by Abrahm Lustgarten
On a cold, overcast
afternoon in January 2003, two tanker trucks backed up to an injection well
site in a pasture outside Rosharon, Texas. There, under a steel shed, they
began to unload thousands of gallons of wastewater for burial deep beneath the
earth.
The waste – the byproduct of oil and gas drilling –
was described
in regulatory documents as a benign mixture of salt and water. But as the
liquid rushed from the trucks, it released a billowing vapor of far more
volatile materials, including benzene and other flammable hydrocarbons.
The truck engines, left to idle by their drivers, sucked the
fumes from the air, revving into a high-pitched whine. Before anyone could
react, one of the trucks backfired, releasing a spark that ignited the
invisible cloud.
Fifteen-foot-high flames enveloped the steel shed and
tankers. Two workers died, and four were rushed to the hospital with burns over
much of their bodies. A third worker died six weeks later.
What happened that day at Rosharon was the
result of a significant breakdown in the nation’s efforts to regulate the handling
of toxic waste, a ProPublica investigation shows.
The site at Rosharon is what is known as a “Class 2” well. Such
wells are subject to looser rules and less scrutiny than others designed for
hazardous materials. Had the chemicals the workers were disposing of that day
come from a factory or a refinery, it would have been illegal to pour them into
that well. But regulatory concessions won by the energy industry over the last
three decades made it legal to dump similar substances into the Rosharon site –
as long as they came from drilling.
Injection wells have proliferated over the last 60 years, in
large part because they are the cheapest, most expedient way to manage hundreds
of billions of gallons of industrial waste generated in the U.S. each year. Yet
the dangers of injection are well known: In accidents dating back to the 1960s,
toxic materials have bubbled up to the surface or escaped, contaminating aquifers that store supplies of drinking
water.
There
are now more than 150,000 Class 2 wells in 33 states, into which oil and
gas drillers have injected at least 10 trillion gallons of fluid. The numbers have increased rapidly in
recent years, driven by expanding use of hydraulic fracturing to reach
previously inaccessible resources.
ProPublica analyzed records summarizing more than 220,000
well inspections conducted between late 2007 and late 2010, including more than
194,000 for Class 2 wells. We also reviewed federal audits of state oversight
programs, interviewed dozens of experts and explored court documents, case
files, and the evolution of underground disposal law over the past 30 years.
Our examination shows that, amid growing use of Class 2
wells, fundamental safeguards are sometimes being ignored or circumvented. State
and federal regulators often do little to confirm what pollutants go into wells
for drilling waste. They rely heavily on an honor system in which companies are
supposed to report what they are pumping into the earth, whether their wells
are structurally sound, and whether they have violated any rules.
More than 1,000 times in the three-year period examined,
operators pumped waste into Class 2 wells at pressure levels they knew could
fracture rock and lead to leaks. In at least 140 cases, companies injected
waste illegally or without a permit.
In several instances, records show, operators did not meet
requirements to identify old or abandoned wells near injection sites until waste flooded back up to the
surface, or found ways to cheat on tests meant to make sure wells aren’t
leaking.
“The program is basically a paper tiger,” said Mario
Salazar, a former senior technical advisor to the Environmental Protection Agency
who worked with its injection regulation program for 25 years. While wells that
handle hazardous waste from other industries have been held to increasingly
tough standards, Salazar said, Class 2 wells remain a gaping hole in the
system. “There are not enough people to look at how these wells are drilled …
to witness whether what they tell you they will do is in fact what they are
doing.”
Thanks in part to legislative measures and rulemaking dating
back to the late 1970s, material from oil and gas drilling is defined as
nonhazardous, no matter what it contains. Oversight of Class 2 wells is often relegated
to overstretched, understaffed state oil and gas agencies, which have to balance
encouraging energy production with protecting the environment. In some areas,
funding for enforcement has dropped even as drilling activity has surged,
leading to more wells and more waste overseen by fewer inspectors.
“Class 2 wells constitute a serious problem,” said John
Apps, a leading geoscientist and injection expert who works with the U.S.
