Executing The Gas Capture Plan

The impact of unprecedented flare regulations on midstream gas gatherers and other technology providers is now more evident than ever in the Bakken.
By Patrick C. Miller | August 12, 2014

A conversation over lunch with a financial analyst gave Dave Scobel, chief operating officer of Caliber Midstream, an idea of what the company was up against in transporting and processing natural gas produced in the Bakken.

“We were picking each other’s brains and I said, ‘Do you have any advice for us as a midstream group in the Bakken?’”

The answer surprised Scobel and his colleagues. 

“The pipelines you’re putting in are too small,” the analyst replied.

“We laughed,” Scobel recalled. “You don’t know what size we’re putting in. How can you say that?”

The analyst’s explanation was simple: “Whatever size you’re putting in, it’s too small.”

When it comes to the issue of flaring natural gas in the Bakken, Scobel’s lunchtime discussion fittingly summarizes the current problem for midstream gatherers: how to correctly scale the infrastructure required to handle the production output.

Understanding The Scale
“We still don’t claim to have the knowledge of how many wells we can put on a section in any given location,” he says. “The producers went to the midstream providers and said, ‘Here’s what we think we’re going to have. We’re going to have four wells for every unit.’ The midstreams came in and built infrastructure to accommodate that.”

As the true production potential of the Bakken became apparent, four wells became eight, which were further downspaced to 12 and may someday grow to 24.

“Several rounds of pipe have gone in, and they’ve all been too small,” Scobel says. “As an industry, we’ve been trying to get our arms around the Bakken reservoir and understanding how much downspacing we can do. How big are these IPs going to be in any given area? Without that understanding, without that knowledge, it’s difficult.”

That’s been the hardest struggle, according to Scobel. “If we, as a midstream group, knew a few years ago exactly how much gas was going to be coming from every township, it would have been easy to lay out a grid to accommodate that. We’ve constantly been surprised to the high side at how much is going to come out of the Bakken.”

And that’s what made it a challenge early in the Bakken’s recent development for midstream companies such as Caliber to accurately predict how much gas transport and gas processing infrastructure was needed.

“Nobody envisioned that it would be as successful as it’s become—not even close. At the time, that would have been a big risk for a midstream company to build out to an unknown,” he says.

Enter The GCP
On July 1 this year, the North Dakota Industrial Commission implemented regulations to significantly reduce the level of flaring in the Bakken and Three Forks Formations by using an approach Department of Mineral Resources Director Lynn Helms described as “a completely new way of controlling flaring.”

The commission’s goal is to reduce flaring to 26 percent by fourth quarter this year; 23 percent by first quarter 2015; 15 percent by first quarter 2016 and 10 percent by the fourth quarter of 2020, with the potential for a reduction to five percent.

The policy—which gives the state regulatory teeth to limit gas flaring—establishes oil production limits that take effect if a producer fails to meet requirements to capture natural gas at the well site.

Gov. Jack Dalrymple called it “a dynamic shift in the way regulators approach reducing natural gas flaring.”

“The surge in shale gas production has required the commission to take an unconventional approach at regulations by getting operators to make plans to capture natural gas at day one,” he added.

Industry Reaction
“Nobody wants to flare gas,” Scobel says. “Producers want to monetize it. We all want to get the flares out.”

He also doesn’t accept the idea that the oil and gas industry has been lax in addressing the flaring issue and needed regulatory persuasion from the NDIC to get serious about reducing the amount of gas flaring in the state.
“There’s been 10,000 miles of natural gas pipe laid and $6 billion spent since 2006,” Scobel says. “It couldn’t be further from the truth to say that industry hasn’t been trying to tackle this issue.”

Brad Stevens, a research engineer at the University of North Dakota Energy & Environmental Research Center, agrees that reducing the amount of flaring by a significant percentage has been easier said than done for a number of reasons.
“It’s easy to fall into that trap of vilifying the industry by saying that they’re just after oil and just flaring the gas because it’s easy and they can’t make any money at it,” he says. “Most companies don’t want to lose one dime anywhere, but they can’t undertake projects that are uneconomical.”

