A reader sent me an article by Cumberland Advisors suggesting that investors were underestimating the power of America's oil and natural gas industry revolution. Hat tip to Barry.
While I agree with some of their comments there are still some reasons why we should not forget about peak oil. Link to Cumberland article
I do agree that the shale oil boom has revolutionized the production of oil within the USA. It has pushed production from 4.8 mbpd in January 2005 to 8.1 mbpd in Jan 2014. That is the highest production rate since 1988.
However, the shale oil revolution is set to fade over the next three years. The problem is the same problem every well ever drilled has experienced. When a well is drilled there is a set amount of oil in the ground under the well. Let's call it 1,000,000 barrels as an example. In practice some wells can extract 100,000 barrels and some can extract 500,000 barrels with most wells somewhere in the middle. The different extraction rates are based on the thickness of the oil, the amount of pressure in the well and the permeability of the rock.
If there is no pressure then pumps have to be installed to create a suction and pull the oil out of the ground. If the oil is thick then it flows much more slowly and the pumps have to work harder and longer. The permeability of the rock is the key element. That means the rock must be porous for the oil to flow underground. Shale is not porous and that is what kept exploration companies from drilling wells into shale for decades. When horizontal drilling was perfected this solved some of the problem since instead of just punching through a 100 foot section of oil play and trying to get a few hundred barrels to the surface they could now drill down to that oil play and then drill horizontally for up to two miles through that 100 foot deep pay zone. Instead of only being exposed to 100 feet of pay now they can be exposed to 10,000 feet of pay. Even if the oil flows slowly through the rock the vast distance of the laterals allows enhanced recovery.
Since shale is not really porous they have to fracture the rock all around the pipe in order to give the oil a way to flow. This is done by pumping in millions of gallons of water and sand under extreme pressure. This forces cracks in the shale and the sand sticks in the cracks to keep them open.
These wells are not cheap. Continental Resources spends about $7 million a well in the Bakken and $9.5 to $10 million in the Cana-Woodford shale (SCOOP) in Oklahoma because the wells are deeper. That means they have to recover a lot of oil to make the well profitable. They have to recover 150,000 barrels from each well to breakeven. If the field does not have enough initial production flows to get over that hump they will not drill. The profit does not begin until after the first 150,000 barrels.
A well that comes in at say 1,000 bpd to start can lose 65% of its production rate in the first 30 days. Over the first six months that declines another 65% and so on. By the end of the first year they are lucky to be producing 150 bpd in some wells. This is called depletion.
I have written on the depletion rate of shale wells several times in these pages. Shale wells deplete faster than almost any conventional well simply because the oil cannot flow underground except where the fracking has created cracks next to the well bore.
The EIA tracks this depletion in the six major shale production areas. In the chart below it shows the depletion rate for wells in each of those shale areas. The light brown bars are the decline rates in Feb 2013. The dark brown bars are expectations for Feb 2014. These are for legacy wells over 1 year old and not for new production.
For instance the legacy wells in the Eagle Ford declined -64,000 bpd between January 2013 and February 2013. They expect that to decline another -70,000 bpd between January 2014 and February 2014. Now to put that into numbers everyone can understand that means that every month the production in the Eagle Ford will decline -70,000 bpd in 2014. That means in order to increase net production they have to add new wells with more than 70,000 bpd in new production, EVERY month. Right now they are doing that.
The chart below shows the amount of net new production in those same fields. Note that the new production in dark brown is increasing at a slower rate than in 2013. This is because every month there are more wells declining at an accelerating rate. For instance all the wells drilled since Feb 2013 are now in their decline cycle in addition to the ones drilled before 2013.
Using the Eagle Ford data they are increasing production by roughly 34,000 bpd per month compared to 50,000 bpd in 2013. The wells in the sweet spots have been drilled and the new wells are not producing enough initial production to keep the net production rising at a faster rate.
The EIA data shows that new well production per rig is rising over the 2013 rate. The reason is better fracking procedures and longer laterals. Producers are being forced to spend more money per well to boost those initial production values.
