ProPublica: Energy & Environment

New Gas Drilling Rules, More Staff for Pennsylvania’s Environmental Agency

2010-02-09T12:44:54-05:00

For months, the gas drilling industry and environmentalists alike have been fixated on New York, waiting for its environmental agency to hash out final drilling regulations so companies can take advantage of the vast gas reserves buried there.

But now some of those expectations can shift to New York’s neighbor to the south, Pennsylvania, where Gov. Edward Rendell has announced that the Department of Environmental Protection will nearly double its enforcement staff, open a new office closer to the drilling action and release new drilling regulations of its own.

In December, when ProPublica surveyed all 31 drilling states, we found that Pennsylvania was part of a national trend – as gas drilling ramped up, inspection staffing levels didn’t keep pace.

In 2008, Pennsylvania had just 35 people to oversee 74,774 wells – that’s more than 2,000 wells per inspector. But unlike many states, as the industry grew in Pennsylvania, the state started to buck this trend, beefing up its enforcement staff to 76 in 2009.

Now, with the DEP expecting permits for drilling in the Marcellus Shale to more than double this year, Pennsylvania is preparing to add 68 more people to its Bureau of Oil and Gas Management. To pay for the expansion, the DEP will dip into the fees it charges for drilling permits, which it raised last year for the first time since 1984. A proposed extraction tax – which Rendell mentioned in a press release announcing the new positions and is expected to bring up in his annual budget address today – could cushion the department even more.

DEP spokesman Neil Weaver tells us that 45 of the new hires will be on the oil and gas enforcement staff, bringing the number of inspectors to 121, more than three times as many as it had just two years ago. To put that in perspective, in 2008, Texas, the largest drilling state, had an enforcement staff of 106 to oversee 263,704 wells, of which 16,569 were new and required the most oversight.

The governor has also announced the opening of a new satellite oil and gas office in Scranton – in the heart of the Marcellus Shale – where 10 of the new hires will be based.

Myron Arnowitt, Pennsylvania director of the citizens’ advocacy group Clean Water Action, offered a mixed review of the increase. "Obviously we’re glad to see that they’re continuing to increase the staff," he said, "but I do think there are some holes still, and some of it has to do with the funding process."

For this fiscal year, the DEP had more than a quarter of its budget cut. And when the state laid off 319 employees, the biggest hit – 138 positions – was dealt to the DEP. Another 120 vacant positions at the DEP were cut too, bringing the total department loss to 258 positions. Although the oil and gas division is adding positions because of the increased permit fees, that won’t help other divisions that are also involved in the drilling boom.

"There are other departments at DEP that are spending a lot of resources addressing the impacts of drilling," Arnowitt said. "Especially water management, which is issuing regulations, has an increase in wastewater plants applying, and water-related enforcement."

As drilling has ramped up in Pennsylvania, complaints about environmental problems have followed suit. Residents in Dimock had fields damaged from spills, and some believe that drilling caused the contamination of drinking water there. Elsewhere, the Monongahela River was contaminated by toxins from drilling wastewater, and there have been a slew of violations reported at drill sites across the state.

So along with the increased enforcement staff, Pennsylvania is revising its drilling regulations. The proposed regulations, which you can find here, strengthen well construction guidelines, hold drillers responsible for restoring or replacing water sources that are contaminated by drilling, and require drillers to notify DEP immediately if wells are over-pressurized, if casings are defective or if gas has migrated into drinking water sources.

The Marcellus Shale Coalition, which represents many of the drilling companies and industry interests in Pennsylvania, issued a news release supporting Rendell’s moves but declined to comment for this article.

The proposed regulation changes were released late last month and will be open to public comment until March 2. After the comments are reviewed, DEP’s Weaver explained, the department can make changes and submit a new version of the regulations to the Environmental Quality Board, which can either accept them or send them back to the department for revisions. If the board accepts the regulations, they will then be reviewed by several agencies (including state congressional committees, the Office of the Chief Counsel, the Independent Regulatory Review Commission and the state attorney general). Once they sign off, the regulations will be published in the Pennsylvania Bulletin and become enforceable.

The proposed revisions are on a smaller scale than New York’s, where the Department of Environmental Conservation is completely reworking its regulations. New York’s public comment period drew more than 12,000 responses, including a sharply worded technical review from the U.S. Environmental Protection Agency, which expressed serious concerns about the effect that drilling could have on public health.

David Sternberg, a spokeswoman for the EPA’s mid-Atlantic region, said the EPA doesn’t plan to comment on Pennsylvania’s revisions. "The proposed regulations are to change their construction standards for gas well drilling," he said. "That’s something that EPA really doesn’t have jurisdiction over."

The drilling industry has special exemptions from seven federal environmental regulations, so most regulation falls to state agencies. But that may be about to change. Matching bills in Congress would make the industry accountable under the federal Safe Drinking Water Act, and increasingly, the EPA is situating itself into the debate.

Late last month, the agency announced that it had created a tip line so the public could report "suspicious activity" related to drilling.

"Public concern about the environmental impacts of oil and natural gas drilling has increased in recent months, particularly regarding development of the Marcellus Shale formation where a significant amount of activity is occurring," said a press release announcing the tip line. "EPA wants to get a better understanding of what people are experiencing and observing as a result of these drilling activities. The information collected may also be useful in investigating industry practices."

Instructions for using the tip line can be found here.

Pennsylvania’s Gas Wells Booming—But So Are Spills

2010-01-27T16:08:13-05:00

by Sabrina Shankman, ProPublica -

As more gas wells are drilled in Pennsylvania's Marcellus Shale, more cases of toxic spills are being reported. Earlier this month, Pennsylvania's environmental officials fined Pennsylvania-based Atlas Resources after a series of violations at 13 wells, including spills of fracturing fluids and other contaminants onto the ground around the sites. And just last week the agency fined M.R. Dirt, a company that removes waste from drilling sites, $6,000 for spilling more than seven tons of drilling dirt along a public road.

The reports come on the heels of a string of other incidents that have killed fish in one of the state's most prized recreational lakes and released toxic chemicals into the environment.

The Atlas spills are significant because they are among the latest and because they happened repeatedly during the routine transfer of fluids. Pennsylvania's Department of Environmental Protection fined Atlas Resources $85,000 for the offenses, which took place between May and December of 2009. Many of the spills were discovered by DEP inspectors.

The violations (PDF) cited by the DEP include spills of fluids from the hydraulic fracturing process at seven sites, and failure to report a spill at one of those sites. One spill was the result of a faulty pit liner, which is supposed to insulate the ground from hydraulic fracturing fluids after they are pumped out of a well.

Atlas Resources controls more than half a million acres within the Marcellus Shale, the massive gas deposit that stretches from Tennessee to New York. The company, whose total revenue was $787.4 million in 2008, issued a statement acknowledging that it had entered a voluntary settlement with the DEP and saying that each of the incidents had been corrected. An Atlas spokesman declined a request to answer additional questions about the violations, or about the company's operations in Pennsylvania.

"If you look at this series of violations -- it's not only that there are multiple violations," said DEP spokeswoman Helen Humphreys, pointing to the fact that the same three violations were turning up at each site. "This is a pattern, and it's a problem."

The pattern, and the problem, extend beyond Atlas.

In December the DEP fined Chesapeake and Schlumberger, two of the biggest operators in the Marcellus Shale and in gas development nationally, for spilling hydrochloric acid, which is used for hydraulic fracturing and is corrosive. Cabot Oil and Gas, a Houston-based energy company that lists T. Boone Pickens as one of its stockholders, was fined in November for a series of spills, including a fracturing fluid spill by its contractor Halliburton.

In October Pennsylvania fined (PDF) Texas-based Range Resources $23,500 for spilling nearly 5,000 gallons of wastewater, including hydraulic fracturing fluids, into a tributary of Cross Creek Lake, a protected watershed near Pittsburgh that contains some of the state's most robust fish populations.

A DEP report (PDF) on that spill said, "The creek was impacted by sediments all the way down to the lake and there was also evidence of a fish kill as invertebrates and fish were observed lying dead in the creek.”

The Range Resources spill occurred on May 26, when the company was pumping fluids from the hydraulic fracturing of three wells through a six-inch pipe to a DEP-approved impoundment. Along the way, two screws along the pipe came loose, according to the Range Resources report on the incident, allowing thousands of gallons to spill onto the ground before the company was able to shut it down.

Range Resources spokesman Matt Pitzarella said the loosened screws were a result of vandalism and that the company responded by increasing security at its sites. The fish killed in Cross Creek amounted to less than a pound of minnows, he said.