Department of Energy’s Lawrence Berkeley National Laboratory. “The risk to
water? I think it’s high, partially because of the enormous number of these
wells and the fact that they are not regulated with the same degree of
conscientiousness.”
In response to questions about the adequacy of oversight, the
EPA, which holds primary regulatory authority over injection wells, reissued a
statement it supplied to ProPublica for an
earlier article in June.
“Underground
injection has been and continues to be a viable technique for subsurface
storage and disposal of fluids when properly done,” a spokesperson wrote. “EPA
recognizes that more can be done to enhance drinking water safeguards and,
along with states and tribes, will work to improve the efficiency of the
underground injection control program."
Some at the EPA and at the Department of Justice, which prosecutes
environmental crimes, say the system’s blind spots suggest that many more violations
likely go undiscovered – at least until they mushroom into a crisis.
That’s what happened at Rosharon.
The accident prompted the EPA to examine what else had been
dumped at the site, ultimately exposing
a scheme by a company that was not involved in the explosion, Texas Oil and
Gathering, to pass off deadly chemicals from a petroleum refining plant as
saltwater from drilling.
The switch saved the company substantial fees by allowing it
to dispose of the material in a Class 2 well, instead of a more stringently controlled
well for hazardous waste, federal investigators said.
Texas
Oil and Gathering’s owner and operations manager were convicted of conspiring
to dump illegal waste and violating the Safe Drinking Water Act. Both declined to comment for this article.
Texas officials
acknowledged that they had not looked beyond the paperwork submitted by the
operators using the well. The delivery trucks weren’t inspected; the wastewater
was not sampled.
“Staff had no
reason to believe at the time that such testing was necessary at this
facility,’’ Ramona Nye, a spokeswoman for the Railroad Commission of Texas,
which regulates the oil and gas industry activity in the state, wrote in an
email. “The likelihood of unpermitted material being disposed of is low.’’
William Miller, the EPA’s chief investigator on the case,
points out that the only reason anyone was held accountable for
injection-related violations was because the site blew up.
“If you can get the stuff down the well how is anyone ever
going to know what it was?” said Miller, who retired from the EPA in 2011.
“There is no way to recover it. It’s an easy way to commit a crime and not have
any evidence left of it afterwards.”
States and Industry Resist
Environmental Protections
One reason that Texas Oil and Gathering was able to dump
toxic waste for years without getting caught is that environmental regulations
governing how the oil and gas industry disposes of material underground were
weakened almost as soon as they were written.
A series of injection accidents beginning in the 1960s – involving
pesticide waste in Colorado, dioxins in Beaumont,
Texas, and drilling waste that spread for miles through a drinking water
aquifer in Arkansas – prompted lawmakers to impose tougher rules on
injection wells.
Wells were divided
into classes, depending on the source of the waste they handled. Class 1 wells
for chemical, pharmaceutical and other industrial wastes, along with Class 2
wells for the oil and gas industry, were subjected to tough controls under the Safe
Drinking Water Act of 1974. From the start, the EPA says, oil and gas waste was
treated as less toxic than waste from other industries, but all such material
was seen as dangerous to drinking water.
Companies drilling the wells were required to do geological
modeling to ensure that surrounding rock layers would not allow waste to escape
through fissures or fault lines. They also were required to check for the
presence of other wells that could be a conduit for contamination. The EPA set baseline standards and
mandated periodic inspections for defects. In many cases, states oversaw their
implementation.
The ink had barely dried on the new regulations when the oil
and gas industry – aided by sympathetic state regulators who thought
their existing oversight was sufficient – began arguing that its waste
should be treated differently.
Industry officials lobbied for state oil and gas agencies,
some of which already had rules in place, to oversee Class 2 wells, not federal
or local environmental officials. Some argued state energy regulators had
greater expertise in well construction and regional geology.
In 1980, California Rep. Henry Waxman sponsored a measure that
allowed the EPA to delegate authority to oversee Class 2 injection to state oil
and gas regulators, even if the rules they applied varied from the Safe
Drinking Water Act and federal guidelines.
