All oil fields see their production levels deplete as they age. Shale wells infamously suffer from exponential decline, with their production rates generally collapsing within the first year of coming online.
Last week I came across this article by Arthur E. Berman. Art is a geological consultant with thirty-seven years of experience in petroleum exploration and production. He just published a very detailed look at the production decline in the Bakken and provided a fascinating glimpse into an aging behemoth of a field.
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% single-month drop (Figure 1). Over the past two years, output has fallen 285,000 b/d (23%). 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.
Figure 1. Bakken Production Declined 92,000 bopd (9%) 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% of the production and also 65% of producing wells in the Bakken play (Table 1).
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.
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.
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% decrease in well performance. Steeper decline rates result in lower EURs.
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.
In fact, a successive increase in oil production decline rates can be seen for all of the major operators evaluated in this study. Decline rates for 2014, 2015 and 2016 are higher than for previous years for these operators despite higher initial rates (Figure 5).
Figure 5. Oil production decline rates for recent years are greater than for previous years for the top 8 Bakken producers. Source: Drilling Info and Labryinth Consulting Services, Inc.
Gas-oil ratios (GOR) for most operators increased from 2012 through 2014 and then, decreased for wells with first production in 2015 (Figure 6).*
Figure 6. 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 7).
Figure 7. 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 7 is demonstrated in Bakken field production shown below in Figure 8. Gas increased before oil production peaked in December 2014 and continued increasing through March 2016, and then declined.
Figure 8. 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 9) and this provides additional support for progressive Bakken depletion.
Figure 9. 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 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.
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 10. That equates to a current well density of 215 acres per well.
Figure 10. 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.
Figure 11 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.
Figure 11. 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% 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.
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*Statoil and Marathon depart somewhat from this general observation. GOR for these companies is lower than average and peaked earlier than most operators although Marathon’s GOR has been relatively flat.
Sincere thanks to Lynn Pittinger for his many useful comments during research for this post.
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