U.S tight oil production from shale plays will fall more quickly than most assume.
Why? High decline rates from shale reservoirs is given. The more interesting reasons are the compounding effects of pad drilling on rig count and poorer average well performance with time.
Rig productivity has increased but average well productivity has decreased. Every rig used in pad drilling has approximately three times the impact on the daily production rate as a rig did before pad drilling. At the same time, average well productivity has decreased by about one-third.
This means that production rates will fall at a much higher rate today than during previous periods of falling rig counts.
Most shale wells today are drilled from pads. One rig drills many wells from the same surface location, as shown in the diagram below
The Eagle Ford Shale play in South Texas is one of the major contributors to increased U.S. oil production. A few charts from the Eagle Ford play will demonstrate why I believe that U.S. production will fall sooner and more sharply than many analysts predict. Related: Why The World Needs Both Shale And Tar Sands
The first chart shows that the number of active drilling rigs (left-hand scale) in the Eagle Ford Shale play stabilized at approximately 200 rigs as pad drilling became common. The number of producing wells (lower scale), however, has continued to increase. This is because a single rig can drill many wells without taking the time to demobilize and remobilize. In other words, drilling has become more efficient as less time is needed to drill a greater number of wells.
The next chart below shows Eagle Ford oil production, the number of producing wells and the number of active drilling rigs versus time.
This chart shows that production growth has not kept pace with the rate of increase in new producing wells since mid-2012. That is because the performance of newer wells is not as good as earlier wells. Related: A Word Of Warning About EIA Forecasts
The final chart shows that the rate of daily production is now more dependent on the number of drilling rigs than on the number of producing wells. Rig productivity--the barrels per day per rig--has increased but average well productivity--the barrels per day per well--has decreased. In other words, production can only be maintained by drilling an ever-increasing number of wells.
Average rig productivity has almost tripled since early 2012. Average well productivity has decreased by one-third over the same period. This means that every rig taken out of service today has more than three times the impact on daily production as before pad drilling became common.
Most experts do not anticipate any significant decrease in U.S. tight oil production in the first half of 2015. Their analyses may not have accounted for the effect of pad drilling and the decrease in average well productivity.
Using the Eagle Ford Shale as an example, U.S. oil production should fall sooner and more sharply than many anticipate. This will be a good thing for oil price recovery but maybe not such a good thing for the future profitability of the plays.
By Arthur E. Berman for Oilprice.com
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It seems that there is no one with the outright verdict of where this business is headed.
The figures are freely available from the EIA, and it demonstrates well productivity is pathetic in both Bakken and Eagle ford. It is as the guy suggested the number of wells that keeps it going. With decline rates around 65-70pc in first year and decline rates increasing in 2nd and third years and most oil companies hiding behind half cycle figures. There will be a lot of pain in the U.S. shale industry, but then it was only ever a last chance saloon, as the bigger U.S. oil players have always said.
Even without the oil price being slashed shale was only ever going to peak in 2016 or earlier, and with that allied to the decline rates and having drilled out the sweet spots, declines would be very fast, with resulting legacy wells after 3 years being no more than marginal stripper wells
Are you seriously asserting that wells do not deplete?
Or are you saying that new wells produce the same as old wells?
Neither statement is a positive to your credibility.
The data shown above clearly illustrates the average barrels per day falling from a peak of 180 to 120 - which is to say, that the best shale exploitation sites are largely already tapped, at least in the Eagle Ford. This in turn means that production increases are largely a function of ongoing rig activity - and there's no debate at all that rig activity is dropping off.
richtfan is correct. "Fracking" is simply an evolution of drilling techniques that has occurred over decades and it continues to evolve. Drillers continue to share successful approaches, are utilizing big data, improved technology, and hard-working American workers to get more oil out of the ground.
Depending on the price of oil, some more rigs will shut down and shale production will suffer but to say it may "end" is just absurd. Fracking has created a permanent "ceiling" on the price of oil protecting us from OPEC, which is now a paper tiger.
