WBPC 2015 Highpoints: Oil Prices, Basin Updates

The Bakken’s main event delivers oil price predictions and region-specific reviews on North Dakota, Saskatchewan and Manitoba production along with relevant changes possible for the Bakken.
By Luke Geiver | May 14, 2015

The Williston Basin Petroleum Conference has reflected the activity level of the basin since its inception 23 years ago. Once a small gathering of petroleum engineers and geologists, the WBPC has become a massive yearly event bringing together energy service firms, exploration and production companies, logistics providers and every other business entity linked to oil and gas production. What happens in the Bakken throughout the year can be felt at the WBPC in early spring. In the recent past, major presentations had been centered on production-increase plans and Basin-wide expansion. This year the mood of the show was heavily influenced by low oil prices and keynote talks focused on commodity prices. Attendance and exhibitor numbers were still significant. Conversations on the show floor, at the tables of the main general session or in the refreshment break lines were all connected to the reality of the low oil price environment and its direct connection to a slowdown in activity. And, despite the ever-present low price cloud lingering over the event, conversations and presentations that started on low oil prices ended with talk of the impending rebound.

History of Oil Declines, Rebounds
Tony Cadrin, president of the Canadian Society of Petroleum Geologists, knows oil price declines in the Williston Basin. Cadrin spoke at the event on his experiences during each of the previous six oil price decline situations dating back to 1986. “Our industry has survived each and every one [of the cycles] and come out stronger through optimization and innovation,” he said.

To prove his point, Cadrin documented each price decline since 1986 and how the price, and industry, rebounded. According to Cadrin, each price decline situation marked an industry milestone of innovation that helped oil and gas production excel.

In 1986, the Saudi market share war caused oil prices to collapse. After the Saudis realized oil produced from outside their region was hitting the market and decreasing their market share, the decision was made to decrease the price per barrel sold to customers around the world. The Saudi-induced price drop eliminated some producers, but it also emphasized the need for non-Saudi producers to deploy new technology. “What came out of this price shock was that the industry started to improve technology. They developed a much more reliable method of directional drilling,” he said.

Two years later, global oil supply had exceeded demand and another price decline had happened. Roughly one year after the 1988 price drop situation, the industry had figured out how to drill near horizontally onshore after using the method offshore.

The Gulf War in 1991 was the cause of the next price drop and the resulting technology innovation still used today was 3D seismic imaging.

In 1998, a lack of oil buyers in the Asian market caused another price drop, but forced geologists to use better imaging to prove where hydrocarbons existed below the surface.

The global recession of 2001 pushed prices down, but upon the price rebound, companies making $10 per barrel quickly saw $100 per barrel profits without any process changes. The fifth downturn cycle also marked the true industry realization of horizontal drilling. “We were really staying in the zone reliably and accurately,” Cadrin said. Doing so allowed companies to open up zones featuring rock permeability that didn’t previously work with vertical drilling.

The next global recession, in 2008, marked the sixth downturn cycle and the breakout of multi-stage horizontal fracturing, the process responsible for the unprecedented growth in U.S. unconventional oil and gas production.

The current oil price decline situation is much like Cadrin’s first. As they did in 1986, the Saudi’s have adopted a strategy to retain market share in the face of pressure from other producers around the world, particularly in the U.S. When the current low oil price situation ends, the industry will better understand enhanced oil recovery methods, Cadrin said. For now, oil prices appear to have hit bottom, and within 6 to 12 months, prices should recover. The longer it takes for oil to find its bottom, the higher the price rebound will be.

Patricia Mohr, vice president of economics and commodity markets for Scotiabank, shared Cadrin’s view on oil price bottoms. Mohr provided a glimpse into future commodity prices, including the perspective that oil prices have officially hit bottom. In 2015, West Texas Intermediate will average $58 per barrel, she believes. Mohr is in charge of providing price forecasts for Scotiabank along with leading a team that tracks commodity prices. By the end of the year, prices should begin to average $65 per barrel, a number she said could represent the price point when major activity could ramp back up in the U.S. At $65/b, drilled wells yet to be completed could undergo a status change. “I think at $65 crude, prices will be high enough to encourage further development and reramp activity in some of the shales,” she said.

Although the supply and demand curves for oil consumption in the world are fairly well-defined and should not undergo a massive shift, Mohr did point to several factors that could positively impact crude prices. The U.S. is expected to record a massive spring and summer driving season. The expectation also comes at a time when vehicle manufacturing in the U.S. will break its previous record set in 2000. Consumers in Europe are also increasing their driving and even China, where motor bikes are popular, numbers indicate that gasoline powered vehicles are in greater demand than ever. The positive signs, however, will not push oil prices past the $70 range until 2017, Mohr said. Global economic activity in 2015 should be 3.2 percent, a rate high enough to sustain the current global economy, but not enough to change the global oil market.

Basin-Wide Updates
Explaining the Bakken can no longer be done during a short elevator ride, according to Alison Ritter, public information director for the North Dakota Department of Mineral Resources. Ritter took the place of Lynn Helms, director of the DMR, to explain the current state of the North Dakota portion of the Bakken, with Helms unable to leave Bismarck, N.D., during the final days of the legislative session.

