July 4, 2011 § Leave a comment
A The New York Times piece on June 26, 2011 discusses this proposition and is very bearish on the prospects. We acknowledge the principal points: some in the industry worry about the profitability especially given the low prices in the last year or two. We present here a case for optimism. These are early days in the exploitation of a completely new type of reservoir. Continuous improvement, as in any industrial endeavor, can be expected. In the case of shale gas the learning curve is likely to be steep. In part this is because of the sheer volume of activity. Each well will drill and produce in as few as twenty one days. The setting is almost akin to a factory, which we all know is the type of setting amenable to rapid learning curves.
Production from shale gas wells declines rapidly: The decline is steep, with a drop of 60% to 80% in the first year. (Conventional reservoirs decline 25% to 40%) After year two there is a gradual decline. The mechanism is likely premature closure of the fractures. This could be due to insufficient penetration of proppant into the formation. (Proppant is sand or other ceramic material injected into the hydraulically created fractures to “prop” them open to allow gas to flow; absent this natural stresses would close the fractures) Industry is working on materials and techniques to cause improved and more sustained flow. A Rice University originated product sourced from nanomaterial is in early stages of commercialization.
Refracturing: This is where new fractures are initiated in existing well bores, often directly on top of the old ones. In the few cases that it has already been attempted in the Barnett, the results have been dramatic. Initial production rates have reached and exceeded the original starting production. And sometimes they decline at the same rate as before. This is indicative of the possibility that new rock pores are being accessed. Research, at the University of Texas to name one, is ongoing and one could expect results to be variable for some time. At present research indicates that the optimal time to refracture is two to three years after initial production.
Somewhat ironically, a shortcoming of the resource, the poor permeability (a measure of the ability of fluids to flow in the rock), may be why this technique works. Ordinarily, poor permeability means less flow, and hence less production. Fracturing improves that. But if the fracture paths are impaired as explained above, the gas does not get fully drained. But it is available for new fractures, and is for all practical purposes from new rock despite being proximal. From the standpoint of economics of the prospect, all that matters is that each operation causes enough production to assure a rate of return. The fast declines are not highly material if this economic threshold is met. One final point: refracturing is at a fraction of the cost of the original well because no new well bore is drilled. So the newer gas has a cost basis that could be a third or less of the initial gas. Does wonders for prospect economics.
Wet Gas: There is a passing allusion to this in the NY Times piece but it deserves serious attention because of the dramatic effect on profitability. Wet gas is defined as natural gas with a significant component of hydrocarbon species other than methane. The economic significance lies in the spread between natural gas and oil prices. Gas on the basis of energy content is currently priced at about a fourth of oil. Decades ago these used to be in parity. Natural gas liquids, the “wet” part of wet gas, are priced in relationship to the price of oil. Condensate is at or somewhat higher than oil price, butane is definitely higher than oil because it is essentially a drop-in replacement for gasoline. Propane is at a discount to oil, as is ethane. Ethane is the least costly, at about half the price of oil. But all these are vast improvements over the price of methane. A typical Marcellus wet gas prices out about 70% over dry gas. Range Resources reports that at a flat $4 per million British Thermal Units (MMBTU) gas price (incidentally the average for 2010 was around this figure), their Internal Rate of Return would be 60%. That is way more profitable than any conventional gas prospect.
Marcellus, the largest and most prolific of the North American deposits, has a wet character on its western side. The as-yet not important producing states of West Virginia and Ohio are advantaged in this regard, as is western Pennsylvania.
How things will play out: Given the facts above, expect the wet gas prospects to be produced first. Over the next few years, the price of methane will rise because of demand. Massive switching from coal fired electricity to gas will occur. This is because even without a price on carbon, the all-in cost of electricity from gas is less than from coal at gas prices below $8 per MMBTU. In a recent publication we present a model predicting gas prices as having a lid at about $8. This stability will contribute to switching of oil to gas. The switches will include methane propulsion of vehicles and gas-to-liquids derived diesel and gasoline. Over time this plus electric vehicles will make a significant dent in our $400 billion annual imported oil bill, and hence our balance of payments. Importantly, gas prices will be less subject to the whims of the weather because heating and cooling will be an ever decreasing component of gas usage.
The demand creation will allow a gradual return to dry gas production. Some of the earlier plays are profitable at $4 already. But a rise in the floor price will ensure the supply that will be dictated when the trends described above mature.
And one day the NY Times will have a page one above the fold piece on how shale gas transformed the US economy. Then I will wake up.