However, I dispute we've seen the end of even the US. I'm not sure what Barton thinks he's proving. Everyone knows that shale wells have steep decline curves; however, they're largely offset by initial production rates that are not even in the same ballpark as most traditionally drilled vertical wells. This has always been a characteristic of the shale revolution. The data Barton is showing speak less to the demise of shale reservoirs and more to the efficiency of pad drilling. Because we are able to drill multiple wells from a single pad, a significant drop in rig count (which we're seeing in capital spending announcements) would logically lead to a sharp reduction in production. I agree with the assertion that this will be good for WTI pricing.
I would also advise Barton to take a slightly longer-term view of the world -- particularly with regard to technology. There are still tremendous hydrocarbon reserves that we know about, yet we still can't access them for various reasons -- simply because the technology isn't there yet. However, it will be. If we have learned nothing else from the shale revolution, we should take careful note of this fact: the technology will evolve and advance and allow for new horizons in the exploitation of reservoirs.
It makes me laugh when people predict the demise of US shale; it's a bit like a six-year-old saying he knows all there is to learn.
Finally, let's not forget that, even with current technology, new plays are being discovered every day and virgin reservoirs abound ... they are just yet to be found.
Too many wells in the same area causes a decrease in output per well is what I think the author is describing.
It stands to reason that the decrease in the price of oil will lessen the number of rigs operating and may cause the production per well numbers to rise again.
A simple drilling and production model will show that, because of the precipitous decline rate, each rig, depending on drilling pace and initial well productivity, has a plateau production rate for all of the wells it drills. Modeling suggests that this is between 17,000 bopd and 6,000 bopd per rig for one month and three month completion rates per well respectively and 1,000 bopd IP and 70% decline in the first year. Shorter cycle times, higher IP and lower decline rates will increase this plateau production rate per rig. Inputs and your mileage may vary.
North Dakota's Oil and Gas Commission suggests that about 230 rigs are necessary to sustain the current production rate but that no more than 198 rig have been drilling at one time. Current production of 1.2 mmbopd corresponds to a production rate of about 5,600 bopd per rig.... not far from the 3 month per well pace plateau production of the model.
The model also shows that 11 to 18 months after a rig stops drilling the production from the string of wells that it drilled will fall by 50%. Sooner for the lower production plateau.
It may take a year but probably less for the negative production impact of laying down rigs to show up.
We showed a deal to a real estate investor from Fort Worth a few years ago. He had a lot of acreage with minerals in the Barnett. He said he was looking for deals to roll his falling royalty cash flow stream into that didn't produce the source rock.... meaning shale because the shale cash flow stream did not have any legs on it. So it has been, so it is and so it will be.
Additionally, I'm not sure if efficiencies of pad drilling can be show in time. When a pad is drilled over months the first well will likely wait over 30 days to be completed. I don't have the data, but I'd be willing to bet the volume of wells waiting for completion are significantly greater than just 2 years ago.
Moreover as others above have pointed out, fracturing and horizontal wells are in their infancy. Wells used to come online and roar up the casing and would be lightly restricted. A lot of companies are choking their wells immediately now thus restricting flow immensely.. Allowing the well to flow hard and with little restriction allows the fracturing treatment and stimulation to come unraveled. The fluid velocity and formation pressure applied on the fractured zones pulls the proppant from the stimulated areas effectively closing the producing zone from the wellbore.
You have to look at individual well performance over a 3, 6, 12, 18 month period with respect to pad drilling. If you do that to say EOG, Statoil, and Whiting Oil and Gas in the Bakken region I think you'll find their new wells are producing significantly better than earlier wells, but have lower IP rates. Admittedly completion designs and techniques have improved. However, pad drilling is nothing new to the above mentioned.
I'm not an experienced oilman or an engineer. I have been on well sites and I talk to company men and pumpers during my day. I'm also privy to well data for certain operators and I see productions numbers. There are hundreds of wells over 5 years old now steadily producing 50-90 bbps a day. Some make only 20-30 or maybe the occasional dud of 10. There's a few wells that are 3-4 years old and still have no Pumping unit on them.