A few years later, Dick Stamets, New Mexico’s chief oil and
gas regulator at the time, told a crowd of state regulators and industry representatives
that the Waxman amendment was a biblical deliverance from oppressive federal
oversight for the drilling industry.
“The Pharaoh EPA did propose regulations and there was chaos
upon the earth,” Stamets said. “The people groaned and labored, and great was
their suffering until Moses Section 1425 (the Waxman amendment) did lead them
to the Promised Land.”
In the late 1980s, the EPA moved to impose more stringent
measures on injection wells after Congress banned injection of ”hazardous” waste.
The new rules barred underground dumping unless companies could prove the
chemicals weren’t a health threat. To earn permission to inject the waste, companies would have to conduct exhaustive
scientific reviews to dispose of hazardous materials, proving their waste
wouldn’t migrate underground for at least 10,000 years.
The energy industry moved preemptively to shield itself from
these changes, too. The Safe Drinking Water Act prohibited the EPA from
interfering with the economics of the oil and gas industry unless there was an
imminent threat to health or the environment. The industry argued that its waste
was mostly harmless brine and that testing and inspecting hundreds of thousands
of wells for waste that would qualify as “hazardous” would delay drillers or
cost them a fortune.
“It would have been crippling to U.S. oil and gas
production,” said Lee Fuller, vice president of government relations for the
Independent Petroleum Association of America. Fuller was a former staff member for
the Senate Environment and Public Works Committee, whose ranking member at the
time, the late Texas Sen. Lloyd Bentsen, led the fight against the hazardous
waste rule. “So yes, the industry was very aggressively seeking some mechanism
to address those consequences.”
Bentsen had won the industry a temporary reprieve in 1980 by
persuading Congress to redefine any substance that resulted from drilling
– or “producing” – an oil or gas well as “non-hazardous,” regardless of
its chemical makeup, pending EPA study. In 1988, the EPA made it permanent,
handing oil and gas companies a landmark
exemption. From then on, benzene
from the fertilizer industry was considered hazardous, threatening health and underground
water supplies; benzene derived from wells for the oil and gas industry was not.
The effect was that the
largest waste stream headed for underground injection, that from the oil and
gas industry, was exempted from one of the most effective parts of environmental
rules governing hazardous waste disposal.
“A blanket exemption without any sense of
what the actual chemistry of these wastewaters is, is very concerning,” said
Briana Mordick, a geologist at the Natural Resources Defense Council.
Other protections also began
to unravel, widening the gap between Class 1 and Class 2 well regulations. Both
regulators and the industry regularly refer to drilling waste as “salt water”
even though, according to a 2002 EPA internal training document obtained by ProPublica, “on any given day, the injectate
of a Class II-D well has the potential to contain hazardous concentrations of
solvents, acids, and other… hazardous wastes.”
Once the wastes were defined as nonhazardous, there was
little justification for holding Class 2 wells to the same rules as other waste
being injected deep underground.
Today, for example, Class
1 wells for hazardous waste are tested for pressure continuously and are
supposed to be inspected for cracks and leaks every 12 months. Oil and gas
wells – though the goal is to inspect their sites annually – have to be tested
only once every five years.
Injection wells are known to cause earthquakes, so Class 1
wells usually have rigorous seismic and geologic siting requirements. Often, Class
2 wells do not. An EPA staff member might spend an entire year reviewing an
application for a new hazardous waste well. Class 2 wells are often permitted
in bulk, meaning hundreds can be green-lighted in a matter of days.
Where Class 1 hazardous waste is injected, companies have to
inspect a two-mile radius for old wells, making sure contaminants will have no avenue
to shoot back up into drinking water aquifers or to the surface. The minimum
standard for oil and gas companies is to inspect within 400 yards, even though
it is widely believed, according to internal EPA memorandums obtained by
ProPublica, that such a rule is arbitrarily defined, runs against “much
existing evidence” and “may not afford adequate protection” of drinking water.
EPA officials
acknowledge that their Class 1 regulations represent the best practices to keep
water safe and that the risk of a Class 2 well leaking is no different than the
risk of a Class 1 well leaking. The contrast in regulations reflects “varying
legal authorities, not varying levels of confidence,” an agency spokeswoman wrote
in an email, referring to the mandate not to let environmental rules interfere
with the nation’s drilling progress.
