In the Bakken, increasing volumes of oil, gas and natural gas liquids (NGLs) are flowing to various markets. Yet, E&P companies, both large and small, are struggling to get good take-away pathways to monetize their production.

Without sufficient infrastructure, bottlenecks and inventory gluts have reduced the price paid per barrel. Also, producers are forced to pay for more expensive and less efficient means of getting oil and gas out of their fields. And, even the best of those methods become undependable during times of bad weather and roadway restrictions.

“Production is ramping up in the Bakken, and I think the industry needs to pay a little bit more attention to making sure they have good long- and near-term takeaway capacity.” —Rehan Rashid, analyst for FBR Capital Markets

From pipelines to trains, to trucks carrying oil—and natural gas—out of production fields, all aspects of midstream infrastructure must be significantly increased to reduce bottlenecks.

For example, Bakken processing infrastructure has failed to keep pace with the dramatic growth of rich-gas production, exacerbating the need to flare gas. An average 18% of gross gas production has been flared during the past 12 months. And Bakken processing capacity is expected to remain constrained until 2014, when the construction of 490 million cubic feet per day of announced processing capacity is completed. In addition to more gas-processing capacity, the area needs more NGL take-away.

The faster such infrastructure is built, the better, say analysts. A window of time is approaching in which serious disconnects exist between maximum forecasted production and minimum take-away capabilities.

In April, about 425,000 barrels of oil per day were produced in the basin, including North Dakota, South Dakota and Eastern Montana, according to Philip McPherson, analyst at Global Hunter Securities LLC. While many of the larger independents have secured firm transportation for a portion of their production, most operators have turned to trucking and rail as a means of reaching the markets, he says.

Such alternative sources of transportation are significantly more expensive than pipelines, “which has taken price realization to more than $10 per barrel,” he says, compared to West Texas Intermediate. Altogether, as of April, aggregate takeaway capacity was 445,000 barrels per day, providing a margin of only 20,000 barrels.

Pipeline and railroad capacity increases are planned for the Bakken during the next few years. Source: FBR Capital Markets.

Coming crude constraints

Meanwhile, according to research by FBR Capital Markets, the 9 million-acre basin could ultimately produce 25 billion barrels of oil equivalent, worth some $140 billion, assuming a long-term $90 per barrel price and per-barrels costs of $12 for finding and development, $28 for cash operating costs including basis differential and production taxes and a 15% discount rate.

The firm’s analysis indicates that the June rig count and planned increases could cause take- away constraints of as much as 75,000 barrels per day by fourth-quarter 2011.

“Production is ramping up in the Bakken, and I think the industry needs to pay a little bit more attention to making sure they have good long- and near-term takeaway capacity,” says Rehan Rashid, analyst for FBR Capital Markets. “Most of the companies and investors that we talk to are reasonably comfortable thinking that there is enough take-away capacity from the area. There is now, and for the next few quarters, and there will be next year, but there will be small windows in time where we have some issues.”

By July, Bakken oil production fell slightly, down to about 410,000 barrels per day, caused by the well-documented Missouri flood, and other factors.

“There was about 100,000 barrels per day of excess capacity in the first quarter of 2011,” explains Rashid. “During the rest of this year’s quarters, we are still okay. But, beginning in fourth-quarter 2011 and the first quarter in 2012, we might be a little bit oversupplied, where production will outpace take-away capacity.”

After that, more pipeline capacity is scheduled to come online, he says. But long term, in late 2013 and early 2014, the basin will have capacity issues again.

“Ultimately, production will get close to 2 million barrels per day, perhaps by 2018 or 2019. The midstream operators and producers should focus on that as a sort of end game for takeaway capacity additions,” he says.

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One of the major take-away projects for the basin will be the TransCanada Corp.’s Keystone XL pipeline. “That project is still two years away, and is something we need to keep an eye on. If it is not built, or is delayed, there will be material implications.”

Regarding Rangeland Energy LLC’s COLT railroad project, he says, “In general, rail transportation is a bit higher costing than pipeline take-away capacity. It is still in the industry’s interest to figure out if there is more ability to expand pipeline capacity for the long term and not be too reliant on the rail side.”

Yet, getting to the big production numbers is not a sure thing, and some challenges lie ahead. “If we look at the projected rig count that is needed to deliver these volumes, and the capex that needs to be spent, there is a lot more work to be done,” observes Rashid. “Yet, with all the rain and related issues with that, a lot of the Bakken companies’ stocks have been under severe pressure from the fall in production. I think that is a transitory issue. The more important issue is the take-away capacity.”