Just three weeks before the fines were announced, Range was penalized by the DEP for another accident -- this time for spilling more than 10,000 gallons of flowback water, which again resulted in a fish kill and a substantial cleanup effort. A DEP spokesman said he could not comment on that spill, because a settlement is still being decided.

"We find both of these to be unfortunate and unacceptable," said Pitzarella, who said that neither spill had any negative impacts on health or property.

Unlike previous spills -- including the recent Atlas spills -- the DEP has not issued press releases for either of the Range Resources spills, and a spokesman has not explained why.

Stricter Rules for Oil and Gas Leasing on Federal Land

2010-01-06T17:00:14-05:00

by Sabrina Shankman, ProPublica -

Interior Secretary Ken Salazar has changed the procedures the Bureau of Land Management must follow before leasing federal land for oil and gas drilling, sending a message that the Department of the Interior aims to reverse some energy policies of the Bush administration.

"The previous Administration's 'anywhere, anyhow' policy on oil and gas development ran afoul of communities, carved up the landscape, and fueled costly conflicts that created uncertainty for investors and industry," Salazar said in a news release. The BLM, which is part of the Department of the Interior, regulates oil and gas on the 256 million acres of federal land it manages.

The reformed policy, which Salazar announced earlier today, will require more detailed reviews before leases are issued, will allow for more public involvement in developing master leasing and development plans, and will shift the focus of new drilling toward areas already being developed. The reforms also create an Energy Reform Team to identify and implement the reforms.

In the past, BLM has used categorical exclusions to approve leases, allowing leases to be rubber-stamped based on existing environmental analysis rather than relying on new reviews. Based on today's announcement, BLM will no longer be allowed to use those exclusions in cases of "extraordinary circumstances" -- meaning drilling that could impact protected species, historic or cultural resources, or human health and safety.

"Restoring balance to an agency that was out of whack for years is a good move," said Amy Mall, a senior policy analyst with the Natural Resources Defense Council. "It means [the BLM is] not just going to lease a parcel because the industry wants it."

She added that while the announcement is a positive one, it remains to be seen whether the reforms will be adequately implemented.

The Department of Interior has created a side-by-side analysis (PDF) of current BLM policy and the proposed reform, and has posted a fact sheet (PDF) on the changes.

Montana Gas and Oil Regulatory Actions on the Rise

2010-01-05T13:51:32-05:00

by Sabrina Shankman, ProPublica -

Last week, ProPublica rolled out a database tracking natural gas drilling and regulation in each of the 32 drilling states in the country, focusing on the 22 that supplied the most complete data.

We've updated the database to include Montana's gas and oil enforcement actions, which you can check out here. Montana shows an overall growth in enforcement actions -- with a 95 percent increase from 2003 to 2009. During the same period, Montana added just one enforcement staff member, bringing its ranks to six, while the number of new wells drilled between 2003 and 2008 increased 7 percent.

That's contrary to what we found in many other drilling states, where the number of new wells skyrocketed while the number of enforcement staff and enforcement actions either stayed the same or grew only slightly.

We'll continue to update the database as states report their 2009 final numbers, so stay tuned.

Natural Gas Drilling: What We Don’t Know

2009-12-31T14:48:40-05:00

by Abrahm Lustgarten, ProPublica -

It takes brute force to wrest natural gas from the earth. Millions of gallons of chemical-laden water mixed with sand -- under enough pressure to peel paint from a car -- are pumped into the ground, pulverizing a layer of rock that holds billions of small bubbles of gas.

The chemicals transform the fluid into a frictionless mass that works its way deep into the earth, prying open tiny cracks that can extend thousands of feet. The particles of sand or silicon wedge inside those cracks, holding the earth open just enough to allow the gas to slip by.

Gas drilling is often portrayed as the ultimate win-win in an era of hard choices: a new, 100-year supply of cleaner-burning fuel, a risk-free solution to the nation’s dependence on foreign energy. In the next 10 years, the United States will use the fracturing technology to drill hundreds of thousands of new wells astride cities, rivers and watersheds. Cash-strapped state governments are pining for the revenue and the much-needed jobs that drilling is expected to bring to poor, rural areas.

Drilling companies assert that the destructive forces unleashed by the fracturing process, including the sometimes toxic chemicals that keep the liquid flowing, remain safely sealed as much as a mile or more beneath the earth, far below drinking water sources and the rest of the natural environment.

More than a year of investigation by ProPublica, however, shows that the issues are far less settled than the industry contends, and that hidden environmental costs could cut deeply into the anticipated benefits.

The technique used to extract the gas, known as hydraulic fracturing, has not received the same scientific scrutiny as the processes used for many other energy sources.

For example, it remains unclear how far the tiny fissures that radiate through the bedrock from hydraulic fracturing might reach, or whether they can connect underground passageways or open cracks into groundwater aquifers that could allow the chemical solution to escape into drinking water. It is not certain that the chemicals – some, such as benzene, that are known to cause cancer – are adequately contained by either the well structure beneath the earth or by the people, pipelines and trucks that handle it on the surface. And it is unclear how the voluminous waste the process creates can be disposed of safely.

“This is a field where there is almost no research,” said Geoffrey Thyne, a former professor at the Colorado School of Mines and an environmental engineering consultant for local government officials in Colorado. “It is very much an emerging problem.”

The lack of scientific certainty about hydraulic fracturing can be traced in part to the drilling industry’s success in persuading Congress to leave regulation of the process to the states, which often lack manpower and funding to do complex studies of underground geology. As a consequence, regulations vary wildly across the country and many basic questions remain unanswered.

ProPublica has uncovered more than a thousand reports of water contamination from drilling across the country, some from surface spills and some from seepage underground. In many instances the water is contaminated with compounds found in the fluids used in hydraulic fracturing. ProPublica also found dozens of homes in Ohio, Pennsylvania and Colorado in which gas from drilling had migrated through underground cracks into basements or wells.

But most of these problems have been blamed on peripheral problems that could be associated with hydraulic fracturing – like well failures or leaks – without a rigorous investigation of the entire process.

ProPublica has also found that drilling procedures that can prevent water pollution and sharply reduce toxic air emissions – another frequent side effect -- are seldom required by state regulators and are mostly practiced when and where the industry wishes.

Another uncertainty arises from the enormous amounts of water needed for “fracking.” The government estimates that companies will drill at least 32,000 new gas wells annually by 2012. That could mean more than 100 billion gallons of hazardous fluids will be used and disposed of each year if existing techniques, which often involve 4 million gallons of water per well, are used.

Proposals for new regulations that might prevent many of these problems almost always lead to a fight. And more often than not, that fight devolves into stark, overdrawn choices between turning on the lights or having clean drinking water; getting rich or staying poor.

Energy lobbyists portray skeptics as hysterical and would-be-regulators as over-reaching. Environmentalists cast the dangers as more proven than is the case, and as unsolvable.

In less contentious settings, even the industry acknowledges the lack of science on key issues.

In a conference call with reporters this spring, American Petroleum Institute senior policy advisor Richard Ranger – an industry expert who has spoken frequently on the fracturing issue -- was asked for evidence that fracturing is without environmental risk:

“Have there been any recent studies done on the safety of this?” a reporter asked.

“The issue of where do these fracking fluids go, the answer is based on the geology being drilled,” Ranger said. “You’ve got them trapped somewhere thousands of feet below with the only pathway out being the well bore.

“I’m just not sure that that study is out there,” Ranger said.

“To be clear, we are saying this is a totally safe technology but we can’t point to any recent studies that say this is a safe technology?” the reporter asked.

“Or that says it is unsafe,” Ranger replied.

ProPublica reporters have posed similar questions to more than 40 academic experts, scientists, industry officials, and federal and state regulators. No one has yet provided a more definitive response.

ProPublica’s reporting over the last year points to four looming questions:

Where are the gaps in the environmental science and what will it take to address them?

How will the wastewater be safely disposed of?

Are regulations in place to make sure the gas is extracted as safely as possible?

And are state and federal regulatory agencies equipped to keep up with the pace of drilling?

“Most likely there are not a lot of win-win propositions,” said David Burnett, a scientist at Texas A&M University’s Global Petroleum Research Institute who specializes in industry practices to reduce environmental harm. But, he said, there is opportunity for compromise on enough issues “so that everybody wins sometimes.”

What We Think We Know

Drilling industry officials say they use a slew of engineering techniques – from sonar to magnetic resonance imaging – to study the underground explosions and strictly control the reach of hydraulic fracturing.

They say that the actual fracturing happens thousands of feet from water supplies and below layers of impenetrable rock that seals the world above from what happens down below.

