I doubt that this will ever reach the levels of public interest that has led earlier exposures of information to acquire a “gate” appendage, but the New York Times (NYT) has begun a running series of articles, starting this weekend, on e-mails that they have acquired that largely deal with the gas shale business. In the discussion on Focus today, it was the first topic of conversation, and so I thought I would write about what the fuss is about. Not, I should hasten to add, that any of this should come as a surprise to you gentle readers, since many of the “revelations” have been covered here in the past.
There is a considerable body of literature that tends to look at future supplies of natural gas, particularly from shales, through very optimistic lenses. This includes reports from such agencies as the EIA and the IEA that suggest that the world is entering the “Golden Age of Natural Gas.” Recent discoveries and projections have led to estimates that the world will be afloat on natural gas for the foreseeable future, as many countries have natural gas tied to shale layers, and American success in developing these deposits could lead to similar success in other countries, providing large volumes of indigenous fuel, at potentially low cost. Unfortunately, as those who have read my posts here know, much of this is over-inflated and not going to happen. While I discussed the problems with the EIA report back in April (haven’t got round to writing on the IEA report yet,) the fundamental points remain valid. The point brought out by the NYT is that the concerns that I have written about are also prevalent within the industry itself, even while it seeks to draw investors into putting up money to drill more wells. And in that activity, as the articles note, industry has been very successful.
If I can re-iterate some of the concerns, they begin with the cost of the drilling and completion operation. Both parts of this are expensive, the initial cost to drill a vertical well, and then turn it horizontal and run it out thousands of feet within the shale costs millions of dollars, as then does the subsequent series of events that includes fracturing the horizontal well a number (perhaps 30) times and using expensive suspension fluids to force small particles into those cracks so as to prop them open and allow gas to migrate from the rock into the well. The costs as a rough initial marker, run around $5 million dollars per well, though they can go considerably higher.
This sort of investment requires a significant return on investment, and in the best wells initial flow rates of over 10 million cubic feet per day can be achieved. However, as the industry has long known, but likely not the general public, those wells are proving to drop in production very quickly. As I quoted back in that earlier piece:
The Day Kimball Hill #A1 is located in Southeast Tarrant County, Texas, and produced an average of 12.97 million cubic feet of natural gas per day in October 2009. Since shale gas wells decline sharply during the first few years, this Barnett Shale well has seen its production fall to 8.66 million cubic feet in November and 6.79 million in December.
The initial high yields from these wells fall by as much as 85% in the first year, and while this may still make the producers such as the Day Kimball profitable, that was the most successful well Chesapeake had drilled until then. For the less successful payback is lower and may not cover costs.
Part of the problem comes in that the companies seeking investors suggest that the wells will continue to produce for up to 50 years. I would not deny that were the wells to remain open that long that some gas would be still coming out of the wells at the end of that period. However natural gas is a lot less valuable cubic inch for cubic inch than oil, and whereas a simple pump can raise a fractional barrel of oil a day and be profitable, this is much harder to do with a marginal gas producer.
The reason for this is that, unlike oil and coal, natural gas is usually carried (after cleaning to remove water oil and any other contaminants) through a pipeline that often runs (via additional pumps) directly to the customer. They, in turn, don’t usually store it, but burn it as needed, drawing the supply straight from the pipe. The problem that this gives the marginal producer is that the gas in the line must be at a certain pressure if it is to move down that pipe to the customer, and then come out of the nozzles at sufficient flow to be useful. That pressure has to be achieved, at the well once the natural pressure of the gas in the well has fallen over time and production, with a compressor, which cost money to install, run and maintain. At a certain point in the well life the gas being produced falls below the point at which it becomes economic to pay for that compressor (which is only a part of the total costs that an operating well will incur). It may even be (at the rates of decline being seen in many current wells) that the decline is so swift that as soon as the natural pressure falls below that needed for the pipeline, that the well closes and a compressor is never economical. In these cases the well life may well only be three or four years, rather than the fifty of the company model.