Gas flaring is exacerbated by the way the wells are developed, Stevens also says. “The initial flow-back of both oil and gas is very high, but it’s a very steep decline curve. It’s difficult to overbuild and sink all those dollars into infrastructure. If you build it to be peak capacity, it’s potentially oversized later on. You know you’re going to have that peak on the front end, but where do you build to, capacity-wise? It’s a challenge, especially as a midstream, when you’re not controlling where and how fast these wells come on.”

The EERC worked with the North Dakota Petroleum Council gas flaring task force to develop an online database of technologies and expertise to provide a “one-stop shop” for oil producers looking for alternatives to flaring gas. The database currently lists 50 different entities.

“It’s not as simple as just putting these technologies out there and saying you’ve got it licked,” Stevens believes. “We took a high-level view of the different technologies and the impact they’d have on flaring. There isn’t a single technology you can deploy to wipe out the flaring to the extent that people would like. It’s going to be a basket of solutions.”

Starting Oct. 1, all Bakken and Three Forks wells will be subject to production restrictions if they are flaring more than the 74 percent gas capture goal.

According to the Department of Mineral Resources, if a gas capture percentage is not met, oil production at the well will be restricted to 200 barrels of oil per day, “if at least 60 percent of the monthly volume of associated gas produced from the well is captured, otherwise oil production from such wells shall not exceed 100 barrels of oil per day.”

In addition, gas flaring will not be permitted if the North Dakota Department of Health determines that the activity is violating the state’s air pollution control rules, which could trigger further production restrictions.

Oil producers will be required to have a gas capture plan (GCP). This plan details how much natural gas an operator anticipates producing from a well, the method of delivering the natural gas to a processor, and where the natural gas will be processed. Operators failing to comply with a GCP, as well as flaring reduction targets, may face the production restrictions.

“The overarching goal is to reduce the number of wells flared and the amount of gas flared,” Helms said earlier this year. “With the help of the commission, we won’t just see percentage of gas flaring go down, but the volume go down as well.”

However, Scobel believes that production trends in the Bakken are already moving the oil and gas industry in the direction of flaring reductions.

Meeting The Flare Reduction Goal
“I think the NDIC might get some undeserved credit,” Scobel says. “My take when I look at what’s going on up here is that it’s been difficult for the producers and the midstreams to have long-term plans together and collaboration while everybody was HBP (held by production) drilling.”

Producers had a hard time scheduling their rigs and understanding what areas production was going to come from and they were scrambling just to hold leases, he explains.  

The move away from HBP drilling to an overall field production mode has helped operators and midstreams unite. “The pad locations are more conducive to getting pipe to them, and producers can work with the midstreams to come up with a systematic approach. I think that’s happening, regardless of the changes that NDIC has come out with.”

Still, Stevens expects that the new regulations will help bring some clarity to the North Dakota’s flaring situation.

“All of the operators have unique scenarios where certain things fit and other things are not applicable technology-wise,” he explains. “It takes time to work through those details. Any given company might have certain wells where a different type of technology is a better fit. That’s the stage we’re in right now.”

Finding The Right Plan
Economics greatly impact the options available to a producer developing a gas capture plan.

“The most important, efficient plan is to tie into a pipeline,” Scobel says.

EERC researchers are continuing to gather data in an effort to help government and industry understand flaring from a big-picture perspective.

“As part of our Bakken optimization program, we’re doing data analysis to better capture what’s going on with flaring,” Stevens says. “Everybody heard the flaring percentage number, but there wasn’t a real good understanding of what that meant—where it was coming from or what types of wells.”

Stevens believes that there’s still much to learn to develop an accurate big-picture understanding of flaring.

“It’s nuanced because you’ve got issues related to flaring on the (Fort Berthold) reservation that are different from off the reservation, and the numbers come out differently,” he says. “It’s one thing to say that the flaring is a certain percentage, but it’s another thing to understand where that number comes from and why it’s happening.”

To emphasize how the industry has adapted and responded to flaring concerns, Scobel points to Caliber’s accomplishment of developing zero emissions pads from which there’s no flaring of produced gas or tank gas—the “little flare” to burn off volatile organic compounds from atmospheric tanks.