Yet there are reasons for concern. Even if layers of rock can seal water supplies from the layer where fluid is injected, the gas well itself creates an opening in that layer. The well bore is supposed to be surrounded by cement, but often there are large empty pockets or the cement itself cracks under pressure. In many instances, the high pressure of the fluids being injected into the ground has created leaks of gas – and sometimes fluids – into surrounding water supplies.

A recent regional government study in Colorado concluded that the same methane gas tapped by drilling had migrated into dozens of water wells, possibly through natural faults and fissures exacerbated by hydraulic fracturing.

Dennis Coleman, a geologist in Illinois, has seen an example where methane gas has seeped underground for more than seven miles – several times what industry spokespeople say should be possible. He is a leading international expert on molecular testing whose company, Isotech Laboratories, does scientific research for government agencies, pharmaceutical companies, and the oil and gas industry.

“There is no such thing as impossible in terms of migration,” Coleman said. “Like everything else in life it comes down to the probability. It is never a hard and fast thing.”

In another case, benzene, a chemical sometimes found in drilling additives, was discovered throughout a 28-mile long aquifer in Wyoming.

“It is common knowledge that the lower layers are full of irregularities and inconsistencies,” said Patrick Jacobson, a rig worker who manages drilling fluid pumps and has worked on Wyoming drilling projects for more than 20 years. “I think anybody who works in the oil fields, if they tell you the truth, would tell you the same thing.”

Scientists have found it difficult to determine whether hydraulic fracturing is responsible for these problems. In large part that’s because the identities of the chemicals used in the fluids have been tightly held as trade secrets, so scientists don’t know precisely what to look for when they sample polluted streams and taps.

Drilling companies disclose enough information to comply with labor regulations meant to keep workers safe, but that information normally consists of a product trade name and rarely includes a complete list of the chemicals it contains.

Recently, this has begun to change.

In September, New York State – as part of a lengthy environmental review meant to assess the risks of fracturing – made public a comprehensive list of 260 chemicals used in drilling fluids, which it had compiled from disclosures it required drilling companies to make. And several companies themselves have begun to advocate for more disclosure, in the hope that transparency may quell the public outcry that has kept them from drilling in valuable parts of New York State.

Chesapeake Energy, which last year told ProPublica that the chemicals are kept secret because “it is like Coke protecting its syrup formula,” now says that disclosure would bring honest discussion.

“We as an industry need to demystify,” Chesapeake’s CEO, Aubrey McClendon, said at an industry conference in September, “and be very upfront about what we are doing, disclose the chemicals that we are using, search for alternatives to some of the chemicals.”

What is now needed most, according to scientists at the Environmental Protection Agency and elsewhere, is a rigorous scientific study that tracks the fracturing process and attempts to measure its reach into underground water supplies.

In Wyoming EPA scientists with the Superfund program are conducting the first federal investigation of this kind, sampling available water sources and looking for any traces of the chemicals used in drilling. But Colorado’s Thyne says a proper study would go a step further.

“The critical thing that has to be done is a systematic sampling of the background prior to drilling activity, during and after drilling activity,” Thyne said, “Ideally we would go out, we would put monitoring wells in and surround an area that was going to be fractured as part of normal operations. The budget for that kind of project would run ballpark $10 million. It’s a relatively small project for the U.S. Geological Survey or the EPA to undertake.”

Where Should the Waste Go?

On the East coast, one of the most important unanswered questions about drilling is how to dispose of the chemically tainted wastewater that hydraulic fracturing produces.

Most drilling wastewater in other parts of the country is stored in underground injection wells that are regulated by EPA under the Safe Drinking Water Act. However the geology in the East makes injection less viable, and less common. In New York and Pennsylvania, millions of gallons of drilling wastewater could eventually be produced each day.

That wastewater will likely be trucked to treatment plants that don’t routinely test for most of the chemicals the wastewater contains and that may not be equipped to remove them. Currently, the plants also can’t remove the high levels of Total Dissolved Solids found in drilling wastewater – a mixture of salts, metals and minerals – that can increase the salinity of fresh water streams and interfere with the biological treatment process at sewage treatment plants, allowing untreated waste to flow into waterways. High TDS levels also can harm industrial and household equipment and affect the color and taste of water.

After the wastewater passes through the treatment plants it is dumped back into public waterways that supply drinking water to at least 27 million Americans, including residents of Philadelphia and New York City. But without identification and routine testing for the problematic chemicals, it will be impossible to know how much of them are making their way to drinking water sources, or how they are accumulating over time. Evolving medical science says low-dose exposure to some of those chemicals could have much greater health effects than the EPA or doctors have previously thought.

“Managing produced water has always seemed like one of the large challenges, because this area geologically doesn’t have the extensive network of underground injection wells,” said Lee Fuller, vice president of government relations for the Independent Petroleum Association of America. “One challenge that industry has got is looking at developing [treatment] technology, which could be very costly.”

All Equal Under the Law

The gas industry, and hydraulic fracturing, is subject to widely different laws in different states. Some of those laws are tough, perhaps burdening the drilling industry unnecessarily. Others are lenient, perhaps leaving much of the country subject to environmental danger.

One thing is certain: There is no national standard for an industrial process that is used prolifically in 32 states and will be used even more in the future.

Gas drillers receive special exemptions from seven federal environmental regulations that apply to countless other industrial activities across the country.

Drilling companies are not required, for example, to report the discharge of toxic chemicals for the Toxics Release Inventory under the Superfund law – including the wastewater that threatens Eastern water supplies. They do not have to comply with the section of the Clean Water Act that regulates pollutants at construction sites. And they don’t have to abide by the Clean Air Act, which regulates industrial emissions.

Gas drilling also has its own individual exemption, approved by Congress during the George W. Bush administration, that explicitly prohibits the Environmental Protection Agency from regulating hydraulic fracturing under the Safe Drinking Water Act, the way the agency regulates almost all other types of underground fluid injection, including those injection wells used for wastewater in the West.

The argument behind these exceptions is that state regulations sufficiently protect the environment from drilling. But the result is that drilling regulation is left to a patchwork of state laws.

A recent report by the Ground Water Protection Council, a research group that once had energy executives on its board but now consists mainly of state regulators, revealed that only four of the 31 drilling states it surveyed have regulations that directly address hydraulic fracturing and that no state requires companies to track the volume of chemicals left underground. One in five states don’t require that the concrete casing used to contain wells be tested before hydraulic fracturing. And more than half the states allow waste pits that hold toxic fluids from fracturing to intersect with the water table, even though waste pits have been connected to hundreds of cases of water contamination.

Although energy companies have developed many techniques that can reduce the spills and seepages that have occurred across the country, they are usually left to implement them when and if they choose, meaning protections can be entirely different between drilling fields a couple of miles apart.

In northern Pennsylvania, for example, drillers do not have to supply regulators with a complete list detailing every chemical they will pump underground, while 15 miles away, in New York, state authorities have said that such disclosure is a must because it is essential to protecting the water.

Many scientists and members of Congress are arguing for a sturdier national standard that would require minimum environmental protections and ensure that a national energy policy based on natural gas extraction can be pursued without jeopardizing the country’s other natural resources.

“What we’re talking about is just putting some basic parameters around it,” said Rep. Jared Polis, D-Colo. “If companies are able to operate within those parameters… then that’s fine. If they can’t economically do that, then that is because they are causing more damage than they are creating value, and they probably shouldn’t be operating in the first place.”

Polis is one of 50 sponsors of the FRAC Act, a bill before Congress that would restore the EPA’s authority to regulate hydraulic fracturing under the Safe Drinking Water Act and would require the disclosure of the chemical additives.

Congress also recently asked the EPA to conduct a new peer-reviewed study of hydraulic fracturing’s effect on water resources, reassessing its old position.

On Wednesday, the EPA voiced its most explicit concerns in a decade about the environmental risks presented by drilling, in its response to New York State’s plan for drilling in the Marcellus Shale, the layer of rock stretching from central New York to Tennessee. The agency said it had “serious reservations” about whether hydraulic fracturing was safe to do inside the New York City watershed and urged the state to consider possible threats to public health.

EPA scientists have also told ProPublica that the study suggested by Congress may soon be underway. If that research is coupled with a congressional reversal of the exemption from the Safe Drinking Water Act, hydraulic fracturing could eventually be regulated like any other injection well in the U.S. That would require, among other things, thorough testing of the rock miles below the surface to confirm that it can safely contain whatever is injected into it – a stipulation that addresses some of the uncertainty and is inconsistently found in state drilling laws.

EPA regulation “would essentially create a base level,” said Steve Heare, director of the EPA's Drinking Water Protection Division in Washington. Under the Safe Drinking Water Act, states “would basically have to make a showing that their regulations were as effective as ours.”

