Scientific and government research indicates that fracking can cause earthquakes in two ways:

1. Primarily, during the fracking process: "[Earthquakes] were caused by fluid injection during hydraulic fracturing in proximity to pre-existing faults."
2. Secondarily, via the disposal of fracking wastewater via underground injection.

And that is being borne out by increased earthquakes in shale plays where oil and gas development is occurring, like Texas and Ohio.

These aren't just small quakes

Although fracturing-related earthquakes are chronic, they were thought to be minor. But new research is showing that they can be quite large and damaging. The focus of the study, a 5.7 magnitude quake near Prague, Oklahoma, damaged 14 homes and other structures in the area.

States are ignoring the issue

Despite the increasingly apparent threat posed by fracking-related earthquakes, many states are ignoring the issue:

"Nine months after a National Academy of Sciences panel said oil and gas regulators should take steps to prevent man-made earthquakes, officials in key states are ignoring quake potential as they rewrite their drilling rules."

Find earthquakes near you

The USGS tracks all earthquakes (man-made and natural) and makes that information readily available here.

Water source a deciding factor in property value

A Duke University and Resources for the Future study found that the most significant factor in the impact of oil and gas development near your property is whether your water is piped in or sourced on-site from a well.

Based in Washington County, PA the study found that property with on-site wells lost 13% of their value.

Another study by Integra Realty Resources in Flower Mound, TX looked at the relationship between property value and proximity to wells. It concluded that properties with houses that were less than 750ft away from a drill site experienced an average sales price drop of 2-7%.

Mortgages

Oil and gas leases have also made it more difficult to get a new mortgage or refinance and can even constitute a technical default on an existing mortgage. Depending on the site of the well, leases can also affect neighbor's mortgages due to setback violations or requirements.

Last year, Jack and Carol Pyhtila spent several weeks working to refinance the mortgage on their roughly 30 acres in Tompkins County, N.Y. But when they arrived to sign the mortgage, the lender, Visions Federal Credit Union, had taken a closer look at the lease on their land and revoked its offer, said Mr. Pyhtila, 72.

Of course, making it more difficult to get a mortgage isn't going to make selling a property with a lease any easier.

Oil boom pushes seniors out of homes

The rush to drill has led many single young men and family men to places like Williston, ND for a shot at financial comeback. 

As the Williston Herald reported, apartments that used to rent for $400 a month five years ago are going for four times that today, and homes that sold for $60,000 are now on the market for $200,000.

While this may sound like a dream for local residents, some, particularly senior citizens and people on fixed income, have found that they are no longer able to afford their rent and have been forced to move. 

Hardrock mines produce millions, sometimes billions of tons of mine waste, which frequently contain toxic materials such as arsenic, mercury, cadmium and lead. Unfortunately, it has become a common industry practice to use lakes, streams and wetlands for mine waste disposal.

The problem: there are two loopholes in regulations adopted by the EPA and Army Corps of Engineers (Corps) that allow many hardrock mines to dispose of mine waste into waterways, destroying fish and other aquatic life.

The first loophole: a 2002 revision of regulations expanded the definition of “fill material” under Section 404 of the Clean Water Act to include mine waste. Section 404 was intended to regulate the placement of rock, soil, clay, sand and other materials normally used in construction related activities, not mining waste.

The second loophole: regulations defining “waters,” allow mine developers to designate natural lakes, rivers, streams, and wetlands as “waste treatment systems,” exempt from the Clean Water Act.

We can close the loopholes, and protect clean water and public health

While it is cheaper for the mining company to dump mine waste in lakes and streams, it is an unnecessary and irresponsible way of doing business. For over 30 years, the mining industry operated without these loopholes.

The good news for people who care about clean water, community health, and abundant wildlife is that EPA and the Corps can close the loopholes with two simple rule changes. First, the agencies should explicitly limit the waste treatment system exclusion to only manmade waters. This was, in fact, how EPA originally interpreted the regulation back in 1980. And second, EPA and the Corps can revise the 2002 definition of “fill” to once again exclude waste disposal.

Spearfish Canyon is a national treasure and vital to the local tourist economy. As stated in a recent editorial by the Rapid City Journal, “Quite literally, there is no other place like it on earth. With tourism the region’s largest industry, protecting Spearfish Canyon ought to be a priority.”

Local community members are opposed to the project, and concerned about the impacts of cyanide leach mining to Spearfish Creek – a prized trout stream. The County denied the companies application for a conditional use permit in 2012 until the State of South Dakota undergoes additional environmental analysis.

The track record of cyanide leach mining has not been good. South Dakota’s Wharf Mine, owned by Goldcorps, has a long history of cyanide spills and water quality violations. South Dakota’s Brohm (Gilt Edge) cyanide leach mine is now a major Superfund site, with severe acid mine drainage.

Exposures to chemicals and pollutants related to oil and gas development may come from multiple sources (e.g., contamination of water sources from leaking waste impoundment pits and tanks or spills of chemicals or wastewater;  air emissions from pits, tanks, compressors, wellheads and other oil and gas infrastructure, spills of chemicals or wastes, etc.).

Many survey respondents indicated that they had concerns about contamination of their drinking water and/or exposure to air emissions from nearby gas development. (Note: The survey did not specifically ask about water concerns, but some survey respondents offered that information. Additionally, some respondents conveyed that information to Earthworks through interviews or initial discussion related to the survey.)

Figure 4.
Symptoms from respondents with water & air tests

Click chart thumbnail for larger view

Earthworks conducted water and air tests at some of the homes of survey respondents. There were 15 survey respondents who had water tested at their homes, and there were 55 respondents who had air tests conducted at their homes.

It is interesting to note, as seen in the chart, that a higher percentage of those who perceived that they had problems with water reported symptoms such as diarrhea and skin issues – symptoms that may be associated to ingesting or bathing in water that contains contaminants. Those who perceived that air exposure to gas-related contaminants was a primary concern more often reported severe headaches and throat irritation, which may be associated with breathing in air contaminants.

The results were complicated by the fact that some of the people receiving water tests also expressed concerns about air exposures (46% reported smelling odors that they associated with gas development), and 43% of those receiving air tests also had water concerns. Therefore, the following analysis does not prove that those receiving water tests had symptoms caused by contaminated water, or that they did not have symptoms related to air exposures.  Nor does it prove that those receiving air tests had symptoms solely related to  air exposures.

The results, however, do suggest that this is an area that bears further scrutiny and research.

The air tests conducted for this project detected a total of 19 chemicals that may cause sinus, skin, ear/nose/mouth, and neurological symptoms, 17 chemicals that may affect vision/eyes, 16 that may induce behavioral effects, 11 that have been associated with liver damage, 9 with kidney damage, and 8 associated with digestive/stomach problems. In addition, the brain and nervous system may be affected by 5 chemicals that were detected, the cardiological system by 5, muscles by 2, and blood cells by 2. The chemicals and their potential health effects (by symptom category) are shown in the table below. Information on potential health effects related to chemicals comes from: Agency for Toxic Substances and Disease Registry (ATSDR) “Toxicological Profiles” (accessed July 30, 2012); and New Jersey Department of Health “Right to Know Hazardous Substance Fact Sheets” (accessed July 30, 2012).

As seen in Figure 1 in the report (and the table below), for most symptoms and in most age groups a higher percentage of the subset living within 1500 feet of an oil and gas facility had symptoms than did the entire age group. For example, 69 % of survey respondents between the ages of 1.5 and 16 who lived within 1500 feet of a gas facility reported throat irriation. Only 57 % of all 1.5-to-16-year-olds reported throat irritation. In sum, while this data analysis does not definitively prove that living closer to an oil and gas facility causes health problems, the data suggest a relationship between distance from facility and occurrence of symptoms.

When the data from air canister samples were broken out by county, we found the highest number of VOCs detected in samples from Washington County (15), Butler County  (15), Bradford County (11), and Fayette County (9). Washington County also had the highest measured concentration of five, and the second highest concentration of 11 VOCs.

Samples from Butler and Bradford counties had the highest concentrations of five and three VOCs, respectively.

Five chemicals were detected in all nine of the samples from Washington County and in the six samples from Butler County: 1,1,2-Trichloro-1,2,2-trifluoroethane, Carbon tetrachloride, Chloromethane, Toluene and Trichlorofluoromethane.

Our results show more VOCs and higher concentrations of the chemicals in Washington County than other counties. This does not necessarily mean that Washington County has worse air quality than other counties in this study. More research would be needed to confirm that, especially given that more samples were taken in Washington than in other counties in our study, thus increasing the chances for detection of VOCs. In addition, the canister samples reflect air quality at one point in time. It is possible that in some places we did not sample when facilities were emitting high concentrations of chemicals, or perhaps the wind was blowing contaminants away from the canisters. 

Yet industry representatives and policymakers seeking to expand drilling often dismiss claims of health impacts as “personal anecdotes” and isolated incidents.

The primary reasons that public health risks posed by increasing gas development can be disputed:

• A lack of established science. Widespread scientific investigation has only recently begun to investigate the relationship between gas development and public health impacts.
• State governments, which are largely responsible for protecting the public from irresponsible oil and gas development, have until recently refused to consider the issue.
• Even as they have become widespread, individual reports of health problems in the gas patch have been continually dismissed as anecdotal by industry and government.

To investigate the connection, between August 2011 and July 2012 Earthworks’ Oil & Gas Accountability Project (OGAP) researched the extent, types, and possible causes of health symptoms experienced by people living in the gas patches of Pennsylvania.

The main conclusions of the project -- Gas Patch Roulette: How Shale Gas Development Risks Public Health in Pennsylvania:

1. Contaminants associated with oil and gas development are present in air and water in many communities where development is occurring.
2. Many residents have developed health symptoms that they did not have before—indicating the strong possibility that they are occurring because of gas development.
3. By permitting widespread gas development without fully understanding its impacts to public health—and using that lack of knowledge to justify regulatory inaction—Pennsylvania and other states are risking the public’s health.

Gas Patch Roulette documents:

• Press release
• Gas Patch Roulette: Summary Report (4 pages)
• Gas Patch Roulette: Full Report (51 pages)

Thanks to federal loopholes unique to the oil and gas industry, state government is the primary regulator of oil and gas development.

So the public is entitled to know, are states doing a good job overseeing the oil & gas development industry?

Breaking All the Rules: The Crisis in Oil & Gas Regulatory Enforcement, demonstrates that states across the country are failing to enforce their own oil and gas development regulations.

The one-year, in-depth research project examined enforcement data and practices in Pennsylvania, Texas, Ohio, New York, New Mexico and Colorado and includes interviews with ex-industry and state agency employees. Read the press release here.

The research produced the national reports, and six state reports focusing on the pertinent state agencies:

• The full report (125 pages with appendices), and the executive summary (13 pages).
• Colorado Oil and Gas Conservation Commission
• New Mexico Oil and Gas Conservation Division
• New York Department of Environmental Conservation
• Ohio Division of Oil and Gas Resources Management
• Pennsylvania Department of Environmental Protection
• Texas Railroad Commission

In addition to these publications, supporting data from the research can be found in the For More Information links below.

Citizen complaints often draw attention to problematic operations that might otherwise go unmonitored for long periods of time. In Pennsylvania, complaints led to the discovery of at least 700 violations between 2007 and 2011. In Texas, 1,997 violations were found as a result of 681 citizen complaints in 2009, alone.

The Railroad Commission (RRC) has stated that “citizens are viewed as extra eyes to help the RRC identify problems.[1] Yet the RRC does not consistently respond to violations identified from citizen complaints. For example, in 2009 RRC took enforcement action for just 4 percent (91) of the 1,997 violations found as a result of complaints.[2] The Sunset Commission stated that this lack of consistency “can contribute to a public perception that the Commission is not willing to take strong enforcement action.”[3] A 2012 Star Telegram editorial stated that “Too many people in Texas see the commission as a servant of and beholden to the oil and gas industry, not as a regulator on behalf of the people of the state.”

According to RRC, all citizen complaints are entered into a database that tracks and stores the complaint information,[4] yet no publicly accessible electronic database of complaints exists on the RRC web site. Beginning in 2012, the legislature required the RRC to publish “quarterly trends of enforcement data, including the number of complaints received and how the complaints were resolved..." on its web site.[5] Cumulative numbers from the first three quarterly reports are shown in the following table. Data from 2007, 2008 and 2009, gathered from other sources, are also included in the table.

Complaints related to oil and gas operations in Texas

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Lack of access to information limits public participation

Citizen do have the potential to be “extra eyes” for RRC, but to be more effective participants in oil and gas enforcement citizens need better access to information. While it is step forward for RRC to be publishing quarterly data on citizen complaints, mere statistics on complaints received and resolved shed very little light on the nature and severity of the problems that citizens are encountering, and whether or not there are patterns of problems occurring (e.g., certain operators that are frequently mentioned, regional hotspots, etc.). Other states provide detailed accounts of citizen complaints. For example, the Colorado Oil and Gas Conservation Commission's (COGCC's) on-line information database enables the public to view all complaints filed with the COGCC. Information in the system includes a description of the complaint, information on the facility in question, and follow-up actions taken by the operator and COGCC.

Citizens can monitor problematic operations or operators, but at the present time it is difficult for the public to identify them. RRC does not have a database of inspections, violations or enforcement actions, so there is currently no simple way for the public to track and find detailed information on violations, enforcement actions and penalties related to oil and gas facilities in their neighborhood or state. Other states Other state agencies provide more information to citizens than the RRC. For example, Pennsylvania's Oil and Gas Compliance Report and Colorado's Oil and Gas Information System contain various types of information on inspections, violations, enforcement actions and complaints. The information is accessible to the public via online databases.

Rider 17 of the 2012-2013 General Appropriations Act required the RRC to publish enforcement data on its web site:

Out of the monies appropriated to the Railroad Commission of Texas for Strategy D.1.2, Public Information and Services, the agency shall publish information about enforcement data on its website, including inspection and enforcement activity, violations and the amount of final enforcement penalties assessed to the operator. The agency shall also make available on its website quarterly trends of enforcement data, including . . . the number and severity of violations sent for enforcement action, the number of violations sent for enforcement action for each Commission rule, and the number of repeat violations found for each operator.[6]

To date, the RRC has been posting quarterly trends of enforcement data. But more detailed enforcement data has not yet appeared on the site.

The RRC should foster relationships with the public by ensuring that violations found as a result of citizens’ complaints receive consistent and strong enforcement. Moreover, to encourage public participation in oversight activities, RRC should increase transparency and public access to electronic oil and gas information on inspections, violations, enforcement actions, penalties and complaints. The system should allow users to view and download data in various spreadsheet formats.

Pennsylvania oil and gas well and inspection statistics

Click chart for larger, footnoted version

In 1987, the Pennsylvania DEP published an Inspection Policy for Oil and Gas Well Activities, which was adopted into the Pennsylvania Code on July 28, 1989. The policy “does not create a duty or obligation upon the Department to conduct a minimum or maximum number of inspections,” but sets forth the intended frequency of inspections, and the circumstances under which a well operator can expect an inspection by the Department.

The policy states that “The Department, its employees and agents intend to conduct inspections at the following frequencies,” and suggests that wells be inspected approximately seven times before a well begins to produce oil or gas, at least once a year thereafter during the production stage to determine compliance with oil and gas statutes, and various other times throughout the life of a well.[1]  New York State's Department of Environmental Conservation (DEC) is nearing the end of an extensive process of reviewing its regulations related to shale gas drilling. Recently, a spokersperson for the DEC said that "the state's draft plan would require at least 13 inspections during each well drilling and completion." This is more stringent than DEP's 1987 inspection policy, which was developed at a time when high-volume hydraulic fracturing and horizontal wells were not yet being used to access oil and gas from shale formations.

DEP is nowhere near keeping up with its 1987 Inspection Policy. There were a 2,843 new wells drilled in Pennsylvania in 2010.[2] Under the policy, there should have been close to 20,000 inspections of those wells. Also, the 61,000 producing wells in 2010 should have each received an inspection. If DEP had been following its adopted policy, it would have performed more than 80,000 inspections. However, in 2010 DEP carried out 15,368 inspections, or just 19 percent the intended inspections laid out in the policy.[3]

It is clear, even to the oil and gas industry, that DEP cannot keep up with its inspection load. At a New York Times Energy Conference held in April 2012, Steve Mueller, president of Southwestern Energy Company, said that "We as an industry have gone to the state of Pennsylvania and said you don't have enough inspectors, you don't have enough people.”[4]

DEP needs to increase the frequency of inspections on new and existing well sites. Until DEP can demonstrate the capacity to oversee existing wells, new drilling permits should not be issued.

In recent years oil and gas development has boomed in Pennsylvania, where more than 19,000 conventional oil and gas wells and more than 5,000 Marcellus shale gas wells have been drilled since 2005. In response to the increase in activity,  DEP quadrupled the size of its enforcement staff to 130 employees, 65 of which are inspectors. In 2011, this number was reportedly increased to 88 inspectors. As will be shown in this fact sheet, DEP’s efforts have not been enough to protect the environment and public health.

“We as an industry have gone to the state of Pennsylvania and said you don't have enough inspectors, you don't have enough people.”[2]

 

--Steve Mueller, president of Southwestern Energy Company

Citizen complaints can be an important barometer of industry behavior, and citizens can provide a crucial early warning of problems at oil and gas sites. In Texas, the oil and gas regulatory agency has stated that “Citizens are viewed as extra eyes to help the RRC [Railroad Commission] identify problems..”[1] In 2009, the RRC received 681 complaints related to oil and gas and found 1,997 violations based on these complaints.[2] In Pennsylvania, complaints led to the discovery of at least 700 violations between 2007 and 2011.

The Texas Railroad Commission publishes quarterly statistics on complaints. Colorado Oil and Gas Conservation Commission (COGCC) publishes complaints statistics in its staff reports, and COGCC's online database enables users to view the 5,000 most recent complaints.

Ohio DOGRM does not publish statistics on citizen complaints relating to oil and gas development. It was only through an information request to DOGRM that Earthworks was able to obtain Ohio citizen complaint data.[3]

Ohio citizen complaints

In Ohio, citizen complaints related to oil and gas operations rose dramatically in 2011.[4] In the years 2008, 2009, 2010, and 2011 DOGRM received 140, 176, 146 and 411 complaints, respectively.

The DOGRM website states that the division responds to questions or complaints within 24 hours either by telephone or in person. But DOGRM does not have a publicly accessible database of complaints, so it is impossible to track the nature of the various complaints, or whether the complaints were resolved in a timely manner and to the satisfaction of those filing them.

Since Ohio does not provide detailed information regarding citizen complaints, it is not clear why complaints more than doubled from 2010 to 2011. Information on citizen complaints—such as information on facilities of concern, nature of the complaint, DOGRM follow-up, and complaint resolution—should be made publicly accessible.

To increase the public's role in oil and gas enforcement, DOGRM must work cooperatively with citizens and dedicate sufficient resources to track and respond effectively to citizen complaints.

Between 2005 and 2011 more than 24,000 oil and gas wells were drilled in Pennsylvania. During that time, there were more than 15,000 violations. Interestingly, since 2008 the number of wells drilled per year has decreased, yet the number of violations per year has more than doubled – from 1,500 in 2008 to 4,069 in 2011.[1]

One of the possible reasons for the recent increase in violations is that there has been an increase in inspections. The following chart, which uses data from DEP’s Oil and Gas Compliance Report system, shows a fairly strong relationship between oil and gas violations and the number of inspections in Pennsylvania. In 2009, inspectors found considerably more violations than other years, and 2005 was a low year for violations. Otherwise, it appears that more inspections result in more violations being found.

Violations and Inspections

Click chart for larger version

The chart also shows that the number of oil and gas rule violations found by Pennsylvania oil and gas inspectors spiked in 2009 and has remained high ever since; 2011 had the most violations of any year in the past decade.

Violations - bad actors abound

Despite an increase in inspections, violations data suggests that the practices of many operators are getting worse, not better, with time. Table 1 shows the twelve operators with the most violations in 2011. All but two (Chief and Anadarko) had more violations in 2011 than in previous years, and many operators have had consistently large numbers of violations for three years running (e.g., Chesapeake, Cabot, Chief, Range, XTO, Ultra).

It should be noted that the operators with the most violations are not necessarily those with the largest number of wells. There are 23 operators in Pennsylvania with more than 1,000 active wells, yet only five of them appear in the following table.

Trends in violations for the top offenders in Pennsylvania

Click chart for larger, footnoted version

Click chart for larger, footnoted version

DEP data also show that many operators repeatedly violate the same rule at different well sites, and from one year to the next.[2] This chart shows the companies that most frequently violated Rule 102.4, which governs erosion and sediment control requirements, in 2010 and 2011. As seen in this chart, Chesapeake had the worst record, with 25 violations of rule 102.4 in 2010, and 35 violations of the rule in 2011. In addition, Cabot, Chief, and Ultra Resources had numerous violations of this rule in 2010 and again in 2011.

The increase in violations in 2011, the pattern of non-compliance among some operators, and the fact that operators violate some rules time-and–time-again makes it clear that DEP’s inspection enforcement actions are not deterring operators from repeatedly breaking the rules and polluting the environment in Pennsylvania.

Prior to 2012, there was no simple way to find statistics related to oil and gas enforcement actions in Texas. As a result of Rider 17 of the 2012-2013 General Appropriations Act, the RRC now has to publish information about enforcement data on its web site, including enforcement activity, violations, the amount of final enforcement penalties assessed to the operator, and a quarterly report that includes a section on enforcement trends.[2]

Information on protested and unprotested enforcement actions can be found in RRC hearings and order files, but this system is extremely cumbersome to navigate. For example, it is not possible to search for protested enforcement actions by date. Meanwhile, unprotested actions are only categorized by hearing date in the Master Default Orders. So one must go through each individual file to find out operator names, which rules were violated, and penalties issued.

Actions not frequent enough to deter violators

Enforcement actions are not taken for every violation - far from it. According the Sunset Commission, the RRC relies on the discretion of each district office to determine which violations should be referred to the legal department for enforcement action, and very few enforcement referrals are made compared to the number of violations identified by RRC field staff.[3] The Sunset Commission found that in 2009 Texas oil and gas inspectors found more than 80,000 violations of state rules, yet field staff forwarded less than 4 percent of these violations to the agency’s central office for enforcement action. In contrast, says the Sunset Commission, the Texas Commission on Environmental Quality forwarded about 20 percent of its 11,000 violations for enforcement action.

Based on our research, it appears that the percentage of oil and gas violations forwarded for enforcement action was actually lower than 4% in 2009. The following table shows that between 2006 and 2010 less than one percent of all violations were referred to RRC enforcement staff. The first three quarters of 2012 showed an increase in enforcement referrals, but still, only slightly more than 2 percent of violations were referred for legal action. It's not clear why there has been a surge in enforcement actions in 2012, nor it is certain that RRC will continue to take actions at this higher rate.

RRC enforcement statistics (2006 - 2010)

Click chart for larger, footnoted version

Compared to some other states, Texas has a low enforcement rate. As seen in the table above, in 2010 RRC district offices made just one enforcement “referral” per 160 oil and gas violations. Meanwhile, that same year Pennsylvania took one enforcement action per 3.3 violations, and Ohio took one enforcement action per 48 violations.[4]

The primary consequence of taking few enforcement actions is that it sends a message to operators that they can break the rules and get away with it. Thus, there is no strong incentive to comply with RRC rules. In its 2011 review, the Sunset Commission found that “. . . the Commission takes relatively few enforcement actions, resulting in a lack of deterrence for future noncompliance. While there is no standard for how many violations should result in a monetary sanction, action should be frequent enough to deter future violations.”[5]

One enforcement action per 160 violations is highly unlikely to motivate oil and gas companies to comply with the Texas oil and gas rules. Perhaps the recent increase in enforcement actions will provide an increased incentive to operators - but this remains to be seen.

Severances and Seals - could be used more effectively

The RRC has an alternative to a full-blown enforcement action. In December 2010, RRC Commissioner Michael Williams told the Sunset Advisory Commission that ". . .lease severance is a valuable tool to enforce our rules, deter future violations and bring operators into quick compliance, without the delay and expense of an enforcement hearing."[6]

The Texas Administrative Code states that, the Commission “may shut in and seal any well if it appears that the operator of a well has violated or is violating any statutes, rules, permits, or orders of the Commission. Prior to shutting in or sealing a well operators are sent a letter by the Commission that instructs them to correct the violation, and provides a date by which compliance must be achieved. If compliance does not occur, the Commission may then seal the well.”

A severance or seal is intended to prevent an operator from producing oil and gas and from transporting oil or gas from a well with a lease. When the violation(s) are corrected, the operator typically pays a $300 fee to obtain a Certificate of Compliance, which must be reissued before the severance or seal can be lifted. In 2008, 1,915 operators paid this reissuance fee, generating close to $1.5 million in revenue for the RRC.[7]

What types of wells get severed or sealed?

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A 2012 investigation by EnergyWire found that the RRC is more likely to sever or seal wells for production violations, e.g., a late or erroneous production report or ‘overproduction’, than for health, environmental or safety violations. RRC told Energywire that the reason more wells are shut down for production than safety problems is that production severances are computer-generated and the agency can look at every well monthly. RRC data obtained by EnergyWire showed that less than 10 percent of the total number of severed or sealed leases were shut down for "field rule violations" –problems found during inspections– in 2010.

As seen in the chart, Earthworks’ analysis of RRC data shows that in 2011 the number of severances and seals applied for field rule violations hit an 11-year low. It’s not clear why there has been such a sharp decline in the use of severances and seals for field rule violations, but the data demonstrate that it is a tool that has been more widely utilized for field rule violations in the past.[8]

How effective are severances/seals?

In the past five years, the RRC issued between 6,000 and 8,500 severances/seals per year.[8]

Click chart for larger version

The power of the severance or seal is that it is supposed to stop production of oil or gas at a well or lease, and consequently operators lose revenue until they can bring the wells back into compliance. The potential loss of revenue should be a motivation to quickly resolve compliance problems. But as seen in the chart, the percentage of resolved severances on oil leases and seals on gas leases has been dropping.[9]

Between 2000 and 2005, between 80 and 84% of severances and seals were resolved (the violations had been corrected and the severance removed). In 2011 there were 8,485 leases that had a severance/seal for a particular violation, and as of April 2012 only 51% of those severances/seals had been resolved.

The drop in resolved severances and seals suggests that operators are becoming less conscientious about coming into compliance once actual production has been cut off. It also suggests a need for follow-up inspections to ensure that the violations that lead to severances/seals are corrected within a certain time-frame. If they are not corrected, the cases should be referred to RRC enforcement for further legal action.

Not all severed/sealed wells stop producing oil or gas

Click chart for larger version

For example, on Oct. 5, 2010 Apache Corporation was sent a certified letter informing the company of a field rule violation. On Jan. 4, 2011 a seal was issued, so production should have stopped. As seen in Chart 26, however, production on Apache’s lease did not stop until July 2011.[FN]

Similarly, in 2003 Aminex USA, Inc. was ordered to pay a $1,000 fine for producing oil from numerous wells on a lease from June 1, 2002 through May 31, 2003, despite the fact that the lease had been severed on May 29, 2002.[FN]

The violations were corrected, but the company failed to obtain a certificate of compliance as required by law, and so production should not have resumed.[FN]

The ability to stop production at wells that are in violation of rules is a powerful enforcement tool that should be more widely applied to encourage compliance with field rule violations. The addition of more enforcement staff to ensure that wells are physically sealed to stop production could increase the effectiveness of severances and seals in Texas.

