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Aware of the Flare

Technology providers are changing what we know about flaring in the Williston Basin. These unique products and approaches are helping to reduce and better utilize associated gas produced in the Bakken and Three Forks Shale plays.
By Luke Geiver | November 19, 2013

Flaring is the most pressing issue and biggest challenge for regulators and operators in the Bakken shale. Flaring also presents the greatest opportunity. Roughly 1 million cubic feet of natural gas is produced per day in the Williston Basin. Of that, 70 percent is captured and sold. The remaining 30 percent is what compels regulators and industry officials to constantly craft flaring legislation, operators to install takeaway infrastructure or test new capturing technology, and local and national reporters to drive the region’s gravel roads photographing the tallest, brightest orange flare burning against the North Dakota skyline for a magazine cover or newspaper front page.

To date, the story on flaring has been documented many times. Flaring in the Bakken, as the story often goes, is all about wasting a resource and an industry more focused on the bottom line than on working to reduce the amount of flares that light up the Williston Basin night. But, due to a better understanding of Bakken gas in combination with the growing use of innovative technology to move, capture or compress Bakken gas, the story has evolved and there is now strong evidence that the 30 percent is heading toward a downward trend.

Issue in a Nutshell
For the North Dakota Petroleum Council, flaring is its No. 1 priority. “There is a tremendous amount of national attention on it,” says Ron Ness, president of the NDPC. “It is a very hard issue to educate people about, you don’t just go out there and grab that gas flare,” he says. “There are a lot of components that go into capturing that gas flare. With oil you can go in and get it with a truck and truck it somewhere. You can’t do that with gas.”

Although natural gas prices are historically low, capturing that gas still presents an economic opportunity for operators and mineral rights owners.  Bakken gas is unique. In 1,000 cubic feet of raw gas, anywhere from 8 to 12 gallons of natural gas liquids including ethane, propane, butane or natural gasoline could be present. Those products add value to the gas stream in addition to its value as a product capable of providing power or heat. Some companies have already proposed facilities to process only one of those NGLs such as butane or ethane.

But as Ness says, capturing gas is a complex process linked in large part to the presence of infrastructure. The unique qualities and value of the gas makes the notion that flaring occurs because capturing is uneconomical untrue.

Justin Kringstad, director of the North Dakota Pipeline Authority, an agency started in 2007 by North Dakota to increase the amount of pipelines present in the state capable of moving energy-related products, also believes there is a misconception about flared gas in the Williston Basin. Between 2011 and 2012, the amount of pipeline installed in North Dakota could span the distance from Seattle to Washington, D.C, twice. Not all of the pipelines installed were linked to natural gas gathering lines, but according to Kringstad, there is a huge push to gather more gas regardless of the gas price.

There are two main challenges to capturing the gas produced in the Williston Basin that occurs during crude retrieval. Both are linked to local gathering, having nothing to do with any large interstate pipeline. First, Kringstad says, flaring occurs because of the inability of remote well sites to be connected to a gathering line due to difficult topography or right-of-way issues. Second, flaring occurs on well sites that are already connected to gathering lines because some pipelines are simply not adequate to move the volume of gas that might be produced on a well site today versus three years ago.

“Well sites are better today,” Kringstad says, “and pipelines put in the ground a few years ago may have been undersized.” Ness points to the trend in multiwell pads as a major factor in why existing pipelines may be undersized. “A lot of the infrastructure was built for one to two wells per 1,280 acre spacing unit. Now, all of a sudden, the technology has improved and we are looking at 4, 8 or 12 more wells in that 1,280.” Most gas lines are installed to handle a set volume and pressure from a set amount of flares. The addition of new wells to a spacing unit creates more gas volume and more pressure. In many cases, infrastructure installed in the past isn’t equipped to handle new gas volumes. And, operators and industry regulators are just now beginning to understand the flow rates and qualities of Bakken and Three Forks shale gas streams.