Better Policing

All the laws and protections in the world won’t ensure that drilling can be done safely if effective enforcement isn’t in place to oversee it.

Yet for all the debate about environmental protections, new laws and national benefits, very little emphasis has been placed on bolstering the agencies that issue drilling permits and go out into the field to make sure the processes are done right.

ProPublica’s recent analysis of 22 states that account for the vast majority of the country’s drilling found that regulatory staffing has not kept up with the drilling boom, meaning that the nation’s ability to enforce rules that provide environmental safeguards is systematically weakening.

New York, one of the hot spots expected to supply this gas-based national energy paradigm, has cut its oil and gas regulatory inspection staff 20 percent since 2003, even while it has approved a 676 percent increase in the number of new wells being drilled each year. Other states have added a few people, but almost none have kept up with the crushing pace of new drilling.

In West Virginia, the third most active gas drilling state in the nation, four new enforcement employees have been hired since 2003, but each inspector is still responsible for some 3,300 wells.

“Crisis management is not the best management in the world and we had to deal with crisis management 90 percent of the time,” said Jerry Tephabock, a former head of state oil and gas inspections in West Virginia who retired in 2007. “There were wells out there that had been drilled that have never been inspected in 15 to 20 years.”

Even if states manage to keep staff levels where they are now – a challenge since 39 states have projected budget deficits for 2010 – the growth that would come from placing more emphasis on natural gas as a part of the nation’s energy strategy may still present sizable risks for both the environment and the economy. Either enforcement would have to slacken, or the permitting of new wells would slow so much that it would stifle the economic growth and energy independence that drilling is expected to bring.

Different states are choosing different paths. Texas regulators promise they will issue new permits to drill within 72 hours, even though their regulator-to-well ratio is one of the most demanding in the nation. New York, in contrast, has pledged to bring new drilling to a crawl until its staff can catch up.

Neither approach addresses the scientific or regulatory gaps that represent drilling’s long-term threats to the environment, however. And it remains to be seen whether politicians and environmental regulators will make sure precautions are taken at the beginning of this new energy boom, or if they will leave the nation to clean up the mess after the boom goes bust, as it has had to do so many times in the past.

ProPublica reporters Joaquin Sapien and Sabrina Shankman contributed to this report.

Interactive: Search Gas Drilling Data in Your State

2009-12-30T13:21:44-05:00

by Jeff Larson, ProPublica -

As part of our report on the strain that the nationwide boom in gas drilling has placed on state regulators, we collected and analyzed drilling records for the past six years from all 32 oil and gas producing states. (We focused on the 22 states with the most complete data.) We’ve put it all up as a pretty, interactive feature so you can look at the data and see how it changed from year to year.

Look up gas drilling data for your state.

State Oil and Gas Regulators Are Spread Too Thin to Do Their Jobs

2009-12-30T12:38:08-05:00

by Abrahm Lustgarten, ProPublica -

Larry Parrish knew something was wrong as soon as he wheeled his state-owned pickup off the West Virginia highway and onto the rocky field where the natural gas well was supposed to be. Oak trees 18 inches in diameter looked dead as boards, and brush as brown as kindling stretched across a piece of farmland the size of a football field.

The dead zone in this otherwise lush mountain country meant one thing to Parrish: Gas drillers had been illegally dumping briny water mixed with chemicals, and the waste had killed everything from the rusty well head all the way downhill into a creek. The worst part, Parrish said, was that the devastation could have been avoided if the West Virginia Department of Environmental Protection had had enough inspectors to make sure the state's growing number of gas wells were checked regularly.

"It was sad -- sickening," said Parrish, a former field inspector for the DEP's office of oil and gas. "It probably had been years since anybody had been out there."

West Virginia has added a handful of people to oversee its growing drilling industry since Parrish retired in 2006, but other than that not much has changed. For the state's 17 inspectors to visit West Virginia's 55,222 wells once a year, they would have to inspect nine wells a day, every day of the year -- no weekends, no vacations.

"We are doing what we can do," said Gene Smith, a regulatory compliance manager for West Virginia. "But that still leaves thousands of wells that are not inspected yearly or even every decade."

Regulators in other states are equally overwhelmed as they try to keep tabs on the nation's nearly one million active oil and gas wells, a number that's likely to climb as the feverish growth in natural gas exploration continues.

Search ProPublica's database to find how many gas regulators work in your state.

A ProPublica investigation comparing the rapid expansion of drilling in 22 states with staffing levels at the agencies charged with policing the wells found that the nation's capacity to enforce its environmental protections is weakening. The picture strikes at the heart of the industry's long-standing argument that state regulatory agencies will be more effective industry watchdogs than the federal government.

While the number of new oil and gas wells being drilled in the 22 states each year has jumped 45 percent since 2004, most of the states have added only a few regulators. Those with the widest gaps are Texas, which is already grappling with the most drilling, and New York, which is expected to soon have the fastest rate of growth.

As regulators' workloads have grown, enforcement actions -- the number of times violations were recorded and acted on -- have dropped in many states, often by more than half. That could mean companies are complying with the law -- or that inspectors aren't checking the wells.

"You just can't do it, physically," said Parrish, who received a $31,000 salary and said he was chronically overworked. "You've got to put out the hottest fires and there was a lot of stuff that slipped through the cracks because no one was looking."

The imbalance between drilling growth and regulatory staffing levels could become a crucial factor as lawmakers and the public weigh how much environmental damage to expect in exchange for the benefits brought by the drilling boom. Thanks in large part to advances in drilling technology, estimates for the amount of natural gas held underneath parts of the United States have increased by 35 percent since 2007 and are now believed to be plentiful enough to meet the nation's needs for more than 100 years. As a result, drilling is expanding rapidly, including in the Marcellus Shale, the layer of rock that stretches from central New York, underneath West Virginia to Tennessee.

The boom, however, has brought complaints of water and air pollution. Modern gas drilling in particular has drawn scrutiny because it relies on hydraulic fracturing, a process that injects millions of gallons of chemically infused water underground and produces large volumes of waste. The industry has fended off efforts to establish stricter regulations in part with its argument that the current state oversight is effective.

What it takes to enforce regulations, and whether authorities have enough resources to get the job done, are questions that rarely enter the debate.

"Not having eyeballs on the ground is horrendous," said Jim Baca, who served during the Clinton administration as director of the U.S. Bureau of Land Management, the federal agency that oversees more than 85,000 oil and gas wells on federal land. "If you don't enforce the law, the industry will do whatever they think they can get away with."

Spokesmen for state and federal regulatory agencies defend their effectiveness and caution that the picture is more nuanced than mathematical equations can convey. They say that they are working to improve efficiency in their departments and that the number of inspectors alone doesn't always reflect enforcement because staffers can be shifted to meet urgent priorities. Employees might have capacity in their workload to absorb much of the growth in drilling that is taking place, they say.

"They may have to work a little harder," said Stuart Gruskin, New York's executive deputy commissioner for environmental conservation, about staffing in his state. "It's like any other business. You can adjust from a management perspective how you utilize your resources until you reach the point where you are not doing a good enough job."

The New York State public employees union disagrees. "Attempting to have them do even more with less is not possible," it said this week in a statement calling for delaying the expansion of drilling for at least a year because of, among other things, what it called understaffing at the Department of Environmental Conservation and other state agencies.

The Lone Star Record

No state has more drilling than Texas, which has 273,660 wells and just 106 regulators to oversee them.

As in most states, regulators for the Railroad Commission of Texas, the agency that is charged with oil and gas regulation, are kept busy by a broad range of responsibilities. They police gas wells, oil wells, waste injection wells, disposal pits, compressor stations and access roads. The wells can be spread across hundreds of miles, sometimes peppered throughout difficult-to-access terrain, with limited cell phone or computer access, heavy rains and rough roads requiring four-wheel drive.

Regulators also approve new permits -- and try to do it fast enough to not saddle the companies applying for them with extra costs. They visit new wells several times during construction and old wells before they are shut in, or sealed. They are obligated to quickly respond to all complaints, which can range from an unauthorized flaring of emissions or gases to a spill of hazardous fluids.

Eighty-three of Texas' regulatory staffers conduct field inspections, according to the commission, meaning each person is responsible for almost 3,300 wells, many of them requiring several visits in a year.

As in West Virginia, keeping up with the workload is nearly impossible.

"It's one of the worst-kept secrets around the state that the wells that are ostensibly checked once a year aren't," said Jeff Weems, a Houston attorney who specializes in the energy industry and is running for the top job at the Texas Railroad Commission. "They could double the number of inspectors and still be straining their staff to do their job."