Currently, North Dakota crude differentials for pipeline-transported production are tracking between 10% and 15%. As producers send out more production on rail, the differential will expand on an aggregate basis. If production is trucked up Canada, differentials could climb even.

“In 2009, when we saw the differential blowout, the cost to move North Dakota crude to Canada by truck, which is the ultimate outlet to relieve barrels from the basin, was about $20 per barrel,” says Rashid. “If that happens today, the differential could be as much as $40 off the West Texas Intermediate price.

Going forward, in first-quarter 2012, producers likely will have difficulty trucking out oil because winter storms make roads difficult to navigate.

“What is clear is that with an asset base that is as big as this, the industry is going to have a peak production that is close to 2 million barrels per day by 2015, rather than the million and change that people generally talk about, because this basin has 25 billion barrels equivalent of ultimately recoverable resources here,” warns Rashid.

Given that, the upstream and midstream sectors will be working tougher during the rest of the year to be sure that, whether by train, trucks or pipelines, crude oil will have sufficient basin-exit options to get to markets in the most efficient and profitable ways possible.

Rich-gas solution

Yet oil is not the only Bakken product facing take-away constraints. Associated gas from production is high-Btu, valuable, and not easily moved to markets from the play.

But, for some gas producers, Alliance Pipeline is in the right place at the right time. “In place right now, we have a gas transmission facility that runs from northeast British Columbia, Canada, to Chicago, Illinois, and passes right through North Dakota on its way,” says Bob Blattler, manager of supply development for Alliance Pipeline.

“At the bottom end of that line is an extraction facility owned and operated by Aux Sable. We are looking to build new infrastructure in North Dakota for associated gas in the Bakken shale-oil development. We will bring connectivity to the Chicago market for this Bakken natural gas.”

Alliance Pipeline plans an open season later this summer for its proposed 77-mile rich-gas project that would have a capability of 120 million cubic feet per day of capacity and would connect with Hess Corp.’s Tioga gas-processing plant.

“Through the open season, we hope to attract incremental supply to that asset as well. Hess is our anchor shipper,” says Blattler. For now, Alliance is pre-marketing the project with other parties in the region.

Like its original system, Alliance’s Tioga Lateral Pipeline will be built to high technological standards. The current Alliance pipeline has only been in the ground for 10 years, and its track record is very good.

“This is a large scale opportunity that we are looking to pursue”, says Blattler. “It includes a significant Federal Energy Regulatory Commission review and application process, including a comprehensive environmental assessment.” The pipeline will cross several counties running from Tioga, North Dakota, to Sherwood, North Dakota, where it will connect with the Alliance mainline and flow onto Chicago. The project will employ up to 375 people during its construction and will serve as a key solution for producers to get their gas and NGLs to market, as well as to help alleviate gas flaring in North Dakota.

“In place right now, we have a gas transmission facility that runs from northeast British Columbia, Canada, to Chicago, Illinois” —Bob Blattler, manager of supply development for Alliance Pipeline

If during the open season the company finds that requested take-away exceeds 120 million cubic feet, it will investigate expanding the project. “There are a number of things we can do to expand capacity,” says Blattler. “We can increase the lateral pipe size. Or, if approved and built, additional compression can be added once the pipeline is in operation.”

Yet, getting even the currently planned work done will not be easy. This area is not like the typical Texas oil field where labor, service and supply are readily at hand.

“One of the issues that the Bakken midstream sector is having is the amount of activity that is already there,” Blattler explains. “The activity has already constrained the labor resource pool. Still, we are optimistic that we will have all of the contractors in place to allow us to put the line into service for July 1, 2013.”

Meanwhile, Alliance Pipeline is already receiving some natural gas production from North Dakota through its Bantry meter station. “That flows through the Pecan Pipeline. We are seeing gas with heating values of 1,500 Btus. That’s key to the producers. They will not have to put in all of the processing that would otherwise be necessary to get to a typical gas-transmission service provider.”

The Alliance assets operate at high pressure, about 1,935 per square inch, so the liquids entrained in the gas stream stay entrained.

Going forward, Alliance is open to other opportunities in the Bakken and elsewhere. As Blattler points out, “We continue to keep our eyes on other supply areas for potential development as their upstream operations go forward.”

