The Decline And Fall Of North Dakota’s Bakken Oil Play

Bakken, NGL, Tallgrass, North Dakota

By: Art Berman – Forbes – Oil production from the Bakken oil fields of North Dakota fell to a 7-year low of 827,000 barrels 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 because of low prices.

The average wellhead price in the play is only $31.75—almost a $9 discount to the West Texas Intermediate benchmark. That’s because of high transportation costs from the Williston Basin to the Cushing pricing point and to refineries. There are only 10 active rigs in the Bakken today compared to an average of 53 rigs in 2020.

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.

2019 wells have much higher production rates in the first 10 or 11 months than wells with first production in 2017 and 2018. Then, 2019 wells declined rapidly and cumulative production after 17 months was lower than 2017 and 2018 wells.

That is a clear example of rate acceleration but lower probable reserve addition. Table 1 below shows that estimated ultimate recovery (EUR) for top Bakken producers peaked in 2017 and that EUR for wells with first production in 2018 and 2019 were lower.

The table further shows that the ratio of EUR-to-12-month cumulative production decreased every year since 2014. That means that an increasing percentage of total reserves are produced in the first year after 2014. That can be a good thing because it may mean that payout occurs earlier and that the net present value is higher. That is not, however, true for wells with lower EUR.

More importantly, the b-exponent decreases for wells drilled after 2016.

Figure 3 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.

An expanded version of this post with more charts and discussion may be found at this link.

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