The Decline and Fall of the Bakken: The Red Queen Collapses

The Bakken Play was described as The Red Queen by my colleague Rune Likvern almost eight years ago. Likvern meant that more and more Bakken wells have to be drilled just to keep production from falling.

“Now, here, you see, it takes all the running you can do, to keep in the same place.”

The Red Queen, Through The Looking Glass, Lewis Carroll

It now appears that ithe Red Queen has finally collapsed from exhaustion. There are only 10 active rigs in the Bakken today compared to 57 rigs in July 2018 and an average of 53 rigs in 2019.

Bakken production fell to a 7-year low of 827,000 barrels of oil per day in May (Figure 1). That is a drop of almost 550,000 barrels per day (-40%) since March. Most of the decrease in output is because more than 2,800 wells were shut in over the last two months.

The average wellhead price in the play is only $31.75—almost a $9 discount to WTI. That’s because of high transportation costs from the Williston Basin to the Cushing pricing point and to refineries.

Low price is not the worst of the Bakken’s problems. The sweet spot of the play has reached maximum infill development. That is clear from the normalized production plots shown in Figure 2. It is a classic example of rate acceleration but lower reserve addition.

EUR and b-exponent

Estimated ultimate recovery (EUR) peaked in 2017 for top Bakken producers Continental, Whiting, Hess and Oasis (Figure 3). EUR for wells with first production in 2018 and 2019 was lower than in 2017.

More importantly, the b-exponent decreased for wells drilled after 2017.

Figure 4 shows a series of idealized production decline profiles or type curves. It is a standard rate vs time presentation with rate on the y-axis and time on the x-axis. All three production history curves start at the same initial rate but depart from each other based on their decline rates. The slope of that decline rate is the b-exponent.

The estimated ultimate recovery of each production history varies as a function of it’s b-exponent. Wells with high b-exponents describe a slower rate of decline and a correspondingly higher EUR than wells with lower b-exponents.

Lower b-exponents reflect increasing boundary-dominated flow whereas higher b-exponents suggest early flow rates that are relatively unconstrained by boundary conditions. At some point in every well’s production history, decline becomes boundary-dominated and that is known as its terminal decline rate.

The sweet spots of shale plays are characterized by high b-exponents and EURs.

Decreasing EUR and b-exponents in the Bakken are because the sweet spot or core area has reached full development. More wells are now being drilled outside the core. Here operators had hoped that new fracking technology would result in commercial well performance.

What has happened instead is that wells produce at high initial rates but exhibit boundary-dominated flow earlier than wells in the core. Wells outside the core are characterized by lower b-exponents and lower reserves than in core areas.

This signals the decline and fall of the Bakken play.

Core vs. Non-Core Areas

Figure 4 shows the $50 and $80 commercial areas of the Bakken in red outlines. It is based on EUR for all wells with 12 months or more production history.

The average well spacing within the $50 commercial area is 6.5 wells per 1280 acre spacing unit (197 acres per well surface location). The corresponding well density between the $50 and $80 commercial areas is only 2.7 well per spacing unit (482 acres per well).

In other words, there are plenty of locations left to develop outside the $50 core if commercial production levels can be achieved. The results of that experiment are not encouraging.

Before the sweet spot was well-defined, more than half of all Bakken wells were drilled in marginal areas and average EUR was less than 350,000 boe per well (Figure 5). As drilling was increasingly focused in the core area, well performance improved to more than 400,000 boe in 2014.

EUR decreased through 2016 but maximum focus in the core area, increased lateral length and advanced fracking techniques resulted in a reversal of declining EUR to a new peak level of 412,000 boe in 2017. Well performance has declined since 2017 as driling has been increasingly outside of $50 commercial area.

Rise and Fall of a Shale Play

The Bakken is a case history of the rise and fall of a shale play. Production began in earnest after higher oil prices became the norm after 2008. By 2010, the Bakken became an important source of U.S. oil when production reached 200,000 barrels per day (Figure 6). Output fell after the price collapse in 2014 but recovered and reached a peak of almost 1.5 mmb/d in November 2019. Current production is about 800,000 barrels per day because of the recent oil-price collapse.

The Bakken is at a severe cost disadvantage compared to other shale plays because of its remote location and high transportation costs to refineries and storage depots.

I have defined the sweet spot of the play within the 390,000 barrel of oil equivalent contour where wells break-even at $50 wellhead price per barrel, corresponding to about $58 WTI price. In fact, only about 46% of wells drilled from 2015 through 2019 made that cut-off (Table 1).

Moreover, prices were only at that level for about half of the time from 2015 through 2019 so really less than 25% of Bakken wells were commercial for much of those four years.

Even at WTI prices of $68, only 62% of Bakken wells broke even, and prices were at that level for just 3 months in the second half of 2018.

At today’s wellhead price of about $30 per barrel at the wellhead, only 8% of wells are commercial (Figure 7).

The Bakken play had a half cycle of about 10 years in which production growth generally increased. Unfortunately, fewer than half of the wells ever paid out their initial capital expenditure.

Until recently, analysts and journalists praised the success of the Bakken and other tight oil plays because of their substantial production growth and contribution to total U.S. output. Now the pendulum of public opinion has shifted. Investors lost their enthusiasm for the shale plays in 2018 because they finally learned the economic lesson that some of us were trying to explain a decade ago.

Bakken wells have impressive estimated ultimate recoveries if only the wells weren’t so expensive to drill and complete. The technology used to produce oil from shale reservoirs is remarkable but it’s not free.

The limiting factor for all oil fields is geology. No technology can transform a shale source rock into a high-quality sandstone or limestone reservoir. As Likvern said, There is no pass on the laws of physics or the history of play and basin developments.

“Technology and/or price cannot overcome the inevitable fact that field size and well productivity declines in most plays, whether in shale or any other plays. Put in a different way: shale plays do not get a pass on the laws of physics or the history of play and basin developments.”

Rune Likvern (2012)

Most of the Bakken’s 3,800 shut in wells will be re-activated as long as oil prices continue to improve. I doubt that will happen until the Covid-19 epidemic is brought under some degree of control and oil demand recovers to 2019 levels. That means that production will languish at the lowest levels in many years.

I suspect that some investors will return to plays like the Bakken once the significance of oil to economic growth is more fully understood. Zero interest rates will motivate margin seekers to reconsider the risks of shale plays as they did after 2008. The immediate challenge is for oil companies to survive until that happens.

I doubt that the Bakken will ever return to 2019 levels. The play is not dead but the Red Queen has collapsed from exhaustion. No amount of running faster can make up for poor well performance outside the core area.