In February 2014 the EIA expects the average new well in the Eagle Ford to produce roughly 400 bpd. At that rate it would take 375 days for the well to become profitable and that assumes no depletion from that 400 bpd rate. While the EIA does not specifically say it I believe that 400 bpd rate is an average for the month. That takes into account the 1000-1500 bpd initial rate for many wells plus the very high initial decline rate over the first month. Obviously there would be a lot fewer commercially successful wells if the initial rate was 400 bpd.
To put this in perspective Baker Hughes said we drilled 9,175 wells in Q3. That equates to 102 wells per day. Obviously that is all over the continental U.S. and not just in the Eagle Ford. The Texas Railroad Commission said there were 4,416 drilling permits issued in the Eagle Ford in 2013. If we do the math that is an average of 368 permits per month. While there is a difference between a permit and a well we are going to assume that over the long term that equated to 368 wells per month on average.
In the chart below showing total oil production from the various plays the Eagle Ford is expected to produce just over 1.2 mbpd in February. That is an increase of roughly 400,000 bpd over the last year. That would be great if we could maintain that rate. However, the EIA expects it to peak at 1.5 mbpd in 2015.
Using the data from the charts above we know that depletion was -70,000 bpd. Net new production was roughly 32,000 bpd. In order to get net new production we have to first replace that -70,000 bpd in depletion. That means production was rising roughly 102,000 bpd on a monthly basis. That means the 368 new wells per month had to produce an average of 277 bpd for the first month and the EIA is saying it was closer to 400 bpd so allowing for variations in the numbers, weather, wells drilled, unscheduled downtime, etc it appears we are right on track.
Where am I going with all this data? First, there are only so many undrilled locations in the "fairway" or sweet spot in each shale play. Once these are drilled the number of new wells will drop dramatically. Producers will be thinking a lot harder about spending $7-$10 million a well and possibly not getting their money back. So by the end of 2015 at the current rate of drilling there will be 73,400 new wells in the USA.
That sounds like a tremendous amount but remember every well previously drilled is declining in production every day. We have to continue to drill thousands of wells per month just to keep the net new production rising over the prior month. At some point when the sweet spots are gone the producers will not be able to keep up with the decline rate and production will peak.
Using the numbers above and assuming that we drilled about 9,000 wells per quarter for the last four years there will be roughly 180,000 shale wells in production and already well past their production prime. Most will be pumping only a fraction of their initial rate and thousands will have already been abandoned. How many new wells would we have to drill to offset depletion from 180,000 legacy wells? The answer is far more than our present 9,000 per quarter only the prime drilling locations will have been exhausted.
Here are the same charts for shale gas production.
Note that the Marcellus is the ONLY shale gas field to increase production over January.
Note that while the Haynesville and Niobrara are still adding strong production per new well the total production for the field is already in decline per the above chart.
Total gas production compared to February 2013.
In prior articles I pointed out that the Eagle Ford was expected to peak in 2015 as the number of prime well locations were exhausted and the number of depleting wells were increasing.
In past articles I pointed out the very steep decline curve on shale wells. This is the chart for the Bakken but they all look the same.
What I think the nice people at Cumberland Advisors have failed to consider is the sheer volume of legacy wells and the decline rates for those wells. The shale boom has been historic but it will end. While the Bakken and Eagle Ford are expected to peak in 2015-2017 there are new shale fields coming online. The Cline shale, the Cana-Woodford shale, etc. Whether these can provide enough initial production to offset the accelerating decline curves in the mounting number of legacy well remains to be seen but I seriously doubt it.
The market collapsed last week on the meltdown in emerging markets. Futures are up slightly as of late Sunday night but there is still a lot of darkness before morning.
The market took a serious hit to sentiment but it is only down -3% overall so no harm was really done. If we rebound this week then the -318 point Dow decline will be quickly forgotten. If we go on to set new lows on Monday I would look for an extended decline. However, the FOMC meeting on Tue/Wed could distract traders and give them a reason to be optimistic.
After the big decline Monday will be margin call day. Even if we open higher there will be a very large number of traders that will be facing margin calls and they will have to sell something to create liquidity in their margin account. This could weigh on the market on Monday and make Tuesday the potential rebound day.
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