was $20,000 per well, but it has now cut costs to zero. Even at $2 per MMBtu, “we’re making money.”

Likewise, a spokesman from Devon Energy, which has used green completions for more than seven years, told Bloomberg, “We’re capturing value that would otherwise be lost. It makes good economic sense for us.” Energy In Depth reports based on input from Devon found that the rental cost for the equipment was roughly $1,000 per day, with a conservative net value of gas saved per well of $50,000.

Completing the efficiency circle

Several companies are taking these efficiencies further, using field gas for localized onsite power generation to cut costs and emissions even further. Apache Corp. is exploring this option, according to company reports. Apache found that the industry used more than 2.6 Bl (700 MMgal) of diesel for hydraulic fracturing in 2012 at a cost of around $2.38 billion. By switching to field gas, the industry could cut its fuel costs by 70% or about $1.67 billion, the company estimated.

And companies are lining up to make this switch possible. Blaise Energy powers North Dakota well sites. The company originally delivered power from generators back into the power grid but found it was easier and cheaper to power well sites directly. Mark Wald, owner of Blaise, said that many of the wells are in remote off-grid areas and use diesel-powered generators to run the sites 24 hours a day. Swapping in field gas rather than hauling in diesel makes more sense. Wald told the Bismarck Tribune that oil companies that made the switch experience savings of up to $25,000 per month in the cost of diesel fuel alone for a single well pad.

Blaise has 25 operational sites and continues to add more units all the time. The company also is building bigger generators to keep up with the demands of multiwell drilling on well pads. Wald said it takes 100 kW to 150 kW to run a typical single well pad and 250 kW to 450 kW to run multiwell sites.

New engines meeting new demands

The trend dovetails nicely with developments in the engine industry toward increased options for alternative-fuel, heavy-duty engines designed for off-road mobile applications. Natural gas-burning engine providers have been ramping up their powerband offerings from the 250 kW to 450 kW range all the way up to the 1.2 MW range. These suppliers have found that due to the savings from trucking in diesel fuel and what is essentially “free” fuel from field gas, the payback on their systems is only a matter of a few months.

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