From the time a well begins producing crude and associated gas, an operator has one year to flare a certain amount of gas before it is required to capture the flare gas, unless it is determined there are circumstances that inhibit an operator from doing so. A recent lawsuit was issued by a group of mineral owners against a group of operators seeking reimbursement for flared gas produced during and after that one-year period. In the lawsuit, the plaintiffs argue that operators are flaring in excess during the first year, and continue flaring after the first year allowance has expired. The lawyers representing the plaintiffs point out that flaring is also taking place although infrastructure is already in place. The status of the lawsuit is still undetermined, but it does highlight the misunderstandings that exist regarding flaring.

“Infrastructure isn’t right-sized,” Ness says, “so that is a big challenge in and of itself. If an operator was going to get its gas as soon as it could, which everybody wanted to do, the operator didn’t build its lines big enough. We have to look at that part of this [flaring] puzzle.”

For both Ness and Kringstad, the answer to flare reduction starts with more infrastructure and compression capabilities. There are currently 18 facilities in the state capable of taking in and processing the associated Bakken or Three Forks shale gas, with more on the way, including a Hess Corp. operated facility that will practically be a refinery, Ness says. But, adding infrastructure takes time, although, since 2007, gas plant capacity has increased 340 percent from 227 million to more than 1 billion cubic feet per day.

The fluctuations between the number of new wells coming online per month, versus those being connected to gathering lines is also a constant concern, Kringstad says. Those fluctuations are stabilizing. Until the Bakken and Three Forks shale plays are right-sized to capture 80 to 90 percent of the flaring instead of 70 percent, there are alternatives, however, both in the field and in the boardrooms that are now revealing how flaring in the Bakken is an opportunity in disguise.

Onsite Answer
The NDPC, along with other industry members, has formed a flaring task force whose goal is to identify solutions for better optimization of the resource at the actual well head and find ways to improve existing infrastructure. The task force consists of government agencies, the Three Affiliated Tribes, researchers, landowners and key industry partners.

Innovative technologies being used in the oilpatch are already reducing the amount of flared gas or cleaning up the gas that is emitted. Many of those technologies are not dependent on new pipeline installation or gas processing facilities.

Gtuit, a Billings, Mont.-based flare solutions provider, is using a small-scale technology to create massive results. The company offers a mobile compression and refrigeration set-up that connects directly to the wellhead. According to Brian Cebull, president of Gtuit, a single unit operating for one year on a well site prevents 3,856 tons of volatile organic compound emissions, 11,500 tons of C02 emissions and captures enough Btus to provide heat for 6,087 homes, numbers Cebull cites from actual testing performed in the Williston Basin. “Our solution addresses those wells that are stranded and may be permanently stranded due to right-of-way issues or topography issues,” Cebull says.

The company currently operates 18 systems. The systems strip out the NGL’s from the gas stream and refrigerate them for storage and transport. Units can be combined and scaled up to handle high volumes of gas, an element of the technology Cebull emphasizes for good reason. “There are lots of folks that are coming up with new technologies now,” Ness says. “The key is to find some that are effective onsite. You want to be able to build scale, to be able to build multiple units in the field rather than a handful here or there.”

The ability of the Gtuit system to strip out the NGL’s provides operators with an attractive economic incentive. Cebull says the value of the NGL’s more than offsets the cost of service. The company designs and builds its own equipment, an aspect that wasn’t always the case. “We went into this purchasing off-the-shelf equipment and discovered quickly that off-the-shelf equipment was not designed for 1,500 to 1,600 Btu gas,” Cebull says. “Our basic system is actually built and rated for rich Bakken gas.”

The systems are brought to and removed from a well site by Cebull’s team and are serviced by Gtuit. “We are not there to compete with the pipelines. We are there to be there on day one, strip the NGLs until the pipeline shows up, then move on to the next well,” Cebull says. The company currently has contracts with Hess Corp.  

Gtuit is also working with power companies to analyze the methane left over in the gas stream after the NGL’s are stripped out, and it has taken requests to consider using the gas to run the artificial lifts on the well sites. The stripped-out gas stream is also perfect for liquefied natural gas or compressed natural gas for use in bifuel applications or diesel replacement streams.

