North Dakota oil output totals 1.39 million b/d in March, up 4% on month: state

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North Dakota oil output totals 1.39 million b/d in March, up 4% on month: state


March oil output not a record, but not far below

Favorable weather sets stage for production growth

Better well completions get higher oil, gas yields

Houston — North Dakota oil production in March totaled 1.39 million b/d, up 4% from February, but still below the all-time high earlier in the year, the state's Department of Mineral Resources said Wednesday.

Natural gas production, though, hit an all-time high of 2.8 Bcf/d, up 6% from February, Lynn Helms, the state's oil and gas director, said during a monthly production webinar.

"That was a pretty good recovery [on the oil side], up almost 55,000 b/d from February," Helms said. "But we're still about 13,000 b/d shy of the record set in January."


That all-time high monthly average production for oil was 1.403 million b/d. The state is one of the largest oil producers in the US, and home to the bulk of production from the Bakken Shale, an unconventional crude formation.

Helms noted that weather in North Dakota for February and the first half of March was "brutal," with temperatures well below zero. Even around March 9, wind chills were 50 degrees below zero.

But starting mid-March, favorable weather has reigned in the state, Helms said.


As a result, "I anticipate that starting with [the April report], we'll get back to setting records," he said.

While he did not officially give a reason for the high gas production in March, Helms said new completion technology is causing volumes to rise for North Dakota wells.

He cited one well in the state's Antelope field that recently came online at 10,000 b/d of oil -- one of the highest initial production rates ever recorded for a US well. Antelope field has been producing since 1952, Helms said.

But even apart from that, domestic unconventional wells in generally are producing increasing yields of oil and gas from improved well-completion techniques.

And for gas, "they're seeing the same kind of well performance in Appalachia and the Anadarko Basin [in Oklahoma] that we're seeing here," Helms said. "They're no longer shocked in Pennsylvania when a new horizontal well ... comes in at 100,000 Mcf/d."


"There is just so much natural gas [being produced] that prices are weak and going to stay pretty weak" going forward, he added.

Horizontal wells still decline much more rapidly than conventional wells, but they're starting out much higher than they did a few years ago, he said.

"Completions are really holding up and sustaining significantly higher production rates," he said.

With the advent of better weather in late March, the number of well completions jumped by 74 from February to 968, Helms said.

And with load restrictions coming off state roads, the number of working hydraulic fracturing crews is rising -- back into the mid-20s at the end of March and climbing, he said.

"We ought to see 40 to 50 frac crews operating in North Dakota through the summer," he said.

Also, the state's rig count on Wednesday was 65, up from April's 63, but below the 66 working in March.

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Hess Produces Record-Breaking Test Well In Williston Basin

Oil Patch Hotline
Thu, 05/02/2019 - 10:09

Hess Corp. has produced a record-breaking 24-hour test well this month in McKenzie County, N.D., surpassing all records for U.S. land wells, according to an article in the website of the Oil Patch Hotline, an oil and gas trade publication for the Williston Basin.

“This was a barn burner,” said Hotline Publisher Dennis Blank. “The highest IP tests recorded before this on new horizontal Bakken wells were in the range of 3,000 to 4,000 barrels of oil equivalent per day.”

Hess said the An-Bohmbach-153-94-2734H set a new record 24-hour IP at 14,662 boe/d. The well produced 10,169 barrels of crude oil and 26,960 Mcf of natural gas and is located in Sec. 22, T153N-R94W. This new record breaker followed an earlier April 5 record of 10,626 boe/d on a companion horizontal well in the same pad.

“It was a great well and a great result,” said Hess President Greg Hill. “We achieved a very high rate IP, and it confirmed that our acreage performed very strongly in comparison to other operators.”

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New completion designs, breakevens help Bakken break records

A historic, decades-old oilfield in North Dakota is responsible for one of the highest barrel per day initial production rates ever recorded from a well on land in the U.S. The record-breaking well highlights how advanced completions in the Bakken shale play have become, and why the play is still leading the world in technological advancements deployed in the field. The Antelope field hosted a well that surpassed 10,000 barrels of oil per day (16,000 barrels of oil equivalent if the natural gas produced from the well was factored in), according to Lynn Helms, director of the department of mineral resources for North Dakota. Helms talked about the well and the impact of enhanced completions on the Bakken during his monthly update to industry and stakeholders.

