Bakken's Average Production Per Well Is Collapsing Fast

by: Zoltan Ban


Bakken average production per well declined from a record 142 b/d in 2012, to an average of 93 b/d in 2016.

In terms of shale profitability, it confirms that EUR numbers quoted in company presentations are likely too optimistic.

In terms of longer term production outlook for the field, it confirms that a high well decline rate is likely to be a heavy burden, limiting field's potential.

The data, which shows average production of all wells currently producing in the North Dakota Bakken formation, is often a data point which tends to be under-appreciated and overlooked, even though there is a lot we can learn from this data point in regards to the Bakken shale field and the wells which were drilled in it so far. When the shale drilling boom first took off, there was little drilling taking place in the field and average production per well was about 25 b/d. In 2007, drilling started to increase and average production per well started to increase as well. Average production per well increased to a record yearly high of 142 b/d in 2012 and is currently down to 83 b/d as of December, which is the last monthly data point.

Data source: North Dakota Government.

As of the end of 2016, average well production in the North Dakota Bakken was 83 b/d, at first glance, one would be tempted to ask "so what?", there are more and more old wells, therefore this should be expected. That may be true, but if we take a closer look at the data, we can learn a lot from it, therefore we should not just ignore it. For instance, given that the average age of those wells is about three and a half years, we know that a typical shale oil well in the Bakken will likely produce about 83 b/d after three years. With many shale producers reporting initial 30-day production rates in the 1,000-1,500 b/d range, it gives us a good idea in regards to how typical well decline rates progress. It is in effect a confirmation of the expected steep decline rates that sometimes get contested in the interest of claiming shale profitability is better than it actually is.

If we look at the average age of a well in 2012 when we reached a peak in the average production of those wells, it was around two years. This tells us that from year two to year three, we can expect a decline of as much as 40%. This tells us that by year three of a typical well's life, there is still a very steep rate of decline in place.

Lessons we can learn from this data in terms of shale well profitability.

Back in 2015, I wrote a series of articles entitled, "Economics of a shale well". It was an exercise in providing an approximate guide to shale project profitability within the first ten years of a well's life. My approach was simple. I took initial production data from individual companies and applied a typical well decline curve to it, in order to figure out whether those wells will pay out or not within the first ten years, assuming a certain price for oil & gas. I covered a significant number of companies, and one of the common features I managed to observe is that EUR numbers seemed to be universally inflated by every company I looked at. In most cases, the estimates have been inflated by a factor of two.

Some may be tempted to argue that I did my shale profitability study of those companies two years ago, therefore it is no longer valid to say that EUR numbers are inflated because wells became better since then. Problem is that EUR estimates continued to rise together with the higher production data from newer wells. The EUR estimate situation is therefore still one where companies are intent to continue to exaggerate, therefore provide an unrealistic view on profitability. Given that we now know with certainty what happens during the first three years of an average well's life, it is becoming harder and harder to continue justifying those numbers as far as I am concerned. The most important part of a shale well's producing life happens during this period. For the EUR numbers that most companies still throw around to be anywhere near accurate, the average shale well would have to produce for about a century, with a dramatically slower decline rate after year three. I know that we can expect shale well decline rates to slow year after year, but it is still hard to justify the numbers we are getting from individual companies.

We should keep in mind the fact that while the slowdown in drilling in the past few years contributed to the relatively sharp decline in average cumulative well production, there are also some factors which likely helped. Some of the less efficient rigs were retired. There was also a trend of consolidation of drilling into the core areas of the field in response to the decline in oil prices. All these factors contributed to increased production from each new well, so even though fewer wells have been added since the oil price crash, in effect speeding up the aging of the average well population, each new well did add more production than the average well did prior to the oil price collapse in 2014.

Now that we are in oil price and thus drilling recovery mode, the decline rate in the cumulative average well should be tempered somewhat or even temporarily reversed for a little while, if there is a large surge in well completions. At the same time, a drilling and completion surge will also likely mean a return to drilling in the less economical parts of the field, which should limit to some extent the up-side in average production per well. It is important to understand that any increase in production per average well will happen as a result of the effect that a well completion surge will have on the average age of Bakken wells. It will not be as a result of some significant leap in well production potential. In fact, the opposite will happen, because a surge in well completions will most likely mean a departure from the core consolidation plan used to survive the oil price slump. After all, drilling opportunities in the Bakken core are not infinite. As I pointed out on previous occasions, the four county core area is increasingly getting crowded, at least in the economical parts of the counties.

Source: AEIdeas.

While the data points in regards to average production per existing well in the Bakken may not seem like such an interesting indicator of anything to many who are investing in shale companies, or those who analyze the industry, I think it is a very useful indicator of where we stand in regards to shale profitability. I recently started analyzing where we stand on cash breakeven odds for a number of shale producers for this year, and as I pointed out Continental (NYSE:CLR) and Whiting (NYSE:WLL), both of which are heavily involved in the Bakken, are both likely to struggle in terms of getting as much money out of the ground as they push into it, unless oil will see a significant increase in prices from current levels. Confirming the fact that the average well only produces just over 80 b/d after about three years in production, it tells us that the total amount of oil that we will likely see coming out of a typical Bakken well will be far less than current company estimates would suggest.

The undeniable fact in regards to well production decline has significant implications for not only shale investments, which thus far showed a great deal of capability to increase production, but are far from proving themselves to be actually profitable, but also in regards to total field production prospects. We now know that wells that may initially produce well over 1,000 b/d will decline to about 80-90 b/d in about three years, meaning that over 90% of the production initially gained when a new well enters production is lost within the first three years and needs to be replaced just to keep production flat.

Another way of looking at it, is that if a well is brought online today, which produces 1,000-1,500 b/d on average for the first 30 days, it will lose about 1 b/d on average every day for the next three years. That is production that needs to be constantly replaced. The rate of decline should decrease considerably after the first three years, nevertheless with every new well that is added to the field, the burden tends to only increase in the long term. This tells us that the odds of a second shale boom in the Bakken field which would mirror in length and intensity the last one is unlikely to happen. In fact, with production off by about 270,000 b/d compared with the peak achieved in December, 2014, it is even possible that the Bakken field may have permanently peaked already. This is something that should be kept in mind when discussions in regards to the global oil market outlook tends to be steered towards oil price pessimism due to the automatic assumption that shale oil will just burst on to the market in sufficient volumes to keep prices low for the foreseeable future. The current profitability prospects, as well as the overall technical field prospects do not support that thesis, even if the thesis itself is widespread.

Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.

I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.