PA Marcellus News Digest March 6, 2012
Activists March For Fracking Tax In Maryland
Opponents of fracking, the controversial drilling technique that extracts natural gas from rock, are rallying in Annapolis. The activists are marching in support of a bill that would assess a $10 per-acre fee on land leased for extracting gas in the Marcellus Shale.
DEP allows Keystone to move forward with Marcellus Shale waste plan
The state Department of Environmental Protection has given the go-ahead for Keystone Sanitary Landfill to process Marcellus Shale rock waste, extracted from natural gas wells, at its facility in Dunmore and Throop, an agency spokeswoman said Monday.
Industry debuts Marcellus to Main Street initiative
WV State Journal
Industries within the Marcellus shale drilling area are reaching out to local businesses looking for partnerships.
The Marcellus Shale Coalition, a Pennsylvania-based industry advocate, announced creation of "Marcellus on Main Street" March 6. The initiative creates a website where small- and mid-sized businesses can engage with energy companies, contractors and suppliers associated with the development of the natural gas industry.
Financial woes shake the DRBC
3 of the 5 commission members have either shrunk payments or stopped paying.
The financial noose is tightening for the Delaware River Basin Commission, the arbiter of whether natural gas drilling will occur in the watershed.
Pennsylvania, which is upset that the commission has yet to authorize drilling, has withheld two quarterly payments to it. A state budget document shows Pennsylvania froze its allocation in January, reducing its payments to the DRBC by 40.7 percent this fiscal year.
Alternatives to fresh water eyed for fracturing
(full text below)
Record droughts and contamination concerns are prompting a fresh look at the use of fresh water in hydraulic fracturing.
The hydrocarbon extraction process uses millions of gallons of fresh water per well. And while some of the flowback -- water filled with brine and chemicals that rises back to the well surface -- is being reused, that cuts freshwater use by a small fraction. That has led some scientists to call for entirely replacing fresh water with low-quality brackish water during hydraulic fracturing.
"The industry can eliminate the use of fresh water in most areas, if the industry wants to," said Steve Holditch, a professor in the Department of Petroleum Engineering at Texas A&M University.
The push is especially strong in the Eagle Ford Shale in Texas, which is suffering from a historic drought. Natural gas and related liquids from the Eagle Ford have contributed nearly $2.9 billion in total economic output to Texas since 2008, according to an industry study by America's Natural Gas Alliance. The industry is vital to the economy, but the use of fresh water at a time when municipalities are running out of supplies has raised some alarm.
Oil and gas operators in the Lone Star State use nearly 3.6 million gallons of fresh water -- enough to fill about six Olympic-sized swimming pools -- to drill a single well in the play, according to the Texas Railroad Commission.
Much of that water comes from the Carrizo Wilcox Aquifer in south Texas, which contained about 176 billion gallons of water in 2008. The Railroad Commission estimates that 2,600 to 2,800 new wells will likely be drilled each year in the region during peak demand, which would require about 9.4 billion gallons yearly from the aquifer.
Engineers usually prefer fresh water for hydraulic fracturing because it is easy to transport in trucks, and there are few issues with spills. More significantly, fracturing fluid -- which contains friction-reducing agents, anti-scaling agents and other chemicals -- is most viable in fresh water.
"The industry currently uses fresh water because a single fracture fluid recipe will work," said Holditch.
In comparison, brackish water is a mixed world. Charged particles such as sodium, chlorine, iron and other elements derived from reservoirs deep underground exist in the water in a continuous flux of attraction and repulsion. Depending on which reservoir the water comes from, the composition of the salts and elements in the water can vary.
When fracturing fluid is added to brackish water, the particles can interact in undesirable ways and inactivate the chemicals. Salts can also cause scaling underground, and some of the elements could potentially block the passage of natural gas to the well bore.
So, when the fracturing fluid is mixed in with brackish water, "you have a tub full of snot instead of a tub full of polymer that is slick," said David Burnett, a professor at Texas A&M University.