There is another concern that the NYT articles raise, and that deals with the change in reserve estimates that are now being made for new wells. I commented on this back when the changes were made in January 2009. To simplify the explanation of the changes before then a company had to physically prove that it had the reserve, and the volume over which it could estimate that the reserve existed was restricted to a relatively short distance from the validation point (usually a well). Investors thus had some degree of certainty about the size of the reserve that they were investing in. (And those who followed the reality Coal series on Spike this season will have seen how the geology changes rapidly, having an immediate impact on production in even a short distance underground - thereby illustrating why the original rules were realistic as a way of protecting the investor).
The change removed the requirement for physical proof, and allowed the company to make an estimate based on the geological data, as established remotely, and without the need for physical validation. As the NYT article notes, this allowed companies to revise their estimates and some did by up to 200%, with the rationale for doing so no longer as clearly visible and verifiable. As the wells are now brought into production those estimates are not always proving valid, according to e-mails within the industry and which the NYT obtained for their stories. The conclusion of monitors in the EIA, as evidenced by similar e-mails released by the agency, is that many of the companies will go bankrupt.
In some ways the response of the industry reminds me a little of what happened after the climate change e-mails were released to the web in what became known as Climategate. Very little specific focus on the criticism, rather moves to obfusticate the issue, and change the subject. In this regard it is sad to note that in the response that Aubrey K. McClendon, Chesapeake's Chief Executive Officer, released on the story his major defense seemed to be
If the Times was interested in reporting the facts and advancing the debate about the prospective benefits of natural gas usage to energy consumers, it could easily have contacted respected independent reservoir evaluation and consulting firms that annually provide reserve certifications to the U.S. Securities and Exchange Commission or contacted experts at the U.S. Energy Information Administration, the Colorado School of Mines' Potential Gas Committee, the Massachusetts Institute of Technology, Navigant Consulting and others who would gladly have gone on record to confirm the abundant resources that have been made available thanks to the horizontal drilling and hydraulic fracturing techniques that Chesapeake and other industry peers have pioneered in deep shale formations across the U.S.
As I noted in my comment on the EIA report there is a huge difference between a reserve (which is economically realizable) and a resource, which is not necessarily economic. The response did not address, in sufficient technical detail, the points that the NYT and released e-mails make, about the decline rates and thus long-term viability of the wells in production. Nor did it highlight in sufficient detail how, outside of the sweet spots such as the Day Kimbell well site, the less productive wells can be expected to remain economically competitive when their production costs could well be over 50% higher than the current price of natural gas as it is sold to the pipeline. Bear in mind also that the gas from shale is competing against natural gas produced from more conventional wells (at lower cost) and against Liquefied Natural Gas (LNG) which is available on the world market. The response by Michael Levi was similarly disappointing, since it tried to diminish the number of operators who might have problems along the “much ado about nothing,” line. While that by Christopher Helman tries to change the subject a little by suggesting that some wells also produce oil that helps with the economics, (this largely relates at the moment to the Eagle Ford shale) rather than the reality that it is the oil that is driving the well production, not the natural gas. And this was covered in these pages last December.
As I mentioned at the top of the post there is little in the NYT stories that is not well known within the industry. The e-mails bear that out. But it will be interesting to see how many papers pick this story up and also to see whether it acquires legs, or is allowed to quietly fade back into the noise. It isn’t after all as though we were betting our economic future on this, is it?
By. Dave Summers
David (Dave) Summers is a Curators' Professor Emeritus of Mining Engineering at Missouri University of Science and Technology (he retired in 2010). He directed the Rock Mechanics and Explosives Research Center at MO S&T off and on from 1976 to 2008, leading research teams that developed new mining and extraction technologies, mainly developing the use of high-pressure waterjets into a broad range of industrial uses. While one of the founders of The Oil Drum, back in 2005, he now also writes separately at Bit Tooth Energy.