In late 2007, a Texas state auditor's report (PDF) examined the Railroad Commission's enforcement record and found that nearly half of the state's wells hadn't been inspected in the five years between 2001 and 2006, when the data was collected. (It also said regulators' routine acceptance of gifts from the companies they police raised questions about their objectivity and conflicts of interest, and the commission imposed a $50 limit on gifts as a result.)

In Texas, as in most states, regulators prioritize their work to make sure the most essential inspections get done. Complaints and spills top the list, along with new well construction.

But the Texas auditor's report found that 30 percent of all spills were inspected "either late or not at all."

"It is quite clear to management that inspecting 100 percent of these notices ... is not possible with current resources," the Railroad Commission wrote in its response to the audit. "To the extent resources become available in future legislative sessions, the Commission could witness more activities."

A spokeswoman for the commission said its workload decreased when drilling activity slowed in 2008, so the staffing situation has improved. She said the agency conducted 128,270 inspections in 2009, and visits every site it deems essential.

"Texas has maintained and will continue to maintain a strong enforcement effort for our environmental rules, regulations and policies," the spokeswoman, Stacie Fowler, said in an e-mail.

But the commission's Web site also makes clear that facilitating energy production is a priority and the state won't slow drilling while inspections catch up. It advertises the current waiting period for approval of new drilling permits: three days.

According to ProPublica's analysis, the number of new wells drilled each year in Texas has jumped 75 percent since 2003. However, staffing increased just 5 percent during that period and enforcement actions increased only 6 percent.

Records show that the Railroad Commission's budget for monitoring and inspections has decreased 10 percent since 2005. Fowler said the agency had requested more staffing from the state legislature at least three times in the last five years and been turned down every time.

From the industry's view, the paucity of enforcement staffing sometimes means it is up to the drilling companies to follow the rules as best they can.

"I never saw a Railroad Commissioner on one of the sites," said Dale Henry, a hydraulic fracturing expert who worked in Texas for the global services company Schlumberger for several decades. Henry said companies abided by the law whether regulators were there or not, but he also said the normal work schedule meant that they often avoided regulators. Inspectors worked 7 a.m. to 5 p.m. weekdays, and "all the work in the field is done by operators between 5 p.m. and 6 a.m. and on weekends."

A Schlumberger spokesman said that the company works closely with regulators and that it is the nature of the process to work through the night.

Even when regulators do inspect problematic sites, the oversight can be patchy.

In September 2007, a field inspector working in the Barnett Shale outside of Fort Worth made a routine stop at an underground injection disposal well site. His formal report (PDF) found no problems and stated: "Well area clean."

Inspectors returned 61 days later after a resident complained of spilled oil, overflowing dikes and green-colored fluid in standing puddles. According to their report (PDF), they found that "oil-stained soil" had seeped several inches into the ground around a large tank, that the "containment dike will not hold estimated capacity" and that standing rainwater had oil in it.

When asked about the discrepancy, Fowler, the Railroad Commission spokeswoman, said conditions can change at a site on a daily basis. But Fowler did not address perhaps the most remarkable finding in the inspectors' report (PDF): State records showed that the well site was not being used, when in fact it was actively being injected with hazardous waste.

"We looked at some records and found that the well was never technically shut in," said Charles Morris, the now-retired inspector who wrote the second report about the troubled well. "That happens all the time in the field, too. I hate to say it, but the commission, sometimes their record keeping is not what it should be."

Part of a Pattern

Texas' staffing challenges match a pattern across the states where drilling is most active.

The number of new wells drilled in West Virginia increased 53 percent from 2003 to 2008. Since 2003 its regulatory staffing increased 20 percent. Enforcement actions, meanwhile, remained relatively constant, though they temporarily dropped by more than half during a peak in drilling in 2007.

North Dakota saw a 987 percent increase in new wells drilled each year since 2003, but took 13 percent fewer enforcement actions, even though it added five regulators.

In Ohio, where the number of new wells drilled each year doubled between 2003 and 2008, four new staffers were hired but the number of formal actions dropped 33 percent.

Not every state saw a drop in enforcement actions.

In Pennsylvania, a state with intensive new Marcellus Shale drilling, state regulators doubled their enforcement staffing last year. Between 2003 and 2009 enforcement actions increased by 60 percent.

Of the 21 states that supplied data on their enforcement actions, five substantially increased those actions even as their staff-to-well ratio lagged. In Louisiana, for example, staffing was flat or falling until 2007, when more inspectors were hired and enforcement actions began shooting up. As a result, the state took almost twice as many enforcement actions between 2003 and 2008, even though the overall staff growth was just 3 percent and the number of new wells drilled annually more than doubled.

The federal government, which separately regulates a large proportion of the drilling on federal land in Western states, is also struggling to police its territory. It has seen a 31 percent increase in drilling since 2003.

A 2005 report (PDF) from the U.S. Government Accountability Office said that the Bureau of Land Management's ability to meet its obligations had been lessened by intense growth, and that "staff had to devote increased time to processing drilling permits, leaving less time for mitigation activities, such as environmental inspections."

The agency has significantly expanded its staffing since then. But even so, a 2009 analysis of its enforcement activity by the Western Organization of Resource Councils, a group of environmental organizations, found that the agency issued fewer enforcement actions in 2007, the last year for which data was available, than it did in 1999.

The analysis, which focused on BLM enforcement and inspection in five Western states, found that BLM inspectors spent a third less time on environmental inspections and completed only 15 percent of the highest-priority inspections. In Farmington, N.M., for example, BLM inspectors completed just 82 of 1,257 high-priority inspections. In Buffalo, Wyo., they finished just 136 of 3,527 red-flag jobs, according to a federal database.

"If you ask any BLM staff who has been dealing with the oil and gas industry, they admit they don't have the staff do deal with this. It hasn't been a priority," said Daniel Patterson, an Arizona state representative and southwest regional director for the group Public Employees for Environmental Responsibility, which works to convey confidential views of its government employee members. "It's pretty much up to the operator to decide if they are going to operate legally or if they are going to cut corners that lead to more pollution. That's a problem."

State and federal regulatory officials say that there is no such thing as a proper ratio of enforcement actions to wells, and that there is no way to measure how effective informal warnings between inspectors and operators are as a deterrent. Such warnings are not recorded in regulators' statistics. They also say there are myriad ways to increase the effectiveness of their oversight, including investing in new technology that improves efficiency and writing stronger laws.

Colorado, which has seen a 149 percent increase in the number of wells drilled each year since 2003, is one state that has done both.

In 2006 the state hired several new inspectors and began computerizing its records and equipping field regulators with laptops full of everything from well histories to violations. In April the state instituted new drilling regulations that are widely seen as some of the toughest in the country.

"We now have more prescriptive rules and policies, which will help to prevent problems that could otherwise evolve into violations triggering the need for enforcement," said David Neslin, director of the Colorado Oil and Gas Conservation Commission.

Whether that is enough to do the job remains to be seen. One new hire is Chuck Browning, who came on eight months ago as a field inspector for the northwest part of the state and said the magnitude of the job can be overwhelming. With two other inspectors, Browning shares responsibility for some 25,000 wells. He bounces back and forth between the Utah and Wyoming borders, tallying 17,000 miles on his Trailblazer since March.

"I'm off in some far-flung remote area of the country side and there's thousands of wells around me," said Browning, a former geologist who has worked in the oil industry for 20 years. "I just pick my way out of the woods knocking them out as best I can."

Not long ago, Browning was wandering through the Rangely field -- an eight-mile wide swath of oil, gas and injection wells that stick up out of the brown arid plain of Northern Colorado like candles in a cake -- when he stumbled on an unmarked open pipe jutting out of the dirt. Gas fumes wavered six inches in the air and when Browning dropped a pebble into the hole, he heard a kurplunk as it struck liquid. Abandoned wells are supposed to be capped and dry -- but this one was about to overflow.

In his truck he fired up his laptop, accessing topographic maps, records and aerial photos of some 88,000 wells across the state, searching for this one. But it didn't appear anywhere.

"I still absolutely have no idea how many wells are up in Rangely. It's well over 1,000," he said. "This one is definitely a potential hazard."

It was the kind of puzzle that can take a day to sort through, and at least another day to bring in the equipment and crews to begin to take care of the abandoned well. It's a wild card that can play havoc with the 10-wells-per-day inspection schedule Browning and so many other regulators are forced to keep.

New York State

If Texas and Colorado -- the first- and eighth-ranked states in the country for number of natural gas wells -- can provide a lesson, states like New York may have the most to learn.

New York, which sits atop the Marcellus Shale, has found itself at the epicenter of the nation's drilling boom and the epicenter of the debate over drilling's effect on the environment. The state's relatively small oil and gas division currently oversees some 13,684 wells, but it is under intense pressure from drilling companies, which would like to see thousands more wells drilled.