There are a couple of reasons that production does not necessarily stop following the issuance of a severance or seal. First, these actions do not always involve an inspector going to the site and physically sealing the well to prevent production. In speaking with RRC compliance and field operations staff, we were told that because the agency is understaffed it could be a month or more before inspectors physically get to wells that have been severed—if they make it there at all. RRC was not able to provide a statistic on how many wells are physically sealed.

Second, even when wells are physically sealed, operators sometimes break the seals and continue producing oil or gas or injecting oilfield wastes.

• On November 14, 2003, the main power supply box at an injection well on the Winters Lease was sealed with Commission seal #16970 and tagged for easy viewing. An inspection conducted on January 6, 2004 indicated that the operator “had caused or allowed the Commission seal to be broken at the power supply box.”[FN]
• On March 5 and April 2, 2009, the Posey No. 1A well was found to be open and oil was flowing oil into a tank, in clear violation of a 2007 severance order. On April 7, 2009, an inspector shut in the Posey No. 1A and sealed it with Commission seal # 241006. On July 14, 2009, an inspection revealed that the Commission seal had been removed. A second seal was installed on the well, and an additional seal was installed on top of the oil storage tank. On July 29, 2009, an inspector found that the seal on the oil storage tank had been cut and removed.[FN}

Penalties - too few, and too modest to change behavior?

Prior to 2012, the RRC did not publish easily accessible statistics on penalties assessed for oil and gas violations. However, some information on oil and gas penatlies were found from other sources. For example, the Texas State Auditor reported that, “in fiscal year 2006, the Commission assessed $1.4 million in penalties,” while the Sunset Commission reported that the RRC collected more than $2 million in penalties in 2009.[10]

The RRC is now required by Rider 17 of the 2012-2013 General Appropriations Act to publish “the amount of final enforcement penalties assessed to the operator” on its web site. During the first three quarters of fiscal year 2012, RRC assessed $856,868 in penalties. Over that period 802 violations were referred for enforcement action, which means the average penalty per enforcement referral was $1,070. This is down from 2009 and 2006, when RRC collected an average of $3,600 and $2,800 per enforcement referral, respectively.[10]

According to the Sunset Commission, “the efficient and fair use of penalties plays a key role in deterring and punishing violators, and thus increases compliance.”[11]

The Texas Oil and Gas Association (TXOGA), on the other hand, has argued that penalties won’t necessarily deter future violations because “violations are more likely to result from lack of knowledge of regulations.”[12]

If penalties were used more frequently and effectively, operators would soon learn that it is not acceptable to be ignorant of the rules. This is the argument put forth by the Sunset Commission, which found that “even modest fines for less serious, but frequent violations can substantially affect compliance, especially once word spreads that coming into compliance will no longer suffice to avoid a penalty.”[11]

TXOGA has argued that small fines are not worth the trouble:

. . .efforts to extract penalty amounts from operators may cost as much or more to process/recover by agency staff, thereby wasting agency time and resources. It is likely that seeking a penalty, with the numerous staff resources require to prepare a referral packet, determine where a violation fits within guidelines, preparation of an enforcement letter, preparation and negotiation of a settlement offer, going to hearing, drafting of a proposal for decision, preparing backup for Commission Agenda, and scheduling/considering the proposed penalty, will cost the State more than that gained from the penalty. . . Collection costs of assessed penalties may be one of the reasons violations have been referred for penalties less frequently than hoped for by the Sunset staff. [12]

--Texas Oil and Gas Association

The Texas Oil and Gas Association may have a point. The maximum penalties for some rule violations are so low that it may not make financial sense for the RRC to pursue enforcement actions against violators.

The RRC has taken a partial step toward increasing the penalties levied against oil and gas operators. In February 2012 the RRC proposed a rule (3.107) to increase the suggested minimum penalty for most rule violations.[13] For example, under the proposed new rule the suggested minimum penalty for missing or insufficient wells signs would increase from $250 to $500 (for wells) and $1,000 (for entrance signs and tank battery signs) per day. Even if the rule passes, however, the new penalty amounts in the rule would act only as a guideline for enforcement staff. The ultimate penalty suggested by RRC enforcement staff would still be ”any amount up to the statutory maximum when warranted by the facts in any case.”

In 1983, the maximum civil penalty for violating an oil and gas environmental or safety rule was set at $10,000 per day, and it has not changed since that year.

If merely adjusted for inflation, the maximum penalty of $10,000 per day in 1983 dollars would amount to approximately $23,000 per day in 2012 dollars. In 2011, Texas Senate Bill 1293 proposed to increase the maximum penalty to $25,000 for each day of continuing violation. This bill did not pass.

Other states have recognized and acted on the need to increase administrative penalties for oil and gas violations. In 2012, Pennsylvania passed a bill that increased the maximum civil penalty for unconventional oil and gas well violations to $75,000 plus $5,000 per day. Conventional wells can be penalized $25,000 plus $1,000 per day of continuing violation. The Pennsylvania House Republican Caucus said the new penalty provision “holds drillers accountable” for their actions.

Penalties can be an effective deterrent for those who violate oil and gas rules. But in order to have a deterrent effect, penalties must be applied frequently enough to send a message that non-compliance comes with a cost. A penalty of a few thousand dollars, however, is unlikely to have a dramatic effect on the behavior of some oil and gas operators. To show that it is serious about oil and gas enforcement, RRC should assess higher minimum penalties for violations and increase the maximum amount that operators can be penalized for breaking rules designed to protect public health, safety and the environment.

According to the Sunset Advisory Commission of Texas (“Sunset Commission”), “Unregulated production of oil and natural gas can detrimentally affect the environment and significantly hinder future product recovery efforts.”[2]

RRC data indicate that enforcement of oil and gas rules by the RRC is not keeping companies from damaging the environment. Between January 2006 and the end of 2011 there were more than 4,500 spills of crude oil and natural gas products. Close to six percent (266) of spills during this period affected water.[3]

Could enforcement efforts have prevented some of the spills? We looked a subset of spills to dig into this question. Spills occur at a variety of oil and gas facilities: tank batteries, pipelines, flowlines, valves, pump stations, and others.

We found that more than half of the spills (57%) between 2006 and 2011 occurred at tank batteries. Of the spills at tank batteries, some were probably not avoidable (e.g., caused by "Acts of God"). But close to half were caused by "equipment failure"[5], which presumably, with adequate maintenance and attention by the operator, may have been prevented.

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This chart shows that year after year, numerous operators have crude oil and natural gas product spills from tank batteries due to “equipment failures.” These types of spills often contaminate soils, create wastes that require proper disposal, and may contaminate water resources. Between 2006 and 2011, 45 spills caused by equipment failure at tank batteries affected water.[6]

As seen from the chart, between 2006 and 2011 six operators each had more than 30 incidents leading to crude oil and product spills at tank batteries. Pioneer Natural Resources had 29 spills in 2011 alone, and over the six-year period had 110 spills due to equipment failures at tank battery sites.[7]

The pattern of repeated problems at tank batteries strongly indicates that the RRC has not done enough to encourage or require companies to prevent pollution at these sites.

Overall, our review of publicly available RRC enforcement data shows that Texas RRC’s capacity to regulate the oil and gas industry has been, and remains, limited:

• Inspections are decreasing despite additional staff
• Violations remain high, and repeat offenders are not deterred by current enforcement actions
• Enforcement tools such as severances are not being used effectively
• Minimum and maximum penalties are too low to deter would-be violators
• RRC should increase transparency of enforcement data, and encourage greater citizen participation in enforcement

Ohio has been an oil- and gas-producing state since the 1850s. Most of Ohio’s 64,500 active wells are classified as “stripper” wells, which are wells that produce minimal amounts of oil and gas on a daily basis.

Ohio has yet to experience the oil and gas shale drilling boom of its neighbor Pennsylvania, where more than 5,700 unconventional shale gas wells have been drilled since 2005. As of August 2012, just 112 horizontal oil and gas shale wells had been drilled in Ohio.[2]

The state of Ohio, however, is expected to experience "a significant increase in future drilling," as much of the state sits over the Utica Shale formation, which experts predict holds large natural gas reserves and potentially oil, and much leasing of the Utica shale has already occurred.

By any reasonable measure, the DOGRM is failing to fulfill its duty to enforce Ohio's oil and gas rules, and is ill-prepared for an oil and gas drilling boom. In particular:

• Inspection capacity is inadequate;
• Violations are inadequately reported and tracked, what information exists is opaque to the public;
• Fines are rarely issued to violators;
• Fines are inadequate to punish or prevent irresponsible behavior by oil and gas operators ;
• The environment is not being protected.

Consequently, the public cannot and should not have confidence that oil and gas development is occurring or will occur responsibly in the state of Ohio.

According to the Texas Sunset Advisory Commission, “When [RRC] inspectors uncover violations of statute or Commission rule, they report the violations to the district office for review, and the agency sends a notice of violation [NOV] to operators.”[1]

At the present time, RRC does not have a publicly accessible database that allows the public to examine the violations recorded by RRC inspectors or the NOVs sent to operators every year.

Rider 17 of the 2012-2013 General Appropriations Act required the RRC to publish information about violations on its web site.[2] In 2012, RRC began posting summary statistics of violations on a quarterly basis. It would be more useful and transparent for the RRC to create a publicly accessible database of the violations. An on-line database of oil and gas violations exists in Pennsylvania, and other states like Ohio also make violations data available electronically. It is not clear if RRC plans to create such a database.

It would be useful to know which rules in particular are being violated, as this might help the RRC and citizens to track the types of violations that are most problematic for operators. In 2009, RRC provided the Texas Sunset Advisory Commission (“Sunset Commission”) with statistics on the top ten most frequently violated rules in the state. The data are summarized in this table.

Ten Railroad Commission of Texas rules most frequently violated in 2009

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According to the Sunset Commission, the RRC tracks the number of violations of statewide rules per year, but until 2012 violations by statewide rule were not posted anywhere on the agency’s web site. Because of Rider 17, RRC now publishes quarterly statistics on violations by statewide rule, but for some unknown reason only does so for a small portion of the total number of alleged violations. For example in the first quarter of 2012 there were 13,196 “alleged violations identified through oil and gas inspections,” but just 140 of those were itemized by rule number. It is not clear why only a small subset of the alleged violations are itemized by rule number.

Looking at limited data provided for the first three quarters of Fiscal Year 2012, there are certain rule violations that stand out. Rules with the most violations are: No. 14 (Plugging - 357 violations),  No. 8 (Water Protection - 194), and No. 3 (Identification or properties - 132).

Violations down, but compliance still a problem

Prior to 2012, RRC did not publish any violation statistics on its web site. We were able to find some violations data in RRC and non-RRC reports. As seen in the chart, between 2006 and 2010 the number of oil and gas violations recorded by RRC inspectors decreased from approximately 90,000 to just over 71,000.[3] Meanwhile, as seen in the chart, the number of inspections increased between 2006 and 2009.

The trend Texas is contrary to what has been observed in other states: typically, when inspections increase, more violations are found (for examples, see our information on inspections and violations in Pennsylvania and Ohio).

There are a few ways to interpret the Texas violations statistics:

• It is possible that by conducting more inspections there has been a more visible presence of Texas RRC personnel in the field, causing operators to work more carefully, and violations to go down.
• Alternatively, it is possible that inspectors did not find as many violations in 2010 because the inspections were not as thorough as they were in 2006. Between 2006 and 2010 the number of inspectors remained fairly constant (87 in 2006, 88 in 2010), but there were approximately 3,500 more inspections in 2010 than in 2006, meaning inspectors spent less time on each inspection.
• It is also possible that inspectors simply stopped issuing violations for minor offenses, or that inspectors were instructed to treat violations differently in recent years. For example, regulatory agencies under administrations that wish to encourage oil and gas development and emphasize employment and revenue over public safety could direct agency personnel to avoid issuing violations and instead talk to operators about their observations.
  

  Former Railroad Commission District Director, Mark Henkhaus, recently wrote that, “I know that a Commission field technician is able to detect 'technical violations' on almost any lease or well site. . . many less-serious violations are dealt with in the Commission’s district office by district staff in person, on the telephone. . .”[4]

  It is possible that 'less serious' violations are no longer receiving official Notices of Violation (NOV), and therefore, the numbers do not appear in violations statistics.

Despite the drop in violations, the fact that there were 70,000 violations in 2010 makes it clear that a very serious problem with compliance still exists in Texas. In 2010, RRC inspectors consistently recorded more violations per inspection than their counterparts in other states.[5] In 2010, RRC inspectors found 0.6 violations per inspection, while inspectors and Pennsylvania and Ohio found 0.2 and 0.1 violations, respectively.

Companies repeatedly violate the same rules

The Sunset Commission, which reviewed the RRC enforcement program in 2011, stated that “part of the reason for the large number of violations is that the Commission’s enforcement process is not structured to deter repeat violations.” The Sunset Commission also found that “the [RRC] does not specifically track repeat violations unless the violation is one of the 4 percent brought forward to enforcement.[6]

Data compiled by Earthworks from the RRC severance database reveals that there operators who repeatedly violate certain RRC rules.[7] This database includes information on wells that have been required to stop producing oil and/or gas because of rule violations. shows that for some oil and gas operators, receiving a violation does not appear to deter them from breaking the same rules over and over again. This section outlines two indicators that behavior may not be seriously affected when companies are issued a violation are that: 1) companies violate the same rules on many well sites (one violation does not alter their behavior); and 2) companies repeatedly violate the same rule (i.e., have recurring violations). Both trends indicate that some companies have little regard for the rules. As a result, the Commission cannot be certain that operators are not committing repeated violations.”

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Companies violate the same rule on many well sites: In Texas, operators with inactive wells are required to conduct a well integrity or H-15 test “to establish that an inactive well over 25 years old does not pose a potential threat of harm to natural resources, including surface and subsurface water, oil and gas.”

Data from the severance database show that over a two-year period (2010 and 2011), there were 1,713 delinquent H-15 reports for natural gas leases. As seen in the chart, there were thirteen companies with 15 or more delinquent H-15 reports for gas leases during this period.[8] Devon Energy and Pioneer Natural Resources were by far the worst offenders, failing to file 100 and 82 H-15 reports, respectively.

Companies repeatedly violate the same rule on the same site: When specific well records were examined, they showed that companies repeatedly violate the same rules at the same facility. For example, in 1995, 1997, 1999, 2002, 2004, and 2006 Chesapeake Operating, Inc. was sent certified letters for failing to file H-15 forms for the Detijerina, H.C. lease as required by law. Similarly, Devon Energy Production Company, L.P. was issued certified letters because of delinquent H-15 filings on its Fagan H.F. lease in 1994, 1995, 1996, 1999, 2001, 2002, 2003, 2004, and 2009.

There is no doubt that many other examples exist of companies repeatedly violating the same rules in Texas. Unfortunately, because the RRC does not yet have a publicly available database of violations, it was not possible to determine the full scope of the problem.

The data above show that despite repeated issuance of violations and oil and gas severances/seals, operators continue to violate the same rules – sometimes on the same well site, sometimes at many of their well sites. The repeated occurrence of the same violation shows a pattern of disregard for RRC rules, and the environment. To reduce the number of repeat violations, RRC should significantly escalate penalties for repeat offenses.

Data on oil and gas related violations are not published on the Ohio Division of Oil & Gas Resources Managmenet (DOGRM) web site, and information that is publicly available is subject to interpretation (See Box 1).

Environmental and other violations on the rise

According to DOGRM, oil and gas violations experienced a jump in 2011. DOGRM told Earthworks that oil and gas violations increased from 634 and 615 violations in 2009 and 2010 to 692 in 2011.

Earthworks’ analysis of RBDMS data showed the same increase in violations in 2011 - but we found several hundred more violations and approximately a hundred more wells with violations in 2011 than in the three previous years.[5]

What is perhaps most remarkable is that in 2011 there was a large increase in the number of violations relating to oil and gas industry pollution (view chart). Even though a shale gas and oil drilling boom has not yet occurred in Ohio, in 2011 environmental pollution impacts related to oil and gas activity were at their highest in years.[6] It should be noted that it is highly likely that chart does not include all oil- and gas-related spills, because Ohio operators are not required to report spills to DOGRM. Reporting spills is required in most other oil-and-gas-producing states.[7]

Ohio violations and inspections

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The increase in violations found in 2011 may be due to the fact that inspections also increased in 2011.

Data from RBDMS were used to look at the number of wells with violations compared to the number of wells that were inspected.[5] As seen in this chart, there appears to be a relationship between the two: in other words, when Ohio inspectors go looking, they find violations.

For example, the most wells were inspected in 2004. That was also the year with the most wells with violations. As the number of wells inspected declined (e.g., from 2005 to 2010), fewer wells were found with violations.

It’s time for DOGRM to step up inspection efforts to catch violators and send a message to the oil and gas industry that DOGRM is serious about achieving compliance with oil and gas rules and protecting public health and the environment.

Citizen complaints often draw attention to problematic operations that might otherwise go unmonitored for long periods of time. The Railroad Commission (RRC), the agency responsible for regulating oil and gas development in Texas, has stated that “citizens are viewed as extra eyes to help the RRC identify problems.” In 2009, the RRC received 681 complaints related to oil and gas and found 1,997 violations based on these complaints.[2]

As in Texas, citizens in Pennsylvania play an important role in alerting agencies to potential violations. As seen in the table, in the years 2007 through 2011 approximately 2,890 oil and gas inspections took place because of complaints.[3] Violations were found as a result of more than 700 of these complaint-driven DEP inspections.

Inspections conducted in response to complaints (2007-2011)

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While DEP keeps a database of inspections that occur as a result of complaints, it does not have a publicly accessible database on oil-and-gas-related complaints. As a result, it is difficult to find important information such as date and location, the nature of the complaint, and whether or not complaints have been resolved.

As important as citizens are in alerting DEP to violations, the relationship between citizens and DEP staff is not always positive. We have received frequent reports from citizens in Pennsylvania that they have filed complaints with DEP (either by calling the complaint hotline or filing a complaint on-line) but never heard back from the agency, or were contacted once with no follow up. In other cases, the agency failed to respond to complaints in a timely manner (e.g., DEP inspected a spill complaint days after it occurred, and after rains had washed away the bulk of the material, or days after odors from compressor stations had ceased).

Stephanie Hallowich, from the southwest Pennsylvania town of Hickory, said the DEP has downplayed or ignored her complaints about air and water contamination from a complex of gas installations near her home. In October, a compressor station experienced what she said was a sudden, violent release of gas that shook her house and filled the air around it with foul-smelling gas. . . "They have not been responsive," she said. "There have been no violations, and they have not been keeping up with inspections."

Other citizens have been met by DEP employees who refuse to answer questions about their procedures. In addition, in most cases, DEP does not communicate with potentially affected citizens as to whether and when problems have been remediated. Many citizens, frustrated and unsure of their rights in these situations, hesitate to file new complaints with the state, and may not know whether potentially dangerous conditions remain. In short, there is a significant level of distrust of DEP’s willingness and ability to follow up on complaints.

DEP should foster relationships with communities by ensuring that citizens’ complaints are taken seriously and are resolved in a timely manner. Part of strengthening relationships involves increasing transparency by creating a publicly accessible database that documents all complaints, and includes information on how DEP responds to, and resolves, citizen complaints and reported problems at sites.

Public lacks access to important data

In January 2012, the Pennsylvania Department of Environmental Protection (DEP) released an on-line database that has made some data on oil and gas wells much more publicly accessible. The Oil and Gas Compliance Report system enables the public to access data on inspections, violations, and enforcement actions taken in the state.

While this system is an improvement over the previous one[4], the system is not perfect. And public access to other important DEP data is also lacking.

• Oil and Gas Compliance Report data appear to change quite frequently[5] – even data from previous years. For example, data downloaded on February 28, 2012 showed 16,472 inspections in 2010, while data downloaded on March 20, 2012 showed 15,368 inspections that for same year.
• Data on penalties is included in the Oil and Gas Compliance Report system, but the format makes it difficult to determine total annual oil- and gas-related penalties.
• Detailed information on inspections is lacking. For example, there is no direct access to inspection reports, as there is in Colorado.[6]
• Information on individual wells, such as copies of permits or other well-related files, is not available on-line as it is in states like Colorado, New Mexico, and Ohio.
• DEP does not have a publicly accessible spills database as exists in Colorado and New Mexico, nor a database of blowouts and well control problems, as exists in Texas.
• Nor does DEP have a publicly accessible database of citizen complaints like Colorado, nor does DEP  public statistics on citizen complaints like Texas or Colorado.

So, when it comes to public transparency there are significant gaps in DEP's on-line information system.

Texas oil and gas inspection data

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As seen in the table above, by 2003, the number of inspectors had been cut to 81.5 full-time equivalents; throughout the mid-2000s there were approximately 87 inspectors; and in 2011, there were 97 full-time inspectors (and other RRC employees conducted inspections on a part-time basis.)[3]

RRC inspectors and wells in Texas

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This chart shows that the overall drop in RRC inspection staff since 1993 has coincided with an increase in oil and gas activity in the state. Between 1993 and 2011 the number of wells producing oil and gas in Texas increased from 237,000 to 261,000. In other words, in 2011 RRC was trying to provide oversight for 24,000 more wells than it had two decades before – but was doing so with 20 fewer inspectors. As a result, in 2011 each inspector was responsible for inspecting close to 2,700 wells, versus 2,000 wells in 1993. In 2011, each inspector visited an average of 1,184 wells.

Inspections decreasing - more wells lack oversight

Surprisingly, the addition of ten or more inspectors in 2011 is not expected to result in an increase in the number of inspections carried out in the state anytime soon. In 2010, when there were 88 inspectors, the RRC conducted 121,000 oil and gas inspections. In 2011, despite the additional inspector capacity, the RRC performed just 115,000 inspections. According to the 2012-2013 General Appropriations Act, the RRC has a goal of conducting 113,400 and 116,100 in 2012 and 2013, respectively.

In the first three quarters of Fiscal Year 2012, the RRC conducted a total of 85,417 inspections. If inspections continue at this pace, the agency is on track to conduct approximately 113,889 inspections in 2012,[5] which is 1,000 fewer inspections than the agency conducted in 2011. The decline in inspections does not appear to be linked to a decline in oil and gas activity in the state. Between January and May of 2012 there were 2,671 more well completions than during the same period in 2011.[6]

The fact that there are more inspectors and fewer inspections may mean that inspections are being conducted in a more thorough manner. As seen in the table above, in 2010, each RRC inspector performed, on average, 1,376 inspections, and in 2011, each inspector conducted an average of 1,184 inspections. While 1,184 is an improvement from the previous year, it is approximately four times the number of inspections conducted by inspectors in Pennsylvania and Ohio, and 300 more inspections than Colorado oil and gas inspectors,[7] which raises the question of whether Texas inspectors can possibly be doing as thorough a job as their counterparts in some other states.

Quality concerns aside, a decline in inspections means that more wells are operating without RRC oversight. As seen in this chart, since 2009 the number of inspections has been decreasing, while the number of producing wells in the state has been on an upward trajectory: between 2007 and 2011 the number of wells that produced oil and gas increased by approximately 20,000, from 241,534 to 261,476.(See table above for data) During that same time period, more than 82,000 new wells were drilled in the state.[8]

Several state oil and gas agencies suggest that wells be inspected at least once during the drilling stage,[9] and that active wells be inspected at least once per year. Texas is nowhere near that bar. If RRC followed that suggested inspection frequency, in 2011 the agency would have conducted 261,476 inspections of producing wells and at least 8,391 inspections of well that were being drilled. As mentioned previously, in 2011 RRC conducted just 115,000 inspections.

The RRC does not currently maintain a publicly accessible database of inspections, so it is not clear how many individual well sites were or were not inspected in 2011. According to the Railroad Commission, during the five-year span ending in October 2006, approximately 70,000 (47%) of the 170,000 active oil and gas leases were not inspected.[10] The RRC has not published similar statistics for the period 2006 to 2011.

If it is assumed  that each inspection conducted by an RRC inspector took place at a different well site, in 2010 RRC failed to inspect approximately 139,000 wells (53 % of the producing wells in the state). If it assumed that each inspection occurred at a different oil and gas facility (which includes active wells, inactive wells, injection facilities, hydrocarbon storage wells, etc.), then in 2010 RRC failed to inspect approximately 288,000 or 71% of oil and gas facilities.[11]

The Railroad Commission is reportedly in the process of making its field inspection data more publicly accessible via the agency’s web site. According to the agency, the online data should be available in the 2013 Fiscal Year. This should help the public and the agency determine which well sites have been neglected, and help to focus attention on how much additional capacity is needed to address the gap in oversight.

Inspection triage

In 2007, the State Auditor of Texas reported that not only were large numbers of wells not being inspected, RRC district offices were also unable to consistently perform timely follow-up inspections to determine whether operators had resolved violations.[12] RRC responded to the State Auditor that while notices of violation all have scheduled follow-up inspection dates, the ability to meet this follow-up deadline will be impacted by staff resources, weather, and other job priorities. . .To the extent resources become available in future legislative sessions, the Commission could witness more activities.”[13]

In 2010, the RRC reiterated the message that its capacity to inspect oil and gas facilities is far exceeded, and that its task continues to grow. A 2010 internal RRC memo on job priorities states that, “in light of increased responsibility and industry activity, demands on the districts have increased significantly over the last several years. . .Until staffing levels are increased to reflect the magnitude of our vast responsibilities our function in the field will continue to be governed by ‘reactive’ activities as opposed to proactive activities.”[14]

The RRC memo outlines a priority system for inspections with emergency incidents (spills, blowouts, accidents) and pollution and safety related complaints being highest priority. Well plugging, casing, mechanical integrity tests, waste disposal and non-emergency complaints were second priority, lease inspections in non-sensitive areas were the third priority, while enforcement actions were considered the fourth or lowest priority.

Given that the number of inspections is decreased from 2010 to 2011, it is highly likely that a reactive approach to inspections is still occurring, and that lower priority inspections are falling to the wayside.

In 2010, the RRC released its strategic plan for 2011 to 2015. In the plan, the RRC highlighted an issue that is likely to increase the workload for its inspectors in coming years: the rise of marginal oil-producing wells.

Although Texas’ oil production rate is declining, the Railroad Commission’s responsibilities may actually increase because it takes just as much effort to perform an inspection. . .for a well producing one barrel of oil per day as it does for a well producing 100 barrels of oil per day. As production from wells become even more marginal, the likelihood of operators abandoning wells for the Commission to plug could increase during periods of low oil and gas prices.[15]

There is a need for additional increases in RRC inspection capacity, both to increase the number of inspections conducted annually, and to allow inspectors to spend more time at each site to ensure that they are able to carry out thorough inspections. Until capacity is increased, RRC should limit the number of permits for new oil and gas wells.

