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Page added on October 30, 2013
The Peak Oil Crisis: The Shale Oil Bubble
Most of us are aware by now that the introduction of widespread hydraulic fracturing into the oil and gas business has resulted in a rapid growth in U.S. production. U.S. crude output is up by nearly 2.5 million barrels a day (b/d) since mid-2007 and natural gas production is up by 25 percent. The key question of course is how long production will continue to grow before it inevitably declines. Optimists maintain that we have just scratched the surface of our shale oil reserves and that production will continue increasing for years, if not decades.
Realists are not so sure, noting that not only is fracked oil very expensive, requiring circa $80 a barrel to cover the costs of extraction, but that production from fracked oil wells drops off quickly so that new wells have to be drilled constantly to maintain production. Until recently information about just how fast our fracked oil wells were depleting was rather hard to come by, so that the hype about the US becoming energy independent and a major oil exporter became conventional wisdom for most.
Last week the US’s Energy Information Administration issued the first in a new series entitled Drilling Productivity Report- For key tight oil and shale gas regions. This report analyzes the six onshore oil and gas regions in the U.S. where 90 percent of the growth in oil production and nearly all of the growth in natural gas production has taken place in the last few years. The report tallies the number of drilling rigs at work in these six regions; the amount of new oil and gas they are bringing into production each month; and most importantly the rate at which production from those wells already in production is falling.
Nearly all of the growth in U.S. onshore crude production these days is coming from North Dakota’s Bakken field and Texas’s Eagle Ford. They account for nearly 2 million of the 2.4 million b/d increase in oil production that the US has seen in recent years. North Dakota publishes detailed data on its oil industry, and from this we learn that the state now has about 9,600 producing oil wells each of which is producing about 100 b/d.
The 183 rigs currently drilling in the Bakken formation are bringing an average of 150 new wells per month into production or about 1,800 per year. Efficient use of these rigs is improving so that the 183 rigs currently active are drilling nearly as many new wells as the 220 that were drilling in the spring of 2012.
There are two key questions which will determine how much longer these shale oil plays will continue growing. One is how many economically viable sites are left to drill; and how long it will it be before production from the 10,000 or wells already pumping in the Bakken will fall to the place where the 150 or so new wells coming into production each month will not be enough to keep total production growing.
While not making a forecast as to when production will peak in the shale fields, the EIA, however, does make a projection as to what will happen in November 2013, not a particularly bold prediction but at least it is something. According to the EIA report, what it terms the decline in “legacy oil production” (i.e. those wells that have been producing for more than a month) for the Bakken field is now at 60,000. The Texas’s Eagle Ford field’s production is now declining at 80,000 b/d and the no longer growing Permian Field is declining at 34,000 b/d.
Winter in North Dakota can be rather harsh and we have already had some snow up there, so bringing new wells into production in the next few months can be difficult. Last winter the number of new wells coming on stream was closer to 100 per month rather than the 200 or so during better weather. In South Texas bad weather is not much of a problem, but the availability of fracking water is.
Anyway the EIA is forecasting that in November the Bakken Shale will bring 86,000 new barrels per day into production for a net gain of 26,000 b/d by the end of the month. In the Eagle Ford shale 105,000 b/d of new production is forecast to come on stream for a net gain of 24,000 b/d or 50,000 b/d for the two oil fields. The other four shale oil fields should have negligible increases in production.
This of course raises the important question of what will be the state of our shale oil production by December of 2014 and during the following year. Remember the number of producing wells in North Dakota is increasing at about 1,800 a year and even more down in Texas.
In looking at the steep decline in production from legacy wells in the Bakken and Eagle Ford shales, decline between November 2012 and November 2013 increased from 44,000 b/d to 60,000 b/d and from 54,000 b/d to 78,000 b/d respectively. Given that there will be another 4,000 or so legacy wells in production by this time next year the decline going on by this time next year is certain to be considerably greater.
While the EIA does not seem willing to make a forecast, it sure looks as if the increase in production for these two fields will be unlikely to keep up with the rate of decline within the next 12 to 18 months and that US shale oil production will no longer be growing.
While it is possible that a surge of investment will increase the drilling to keep up with declines in production from the older wells, this is expensive, and for now it looks as if oil prices are heading for a level where fracked oil production is not profitable. Outside geologists with access to proprietary data on decline rates have been forecasting for some time now that as the number wells increases and their quality declines, the shale boom will be coming to an end in the next two years. The release of EIA data seems to confirm these predictions.
5 Comments on "The Peak Oil Crisis: The Shale Oil Bubble"
rockman on Wed, 30th Oct 2013 8:59 pm
“Until recently information about just how fast our fracked oil wells were depleting was rather hard to come by, so that the hype about the US becoming energy independent and a major oil exporter became conventional wisdom for most.” As far as the Eagle Ford Shale goes that’s completely erroneous. The monthly production from every lease producing EFS lease is available for free from the Texas Rail Road Commission. A little inconvenient but there for the asking. But for about $2000/yr one can get a subscription to Drilling Info and download every bit of the details in an Excel spreadsheet and plot the decline rates to your heart’s content.