Companies would prefer to avoid the risk of an inactive fluid damaging their well bore, but this does not mean that salt water cannot be used in drilling. In fact, the oil and gas industry regularly uses fracturing fluids with salt water for offshore drilling. The practice has been avoided inland because of cost, and fresh water has been easily and cheaply available in most places.
The brackish water can be fixed so it does not react undesirably, and scientists are trying to figure out the threshold of salt beyond which the fracturing fluid becomes inactive. Currently, the limit for salt would be roughly equal to the level in seawater that is used by the offshore oil industry: about 35,000 parts per million.
"Every drilling engineer and every company manager, every team leader would like to know that [threshold]," Burnett said. There could be different thresholds depending on which underground reservoir the brackish water comes from. The best way for gas companies to deal with this variability would be to keep a chemist on site to fix the water for use, he said.
Chesapeake Energy Corp. spokesman Jim Gipson said that his company is testing water of various qualities less than fresh water for use during fracturing.
Switching to brackish water would be desirable, said Amy Hardberger of the Environmental Defense Fund in Texas, but she remained unconvinced that fresh water could be completely eliminated. Given that water is usually a free resource, it is often cheaper to use the supplies, at least until regulation kicks in.
"You would have to have enough affordable water to satisfy the needs of the frack; it would need to be of the type of chemical constituency that could be sort of treated without having to add additional fresh water," she said. "So I think it could be very difficult and probably quite expensive, so there is not enough motivation right now to move away completely from freshwater use."
Over the past two years, some drillers have started reusing flowback, obtained when about 20 percent of the water injected underground rises back to the surface, in subsequent fracks. A lack of disposal wells in Pennsylvania and tightening regulations for disposal of the waste led to the change.
A patchwork of states have started to express concern about water use, as well, including some local water districts in Texas that have added hydraulic fracturing to the list of activities to face water restrictions.
"I think necessity is the mother of all invention; we see [reuse] moving forward in areas where fresh water is limited," said Hardberger of EDF. "As water pressure and water strains increase particularly in certain regions, the demand to encourage technology developed to minimize freshwater usage is increasing, which is great."
Fountain Quail Water Management LLC, a water recycling company, has been helping gas producers recycle flowback in the Marcellus, Barnett and Eagle Ford shales. Brent Halldorson, chief operating officer, said that the revolution toward recycling began with the Marcellus Shale in Pennsylvania, where there are only six disposal wells. In comparison, there are tens of thousands of disposal wells in Texas, where fracking first took off in the Barnett Shale. Marcellus producers found it more expensive to dispose of the waste than to reuse it.
Fountain Quail has set up a water treatment facility in the Marcellus Shale that it operates together with Eureka Resources in Williamsport, Pa., to service XTO Resources, Chesapeake Energy and Range Resources Corp. The facility filters the flowback to remove unwanted salts and contaminants, and the water can be reused. Only the heavy contaminants are disposed.
Fountain Quail also has three water treatment contracts in the Eagle Ford, Halldorson said.
Still, not every company has embraced recycling, because shale plays differ vastly in their geologies. The composition of the flowback depends on which play is being considered, and some shales can yield too much salt and minerals to be easily used. And in most plays, only a small fraction of the water comes back to the surface, which means fresh water would still be needed to make up the volume.
Devon Energy Corp. has been a pioneer in recycling flowback, first in the Barnett Shale using Fountain Quail's technology, and now in the Cana play near Oklahoma City. Devon produced 275 million cubic feet equivalents of natural gas from the natural gas condensate-rich Cana play in 2011, according to its fourth-quarter earnings.
The company is building a 500,000-gallon central reservoir to hold produce water that can be moved through a network of pipelines for fracturing new gas wells. Oklahoma's shale is relatively free of elements that can interfere with fracturing fluid, meaning that the flowback is relatively clean and does not need to be filtered as in the Marcellus, said Devon spokesman Chip Minty. The company would supplement the flowback with fresh water before fracturing.
"We saw the nature of the water flowing back to the surface; it was not high in chlorides, might be viable to reuse it; we understood that whatever we can do to reduce our demand for water is a good thing," he said.
Minty said that no other operation in the United States has a centralized holding facility for water recycling, but the idea has gained traction with other companies.