By Brian K. Schimmoller, Contributing Editor
Considering the unparalleled gas turbine boom in the United States from 1999 to 2001, one might expect to see a dramatic increase in domestic natural gas consumption over the same time period. However, while total U.S. natural gas consumption did grow between 1997 and 2000, the increase was less than 3 percent, and since 2000, consumption has actually fallen more than 4 percent. The big change has not been in numbers, but in who’s buying the gas. Residential and commercial consumption has been essentially flat since 1997. Industrial consumption, not surprisingly, has fallen, about 10 percent, as gas-intensive industries have shut down or moved overseas. That leaves the power sector, where consumption has climbed more than 10 percent since 1997.
If overall gas demand hasn’t changed all that much, what’s with the high prices? The biggest driver is supply. The U.S. natural gas industry is fighting a losing battle in terms of maintaining current production levels. Since 2000, domestic production has held steady, but at the expense of more than 60,000 additional wells. Imports from Canada can fill the gap, right? Wrong. Canadian natural gas imports peaked in 2002 and have been falling since. U.S. and Canadian suppliers have harvested the low-hanging fruit and are now having to tap into less conventional sources.
Well, then, liquefied natural gas (LNG) will save the day. Think again. Rosy projections from a few years ago – that LNG could meet 20 percent of U.S. natural gas demand – are looking less likely now. Liquefaction costs have increased substantially; global demand for natural gas provides LNG suppliers with more market outlets, often much closer than the United States; geopolitical concerns with LNG supplier countries such as Iran and Russia may limit U.S. options; and safety issues regarding regasification terminals could hamper import capacity. LNG imports actually fell from 2004 to 2005.
So what will fuel our large installed base of gas-fired capacity, currently at about 250 GW? And what will fuel any additional gas-fired capacity that comes online in the future? The Energy Information Administration’s Annual Energy Outlook 2006 expects another 70+ GW of gas-fired capacity to enter operation between about 2012 and 2025. Even accounting for retirements of older units, gas consumption in the electric power sector is projected to increase by more than 50 percent over the next 15 years.
In the near term, sustained high natural gas prices are an almost certainty absent a significant recession. In the long term, the options include a shift to other fuels, substantially increased reliance on foreign suppliers or increased utilization of unconventional sources. The first option is likely, as reflected by the current level of interest in coal, nuclear and renewable power. The second option is certainly plausible given past and current behavior, but is undesirable from an energy security perspective. That leaves the third option, unconventional resources, which hold a lot of promise, but will require significant investment.
Unconventional gas resources refer to resources that are more difficult and less economically sound to extract, typically because the required extraction technology is insufficiently developed. What qualifies as an unconventional resource, however, can change over time. Coalbed methane, for example, has moved from the unconventional to the conventional category in recent years. Annual production has risen from essentially nothing in the late 1980s to more than 1,720 Bcf today.
Other unconventional gas resources include deep gas, tight gas and methane hydrates. Deep gas refers to gas resources that exist at depths beyond 15,000 feet, where significant technological challenges come into play: high temperatures, high pressures, hard rock and corrosive gases. To date, less than 1 percent of all wells drilled in the United States have gone below 15,000 feet. Estimates place the recoverable resource for deep gas at 50 to 110 Tcf. For comparison, annual U.S. natural gas consumption is about 22 Tcf.
Tight natural gas resources refer to gas trapped in sandstone formations with very low permeability. Several techniques can facilitate recovery, including fracturing and acidizing, but these can be costly. Pinpointing promising well locations is also complex and costly. Estimated resource levels are fairly high, however, in the 190 to 380 Tcf range.
Methane hydrates represent a fascinating – if long-term – prospect. These gas resources, in simple terms, are pockets of methane trapped in cages of ice. They are naturally occurring and are found around the world, in both terrestrial (permafrost) and marine environments. The U.S. Geological Survey estimates that the United States has in-place methane hydrate resources of more than 300,000 Tcf. Worldwide, methane hydrate resources are believed to contain more carbon than all fossil fuels combined.
Methane hydrate research, however, is still in its infancy. Gaining a better understanding of their origin, occurrence and stability is essential in assessing their potential for widespread production. There are also concerns about the effect of methane hydrates on conventional oil and gas production. The movement of hot oil through pipework at great depths could dissociate methane from surrounding sediments, possibly generating pockets of highly pressurized gas and increasing the possibility of gas blowouts and sea-floor failure.
As with all energy issues, there is no silver bullet for our natural gas supply situation. However, there are options – or opportunities – that hold promise. Exploiting these opportunities may become critical to the nation’s energy security and to the vitality of an economy fueled by low-cost energy.