“We are seeing the effects of remarkable wells,” he said. “There is almost no where you can drill where you can’t make money.”

New completion designs are expanding the perceived core of the Bakken and Three Forks formation by roughly 40 to 50 miles in some cases. According to Helms, the wells still decline but they start out with production rates that are 50 percent higher than previous versions and also remain producing at sustained levels that are also

50 percent higher than wells producing for a similar time frame that were also previously drilled and completed in a similar area.

“Virtually everywhere is economic,” he said.

Starting in mid-March, the Bakken reached roughly 25 frack crews after weather hampered operations in the Williston Basin for the winter months. By mid-summer, there should be approximately 50 frack crews operating in the state.  “Everything is moving at a rapid pace now. Road restrictions are off,” he said, adding that some counties have seen a big uptick in activity and workover and completion work is really taking off.

Later this year, oil production should once again begin breaking records. Natural gas production continues to rise. In March, natural gas production rose 6.5 percent from the previous month. Prices remain low for gas and natural gas liquid takeaway capacity still remains inadequate. Other states with shale gas plays have expressed similar issues as North Dakota, he noted, adding that all states are now accustomed to massive gas production volumes from new wells. In North Dakota, the volume of gas captured is at an all-time high, but supply is outpacing takeaway capacity.

On the crude-by-rail front, the state intends to file a lawsuit against the state of Washington related to new crude-by-rail vapor pressure restrictions the state has planned to start later this summer. According to Helms, the lawsuit is based on a violation of interstate commerce laws and the science behind the Washington law.

With 1,800 job openings for oil and gas positions in the state, Helms said they are also sharing the same issues of other states that have shale plays: they all need more workforce. The state has plans to develop new options for high school workers and streamline the process of getting into certain jobs. In the next two years, projections show the state will need to fill 3,500 jobs each year to meet the need of the oil and gas industry.

Permitting for new wells is still strong at roughly 100 to 150 permits per month. Oil prices are expected to rise due to global turmoil and throughout the year, Helms expects the Bakken and Three Forks (where 99 percent of the new wells are being drilled) to add drilling rigs.

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Breakeven oil prices underscore shale’s impact on the market

By Michael Plante, Kunal Patel | May 21, 2019


The oil price that companies need to profitably drill new wells has closely tracked prices for long-dated oil futures in recent years. The emergence of U.S. shale production seems to be playing a large role in anchoring long-term oil prices.

The breakeven price—the price of oil needed to profitably drill a new well—is of great interest because it provides information on how activity in the oil sector might adjust if oil prices move dramatically. Its relevance has only grown over the past decade with the emergence of shale oil in the United States. Shale has a shorter lead time between drilling and production relative to offshore exploration


and other traditional oil projects, making it more responsive to oil price movements.

The average breakeven price of oil has fallen 4 percent (or $2 per barrel) over the past year, to $50 per barrel, according to the latest Dallas Fed Energy Survey. The $50 top-line figure masks some important differences. Areas such as the Midland and Delaware basins in the Permian Basin, hotbeds of shale activity, are routinely lower on average than other locations (Chart 1). There is also variability among operators; within the Permian Basin, for example, individual responses to the most recent survey ranged from $23 to $70.

Not All Basins Created Equal

A recurring feature of Dallas Fed Energy Survey breakeven prices is wide variation in responses, both across and within areas. The survey does not specifically define “profitable,” which introduces a human element that could contribute to some of the variation. More important is the reality that some areas are “sweet” spots, with lower costs and wells that are more productive.

One way to see this more concretely is to consider model-based breakeven prices produced by energy consulting firms. These models often allow one to vary assumptions about drilling costs, production levels and other factors among areas. Similar to the Dallas Fed survey results, model-based breakeven prices often show wide variability within and across areas.

For example, Bloomberg New Energy Finance’s breakeven prices in the Permian range from $46 per barrel in Loving County to $87 per barrel in Reagan County. The wide variability is largely driven by the quality of the rock, with wells in Loving County typically producing at higher rates and lower costs relative to Reagan County.

Breakevens Track Long-Dated Crude Oil Futures

A futures contract is a binding agreement to buy or sell a specific commodity for delivery on a specific date in the future. When we refer to the long-dated futures price, we mean the price of oil for delivery five years in the future.