State injection regulators counter that much drilling-related
waste is put in the same geologic formations that produce oil and gas, in which
contaminants like benzene naturally occur. The water close to these wells is
often already undrinkable, they say, so lesser protections make sense.
According to the EPA’s most
recent inventory, the number of Class 2 wells is near an all-time high.
Oklahoma, Texas, Kansas and
California use tens of thousands of Class 2 wells to push out oil and gas or dispose
of fracking fluids and “produced” water, as the waste derived from drilling is
called. In North Dakota, injection permits have increased tenfold, with more wells being permitted in one
month – September 2011 –than is typical in an entire year. New Mexico
issued twice as many permits last year as it did in 2007. Ohio injected twice
as much waste in 2011 as it did in 2006 and is evaluating applications for dozens
of new injection sites. largely for waste exported by Pennsylvania and New
York, where such wells are deemed unsafe.
As much as 70 percent of the
waste destined for Class 2 facilities would be considered toxic if it were not
for the loopholes in the law, according to Wilma Subra, a chemist and activist
who sits on the board of STRONGER,
a partnership of oil and gas industry representatives and state regulators
aimed at bolstering state standards.
Recently, Stark
Concerned Citizens, an anti-drilling group, asked Ohio regulators why
radioactive materials such as radium weren’t identified or disclosed when
injected into Class 2 wells.
“The law allows it,”
Tom Tomastik, a geologist with
Ohio’s Department of Natural Resources and a national expert on injection well
regulation,
replied in a Sept. 17 email. “It does not matter what is in it. As long as it
comes from the oil and gas field it can be injected.”
Well Operators Game
Safety Tests
When Carl Weller showed up, shovel in hand, at a Kentucky
farm field dotted with injection wells in June 2007, he was acting on a
tip. Weller, a contracted EPA injection
inspector, was an expert in testing for what regulators call “mechanical
integrity,” using air pressure to check if wells have leaks or cracks.
Such tests are among the only ways to know whether cement
and steel well structures are intact, preventing brine and other chemicals from
reaching drinking water.
Using his shovel, Weller
dug around the top of a well, unearthing the steel tubing near the surface. A
few inches down, he came across an apparatus he had never seen before: A
section of high-pressure tubing ran out of the well bore and connected to a
three-foot-long section of steel pipe, sealed at both ends. The apparatus
appeared designed to divert air pumped into the well into the pipe instead,
making the well test as if it were airtight.
“The only
reason that I know of that that device would be installed would be to perform a
false mechanical integrity test, more than likely because the well itself would
not pass,” Weller testified in 2009 as part of a case against the well’s
operator. The EPA did not make Weller available to comment for this article.
When EPA
inspectors kept digging, they found the buried devices on 10 more wells.
The case
stunned regulators. Weller had been inspecting the site’s injection wells, which
were used to enhance the recovery of oil, for the better part of a decade, certifying
them as safe. After the EPA’s
discoveries, workers at the company that operated the wells, Roseclare Oil, accused its manager, Daniel Lewis, of having conspired
to cheat the tests for much of that time.
In 2009, Lewis
was convicted of a felony charge for gaming the
safety tests on Roseclare’s wells and was sentenced to 3 years probation and a
$5,000 fine. He maintains his innocence, saying the wells were rigged by his
father, who ran the company’s local operations until his death, but said such
practices were typical in Kentucky’s oil and gas industry. “I’d say it’s
pretty common,” said Lewis, whose probation was commuted in 2011. “But it’s not something people go around
talking about either.”
From Lewis’ perspective, injection well operators
sometimes have little choice but to try to fool inspectors. Many wells are
decades old and were drilled before the current regulations were written. Some are
decrepit, their cement aging and cracked. They also can’t be easily – or
cheaply – repaired.
Lewis, who is now a part-owner of Roseclare and continues
to run its operations, said that before wells were due for EPA inspections he
would pretest them himself. If one failed, he’d enter problem-solving mode,
prepping the site for the EPA’s arrival. Two of his employees testified that he
ordered them to fabricate and install the diverters.
