November 2016, Vol. 243, No. 11

Features

Thriving in a Major U.S. Shale Play: The Bakken Unpacked

As an oil and natural gas industry veteran who has been around the block a few times, Rick Moncrief, CEO of Tulsa, OK-based WPX Energy, likes to compare and contrast North Dakota’s Bakken Shale play with the venerable Permian Basin of West Texas and eastern New Mexico since his company has acquired and drilled its way to substantial stakes in both plays.

“Today, when I step back to see what the Bakken has turned into, I think it is absolutely incredible,” Moncrief said, with a mixture of passion and nostalgia.

It said a lot about both areas that Moncrief, who as a young engineer in the 1980s drilled the first horizontal well in the Bakken (1987) in a $9/bbl domestic oil price environment, hasn’t given up on either the Bakken or Permian as he expands his small- to medium-size exploration and production (E&P) company.

Despite the bullishness of Moncrief and a long line of credible major oil and gas pros who are still strong supporters, Bakken production in mid-2016 took its biggest month-to-month tumble ever. Therefore, as it becomes infrastructure-rich amid downcast production prospects, some analysts have begun to calculate that the midstream bet on the Bakken’s remote-from-markets supplies is turning sour. They say changing economic conditions have raised questions concerning future growth and the economic efficacy of the latest major pipeline out of the Bakken, Energy Transfer Partners’ (ETP) controversial Dakota Access pipeline.

The lingering areas of concern in mid-2016 include a combination of what happens in upcoming months and years to crude oil prices, how much of an eventual bounce back there is in Bakken production, which state and industry officials think could increase substantially after 2017, and whether additional major oil pipeline projects get built if and when Dakota Access is fully operational.

“As producers know all too well, hydrocarbons produced at remote locations have little-to-no value unless they can be efficiently and cost-effectively transported to market,” said Housley Carr, an analyst with RBN Energy LLC. “It’s very rare for oil or gas to be consumed very near where it’s produced.”

Carr’s thoughts essentially capture the contrasting strengths of the Bakken and the Permian that Moncrief likes to dissect. One is situated far from refineries and markets while the other sits near the U.S. refining and marketing mecca in Texas.

“You’re going to hear a lot more from the Permian in the next few years,” predicts Moncrief, who breaks it down – east-to-west – Midland, East-Central, Delaware basins, the latter being where WPX has bought its biggest stake in the Permian. He calls the Delaware part still “immature,” akin to the Bakken of a few years ago.

Moncrief tends to use lots of superlatives when talking about the Williston Basin and the Permian, noting WPX has been aggressive in both and intends to stay that way. While he differentiates the two, he labels both as “world class.”

Today, WPX is one of the newest Permian players thanks to a 2015 “company-defining” acquisition, netting about 94,000 acres under lease in the Delaware portion of the play and more than 3,500-4,000 gross drilling locations across stacked pay intervals. “This represents decades of drilling opportunities,” Moncrief said.

WPX also has core acreage in North Dakota’s Williston Basin and New Mexico’s San Juan Basin. WPX set a new high for oil production in first-quarter 2016, averaging 41,500 bpd. Total liquids volumes, including natural gas liquids (NGL), accounted for 62% of 1Q 2016 production.

At mid-2016 commodity prices, WPX plans to execute a capital budget ranging from $350-450 million for this year, nearly all for drilling and completion activity. Over half of the capital is targeted for development in the Permian’s Delaware Basin. WPX recently increased its estimated ultimate recoveries (EURs) for its Delaware wells to 900 MMboe, up 34% from its acquisition type curve of 670 MMboe.

While the economics are slightly better in the Permian than the Bakken, Moncrief likes WPX’s prospects in both basins where the average costs/well were reduced to $5-5.5 million/well in mid-2016. “I’d love to have more acreage in the Bakken,” Moncrief told an energy audience in Bismarck, ND.

Whether the markets are up or down, or production is robust or anemic, Jim Volker, CEO of Denver-based Whiting Petroleum Corp., the largest Bakken producer in North Dakota, preaches the need to be what he calls “good stewards of the resources,” adhering to all the state and federal regulations. As he reiterated his philosophy to a large audience at the Williston Basin Petroleum Conference this year in Bismarck, he exuded Moncrief’s bullishness about the Bakken’s long-term potential, noting that in the 2016 low-commodity price environment, Whiting was anticipating completing more wells again.

