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Arthur Berman

Arthur Berman

Arthur E. Berman is a petroleum geologist with 36 years of oil and gas industry experience. He is an expert on U.S. shale plays and…

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Why Investors Should Beware Of The Bakken

It’s the beginning of the end for the Bakken Shale play.

The decline in Bakken oil production that started in January 2015 is probably not reversible. New well performance has deteriorated, gas-oil ratios have increased and water cuts are rising. Much of the reservoir energy from gas expansion is depleted and decline rates should accelerate. More drilling may increase daily output for awhile but won’t resolve the underlying problem of poorer well performance and declining per-well reserves.

December 2016 production fell 92,000 barrels per day (b/d)–a whopping 9 percent single-month drop (Figure 1). Over the past two years, output has fallen 285,000 b/d (23 percent). This was despite an increase in the number of producing wells that reached an all-time high of 13,520 in November. That number fell by 183 wells in December.


(Click to enlarge)

Figure 1. Bakken Production Declined 92,000 bopd (9 percent) in December. Source: North Dakota Department of Mineral Resources and Labyrinth Consulting Services, Inc.

Well Performance Is Declining

Well performance was evaluated for eight operators using standard rate vs. time decline-curve analysis methods. These operators account for 65 percent of the production and also 65 percent of producing wells in the Bakken play (Table 1).


(Click to enlarge)

Table 1. Operators, Cumulative Oil Production, Total Producing Wells and 2012-2015 Wells Used for Decline-Curve Analysis (DCA) in this study. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Estimated ultimate recovery (EUR) decreased over time for most operators and 2015 EUR was lower for all operators than in any previous year (Figure 2). This suggests that well performance has deteriorated despite improvements in technology and efficiency.


(Click to enlarge)

Figure 2. Bakken EUR (Estimated Ultimate Recovery) Has Generally Decreased Over Time. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Figure 3 shows Bakken EUR and the commercial core area in green. The map on the left shows all wells with 12-months of production history and the map on the right, all wells with first production in 2015 and 2016.

Most 2015-2016 drilling was focused around the commercial core area. The fact that EURs from these core-centered locations were lower than earlier, less favorably located wells indicates that the commercial core is showing signs of depletion and well interference.

(Click to enlarge) 

Figure 3. Bakken EUR map showing all wells with 12-months of production and all wells with first production in 2015 and 2016. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Well-level analysis indicates a fairly systematic steepening of decline rates over time. Figure 4 shows Continental Resources wells with first production in 2012 and 2015. 2012 wells have a shallow, super-harmonic (b-exponent = 1.3) decline rate but 2015 wells have a steeper, weakly hyperbolic (b-exponent=0.2) decline rate.

Oil reserves for 2012 wells averaged 343,000 barrels but only 229,000 barrels for 2015 wells–a 33 percent decrease in well performance. Steeper decline rates result in lower EURs.

(Click to enlarge)

Figure 4. Well-level analysis shows steeper decline rates for more recent wells than for older wells. Source: Drilling Info and Labyrinth Consulting Services, Inc. Related: One Shocking Chart On The Death Of A Gold Nation

Gas-oil ratios (GOR) for most operators increased from 2012 through 2014 and then, decreased for wells with first production in 2015 (Figure 5).*

(Click to enlarge)

Figure 5. Bakken gas-oil ratios generally increased over time but then decreased in 2016. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Changing GOR is important because it suggests decreasing reservoir energy. The Bakken has a solution gas drive mechanism. Initially, oil is produced by liquid expansion across the pressure drop from the reservoir to the well bore. Later, gas dissolved in the oil expands and this is the mechanism that lifts oil to the surface.

Rapidly increasing GOR in the Bakken probably indicates partial reservoir depletion and subsequently decreasing GOR suggests more advanced depletion accompanied by declining reservoir pressure, declining oil production and increasing water cut (Figure 6).

(Click to enlarge)

Figure 6. Increasing gas-oil ratio indicates partial reservoir depletion–Decreasing gas-oil ratio indicates advanced depletion. Source: Schlumberger and Labyrinth Consulting Services, Inc.

The sequence of events summarized in Figure 6 is demonstrated in Bakken field production shown below in Figure 7. Gas increased before oil production peaked in December 2014 and continued increasing through March 2016, and then declined.

(Click to enlarge)

Figure 7. Bakken gas production increased as oil production peaked and then it declined. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Water cut—water as a percent of total liquid produced—has increased for most operators over time (Figure 8) and this provides additional support for progressive Bakken depletion.

(Click to enlarge)

Figure 8. Bakken water cut has generally increased over time. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Company Performance, Break-Even Prices and Future Drilling Locations

Well performance for the 8 key operators shown above in Table 1 above provides a framework for company performance and break-even prices for the Bakken play.