I wouldn't discount shale or bet on its abrupt downfall unless I really knew what I was talking about.
Furthermore, if rigs have accelerated drilling time and drilling more feet/day than before, it certainly doesn't mean completions are keeping pace with that drilling efficiency. No new completions, no new production.
Since adding my comment last night I looked at some IP stats for EOG in the Bakken (largest lease holder in the EF oil window). They brought three pad wells online in August 2014. The avg. daily production was outpaced by the IP rate for 90 days. In the first 90 days of production you have to also account for work over treatment. During fracturing stimulation plugs are set in the lateral. A drill out or clean out of the lateral is required. This interrupts production slightly. Additionally, wells are being plugged as adjacent wells are stimulated. It may just require a wireline truck to plug the well but most companies will unplug with a rig to retrieve the plug and assemble a production string. This all takes time to happen so wells may be unable to produce for weeks. The more densely populated the field (aka pad drilling) the more new wells need to be plugged off during fracturing stimulation of adjacent wells.
So many above are using absolute adjectives to describe this data while showing a complete lack of understanding of oil and gas production. Yes, shale wells decline sharply, but the tail is long and steady and compares to long run production of conventional wells. And also pointed out above, shale wells come online with IP's much higher than most conventional wells. At best the above is pure speculation on a new trend from data, but no solid inferences can be made at this time. I would say the speculation also comes from an uneducated position in oil and gas production. Or at least the dynamics of pad drilling. Hopefully no one making the above comments is managing my 401k fund.
The evidence is in the September 30th SEC filings. I looked at 27 mid to small producers' filings and also reviewed filings for most of the international producers.
Virtually none of the mid-to-small companies had any held cash reserves and receivables beyond near-term creditor requirements. If they couldn't even generate enough cash during a period of peak oil prices and close to peak production then how is this a good business?
Some did not report profits even for a period when WTI averaged over $90 per barrel. Deducting 'profits' on future price hedging to get at genuine Q3 results makes the picture much worse. A number even had accumulated losses rather than profit reserves.
Retained Property, Plant and Equipment balances averaged around ten years at current depreciation rates even though, on average, wells have 80-90% production decline rates after three years. This looks incredibly optimistic and largely explains the anomaly between apparent profit and absence of cash build.
Drilling costs were heavily debt financed with most companies already carrying heavy debt burdens by 30 Sept. Sub-prime bonds are no longer available, so how long will reserves based lenders keep financing them?
None of the international producers carried any significant price hedging for 2015. Amongst the mid-small producers, price hedging averaged 33% of projected 2015 production though a proportion of this is three-way collars which offer a maximum cover below $15 per barrel and even the full hedges are below Q3 average price levels so not much income protection there.
This looks like a poor business even at $90-100 WTI.
A surge of subprime debt in excess of $200 billion has lead to a culture of chasing production without regard to economics. Funds for future drilling will be drying up much faster than the market has understood and existing production declines at an average 10% per quarter or more across the whole shale oil sector without new wells coming on. It probably takes at least 1,250 new wells per quarter just to maintain overall production.
The industry's challenge is to make this a good business at say $75 WTI. It was nowhere near that up to Q3 2014 and it will take much better financial management and operational honesty to achieve that.
That means better balance of financing between operating cashflow, debt and equity. It also means respecting rather than ignoring economics.
I reckon that it can be done and we could see decent ongoing shale oil production for years to come but at significantly lower daily rates than we have seen recently.
That means we still have a great resource to enjoy for a decade or two. Just as soon as someone tells the company promoters and their co-conspirators in the financial markets to stop talking rubbish about healthy IRRs at WTI as low as $50and start running their operations properly.
The problem with US shale oil isn't WTI at $50 it's WTI at $100.
$50 just isn't going to stay for long but if the industry can't admit that it wasn't going well at $100 then it isn't going to sort out its problems and then they are going to see a whole lot of bond defaults, and bankruptcies.