Chesapeake Energy, one of the nation's largest natural gas companies, has gobbled up more than a half a million acres of land leases in New York, and earlier this month Exxon said it would pay $31 billion for XTO Energy, a gas company that also holds extensive rights to drill in Pennsylvania and West Virginia's Marcellus Shale.

The state has delayed that development, however, to study the environmental consequences of hydraulic fracturing and investigate a chorus of objections from people who fear that drilling will contaminate drinking water. Just last week New York City called for a ban on drilling inside its watershed, citing a consultant's report that said it could jeopardize the drinking water for nine million residents.

At the same time, however, Gov. David Paterson, reeling from one of the worst state financial shortfalls in the nation, has made gas development a cornerstone of his draft energy plan.

New York regulators say that they have a better environmental record than most states when it comes to regulating oil and gas, and that a suite of proposed rules will put the state's drilling laws on par with Colorado's. Yet New York is the only state examined by ProPublica that has cut its regulatory staffing in recent years. Since 2003 New York's Department of Environmental Conservation has reduced its oil and gas division field inspector staffing by 20 percent (its overall enforcement-related staff, when including management and office positions, dropped 10 percent), stoking concerns that when the drilling kicks into high gear, the state will suffer the same sort of problems that have plagued West Virginia and Texas.

Gruskin, the New York DEC's executive deputy commissioner, says that the agency is committed to good oversight and that energy companies that want to drill in New York will simply have to adapt to the agency's pace.

"It's going to go slow. Very slow," he said. "If we only have a certain number of inspectors available in that region, people are going to have to wait until they are available. And that's just reality, that's the way it's going to be.”

But Gruskin's promise not to let drilling outpace his headcount doesn't match the recent past. Even as the regulatory staffing was being reduced, the DEC allowed a 676 percent increase in new wells drilled each year, a statistic that makes New York one of the fastest-growing drilling states in the nation. Meanwhile, the state's 16 field inspectors took only three more enforcement actions against drilling companies in 2008 than they did in 2003.

If the flat enforcement statistics were a problem, Gruskin said, the number of spills and environmental problems would have gone up -- something he points out hasn't happened.

And unless it does, the state appears content to play chicken.

"I don't think the industry believes that our resources have become so thin that they are not going to get caught." Gruskin said. "There are a lot of eyes on what is going on."

ProPublica reporter Sabrina Shankman contributed to this report. So did ProPublica's director of research Lisa Schwartz and researcher Kitty Bennett.

Drilling Wastewater Disposal Options in N.Y. Report Have Problems of Their Own

2009-12-29T00:00:37-05:00

by Joaquin Sapien and Sabrina Shankman, ProPublica -

Dec. 29: This story has been updated and clarified.

A version of this story is being published by the Albany Times-Union.

Environmentalists, state regulators and even energy companies agree that the problem most likely to slow natural gas drilling in the Marcellus Shale in New York is safely disposing of the billions of gallons of contaminated wastewater the industry will produce.

Between 1,500 and 2,500 wells per year could eventually be drilled into the huge natural gas reserve, state regulators say, although other estimates are far higher (PDF). Each well will produce about 1.2 million gallons of wastewater that can contain chemicals introduced during the drilling process and dredged up from deep within the earth. Using the state’s higher estimate, that means the industry will have to find a way to dispose of as much as 3 billion gallons a year, enough to fill 5,000 Olympic-sized swimming pools.

New York's Department of Environmental Conservation took a stab at addressing the wastewater problem in the draft environmental impact statement (EIS) on gas drilling it released in September. The report said the DEC won't issue drilling permits until companies prove they can dispose of the water. The report also listed three disposal options: Injecting it into underground storage wells, trucking it to specialized treatment plants in nearby states, or having it processed at sewage plants in New York.

But ProPublica has found that none of these methods are realistic.

Of the 135 New York plants listed in the report, only a tiny fraction can or will accept Marcellus Shale wastewater. ProPublica interviewed spokespeople for 109 of those plants and found that just three have any interest in accepting the water -- and only in small amounts. New York City's 14 treatment plants, whose operators declined to talk to ProPublica, are already running at capacity -- and often over it -- which means they too are unlikely wastewater recipients.
Of the 11 out-of-state plants the DEC listed as options, nine can't take any more wastewater. Two declined to answer questions for this story.
Of the six injection wells (PDF) that operate in New York, only one is licensed to accept oil and gas wastewater. It's owned by Lenape Resources Inc., which uses it exclusively for wastewater from its own gas fields.

When asked why the report included options that aren't feasible, DEC officials said they weren't recommending the facilities, but were merely offering an inventory of possible disposal methods. Ultimately it is the responsibility of the energy companies -- not the regulators -- to solve the wastewater problem, they said.

"In the history of environmental regulation, I think there are many instances where environmental regulatory requirements have been a driver of technology, and this could be one of those instances," said Stuart Gruskin, the DEC's executive deputy commissioner.

Raoul LeBlanc, a senior financial analyst for the energy consulting firm PFC Energy, said the "theme of regulation outrunning capacity" is likely to be repeated in the development of the Marcellus.

"This probably means delays to the ambitious programs for developing this resource and getting it to Northeast consumers," LeBlanc said.

The bottleneck of treatment options has already inspired Range Resources, one of the biggest natural gas producers in the Northeast, to develop technology that allows it to reuse all the wastewater it removes from its Pennsylvania wells. Range leaves about 80 percent of its wastewater in its wells. The 20 percent that is recovered is blended with fresh water and used to drill new wells.

"Six months ago recycling was not even considered a realistic option, but there are certain things you don't know until you try," said Matt Pitzarella, a spokesman for Range, which is among the companies expected to apply for drilling permits in New York.

Range and other energy companies are also working with Radisav Vidic, an environmental engineering professor at the University of Pittsburgh who has a $1.06 million grant from the U.S. Department of Energy to find new wastewater recycling techniques. But Vidic says that reusing wastewater has its own limitations. It's working for Range, Vidic said, because most of the company's water stays underground and because its wells are spaced close together, so it's easy to truck the recovered wastewater from well to well.

DEC officials, government scientists and industry representatives all told ProPublica that until more sophisticated treatment solutions are developed, drilling in New York's portion of the Marcellus Shale will be off to a slow start.

"If no one is going to accept it, and the DEC follows the line in the EIS, then apparently drilling will be in hiatus until someone comes up with a way to treat it," said Bill Kappel, a hydrologist with the U.S. Geological Survey.

Wastewater Already a Problem in Pennsylvania

Wastewater disposal is especially critical in the Marcellus, because much of the gas there is buried a mile or more underground and the only way to get it out is through hydraulic fracturing, a process that uses large amounts of water mixed with chemicals to break layers of rock and release the gas. Instead of plunging vertically into the ground, as existing New York wells do, most Marcellus wells will be shifted horizontally once they reach the shale. This allows drillers to extract more gas from a broader area with fewer wells, but each horizontal well can create about a million gallons more wastewater than a vertical well.

When the water flows back out, it contains small amounts of the chemicals added to facilitate gas production, plus natural toxins dredged up from the earth, like benzene, which carries cancer risks. When the DEC tested 12 vertical wells in the Marcellus in 2008 and 2009, it found that the wastewater at 10 of them also contained a radioactive derivative of uranium at levels hundreds of times as high as the federal limit for people to drink safely.

Drilling wastewater also contains high levels of total dissolved solids, or TDS, which includes minerals that can make it five times as salty as seawater (PDF). TDS isn't considered particularly harmful to people (PDF), but it can damage freshwater streams and affect the color, taste and odor of drinking water.

In Western states drillers usually dispose of their wastewater in injection wells that are designed for long-term storage and are regulated by the U.S. Environmental Protection Agency. But the geography in the Northeast makes it difficult and costly to drill injection wells. There are only six such wells in New York, although Chesapeake Energy Corp. is filing an application (PDF) for another one.

Instead, most drilling wastewater in the Northeast is processed through municipal and industrial treatment plants that aren't equipped to remove TDS, radium or any chemicals it contains. The water is then discharged into nearby streams and rivers.

High TDS levels have already caused problems for drinking water in Pennsylvania, where Marcellus Shale gas drilling accelerated in the spring of 2008. Much of Pennsylvania's wastewater was originally sent to municipal sewage treatment plants along the Monongahela River, a drinking water source for 250,000 people. TDS levels in the river were already high because of leakage from abandoned mines and other industrial waste, but after drilling wastewater was released into the river, TDS skyrocketed. Pennsylvania's Department of Environmental Protection is holding public hearings on new regulations (PDF) that would dramatically reduce the amount of TDS that can be discharged into waterways after Jan. 1, 2011.