Ohio violations related to pollution

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No statistics or information on enforcement actions and penalties could be found on the DOGRM website or in its publications, but DOGRM provided information on enforcement actions and penalties to Earthworks in response to a request for this information.[1]

As seen in this chart, Ohio does not take many enforcement actions against oil and gas operators, and the number of enforcement actions has been declining in the past few years. Enforcement actions in Ohio decreased from 55 actions in 2008 to 29 actions in 2011. Put another way, in 2008, one enforcement action was taken for every 23 violations, whereas in 2011 one enforcement action was taken for every 57 violations.[2]

Such a weak show of enforcement in the face of increasing violations sends a message that breaking oil and gas rules in Ohio results in minor or no consequences. As a result, there is not a strong deterrent effect on would-be violators. It is not surprising, then, that the number of violations increased dramatically over this period. According to RBDMS data, almost 400 more violations were found in Ohio in 2011 than in 2008.

Penalties - too low to deter violators

While fewer enforcement actions have been taken, there has been a small increase in the total amount of penalties assessed for oil and gas rule violations since 2008. But the amount of fines collected in Ohio remains a pittance. As seen in the table, the average fine in 2011 was approximately $2,500. Prior to 2010 the average penalty was less than $1,000.

Ohio enforcement actions and penalties

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In 2005, a review of Ohio’s oil and gas regulations conducted by STRONGER, Inc. found that “The DMRM [now DOGRM] a seeks to resolve most issues without the use of penalties,[3] finding that it improves compliance.” This is not a surprising statement, given the fact that DOGRM is not able to assess penalties large enough to effectively deter operators from violating rules or to provide any incentive to conduct better practices and avoid problems from occurring.

In June 2012, Senate Bill 315 was passed. According to DOGRM, it established “mandatory daily fines for well operators who violate the law.” For most violations the maximum fine is $4,000 per day, although violations related to transporting and injecting brine without a permit have a maximum penalty of $20,000 per day. Pollution of drinking water or endangerment of health and safety only garners a daily penalty of $10,000. the largest civil penalty that can be assessed in Ohio is $20,000.For most oil and gas regulation offenses, the maximum fine is $4,000.[4]

It remains to be seen how often these “mandatory” penalties will be applied, and how these new penalties will affect operator compliance.

Ohio lawmakers must demonstrate that they recognize that the frequency of enforcement actions and the size of fines currently levied against oil and gas operators are simply not enough to deter violations in Ohio.

Ohio oil and gas inspections

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The number of inspections of oil and gas wells in Ohio is currently below what it was in the mid-2000s. This is true even though the number of active wells increased from 62,675 in 2005 to more than 64,000 in 2011.[1]

As seen in the chart, in 2005 oil and gas inspectors conducted approximately 13,500 inspections and visited more than 9,000 active wells in the state. By 2011, DOGRM had reduced the number of oil and gas inspections by 3,000 per year, and as a result, inspected just 6,500 of the state’s active wells.[2]

Currently, a large percentage of Ohio’s active wells are stripper wells (i.e., produce fewer than 10 barrels or oil or less than 60 thousand cubic feet of gas per day). Even though these are low-producing wells, however, it is still imperative that they be inspected on a regular basis as corrosion, and consequently leaks of produced water and hydrocarbons can be a problem for stripper wells.[3] According to a 2003 report prepared for the Department of Energy, “Due to the limited income associated with stripper oil and gas wells, many operators often cannot afford to implement the level of corrosion control methods utilized by major . . companies.”[4]

Relative to other states that we reviewed, Ohio ranks low in terms of how many inspections it conducts per year. As seen from the table, Ohio has more active oil and gas wells than Colorado and New Mexico, but in 2010 Ohio inspectors conducted half the number of inspections of their New Mexico counterparts, and only 65 percent of what inspectors in Colorado performed.

Estimated number of active wells that were not inspected in 2010

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Perhaps even mores striking, data in the table reveal that in 2010 Ohio failed to perform inspections at 91 percent of the state’s active oil and gas wells. More than 58,000 oil and gas wells had no regulatory oversight that year. The situation did not improve in 2011. That year, approximately 90% of wells did not get inspected.[5]

More inspectors needed

In 2010, Ohio passed Senate Bill 165, which made changes to and updated the Oil and Gas Law. In the bill’s fiscal note, it was estimated that 33 new staff would be added to the oil and gas program to deal with regulatory responsibilities added by the bill. These staff increases would be “supported in large part by the new and increased fees proposed in the bill.” The bill did not specify how many of the new staff would be oil and gas inspectors, nor how soon the new employees would be hired.

The DOGRM web site shows that there are now 27 inspectors in Ohio,[6] up from 21 in 2010.[7] While the hiring of additional inspectors led to an increase in the number of inspections, it is still not enough to ensure adequate oversight of oil and gas operations in Ohio. As mentioned above, only 90% of Ohio's active wells were inspected in 2011.

Also, when compared to states like Pennsylvania the workload of each Ohio inspector is immense. In 2011, each Pennsylvania oil and gas inspector was responsible for 885 active wells, on average.[8] Meanwhile, with 64,481 active wells and just 27 inspectors, each Ohio inspector was responsible for an average of 2,388 active wells in 2011—more than twice the number of their Pennsylvania counterparts. It is virtually impossible for one inspector to visit, let alone carefully inspect, 2,388 well sites a year.

According to other states, all new wells should be inspected at least three times (e.g., twice during the drilling/completion process, and once after drilling is completed), and each active wells should be inspected at least once a year.[9] This means that OCD should have performed at least 65,000 inspections in 2011.[10] They conducted approximately 10,000.[11]

Clearly, DOGRM lacks the capacity to provide adequate oversight of existing wells, and is poorly positioned to provide adequate oversight for the planned addition of thousands of new shale oil and gas wells that may be developed in both the Marcellus and the Utica Shale formations.

Violations and enforcement actions

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When violations of laws relating to oil and gas development occur, the DEP has the ability to issue notices of violation, cease and desist orders, suspend or deny permits, or issue monetary penalties to violators.

As seen in this chart, over past decade the total number of enforcement actions in Pennsylvania more than doubled[1], from 426 in 2002 to 976 in 2011. Over that same time period, however, there was nearly a four-fold increase in violations[2], from approximately 1,153 in 2002 to 4,069 in 2011. This suggests that enforcement actions have not been keeping pace with the number of violations.

According to DEP, "environmental inspectors have had greater authority since April [2012] to penalize operators. . .and enforce violations."

Yet enforcement actions have not increased relative to violations. In fact, as seen in the chart and table, a larger percent of violations are going unpunished now than in any of the past 10 years.

In April, May and June of 2012 (the period in which inspectors have had "greater authority" to enforce violations) an average of 20% of violations resulted in enforcement actions. This is down from 2011, when enforcement action was taken on 24% of violations, and nowhere near 2004, when DEP took action for more than half of all violations.

Pennsylvania violations and enforcement data

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Too much discretion in enforcement actions

The Pennsylvania DEP developed an enforcement policy in 2002 that includes basic principles, such as:

• An appropriate enforcement action is to be taken for each identified violation;
• No violation is to be ignored; and
• All companies are to be treated fairly and equally by the Department.

A review of 2010 data shows inconsistent application of enforcement actions and penalties for companies that violate the same rules in Pennsylvania. As seen in Table 17, Clarion Oil and Gas and Alpha Well Inc. both repeatedly violated the same rules, yet Alpha was issued NOVs for the violations and Clarion was not. This is despite the fact that Clarion violated the two rules much more often than Alpha (Clarion had 29 violations, Alpha 12).

Baker Gas Inc. and Oil and Gas Management Inc. also violated the 201TAG and 210UNPLUG rules in 2010, yet both companies were issued NOVs and were penalized for their actions. What is even more interesting is that these companies violated each rule just once (in contrast to the numerous violations incurred by Clarion and Alpha).

insert table here

There are also cases in Pennsylvania in which the punishment fails to address the severity of the violation(s). Between 2007 and 2009, DEP inspectors found more than 300 violations at U.S. Energy Development Corp. well sites. Yet the company received a penalty of just $29,750 in 2009. In 2010, U.S. Energy Development Corp had 44 violations and resolved just 29 of them. While this is a better record than 2009, it is clear that the company did not learn to correct violations in a timely manner.

When such a record of noncompliance receives small or no fines, the possibility that enforcement serves as a deterrence factor for bad behavior declines dramatically.

Penalties - data confusing; penalties fell in 2011

DEP does not publish annual statistics on oil- and gas-related penalties assessed and collected by the agency. DEP’s Oil and Gas Compliance Report system includes data on penalties, but it is not a straightforward task to determine the total penalties assessed per year. When penalties are assessed through a Consent Assessment of Civil Penalty (CACP), a Consent Order and Agreement (COA), or some other method, the negotiated penalty amount may be listed multiple times[3] in spreadsheets downloaded from the Compliance Report system. The annual penalty amounts shown in the chart were derived by removing redundant penalties from the data.[4]

It should also be noted that information on penalties in DEP’s Compliance Report system may not be complete. For example, a May 17, 2011 DEP News Release announced that “Under a Consent Order and Agreement, or COA, Chesapeake will pay DEP $900,000 for contaminating private water supplies. . . Under a second COA, Chesapeake will pay $188,000 for a Feb. 23 tank fire.” The Compliance Report system shows just one COA with $188,000 in penalties assessed to Chesapeake in May 2011.

Violations and penalties

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As seen in this chart, although violations remained high in 2011, the dollar amount of assessed penalties plummeted. Similarly, the number of enforcement actions taken in 2011 was higher than in previous years, while the total amount of penalties declined. This suggests that on average, the amount of the fines were not as large in 2011 as in previous years.

While DEP’s enforcement actions and penalties have increased in the past few years, they have not been enough to deter operators from violating oil and gas rules. More resources need to be allocated to enforcement efforts to reverse the increasing trend in violations. Levying higher fines may also be necessary to create a stronger “deterrent effect” among operators.

S.1113, sponsored by Senator Lisa Murkowski (R-AK), seeks to encourage "critical" minerals development in the United States by asking the Interior Department to:

• Determine a methodology for identifying critical minerals
• Create a list of critical minerals using that methodology
• Examine all mining regulations soup to nuts to determine where permitting of critical minerals should be streamlined.

Harvesting many rare earth minerals occurs as a by-product of other traditional hardrock metals. This presents the practical problem of streamlining permits for the rare earth minerals found in the same mine as uranium, iron, or copper. Worse yet, the bill allows the Interior Department to select any metal that could be subject to supply disruption or important for defense or agricultural applications as "critical".

Congress is effectively talking about creating incentives for large, profitable mining operations that have rare earths or other minerals as a by-product of the primary mineral production.

To the extent that there is a problem, the market is already solving it. A rare earths mine in California is slated to reopen within the year. And surveys of mining companies worldwide indicate that U.S. regulation/permitting is a competitive advantage rather than a disadvantage.

We expect the bill to be marked up in September 2012.

Permits

Mining industry surveys indicate that U.S. regulation/permitting is a competitive advantage rather than a disadvantage. S.1113 would compromise the permitting process. The National Academy of Sciences has already identified copper as one mineral under consideration for strategic mineral designation-- despite ample stocks (nationally and worldwide) and declining prices.

Take Action

Tell your Senators to Say NO to S. 1113! Urge them that limiting environmental review and public input does not change the global commodities markets.

Rare Earths - Critical Minerals

China has manipulated the rare earths minerals (REE) market, which is critical to manufacturing everything from iPhones to predator drones. And they currently control the vast majority of global production.

But, China does NOT host the vast majority of the world's REE reserves. In fact "rare" earths is a bit of a misnomer -- they're not rare. Up until the late ‘90s, the now shuttered REE mine in California (Mountain Pass, owned by Molycorp) produced nearly all of our domestic needs. That mine is supposed to reopen soon.

In the meantime, China’s control of REE production has renewed a bipartisan interest in maintaining a supply of these materials.

In the House

A different critical minerals bill, HR 4402, passed the House of Representatives back in July. 

The National Strategic and Critical Minerals Production Act of 2012, authored by former National Mining Association official Rep. Mark Amodei of Nevada, delivers on the mining industry’s policy fantasy.  If HR 4402 ever becomes law, nearly anything pulled from the ground could be a critical mineral.  Mining companies will simply bypass the environmental reviews required by the National Environmental Policy Act, short-circuit the permitting and public input processes, and close the courthouse door to justice-seeking impacted communities. 

If S. 1113 passes the Senate, members of Congress will eventually have to negotiate a compromise version between the two chambers, likely worsening the Senate version. 

The Susquehanna River Basin Commission manages of the water resources of the basin under comprehensive watershed management and planning principles. 

The Ask

Organizations and citizens across Maryland, New York, and Pennsylvania are coming together to make sure that the Susquehanna River Basin Commission (SRBC) steps up to protect communities and the environment from the harmful impacts of gas operations, which use a lot of water and create a lot of pollution.

The agency needs to stop conducting business as usual. Instead of promoting drilling by issuing water withdrawal permits one-by-one, SRBC must manage shared, public resources using long-term planning and sound science.  The Commission will be revising its comprehensive plan in 2013, and can do what it takes to stem drilling damage and save the Susquehanna for generations to come. Get the facts to make a difference.

Take Action

Do you live in New York, Pennsylvania or Maryland? Tell your Governor to save the Susquehanna!

Don't live in the Basin? Tell Colonel Savre that you care!

Join the Network

The SRBC Network Google Group is a new coordinating network engaging organizations and citizens in Pennsylvania, New York, and Maryland to facilitate both action and policy-focused work around the Susquehanna River Basin Commission (SRBC). Postings here should focus on near-term, specific “asks” and efforts, information about drilling in the Basin, and opportunities to take action and submit comments.

To visit every producing well at least once per year, OCD inspectors would each have to inspect more than 15 wells per day. Needless to say, OCD did not.

In 2010, OCD conducted 20,780 inspections, which means that at least 60% of producing wells did not get inspected [2]. In 2011, OCD increased its number of inspections, but still failed to inspect approximately 54% of producing wells.

A lack of inspection capacity has been a problem in New Mexico for years. In 2008 it was reported that OCD inspectors in the Aztec office made an effort to inspect each of the district’s 24,000 active wells once every five years. That year, the entire state of New Mexico employed 18 inspectors. In 2011, there were six fewer inspectors in the state [3], so it almost certain that wells inspected by the Aztec office of OCD are still only inspected once every five years, at most.

New Mexico’s inspection capacity lags behind other states

Compared to other oil and gas states [1], New Mexico’s inspection capacity is low. As seen in the map, in 2010 Pennsylvania had 65 inspectors to monitor 90,000 active wells and New York state had 16 inspectors to monitor approximately 10,000 active wells. Meanwhile, New Mexico OCD had 12 inspectors to monitor more than 50,000 wells in a state that is larger than New York and Pennsylvania combined.

OCD inspectors have a higher inspection burden than their counterparts in other states. In 2010, New Mexico inspectors carried out, on average, 1,732 inspections each. In 2011, OCD increased its number of oil and gas inspections by more than 5,000, but retained the same number of inspectors. So each inspector carried out an average of 2,129 inspections [4], and possibly as many as 2,450, in 2011.

Inspectors in other states conduct far fewer inspections [5]. In 2011, Texas and Colorado inspectors each performed approximately 1,184 and 816 inspections, respectively, and Ohio and Pennsylvania inspectors each carried out fewer than 400 inspections per year. It seems reasonable to assume that an inspector who conducts 400 or 1,000 inspections per year can do so in a much more thorough manner than an inspector who conducts more than 2,000 inspections per year.

OCD has recognized its lack of inspection capacity. In the Energy, Minerals and Natural Resources Annual Report for 2011, one of the OCD’s goals was to “increase staffing in the district offices to enhance application processing and well inspections.”

New Mexico must hire more inspectors

According to other state oil and gas agencies [6], all new wells should be inspected at least three times (e.g., at least twice during the drilling/completion process, and once after drilling is completed), and each active wells should be inspected at least once a year. This means that OCD should have performed at least 55,000 inspections in 2011 [7]. They conducted just 25,543 [8].

Clearly, there is a critical need to increase the number of inspectors in the state – both to decrease the burden on existing inspectors, and to increase OCD’s capacity to inspect more wells on an annual basis. If staffing levels increase, all new hires should be put toward inspections, not to processing permit applications, until OCD can provide adequate oversight for all of its existing wells.

Box 1: OCD Violations data
are incomplete and misleading

How does OCD track violations? OCD maintains a non-public Compliance Database that includes information on wells with violations, dates of violations, OCD response (non-compliance letter, phone call, email, etc.), and date that compliance was achieved.

What is public? In New Mexico the only violations-related information readily available to the public is on a well-by-well basis via the OCD Electronic Permitting System (EPS).

It would be impossible for a person to to get the big picture -- compile statistics on violations by going through tens of thousands of individual well files.

How can the public tell if a violation has occurred? In most cases, scanned copies of Letters of Violation and other letters issued to well operators for less serious violations can be viewed in the EPS well file documents. But letters are not issued for every violation. Also, not all letters cite the rule(s) that have been violated.

What is the difference between and Letter of Violation (LOV) and other types of letters? When inspectors find what they consider violations, official Letters of Violation (LOVs) may be set to operators. Less serious violations, may not receive an LOV, but may still send a (lesser) noncompliance notification letter to the operator. Or OCD may simply phone or email the operator.

Information on LOVs found in EPS well files can be misleading. Under the Compliance tab of the well file, both the Notification and Enforcement boxes may say that a “Letter of Violation” was sent. However, the only time OCD considers that an official Letter of Violation was issued is if the Notification box shows a Letter of Violation. If the Notification box contains anything other than Letter of Violation, even if the Enforcement box shows Letter of Violation, then an official LOV was not issued. (A non-compliance letter may have been sent, but these letters are not treated the same as LOVs, and are not included in LOV statistics). See the two examples below.

LOV issued

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No LOV issued

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Making matters worse is that all letters sent to an operator have the title LETTER OF VIOLATION, regardless of whether it was an actual LOV, or simply a letter sent to inform operators of non-compliance. According to OCD, this is because the Risk-Based Data Management System used by its inspectors automatically formats letters, and therefore all of them include the title LETTER OF VIOLATION. Although aware of this glitch, OCD has not allocated staff time to fix it.[1]

Violations data are lacking

Violations data is hard to get in New Mexico (See Box 1). The state Oil Conservation Division (OCD) does maintain a violations database, but it isn't public. Nor are violation statistics published on the OCD web site.

OCD should make oil and gas violations data easily accessible to the public.

OCD should develop an on-line, publicly accessible system that allows both OCD staff and the public to track an operator’s record of compliance and ensure that violations have been corrected. The database should include information on violations by:

• well sites,
• operator name,
• the rules violated,
• the OCD response (e.g., date and type of enforcement actions),
• the date compliance achieved,
• and a link to other OCD well data.

All violations, regardless of whether or not an LOV was issued, should be recorded and tracked by OCD. These statistics should be compiled and reported on a monthly and annual basis on the “Statistics” page of the OCD web site and be available for bulk download.

Are New Mexico violations on the decline?

Since statistics on oil and gas violations in New Mexico are not available, we attempted to gauge violations by looking at the number of "Letters of Violation" (LOV) issued by OCD in the past three years.[2]

LOVs are sent to notify operators that they are in violation of OCD rule(s), and to inform operators of a date by which they must resolve violation(s). As shown in the chart below, the number of LOVs sent to operators in 2009, 2010 and 2011. The OCD data show a sharp decrease in the number of LOVs sent over the past few years. Less than one-third of the number of LOVs issued in 2009 were sent in 2011 (673 vs. 202). This does not necessarily mean that violations have declined. According to OCD, statistics on LOVs do not reflect the total number of violations per year,[3] as each letter may contain multiple violations, and LOVs are typically only sent to operators when there are serious violations.

Furthermore, as described in New Mexico Penalties and Sanctions, OCD inspectors have a great deal of discretion in how they deal with violations. So statistics on LOVs are an unreliable measure of violations and non-compliance.

NM Letters of Violation (LOV)

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It’s not clear why there has been such a dramatic decrease in the number of LOVs. In some states, there is a relationship between the number of inspections and the number of violations (more inspections lead to the discovery of more violations). But this does not appear to be the case in New Mexico.

As discussed in the section on New Mexico Penalties and Sanctions, OCD is severely hamstrung in its ability to pursue enforcement actions against operators that violate OCD rules. If operators refuse to comply with the requirements in LOVs, it is unlikely that OCD will ever pursue civil penalty actions because the expense of these undertakings is more than the meager penalties that can be collected under the current rules. So, it is possible that the agency may be expending fewer resources on recording violations and issuing LOVs, and instead focusing efforts on achieving compliance through alternative means.

One such alternative approach appears to be helping to decrease non-compliance by new operators. Over the past few years the state has been educating new operators on particular types of violations. In 2009, the OCD enforcement team identified ten common compliance problems [4] and implemented a program to review rule requirements with each new well operator. Operators receive an orientation letter in which the common compliance problems are mentioned, and the operators are required to sign and return a letter saying that they have read and understood the requirements of the particular rules. According to OCD, compliance by new operators has improved [5] since the implementation of the orientation letter. (View a copy of the orientation letter )

Select operators notified of non-compliance

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Compliance still a problem

Even if new operator compliance is improving OCD data suggest that compliance among existing operators is still a problem. Many of the same operators are receiving high numbers of non-compliance letters from one year to the next. The following three charts use data from OCD Compliance Summaries.[6] The first chart illustrates how some companies clearly have a problem with compliance.[7]

How quickly operators resolve violations is another important factor to consider when evaluating the effectiveness of an enforcement program. This chart shows that certain companies have a difficult time coming into compliance. (Chart does not include all operators with unresolved violations) As of February, 2012 the operators in the chart had still not resolved the problems that led to LOVs and other letters of non-compliance in 2010 and 2011.

# unresolved violations by operator

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OCD Compliance Summary data show that as of early 2012 compliance had been achieved in 311 (39%) of the 797 incidents that resulted in letters of non-compliance in 2010, and compliance had been achieved in 170 of the 453 cases in 2011 (38% compliance).

With respect to the more serious violations (those that warranted LOVs), Earthworks’ analysis of OCD data showed slightly higher rates of compliance. In 2010, 414 LOVS were sent to operators, and as of early, 2012 compliance had been achieved for 220 (53%) of the cases. In 2011, 203 LOVs were sent, and compliance had been achieved for 101 (50%) of the cases. These rates may be higher, but when only half of the serious problems are resolved within a year or two, it is clear that there is a significant problem with compliance.

The New Mexico Oil Conservation Division (OCD) is charged by the New Mexico Oil and Gas Act to

“enforce effectively the provisions of this act or any other law of this state relating to the conservation of oil or gas.”

By any reasonable measure, the OCD is failing to fulfill its duty to enforce New Mexico’s oil and gas rules. In particular:

• Inspection capacity is inadequate;
• Violations are arbitrarily assessed;
• Violations are inadequately reported and tracked, what information exists is opaque to the public;
• Civil fines cannot be assessed by the OCD, they must be adjudicated;
• Fines are rarely issued to violators;
• Fines are inadequate to punish or prevent irresponsible behavior by oil and gas operators – or even to cover the state’s costs of fining a violator;
• The environment is not protected.

Consequently, the public cannot and should not have confidence that oil and gas development is occurring or will occur responsibly in the state of New Mexico.

When a serious violation of OCD rules is discovered, an OCD inspector may issue a formal Letter of Violation (LOV). For less serious violations, noncompliance letters (LET) or Field Visit Inspection Letters (FVIs) may be sent.

But New Mexico lacks state guidelines for determining what constitutes a significant violation of OCD rules. This means each individual inspector has complete discretion to determine what constitutes a serious violation requiring an LOV. According to OCD, “Each inspector has his own criteria,”[1] for determining when Letters of Violation are issued to operators. As a result, operators may receive different treatment simply because their site was inspected by inspector X instead of inspector Y.

Based on Earthworks’ analysis of OCD data acquired through a public information request, it is clear that LOVs are inconsistently applied. For example, in 2011 the very same rule violations resulted in an LOV, LET or FVI. About half of the operators that did not have signs on their wells received an LOV, while half received FVI or LET. Similarly, the more serious violation of a "failed pressure test" resulted in 8 LOVs, 11 FVIs and 7 LETs. (View data chart)

Furthermore, there are regional differences in the use of LOVs as an enforcement tool. For example, very few Letters of Violation are issued out of the Aztec field office – a district that has more than 22,000 active oil and gas wells.[2] According to OCD, the Aztec District has a “different type of working relationship with operators,”[3] than other OCD districts. There are fewer operators, and so Aztec inspectors convey non-compliance through emails, phone calls or letters that are not official Letters of Violation.

When enforcement actions for both minor and more serious violations can vary widely from one inspector to the next, and from one district to the next, it erodes public confidence in OCD. Where inspectors have their own personal criteria for enforcement, it makes a mockery of the notion that we are a country of laws. And it creates the opposite of the regulatory “certainty” oil and gas operators repeatedly and publicly claim they desire.

Penalties ineffective and outdated

Oil & gas fines collected by OCD

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The OCD lacks a regulatory tool that many other oil-and-gas-producing states and even other New Mexico state agencies possess -- the ability to levy civil penalties on operators who violate the rules. Not only do such penalties help to deter operators from breaking the rules, they can also be a source of revenue to help fund oil and gas agency programs (such as enforcement, plugging of inactive wells or others).

In Pennsylvania, the Department of Environment can penalize operators of unconventional gas wells up to $75,000 plus $5,000 for each continuing day of violation and operators of conventional wells $25,000 plus $1,000 per day for violating oil and gas rules. In Texas, the Railroad Commission can fine oil and gas operators up to $10,000/day if they break rules pertaining to safety or pollution prevention. In recent years, Pennsylvania, Texas and Colorado have each annually collected millions of dollars worth of revenue from penalties for oil and gas rule violations.

As seen in the chart, in the years 2007 through 2009 New Mexico collected hundreds of thousands of dollars in penalties [6] per year from the oil and gas industry. In 2009, however, an oil and gas company won a court case that effectively stopped New Mexico from collecting penalties for rule violations (discussed below). The $14,000 collected in 2010 was largely through penalties for violating terms of Agreed Compliance Orders, not from penalties assessed for rule violations.

Prior to November 2009, the OCD had the ability to administratively assess civil penalties for violations of the state’s oil and gas regulations. In November 2007, Marbob Energy Corporation (Marbob) challenged the agency’s statutory authority to assess civil penalties. In November 2009, the New Mexico Supreme Court ruled that OCD does not have the authority to administratively assess penalties for violations. Rather, the Court ruled that the state Attorney General’s office must bring suit on behalf of the OCD for each and every violation to establish liability and assess the appropriate penalty, and this suit must be brought in the district court in the county in which the operator/defendant resides or in the county where the violation occurred.

Comparison of NM statutory penalties

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Not only is the maximum penalty extremely low, but the threshold for assessing this penalty is extremely high: penalties only apply if an operator knowingly and willfully commits the violation. This is a much higher burden of proof than in is required in other states such as Pennsylvania, where civil penalties “may be assessed whether or not the violation was willful.“ New Mexico’s own Air Quality Bureau has a policy that states, “a violator’s knowledge regarding the requirement may result in an upward adjustment [to the penalty amount], but the violator’s lack of knowledge regarding the requirement does not excuse the violation because ignorance of the law is not a defense to liability.”