Also echoing North Dakota Gov. Jack Dalrymple’s strong statements about the Bakken’s future, Volker said the Bakken and the DJ Basin in Colorado can create more value than just about anywhere else in the United States, and Whiting will complete more wells and develop new ones on its mix of some 5,500 drilling locations, many in prime spots of North Dakota.

“The net present value here is higher for our shareholders than any other place in the country,” he said, adding, “We’re a big believer in the Bakken. We put our money where our mouth is here.” The 445,000 net acres held by Whiting in the Bakken add up to an estimated 700,000-900,000 boe/d.

Like other operators and many state officials, Volker sees the continuing efficiency improvements and technology advances in the field as greatly driving down costs. Therefore, with relatively modest and sustained oil price increases ($50-60/bbl), Bakken wells can supply attractive margins. Multi-stage hydraulic fracking with numerous entry points has been perfected and is driving down costs and driving up production, Volker said. More than 100 entry points over a 10,000-foot lateral and 6 million pounds of sand and 200,000 barrels of water are driving Whiting production to 900,000 boe/well, he said.

Further confirmation of these advances comes from Gerbert Schoonman, Hess Corp.’s vice president overseeing its extensive onshore Bakken assets. Schoonman breaks down those operations into essentially a manufacturing process and applying an auto industry-inspired “lean” manufacturing approach. This is the heart of the company’s efficiency gains in the Bakken, with a focus on scalability and use in all areas of the shale play, he said.

Hess managed to slash well drilling times from 45 to 16 days and from $34 million to $5.1 million per well, he said. The “lean” model applied also has helped with well spacing in not just the Bakken but other robust plays, such as the Permian and Utica in Texas and Ohio, respectively. The approach has created some high returns in the Bakken, Schoonman said, and can be used throughout the North Dakota play.

For Volker, sustained oil prices in the $50-60/bbl range can supply attractive rates of return in which operators get their money back within a year and are incented to drill more new wells. “Not only are we operating cleaner [environmentally], but more efficiently and we’re doing it with less money,” Volker said.

With over 80% of Whiting’s production in the Bakken (and another 10% in the nearby Rockies’ plays), Phillip Archer, Whiting’s senior midstream manager, feels familiar with every rock and pebble spread across the North Dakota prairie land, operating in all the producing parts of the state. He readily describes the details of building oil and gas gathering systems in the Belfield area of the Pronghorn Field, west of Dickinson, ND. Archer likes the “forgiving topography” in the area, unlike many other areas he has covered in North Dakota.

Archer deconstructs Whiting’s 140 miles of liquids gathering lines – oil and water – in the area. While advanced technology plays an ever-bigger role in the systematic pipeline monitoring, every week a field technician is driving or walking pipe rights-of-way as well, he said. That’s the external part, but there are also inline inspections, for which there are growing pressures to do more and emerging technologies to get the job done quicker and cheaper.

These two traditionally have encompassed pipe-monitoring programs, but now there is “CPM,” computational pipeline monitoring. CPM uses various flow-measuring devices to avoid gaps and inconsistencies in the data gathered and digested. It’s a pressure and flow-monitoring approach.

With the use of sophisticated algorithms, Whiting applies various line-balance technologies that provide what Archer describes as “fast, faster and fastest” results in 60-minutes to less-than-5-minute increments. There are pluses and minuses to the different measurements – the slowest has the highest accuracy while the fastest is the least accurate, but each provides useful monitoring information.

On the pressure measurements, changes in pounds can sound alarms, and eventually they can lead to a line being shut down, he said. “It’s tracking barrels-in and barrels-out, with pounds of pressure difference every five minutes with alarms all along a 7-mile pipeline. If you get a hundred pounds difference over the five minutes, there will be a high idle leading to a shutdown.”

For pipeline locating, Whiting has developed a one-call system focused on efficiency, safety and integrity, according to Archer. The company is informed and involved if there is any activity within 300 feet of its pipelines, and if there is work anywhere within 20 feet of a Whiting pipeline, a company representative is onsite before any work can start, Archer said.

In a third area designated as critical – within five feet of a pipeline – Whiting requires fiber optics and other advanced technologies like SkyView for locating pipes. “Since we started this program in 2008 and relied on contractors quite a bit to do the actual locating, our line-locating success has improved dramatically,” Archer said. “We’ve been able to pull down the rate of what we call ‘strikes.’”

Companies that provide heavy equipment in the Bakken and the other major plays in the U.S. and globally are wound tightly to the E&Ps, seeking to help driving down costs, said David Dunlevy, general manager at Caterpillar Oil & Gas. Noting many skeptics will question whether Caterpillar really wants to invest long-term in the fossil fuel industry, Dunlevy said the company’s affirmative answer is unequivocal.