“Outside geologists with access to proprietary data on decline rates have been forecasting for some time now that as the number wells increases and their quality declines, the shale boom will be coming to an end in the next two years.” Not a very brave prediction given this has been the path of every oil trend ever developed since the dawn of the petroleum age. And since they don’t define exactly what constitutes a “boom” it’s a tad difficult to define it’s end. Again, none of the data necessary to predict the future declines is proprietary. I see such statements as pure BS to give the appearance that some great cover up has been exposed. The production profile of fractured reservoirs was well established decades ago. The future high decline rates of the EFS wells was very predictable before the “boom” started. All it would have taken is a one hour Internet search.
For recent confirmation just search for the Austin Chalk in Texas. It was horizontally drilled and frac’d in the 90’s and was the hottest oil play on the planet at the time. The AC play covered a much larger area than the EFS but not much is written about it today. And for good reason: just like every previous hot play (as well as all the current hot plays) eventually they get drilled up for the most part. The Bakken and EFS will continue to be developed (as long as oil prices hold) but only as long as viable locations remain. But there’s a finite number of locations so these plays will die and do so with the same well established production profile of the AC and every other fractured reservoir play in history.
This report is far from being the great landmark expose they would like us to believe.
Feemer on Wed, 30th Oct 2013 11:58 pm
I believe that by the end of 2014, beginning of 2015, The fracking boom will have ended and will have started to go into terminal decline. I laugh at people who say the US will be energy independent. Something I am more worried about though is that many natural gas plants are being built and replacing coal plants. Obviously it makes sense because NG is so cheap, and the free market is doing this, but when this boom ends in 2015 or so, and natural gas becomes much more expensive, there could be power shortages, because coal plants have been replaced by NG plants. Now i’m no fan of coal, but the end to this boom could affect electricity, not just crude oil or natural gas.
Cave Bio on Thu, 31st Oct 2013 1:55 am
I have heard that nat. gas wells flow much better (less of a decline rate, with wells flowing for a longer period of time) than fracked oil wells. The (logical) explanation is that nat. gas is a much smaller molecule.
If this is true then I would expect the nat. gas fracking “revolution” to last longer than oil.
Any thoughts?
Best,
Tom
rockman on Thu, 31st Oct 2013 1:44 pm
Cave Bio – It has a bit to do with molecular size but much more about pressure. A short and incomplete explanation: the oil or NG flows out of the reservoir based upon the pressure difference between it at atmospheric pressure. Simple enough but now complicate it with the weight of the production in the casing. A string of production tubing is filled with, let’s say, an 8,000’ column of oil weighing X pounds. That weight exerts a back pressure on the reservoir. Nearly all fracture plays are pressure depletion drive; as the well produces the formation pressure decrease. Once it drops below the weight (the “head”) of the oil in the column flow no longer comes out of the reservoir and the well dies. But we have a variety of “lift systems” we use to reduce the head and allow the reservoir flow. No doubt you’ve seen pictures of pump jacks. They are one a number of methods. But lifting costs money and eventually the cost is too high to sustain production even when oil could still be produced.
Easy to imagine that an 8,000’ column of pure methane weighs considerable less than the same column of oil. But some reservoirs do produce a bit of oil with the NG but we’ll skip that detail. So with a much smaller head the NG doesn’t exert as high back pressure on the reservoir and production can continue for a long time. But eventually the declining pressure poses another economic challenge: line pressure. The production has to flow into a pipeline to reach the market. That line pressure may be 600 psi. As the wellhead pressure decrease so does the ability for the well to flow into the p/l. When the well head pressure reaches 600 psi all flow stops. Then, if the economics work, we put a NG compressor on the well. It will usually be fueled by some of the produced NG. Thus the NG pressure is increased and flow continues. But again only until the net income is positive.
There are a little more details and variations. There are also a few unusual reservoirs like the New Albany Shale in KY and elsewhere. The NG is held in organic molecules in the rock and as pressure is reduced those molecules become unstable and release the NG. The good news: these wells can produce for decades with virtually no decline. The bad news: they produce at a very low rate: maybe just $150/day. The NAS was the first commercial NG in the country and was fueling street lights at the beginning of the 1900’s.
rockman on Thu, 31st Oct 2013 1:50 pm
CB – Forgot to mention the most important factor: price. The shale gas revolution ended in late ’08 when NG prices collapsed and the rig rate drilling those wells dropped almost 80%. There’s still activity in such plays as the Marcellus but it ain’t much of a revolution these days. And when NG prices increase above $6-$8 per mcf we’ll see a lot more activity. Just as if oil prices were to drop a good bit we would see the end of the oil shale revolution.
The only revolution we’ve seen is in the pricing of oil/NG. Everything else has just been a response to those changes.