New York’s municipal and industrial treatment plants are also unequipped to remove TDS, which is one reason so many plant operators say they don't want to take the wastewater. Their biggest fear is that TDS or some other contaminant in the wastewater might kill the freshwater organisms that they use in their treatment process, leaving untreated sewage flowing into rivers and streams where they release their water.

Many of the New York plant operators ProPublica interviewed have refused requests from drillers to take the wastewater and were annoyed that the DEC put them on the list of possible disposal options. DEC spokesman Yancey Roy said the DEC had contacted most of the operators it listed -- but most of the operators interviewed by ProPublica said they hadn't spoken with the DEC about taking drilling wastewater.

Brian Rayburn, who oversees the municipal sewage plant in the village of Bloomfield, said his facility has already reached its 323,000-gallon-a-day capacity just serving the needs of his community. Ken Bray, who operates the city of Amsterdam's plant, said the DEC recommended in 2004 that the plant not take on any new types of waste until repairs were made. Those repairs aren't finished, so Bray was surprised to find his plant on the list.

DEC Also Short-Staffed

Katherine Nadeau, a water and natural resources associate for Environmental Advocates of New York, thinks the operators' concerns about drilling wastewater are well-founded.

Last year Nadeau studied the records of 32 New York sewage plants and found that many were discharging more pollutants (PDF) than they are allowed to under state and federal laws and that some hadn't received a full compliance review from the DEC in decades. She thinks the DEC staff is stretched too thin to make sure New York's drinking water is protected from drilling.

James Tierney, the DEC's assistant commissioner of water resources, raised the staffing issue in testimony (PDF) submitted to a New York State Senate committee in October, the day after the draft environmental review came out.

"Even before the current state and national fiscal crisis, the Division of Water faced significant cuts to both state and federal funding," said Tierney, whose department oversees the treatment plants that accept drilling wastewater. "In 1990, the Division had 339 staff; today, the Division has 267 staff, and at least twice the workload."

Wastewater a "Hot Potato"

Although the recommendations in New York's environmental impact statement haven't been finalized yet, the DEC is already enforcing new wastewater disposal requirements, causing delays for some drillers.

Orville Cole spent more than a year searching for a plant that would take the wastewater from a well he was drilling in Otsego County for Gastem USA, a subsidiary of the Canadian-based natural gas company Gastem. The well is vertical, which means it will produce only about 35,000 gallons of wastewater, about 3 percent of the amount that will come from one of the horizontal wells planned for the Marcellus. Yet three different sewage treatment plants rejected Cole's water, because they feared that the chemicals the water contained could damage their plants or foul the waterways they discharge into.

Finally a municipal sewage treatment plant in Watertown, a three-hour drive from Cole's drilling site, agreed to take the wastewater. But still there were problems.

As the first five tanker loads of Cole's wastewater were being pumped into the Watertown plant in September, the plant's chief operator, Michael Sligar, noticed that it was turning dark and dirty.

Fearing that his plant might not be able to handle whatever was in the water, Sligar sent the last two tanker trucks back to Cole's drill site, where they sat for two weeks while Sligar analyzed the contents. The DEC and Sligar eventually decided that the plant could safely accept the water. But Sligar said that's no assurance that he'll be able to treat future deliveries from Cole's well, because the composition of a well's wastewater can change, depending on how long it has been underground.

If Sligar ends up rejecting the wastewater, Cole would turn to the backup plan the DEC now requires all drillers to have. In Cole's case that's an underground storage well in Ohio, a 10-hour drive from his well.

Sligar calls the Marcellus Shale wastewater a "hot potato" and says he's taking it only because he feels obligated to the state, which helps fund his plant.

"My peers don't warmly embrace this entire challenge," he said. "We would rather have this problem go away, but we don't have that option."

Update: A spokesman for New York City's Department of Environmental Protection got back to us and let us know that its 14 wastewater treatment plants won't accept wastewater from drilling in the Marcellus Shale. The spokesman said the city only accepts wastewater from within its jurisdiction, so applications to bring in wastewater from the Marcellus, which is upstate, would be turned down.

Clarification: This post originally said that state regulators said that at least 2,500 wells per year could eventually be drilled in New York's Marcellus Shale. Actually, their estimate ranged from 1,500 to 2,500 wells per year, although other estimates are far higher.

In New Gas Wells, More Drilling Chemicals Remain Underground

2009-12-27T08:12:39-05:00

by Abrahm Lustgarten, ProPublica -

This story was co-published with Politico.

For more than a decade the energy industry has steadfastly argued before courts, Congress and the public that the federal law protecting drinking water should not be applied to hydraulic fracturing, the industrial process that is essential to extracting the nation's vast natural gas reserves. In 2005 Congress, persuaded, passed a law prohibiting such regulation.

Now an important part of that argument -- that most of the millions of gallons of toxic chemicals that drillers inject underground are removed for safe disposal, and are not permanently discarded inside the earth -- does not apply to drilling in many of the nation's booming new gas fields.

Three company spokesmen and a regulatory official said in separate interviews with ProPublica that as much as 85 percent of the fluids used during hydraulic fracturing is being left underground after wells are drilled in the Marcellus Shale, the massive gas deposit that stretches from New York to Tennessee.

That means that for each modern gas well drilled in the Marcellus and places like it, more than 3 million gallons of chemically tainted wastewater could be left in the ground forever. Drilling companies say that chemicals make up less than 1 percent of that fluid. But by volume, those chemicals alone still amount to 34,000 gallons in a typical well.

These disclosures raise new questions about why the Safe Drinking Water Act, the federal law that regulates fluids injected underground so they don't contaminate drinking water aquifers, should not apply to hydraulic fracturing, and whether the thinking behind Congress' 2005 vote to shield drilling from regulation is still valid.

When lawmakers approved that exemption, it was generally accepted that only about 30 percent of the fluids stayed in the ground. At the time, fracturing was also used in far fewer wells than it is today and required far less fluid. Ninety percent of the nation's wells now rely on the process, which is widely credited for making it financially feasible to tap into the Marcellus Shale and other new gas deposits.

Congress is considering a bill that would repeal the exemption, and has directed the Environmental Protection Agency to undertake a fresh study of how hydraulic fracturing may affect drinking water supplies. But the government faces stiff pressure from the energy industry to maintain the status quo -- in which gas drilling is regulated state by state -- as companies race to exploit the nation's vast shale deposits and meet the growing demand for cleaner fuel. Just this month, Exxon announced it would spend some $31 billion to buy XTO Energy, a company that controls substantial gas reserves in the Marcellus -- but only on the condition that Congress doesn't enact laws on fracturing that make drilling "commercially impracticable."

The realization that most of the chemicals and fluids injected underground remain there could stoke the debate further, especially since it contradicts the industry's long-standing message that only a small proportion of the fluids is left behind at most wells.

But while the message has not changed, the drilling has.

In the nation's largest and most important natural gas fields, far more chemicals are being used today than when Congress and the EPA last visited the fracturing issue, and far more of those fluids are remaining underground. Drilling companies say that as they've drilled in the Marcellus they've discovered that the shale rock -- which is similar to many of the nation's largest natural gas projects in Louisiana, Texas and several other states -- holds more fluids than they expected.

During hydraulic fracturing, drillers use combinations of some of the 260 chemical additives associated with the process, plus large amounts of water and sand, to break rock and release gas. Benzene and formaldehyde, both known carcinogens, are among the substances that are commonly found.

If another industry proposed injecting chemicals -- or even salt water -- underground for disposal, the EPA would require it to conduct a geological study to make sure the ground could hold those fluids without leaking and to follow construction standards when building the well. In some cases the EPA would also establish a monitoring system to track what happened as the well aged.

But because hydraulic fracturing is exempt from the Safe Drinking Water Act, it doesn't necessarily have to conform to these federal standards. Instead, oversight of the drilling chemicals and the injection process has been left solely to the states, some of which regulate parts of the process while others do not.

As the industry was lobbying Congress for that exemption -- and ever since -- the notion that most fluids would not be left underground continued to emerge as a recurring theme put forth by everyone from attorneys for Halliburton, which developed the fracturing process and is one of the leading drilling service companies, to government researchers and regulators.

"Hydraulic fracturing is fundamentally different," wrote Mike Paque, director of the Ground Water Protection Council, an association of state oil and gas regulators, to Senate staff in a 2002 letter advocating for the exemption, "because it is part of the well completion process, does not 'dispose of fluids' and is of short duration, with most of the fluids being immediately recovered."

In May, ProPublica heard a similar explanation from the industry-funded American Petroleum Institute.