Processing progress

Elsewhere, Phil Archer, facilities manager for Whiting Petroleum Corp.’s Robinson Lake project is hard at work to bring more gas-processing capacity to the area.

“Our Bakken facilities center around Robinson Lake, which is south of Stanley in North Dakota. We are working on a second gas-processing complex that serves the Pronghorn field.” The facility, called the Belfield plant after the nearest town, is now in the concrete-stage of construction.

“This is a first for Whiting, to form midstream facilities that are distinct from upstream operations. It’s a sign of our growth.” — Archer, facilities manager for Whiting Petroleum Corp.

“This is a first for Whiting, to form midstream facilities that are distinct from upstream operations. It’s a sign of our growth,” he says.

The Sanish field, which facilitated the company’s Robinson Lake plant, has put the company into “a whole new realm,” he says. “We have enough people in our facilities organization now that it justifies direct management.”

Whiting is finalizing the expansion of Robinson Lake that will take the facility up to a process capacity of up to 90 million cubic feet per day.

“It’s similar to facilities in other rich-gas plays with 1,500 Btu gas and 10 gallons of natural gas liquids per thousand cubic feet of gas,” explains Archer. “Using propane refrigeration to cut deep into the gas stream, we can recover six gallons of natural gas liquids per thousand cubic feet of gas.”

The company has also constructed a 240,000-gallons-per-day fractionation system at Robinson Lake. The facility makes propane, field-grade butane and natural gasoline, which it sells along with its oil production from the area. “The fractionator has been quite economical, because there is a sufficient local propane market,” he says.

Currently, the facility processes 50% third-party gas. “It is anchored by Whiting gas, and designed primarily for Whiting gas, but we are open for business for third-party gas.”

The Robinson Lake facility is one of several projects developed to eliminate gas flaring in the play. “We are building these facilities to match up with our production areas as close as possible to eliminate flaring.”

Minot, North Dakota, where many oilworkers from the Bakken gather, saw its Ward County Fairgrounds flooded by Missouri River in June. Photo by Lowell Georgia for Hart Energy.

Whiting’s “number one issue” with the plant is the same issue all local producers and processors face—growing pains. Specifically, Archer is tasked with establishing the organization at the plant, and is looking at housing and new work force deployment.

“I was fortunate to make my first trip out there a few weeks ago, and I found it a bit challenging. The conditions there, like the housing for employees, are more challenging than I have seen at places like Vernal, Rock Springs and Gillette, when they were really strapped for hotel space. It’s tough.”

To solve the housing issue, Whiting is building man camps for some of its transient drilling, construction and operations personnel, as other producers in the area are doing.

“At some point, we might be involved in facilitating the construction of apartments or other types of housing. The industry is seeing operator-employment opportunities turned down, simply because there just is not enough housing. We are also training a new workforce, getting them familiar with these processing requirements.”

So how well is Whiting’s oil take-away system working? “Pretty good, actually, since that is the cash register,” says Archer.

Whiting’s Sanish-produced oil is gathered along the same rights-of-way as the gas gathering, and is moved to the Robinson Lake facility to a receiving tank. From there, the oil is transferred into a short segment of pipeline and is finally delivered into Enbridge’s system at its pipeline-injection tank facility at Stanley. “We partnered with Plains for that company to take over and operate that short segment,” he says.

Hess Corp.’s gas plant near Tioga, North Dakota, is under expansion construction. Photo by Lowell Georgia for Hart Energy.

Trucking compressed gas

As has been well documented, much of the Bakken oil is making its way out of the play via trucking companies, because there is insufficient pipeline take-away for the increasing volumes. But Bakken trucking is not just for oil. The Bakken Express project, a compressed natural gas trucking project, will also help to minimize flare in the Belfield and Pronghorn areas.

“As we start to build a plant over there, we are going to build the capability to truck gas over to Petrohunt’s pipeline,” says Archer. “These trucks are capable of carrying 125 thousand cubic feet of pressurized gas per truckload.”

The project was conceived by a local North Dakota entrepreneur, he explains, who developed the business model and received some North Dakota state funding.

“He proposed that, when we got our gathering built, but before our processing and pipeline take-away connections were in place, they would truck the gas some 29 miles to Petrohunt’s pipeline. It’s in everyone’s best interest to get that gas into a pipeline.”

A slug catcher reflects the morning sunlight at Whiting Petroleum Corp.’s Robinson Lake facilities. Photo courtesy of Whiting Petroleum Corp.