As seen from this table, other New Mexico resource or environmental statutes provide for higher penalties than the Oil and Gas Act, they provide “strict liability” for civil penalties (i.e., a violator is subject to a penalty for any violation regardless of knowledge or intent), and the penalties can be assessed administratively (i.e., by the agencies, not the courts).

Clearly, New Mexico’s oil and gas statute needs to be revised to return to OCD the ability to assess administrative penalties, and increase penalty amounts to at least match other oil and gas producing states and other agencies within New Mexico. Otherwise, there will continue to be little motivation for oil and gas operators to adhere to New Mexico's oil and gas rules.

Citizen complaints can be an important barometer of industry behavior, and citizens can provide a crucial early warning of problems at oil and gas sites.

In Texas, the oil and gas regulatory agency has stated that “Citizens are viewed as extra eyes to help the RRC [Railroad Commission] identify problems..”[1] In 2009, the RRC received 681 complaints related to oil and gas and found 1,997 violations based on these complaints.[2] In Pennsylvania, complaints led to the discovery of at least 700 violations between 2007 and 2011.

The Texas Railroad Commission publishes quarterly statistics on complaints. Colorado Oil and Gas Conservation Commission (COGCC) publishes complaints statistics in its staff reports, and COGCC's online database enables users to view the 5,000 most recent complaints.

New Mexico's Oil Conservation Division (OCD) does not publish any statistics on citizen complaints on its web site. OCD's Electronic Permitting System, which allows users to view information on wells, does contain a category of information labelled "Complaints, Incidents and Spills". But it appears that information on complaints is not kept up-to-date in this system. For example, even though OCD carried out an inspection in response to a complaint about a leak being covered up[3] the EPS well file did not contain any details on the complaint.

Since New Mexico does not provide detailed information regarding citizen complaints, it is impossible to know the full scope of the problems being experienced by citizens living close to New Mexico's oil and gas fields.

Information on citizen complaints in New Mexico—such as information on facilities of concern, nature of the complaint, OCD follow-up, and complaint resolution—should be made publicly accessible.

We tried to speak with a representative of the New York DMR Bureau of Oil and Gas Permitting and Management about obtaining statistics on inspections, violations, and complaints relating to existing wells and facilities.[1] However, our calls were not returned. Eventually, in response to an email request for information on these topics, Earthworks received this reply:

“The Division of Mineral Resources does not currently have a database for the information requested below. We are preparing to have one in operation at the time high-volume hydraulic fracturing activities are approved to go forward in the state. We do have paper records located in the field offices where the proposed wells were drilled. The record [sic] are filed by county, operator and by well name. You can review the paper records at our . . . offices.”[2]

Some data are publicly available, such as statistics on inspections, enforcement actions and penalties collected for oil and gas violations, but no detailed information is currently available on-line. This makes it very difficult for the public to monitor oil and gas operations.

DEC must ensure that adequate resources are put toward increasing transparency of oil and gas facility data and oil and gas enforcement data. These systems should be put in place before shale development is allowed to occur in the state.

Citizen complaints - need more attention

According to the DMR Bureau of Oil and Gas Permitting and Management web site, the Bureau investigates and resolves citizen complaints and non-routine incidents. As with other enforcement-type information, the Bureau currently does not track citizen complaints in a manner that is accessible to the public.[3]

Other states track and publish data on citizen complaints. The Texas Railroad Commission publishes quarterly statistics on complaints. Colorado Oil and Gas Conservation Commission (COGCC) publishes complaints statistics in its staff reports, and COGCC's online database enables users to view the 5,000 most recent complaints.

Citizen complaints can be an important barometer of industry behavior, and citizens can provide a crucial early warning of problems at oil and gas sites. In Texas, the oil and gas regulatory agency has stated that “Citizens are viewed as extra eyes to help the RRC [Railroad Commission] identify problems..”[4] In 2009, the RRC received 681 complaints related to oil and gas and found 1,997 violations based on these complaints.[5] In Pennsylvania, complaints led to the discovery of at least 700 violations between 2007 and 2011.

To utilize the "extra eyes" of citizens, however, state oil and gas agencies like DEC must work cooperatively with citizens and dedicate sufficient resources to track and respond effectively to citizen complaints.

At the present time DEC does not appear to be dedicating enough resources to citizen complaints. Currently, the investigation of water well complaints in relation to oil and gas development is not always handled by DEC.[6] Based on information in the SGEIS, it is not clear if the DEC will only respond to water complaints that occur during oil and gas drilling, or whether DEC will also investigate water complaints if they occur close to established oil and gas wells or other oil and gas facilities (such as chemical storage areas). All citizen complaints related to water contamination, especially those involving methane, hydrocarbons, or chemicals in water, should be followed up by DEC regardless of the stage of oil and gas development.

DEC should be fostering relationships with the public by ensuring that citizen complaints are taken seriously and are resolved in a timely manner. Part of strengthening relationships involves increasing transparency by creating a publicly accessible database that documents all complaints, and includes information on how DEC responds to and resolves citizen complaints.

The DEC’s Division of Mineral Resources’ Oil, Gas and Mineral Resources Annual Reports contain some information about penalties and other enforcement actions taken against oil and gas operators. Annual reports for 2010 or 2011 have not yet been published by DEC.

Oil and gas enforcement actions and penalties in New York

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As seen in the table, civil penalties for violations of DEC’s oil and gas regulations have not amounted to much. In most years administrative penalties assessed by DEC totaled less than $20,000. DMR annual reports show that in 2006 and 2007 the penalties were collected as a result of a mere 12 and 10 administrative enforcement cases, respectively. (Data on enforcement cases were not provided for other years.) So, on average, less than $2,000 was collected per enforcement case.

Penalties provisions - weak

The purpose of penalties is two-fold: to deter violators, and in some cases to provide compensation for harm, such as pollution. It is unlikely that a $2,000 penalty is going to have much of a deterrent effect on operators, especially given the fact that so few penalties are issued in New York every year.

Compared to Pennsylvania, which is in the midst of a shale gas drilling boom, the maximum penalty for violating rules related to New York's Mineral Resources (e.g., oil and gas) is low – it cannot exceed $8,000 plus an additional penalty of $2,000 for each day that the violation continues. The Pennsylvania Department of Environmental Protection (DEP) has the ability to issue penalties of up to $25,000 plus $1,000 per day of continuing violation for conventional oil and gas wells, and the Pennsylvania DEP can assess penalties of $75,000 plus $5,000 a day for violations at unconventional wells.[1] In Texas, the Railroad Commission can fine oil and gas operators up to $10,000/day if they break rules pertaining to safety or pollution prevention.

There are stronger penalty provisions in some environmental statutes in New York. For example, the Environmental Conservation Law enables penalties up to $37,500 per day, per violation of various sections of the Water Pollution Control Law. These penalties can be applied to oil and gas operators if they violate the statutes. It is not clear, however, how often these provisions are used against oil and gas operators.

One example was found where DEC assessed penalties against and oil and gas operator for violating New York's Water Pollution Control Law.[2] In January 2012 DEC filed a complaint assessing a civil penalty of $187,500 against oil and gas operator U.S. Energy for polluting a stream in New York’s Allegany State Park.

Penalties and enforcement actions - data lacking

It’s difficult to do an in-depth analysis of DEC’s oil and gas enforcement program because DEC does a poor job of posting information on oil and gas enforcement actions. As seen in the table above, in most years there has been no information on the number of administrative enforcement actions that led to penalties (or number of actions taken by the Attorney General). Also, little information was found on the names of the operators receiving penalties, or other particulars of the enforcement cases (e.g., which rules were violated, and which types of violations resulted in enforcement actions and penalties).[3]

Other states do a much better job of providing information on enforcement actions. For example, the Pennsylvania DEP has an online, searchable database that allows users to search for enforcement actions by operator, county, municipality, with a particular time period, and provides information on penalties and whether or not violations have been resolved. Colorado’s Oil and Gas Conservation Commission web site allows interested parties to view enforcement hearing documents and find out the amount of penalties assessed to operators.

The tracking of violations and enforcement actions is not only of interest to the public, it is also a very important tool to enhance DEC’s understanding of where to focus its enforcement efforts.

In 2011, the Texas Sunset Commission berated the Texas Railroad Commission for its poor tracking of serious oil and gas violations and repeated violations by the same operator, and commented that without this type of information, “the Commission cannot determine or ensure effective and consistent enforcement across the state.”[4]

DEC needs to make enforcement data easier to access so that employees can better understand where to focus their enforcement efforts. Also, data on violations, date of resolution, repeat violators, enforcement actions taken in response to violations, penalties resulting from enforcement actions should be tracked and published in on-line, publicly accessible databases that enable users to download information into spreadsheets.

As in other states reviewed by Earthworks, inspections have not kept pace with the growth of oil and gas development in New York.

New York inspections and wells

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Data on active oil and gas wells in New York and inspections conducted by the oil and gas staff of the Division of Mineral Resources (DMR) can be found in the division’s Oil, Gas, and Mineral Resources Annual Reports. The most recent Annual Report was published in 2010, and contained statistics for 2009. 2010 data for active wells and inspections were found from other sources.[1]

These data show that inspections in New York have declined in the past few years, despite a growth in the number of active wells. The number of oil and gas inspections decreased by more than 1,000 per year between 2001 and 2010. Meanwhile, the number of active wells increased by approximately 1,000 over the same time period.

In 2002, DMR inspectors were conducting one inspection per 2.6 active wells. By 2010, they were only able to conduct one inspection per every 4 active wells.[2] As a result, at least 7,854 active wells in New York failed to be inspected in 2010.[3]

As the data in this table show, in 2010 more than 75 percent of active wells (3 out of 4) were not inspected in New York. Compared with other states that we reviewed, only Pennsylvania and Ohio inspectors failed to inspect a higher percentage of active wells in 2010.

Estimated number of active wells that were not inspected in 2010

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Inspection policy - needed

How frequently are wells inspected? How frequently should they be inspected?

According to the DMR’s 2009 Oil, Gas and Mineral Resources Annual Report, oil and gas staff inspect well sites:

• during permit application review to check environmental and public safety issues
• during drilling to check on well site construction and drilling permit compliance
• during the operating phase to check for leaks, spills, or other potential problems
• to ensure that well plugging and site reclamation meet requirements
• upon receipt of a well transfer request
• when staff perform follow-up inspections to ensure any violations are properly remediated

The annual report does not elaborate on how often or for how long inspectors are present during drilling activities (drilling and well completion can last for weeks), and how frequently wells are inspected during their operating phase (wells can operate for decades).

Currently there are no accepted best practices for inspections. However, some states have developed guidelines for how frequently oil and gas wells should be inspected. This table shows that relative to Pennsylvania and North Dakota, New York’s current suggested inspection frequencies are much lower.

Suggested inspection frequencies in PA, ND and NY

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On the New York Department of Environmental Conservation (DEC) web site, the department states that if high-volue hydraulic fracturing (HVHF) is used to drill oil and gas wells, drilling permits will only be issued to the extent that the department has the resources to review and oversee activities. Similarly, in the revised draft environmental impact statement related to Marcellus shale develompent, DEC proposed to "limit [drilling] permit issuance to match the Department resources that are made available to review and approve permit applications, and to adequately inspect well pads and enforce permit conditions and regulations.”[4]

In July 2012, the Times Union quoted a DEC spokesperson as saying "the state's draft plan would require at least 13 inspections during each well drilling and completion." If this becomes a binding policy, it will be a vast improvement over their current inspection program (seen in the table above). 

From the limited information available, it appears that DEC's current approach to determining the number of oil-and-gas-related inspections may be far from adequate. For example, DEC's Division of Water (DOW) has the primary responsibility for site inspections related to oil and gas stormwater permits. According to DOW, "The number and type of inspections to be performed at permitted facilities are determined during DOW's annual work planning process."[5] This suggests that DOW determines the number of inspections based on available inspectors, rather that determining how many inspections should be conducted based on what is needed to ensure effective oversight of these facilities.

DEC should develop a binding inspection policy that outlines when and how often inspections must occur. Such a document will help the agency determine how many drilling permits it can handle with available staff, while still performing the required inspection and enforcement duties.

DEC inspection and enforcement staff - must be increased

If allowed to proceed, the majority of future oil and gas development in New York is going to be from unconventional oil and gas wells, with the higher volumes of water and chemicals used and waste produced. In September 2011, Gannett news reported that DEC estimated it would need “an additional 226 staffers within five years if high-volume hydrofracking moves forward in New York.” The article also said that, “The DEC has been hit particularly hard by staff cuts in recent years, losing 806 full-time employees since April 2008.”

Whether or not New York will be able to hire and retain experienced oil and gas agency staff remains and open question. Pennsylvania and Texas have recently increased inspection capacity in response to a booming shale gas and oil industry, but both states have had a difficult time keeping positions filled.

In 2011, Citizens Voice reported that the Pennsylvania Department of Environmental Projection was able to hire oil and gas program staff but retaining them was a challenge. At least four former well-site inspectors had been hired away by oil and gas companies operating in Pennsylvania. In 2011, the Texas Sunset Advisory Commission reviewed the Texas Railroad Commission (agency responsible for oil and gas oversight) and found that “. . . inadequate pay and lack of career advancement resulted in 26 employees under the age of 40 leaving in 2009,” and “. . .having to compete with higher paying private sector jobs also creates barriers to recruiting employees.[6]”

There is no doubt that additional inspection staff need to be hired to ensure that existing and new wells receive adequate oversight. DEC needs to ensure that it can fund oversight efforts (wages must be high enough to attract and keep qualified, experienced staff) before it begins to permit new wells.

Page updated July 31, 2012

On July 17, 2012 the Times Union quoted a DEC spokesperson as saying "the state's draft plan would require at least 13 inspections during each well drilling and completion."

On July 17, 2012 Earthworks released its report NYS DEC: Inadequate enforcement guarantees irresponsible oil and gas development. The report was released with our partners Catskill Mountainkeeper, Delaware Riverkeeper Network, Earthjustice, Environmental Advocates of New York, Environment New York, and Riverkeeper. View the press release.

Background

New York’s Department of Environmental Conservation (DEC), primarily through the Division of Mineral Resources (DMR), administers regulations and a permitting program for oil and gas drilling and well operations. The Division’s mandate involves “fostering, encouragement and promotion of the development, production and utilization of… oil and gas,” as well as responsibility for enforcement of oil and gas regulations and “the prevention of pollution.”[1] Other divisions within DEC also participate in various aspects of oil and gas permitting and inspections.[2]

New York has been an oil and gas producing state since the 1800s, but compared to other states New York has a relatively small industry. Although the potential for development exists, New York has not yet experienced the boom in shale gas drilling that is occurring in Pennsylvania and other parts of the country, 

In New York, the primary target for shale gas development is the Marcellus Shale, with the deeper Utica Shale also identified as a potential resource.[3] The New York DEC has determined, based on industry projections, that it may receive applications to drill approximately 1,600 Marcellus Shale wells in an average year, and that development of Marcellus Shale wells could span a 30-year period.[4]

Currently, permitting of shale gas wells using horizontal drilling and high-volume hydraulic fracturing (HVHF) is on hold until DEC completes the environmental review required by state law, including the issuance of a Final Supplemental Generic Environmental Impact Statement (SGEIS).[5]

In June 2012, the New York Times reported that Governor Cuomo was "pursuing a plan to limit the controversial drilling method known as hydraulic fracturing to portions of several struggling New York counties along the border with Pennsylvania, and to permit it only in communities that express support for the technology." But to date, no such plan has been publicly released.

DEC has been criticized by organizations such as Environmental Advocates of New York, for failing to adequately monitor the treatment and disposal of wastewater from existing gas wells. Similarly, our review of publicly available DEC enforcement data shows that New York DEC is not prepared to oversee the expected shale gas boom because it is struggling to govern existing oil and gas wells:

• Inspections occur too infrequently and too irregularly
• Fines are inadequate
• Lack of data prevents public evaluation of DEC’s oversight
• Citizen complaints are not efficiently used to improve oversight

The Path Forward

• From top management to field staff, the DEC needs to demonstrate by its enforcement actions that it is serious about protecting New York’s health, safety, and the environment.
• DEC should hire more inspectors, at competitive wages, in order to provide consistent and thorough oversight for all active wells in the state. Until enough capacity can be added to at least inspect each producing well once a year DEC should limit the number of new drilling permits.
• The DEC needs to develop an inspection and enforcement policy to determine adequate oversight, and refrain from issuing new permits if it fails to meet its oversight responsibilities.
• The DEC should track inspections, violations, penalties and enforcement actions and make this information publicly accessible via an on-line database.
• Penalties for violations of oil and gas regulations need to be increased, and enforcement actions taken more frequently to deter operators from violating the rules.
• The DEC can strengthen relationships with citizens by responding to and resolving all citizen complaints in a timely and thorough manner. DEC should also track and make publicly available information on citizen complaints – such as information on facilities of concern, nature of complaint, DEC follow-up and complaint resolution.

When oil and gas rules are violated, most states have the ability to assess “civil” monetary penalties (i.e., fines).

The purpose of penalties is two-fold:

1. To deter violators, and
2. In some cases to provide compensation for harm, such as pollution.

In Texas, a regulatory review of enforcement practices concluded that penalties play a key role in deterring and punishing violators, thus increasing compliance.

Compared to other major oil and gas producing states, Colorado’s fines for oil and gas violations are weak.

According to COGCC rules, operators may receive a maximum fine of $1,000 a day for each day that a violation continues. This is similar to New Mexico, which hasn’t changed its penalty schedule since 1935.

Pennsylvania, on the other hand, has the ability to issue a $25,000 fine (plus $1,000/day for each day of continued violation) for conventional wells, and $75,000 (plus $5,000 per day) for unconventional gas wells. Texas also has stronger penalty provisions – its Railroad Commission can issue fines of $10,000 per day for oil and gas violations that pertain to safety or the prevention or control of pollution.

Very few violators are penalized

As seen in the below chart very few operators in Colorado receive penalties for violating rules.

In 2010, just ten operators received penalties, even though 319 NOAVs were issued that year to at least 83 different operators.

In 2011, only 22 operators received penalties even though 79 operators received a total of 230 NOAVs.

It’s unclear if this is a resource issue (i.e., enforcement actions require more staff time), or if there is some other reason that COGCC is not fully utilizing its enforcement powers against violators.

Colorado Enforcement Actions and Penalty Data

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Fines for violators, even repeat violators, are low

Between 2005 and 2009 less than $500,000 in penalties were assessed per year. In 2010 the commission reported collecting three times the typical amount because “the COGCC pursued a backlog of enforcement matters, most of which involved incidents that had occurred in previous years.” Similarly, in 2011 “COGCC continued to pursue a backlog of enforcement matters.”

Therefore, one cannot assume that the higher total amount of penalties assessed in 2010 and 2011 are going to continue in future years.

A recent fine issued to Aspen Operating LLC (“Aspen”) suggests that COGCC is continuing its weak application of penalties. At a May 2011 hearing COGCC staff recommended that a $200,000 penalty, the maximum allowed under its rules, be assessed against Aspen for 20 alleged violations. Aspen failed to show up for the May hearing. When the case was re-heard in January 2012, the Commissioners reduced the fine to $20,000. This is yet another example that suggests to the public and operators that violating COGCC rules results in minor consequences.

COGCC should assess more fines, increase maximum penalties and hire more enforcement staff to ensure that penalties actually deter violators and better protect public health, safety, welfare and the environment.

And unlike some other states, the COGCC does not have a user-friendly, public database that provides information on violations. Consequently, it is extremely difficult to determine if the number of violations is increasing or decreasing, which rules are most often violated, or if there are companies that are particu­larly bad actors.

Without this information, it is difficult to know where to focus inspection and enforcement efforts.

NOAVs make violation reporting more confusing

The only publicly accessible statistics related to violations are for Notices of Alleged Violations (NOAVs). But COGCC statistics on NOAVs are uncertain.

The statistics on NOAVs reported in COGCC staff reports differ from data downloaded from the COGCC Inspection/Incident Inquiry online database. (See Table

The number of NOAVs does not represent the number of violations because violations do not necessarily lead to the issuance of NOAVs (See Box).

Also, when NOAVs are issued, they may cite violations of more than one rule, order, or permit condition. For example, one NOAV issued to Cutler Brothers on Dec. 28, 2010 cited alleged violations of Rules 604 a(4), 906 e(1), 210 d(1)(2), and 15 other rules.

Violation reporting is inconsistent

A review of 1,000 inspections that took place between August 3 and Sept. 23, 2011, showed 145 “unsatisfactory” inspections, yet only 77 of those inspections listed violations. If rules were broken, the inspection reports should have noted violations. If rules were not broken, then it’s not clear what made the inspection “unsatisfactory.”

Of the 77 inspections showing violations only 11 NOAVs were issued to operators. In some cases, the violations were minor, such as not having the proper signs on tanks.

In other cases, however, NOAVs were not issued even when there were spills or contamination events (see Box 2) or when inspections indicated that operators had been informed of the violation two times before (i.e., it was the third notice).

There were also cases where a similar type of violation (e.g., an open wellbore that needed to be plugged and the well site reclaimed) resulted in an NOAV for one operator but not for another.

The COGCC needs to do a better job of consistently assessing, tracking statistics, and publicly report­ing violations, and the agency should issue NOAVs whenever violations occur.

Assuming that each inspection was conducted at a different well site, approximately 27,000 wells or 63% of Colorado’s active oil and gas wells were not inspected in 2010.

Even fewer inspections were conducted in 2011 (12,239), while the number of active wells increased to 46,835, leaving approximately 34,500 (74%) of active wells with little or no oversight.

Colorado Inspection Data

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Colorado’s inspection capacity lags behind other states

Pennsylvania has greatly increased its inspection and enforcement staff in response to its (Marcellus) shale gas boom. Between 2000 and 2010 the number of active wells in Pennsylvania almost doubled from 36,000 to 71,000. In response to the drilling of thousands of shale gas wells, Pennsylvania Department of Environmental Protection recently quadrupled the size of its enforcement staff to 130 employees, 65 of which are inspectors.

• In 2010, each Pennsylvania oil and gas inspector was responsible for, on average, 1,092 active wells.
• In Colorado, with 43,000 active wells just 15 inspec­tors in 2010, each COGCC inspector was responsible for an average of 2,890 active wells – more than twice the number of their Pennsylvania counterparts.

It is nearly impossible for one inspector to visit, let alone carefully inspect 2,890 well sites a year.

In 2010, each of COGCC’s 15 inspectors performed, on average, 1,082 inspections. That number is high compared to oil and gas inspectors in Pennsylvania, Ohio and New York state, each of whom conducted 253, 499 and 154 inspections in 2010, respectively, and implies that COGCC inspectors are not able to spend as much time on each inspection as their counterparts in some other states.

States, such as Pennsylvania, North Dakota and New York recommend that each producing well be inspected at least once per year, and new wells, especially horizontal wells, be inspected multiple times during the drilling and completion process.

Colorado must hire more inspectors

To do an adequate job of inspecting new and active wells, all new wells should be inspected at least three times (e.g., twice during the drilling/completion process, and once after drilling is completed), and each active well in Colorado should be inspected at least once a year. This means that COGCC should perform at least 55,000 inspections in 2012. In 2011, COGCC conducted 12,239 inspections.

Clearly, the COGCC needs to hire more inspectors to keep up with the growing number of new and active wells in Colorado.

The Colorado Oil and Gas Conservation Commission fails to achieve its mission to “foster the responsible development of Colorado’s oil and gas natural resources.” due to its inadequate enforcement of its own rules.

Under current regulatory enforcement:

• Inspection capacity is inadequate;
• Violations are not consistently assessed;
• Violations are inadequately reported and tracked;
• Fines are rarely issued to violators;
• Fines are inadequate to punish or prevent irresponsible behavior by oil and gas operators;
• The environment is not protected.

Colorado enforcement hasn't kept pace with the drilling boom

Colorado, like many other states, has experienced a drilling boom in the last decade – the number of active wells almost doubled from 22,228 in 2000 to 43,354 in 2010. With a potential shale gas and shale oil boom on the horizon, Colorado is positioned to see even more drilling in years to come. But regulatory enforcement has not kept pace with drilling, and as a result, Colorado’s public health, safety and the environment have suffered.

Colorado Oil & Gas Related Spills

As seen in the above chart compiled from COGCC data reported to the Water Quality Control Commission, there’s been a large increase in the number of oil and gas related spills over the past seven years.

One possible reason for the increase: there's no real incentive for operators to replace faulty equipment or train employees to prevent spills:

• The COGCC rarely penalizes companies responsible for spills; and
• When enforcement actions do occur, they aren't timely.

The five CO spills that led to penalties in 2011

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In 2011, the COGCC imposed fines for a mere five spills, all of which had happened in previous years.

In 2010 and 2011, Noble Energy had more spills than any other operator (126 spills – 81 affected ground water, 6 surface water), yet in 2011 it received an Outstanding Operator Award for environmental protection from the COGCC.

Congratulating the worst spill offender for its efforts at preventing pollution sends the message to both the public and other operators that spills don’t matter and there are no real consequences for breaking the rules.

Dodd-Frank imposes new supply-chain reporting requirements on U.S. companies sourcing conflict minerals from Democratic Republic of Congo (DRC), where the extraction and trade of tin, tantalum, tungsten, and gold are used to finance armed conflicts that have led to atrocious human rights violations, gender-based violence, rampant rape, and slavery. (UN Human Rights Report, State Dept. DRC Report).

This is not a ban on minerals from eastern DRC, it simply requires any company using these minerals to disclose whether those minerals originated from the war-torn eastern DRC.

Congress passed these requirements with the intention of curbing the trade of conflict minerals because “the exploitation and trade of conflict minerals originating in the Democratic Republic of the Congo is helping to finance conflict characterized by extreme levels of violence in the eastern Democratic Republic of the Congo, particularly sexual- and gender-based violence, and contributing to an emergency humanitarian situation therein”

The Securities and Exchange Commission’s Role

The Securities and Exchange Commission (SEC) is tasked with issuing rules telling companies how to comply with Dodd-Frank generally, and section 1502 in particular.

Dodd-Frank gave the SEC 270 days after its passage to issue the new rules governing conflict minerals disclosure. Unfortunately, over 530 days after passage, there are still no rules.

Global Witness defines conflict resources as "natural resources whose systematic exploitation and trade in a context of conflict contribute to, benefit from or result in the commission of serious violations of human rights, violations of international humanitarian law or violations amounting to crimes under international law".

Gold that is mined and traded in conflict areas is, by definition, dirty gold.

Conflict Minerals in the Democratic Republic of Congo (DRC)

In the DRC a decade-long conflict that has produced atrocious human rights violations, gender-based violence, rampant rape, and slavery (UN Report, State Dept. Report). This conflict, and associated atrocities, is often financed by the extraction and sale of conflict minerals. These include tin, tantalum, tungsten, and gold.