“You go and work in it and try to get it to hold and it won’t
hold,” Lewis said of the wells. “What are you going to do? It’s kind of a ‘Don’t
ask, don’t tell.’”
Randy Ream, the Assistant U.S. Attorney for Kentucky’s
Western District who prosecuted the case against Lewis, called his scheme unusually
elaborate but agreed that efforts to get around the rules for injection wells are
common. Sometimes, he said, they result in the contamination of private
drinking water wells.
“We have people who have constructed wells that are not
certified injection wells, or we have people who will put their brine in a tank
and carry it over and put it in somebody else’s well,” Ream said. “One guy, he’s got oil coming out of his
shower head.”
“There is just so much brine,” Ream added, “and you have to
get rid of it.”
So Many Wells, So Few
Inspectors
One obstacle to more effective enforcement in Kentucky and
elsewhere, Ream said, is that regulators cannot always keep up with well tests
and inspections.
According to EPA records, Kentucky has 3,403 Class 2 wells,
which are supposed to be tested for mechanical integrity once every five years.
But since 2007, an average of just 253 wells a year have been tested, less than
half as many as there should have been to remain on schedule.
A spokeswoman for the EPA’s regional office in Atlanta said in
an email that only half of Kentucky’s injection wells are actively used and only
active wells can be tested. She said mechanical integrity tests are performed
on each well every 36 months, but did not address the discrepancy between this
schedule and the number of tests reflected in EPA data.
The EPA employs just six people to check its wells across
the southeast, not just in Kentucky, but in Tennessee and Florida, too. Those
same people are also responsible for working with state inspection programs in
North and South Carolina, Georgia, Alabama and Mississippi, which have their
own inspection staffs.
Most states aim to visit injection sites at least once a
year, and some meet or exceed that schedule, EPA records show. Ohio, for
example, recently added staff dedicated exclusively to injection oversight and visits
its active injection sites every 12 weeks. (Ohio also insists that Class 2
wells meet many of the more stringent testing and permitting regulations it
uses for Class 1 hazardous waste wells.)
“Ohio’s [rules] are based on what we felt we needed to
develop to continue to alleviate any concerns,” said Tomastik, of Ohio’s Department
of Natural Resources. “Obviously without regulatory presence in the field, the
operator is not concerned about operating within the requirements.”
But understaffing seems to be endemic across drilling states,
especially where state regulatory agencies are responsible for checking both
producing oil and gas wells and injection wells for waste or to enhance
production.
In Montana,
EPA auditors noted that inspectors are choosing which wells to inspect and
have a “significant” workload. In
North Dakota, EPA auditors also
noted the pressures of “exponential” growth and an “increasing
workload.”
To meet the goal of inspecting each well annually, Texas inspectors
would have to visit eight wells a day, every day, including Sundays and
Christmas. That’s after Texas’ Railroad Commission hired 65 staffers last year to
help inspect the state’s 428,000 wells.
Nye, the commission’s spokeswoman, said the state had
sufficient funding and inspected each of its commercial disposal wells twice
last year.
“The
Commission has a stringent and comprehensive review process for these wells,”
Nye wrote in an email. “Railroad
Commission staff work diligently to ensure saltwater disposal wells are not and
will not be a problem.”
But inspectors don’t check on private disposal wells, which are
far more numerous, with the same regularity. Nor do they keep a schedule for
when officials should conduct such visits.
Other states are struggling under similar burdens. In
Wyoming, inspectors would also have to check eight wells a day for each well to
be checked once a year – a pace possible if wells are clustered together,
experts said, but otherwise difficult to achieve. In West Virginia and Kansas,
inspectors would have to check seven wells per day.
Visiting injection wells often ranks low among inspectors’ priorities
unless there is an accident or spill, according to a 2007 Texas
auditor’s report. The most urgent responsibility for regulators, beyond
responding to emergencies, is typically overseeing the development of new oil
and gas wells.