"Hydraulic fracturing operations are something that are done from 24 hours to a couple of days versus a program where you are injecting products into the ground and they are intended to be sequestered for time into the future," said Stephanie Meadows, a senior API policy analyst who has been closely involved in fracturing legislation issues. "I don't see the benefit of trying to take that sort of sequestration type activity and applying it to something that is temporary in time."

Asked how much fracturing fluid can remain underground, and whether it could be as high as 30 percent, the figure that was still being included in government reports earlier this year, Meadows said: "I guess I didn't know that the statistics are that high."

Neither the American Petroleum Institute nor the Ground Water Protection Council responded to requests for further comment.

EPA officials maintained in 2005, and say now, that the volume of fluids left underground had little to do with its opinion that hydraulic fracturing for gas wells is not the same as underground injection. They say that distinction is because the primary function of the two types of wells is different: Gas wells are for production processes, while most EPA-regulated underground injection wells are intended for storage.

But Stephen Heare, director of the EPA's Drinking Water Protection Division in Washington, said that both the circumstances and the drilling technology have evolved. When asked to explain how hydraulic fracturing today is different from other forms of underground injection, he said the bottom line was simple.

"If you are emplacing fluid, it does not matter whether you are recovering 30 percent or 65 percent of it, if you are emplacing fluids, that is underground injection," Heare said. "The simple explanation for why hydraulic fracturing is different from other injection activities," he added, is that hydraulic fracturing "is exempt from regulation under the Safe Drinking Water Act."

The argument that fracturing should not be regulated by the EPA became prominent in the 1990s, after the EPA said that fracturing lay outside the scope of the Safe Drinking Water Act, because the primary purpose of gas wells was energy production, not fluid disposal.

A 1997 Alabama lawsuit challenged that position, and the 11th Circuit Court of Appeals ruled against the EPA.

In that decision, the judges wrote that "According to the state agency, hydraulic fracturing is not underground injection because it does not result in permanent subsurface 'emplacement' of the fluids, as these fluids are pumped out of the ground before methane gas is extracted out of the well." But the judges called that assertion "untenable" and ordered the EPA to regulate fracturing in Alabama under the Safe Drinking Water Act. They also ordered the EPA to more clearly define fracturing as a type of underground injection, a move that could have paved the way for regulation in other states as well.

But in 2005, before such regulation could happen, Congress stepped in and gave hydraulic fracturing its special exemption from the Safe Drinking Water Act.

When Congress voted for the exemption, it referred to a 2004 EPA report, which concluded that fracturing did not pose a threat to drinking water. That report, which has since been criticized as incomplete, said that while some of the fracturing fluids remained underground, "Most of the fracturing fluids injected into the formation are pumped back out of the well along with groundwater and methane gas."

Lee Fuller, vice president of government affairs for the Independent Petroleum Association of America, said that the emphasis on wastewater removal was made to help legislators understand how fracturing was different from underground injection, but that those legislators also knew that much of the water stayed underground when they voted for the exemption.

"The EPA study said there was a certain amount of the water that does stay in the fractured formation. That information was known," he said, adding that more of the water may seep out over the life span of the well. "So I think there was an understanding of it on the part of the proponents of the proposal."

In the 2004 report, the EPA said as much as 59 percent of fracturing fluids can remain underground. A 2009 Department of Energy report titled Modern Shale Gas put that figure at 30 to 70 percent, but emphasized that most wells fall into the lower end of that range, explaining that "the majority of fracturing fluid is recovered in a matter of several hours to a couple of weeks."

Just six months ago that point was reiterated in testimony before the House Committee on Natural Resources, when the Interstate Oil and Gas Compact Commission repeated a statement that former Alabama state geologist Donald Oltz made in the 1997 Alabama court case: "Almost all hydraulic fracturing fluid is recovered to the surface after a hydraulic fracturing operation."

That statement contrasts sharply with the latest reports from regions where gas drilling is on the upswing.

Spokesmen for Cabot Oil and Gas, Range Resources and Fortuna Energy -- three of the most active companies developing gas resources in the Marcellus Shale -- say that more water is trapped underground in newer drilling areas because the "tight shale" that is loath to give up the gas is likely to hold on to the fluids too.

"It's not like you pump a volume of water into the frack and then it gives you that volume back," said Ken Komoroski, a spokesman for Cabot Oil and Gas, who says only 15 to 20 percent of the fluid comes back out. "Most of the water and sand stays in the formation compared to in other geologic formations."

In Pennsylvania, where regulators had once predicted that drilling in the Marcellus would produce about 19 million gallons of wastewater per day, that estimate has been revised to just a fraction of that volume, largely because so much of the fluid is remaining underground.

Range Resources now reuses 100 percent of the wastewater it extracts from its Pennsylvania wells by diluting it with fresh water and using it to drill more wells, said spokesman Matt Pitzarella. Range has been able to do that, Pitzarella said, in part because it's extracting only 20 percent of the 4 million gallons it pumps underground for each of its wells.

Gas industry officials say the amount of fluids they leave behind in their wells should have no bearing on whether hydraulic fracturing is or is not regulated by the federal government. What's important is managing the risk, says the Independent Petroleum Association's Fuller, a job he says the industry is doing very well without additional oversight.

"You are wrapping yourself around a distinction of whether something should or should not be regulated under the Safe Drinking Water Act as opposed to whether something does or does not pose an environmental risk," said Fuller, who asserts that despite numerous reports of contamination in drilling areas, the fracturing process has never been conclusively proven to be the cause.

Regulation, Fuller said, "may shut down natural gas drilling for a long time, but it is not going to make the environment any better."

It will fall to Congress -- and then to the EPA -- to decide whether that is truly the case. Sponsors of the Frack Act hope for a vote this spring. If it passes, and if the EPA finds reason to change the conclusions it reached in 2004, the agency would then have to decide exactly how fracturing will be addressed by the Safe Drinking Water Act.

"The thinking we did then, the study that we did then, we were really looking at a different set of circumstances," said Heare, the EPA's Drinking Water Protection Division director. "The agency has not investigated the impacts of hydraulic fracturing in other settings such as shale gas production and at this time is unable to quantify the potential threat."

New York City Calls for Drilling Ban in Watershed, Rejects State Study

2009-12-24T15:47:46-05:00

by Joaquin Sapien and Abrahm Lustgarten and Christopher Flavelle, ProPublica -

After months of warning signs, New York City officials have called for a ban on natural gas drilling within the city’s 2,000-square-mile upstate watershed and urged Albany to withdraw its controversial draft environmental review for drilling across the state.

The move follows the completion of a yearlong study by a private consulting firm commissioned by the city, which found that "gas drilling poses unacceptable risks to the unfiltered drinking water supply for nine million New Yorkers." It sets up a confrontation between the city, which says any degradation of its unfiltered water supply could cost upwards of $10 billion to fix, and Gov. David Paterson, who has said the drilling would be an important part of the state’s economic recovery.

The city announced its position following the release of a consultant’s report, commissioned by city’s Department of Environmental Protection, which found that the chemicals injected into the ground as part of the drilling process known as hydraulic fracturing could make their way to groundwater and contaminate water reservoirs. It cautioned that the wastewater produced from the process posed a similar risk.

Gas development, the report said, could mean 6,000 wells drilled in the watershed and brings a "risk of exposing watershed residents and potentially NYC residents to chronic low levels of toxic chemicals."

The report also found that the fracturing process, which happens under very high pressure, could spread subsurface contamination and alter the natural flow of deep groundwater. It raised concerns that the disruption from the process could damage the tunnels that bring drinking water to the five boroughs.

The city’s investigation as well as a statewide environmental review follow a lengthy investigation by ProPublica, which found that state environment officials may not be prepared to handle the effects of the drilling, and raised early questions about how drilling development could impact New York City’s water supply.

Mayor Michael Bloomberg had declined to take a firm stance on the issue until the report was completed, but has now submitted the city’s comments to the state Department of Environmental Conservation in time to meet Albany’s Dec. 31 deadline for public review of the drilling plan.

"The mayor very clearly said that if our analysis were to determine that [drilling] should be prohibited – and now it has – we would fight it," said Marc LaVorgna, a spokesman for Bloomberg. "It’s clear that it’s a risk that cannot be taken and drilling cannot be permitted."

At a press conference held yesterday, Gov. Paterson said that his office was aware of the mayor’s position, and that his comments would be considered during public comment period for the state’s draft environmental review on drilling released in September. The public comment period was extended from November to the end of December in response to uproar from environmentalists, politicians and concerned residents, and to allow New York City the time to complete its review.

"This is the time when the public, the mayor and any other advocate can try to persuade us that this decision needs to be reversed," said Paterson.