By David Wagman, Chief Editor
John Adams, senior vice president of Power Operations at Calpine, recalls in this month’s gas executive roundtable how new natural gas use was banned by Congress in the late 1970s over fears that less than a decade’s worth of supply remained.
“Here we are now, 30 years later and there are projections that we have between an 80- to 100-year supply of natural gas,” he said.
He may have been too cautious with that estimate. The Energy Information Administration said last month that technically recoverable shale gas resources could give the U.S. as much as a 300-year supply. How fortunes can change with the advancement of technology.
Natural gas is the fuel of choice for new electric power generation. True, it is a fossil fuel and has an emissions profile. But natural gas has gained a reputation as a cleaner alternative to oil and coal. Plants are relatively easy to site. And, in recent years, price volatility has eased, helping power planners figure the long-term cost of a generating asset with more precision.
The coal industry is something of a fan, with ongoing efforts to promote integrated gasification combined cycle as a way to convert coal to syngas for combustion and electricity generation.
EIA expects total natural gas consumption to reach 66.7 billion cubic feet per day (Bcf/d) in 2011, led by industrial sector growth. Electric power generation use is forecast to grow almost 3 percent this year. At the same time, EIA expects natural gas production to slow from the 4.5 percent rate of growth seen in 2010. Its April “Short Term Energy Outlook” pegs total marketed production growth at 2.4 percent in 2011 and 0.8 percent in 2012.
EIA reported that another important measure, the number of natural gas drill rigs, fell from 973 in April 2010 to 889 as of April 8. With oil prices high due to political turmoil in key producing regions, the price difference between petroleum liquids and natural gas on an energy-equivalent basis helps favor drilling for liquids over dry gas. EIA expects higher consumption in 2012 (led by the electric power sector) to push prices up and improve the economics for producers to resume drilling.
The Henry Hub spot price averaged $3.97 per MMBtu in March, 12 cents lower than in February. EIA said it expects Henry Hub prices to average $4.10 per MMBtu this year, down 29 cents from 2010. It projects Henry Hub prices to rise to $4.55 per MMBtu in 2012.
EIA said uncertainty over future natural gas prices has eased this year compared with 2010, a good sign for those worried about volatility. Natural gas futures for June 2011 delivery averaged $4.29 per MMBtu in early April with an average implied volatility of 34 percent. The lower and upper bounds for a 95 percent confidence interval for June 2011 contracts were $3.37 per MMBtu and $5.47 per MMBtu, respectively. At this time last year, June 2010 futures contracts averaged $4.04 per MMBtu with 41 percent implied volatility. The corresponding lower and upper limits were $3.00 per MMBtu and $5.50 per MMBtu.
In our roundtable, Larry Nichols, CEO of producer Devon Energy, said, “At $4, there’s very little that’s economically attractive on a full-cycle basis. As it gets about $5 and $6, then that opens up a lot of additional reservoirs. I think that $4.50 to $7 is a good number to look at.”
Some natural gas producers have given the industry a black eye, the result of bad production practices. YouTube has featured the occasional video of kitchen sinks turned into torches, allegedly after hydraulic fracturing in shale formations caused natural gas to migrate into groundwater supplies.
“Ultimately what’s going to be available for resource recovery is going to come down to access versus key regulatory issues,” said Daryll Shoemaker, director of Power and Energy for HDR Inc. during our roundtable. “They all need to be proactively addressed.”
One issue is treating water produced as a result of the resource recovery process. The National Energy Technology Laboratory last month reported results of a system that can turn wastewater from natural gas production into clean water.
Altela Inc.’s AltelaRain 4000 water desalination system was tested at BLX Inc.’s Sleppy well site in Indiana County, Penn. as part of a sponsored demonstration. During nine continuous months of operation, the unit treated 77 percent of the water stream onsite, providing distilled water as the product. The average treated water cost per barrel over the demonstration period was around 20 percent lower compared to the previous total conventional disposal costs at the site. The system also reduced the need for trucking wastewater from the site.
Based on data generated from the NETL demonstration, Altela increased its technology’s efficiency by more than 30 percent. All of the clean water produced at the demonstration site was suitable for re-use for additional natural gas stimulation. It also was suitable to be discharged to surface waterways.
As a result of the demonstration project, Altela designed larger towers for the system and four modules were sold and installed to treat around 100,000 gallons per day of produced and flowback water from hydraulic fracturing. This commercial installation is said to be a 50-fold increase in capacity over the demonstration unit and represents the first of what could be many planned facilities to be developed in the Marcellus Shale Basin and similar shale gas basins throughout the United States.
Shale gas has the potential to be a major contributor to the U.S. energy mix. Wastewater production issues need continuing attention to ensure this resource can achieve its full, low-cost potential.
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