It is because of the growing public awareness of conflict minerals, and violence in the Democratic Republic of Congo (DRC), that the US Congress included Section 1502 in the 2010 Dodd-Frank Act. This section requires that companies take steps to understand if their supply chain contains conflict minerals from the DRC.

The goal of Section 1502 is to eliminate demand for conflict minerals by informing consumers whether they’re purchasing goods manufactured with conflict minerals.

Mercury pollution: from gold ore to your table

Mercury is a naturally occurring element in some gold ore, which is primarily released into the air during the ore-heating stage of gold extraction.

Airborne mercury can travel great distances, ultimately settling in lakes and rivers. There, bacteria transform the mercury into methylmercury, which is toxic to humans. The mercury then accumulates in fish.

Predatory fish such as tuna and bass can have dangerous levels of mercury in their flesh, which upon ingestion will build up in humans as well. In 2008, 41 states had advised limiting fish consumption, issuing a total of 3,361 advisories due to mercury contamination. The advisories included over 16 million lakes and over 1.2 million river miles.

Mercury pollution’s toxic impacts on children

According to a 2005 study, between 317,000 and 637,000 children born each year in the United States are exposed in the womb to mercury levels above the Environmental Protection Agency's safety level.

Children of women exposed to relatively high levels of mercury during pregnancy show delayed onset of walking and talking, reduced neurological test scores, and delays and deficits in learning ability. The study further states that diminished intelligence of children exposed to mercury contamination before birth costs the U.S. economy $8.7 billion a year in lost productivity.

State and federal regulatory response

On March 8, 2006, the state of Nevada, home to 14 of the more than 20 gold mines in the U.S., adopted the first regulations requiring mercury pollution controls for gold mines, the Nevada Mercury Control Program. Subsequently, the EPA undertook wider discussions of emissions standards.

On December 16, 2010, the EPA put in place the first nation-wide mercury emission limits for gold and silver mines. The new rule is expected to reduce mercury emissions from 2,260 to 1,200 pounds per year, which is about a 77% reduction from 2007 levels.

In some cases these "best" practices are developed and used by companies to save money.

In other cases alternative practices, or best management practices (BMPs), are required by regulatory requirement.

Voluntary best practices

Some oil and gas companies innovate and improve their systems to cut costs. By cutting air emissions, reducing water use, controlling erosion, and employing other practices that increase revenue, they also reduce impacts on communities and the environment.

Closed loop/pitless waste disposal

For example, technologies have been developed that allow oil and gas operators to forego digging earthen waste pits.  Instead, they used “close loop” systems where wastes enter steel tanks.  For more information on this process and the benefits and profits that it brings to the industry, see Alternatives to Pits.

Natural Gas STAR

Through Natural Gas STAR, a voluntary EPA program, participating companies implement approximately 150 cost-effective technologies and practices that reduce emissions of air pollution from oil and gas development.  In the process, they reduced emissions by 114 billion cubic feet (bcf) in 2008. 

By capturing and selling gas that would have otherwise leaked into the atmosphere, U.S. companies gained revenue of more than $802 million.

Required best practices

Oil and gas production regulations vary in stringency from state to state.  If states with the most rigorous (in terms of protecting communities and the environment) rules – the “best practices” -- still have an active oil and gas industry, it demonstrates that companies can be better actors and still be competitive.

When these best practices are first codified industry will often challenge the new rules.  They invariably argue that the cost of implementing the best practices will force them to go elsewhere. 

Colorado’s Pit Rule

This happened in 2008 when the Colorado Oil and Gas Conservation Commission updated its rules.

One update required the disposal of pit liners in accordance with solid waste regulations -- using certified landfills or recycling them.  Previously, operators were allowed to bury potentially toxic pit liners at the drilling site. 

The Colorado Petroleum Association initially objected to the rule, but ultimately reconsidered. Meanwhile, one company, Williams, developed innovative ways to work with the rule – by “turning the waste into a resource.” Williams bales the liner and sells them to industries that recycle them into non-food-grade industrial products like bumpers or pallets; and by circumventing the need for drilling pit liners by switching to closed loop drilling systems.

Principles of legitimate 1872 Mining Law reform should include:

Protecting special places from mining

Under the federal government's current interpretation, land managers give preference to mining over all other land uses - from recreation to drinking water supplies to hunting.

This leaves special places like the Cabinet Mountains Wilderness, and the wild and scenic Chetco River in danger from mineral development.

Reform of the mining law must recognize that there are some places that should not be mined and must clearly give land managers the ability to deny a mine proposal if there are other important resource values that could be damaged by a mining operation.

Strengthening environmental standards

There are no statutory environmental standards written specifically for mining on lands open to location under the 1872 Mining Law.

The Clean Water Act does not protect groundwater from mining pollution, and there is no definition of how to reclaim a mine, for example. Mining industry-specific environmental standards must be created to:

• protect surface and groundwater quality from erosion and toxic discharge;
• require landscape restoration concurrent with mining; protect topsoil and wildlife habitats;
• require productive native revegetation; and
• minimize and neutralize mine wastes.

Fiscal reforms

The 1872 Mining Law currently provides the mining industry with billions of dollar in subsidies. The two most egregious:

• unlike all other extractive industries, hardrock mining pays no royalty for minerals taken from public lands;
• for $5 an acre, mining interests have patented (purchased) an area roughly equivalent in size to the state of Connecticut containing minerals valued at more than $300 billion.

A new, reformed mining law should end patenting, and establish a fair royalty -- based on the value of the mineral extracted.

Enforcement, inspection, and bonding

Enforcement and inspection

Currently, public land managers cannot enforce what mining regulations that do exist. Instead, they must petition the Justice Department to do so - a slow and cumbersome process.

Under a reformed mining law, land managers must have the authority to ensure operator compliance by requiring:

• enforcement actions for violations,
• frequent inspections, and
• civil and criminal penalty assessments.

Additionally, new mining permits must not be given to operators with outstanding violations.

Bonding and financial guarantees

To protect taxpayers and provide incentive to fully comply with the law, financial guarantees must be required for all phases of operation that would completely cover the cost of both reclaiming the mine and the costs associated with managing the reclamation.

Financial guarantees must be backed by concrete financial instruments. Self-bonding/corporate guarantees is not acceptable.

Abandoned mine reclamation fund

There are more than 500,000 abandoned hardrock mines in the United States that will cost between $32 and $72 billion dollars to reclaim. Currently there is no funding source for abandoned hardrock mine reclamation. An abandoned mine land fund, paid for through mining royalties and fees, is needed to clean up the scarred landscapes and polluted waters left by the mining industry.

The mining industry was different over 130 years ago, when the 1872 Mining Law was signed into law by President Ulysses S. Grant. The law was written to govern the archetypal "miner 49'er": a grizzled prospector with a mule and a pick axe.

Today, mining is largely the business of billion dollar, multinational corporations operating in a global market. And many of the largest mining companies operating in the United States are foreign owned. For example, according to the U.S. Geological Survey, seven of the top ten producing gold mines in the U.S. are foreign owned.

Mines Visible from Outer Space - Environmental Impacts to Match

A huge mining industry digs huge mines.

Modern mines are enormous operations that leave behind scarred landscapes, polluted water and damaged communities. Hardrock mining, the extraction of metals such as gold, silver and copper, can cause significant impacts on the environment, potentially affecting ground and surface waters, aquatic life, vegetation, soils, air, wildlife, and human health.

...now (inadequately) governs multibillion dollar operations large enough to be visible
from space, like Barrick's Cortez open pit mine in Nevada. Photo: Travis Rummel

That's because rich mineral deposits, containing visible veins of ore, are a thing of the past.

A modern mine extracts "mineralized" deposits -- where the ore contains only microscopic quantities of gold (or copper, silver, etc.) As a result, mining is extremely wasteful. For example, mining enough gold for a single ring creates 20 tons of mine waste.

To extract the huge volumes of waste rock and ore necessary to produce the gold/silver/copper, most modern mines are enormous open pits. These pits often exceed 1 mile in diameter and 1,000 feet in depth. Some, like the Bingham Canyon mine in Utah, are visible from orbit.

The pollution impacts of these operations are proportional to their size: according to the EPA, hardrock mining is the number one toxic polluter in the United States, and has polluted 40% of the stream reaches of the headwaters of western watersheds.

The 1872 Mining Law governs hardrock mining on 350 million acres of public domain lands -- mostly in the West and Alaska. This constitutes more than 15% of all the land in the United States, or two thirds of the lands the federal government holds in trust for all Americans.

Public domain lands

Public domain lands consist of lands ceded to the federal government by the thirteen original states, plus "acquisitions" from Native Americans and foreign powers, and that have remained continuously in federal control since acquisition. For example, the Louisiana Purchase was all public-domain lands at one time.

Public domain lands do not include lands purchased or otherwise acquired by the federal government within the existing boundaries of the United States. For example, almost all National Forests east of the Mississippi River are not public domain lands, even though they are publicly owned lands.

Hardrock minerals

Practically speaking, hardrock minerals are mainly metals like gold, copper, and uranium. These metals constitute the vast majority of the value of mineral production governed by the Mining Law.

Specifically, hardrock minerals are actually defined by what they are not. When originally passed, the Mining Law governed all types of mining. Over the past 135 years, certain types of minerals have been removed from its jurisdiction -- including common materials like limestone, and all fuel minerals such as coal, oil and natural gas -- except uranium.

The right to mine -- staking a claim

Under the 1872 Mining Law, any U.S. citizen (including foreign companies with subsidiaries incorporated in the U.S.) can freely enter public domain lands to explore minerals. No permit needed. A small subset of public domain lands are excluded (e.g. National Parks and Wildernesses).

According to the Mining Law, once you discover a valuable hardrock mineral, you can then establish your right to mine that mineral by staking a claim. In practice, the federal government rarely checks to see if you've actually made a valuable discovery.

The right to mine -- the "highest and best use"

Once a claim is staked, the federal government has historically treated the claim as equivalent to a right to mine.

All other types of mine proposals (e.g. coal) on public lands must be weighed against other potential land uses before permittal.

But in the modern era, federal land management agencies have consistently argued that they cannot deny hardrock mining proposals because of the 1872 Mining Law -- federal land managers insist that, in the eyes of the Mining Law, mining is the highest and best use of public lands.

The 1872 Mining Law was signed into law by President Ulysses S. Grant. It was passed to promote the development and settlement of publicly-owned lands in the western United States.

A law that rips off taxpayers

The Mining Law promotes development by allowing mining interests to --

• take valuable hardrock minerals including gold, silver, and uranium from public lands without royalty payment to the taxpayer -- unlike other mining industries that extract coal, oil or natural gas;
• buy valuable mineral bearing public lands for no more than $5 per acre -- 1872 prices.

A law with a heavy environmental price

19th century America wasn't concerned with environmental protection. So the mining law doesn't contain environmental protection provisions. Communities and environments have paid the price.

One result: hundreds of thousands of abandoned mines.

According to EARTHWORKS estimates, it will cost taxpayers between $32-72 billion to clean up these mines. And taxpayers are potentially liable for billions more in cleanup costs at currently operating mines.

Another result: according to the Environmental Protection Agency, 40% of the headwaters of western U.S. watersheds have been polluted by mining.

A law that trumps all other land uses

The Mining Law has been historically interpreted to trump all other potential uses of public lands. If you hold a mining claim, that claim is treated as a right-to-mine by the federal government. The federal government is on record as saying that they cannot say no to mining proposals.

Even if those proposals threaten some of America's most special places. Even if those proposals pollute clean water.

A law in need of reform

It's the 21st century. The western U.S. is developed. And settled. Now we need to take care of the people (and communities) that settled there.

The way forward

EARTHWORKS is working to reform this archaic law to better protect taxpayers, communities and the environment. We work with federal, state and local government, the mining industry, and impacted communities.

Smith-Highland Ranch:
Wyoming’s “model” for ISL mining

Power Resources Corporation, owned by Cameco, owns and operates the Smith Ranch and Highland ISL facilities in Converse County, Wyoming. Together, the facilities form the largest uranium production facility in the United States.

In 2006, Cameco Corporation received certification under the ISO 14001:2004 program, one of the most internationally recognized standards for environmental management. The certificate was awarded to Cameco for its excellence in environmental protection and implementation of “best practice” environmental management system at its Smith-Highland facilities.[1]

Just over a year later, the Wyoming DEQ slammed Smith-Highland Ranch with several environmental violations.

• A DEQ investigation in the fall of 2007 revealed that the Smith-Highland ISL projects had “an inordinate” number of spills, leaks, and other releases. According to the WDEQ documents there were over 80 spills reported. Of the 202,247 gallons of mining fluid spilled, only 3,500 gallons were recovered.[2]
• Other violations included delayed restoration of groundwater, “routine” spills, and a bond inadequate to cover restoration costs.
• Power Resources Corporation routinely violated DEQ laws directing underground water restoration to occur simultaneously with ongoing production.[3]
• The cleanup efforts had suffered due to inadequate staffing, high turnover, and lack of corporate commitment.

In July 2008, Cameco agreed to pay a total of $1.4 million in fees to the WDEQ and state for the numerous violations.[4]

The Smith-Highland Ranch is not only an example of the potential environmental hazards associated with ISL operations, but also the poor oversight of ISL projects in Wyoming. ISL production of uranium is the primary method of uranium extraction today, and the DEQ should have stronger oversight over these operations.

Lincoln Park/Cotter Mill:
Canon City's Superfund site

Cotter Mill Superfund site. Note the golf course immediately
to the north. Photo: Google Maps

The Canon City Mill site located just outside of Canon City, Colorado is owned and operated by Cotter Corporation, a Colorado based uranium mining group.

The mill operated continuously from 1958 until 1979, and has operated intermittently since that time.

Before 1980, Cotter Corporation disposed of tailings and other wastes from uranium processing into unlined bonds. Contaminants such as molybdenum, uranium, and uranium daughter products leached into the groundwater and migrated to Lincoln Park and nearby local wells.[5]

As a result of high contamination levels, the US EPA placed the Cotter mill on the Superfund National Priorities List in 1984.

Since decommissioning and reclamation efforts at the mill began, Cotter Corporation has been cited for numerous labor and environmental violations and has continuously shown negligence of EPA standards and requirements.

Among the several labor violations and contamination spills, Cotter Corporation pleaded guilty in March 2008 for its role in the poisoning deaths of migratory birds at the mill. Approximately 40 geese were killed after coming into contact with the solvent in the pond.

Previously stating that the mill would eventually reopen, in September 2010, Cotter made a statement telling regulators they would discontinue testing radon emissions on the site because it is no longer an active facility subject to regulation.[6]

The battle continues, as many environmental groups question Cotter Corporation’s commitment to environmental protection.  A citizens group filed a lawsuit in September 2010 accusing Colorado regulators of failing to require Cotter Corp. to set aside enough money to clean up its uranium mill in Canon city. The department estimated costs of at least $43 million, while Cotter set aside only $20.2 million.[7]

The Schwartzwalder Mine:
Cotter Corp. vs. Colorado Mined Lands Reclamation Board

Once one of the nation’s largest underground uranium mines, the Schwartzwalder Mine is located in Jefferson County northwest of Denver, Colorado.

Colorado Cotter Corporation acquired the Schwartzwalder Mine in 1965 and was operational until 2000. The uranium deposit was discovered in the 1940s and was developed as a multi-level, hard rock underground uranium mine.[8]

As a result of the drop in uranium prices in the past decade, Cotter Corporation shut down the Schwartzwalder Mine and started reclamation.

The Schwartzwalder Mine has faced many environmental issues since its closure. The Colorado Department of Public Health and Environment and Cotter Corporation have yet to settle on a plan for cleanup.

Today, groundwater near the Schwartzwalder Mine contains uranium levels that are 1,000 times higher than human health standards.

Since April 2010, Cotter has faced numerous state orders to pump and treat the toxic water that is filling the mine and allegedly contaminating nearby reservoirs. Ralston Creek, which flows into Denver Water’s Ralston Reservoir, contains uranium levels 310 ppb.

In August 2010, Cotter agreed to remove tainted water from its mine, but had chosen to pump and clean only surface ponds and not the water inside of the mineshafts.

Despite high uranium concentrations in nearby water resources, Cotter Corporation defied state orders to clean up the site and refused to pay state fines ($55,000) for failing to do so. Cotter Corporation claims that the mine water is not contaminating Ralston Creek, therefore has no obligation to pump and treat this water immediately.

The Schwartzwalder Mine has been in environmental non-compliance for 12 of the past 12 quarters. Concentration violations include uranium, boron, chromium, copper, cyanide, fluoride, zinc, thallium, radium 226, and radium 226 as well as several other environmental violations.

In October 2010, Cotter Corporation filed a lawsuit against Colorado’s Mined Lands and Reclamation Board for abusing its discretion when it ordered Cotter to pump out and treat uranium-tainted water. At issue is whether state regulators had enough evidence to order the cleanup and impose large fines against Cotter Corporation.[9]

As the legal battle continues between state departments and Cotter Corporation, water in the mining shaft still poses as a threat to water resources.[10]

The case at the Schwartzwalder mine has many environmental groups up in arms. “The mess at Schwartzwalder shows that Colorado isn’t ready for a new uranium boom,” spokesman Matt Garrington said. “We have abandoned and inactive uranium mines littered across the state that haven’t been cleanup up and are still causing environmental problems.”[11]

In situ leaching - what it is

ISL involves injecting chemicals, called “lixivants” into an aquifer that contains a uranium ore body (i.e. deposit). The chemicals used are typically sulfuric acid or ammonium carbonate. 

Under natural conditions, these ore bodies are localized and the radiation and heavy metals associated with them remain confined in small portions of an aquifer. Because under natural conditions the toxic substances associated with uranium ore bodies are locally confined, their host aquifers can be – and often are – used as drinking water sources. 

When lixiviant is injected into an aquifer, it creates a chemical reaction with the uranium, causing it to spread over large areas of an aquifer.  The uranium plume is brought to the surface with a series of “production wells” and processed for shipment to enrichment facilities.

In the US the production life of a well field is roughly 1 to 3 years 1. However, groundwater restoration efforts can last for decades.

Permitting and regulation

In situ recovery process.
Image: Nuclear Regulatory Commission

ISL operations are permitted and regulated by the Nuclear Regulatory Commission (NRC) or through agreement with states.

The NRC currently regulates ISL operations in Wyoming, Nebraska, and New Mexico.

In all cases, ISL uranium mines must obtain -

1. an aquifer “exemption” permit to degrade the quality of groundwater resources, and
2. an underground injection control permit from a state regulatory agency or the EPA in order to pollute the groundwater during the mining operation.

Exempted aquifers are exempted from the Safe Drinking Water Act and cannot be used as a future underground source of drinking water.

Regulation of ISL operations has proven problematic.

Environmental pollution from ISL: inevitable

The primary problem with ISL regulation: the NRC acknowledges that, although ISL permits require complete restoration of groundwater conditions after mining operations, some of the “baseline parameters” have proved to be unachievable by mining companies.

While the uranium mining industry insists that ISL mining methods are environmentally safe, numerous fines and violations by regulatory agencies have shown just how problematic ISL operations can be.

The increase in ISL environmental violations in recent years has led many states to relax environmental standards rather than impose stricter regulations against the mining companies.

Of the 8 currently operating ISL operations in the United States, only one has not had any reported environmental violations (Alta Mesa, Texas). Most ISL projects have had numerous spills, contaminated underground aquifers, and have failed to reclaim non-operating on site wells.

The state of Texas has produced a document Waste Minimization in the Oil Field that provides a general overview of waste minimization techniques for wastes arising from oil and gas operations, including drilling operations. The document also provides case studies of successful waste minimization projects and a bibliography of useful technical references. The document includes dozens of examples of alternative drilling practices, such as:

• Product substitution. Replacing conventional, toxic products with less toxic, yet effective, substitutes. For example, companies are substituting low toxicity glycols, synthetic hydrocarbons, polymers, and esters for conventional oil-based drilling fluids. The use of these substitutes eliminates the generation of oil-contaminated cuttings and other contamination by the oil-based fluid and decreases concerns related to site clean-up when the well is abandoned. Drilling engineers have published numerous technical papers that describe the successful application of substitute drilling fluids. In many instances, this substitution has resulted in significant cost savings. Similarly, companies have designed alternatives to the conventional water- and chemical-based hydraulic fracturing techniques, by substituting carbon dioxide for the more common and more toxic fracing fluids.
• Process or procedural modifications. For example, in the past few years the drilling industry has improved the technology of slim hole drilling. If feasible, slim hole drilling reduces the volume of wastes (e.g., drilling fluid and the drill cuttings) produced during drilling. The total cost of a slim hole drilling operation may be considerably less than for conventional hole sizes, and smaller casing is required, which may help reduce the total cost of the operation.
• Reduction in water use. For example, companies can reclaim water from waste drilling fluids by using mechanical or chemical separation techniques such as large bowl centrifuges, hydrocyclones, and/or chemical flocculants. The reclaimed water may then be reused, thus reducing the demand on, and cost of, new water sources. Dewatering of wastes may also result in a reduction of the volume of drilling waste to be managed, thus saving waste management costs, easing site closure concerns and costs, and reducing future potential liability concerns.
• Preventative maintenance. For example, chemicals and materials should be stored so that they are not in contact with the ground (e.g., stored on wooden pallets), or exposed to the weather. There should be secondary containment in the case of spills. All drums and containers should be kept closed except when in use. It is very important that all chemical and material containers always be properly labeled so that their contents may be identified at any time. Proper storage and labeling of containers allows quick and easy identification and classification of released chemical or material in the event of a leak or rupture. In some instances, that could save hundreds of dollars in soil sampling and laboratory analysis costs.
• Recycling. For example, the cost of closing a drilling site is increased if waste drilling fluid in a reserve pit must be dewatered and/or stabilized prior to closure. An alternative is to recycle or reuse the waste drilling fluid, e.g., in another drilling project. One company designed a multi-well drilling project where the same drilling fluid was used for drilling each successive well. The result was significant cost savings and greatly reduced waste management concerns. Another cost effective alternative for reuse of waste drilling fluid is in plugging or spudding of other wells.

Pollution Prevention and Waste Management

• Drilling Waste Management Information System is an online resource created by the Argonne National Laboratory and industry. It contains technical and regulatory information on standard and “optimal” practices for managing drilling wastes.
• A Pollution Prevention Opportunities Guide for the Oil Field Service Industry.  Alaska Department of Environmental Conservation Pollution Prevention Office.New Mexico Energy, Minerals and Natural Resources Department's two-volume handbook on Pollution Prevention - Best Management Practices for the Oil and Gas Industry.
• The Railroad Commission of Texas (state regulatory body) has produced a Minimization in the Oil Field Manual; and a program devoted to waste minimization in the oil and gas industry; and a page of links to other waste minimization resources for the oil and gasindustry.
• U.S. Environmental Protection Agency Oil and Gas Industry Sector Notebook describes pollution prevention opportunities.
• Best Management Practices for Oil Exploration and Extraction produced by the Illinois office of the EPA.
• Southwest Pollution Prevention Center, Gas and Oil Hub provides information on oil and gas pollution prevention alternatives for all stages of oil and gas development, and it lists of wastes associated with various stages of oil and gas operations.

• Emissions of greenhouse gases and other pollutants can be reduced by using a number of cost effective technologies and practices.  These include monitoring and pinpointing fugitive emissions, and then sealing the leaks; using lower heater treater temperatures; connecting storage tanks to flare systems; converting gas-driven chemical pumps to electric-, air- or nitrogen driven pumps; compressing casing gas and shutting down line pigging. Also, air emission may be decreased by installing: no-bleed or low-bleed pneumatic devices; vapor recovery units; high efficiency flares; closed-loop skimmers on water tanks; and separator pumps and evacuators on pipeline bleeders.[1]
• If the control valves on a pump's separator unit, which separates the methane and water, are replaced with better valves, methane emissions to the atmosphere can be reduced. This will have positive environmental benefits, as methane is a powerful greenhouse gas that contributes to global warming. By replacing 3,300 controllers on 2,760 wells in Colorado and New Mexico, the Colorado Oil and Gas Conservation Commission expects that methane emissions will be reduced by 12,000 tons per year in the San Juan Basin. According to an engineer with the company BP, replacing valves not only has a positive benefit with greenhouse gases, it also has a positive economic benefit for that company.[2]
• Wellhead compressors that are powered by natural gas emit NOx and VOCs (which contribute to ground-level ozone) and carbon monoxide. According to the federal Bureau of Land Management, there are add-on technologies, such as catalytic converters, that can reduce these emissions by as much as 95%.[3]
• Cavitation baffle systems (large storm sewer concrete pipe) can be used to reduce flare height and contain the majority of coal dust during coalbed methane cavitation operations. [4]
• Barrett Resources Corporation has minimized odors, a common complaint from surface owners, from some of its natural gas production sites by using combustion units designed to destroy vapors released by condensate tanks and glycol dehydrators. These units also reduce emissions of methane (a greenhouse gas), and other hydrocarbons that can affect visibility.
• Standard glycol dehydrators which are used to remove water from natural gas, typically vent water and hazardous gases directly into the atmosphere. Glycol dehydrators are a major source of benzene emissions within the oil and gas industry. Fatalities from human exposure to high concentrations of benzene have been documented since the early 1900s, and studies have shown correlations between workplace exposure to benzene and the onset of certain forms of leukemia. The issue of air emissions from glycol dehydrators has only been identified in the past couple of decades. Most of the glycol dehydration units are installed in rural environments; they are typically left unattended, and emissions are not regularly monitored.
  Emissions from glycol dehydrators can be reduced by: optimization of operations; equipment modifications or replacement; and/or, addition of emission control equipment. Emission controls such as condensers, flare stacks, and incinerators for still column vent vapors have been installed by industry at some locations. Research by the U.S. EPA has indicated that operators of glycol dehydrators often maintain a circulation rate that is at least two times higher than is needed to remove enough water from the gas. Therefore, companies can reduce their glycol use by performing simple calculations to determine the minimum circulation rate needed. By doing so, they will lose less methane to the atmosphere; improve the dehydrator unit efficiency; and decrease fuel pump use. EPA has calculated that by doing so, the potential savings for a dehydrator unit can range from $260 to $26,280 per year.[5]

Benefits of Directional Drilling

Horizontal and vertical well on one pad, Vermejo Park Ranch

The benefits of directional drilling are numerous. Using these techniques, companies can drill a number of wells in different directions from one well pad (multilateral wells), which can decrease overall surface disturbance by reducing the number of well pads required to drain an oil or gas field.

Studies also show that directional drilling has been successful in a variety of geological formations (e.g., shallow reservoirs, deep reservoirs, tight sands, coal beds, tar sands). Furthermore, if horizontal drilling is used in coal beds, there may be no need to hydraulically fracture the beds, resulting in a decreased potential for groundwater pollution.

Directional drilling diagram. Credit: Geology.com

Perhaps the greatest benefit to the surface owner, or for the protection of sensitive ecosystems, is the ability to locate well sites away from residences or other areas that should not be disturbed. It is now possible for companies to access oil or gas by drilling a well that is miles away from a specific property or site.