Reserves were estimated for more than 4,400 wells with first production in 2012 through 2015 using standard rate vs. time methods. Decline-curve analysis (DCA) was used to evaluate wells with at least 12 months of production history for key operators. Production group DCA was done separately by operator and year of first production for oil, gas and water.

Results are summarized in the following tables.

(Click to enlarge)

Table 2. Summary tables of key operator EUR and break-even prices and economic assumptions. Source: Drilling Info and Labyrinth Consulting Services, Inc.


None of the key operators’ average well breaks even at current Bakken wellhead prices of $42.50 per barrel although ConocoPhillips ($43.08 break-even price) is very close. EOG, XTO and Marathon all break even at prices less than $50 per barrel but other operators need higher oil prices to break even. It is worth noting that Bakken wellhead prices are about $10 per barrel less than WTI benchmark prices.

Current well density was calculated by measuring the area of the $50 commercial area (406,000 BOE cutoff) and dividing by the number of horizontal wells within that area. There are 5,500 producing wells within the 1.2 million acre commercial area shown in Figure 9. That equates to a current well density of 215 acres per well.

Figure 9. Bakken EUR map showing the $50 (406,000 BOE EUR) commercial area and well density table. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Tight oil operators describe infill spacing of 40 to 120 acres per well favoring the lower end of that range. Current well density in the Bakken core of 215 acres per well suggests substantial infill locations remain yet declining EURs, increasing water cut and falling GOR do not support further infill drilling.

The Bakken is unique because of the extraordinary lengths of lateral wellbores compared with other tight oil plays. Laterals are commonly more than 10,000 feet in length and often approach 12,000 feet. Related: OPEC Lost $2 Trillion In Oil Price Slump

Figure 10 shows lateral lengths in the Bakken. It is clear that within the commercial core area, most laterals exceed 8,000 feet. Available evidence suggests that current well density is sufficient to fully drain reservoir volumes. That implies that further drilling will not result in producing new oil volumes but will interfere with and cannibalize production from existing wells.

(Click to enlarge)

Figure 10. Bakken lateral length map. Source: Drilling Info and Labyrinth Consulting Services, Inc.

The Downside of Technology

The Bakken play represents the fullest application of modern horizontal drilling and hydraulic fracturing technologies. The Middle Bakken and Three Forks reservoirs are tight, naturally fractured sandstones that respond exceptionally well to long laterals and multi-stage fracture stimulation. Field rules allowed long laterals well before these were feasible in other plays.

The downside of efficiency and technology is that depletion has accelerated. Resulting higher initial rates masked underlying field decline that is becoming apparent only in wells with first production in 2015. The evidence for depletion is compelling but pressure data is not publicly available and is needed to complete the case.

The most appealing aspect of resource plays is their apparent lack of risk. Source rocks are the drilling target so finding oil and gas is given. Because the plays are continuous accumulations, there is no need to map and define a trap. Since the reservoirs are tight, seals are not an issue either. But commercial risk should be more of a concern for investors than it seems to be so far.

The downside is that there is no way to stay away from water and it is produced from day one in large volumes. The Bakken has produced 1.5 billion barrels of water along with its 2.2 billion barrels of oil over the decades. Where are they putting it and what does that cost?

Investors should be worried. As analysts cheered the resilience of shale plays after the 2014 price collapse, nearly a billion barrels of Bakken oil were produced at a loss--about 40 percent of total production since the 1960s. Vast volumes of oil were squandered at low prices for the sake of cash flow to support unmanageable debt loads and to satisfy investors about production growth. The clear message is that investors do not understand the uncertainties of tight oil and shale gas plays.

And all major Bakken producers continue to lose money at current wellhead prices. If observations presented here hold up, there may be nowhere for the Bakken to go but down. Higher oil prices may not help much because the best days for the play are behind us. Future profits were sacrificed for short-term objectives that lost the companies and their shareholders money.

The early demise of the Bakken should serve as a warning about the future of other tight oil plays.

By Art Berman for Oilprice.com

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  • Tesla on March 01 2017 said:
    An exceptionally well written article by a very knowledgeable industry insider. This is a big contrast with some other writers on this website, who only seem to write articles to serve the interests of oil shorts.

    In my opinion, the fast reserve depletion of the Bakken is a precursor to the demise of the whole US shale industry, including the Permian. People are taught by Wall Street oil shorts that US shale has infinite reserve to increase production indefinitely. The simple physical truth is that the faster you produce, the faster you deplete your finite reserve.

