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The study found that, after five years of production, the most active Wolfcamp sub-plays have annual decline rates roughly double the proxy value of 5 to 10 percent commonly used. The most common terminal decline value actually observed in mature horizontal Wolfcamp wells was 14 percent.
The report analyzed the impact of the more plausible terminal decline rates and found that under a 14 percent terminal decline scenario, the near-term impact to total Permian supply is relatively minimal, but by 2040 nearly 800,000 barrels per day of Permian production is at risk.
After 5 years 10 to 20% decline still occurring? There goes the profit.
Terminal declines of 14%? There goes the reserves.
Most plausible unconventional plays are way, way less than that. My experience in the Bakken was decline rates after 5 years of less than 10%, and terminal decline rates at the most of 6%.
One of the key takeaways I have seen on unconventionals is yes, decline rates are quite large in the first 1-3 years, but the hyperbolic nature of the decline rate due to the very tight shales contributing production caused rates to minimally decline after that point, a rare event in conventional plays, up to 50 year expected lives, and free cash flow enjoyed for decades.
I suspect a geologic explanation for the larger declines exist. Perhaps, as some geos have explained to me, the variations of the productive streaks within the Wolfcamp are much larger than expected, and the longer-term contributions do not occur.
Most of the operators will try to explain away by saying it is the way the zones are fracced. Not likely to be the case.
I have said it many times, the Permian in general is not an unconventional play like the Marcellus, Haynesville, Williston or Eagleford. Perhaps @Smokin Joe can comment.
It is simply a very large basin with lots of oil in lots of zones that was drilled vertically, and is now being redrilled horizontally.
If these trends continue, look for a lot of bankrupt companies sinking too much money into the Permian as cashflows dry up and reserves are cut.
The effect on the US would be a tighter oil resource realized sooner.
My only work in the Permian Basin consisted of running Mass Spec on a single wellbore down there. While just gaining some popularity, the Mass Spec data enables identification of different reservoir compartments and permeability barriers, and geochemical evaluation of those compartments individually with data gathered while drilling.
As one engineer in the Williston Basin commented to me, as long as they can just shove the sand to it and get production (make money), there is a significant contingent who really don't care about such fine points.
If we look back fifty years, there was a similar attitude toward mudlogging, and it was only after proven discoveries found only because that information was collected that the technology gained acceptance.
While not gathering that data may work well enough as a strategy in the Bakken/Three Forks, every basin/formation is different, and the variability in the Wolfcamp may render the gathering of that data more important in tailoring fracs and selecting frac stages and reservoir compartments for maximum recovery.
There are a couple of different schools of thought among those who cut the checks for data gathering. The first is that we never had it before, so why bother, (If it ain't broke, don't fix it), and the other is that if you have the data, someone will find a way to make use of it.
While change comes slowly to the industry in some regards, targeting reservoir compartments which have the highest recovery potential may be the way to approach reserves with variable reservoir quality. OTOH, having the data would also allow the most efficient use of production enhancement techniques to maximize the return from marginal areas in the reservoir as well.
As for the Bakken and Three Forks, shows have been noted in the formations for decades, all over the Williston Basin, and only rarely did wellsite geologists ( at least this one) not call for further investigation of those shows (and Three Forks shows) before it was finally proven that the production potential was much more widespread than in occasional vertical wells which intersected natural fracture sets and produced, either as secondary targets, or in one well I worked as an unanticipated primary zone which would not be ignored.
I have little doubt that formation composition and gross stratigraphy play a key part in the better production figures in the Bakken, but definite 'hotspots' have been identified, and the focus has been on drilling and producing those hotspots, which, in turn, gives not only better production per well, but better decline rates and a higher ROI.
I can't say whether that same strategy has been applied to the Wolfcamp, and the horizontal play is younger, so I suspect there is a statistical artifact created by wells which have been drilled in more marginal areas, not yet statistically overwhelmed by activity in higher production potential locales. Yes, some areas aren't as good as others, and the unwary operator may sink their company trying to approach those areas as if they were prime production. In my opinion, that's where the data become critical in identifying that potential before even more money is sunk into a frac that is unlikely to produce results, or in tailoring a frac that will at least optimize ROI.
Even the Bakken is not universally good. We worked wells which more or less found the extent to the southeast of recoverable hydrocarbons, beyond that area where good wells could be made, and definitely outside the area where the best wells were. Other operators were doing the same in other parts of the basin, and in relatively short order (partly because of State data gathering and availability requirements) the best areas were identified. In Montana, the extent of the Elm Coulee Field was found by stepping out until there was nothing left to step into.
Considering a lot of Bakken wells were drilled and completed as the first well on the pad (after the advent of pad drilling) and there continues to be a significant backlog of DUC wells, those initial wells (to hold leases) may well be showing the influence of the undeveloped portions of that spacing, whether DUC wells are present or not. As development continues and those other wells come on line, there may be some decline in the apparent quality of production, but keep in mind that these wells are still in areas where the best production has been found. I think there is some 'cherry picking' effect involved. As the play continues to mature and DUCs are brought on line, re-fracs are conducted, and less (note
less, not un-) desireable acreage comes into play, those numbers may become a little less attractive.
As for percentage declines, I guess that depends where you start. Every successive decline at the same percentage rate translates into a smaller decline in number of barrels. We have observed that hyperbolic initial decline rate in horizontals here, in the first two years or so (I often advised landowners to bank their first two year's royalty checks and not to expect more than 20% of the first one in the long run after a couple of years, because people have been known to go a little nuts and set themselves up with a non-recoverable debt load based on the IP royalties.) Subsequent decline curves tend to be much flatter, but the reality is that of the overall production in an unconventional play, that hyperbolic decline is the part that needs to be replaced by new production, which in turn is declining from the day it goes on line.
Any hiccup in the system, an interruption in drilling, and the decline will look worse as those wells come into production maturity, reaching the flatter portion of their decline curves, then overall production will level out below the maximum, reduced by that first phase reduction from IP times the number of wells which fall into that age bracket. The Bakken Boom, limited by infrastructure, maxxed out at roughly 220 rigs, drilling as many as 10 wells annually each, which left a maximum of some 4000 or so wells in that first production phase of high decline (fewer actually, because frac crews were struggling to keep up, and without the takeaway capacity completing a well not needed to hold the lease and producing that oil at discounts of up to $30/bbl made little sense if the cash flow wasn't needed immediately.
There are some 500 or so rigs in the Permian, which means the number of wells which would fall into the initial phase is multiples of that in the Bakken, so any decline in drilling/completions will show up as a relatively sudden drop in production for the region, amplified by the sheer number of wells involved.
It all depends on the IP as well, where that 14% decline takes you, but those numbers suggest smaller reservoir compartments overall, which are poorly connected. I'm not sure how well a frac can overcome that.
I suspect discounts applied due to takeaway capacity limitations and shipping expenses will impact profits in the region as well--we saw much the same here, even as rail terminals were being built and the DAPL was being constructed. The Obama Administration's stonewalling on the Keystone XL project did not help, either, although the estimated takeaway added would have been only 100K BOPD or so.