A major benefit to the companies and mineral owners receiving royalties is increased oil and gas production. Oil- and gas-bearing formations tend to be more wide than they are deep, consequently, wells that intersect a producing formation at an angle or horizontally often can drain more of the oil and gas than purely vertical wells. There are numerous studies showing that directionally drilled wells have been able to extract 2- 25 times more oil or gas than vertical wells drilled in the same oil or gas field.

The drilling of a directional well is more costly than drilling a typical vertical well because it requires specialized equipment; constant attention to the placement of the drill bit; it takes several days longer to drill the wells; and pumping costs may increase because parts may wear out faster. According to the U.S. EPA, however, the increased costs of directional drilling are often more than offset by increased production and the reduced need for drilling multiple wells.

In the Dundee Formation of Michigan, as much as 85 % of the known oil remained in the formation after many years of production, but many wells were on the verge of being plugged because daily production had fallen to only five barrels of oil per well. The U.S. Department of Energy co-sponsored a project to drill a horizontal well in the formation. This well produced 100 barrels per day. The program attracted other well developers, and 20 to 30 additional horizontal wells are being drilled in the formation. It is estimated that the application of horizontal drilling to this formation may yield an additional 80 to 100 million barrels of oil.

Examples of Regulations Requiring the Use of Directional Drilling

In the Ignacio-Blanco field of the San Juan Basin of Colorado, the typical spacing of coalbed methane wells is one well per 160 or 320 acres. In 2005, several companies approached the Colorado Oil and Gas Conservation Commission because they wanted the ability to drill one well per 80 acres in order to extract the methane.

The COGCC granted the companies the ability to have 80-acre DOWNHOLE spacing. On the ground surface, however, the companies were required to drill the new well from an existing pad (which they are allowed to enlarge, but only slightly). In other words, the SURFACE spacing will remain at one welllpad per 160 acres.

While it does not explicitly mention "directional drilling," in practice, In order to access the gas from an existing pad the companies in La Plata County are going to have to directionally drill.

• Read the COGCC Order No. 112-180, which outlines the requirement to drill from an exisiting (or "common") pad.
• Read the Memorandum of Understandings signed by BP and La Plata County, which also includes a provision to drill from existing well pad unless that is found to be "impractical."

In flareless or green completions the gas that comes to the surface is separated from fluids and solids using a series of heavy-duty separators (sometimes referred to as "flowback units"). The water is discharged to tanks to be reused, the sand is sent to a reserve pit, and the gas is either cycled back through the well bore, or sent to a pipeline to be sold rather than vented or flared. According to the U.S. Environmental Protection Agency (EPA), benefits of this system include: the elimination or reduction in venting or flaring of natural gas; sale of the gas and condensate provides the operator with an immediate revenue stream; there is a reduction in solid waste and water pollution; and the system enables safer operating practices.

Emissions Reductions: One company, which drilled 63 wells using flareless completions, reported a reduction in natural gas emissions of 7,410 thousand cubic feet per year, which is 70% of the gas that would formerly have been vented to the atmosphere. [2] Another company has been able to reduce flaring by 85-90%.[3]

Costs and Pay-Back: The capital costs for companies include the use of separators, sand traps and tanks. One company reported these costs as being $180,000. The equipment, however, can be moved from site to site, so if a company were to complete 60 wells per year the annual capital charges would be less than $10,000. Operating costs are less than $1,000 per year. EPA has estimated that "green completions" can pay back their costs in about 1 year.

An alternative to sending the gas to the pipeline is to send it to a flare tank. Flare tanks capture and more fully combust the waste gases. The tanks can be carried from site to site. This practice avoids the costs associated with excavating and reclaiming flare pits, and avoids the potential liability associated with cleaning up soils contaminated by flaring.

To mitigate noise impacts from engines, a sound barrier made out of four inches of insulation and 18-gauge steel can be used. Sound barriers are placed in an L-shape above the engine, and they extend past the sides of the engine.[2] Some engines can operate at a constant number of revolutions per minute (RPM), which reduces the updown noise caused by other engines, which speed up and slow down. Mufflers, like those used for automobile engines, can be used to minimize engine noise.[3] To reduce noise in sensitive areas, well-site or field compressors may be enclosed in a sound-insulated building, and equipped with two buried hospital-grade mufflers in series.

Noise from compressors can be mitigated by treating each significant noise source: gas turbines or engines, compressors, exhaust outlets and air inlets, and cooling and ventilation fans. Abatement may involve changing the blades on fans, which can change the frequency of sound emitted, thereby removing the annoying tones. Engine noise can be muffled using automotive-type mufflers, or by housing the engines inacoustically insulated structures. Also, the entire compressor can be housed in an acoustically insulated building.

After the drilling phase if over, the portion of the drilling pad not needed for oil or gas production can be reclaimed. This is known as interim reclamation, and it is required by law in many states. Unfortunately, lack of enforcement by state agencies means that interim reclamation does not occur in many jurisdictions.

During the drilling phase, pad size can be reduced by drilling multiple wells from one site. For example, at the Vermejo Park Ranch two or more wells have been drilled from the same pad (see directional drilling).

Redesigning pits can decrease the amount of surface disturbance.

If a pitless drilling system is not used for drilling fluids, another approach may be to use a V-shaped pit instead of the traditional rectangular pit. This type of pit reduces water requirements, as well as the amount of surface disturbance.

The design is as follows: the open end of the "V" faces the drilling rig and the cross-sectional view resembles a squared-off funnel (about 10 feet deep with the upper 5 feet having slanted walls to a width of about 20 feet). Because the fluid must travel the full length of the pit, this design prevents mud from channeling between the discharge point and the suction point, and reduces the amount of water that must be added to maintain the desired fluid characteristics. In addition, because the V-shaped pit is long and narrow, it is easier to construct and leaves a smaller "footprint" at the site.[1]

A company installed a V-shaped reserve pit and compared the costs with those incurred at similar-sized wells using a traditional pit. The company determined that pit construction time was reduced by about 40 percent, water costs for the well were reduced by about 38 percent, and pit liner costs were reduced by about 43 percent. The total cost savings were about $10,800 per well.

It should be noted that whenever earthen pits are used to store wastes, they should be lined with multiple layers of synthetic fabric with leak detection devices between the layers.

A low-profile pumping unit can replace the conventional unit, which uses a 30- to 40-foot beam and looks like a giant, bobbing horse's head. The conventional pump is run on a gas- or diesel-powered engine, which is noisy and smelly. Alternatives to this large pump include using a pneumatic pumping device that doesn't require an engine, therefore, produces little or no noise. This pump stands about 10 to 15-feet tall. According to one company, pneumatic pumps will not function correctly if a lot of water is extracted while extracting methane gas. [1] When larger amounts of water are produced, an alternative to the standard beam pump is the progressive cavity pump. These pumps come in different shapes and sizes, and like the pneumatic pump, they can turn on electric motors, and therefore, be much quieter than conventional pumps.

If pits are used to store oil and gas wastes, they should have, at minimum:

• two layers of liners,
• a leak detection system between the liner layers,
• fences tall and strong enough to keep out wildlife, and
• nets or other devices installed to prevent birds from coming in contact with the wastes.

Pits aren't necessary

There are more environmentally friendly alternatives to using pits (even lined pits):

• Closed containment systems (tanks)
• Closed-loop drilling systems
• Closed-loop drilling case studies

Closed Containment Systems

A closed tank system - that needs improving.
Photo: USFWS

Oil and gas operators can use closed containment systems (e.g., tanks that are not open on top) in place of various production pits.

As with pits, it is important that tanks be enclosed by fences and nets. Otherwise, birds, wildlife and livestock may still be attracted to the liquid in the tanks.

Tanks have a tendency to corrode with time and develop leaks. And they may overflow if their capacity is not adequate to hold the wastes (and any precipitation if the tanks are not enclosed).

The New Mexico Oil and Conservation Division's document Pollution Prevention Best Management Practices for the New Mexico Oil and Gas Industry suggests the following measures to prevent contamination from tanks. [1]

• All above ground tanks that contain fluids other than fresh water must be contained in an impermeable bermed enclosure to contain a volume of one-third more than the total volume of the largest tank or of all interconnected tanks.
• All below grade tanks. . . must have secondary containment and leak detection.

Leaking tank in San Juan County, NM.
Photo: San Juan Citizens Alliance

The photo of the system above (credited to USFWS) does not have adequate secondary containment. If a leak were to develop underground the wastes would seep into the soil, contaminating the soil and possibly the groundwater. The lid does adequately prevent wildlife and birds from accessing the wastes. The pipe coming out of the lid allows venting of any built-up gases in order to prevent explosions.

The tank in the photo to the right has a steel-mesh lid to keep out wildlife and birds. The secondary containment pit has prevented the fluids from flowing all over the well site, but the waste fluids have seeped into the surrounding soil. Thus, it is possible that groundwater contamination has occurred. These wastes, which may contain toxic chemicals, are now accessible to wildlife.

Benefits of closed containment systems

• Tanks require little or no maintenance.
• Tanks may be reused (moved to a new site) when the well stops producing.
• Tanks isolate waste products from the environment; if enclosed tanks are installed, there is no need to install fences or netting to keep out wildlife and livestock.
• These systems greatly reduce or eliminate soil contamination, thereby reducing remediation costs.

Examples of closed containment systems:

Aboveground tank in San Juan County, NM.
Photo: San Juan Citizens Alliance

• In 2003, the Farmington, New Mexico City Council approved five gas wells on the condition that the company agreed to store condensate wastes in buried tanks; and install double walled condensate tanks as a means of leak protection.(Source: Laura Banish. February 12, 2003. "Farmington council approves five new gas wells," Farmington Daily Times).
• Many well sites in New Mexico use tanks to hold production wastes, but most lack leak detection devices and adequate secondary containment systems.

In the photo to the right, the tank has a solid top to prevent wildlife access. But there is no secondary containment system to prevent any fluids that overflow from seeping into the soil,  and there is no way to easily detect if the bottom of the tank is leaking.

Closed-loop or "Pitless" Drilling Systems

During drilling operations, "closed-loop" drilling fluid systems (sometimes referred to as "closed mud" or "pitless" systems) can greatly reduce or eliminate the discharge of toxic drilling wastes on site. These systems negate the need for drilling reserve pits. Not only is it possible to have pitless drilling operations, it can also be an economic advantage to companies to used closed-loop drilling systems.

Many companies are using closed loop drilling systems in Texas, Louisiana, Oklahoma, Alaska and other states. Examples of companies who are using closed-loop technologies include: Shell, El Paso, Chevron-Texaco, Exxon, and many others.

Differences between conventional drilling and closed-loop drilling systems

Drilling reserve pit. Photo: Dan Randolph

At a typical oil or gas drilling site, drilling fluids (mud, water, additives) are circulated through the wellbore, then the fluids and drill cuttings (rock fragments created by the drilling process) are deposited in a reserve pit dug near well. This pit is used to hold used drilling fluids and wastes.

A reserve pit can be the source of considerable costs at a drilling site.

• The pit itself must be constructed at the beginning of drilling, which requires the use of heavy earthmoving equipment.
• The pit may have to be lined.
• When the drilling project is over, the pit, including all of the waste fluids and solids, must be properly remediated. Remediation could include activities such as: the removal and offsite disposal of the waste materials and liner; the burial of the wastes and liner; backfilling of the pit with soil; and revegetation of the disturbed pit area.

Also, there are health, environmental, and financial risks associated with pits, which can contaminate soils with hydrocarbons, metals and salts, and leak potentially toxic liquids into surface or groundwater. [2]

Closed-loop drilling site in Colorado
Photo: Dan Randolph

In a closed-loop drilling fluid system, the reserve pit is replaced with a series of storage tanks that separate liquids and solids. Equipment to separate out solids (e.g., screen shakers, hydrocyclones, centrifuges) and collection equipment (e.g., vacuum trucks, shale barges) minimize the amount of drilling waste muds and cuttings that require disposal, and maximize the amount of drilling fluid recycled and reused in the drilling process. The wastes created are typically transferred off-site for disposal at injection wells or oilfield waste disposal facilities.

The tanks represent an additional cost, but overall, pitless drilling can save an operator money because there is no need to construct a pit, there is a reduction in the amount of environmental releases, and the closed-loop system results in more efficient use of drilling fluid.

Benefits of Pitless Drilling:[3]

• it eliminates unsightly and hazardous pits
• it reduces the time, energy and expense of building, fencing and reclaiming reserve pits
• it decreases the need for cuts in sensitive and hilly areas
• total surface disturbance associated with a well pad is reduced
• it eliminates risk of waterfowl and wildlife mortality related to pits
• it eliminates risk of damaging underground pipelines and utilities
• it allows drilling in areas with a high ground water table
• it virtually eliminates drilling waste
• rigs use less water per well - it can reduce water consumption by as much as 80%
• the US Environmental Protection Agency (EPA) has estimated that "closed loop systems" can reduce the volume of drilling fluids by as much as 90% [4]
• it eliminates soil segregation, which reduces wind erosion problems
• it reduces truck traffic associated with transporting drilling wastes by as much as 75%
• it may improve relationship with surface owners
• it greatly reduced waste tracking and need for land farming operations
• drill cuttings may be put to beneficial use, e.g., if not contaminated they may provide a source of finely-ground clay for berm construction around tank batteries or other uses
• the tanks can be re-used

Closed-loop systems reduce company liability

Pits may or may not be lined (depending on the oil and gas regulations); and pits are open to the atmosphere. Because of this, the pit may leak liquids into surface or groundwater and release high levels of volatile organic compounds, which in turn create health, environmental, and financial risks. If improperly fenced, livestock may enter the pit area. If the livestock is poisoned by the pit materials, companies may be liable for the deaths, and be required to compensate the livestock owner.

According to the Railroad Commission of Texas, even though closed-loop drilling is not always the least expensive option, some companies in Texas have elected to use only closed-loop drilling fluids systems in their operations. Why? Because whenever a closed-loop system is used, the operator reduces the potential future liability associated with a conventional earthen pit, and reduces the waste management and site closure costs. It's also good for the company image and public relations.

Increased Utilization of Closed-Loop Drilling

According to a paper entitled "Bulk Transportation of Drilling Wastes," delivered at an American Association of Drilling Engineers Conference in 2002:

. . .environmental concerns and regulatory authorities are forcing the offshore drilling industry to modify or eliminate dumping of drilling wastes overboard. On land rigs, the practice of constructing earthen reserve pits is also declining in favor of 'zero-discharge' closed-loop systems. Therefore the effective containment and transportation of drilling wastes is becoming ever more important. The environmental benefits of a well designed waste collection and transportation system can be observed directly in many cases.[5]

The New Mexico Oil Conservation Division identifies closed-loop drilling as a "best management practice" in their Pollution Prevention Best Management Practices for the New Mexico Oil and Gas Industry. (See footnote 1) New Mexico OCD is not alone in identifying closed-loop drilling systems as a best practice. In almost any pollution prevention or "Best Management Practices" document for the oil and gas industry, closed-loop drilling systems are mentioned as the most environmentally safe method for reducing the potential impact that drilling operations can have on the environment. For example, the practice is mentioned in the following documents:

• The Illinois Environmental Protection Agency's Best Management Practices for Oil Exploration and Extraction
• Railroad Commission of Texas' Waste Minimization in Drilling Operations

Increasingly, closed loop systems are being used all over the United States, Canada, and the world. In personal conversations with closed-loop drilling system companies, OGAP has heard that one company has performed approximately 900 closed-loop drilling operations in the past eight years (in CO, WY, ND, NM and other western states). A representative from another company operating out of Texas, Louisiana and Oklahoma remarked that most of the major companies in the region are using closed-loop drilling systems at the majority of their operations, because they understand the potential future liabilities that may follow them if they use conventional drilling systems that use reserve pits.

This information was corroborated by the Texas Railroad Commission, which stated that, "Even though it is not always cost effective, some companies have elected to use only closed loop drilling fluid systems in their operations. . .whenever a closed-loop system is used, the operator reduced his potential liability associated with a conventional earthen pit and waste management and site closure costs." [6]

According to the U.S. Congress, Office of Technology Assessment, these systems are increasingly being used (e.g., in California) because of the reduction in overall drilling costs and in the volume of wastes needing disposal. (See footnote 4)

Comparison of closed-loop systems versus pits

CASE 1: Prima Energy's Cost-Benefit Analysis [7]

Prima Energy Corp. has drilled more than 68 wells in Colorado using a highly automated closed-loop system, which the company started developing along with Nabors Drilling USA, Inc. in 1993. The company found that the economics of drilling these wells in Colorado were best if drilling required less than 12 days.

The table below provides a summary of the economics of using conventional reserve pits versus closed-loop drilling systems.

* Dewatering cost includes rental of unit, labor, extra fuel, polymer and acid,
linear motion shaker, centrifuge, trucking, end loader and miscellaneous costs.

Prima Energy's calculated benefits of closed-loop drilling:

• cost savings of $1,320 per well
• water savings of 5,200 barrels (closed-loop drilling used 80% less water)

CASE 2: MiSWACO - Closed-loop vs. Conventinal Systems: A tale of two wells [8]

Closed-loop systems employ a suite of solids control equipment to minimize drilling fluid dilution and provide the economic handling of the drilling wastes. For one company, a typical closed-loop system includes a series of linear-motion shakers, mud cleaners and centrifuges followed by a dewatering system. The combination of equipment typically results in a "dry" location where a reserve pit is not required, used fluids are recycled, and solid wastes can be landfarmed, hauled off or injected downhole.

Two wells, drilled only 200 ft apart in Matagorda County, TX, provided a unique opportunity to compare the cost savings difference between conventional solids-control equipment and the company's closed-loop system. Both wells drilled through the same formations, using the same rig crew, mud company and bit program.

The closed-loop system with improved solids control resulted in some significant savings:

• 43% savings in drilling fluid costs
• 23% fewer rotating hours
• 33% fewer days to drill to a comparable depth
• 37% reduction in the number of bits used
• up to 39% improvement in the rate of penetration

CASE 3: Reducing Waste Volume and Costs Using Closed-loop Systems [9]

Challenges: Challenges associated with conventional reserve pits include volume of drilling wastes; drill site installation and restoration costs; pollution of land and/or surface water due to failure of pits and/or containment system and associated cleanup costs; and potential for subsurface pollution due to downward migration from pits and/or surface soil permeability.

Solution: Use closed-drilling pit system to reduce volume of drilling waste. The drilling contractor maintained "safe pit levels" and recycled drilling fluid to minimize pit volumes and disposal requirements. Waste management costs due to procedures other than those specified were also the responsibility of the drilling contractor. Cost savings provided the incentive to implement and maintain proper procedures to minimize waste generation in the closed-loop system.

Benefits: The following benefits were realized:

• Total estimated cost savings (considering reduced costs for drill site installation, fluid hauling and disposal, dirt work, and surface damage payment): $11,000.00
• Reduced surface disturbance by 18,000 square feet (0.4 acres).
• Reduced drilling mud and wastes in pits by 15,625 barrels.
• Reduced potential for environmental impact to surface and groundwater.

CASE 4: Closed Loop Drilling Fluid System [10]

Problem: A small independent operator was concerned about the volume of drilling waste in conventional reserve pits at his drilling locations. Waste management costs were a concern, as well as the costs associated with impact on adjacent land due to pit failures. The operator was concerned about the potential for surface water or ground water contamination and the associated potential liabilities.

Solution: The operator was drilling relatively shallow wells in normally pressured strata. Because the drilling plan was relatively simple, the operator investigated the feasibility of using a closed-loop drilling fluid system for these wells. The use of a closed-loop system eliminated the need for a conventional reserve pit. The operator negotiated with drilling contractors to obtain a turn-key contract that required the drilling company to use a closed-loop system and take responsibility for recycling the waste drilling fluid.

Benefits: The turn-key contract was incrementally more expensive. Yet, because of reduced drill site construction and closure costs; reduced waste management costs; and reduced surface damage payments, the operator realized a savings of about $10,000 per well. Also, the operator reduced the potential for environmental impact and associated potential liability concerns.

CASE 5: Closed-loop System Helps Reduce Drilling Waste [11]

A large oil and gas production company used a number of pollution prevention techniques, including closed loop drilling, to drill an exploratory well adjacent to the Tishomingo Wildlife Refuge in Johnston County, OK. The well was drilled on land owned by the U.S. Army Corps of Engineers. Some of the measures taken in drilling the well included:

• Using a closed-loop mud system that allowed for reuse of drilling fluids and use of smaller quantities of water for dilution of the mud to control viscosity and density
• Use of compressed air as the drilling fluid where possible, which allowed for the use of smaller quantities of water and drilling fluid
• Using a smaller casing, which allowed for the use of a 25% smaller hole. This generated a smaller volume of drill cuttings and required less drilling fluid

Savings and Benefits: The hole-size reduction, use of air drilling and closed-loop system reduced wastes by close to 1.5 million pounds. A material and disposal cost savings of $12,700 was achieved.

Find out about the Summit Co-Sponsors

There are a variety of chemicals used during the drilling and production phases of oil and gas; and different types of wastes are produced throughout the development process.

The purpose of the Oil & Gas Accountability Project's Public Health and Toxics Program is to help communities and citizens better understand and protect themselves from the health and environmental impacts associated with toxic oil and gas chemicals and wastes.

Public Health and Toxics Issues

• HYDRAULIC FRACTURING. This often involves the injection of known toxic chemicals into or close to drinking water supplies
• CHEMICAL DISCLOSURE. Increasingly, landowners and residents of oil and gas field communities are reporting health impacts that they believe are linked to environmental toxics associated with the oil and gas development activities in their area. These reports include incidents of: asthma, respiratory and cardiovascular illnesses, autoimmune diseases, liver failure, cancer and other ailments such as headaches, nausea, and sleeplessness.
• PITS. Contamination of groundwater, soil and air may result from the storage and disposal of oil and gas wastes in unlined and lined pits.
• OIL AND GAS POLLUTION. There are many chemicals used and waste produced throughout the various stages of oil and gas development. These chemicals and wastes can contaminate air, water and soil.
• AIR POLLUTION. Oil and gas development contributes to air pollution problems such as increased low-level ozone (smog), toxic levels of hydrogen sulfide, and localized zones of airborne hydrocarbons like VOCs and PAHs.
• HYDROGEN SULFIDE. This is a particularly toxic gas that is sometimes associated with oil and gas development. Citizens from many states and Alberta, Canada have experienced health problems from exposure to this gas.
• HEALTH IMPACTS. More and more, people are speaking up about health problems that seem to be related to oil and gas pollution.
• NOISE. More than merely annoying, the noise from oil and gas can affect people's health and drive them from their homes.
• OIL AND GAS INDUSTRY EXEMPTIONS. The oil and gas industry enjoys exemptions from some of the major federal pollution laws, such as the Safe Drinking Water Act.
• PATHWAYS AND SOURCES OF CONTAMINATION. There are a number of ways that contaminants from oil and gas operations can enter the environment..
• 2010 People's Oil and Gas Summit - Toxics in Our Communities drew together people from across North America to talk about public health and toxics issues related to oil and gas development.

Citizens and state officials in New Mexico have become increasingly concerned with the potential environmental and health effects related to oil and gas industry emissions and chemical releases.

Unlined Drip Pit in New Mexico

Citizens have expressed concern about contamination from oil and gas pits, well sites and gas plants.

* GROUNDWATER CONTAMINATION: Read about groundwater contamination from oil and gas pits in New Mexico.

* SPILLS: At around 10 p.m. on June 7, 2006, a spill of hydraulic fracturing fluid at a Farmington Halliburton facility created a toxic cloud that caused a mass evacuation of 200 residents from a nearby neighborhood. Between 30 and 60 gallons of an "acidizing composition," which is used while hydraulically fracturing some oil and gas wells, spilled while Halliburton employees were mixing the fluid. The city fire chief said that the product may cause skin and respiratory burns, is harmful if swallowed, and will combust at 103 degrees F. One resident said that she was nauseous and vomited clear liquid for several hours after being exposed to the toxic cloud. (Source: Farmington Daily Times. July 7, 2006. "Halliburton spill results in acid cloud.")

* HYDROGEN SULFIDE: Hydrogen sulfide, a deadly gas, is found at many gas sites throughout New Mexico. In the San Juan Basin, alone, there are approximately 375 wells that contain hydrogen sulfide. Download a presentation on Hydrogen Sulfide Occurrences in the San Juan Basin.

Agency Initiatives

A number of New Mexico state agency initiatives reflect an overall growing concern with oil and gas industry wastes and emissions.

* NEW: New Mexico Oil Conservation Commission released its new rules governing oil and gas pits. For more information.

* Recently, the state agencies have begun to tighten regulations governing the disposal of oil and gas wastes at landfills and landfarms.

* Attention is also being paid to health impacts from a decline in air quality, due in part to oil and gas industry emissions. For more information, visit the Four Corners Air Quality Task Force web site.

Chemicals used by the New Mexico oil and gas industry

Increasing attention is being paid to chemical products used by the oil and gas industry. In New Mexico, data show that there are a wide variety of chemical products used throughout the exploration, drilling and production phases oil and gas development. Although it is common to hear from industry and some state agency representatives that drilling and production chemicals and wastes are benign, there is competing industry information indicating that toxic chemicals are used and released throughout the development process.

Organizations like The Endocrine Disruption Exchange, Inc. (TEDX) of Paonia, Colorado have begun to gather data and assess the potential health effects associated with chemicals used in oil and gas development. A TEDX analysis of chemicals used in oil and gas development in New Mexico found that approximately half of the chemicals can cause respiratory, skin, gastro-intestinal and/or liver problems, and approximately one third of the chemicals are harmful to nervous system, kidney and/or cardio vascular functions.

"We are seeing similar problems in Colorado," said Theo Colborn, President of TEDX, "Our biggest concern is that there are many products and chemicals in use that industry says are proprietary and for which the public has no information. The public deserves to know what chemicals they are living with."

Download a copy of the 2007 TEDX report on Chemicals Used in Oil and Natural Gas Development and Delivery in New Mexico.

WHY COLORADANS SHOULD CARE ABOUT OIL AND GAS TOXICS

In 2005, a record high of 4,373 drilling permits were approved in Colorado. That same year, the director of the Colorado Oil and Gas Conservation Commission (COGCC) reported that COGCC staff were only able to monitor well sites approximately once every 3 years.[1] In 2006, the record for the number of approved drilling permits set in 2005 was surpassed by 35%.[2]

Colorado residents living in oil and gas producing regions have long voiced complaints about foul odors, tainted water and health-related concerns. But this most recent surge in oil and gas development has raised concerns to an unprecedented level. Below you will find information on the health impacts being felt and concerns being raised by Colorado residents.

The chemicals used during oil and gas operations can escape into the environment via a number of pathways: wastes and chemicals stored in pits or tanks may spill or overflow, releasing toxic compounds into air, water or soil. Chemicals injected into the ground may come in contact with drinking water aquifers. And flammable chemicals may burn, releasing a host of toxic by-products into the air.

There are clear ways to start addressing some of the contamination and health concerns:

• Require oil and gas companies to disclose the complete make-up and volumes of chemicals in their products.
• Require monitoring of air and water quality in oil and gas producing areas.

This information is necessary in order to determine the level of public exposure to oil and gas chemicals, and to assess the potential short and long term effects of these chemicals on human health and the environment.