The result is that several years can pass between inspections
of many injection well sites. In 2010, state regulators visited less than half of
the Class 2 sites that a federal well inventory shows they were responsible for
monitoring, ProPublica’s analysis showed. EPA inspectors checked on such wells even
less frequently, visiting less than one-quarter of the sites under their
jurisdiction in 2010.
“I don’t give a darn whether you have federal regulations,
or a squeaky clean permitting system,” said Bill Bryson, a member of the Kansas
Geological Survey and the former head of Kansas’ oil and gas commission. “If
you don’t have somebody going out and looking at the wells it doesn’t do any
good, and if you don’t have the right people looking … it doesn’t do any good
either.”
Much of the problem with oversight comes down to money,
critics say. In some states, budgets and staff for oil and gas agencies have
dropped relative to the number of new wells being drilled over the last nine
years.
Kansas employs about the same number of inspectors as it did in 2003, even though it drills four times as many new wells. New drilling has nearly
doubled in Louisiana over the same period, but the state’s enforcement staff has
remained static and its oil and gas budget has increased modestly. In Illinois,
drilling has nearly doubled, while the number of enforcement staff has been
reduced.
Since the Underground Injection Control program is run under
a federal mandate, states rely partly on money from the EPA to fund oversight
and enforcement. Federal dollars make up 20 percent of Texas’ budget, for
example. But in the last 22 years, the EPA’s annual operating budget for
injection has remained about the same: $10 million. Taking inflation into
account, funding has dropped at least 40 percent from 1990 to 2012, though the
regulations for all well classes have only grown more complex.
“The UIC program has been flat funded for years,” said Dan
Jarvis, the field operations manager for Utah’s Division of Oil, Gas and Mining.
“With more manpower, obviously you
put them on the ground and you’re going to have better compliance. Our field
people are some of the greatest guys going, but they are overworked.”
The EPA declined to disclose the operating budget for regional
offices that monitor waste wells under federal jurisdiction or oversee state injection
programs. Documents
show, however, that in 2011 the agency suspended its travel budget for
visits to some of the states that have the largest injection programs,
including Louisiana, Texas and Oklahoma.
“Do you think we are doing more now than we were doing 30
years ago? No, there is no money,” said Salazar, the former EPA injection
expert. “There are not enough people to know what is going on. It is the ideal
storm for industry. Less and less people, more and more things that the EPA has
to do.”
Ultimately, much of the responsibility for meeting EPA
standards falls to companies themselves. Some operators routinely exceed the
minimum requirements of injection regulations, says Hughbert Collier, who runs
a Texas environmental engineering firm that consults with injection well
operators. They conduct their own integrity tests every year and make sure
employees visit well sites once a month.
But operators inclined to cut corners have little to hold
them back.
“What most people would be surprised about is that regulators
don’t have real good control over everything that goes on in the regulated
community,” said Miller, the former EPA criminal investigator in Texas. “Most
of our environmental law requires self-reporting and that requires honest
people.”
When violations are identified – such as the 140 times
waste was illegally injected and noted in the regulatory reports – the
consequences can be minimal, and only in rare cases do transgressions rise to
the level of criminal prosecution. In the three years of national data reviewed
by ProPublica, which included more than 24,000 formal notices of violations, only
one case was referred to criminal investigators.
Usually, violations result in citations or informal warnings.
If operators do not address violations, then modest fines may be levied; in
some cases, wells are temporarily shut down. There is no central source of
information on the size of fines, but an audit of Louisiana’s
injection program provides a glimpse: In 2011, the state collected an
average of $158 for each violation.
After three deaths, two federal worker safety investigations
and a criminal prosecution, few injection sites nationwide received as much
regulatory scrutiny as those in Rosharon, Texas. Yet, despite all the attention, the wells
there later failed on the most basic level.
On Feb. 17, 2010, thousands of gallons of waste that had
been deposited into these wells gurgled
to the surface in what the Railroad Commission described as a “breakout.” Materials
injected far below the earth had managed to migrate back up to the surface,
perhaps through an old well missed by regulators.
As of this June, investigators were still analyzing whether
the chemicals injected underneath the site had reached water supplies.
Jesse Nankin
contributed research for this report.