With that in mind, there is a very close and interesting connection between average breakeven prices and the long-dated West Texas Intermediate futures contract (Chart 2). This is true not only for the Dallas Fed Energy Survey, but also for the Federal Reserve Bank of Kansas City’s energy survey.

How should we interpret the long-dated futures price of oil? In theory, if the oil market were perfectly competitive, the long-dated futures price should equal the marginal cost of supply—the cost of producing one additional unit—needed to meet long-run demand.

In reality, while it is true that most producers in the oil market are price takers—they produce a small amount of oil relative to global supply and their product has minimal differentiation—the oil market is not perfectly competitive: OPEC can add or withhold production because it operates with spare capacity. Nonetheless, there is still good reason to believe the long-dated futures price will have a close connection with the marginal cost of supply.

Shale Flattens Oil Cost Curve, Anchors Futures Prices

Rising U.S. shale production—likely to be a major source of incremental supply in coming years—has significantly affected the marginal cost of supply, providing a plausible link between the Dallas Fed average breakeven price and the long-dated futures price.

Horizontal drilling and hydraulic fracturing have made accessible significant amounts of oil reserves previously considered uneconomical to develop. Moreover, production costs for those reserves have declined dramatically over the past 10 years. More generally, companies have sought to lower costs associated with other, more traditional onshore and offshore oil holdings. As a result, larger quantities of oil are economical to produce at much lower prices than would have been possible before.

Recently evolving oil cost curves illustrate this development. An oil cost curve tries to provide information on how much extra supply could be forthcoming at a given price of oil. Usually the price of oil is shown on the left-hand axis. If the curve is upwardly steep, very high oil prices are needed to bring relatively small amounts of new production. A flat curve suggests the opposite.

Over the past 10 years, oil cost curves have moved from being very steep to having a long, flat portion between $50 and $60 as the industry has added resources and as costs have declined (Chart 3). In other words, shale production means there is a much larger amount of supply that can be called into action given a much smaller price increase than in the past.

While market participants may differ on how much oil is available at a given price, they are all aware of the overall trends. These represent strong forces that should keep long-dated futures prices from rising too high or falling too low. Similarly, breakeven prices reported by Dallas Fed Energy Survey participants reflect the principal trends involving the marginal cost of supply in the oil market.

Given current market prices, U.S. shale production will continue growing this year. Indeed, a recent report by the International Energy Agency highlighted that shale production is likely to be a major driver over the next five years. This does not rule out the possibility of major oil price movements, but it does point to a strong tendency that oil prices will be range bound in the near future.

-Plante is a senior research economist in the Research Department at the Federal Reserve Bank of Dallas.

-Patel is an associate economist in the Research Department at the Federal Reserve Bank of Dallas.







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The Dallas Fed does not know squat  about shale oil economics other than what the shale oil industry says about itself... in Dallas Fed "surveys." How dumb is this article? Well, the simple fact that the Dallas Fed says that shale oil break'evens are the same as conventional, non-shale break'evens, is evidence enough. Nobody in the conventional, non-shale oil industry is willing to drill and complete wells based on the hope of 150% rates of return over 15 years. That is a losing proposition. When you borrow money to drill those lousy wells it is an even worse  proposition. After a decade and nearly 80,000 shale oil wells, the LTO industry is deeply in debt and was still outspending revenue by a wide margin in 2018 (IEA).  

Rising production in the Bakken does not mean anything other than a desperate attempt at more wells, on ridiculous spacing in sweet spots, with higher IP's and much steeper declines. Over drilling is resulting in rising GOR and much higher condensate gravities, a sure sign of depletion. More of that gas is getting flared and the E in the BOE revenue stream is peanuts. At $50 NDS after transportation deducts it takes 485K BO per Bakken well just to reach payout. Here is what "technology" has done for the Bakken...   "Five to six years ago it used to take a well about 5 years to recover 200 thousand barrels of oil, as you’ll find in the bottom chart in the ‘Well quality’ overview. New wells are capable of reaching this level in just 15 months. However, initial declines are steeper nowadays. After about 2 years on production, these new wells decline to production rates not far above those of older vintages, on average (see the top chart in that dashboard)."





Edited by Mike Shellman
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