OIL AND GAS TOXICS, CONTAMINATION AND PUBLIC HEALTH

• Disclosure of all chemicals used by the oil and gas industry is finaaly making some progress as the COGCC considers a rule that would require all operators in the state to disclose all chemicals used at all facilities. Read about COGCC's current rulemaking process, updates and information!
• News articles and landowner stories related to health impacts from oil and gas development
• Potential health effects related to chemicals used during oil and gas development
• Oil and gas industry spills affecting water in Colorado
• Setbacks

News Articles and Landowner Testimonials

Below are some selected news articles and excerpts from landowner testimonials. Visit our web page on Health Concerns in Colorado's oil and gas fields for many more examples.

Voices from the Gas Fields (Orion Magazine, November/December 2006, Rebecca Clarren) This article features stories of the health impacts being felt by residents in Garfield County, Colorado. There are also audio and video clips with additional stories, and information on issues related to oil and gas and health.

'Collateral damage' - Residents fear murky effects of energy boom (Aspen Times, December 3, 2006, Judith Kohler) Chris Mobaldi is 59, but looks at least 70. In the last decade, she has had two tumors removed from her pituitary gland and endured excruciating pain. ...The Mobaldis believe her neurological system was damaged by drinking water that may have been contaminated by drilling fluids from wells around their former home about 60 miles to the east in Rifle... Other residents near the epicenter of the Rockies' energy boom are starting to worry about their health, too, and who, exactly, is looking out for them. The federal government leaves much of the regulation up to state officials - and in Colorado, some residents fear there isn't nearly enough oversight to keep them safe.

Families fume about gas leaks near Trinidad (The Pueblo Chieftain, July 17, 2005, Mike Garrett) Raton Basin landowners charge that their water wells are being polluted by seeping methane gas from coal-seam outcrops. The ranchers also complain their crop fields and yards are becoming "hot spots" of accumulating gas.

Oil and water make for shaky mix (Durango Telegraph, March 24, 2005, Will Sands) Jake Hottle has been dealing with tainted drinking water for several decades. . .His personal experiences and those of his neighbors led him to form the Cedar Hill Clean Water Coalition. Through investigations, the coalition steadily found poorly cemented wells and open-pit dumping as well as methane gas in 40 percent of the water wells tested. "After a long struggle, the industry finally went back in and properly cemented their wells, and they started lining their pits," Hottle said. While proper cementing and pit lining are now mandated practices, Hottle and many others argue that the industry needs to try still harder.

EPA to citizens: Frack you (Salon.Com, May 5, 2006, Rebecca Clarren) "It's a Catch-22," says the remarkably frank Weston Wilson, an environmental engineer with the EPA's Denver office for the past 32 years. "If the EPA doesn't study the health impacts, then there's no proof that there's anything dangerous happening. It's irrational and corrupt. We used to investigate mysteries, and now we're not. It's sad."

Water well contaminated after hydraulic fracturing of a well near their Colorado home (Landowner testimonial - Laura Amos) In May 2001 while fracturing four wells on our neighbors' property, the gas well operator "blew up" our water well. Fracturing created or opened a hydrogeological connection between our water well and the gas well, sending the cap of our water well flying and blowing our water into the air like a geyser at Yellowstone. Immediately our water turned gray, had a horrible smell, and bubbled like 7-Up.

Potential health effects related to oil and gas chemicals

In 2006, The Endocrine Disruption Exchange (TEDX, Inc.) began gathering health and toxicity data related to chemicals used in oil an gas operations in Colorado. The TEDX review revealed some startling information on chemical ingredients, toxicity, and potential health effects related to ingestion, inhalation, and other exposures to these chemicals.

• The analysis conducted by TEDX showed that toxic chemicals are used throughout the oil and gas development process in Colorado.
• Of the 245 chemicals identified so far, some chemicals of concern include: 2-butoxy ethanol (2-BE); 2-(2-methoxyethoxy)ethanol; nonylphenols; assorted petroleum distillates; and toxic metals.
• Many of the toxic chemicals are water soluble, volatile and highly mobile. In other words, they do not stay put.
• The four most common adverse health effects of the chemicals in the TEDX database are: (1) neurotoxicity; (2) skin/sense organ toxicity; (3) respiratory problems; and (4)gastrointestinal/liver damage.

Read a more thorough summary of the TEDX data, or visit the TEDX web site to find out more information on the project.

Read the most recent TDEX report (January 15, 2008).

Spills

Spills and leaks of raw chemicals or oil and gas wastes may affect land, water and air. In Colorado, the Colorado Oil and Gas Conservation Commission (COGCC) requires companies to report spills of fluids related to any unauthorized release of exploration and production (E&P) wastes that are 5 barrels or more in volume. In some cases, smaller spills are reported, e.g., if the spill enters surface or groundwater.

In the four-year period between June of 2002 and June of 2006, there were approximately 924 spills of oil and gas chemicals and wastes. Spilled products included: crude oil, condensate, produced water, and "other" products. The other products included diesel fuel, glycol, amine, lubricating oil, hydraulic fracturing fluids, drilling muds, other chemicals, and natural gas leaks.

As the chart shows, a large percentage of spills recorded by the COGCC do find their way into groundwater or surface water. Of the 924 oil and gas industry spills reviewed, 20% of them contaminated water: 14% of the spills affected groundwater; and 6% of all spills affected surface water.

Setbacks

Chemicals from oil and gas production and waste facilities enter the air, water and soil through a number of pathways.

One major concern for landowners in Colorado is how quickly these chemicals can travel through the air exposing nearby residents, or leak into water supplies. Depending on the physical location of production and waste facilities chemicals can also get "caught" in the air and build to dangerous levels.

Setback requirements can help communities manage the threat of oil and gas chemicals and health and safety exposures. Many states and local governments require specific setbacks to protect people and wildlife from oil and gas activities. These setbacks can apply to residential homes, drinking water supplies, schools, hospitals, retirement communities, high density areas, quiet zones and natural areas with sensitive species. Below are several examples:

• Maryland: "The Department may not issue a drilling and operating permit if the well location is closer than 1,000 feet to a school, church, drinking water supply, wellhead protection area, or an occupied dwelling unless written permission of the owners is submitted with the application and approved by the Department." [3]
• Coffeyville, TX: It shall be unlawful to drill, re-drill, deepen, re-enter, activate, or convert any well, the center of which, at the surface of the ground, is located; or within 1,000 feet of any residence, religious institution...hospital or school. [4]
• Flower Mound, TX: If located on same property as well, new construction must meet the ordinance setback requirements (1,000 feet) from an existing well. [5]

CONTACTS

Many citizens and organizations are working to improve regulations relating to oil and gas contamination and public health. To find out more about these efforts visit the main OGAP Colorado Toxics web page or contact the groups listed below.

• Do It Right Las Animas
  Tracy Dahl
  Email: polarsolar [at] hughes [dot] net
• Grand Valley Citizens Alliance
  Patrick Barker
  Phone: 970-379-3252
  Email: patrick [at] wccongress [dot] org
• San Juan Citizens Alliance
  Josh Joswick
  Phone: 970-259-3583
  Email: josh [at] sanjuancitizens [dot] org
• Western Colorado Congress
  Matt Sura
  Phone: 970-256-7650
  Email: sura [at] wccongress [dot] org
• Western Slope Environmental Resource Council
  Rob Peters
  Phone: 970-527-5307
  Email: rob [at] wserc [dot] org

FOOTNOTES

[1] Hanel, J. Dec. 1, 2005. "State oil and gas agency: More inspectors needed,"
Durango Herald.

[2] Colorado Oil and Gas Conservation Commission. January 9, 2007 Staff Report.

[3] Code of Maryland Regulations, Title 26. Department of Environment. Section 19.01.09 Oil and Gas Resources, "Criteria for Approval of Drilling and Operating Permit."

[4] Land Development Code, City of Coffeyville. Chapter 3.1 Oil and Gas Drilling and Production. Section 3.1-145D.

[5] http://www.flower-mound.com/news/StakeholderPublicMeeting6-29-06.pdf

View the Final Summit Agenda

40 organizations from across the country have co-sponsored the 2010 National People's Oil and Gas Summit. These groups include:

• EARTHWORKS' Oil & Gas Accountability Project (National)
• Argyle - Bartonville Communities Alliance (TX)
• Arkansans for Gas Drilling Accountability (AR)
• Binghamton Regional Sustainability Coalition (NY) - BRSC's work on the gas issue focuses on education & policy. Board chair Chris Burger serves on the Broome County Legislatures Gas Task Force as well as New York State Sierra Club Gas Drilling Task Force. Read more about BRSC's work.
• Catskill Citizens for Safe Energy (NY) - CCSE is an all volunteer grassroots organization intended to give residents a voice regarding unconventional shale gas extraction. Our web site has a current Newsroom, a comprehensive Learn More section and advocacy campaigns. We also engage in educational outreach and lobbying. Find our more about CCSE's work.
• Catskill Mountainkeeper (NY)
• Citizens Against Resource Exploitation (AR)
• Clean Water Action (National)
• Clean Water Network (National)
• Cook Inletkeeper (AK)
• Dallas Area Residents for Responsible Drilling (TX)
• Damascus Citizens for Sustainability (NY)
• Delaware Riverkeeper Network (PA)
• Double Oak Cares (TX)
• Downwinders At Risk (TX) is a 17-year old local clean air group headquartered in Dallas-Ft. Worth. We're trying to use the clean air planning process for ozone reduction, known as a "State Implementation Plan," to impose regional standards and air pollution controls on Barnett Shale facilities that contribute to DFW's chronic smog problem.
• Dryden Resource Awareness Coalition (NY)
• Environmental Working Group (National)
• Food and Water Watch (National) - Two recent efforts have worked against risky and environmentally harmful practices of the oil and gas industry. We have worked in partnership with local groups in New York, Pennsylvania and other states across the country to stop the rapid expansion of the natural gas industry. Read more about FWW's work.
• Fort Worth CAN DO (TX)
• Marcellus Shale Protest (PA)
• Mineral Owners for Responsible Action and Land Safety MORALS (TX)
• National Alliance for Drilling Reform (National)
• Native Action (Northern Cheyenne Indian Reservation)
• Natural Resources Defense Council (National)
• People's Oil and Gas Collaborative - Ohio
• PA Forest Coalition (PA)
• Park Foundation (Eastern US)
• PennEnvironment (PA) - PennEnvironment is working to preserve and protect Pennsylvania's precious waterways, open spaces, farmlands and public health from the unwanted and dangerous effects of Marcellus Shale gas drilling. Read more about PennEnvironment's work.
• Pennsylvania Alliance for Clean Water and Air (PA)PACWA has been busy spreading public awareness throughout the Northcentral and Northwest regions of PA. In July, 2010 we had a meeting in DuBois titled "The Truth About Marcellus Gas Drilling", which featured Ben Price of CELDF and Bill Belitskus of Allegheny Defense Projectand on September 24, 2010 we held a public information meeting in Brookville titled "Protect and Prepare for the Natural Gas Boom." Read more about PACWA's activities.
• People for a Healthy Environment, Inc. (NY)
• Powder River Basin Resource Council (WY)
• Responsible Drilling Alliance (PA)
• San Juan Citizens Alliance (CO and NM)San Juan Citizens Alliance (SJCA) has been working on social and environmental justice issues in the San Juan Basin of southwest Colorado and northwest New Mexico since 1986. As part of that work, SJCA actively advocates for regulation of the oil and gas industry as that development impacts our communities on both public and private lands.Read more about SJCA's work.
• Texans for Responsible and Accountable Energy Development (TX)
• Texas Oil and Gas Accountability Project (TX)
• Weitz & Luxenberg (National)
• Western Organization of Resource Councils (ID, MT, ND, OR, SD, WY)
• Wise County Alliance for Responsible Drilling (TX)
• West Virginia Surface Owners' Rights Organization (WV)
• Wyoming Outdoor Council (WY)- WOC works to ensure that all types of energy development are regulated carefully so other values of these lands--such as critical wildlife habitat, fisheries, and recreational opportunities--are preserved for future generations. Find out more about WOC's work.

Find out more about some of the Summit co-sponsors and their work on oil and gas issues

Some of our co-sponsors provided us with a few more details about their work. You can read about them below.

Binghamton Regional Sustainability Coalition

BRSC's work on the gas issue focuses on education & policy. Board chair Chris Burger serves on the Broome County Legislatures Gas Task Force as well as New York State Sierra Club Gas Drilling Task Force. Chris is founding member of the Coalition to Protect New York. He gives frequent public presentations throughout the state. Both Chris and Vice-chair Adam Flint make frequent appearances in the regional media on this issue. Both are founding members of the New York Gas Coordination Group. Adam advises student and community groups in the greater Binghamton area on organizing and media strategy. He also works with OGAP's Cleanwaternotdirtydrilling.org campaign. Our partner organization, New York Residents Against Drilling (NYRAD.org), spun off from BRSC to focus on grassroots organizing, advocacy and education in the region.

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Catskill Citizens for Safe Energy

is an all volunteer grassroots organization intended to give residents a voice regarding unconventional shale gas extraction . At catskillcitizens.org we provide a current Newsroom, a comprehensive Learn More section and advocacy campaigns. We also engage in educational outreach and lobbying.

New York State and the DRBC heading in the wrong direction

In September, the Delaware River Basin Commission made it clear that it would go ahead and issue draft regulations for drilling in the Basin without conducting a cumulative impact study and without waiting for the results of the ongoing EPA study on hydraulic fracturing and drinking water safety. (Draft regulations are now expected as early as November or December.) In putting fracking ahead of public safety the DRBC is just the latest regulatory body to give precedence to special interests over public welfare.

Ten million Americans, through their elected representatives in the New York City Council and the Philadelphia City Council, have already called on the DRBC to delay drilling pending further study. Add your voice to the ten million-demand that drilling regulations in this critical watershed be based on real science, not political pressure. Take Action

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Food and Water Watch

Food & Water Watch works to ensure the food, water and fish we consume is safe, accessible and sustainably produced. So we can all enjoy and trust in what we eat and drink, we help people take charge of where their food comes from, keep clean, affordable, public tap water flowing freely to our homes, protect the environmental quality of oceans, force government to do its job protecting citizens, and educate about the importance of keeping shared resources under public control.

Two recent efforts have worked against risky and environmentally harmful practices of the oil and gas industry. We have worked in partnership with local groups in New York, Pennsylvania and other states across the country to stop the rapid expansion of the natural gas industry. Read our report Not So Fast Natural Gas: Why Accelerating Risky Drilling Threatens America's Water.

Our Spill the Truth campaign highlights how BP's long-term, reckless disregard of safety is threatening the Gulf with a spill many times larger than Horizon at its BP Atlantis platform. Strong evidence reveals that the Atlantis platform is a disaster waiting to happen, and other platforms may be operating unsafely too. Last year, Food & Water Watch learned from a whistleblower that, as a contractor for BP, he discovered the Atlantis platform was operating without proper safety documentation. For these reasons, we are calling upon the Obama Administration to immediately close down Atlantis until it can be proven safe and to conduct a review of all deepwater platforms in operation. Offshore drilling operations must be strongly regulated to ensure the safety of our food and water resources.

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PennEnvironment

PennEnvironment is a statewide, citizen-based environmental advocacy organization. Our professional staff combines independent research, practical ideas and tough-minded advocacy to overcome the opposition of powerful special interests and win real results for Pennsylvania's environment. PennEnvironment draws on 30 years of success in tackling our state's top environmental problems.

PennEnvironment is working to preserve and protect Pennsylvania's precious waterways, open spaces, farmlands and public health from the unwanted and dangerous effects of Marcellus Shale gas drilling. We are working to educate and activate the general public, inform the media, and collaborate with groups and individuals in an effort to pass strong policies and regulations that protect our environment and public health from gas drilling.

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Pennsylvania Alliance for Clean Water and Air

PACWA has been busy spreading public awareness throughout the Northcentral and Northwest regions of PA. On July 25, 2010 we had a meeting in DuBois titled "The Truth About Marcellus Gas Drilling", which featured Ben Price of CELDF and Bill Belitskus of Allegheny Defense Project, which had more than 100 attendees. On September 24, 2010 we held a public information meeting in Brookville titled "Protect and Prepare for the Natural Gas Boom", which was attended by more than 50 people. For this event we chartered an airplane and flew over the Moshannon State Forest and took aerial photos, to show at the meeting, of the destruction and deforestation taking place due to gas drilling. (Photos can be viewed on PACWA's website)

In September, Jenny Lisak met with a Radio Canada reporter for an interview to be broadcast on Canadian Public Radio. And in November she plans to meet with a British Television reporter for a story to be aired in Great Brittain. We have written many letters to the editor of local newspapers and even been published in the Pittsburgh Post Gazette.

We have members in attendence at all DuBois City Council meetings, various township and borough meeings, Jefferson County Marcellus Gas Task Force meetings, and C.A.R.E.S. public information meetings in Elk County. These members have been responsible for increased demand for local zoning ordinances to restrict drilling in these areas.

Members of PACWA attended Rally days at the Capitol Rotunda in Harrisburg in October and the Statewide Conference on Marcellus/Natural Gas Drilling in Harrisburg. We will have members in attendance at the Marcellus Protest in Pittsburgh on November 3rd as well. PACWA members have gone to great lengths to personally meet with Rep Sam Smith, Rep Bud George, Senate Candidate Sestak, and many other politicians.

Later this month PACWA members are teaming with other members of the community to present a public screening of Gasland in Dubois. We have a Facebook page with over 200 members and an website that is updated regularly with events and news stories. PACWA initiated a Google Groups forum (North Central PA Forum) for concerned citizen in the Northcentral tier of the state.

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San Juan Citizens Alliance (SJCA)

SJCA has been working on social and environmental justice issues in the San Juan Basin of southwest Colorado and northwest New Mexico since 1986. As part of that work, SJCA actively advocates for regulation of the oil and gas industry as that development impacts our communities on both public and private lands. This includes engaging with federal (BLM), state (Colorado Oil and Gas Conservation Commission; New Mexico Oil Conservation Division), and local (county governments) regulatory agencies tasked with oversight of the industry.

In Colorado, SJCA has fought development of federal minerals in the HD Mountains and is currently involved in shaping the Supplemental EIS being written by USFS/BLM for development of the Gothic Shale; in New Mexico, our federal work has been aimed getting the BLM Farmington NM office to be accountable for the automatic sign-offs on gas development which has become its custom and culture.

In both states, SJCA has been heavily involved in the writing of state regulations aimed at increasing protections to our air, land, water and surface owners' rights.

Locally, SJCA continues to advocate for residents faced with both ongoing impacts of coal bed methane development and the increasing reluctance of county government to exercise its land use authority and enforce its oil and gas regulations.

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The Wyoming Outdoor Council

The Wyoming Outdoor Council (WOC) has worked since 1967 to protect Wyoming's environment and quality of life for future generations.

The Wyoming Outdoor Council seeks to maintain balance between protecting our state's natural heritage and developing its energy resources. The Council works to ensure that all types of energy development are regulated carefully so other values of these lands--such as critical wildlife habitat, fisheries, and recreational opportunities--are preserved for future generations.

The Outdoor Council believes some places in Wyoming must remain free from industrialization while others should be developed using the best technology available to safeguard our healthy communities.

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Panel 2:
Community socio-economic impacts of natural gas development

Panel 3:
Strategies for reducing community and environmental impacts

Panel 4:
When the landman comes knocking - strategic options for individuals and communities

Panel 5:
Web-based tools for information sharing and documentation

Panel 6:
Citizen-based monitoring approaches

Panel 7:
Emerging issues related to natural gas and energy in the U.S.

The BREATHE Act would close two exemptions in the Clean Air Act (CAA) that threaten the health of communities wrestling with oil and gas production in their backyard.

Oil & gas production's air pollution should be regulated by the Clean Air Act

Adopted in 1970, the Clean Air Act is the comprehensive federal law that regulates air pollution.

The CAA established limits for major pollution sources called the National Emission Standards for Hazardous Air Pollutants (NESHAPS).

Well pads in Wyoming's Jonah gas field stretch to horizon, yet are currently
exempt from regulation under the Clean Air Act. Consequently, air pollution in
parts of rural Wyoming is worse than in Los Angeles. The BREATHE Act would
fix this. Photo: SkyTruth

Smaller sources of pollutants that are

• controlled by a single operator,
• located close to each other, and
• perform similar functions

considered as one source of emissions. This aggregation allows for CAA oversight of smaller sources that, when concentrated, may actually be as harmful as larger sources.

This tool, aggregation under NESHAPS, is a perfect fit for regulating oil and gas drilling air pollution, which originates from clusters of wells (see image).

Oil & gas loopholes in the Clean Air Act

Unfortunately, the CAA exempts oil and gas wells, and in some instances pipeline compressors and pump stations, from aggregation under NESHAPS. This exemption allows the oil and gas production industry to pollute the air while largely unregulated by the CAA.

In addition, hydrogen sulfide was removed from the list of Hazardous Air Pollutants under the CAA in 1991. This elimination has remained despite a 1993 EPA study, Report to Congress on Hydrogen Sulfide Air Emissions Associated with the Extraction of Oil and Natural Gas, which clearly concludes that accidental releases of hydrogen sulfide during oil and gas development are a serious air quality concern and pose a great risk to public health.

Common symptoms of exposure to low levels of hydrogen sulfide can include headache, skin complications, respiratory problems and system damage, confusion, verbal impairment, and memory loss.

The BREATHE Act would apply the Clean Air Act to oil & gas production

The BREATHE Act closes both the NESHAPS and the hydrogen sulfide exemptions. Which would allow gaspatch residents to breath a sigh of relief.

"Best" Regulations

The Oil and Gas Accountability Project believes that one way to improve oil and gas regulations is to be able to present examples of jurisdictions that have instituted more stringent regulatory requirements. This information provides a backbone argument for stronger regulations - "if they can do it there, we can do it here." Additionally, if companies are abiding by a regulatory requirement in one locale, it strongly suggests that they have developed technologies or practices to meet those requirements.

There is no single country, state, county or municipality that has "the best" set of regulations. We have found, however, numerous examples of very strong provisions from across the country, or, in some cases, from jurisdictions outside of the United States.

Follow the links (COMING SOON!) to find examples of regulations that are more progressive, and more protective of the environment and public health, safety and welfare.

Minimizing Surface Disturbance

• Directional Drilling

Protection of Water

• Baseline Water Quality Testing prior to drilling
• Baseline Water Quantity Testing prior to drilling
• Holding Operators Liable for Water Contamination

Waste Disposal

• Banning Earthen Waste Pits
• Improving Closure Standards

Reducing Use of Toxic Chemicals

• Banning the Use of Diesel in Hydraulic Fracturing Fluids
• Requiring Non-toxic Hydraulic Fracturing Fluids
• Using Less Toxic Chemical Additives

Minimizing Air Pollution

• Flareless Completions

Reducing Noise

• Low Frequency Noise

Moratoriums

• NM County Issues Moratorium on Drilling Operations

In response to the surge in oil and gas drilling activities in the west, Santa Fe, NM has issued a moratorium on drilling activities until adequate oil and gas regulations can be enacted. The moratorium is currently in effect for 1 year. Read the Moratorium. Several other counties in NM and CO are also considering moratoriums including Rio Arriba County, NM and Huerfano County, CO. Check back for updates on these efforts!

• TX City Issues Moratorium on Drilling Operation

Copperas Cove - Following vocal opposition for residents and aggressive legal tactics by oil and gas copanies, the City Council implemented a 180-day moratorium on drilling permits on Tuesday to allow the city time to review it's ordinance.

As a result of public backlash starting in April, the council has
lately expressed interest in strengthening the city's drilling
regulations and has delayed approving permits several times while gathering citizen input.

For more information:

http://www.kdhnews.com/news/story.aspx?s=27409

OGAP's Model County Regulations

OGAP has worked with a number of county and municipal governments to enact or improve their oil and gas regulations. Local governments are sometimes limited in what aspects of oil and gas development they can regulate. For example, in Colorado, the noise from oil and gas facilities can only be regulated by the state. To help provide some guidance on what counties can and cannot regulate, OGAP has prepared the following model county regulations for New Mexico and Colorado. Local governments or citizens in other jurisdictions are encouraged to contact us for consultation or advice regarding regulations in your areas. Please note that OGAP is in the process of overhauling both of these model county regulations in response to the many changes. Check back for updates.

• Colorado Model County Regulations

The Endocrine Disruption Exchange (TEDX) in Paonia, CO found 104 products that contain at least 85 chemicals in their recent analysis of chemicals used by the oil and gas industry in Montana. Eighty-three percent of the products have one or more adverse health effects. Of these, 17% have one to three possible health effects, and 83% have between four and fourteen possible health effects. Fourteen products have 14 adverse health effects.

Upon plotting the percent of chemicals in each health category, a pattern emerged of the possible health effects for the 85 chemicals. The four categories with the highest exposure risk are (1) eyes, skin, and sensory organs; (2) respiratory system; (3) gastrointestinal tract and liver; and (4) the cardiovascular system and blood.

Thirty-seven chemicals were water soluble. The four categories with the highest exposure risk are (1) eyes, skin, and other sensory organs: (2) gastrointestinal tract and liver; (3) respiratory system; and (4) the cardiovascular system and blood.

Thirty-eight chemicals were volatile. The four categories with the highest exposure risk are (1) respiratory system; (2) eyes, skin, and other sensory organs; (3) the brain and nervous system; and (4) the gastrointestinal tract and liver.

Several reasons led to the lack of data about the health effects of some of the products and chemicals on the spread sheet: (a) Some products list no ingredients. (b) Some products list some or all of the ingredients as "proprietary." (c) No health effect data were found for a particular chemical or product.

The products and chemicals included on this list were compiled from the Tier II reports sent to the state of Montana for the years 2005, 2006, and 2007. Tier II reports are required by the Emergency Planning and Right to Know Act to help local communities protect public health, safety, and the environment from chemical hazards. However, the oil and gas industry is exempt from this requirement. In return for this exemption industry files voluntary Tier II reports that are often "boilerplate" and do not contain all the chemicals used on a particular site.

The information contained in Tier II reports varies from state to state, and, in the case of the Montana Tier IIs, from company to company. Some companies listed all the chemicals in the products stored, though many of the ingredients were cited as proprietary, while other companies only provided a general statement of what was stored on a site, such as "surfactants" or "corrosion inhibitors." Because of the lack of specific information in many reports, the data in this analysis is likely an underestimation of what is actually in use and storage in the state of Montana.

Only 20% of the information about the composition of the products on the list comes from a Material Safety Data Sheet (MSDS). Ingredients on MSDSs are sometimes labeled as "proprietary" or "no hazardous ingredients" even when there are significant health effects listed on the MSDS. This was the case for three of the 21 MSDSs.

Some of the citations used to establish the health effects of the chemicals on this list are old, dating back to the 1970's and 80's. In several cases data were derived from abstracts, not the full report or manuscript. In other cases, citations were taken from toxic chemical databases, such as TOXNET, Chem ID, etc. Many reports submitted to the US Environmental Protection Agency by the manufacturer to register a chemical are not accessible. In some cases it is impossible to track down any health effect for a chemical, especially when the manufacturer provides no Chemical Abstracts Service (CAS) number.

