A week can hardly pass without hearing about the onshore U.S. oil boom. While there are plenty of reserves to be developed through unconventional means, expectations for long-term shale oil growth may be too high. Some facts seem to indicate future production gains might be more difficult than currently anticipated. If that's the case, investors holding optimistically priced oil and gas producers could be unpleasantly surprised. Don't believe there's a risk? Let's take a look.
Two main hindrances for future shale growth
There are two main headwinds for future shale oil production growth; low well amounts currently delivered and steep depletion rates. A relatively small amount of oil produced per well means that increasing the number of wells has to be a method of replenishing lost production. Rapid oil reservoir depletion, when the production rate of a well drops significantly and quickly, means that additional wells will be needed sooner and more often to maintain delivery levels.
A relationship between three data points is helpful in judging how strong these headwinds might be. Initial well production rates (basically the amount produced on the first day a well comes in), the 30-day rate (average production after 30 days), and the long-term production rate (a figure that is rarely reported but is helpful in estimating depletion). In general, the lower the figures, absolutely and relatively, the tougher it will be to achieve meaningful long-term growth. Three main shale plays provides some relevant information.
A copious oil region: The Eagle Ford
The Eagle Ford shale might be the country's most prolific shale oil play. Located in South Texas, it has been described as a "borderline carbonate reservoir." This means that it is not a typical shale formation but its oil is easier to recover than most. EOG Resources is the major player in the Eagle Ford, discovering it in 2010 and being the largest leaseholder.
In the latest quarter, EOG reported that, in one region of the Eagle Ford, wells came in with initial production rates ranging from 1,830 to 2,050 barrels of crude oil equivalent per day. In a more fertile area, higher initial rates ranged from 2,990 to 7,515 Boepd. The company also reported that its best well to date, the Burrow Unit #5H, had an average production rate of 4,265 Boepd, or about 57% of its initial rate, after 30 days.
There are a few takeaways from these developments. Though the Eagle Ford is abundant on a shale oil basis, it's not hugely so on an industry basis. For example BP's Macondo well, the one involved in the Gulf of Mexico disaster, was flowing around 50,000 Boepd. EOG's data also indicates that well production can vary tremendously by area. Assuming that producers look to the easiest and most accomplished targets first, that could have future negative production ramifications. Also, though longer depletion rates weren't provided, the 30-day rate at 57% of initial production could be a helpful benchmark.
Another key shale region: The Bakken
Data from EOG's Bakken projects supplies further shale insight. The Bakken, with drilling mostly located in North Dakota, is one of the most important sources of oil in the United States.
In its most recent quarter, EOG reported Bakken results with initial production between 2,120 and 2,685 Boepd. What's interesting is that these amounts were aided by 160-acre well spacing. To make wells more productive, getting more oil out quicker and cheaper, EOG proposed moving wells from being spaced at 320-acres to a closer spread. While this increases current production, the technique might also deplete reservoirs faster.
Continental Resources , the largest leaseholder and producer in the Bakken, provides additional information. It reported wells recently completed in North Dakota averaged initial one-day tests of 1,150 Boepd, much lower than EOG's performance. This might be due to well placement. The company is only now starting to test 320-acre and 160-acre spacing.
Continental's attempt to drive down costs by the use of multiple well drilling pads increases depletion worries. Pad drilling, basically drilling multiple wells in differing horizontal directions from one rig location, produces more in a shorter time, but it might also exhaust whatever resources are in that location quicker.
A recent encouraging play: The Spraberry-Wolfcamp
While the Bakken's potential has been known for a while, a more recent hope is the Spraberry-Wolfcamp region, a play in the Permian Basin of West Central Texas.
Pioneer Natural Resources is the largest acreage holder in the area and has reported some drilling results. In its latest quarter, new wells had a 24-hour peak initial production rate of between 1,572 and 1,712 Boepd and peak 30-day averages of 1,040 to 1,107 Boepd, or a respectable 65% of initial levels. The company's DL Hutt C #1H well, its best horizontal well so far, had an initial 24-hour peak production rate of 1,693 Boepd and an average peak 30-day rate of 1,402 Boepd or an impressive 83% of the first day.
Realizing there have been an awful lot of numbers presented, they do hint at a serious consideration for investors, however. Relatively low and noticeably declining well production could mean that shale oil producers will have to continually find and develop new reserves not just to meet growth expectations but to eventually maintain production levels. Especially when initial wells start to meaningfully deteriorate. While the figures provided aren't necessarily conclusive, they do suggest that longer-term investors might want to at least contemplate potential future growth difficulties before committing to a shale oil stock.
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The article A Long-Term Risk for Shale Oil Stocks originally appeared on Fool.com.Bob Chandler has a short position in Continental Resources. The Motley Fool owns shares of EOG Resources. Try any of our Foolish newsletter services free for 30 days. We Fools may not all hold the same opinions, but we all believe that considering a diverse range of insights makes us better investors. The Motley Fool has a disclosure policy.
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