“You can truly have a zero-emissions pad, and that’s a win in anyone’s book,” he says. “Our goal is to have as small of a footprint as we can on these pads. By not flowing through the atmospheric tanks, producers need fewer tanks on location so we have a smaller footprint when we’re out there. We’re turning those flares off on location, which is more environmentally friendly.”

Helms has said there are already examples of companies beginning to work together to improve the efficiency of capturing and moving gas to processing sites. He is hopeful that the new flaring regulations will help create industry partnerships that reduce flaring.

“The message to me from the commission on the first was very clear and that is that this policy is only going to make a difference if we are very, very strict about granting exemptions to it,” Helms said. “There is, I think, enough time between now and Oct. 1 and now and Dec. 1—when that October data comes in—for companies to form those alliances and make those cooperative agreements.”

Scobel and Stevens agree that collaboration and cooperation are playing a key role in getting flaring under control.

“Collaborating with our competitors and our peer group in the Bakken, I’d just point out that none of this was done through regulation,” Scobel says. “This was operators getting together and seeing how we can meet best practices as an industry prior to any discussion from governing bodies.”

In hindsight, it might look like all this collaboration came out because of the new gas capture plans, “but really, industry was starting to do this already. There’s much more collaboration going on because it’s just easier to forecast what’s happening with the leases being held.”

The EERC’s online database of organizations with gas flaring technology and expertise has had the unforeseen benefit of encouraging collaborations between different entities.

“Where there are opportunities to pair up a natural gas liquids company with some other company in CNG (compressed natural gas), they don’t choose to go down that path,” Stevens says. “It probably doesn’t make a lot of sense for them to create their own CNG platform, but they can partner with somebody who already has a system and strike an arrangement. They’ve got a broader package to offer than if they’re just NGLs (natural gas liquids) or just CNGs.”

“We’re seeing more of that happening, and we’ve encouraged it to help these vendors and technology people to get in line with what we’re seeing E and P (exploration and production) companies looking for,” Stevens also said. “They’re looking for a turnkey solution. They want someone to bring in a solution that they’re looking for and operate it and prove economics.”

However, bringing a solution to a well site can come with complications.

“One of the most misunderstood terms in our business is ‘skid mounted,” Scobel believes. “When people hear that a process is skid mounted, it implies that you pull it up with your pickup, plug it into the wall and away you go.”

“Even skid-mounted equipment needs quite a bit of connection and construction to get it all bolted together on location,” Scobel explains.

It’s not so much that there isn’t a solution to gas flaring, but the amount of time needed and the number of obstacles that must be overcome to implement them.

“The areas that you see the most flaring are the areas furthest from processing and that don’t have enough pipe infrastructure,” Scobel says. “The low-pressure gathering that’s required to get this gas to a processing point is intensive. It takes large pipe. It takes dollars to do this. It takes time to acquire right of ways and get this stuff built and designed and installed and to work out deals with the operators.”

In addition, Scobel noted that other factors impacting the construction of infrastructure includes the cost of acreage, rugged topography, traversing U.S. Forest Service land and dealing with Lake Sakakawea and wetlands.
“On our side, when we’re evaluating the economics, it can make deploying those assets more complicated or more expensive,” he says.

Significantly reducing flaring isn’t the only area in which Caliber Midstream is working to improve the quality of life in the Bakken. Scobel said the company provides a full suite of services to its operators aimed at improving safety, reducing truck traffic, creating better relations with landowners and minimizing environmental impact.

For example he noted that: “We’re putting in four or five lines in a right of way.

The landowner benefits from dealing with one company instead of four or five. We can also bring our safety program into a right of way and have a corridor where all the construction is controlled by one company. It’s safer and more friendly to landowners as well.”
Caliber delivers freshwater to well sites by pipeline and transports produced water, crude and gas away from the site by pipe.

“As an industry, we’re seeing a reduction in truck traffic as a result of being connected by pipe,” Scobel says. “We’re trying to get all the trucks off the road. It’s a lofty goal, but that’s where we’re headed.”

Besides eliminating gas flares, Scobel sees visible differences on well sites serviced by Caliber.

“You see a much smaller footprint, fewer tanks on location and less capital deployed by our partners,” he said. “That’s certainly a success story.”


Author: Patrick C. Miller
Staff Writer, The Bakken magazine

Printed in The Bakken magazine - August 2014