“Our estimates show that fossil fuels globally will be increased by about 25% by 2040,” he said, noting that populations around the globe want to improve their standards of living, and this means access to clean water, reliable infrastructure and affordable energy.

“About five years ago we began to really accelerate our investment in parts of our business where natural gas is involved, and today we have about three times more engineers working on gas-related products as we had five years ago,” said Dunlevy, citing the example of gas capture in flaring reduction systems and remote monitoring technology for pipelines and other infrastructure, as “a very rapidly growing part of our business.”

Schoonman calls Hess’s lean approach to its oilfield operations “a big deal” that has resulted in an extra 1.4-1.6 MMbbls of sweet crude production. Through its lean program, Hess has detailed data on each of its wells in all areas of the Bakken.

“We’ve moved from 35 to 50 fracking stages on a single well, completing them in 24 hours without missing a stage, and it can be done for $2 million,” he said. “This technology is something we believe in.”

Noting that Hess is committed to sustainable operations, Schoonman said the “Bakken will only get bigger and better.”

Elsewhere in the Bakken, service companies like Halliburton have been testing and perfecting various refracturing approaches, though some technical experts urge a vetting of potential wells as candidates for these enhanced recovery processes. “We’ve come up with a thorough and rigorous candidate selection process,” said Halliburton’s Kumar Ramurthy, an engineer leading some of the company’s refracking research prior to the design and implementation on specific well sites.

Part of the diagnostic work on ferreting through various well candidates for refracking is done with fiber optics and fiber coils. They help gauge temperatures and acoustics critical to picking the best candidates for refracking. These are increasingly valuable tools in work on unconventional wells, said Halliburton technical experts.

A beneficiary of the continuing technological advances, Don Hrap, president of ConocoPhillips Lower 48 operations, calls the Bakken a “world-class energy resource, absolutely robust” and a key part of North Dakota and the larger oil and gas industry. He shrugs off the concerns about the recent lean times and low prices as part of the cyclical uncertainty in any commodity. Today, the industry is in a much stronger position than in past down cycles simply because it has the ability “to do more with less moving forward.”

As Volker and other industry colleagues reiterate, Hrap is convinced that technology has been a huge part of the U.S. energy renaissance and will remain so. “Frankly, all the technology advances [multiple well pads, faster completions, fracking advances and proppant breakthroughs] have made $60/bbl oil the new $100/bbl.” Hrap stresses that U.S. oil reserves increased 90% in six years, and natural gas reserves 125% in 20 years. “We’re at the point where North America has enough natural gas for the next 100 years,” he said.

Even with his acknowledgement that major regulatory pressures and global economic headwinds are facing the North American oil and gas industry, Hrap is another optimist, noting the expanding North American resource base and technological advances ultimately will mitigate those two national and international challenges.

“We’ve got resources and technology in the United States that are second to none,” said Hrap, recalling that he has experienced about a half-dozen up-down cycles during his career. “What’s different in this one are the resources available and the technological capability we have.”

The Energy and Environmental Research Center (EERC) at the University of North Dakota is a collaborator and innovator on some of the ongoing research, spanning ways to extend and increase recovery rates that have been notoriously low in the Bakken, refining the husbanding of produced water, and expanding and enhancing the whole fracking process in a region where great strides are being made.

A researcher at Montana Tech, Todd Hoffman, is doing extensive research on enhanced oil recovery (EOR) centered on a distant portion of the Bakken in far northeast Montana, and he said the application of EOR will continue to grow in plays like the Bakken for years to come. He cites up to 20 studies available on EOR, many of which leave open the question of “how well are we capturing EOR capability?”

Conrad Ayasse, with IOR Canada Ltd., deals with fracture flooding, using water injections in existing fractures to induce more oil production with no new drilling.

“We need to inject fluids to increase and maintain pressures to offset production declines,” Ayasse told operators at the Williston Basin conference. “The challenge is figurinf out how to inject high rates of pressure into the typical tight rocks involved in shale plays. In a multi-fractured well with 20 fractures, if you inject every other fracture, the surface you get [for production] is 2,000 times greater than a horizontal well, so you’re going to get very high injectivity.”

These types of research results are music to ears of CEOs at Bakken E&Ps even as they grapple with the sour notes of the oil price crash.

Richard Nemec is a Los Angeles-based correspondent for P&GJ. He can be reached at: rnemec@ca.rr.com.