Gtuit is expanding, Cebull says, because its clients are seeing the value in its systems. “Our goal is to be the best in the world for treating raw wellhead gas,” he says. Cebull does have competition. Several companies, including Bakken Western Services LLC, also provides a flare reduction technology capable of stripping out NGLs. Blaise Energy Inc. provides a technology that converts associated gas into propane for use in transportation or heat. According to Ness and Kringstad, companies from around the world are coming to the Bakken to provide technology for flare reduction.

Steffes Corp., a Dickinson, N.D.-based steel fabricator that has grown significantly since the Bakken shale play ramped up in 2007, has also entered the flare gas solution industry. The company has designed an engineered flare that helps to drastically reduce the amount of volatile organic compounds emitted at the well site.
Todd Mayer, new business development manager and a recognized guru of flaring solutions, says the Steffes approach to flaring is based on the extreme flow ranges of gas that occurs in most Bakken or Three Forks wells. In any given day, gas production can range from 1 million to zero cubic feet per day, he says. “It is well documented that wells might flow in the first week or so at 1 million cubic feet per day and then fall quickly to one-tenth of that. You need devices that are able to handle these wide ranges of flow and burn efficiently over wide ranges,” he says.

Not only does a Bakken or Three Forks well site present an operator with a wide flow range for gas production, it also produces two types of gas: the produced gas that is high-pressure and ready for a pipeline, and the low-pressure gas present in the oil tanks.

“Our customers wanted to know if we could design a system to be a combination system, one that could take on both gas streams,” Mayer says.
The engineered flare system Mayer and his team spent over a year designing can handle both gas streams, and turns that bright orange flare into a thing of the past. The system features a high-pressure tip, a low-pressure tip and a pilot light. To get a cleaner burning flare, the system relies on air mixed with the gas stream. “When you start to see smoke, we just don’t have enough air mixed in the gas,” he says.

The high-pressure flare tip is connected to the separator that disperses the gas and oil. The high-pressure flare tip features a stainless steel casying on top of a 6-inch pipe. When the gas pressure builds up in the pipe after being sent over from the separator, the pressure raises that stainless steel casting. The gas then leaks out the crack created between the pipe head and the casting and then hugs the outside of the casting, moving vertically, not horizontally, Mayer says. “It’s like an airplane wing, it [gas] wants to hug that curved radius on that casting.” As it hugs the casting, the gas stream gathers velocity and, more importantly, air.

The design accomplishes two things. The movable casting can accommodate a high range of high-pressure gas flows. Sometimes the crack will be barely there, other times it will by one-eighth of an inch open for gas flow. And, because of the curved casting design that forces the gas stream upward, the resulting flare that is produced burns cleaner and nearly translucent due to the addition of air to the gas stream. “There is no computer that is controlling it. It is weight and pressure that moves it [casting],” Mayer says.

Although the design is simple, it offers operators a robust option to reduce the amount of emissions created during flaring. Since first unveiling the product almost three years ago, the company has sold nearly 1,000 units. “It is much larger and more popular than we ever thought it would be,” he says.

Steffes is continually working to perfect the system. A team will train well site service teams how to install the system and most systems are checked monthly, although many don’t need a check. The units are designed for one to two well pads, but Mayer and his team are working on units that are designed for multi-well pads. “Having a larger flare option available is crucial,” he says. For the low-pressure gas streams that do not create enough pressure to lift off that stainless steel casting, the company has developed a low-pressure air-assist option that includes a battery operated fan to inject air into the stream, creating a cleaner burning flare.

Mayer says his customers are happy with his system, but he is constantly working to tweak the design. Cebull is doing the same with his team on the Gtuit system, and they share a sentiment that helps to illuminate why a new chapter in the Williston Basin’s story on flaring has begun. “We are proud,” Cebull says, “to be a part of the comprehensive solution to address natural gas flaring in N.D.”

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Author: Luke Geiver
Managing Editor, The Bakken magazine
lgeiver@bbiinternational.com
701-738-4944