    With this knowledge and with luck in timing, you can make a ton of money in the next few years.
  • Hayes on March 01 2017 said:
    I have no idea how this man has any clout in this industry. All people have to do is a Google search on Art Berman and look at all of his nonsense over the years. His schtick grew old about a decade ago.
  • CrazyUncle on March 01 2017 said:
    The Bakken is so 2015. It's all about the Permian. Can't get land in the Permian try the SCOOP or the STACK. The end result will be the same, but you can keep raising money on the same old business plan, just a different play. You see it's not the plan that is faulty, it's the rock. Executives get big salaries and shareholders get the promise that "next year" the company will be cash flow positive. It's only been a decade...
  • Lee James on March 02 2017 said:
    There's something seductive about fracing machinery, and that it goes so far underground, that we forget that the resource objective is, after-all, finite.
  • pat paterson on March 02 2017 said:
    thank you for the well written article...

    agree with your comment tesla...
  • Josh Jones on March 02 2017 said:
    I wonder if anyone chokes back their wells when crude sells for less than what it costs to produce. And why would anyone drill a well and not frac it... it's gotta be reservoir depletion, right? And what gives with production declines in months when travel is difficult to impossible and temperatures are fifty degrees below the freezing point of water. That's frackin' weather in Texas, y'all! Any correlation between lateral length and production declines is purely coincidental, and I'm being polite. Let me guess - the author is a highly educated engineer with advanced degrees in petroleum geology.
  • Joe on March 02 2017 said:
    So Tesla, you think oil prices are heading up?
  • Bud on March 02 2017 said:
    The shorts have made good money, but that was based on geopolitics and listening to what the Saudis were saying.

    Regarding the bakken, you are analyzing wells that, other than 15, were based on much higher oil prices. Hess and Marathon did very little drilling up there in the past year plus, so the numbers look better given your methodologies.

    It would be helpful to analyse the newest wells built with 50 dollar oil in mind. Your map shows sweet spots in Dunn and a concentration around Spanish and New Town. Marathon has shown some monster 30 day ip in this area that they claim will produce upwards of 90 percent IRR given the current flat futures curve.

    These firms need to produce oil, so it would be informative to know who has drilled up most of their best acreage and who does not. Given the commodity has an annualized long term avg Vol of near 45 percent, it is hard to discount oil back in the 70-80 dollar range given depletion and geopolitical uncertainty. So, if oil is back in that range in two years, who is in the best shape in the bakken regardless of whether the production drops at field level? Curious that you don't talk about the margins impact from the new delayed pipeline and the exports into Canada. Marathons margins in the bakken look as good as those in Texas when you factor in NGLs.
  • Steve on March 02 2017 said:
    So many comments so many different views. Most every operator choke their wells back, as well as shut them in. All costs have come down from drilling to fracing. You drill on a lease and not complete it as after permitted lease you have 1 year to drill then another year to complete, when oil was high you stood in line to get anything done in the bakken. Times have changed in the bakken, life is better for operators. As far as bakken shale depleting at a rate it can't come back is a careless statement and time will show, bakken is bidding it's time waiting on mid $60 bbl pricing. With DAPL now completed, (it is finished with oil flowing only days away) and Keystone being re-submitted cost will come down for 3-forks, bakken benches, sanish, and tyler oil plays all producing LSC. Now what no one really talks about is our neighbor to the north (Canada) who are completing LSC wells at very low cost. Less than $4.4 million from permit to production. Oil Sands will be increasing production and dumping quickly onto the market this needs to be addressed with more concern than America's shale plays being depleted. JUST SAYING !

    Thank You,

  • Werner J. Casotti on March 03 2017 said:
    In my sincere opinion, Art Berman’s article on the Bakken shale is of an excellent technical and economic level.

    Oil geologists are the professionals better qualified to give opinions on these subjects, even better than oil engineers, which is my case, I obtained my title in 1969 in Mendoza, Argentina.

    It would be interesting to know Berman’s opinion on our “Vaca Muerta” (Dead Cow) shale play, which should be called “Very Rich Cow”, because the Argentinian State, in fact the pockets of taxes-paying citizens, offers 7,5 US$/MMBtu to foreign and national enterprises, to provide natural gas, relatively a lot more expensive than the price of the commodity in the US and the rest of the world.

    Best regards,

    Werner J. Casotti
  • Anonymous234 on March 03 2017 said:
    Art has removed several viewing of the comments on his post on his home blog. Several good numeric criticisms were included.

    I also recommend to look at the (measured) criticisms by Enno Peters on Shale Profile, with lots of data. (He is actually more towards a shale critic, although sort of middle of the road, so it is not bias.)

    Bottom line is if you look at the cum curves, there is NO clear proof of the wells getting worse. The opposite, actually.

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