Today, inquiries to Ritter include questions on oil prices, policy changes and legislative updates. The DMR has recently added to its informational offerings by tracking drilled but uncompleted wells because DUCs are now a popular topic of interest, she said. In North Dakota, there are currently 900 wells drilled but uncompleted. The DUC term is not unique just to the Bakken, however, as many wells in the Eagle Ford and Permian are also under that label.

In the North Dakota portion of the Bakken, wells must be economically producing one year after total depth on a well was reached, according to state law. But, operators do have the option of putting an uncompleted well that has surpassed the one-year timeline into a temporarily abandoned status. The status requires the operators to maintain and continuously test the wells. Until prices recover, operators will not want to bring wells online and forego the high production levels that occur early in the well’s life.

When oil prices do recover, it could take roughly 10 months for the rigs that have left the state to move back into operation. But, despite the current rig count, North Dakota’s oil production should remain above 1 million barrels of oil per day in 2015. Roughly 2,400 wells will be drilled this year.

For Manitoba in 2014, 464 wells were drilled by 28 companies. Of those wells, 61 were drilled into the Bakken formation that lies within Manitoba. Keith Lowdon from the Manitoba Mineral Resources, said that during the past year, the province’s sentiment on the Williston Basin has waned after being very optimistic.

This year, roughly $700 million will be spent on oil and gas expenditures to drilling and complete 280 wells for approximately 47,000 barrels of oil production per day. Drilling could be down by 25 percent compared to the previous year.

In Saskatchewan, 2,700 wells will  be drilled in 2015, according to Melinda Yurkowski, senior research geologist for the Saskatchewan Ministry of the Economy. The southeastern portion of the province, which includes the Bakken and Torquay formations of the Williston Basin, will record 800 to 900 drilled and completed wells. Of the 575 wells drilled in the province this year, 200 have been in the Williston Basin.

Like all areas of the Bakken, drilling activity in the Saskatchewan province has been down. Through the first three months of this year, 575 wells have been drilled, compared to 970 for the same period last year.

Although the Bakken and Three Forks (Torquay) plays will continue to receive attention and produce at high levels in 2015, Yurkowski believes more activity is shifting to the Viking play on the western border. But, in the Torquay, there are two areas receiving significant attention that she said she will be monitoring over the next year. In the Ryerson, on the eastern edge of the province, the lower Bakken is missing and the Torquay sits right under the middle Bakken, making the play an attractive, shallower formation to target. In the Flatlake area, the lower Bakken formation is present and separated from the Torquay, and is showing a very noticeable uptick in activity.

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

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Three Forks: What’s In A Name? 
Petroleum Geologists are contemplating a name change for the Three Forks formation located within the Williston Basin. The formation has become a staple target for exploration and production firms looking to increase well counts in geologic zones outside of the Bakken. Steve Nordeng, distinguished professor at the Harold Hamm School of Geology and Geological Engineering at the University of North Dakota, explained the reasoning behind the possible name change in his presentation, “A Plea For A Standardized Three Forks Stratigraphy.”

Although the Three Forks was originally worked on and described in 1961, Nordeng and Julie LeFever, geologist with the North Dakota Geological Survey, created a new stratigraphy of the formation in 2010. Since that time, there has been a great deal of confusion between directional drillers and petroleum geologists, according to Nordeng. “There is a mismatch in nomenclature,” Nordeng says.

To describe the Three Forks formation, Nordeng and LeFever dissected the formation into six units, with the top of the formation labeled as six, following in descending order. Others, however, have referred to the Three Forks as having three benches, the top portion of the formation known as the first bench, following in ascending order. Issues arise when drillers claim they are drilling into the first unit and they are actually referring to the sixth, Nordeng says.

“Is the Three Forks sufficiently important enough to warrant formal designation of beds and or members?” Nordeng asks.

In the past five years, the Three Forks formation has produced 30 million barrels of oil from 2,919 wells. During the current period of relaxed drilling activity, this may be a good time to change the name of the Three Forks formation’s discrete zones so that detail in each zone is captured and drillers and geologists can avoid terminology confusion, Nordeng says.

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Saskatchewan’s Bakken Oil Volumes 
Peter Budgell of the Saskatchewan National Energy Board says his team is not about picking winning oil plays, it only tries to calculate how much oil is in the ground. The NEB team recently released an assessment of the unconventional petroleum resources in the Bakken. At the WBPC, Budgell explained the findings.

In Saskatchewan, there is roughly 835 million to 2.2 billion barrels of marketable oil in place—oil that can make it to market. The highest concentrations of oil in place reside in the Viewfield formation and North Dakota/Saskatchewan border areas. “The Bakken is likely one of the largest accumulations of tight oil in Canada,” Budgell says.

To assess the oil in place, the NEB team used a distribution of distributions approach, meaning the team relied on in-place volumes calculated with standard volumetric equations where the variables were determined from map grids of geological data. The findings show that 1.2 billion barrels of future production is still left in the Saskatchewan portion of the Bakken.