No health effects were found for nine of the chemicals on the list. Of these, only 4 had been assigned a CAS number which facilitates searching the literature. We found no health related literature for these chemicals. It was impossible to determine the safety of the other 5 chemicals either because they were listed as proprietary, or "various," or no chemical was identified (4), or had chemical names that were so general that the specific chemical could not be identified (1).

Download the most recent TEDX report on chemicals from oil and gas in Montana.

Go to the TEDX website for more information.

The Peoples' Oil and Gas Summit is a core component of EARTHWORKS' efforts to build bridges between communities that have been dealing with these issues for decades and those facing the drilling boom for the first time. Our experience has been that such bridges help foster new activists, renew long-term activists, and greatly increase momentum on pushing local, state, and national reform efforts.

Summit Updates

Summit updates will be posted here as they become available -- including presentations and logistical info.

UPDATE 11/20: SPEAKER PRESENTATIONS NOW ONLINE Included in the final agenda are links to speaker presentations, and additional information related to the various panels.

UPDATE 11/16: FINAL AGENDA AVAILABLE ONLINE Included in the final agenda are links to speaker bios, and additional information related to the various panels.

UPDATE 10/31: FIND OUT ABOUT THE SUMMIT CO-SPONSORS More than 35 organizations from across the country have co-sponsored the 2010 National People's Oil and Gas Summit. Find out more about the Summit co-sponsors, and the work they're doing to protect people and the environment from the harmful impacts related to oil and gas development.

UPDATE 10/25: DRAFT AGENDA AVAILABLE ONLINE Thanks to the hard work of the Steering Committee members, the draft final Agenda for the Summit is now available.

UPDATE 9/5: We have put together a Summit Steering Committee to help shape the agenda. In addition to EARTHWORKS staff, the Committee includes:

• Adam Flint, Binghamton Regional Sustainability Coalition
• Wes Gillingham, Catskill Mountainkeeper
• Myron Arnowitt, Clean Water Action
• Tony Ingraffea, Cornell University
• Tracy Carluccio, Delaware Riverkeeper Network
• Kari Matsko, Northeast Ohio Gas Accountability Project
• Lynn Senick, Northeast Pennsylvania Gas Action
• Erika Staaf, PennEnvironment
• Deb Thomas, Powder River Basin Resource Council
• Jill Morrison, Powder River Basin Resource Council
• Lisa Wright, Shaleshock
• Sharon Wilson, Texas Oil and Gas Accountability Project
• Julie Archer, West Virginia Surface Owners' Rights Organization

Find out about the Summit Co-Sponsors

Thursday, November 18

Friday, November 19

Saturday, November 20

The Marcellus Shale, a natural gas reserve which runs through parts of New York, Pennsylvania, Ohio and West Virginia, is currently experiencing a huge boom in exploration and extraction. New drilling technologies, like hydraulic fracturing have made this deposit, which once was too expensive to extract, economically accessible.

New York welcomes drillers
New York Governor David Patterson and the state legislature recently simplified the application process for natural gas development, so an increase in the number of applications for drilling permits is expected.

EARTHWORKS recently provided cautionary feedback in response to the New York Department of Environmental Conservation request for comments.

Fracturing's checkered history
The technique used to extract the gas in the Marcellus Shale is hydraulic fracturing. It uses toxics which have contaminated water supplies in New Mexico and Colorado. Despite this history, fracturing is unregulated under the Safe Drinking Water Act.

The following chart summarizes the major air pollutants released during oil and gas development and the major sources of emissions. Click on each category to read details about the pollutant or the source activity.

• 'x' means that a pollutant is emitted as a direct result of the particular activity
• 'o' means that the pollutant is generated in a secondary reaction associated with the particular oil and gas development activity.

How air quality related to oil and gas is regulated

The Air Pollution Control Division of the Colorado Department of Public Health and Environment is resposible for regulating air pollution emissions from oil and gas facilities operating in Colorado.

Recent changes to oil and gas air quality regulations (2004)

Denver has an air pollution problem. The concentrations of ground-level ozone (also known as smog) are so high that they occasionally exceed the acceptable level set by the federal government (the national 8-Hour Ozone Standard is 0.08 parts per million). Ground-level ozone, which is unhealthy to breathe, is formed when volatile organic compounds (VOCs) mix with oxides of nitrogen (NOx) and other pollutants in the presence of sunlight.

In 2004, Colorado developed an Ozone Action Plan, which was designed to quickly reduce VOC emissions so that the state would remain in compliance with the federal 8-hour Ozone Standard.

Part of Colorado's Ozone Action Plan involved the adoption of Section XII of Air Quality Control Commission Regulation Number 7 - "Emissions of Volatile Organic Compounds." This provision limited the amount of VOCs that could be emitted from oil and gas condensate storage tanks in an area surrounding Denver ("8-hour Ozone Control Area"). VOC emissions from condensate storage tanks in the area were to be reduced so that they would not exceed 91.3 tons per day (tpd) for the period from May 1 through September 30 (the "ozone season") in 2007, and would not exceed 100.9 tpd for the 2012 ozone season.

In 2005, the state Air Pollution Control Division reviewed data on emissions from oil and gas facilities and found that VOC emissions were significantly higher than had been anticipated in the Ozone Action Plan. The Division concluded that the emission reductions required under the current regulation were not going to keep the area below the 91.3 ton-per-day cap for 2007 as set forth in the Ozone Action Plan.

The Division also found that unanticipated increases in VOC and nitrogen oxide (NOx) emissions due to oil and gas expansion in several areas of the State were contributing to high ozone levels in the Denver area and elsewhere in the State.

It is clear that if the oil and gas industry continues to emit VOCs at current levels, that parts of the state will exceed the federal ozone standard, which will endanger public health, as well as place a heavy burden on state regulators to develop detailed plan to address the problem.

Recent changes to the air quality regulations (2006)

On December 17, 2006, the Colorado Air Quality Control Commission (AQCC) adopted regulations to reduce oil and gas industry emissions of volatile organic compounds (VOCs), nitrogen oxides and carbon monoxide in both the Front Range Early Action Compact Area, and to a lesser extent, statewide.

The AQCC adopted the rules after two hearings, which were well attended by citizens, environmental organizations and the oil and gas industry. A number of citizens provided testimony on health effects being experienced by people living in oil and gas producing areas; and several citizens' and environmental groups provided testimony about the known health impacts of many oil and gas chemicals and equipment emissions.

Several Air Quality Control Commissioners voiced the need to begin addressing the health risks posed by oil and gas industry emissions as a reason to adopt more stringent air quality rules.

Under the new rules, VOCs from the most polluting condensate tanks would be reduced by 95%, and VOCs from the most polluting glycol dehydrators would be reduced by 90%. Additionally, VOCs, nitrogen oxides and carbon monoxide from combustion engines that are rated at 100 horsepower or higher would eventually be reduced by 75%.

According to an article in the Rocky Mountain News, the new rule includes:

• Cutting emissions: Oil and gas operators in a drilling region northeast of Denver must cut overall emissions of volatile organic compounds (VOCs) from condensate storage tanks by 75 percent before May 1, 2007. That's an increase from current rules requiring cuts of 47.5 percent.
• New emission controls: Statewide, oil and gas operators must, for the first time, install emission controls on condensate storage tanks that emit more than 20 tons per year of VOCs. New emission controls on natural gas engines and dehydrating equipment also were approved. The new rules will be phased in over the next two years.
• Air quality reporting: The state's Air Pollution Control Division must provide an annual report on how the oil and gas industry is affecting air quality across the state.

The Colorado Air Pollution Control Division has observed that ozone levels in rural areas are gradually increasing along with increasing oil and gas exploration and development. In some areas, ozone levels are approaching (and occasionally exceeding) the federal standard of 0.08 parts per million (ppm) or 80 parts per billion. In southwestern Colorado, air monitors in Mesa Verde National Park show that smog levels have steadily risen in the last decade, with some of the highest readings being recorded in the last two years.

The Colorado Air Pollution Control Division reports that during the period 2000-2005, the following maximum ozone levels were measured:

• Mesa Verde (southwest Colorado): 0.082 parts per million (ppm).
• Ignacio, Colorado (southwest, near the NM border): 0.072 ppm.
• Shiprock, New Mexico (near Colorados Four-Corners area): 0.81 ppm
• Utah Canyonlands (southeast Utah): 0.079 ppm
  

Air pollution from oil and gas development is significant - and it's on the rise

Smog forming compounds and other air toxics are released at every stage of oil and gas development. Drilling rigs emit a variety of air pollutants including NOx, carbon monoxide and carbon dioxide. During well completion, tons of VOCs may be vented or flared. Oil and natural gas condensate tanks and glycol dehydrators release VOCs. Compressor stations emit a variety of ozone-forming compounds, as well as other air pollutants. And according to data compiled by Rocky Mountain Clean Air Action, a single EnCana natural gas processing plant in Rio Blanco County has the potential to release nitrogen oxides, carbon monoxide and volatile organic compounds equal to the emissions from 43,000 cars!

Below are three examples of significant sources of air pollution from oil and gas operations in Colorado:

• Condensate tanks collect liquid hydrocarbons during oil and gas production. The State estimates that there are 152 large condensate tanks in the Denver metro area that annually release 11,868,000 pounds (5,900 tons) of volatile organic compounds (VOCs). In Garfield County, VOC emissions from condensate tanks exceed 4,700 tpy.
• Glycol dehydrators are used to separate water from gas. The State estimates that there are 38 glycol dehydrators outside the Denver metro area that annually release 2,318,600 pounds (1,160 tons) of VOCs.
• Engines, such as those used to compress natural gas, currently have no pollution controls, despite the fact that they emit large volumes of air pollutants. For example, on a yearly basis, a single 1200 horsepower reciprocating internal combustion engine at a compressor station can release VOCs, NOx and carbon monoxide equivalent to the emissions from 8,000 cars.

Data from the Colorado Department of Public Health and Environment's oil and gas emissions inventory show that VOC emissions from existing oil and gas facilities are increasing statewide. Based upon the inventory data for 2004 and 2005, oil and gas production facilities are responsible for more than 50% of all VOCs released from stationary sources in the state of Colorado.

According to Rocky Mountain Clean Air Action, in some counties, such as Garfield, Las Animas, Rio Blanco, and San Miguel, oil and gas production facilities are responsible for more than 90% of all smog-forming compounds released by stationary sources.

County	Total smog forming compounds from stationary sources (tons/year)	Total smog forming compounds from oil and gas	Contribution of oil and gas to pollution
Delta	139	46	33%
Dolores	143	112	78%
Garfield	7522	7174	95%
La Plata	718	485	68%
Las Animas	453	419	92%
Mesa	1340	506	38%
Rio Blanco	2778	2696	97%
San Miguel	542	501	93%
Weld	53372	50731	95%

Oil and gas development continues to expand throughout Colorado. As of early September, 2006, the COGCC was receiving, on average, more than 100 additional well permit applications per month, statewide, as compared to its monthly average during 2005. Of the 2006 permit applications received, more than 54% are in counties where, up until December, 2006, there were no restrictions on VOC emissions.

In December, 2006, the Colorado Air Quality Control Commission approved several
new restrictions on the oil and gas industry in an effort to curb emissions of ozone-forming compounds affecting air quality across the state and in the Denver region. Read more about the 2006 Air Quality Rule Changes.

According to an article in the Rocky Mountain News, the new rule includes:

• Cutting emissions: Oil and gas operators in a drilling region northeast of Denver must cut overall emissions of volatile organic compounds (VOCs) from condensate storage tanks by 75 percent before May 1, 2007. That's an increase from current rules requiring cuts of 47.5 percent.
  
• New emission controls: Statewide, oil and gas operators must, for the first time, install emission controls on condensate storage tanks that emit more than 20 tons per year of VOCs. New emission controls on natural gas engines and dehydrating equipment also were approved. The new rules will be phased in over the next two years.
  
• Air quality reporting : The state's Air Pollution Control Division must provide an annual report on how the oil and gas industry is affecting air quality across the state.

Source: Todd Hartman. Dec. 418, 2006. "Air Panel OKs New Controls on Oil, Gas Industry Pollution." Rocky Mountain News.

• Blowouts
• Condensate tanks
• Construction activity
• Dehydrators
• Engines
• Flaring
• Fugitive emissions
• Pits
• Vehicles
• Venting

Condensate tanks: Some natural gas wells produce a semi-liquid condensate along with the gas. Condensates are hydrocarbons that are in a gaseous state within the reservoir (prior to production), but become liquid during the production process. Condensates are composed of hydrocarbons (typically those containing five or more carbon molecules), as well as aromatic hydrocarbons such as benzene, toluene, xylenes and ethylbenzene (BTEX).

Condensates may give off a characteristic hydrocarbon or petroleum-type smell. BTEX give off a sweet, aromatic odor. Most people can smell benzene when it reaches levels of approximately 1.5 - 5 parts of benzene per million parts of air (ppm). The Occupational Safety and Health Administration (OSHA) has set maximum exposure levels for workers at 1 ppm (over an 8-hour period) and 5 ppm (over a 15-minute period). At levels above 150 ppm some people may begin to experience serious and irreversible health effects.

The vapors of benzene, toluene and xylenes are heavier than air and may accumulate in low-lying areas.

Construction activity: a certain amount of construction accompanies every phase of oil and gas development (exploration, field organization, production, and site abandonment). Each requires disturbing the soil to some degree through the use of construction machinery. These activities generate particulate matter and stir up dust, which in turn react with the other prerequisites to form ground-level ozone, or smog.

Dehydrators:
If the gas wells use glycol dehydrators to remove water from the gas, the dehydrator may release aromatic organic chemicals to the atmosphere. If the natural gas undergoing dehydration contains benzene, toluene, or other volatile organic compounds, significant quantities of these compounds can be released when the glycol solution undergoes regeneration.

Engines
Drilling, completion and workover trucks, rigs and equipment such as pumps typically run off of diesel-powered or gasoline engines. The exhaust fumes from gasoline and diesel fuels can produce emissions that are noticeable to people living downwind.

Polycyclic aromatic hydrocarbons (PAHs) are found in exhaust from motor vehicles and other gasoline and diesel engines. A long list of other air pollutants, including nitrogen oxides, carbon monoxide, BTEX, formaldehyde and metals are also contained in diesel fuel combustion products.

Flaring
Flaring is the practice of burning gas that is deemed uneconomical to collect and sell. Flaring is also used to burn gases that would otherwise present a safety problem. It is common to flare natural gas that contains hydrogen sulfide (i.e., sour gas), in order to convert the highly toxic hydrogen sulfide gas into less toxic compounds.

Flares emit a host of air pollutants, depending on the chemical composition of the gas being burned and the efficiency and temperature of the flare. Flaring results in hydrogen sulfide emissions if hydrogen sulfide is present in large enough amounts in the natural gas. There may also be additional by-products formed if some of the chemicals used during the drilling or hydraulic fracturing process are converted to a gaseous form and are burned along with the natural gas.

The Ventura County Air Pollution Control District, in California has estimated that the following air pollutants may be released from natural gas flares: benzene, formaldehyde, polycyclic aromatic hydrocarbons (PAHs, including naphthalene), acetaldehyde, acrolein, propylene, toluene, xylenes, ethyl benzene and hexane. Researchers in Canada have measured more than 60 air pollutants downwind of natural gas flares.[1]

Fugitive Emissions
Fugitive emissions are unintentional leaks of gases. This may occur from breaks or small cracks in seals, tubing, valves or pipelines, as well when lids or caps on equipment or tanks have not been properly closed or tightened. When natural gas escapes via fugitive emissions, methane as well as volatile organic compounds (VOCs) and any other contaminants in the gas (e.g., hydrogen sulfide) are released to the atmosphere.

Recently, while on a tour of oil and gas fields in Weld and Adams counties, a team of high-tech Environmental Protection Agency investigators used an infrared camera to look for fugitive emissions, which are normally invisible to the naked eye. They aimed their camera at pipelines, valves and hatches atop storage tanks, the EPA regulators found numerous sources of fugitive emissions. According to a story in the Rocky Mountain News, "in one case, an open hatch atop a storage tank was gushing such a tremendous volume of emissions into the air that one participant jokingly compared it to the eruption of Mount Vesuvius near the ancient city of Pompeii."

This video (H/T Bluedaze) reveals fugitive emissions from several Barnett Shale gas well sites.

Dr. Theo Colburn of The Endocrine Disruption Exchange, has explained that "the tanks you see in this picture can be found across the gas fields in the US.

They look harmless as you drive by just like the other stationary equipment you see on well pads. Without an infrared camera, as in this case, that picks up the plume of the highly active volatile chemicals escaping from the tanks, no one would suspect that the tanks could possibly pose a public health problem.

As natural gas extraction continues to increase, federal, state, and local public health authorities and regulatory agencies are unprepared to deal with the problem."

Pits
Earthen pits are often used to store or evaporate produced water and waste water from natural gas dehydration or oil/gas separation units. Additionally, prior to disposal drilling wastes (muds and cements) and hydraulic fracturing (fracking) wastes are often stored in earthen or metal pits that are open to the air. There are hundreds of different chemicals that may be used during drilling, fracking and workover procedures, including acids, biocides, surfactants, solvents, lubricants and others.

Chemical compounds that are naturally present in natural gas, or chemicals that have been injected downhole during drilling, hydraulic fracturing or well workover operations, will be present in the water or wastes that are held in pits. Some of the lighter or more volatile chemicals and compounds, such as benzene, toluene, hydrogen sulfide, etc., will escape from the produced water pits into the atmosphere. These chemicals may then be transported through the air, into nearby neighborhoods. The odors associated with the natural gases or chemicals will vary, depending on the concentrations, volumes, and combinations of chemicals released.

Vehicles

The biggest pollutant from motor vehicle traffic at oil and gas operations is dust.

Burning fuel to power trucks also emits NOx, carbon monoxide, and sulfur dioxide, as well as particulate matter. These compounds combine with VOCs to form ground-level ozone (smog).

Venting
Venting is the release of gas to the atmosphere. Venting occurs at a number of points in the oil and gas development process (well completion; well maintenance; pipeline maintenance; tank maintenance; etc.).

During oil and gas development, huge quantities of gas may vented to the atmosphere. For example, during well completion, after a well is drilled and stimulated (e.g., hydraulically fractured), the wellbore and surrounding formation must be cleaned out. The solids and fluids from the well go into pits, while the gases are allowed to escape into the atmosphere, or they are burned off (flared). It has been estimated that a single well Wyoming's Jonah field will emit 115 tons of VOCs, and 4 tons of hazardous air pollutants such as benzene, toluene, ethylbenzene, xylene and hexanes. If the gas is flared, rather than vented, the emissions of VOCs and HAPs are reduced to 29 and 1 ton, respectively; but flaring of completion gases also results in the release more than a ton of nitrogen oxides, and almost half a ton of carbon monoxide per well.[2]

The primary component of natural gas is methane, which is odorless when it comes directly out of the gas well. At gas processing facilities, chemical odorants such as mercaptans are added to methane, so that consumers are able to smell it in the event of a gas leak. In addition to methane, natural gas typically contains other hydrocarbons such as ethane, propane, butane, and pentanes. Raw natural gas may also contain water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds.

Almost all references to the odor of raw or wellhead natural gas state that it, like methane, is odorless. The Ohio Department of Natural Resources, however, advises landowners that one way to detect an abandoned oil or gas well on their property is if they smell "natural gas" odors coming from their tap water. So, in some cases, there may be a slight hydrocarbon odor associated with venting of natural gas.

If the concentration of H2S in the gas is high enough, there may also be a "rotten egg" odor associated with the gas.

• Benzene, Toluene, Ethylbenzene and Xylene (BTEX)
• Carbon Monoxide
• Dust
• Hydrogen Sulfide
• Natural Gas
• Nitrogen Oxides
• Ozone
• Particulate Matter
• Sulfur Dioxide
• Volatile Organic Compounds

BTEX compounds. BTEX stands for benzene, toluene, ethylbenzene, and xylene, a group of compounds all that also belong to the broader category of volatile organic compounds, VOCs. Benzene is a known carcinogen, and has also been shown to cause blood disorders and to impact the central nervous system the reproductive system. Toluene may affect the reproductive and central nervous systems. Ethylbenzene and xylene may have respiratory and neurological effects. BTEX compounds can be emitted during various oil and gas operations activities, including flaring, venting, engines, produced water storage tanks, and during the dehydration of natural gas.

Carbon monoxide (CO). Carbon monoxide is emitted during flaring and from the operation of various machinery at oil and gas development sites. It is a colorless, odorless, flammable gas produced by incomplete burning of carbon-based fuels such as oil, natural gas, coal, and even wood. Carbon monoxide is poisonous if inhaled. It inhibits the blood's ability to carry oxygen, and can cause dizziness, unconsciousness, and even death.

Dust. Dust is created whenever there is dirt-moving activity such as construction of well pads, as well as when there is vehicle traffic on unpaved roads. Dust can cause or aggravate nuisances such as hay fever and allergies; stunt the growth of vegetation; and lead to decreased visibility.

Hydrogen sulfide (H2S). Hydrogen sulfide occurs naturally in some oil and gas formations. When oil or gas is extracted from these formations, H2S may be released when gas is vented, when there is incomplete combustion of flared gas, or via fugitive emissions from equipment. Hydrogen sulfide is a toxic gas which has a characteristic rotten egg odor at low concentrations. It is lethal if inhaled at high concentrations.

Natural Gas. Natural gas is released during venting operations, or when there are leaks in equipment used during oil and gas development. The primary component of natural gas is methane, which is odorless when it comes directly out of the gas well. In addition to methane, natural gas typically contains other hydrocarbons such as ethane, propane, butane, and pentanes. Raw natural gas may also contain hazardous air pollutants such as benzene, toluene, ethylbenzene, xylenes and hexanes, hydrogen sulfide (H2S), and carbon dioxide. Other compounds in natural gas typically include water vapor, helium, and nitrogen. Almost all references to the odor of raw or wellhead natural gas state that it, like methane, is odorless. The Ohio Department of Natural Resources, however, advises landowners that one way to detect an abandoned oil or gas well on their property is if they smell "natural gas" odors coming from their tap water. So, in some cases, there may be a slight hydrocarbon odor associated with venting of natural gas.

Nitrogen Oxides (NOx). NOx are formed during the combustion of fossil fuels, which causes a chemical reaction between nitrogen (which occurs naturally in the atmosphere) and oxygen. During oil and gas production, NOx are formed during flaring operations, and when fuel is burned to provide power to machinery such as compressor engines and other heavy equipment. NOx, in turn, may react with VOCs to form ground-level ozone. Nitrogen dioxide, one of the NOx chemicals, is a criteria pollutant regulated by the EPA, and can be seen, along with other particles in polluted air, as a reddish-brown haze. The health impacts from NOx include respiratory problems, heart conditions, and lung damage,

Ozone. Ozone itself is not released during oil and gas development. But some of the main compounds that combine to form ozone (e.g., volatile organic compounds and nitrogen oxides) are released from oil and gas operations. Ozone, when found at ground-level, is also referred to as "smog," which, when inhaled can cause or aggravate respiratory ailments such as asthma.

Particulate Matter. Particulate matter is composed of small particles that are suspended in the air and settle to the ground slowly. The most common sources of particulate matter from oil and gas operations are dust or soil entering the air during pad construction, traffic on access roads, and diesel exhaust from vehicles and engines used to power machinery at oil and gas facilities. Particulate matter can also be emitted during venting and flaring operations. Depending on the size and chemical composition of the particulate matter, the inhalation of these particles may lead to adverse health effects such as respiratory or breathing ailments, cancer, or premature death. Particulate matter suspended in air may also contribute to decreased visibility (i.e., regional haze).

Sulfur dioxide (SO2). Sulfur dioxide is formed when fossil fuels containing sulfur are burned. Many oil, natural gas, and coal formations contain traces of sulfur. Thus, SO2 may be emitted during flaring of natural gas, or when fossil fuels are burned to provide power to pumpjack or compressor engines or other equipment and vehicles at oil and gas sites. Sour gas processing plants also emit sulfur dioxide. SO2 is regulated by the EPA as a criteria air pollutant, and along with NOx, is a principal contributor to acid rain. Sulfur dioxide reacts with other chemicals to form particulate pollution, which can damage lungs and cause respiratory illness, heart conditions, and premature death.

Volatile organic compounds (VOCs). VOCs are carbon-containing substances that readily evaporate into the air. They can combine with nitrogen oxides to form ground-level ozone, which can cause respiratory ailments such as asthma, and decreased lung function. Examples of VOCs are benzene and toluene.

• At least 10 states have already enacted surface owner protection or damage compensation laws, and still have thriving oil and gas programs.
• Surface damages legislation restores the balance between landowners and the oil and gas industry - and doesn't curtail production or jobs.
• Compensating surface owners or posting damage bonds will not significantly hurt oil and gas profits or prevent oil and gas development.

1) AT LEAST TEN STATES IN THE U.S. HAVE THRIVING OIL AND GAS PROGRAMS AND HAVE ALREADY IMPLEMENTED SURFACE OWNER PROTECTION OR DAMAGE COMPENSATION LAWS.

• The State of Oklahoma's Surface Damage Act (Title 52 Chapter 318.2) provides one model for restoring balance between the oil and gas industry and landowners. This legislation also requires companies to negotiate written contracts with surface owners before drilling begins.
• In Oklahoma - Mineral owners must negotiate a written contract with the surface owner for the payment of any damages that may be caused by a drilling operation. This agreement must be negotiated prior to entering the site with heavy equipment. If agreement is not reached: or all parties are not contacted, the district court will appoint appraisers to make recommendations to the parties and to the district court concerning the amount of damages. The mineral and surface owners are each allowed to select one appraiser, and the two selected appraisers then select a third appraiser for appointment by the court. The mineral owner and the surface owner share equally in the payment of the appraisers' fees and court costs. No drilling may occur until an agreement is reached or a petition is made to the court to appoint appraisers. The courts may award triple damages where: the mineral owner willfully and knowingly began to drill without giving notice or without agreement of the surface owner; or the operator willfully and knowingly failed to keep posted the required bond.

2) SURFACE DAMAGES LEGISLATION RESTORES BALANCE BETWEEN THE OIL & GAS INDUSTRY, AND IT DOESN'T CURTAIL PRODUCTION OR JOBS.

• Oklahoma's Surface Damage Act became effective July 1, 1982. Gas production in Oklahoma reached an all time high in 1990 and was not affected by the Surface Damage Act. In fact, oil and gas production in the State of Oklahoma as in every other Western state, is most predominately affected by national market price and other bottle necks, such as availability of drilling rigs and availability of workers.

3) COMPENSATING SURFACE OWNERS OR POSTING DAMAGE BONDS WILL NOT SIGNIFICANTLY HURT OIL AND GAS PROFITS OR PREVENT THE DEVELOPMENT OF PROJECTS.

According to statistics from the Independent Petroleum Producers of America (IPAA), it costs approximately $468,000 to drill and equip an oil well in Oklahoma and $444,000 in New Mexico. It costs approximately $650,000 to drill a gas well in Oklahoma, and $583,000 in New Mexico. Not only is it less expensive to drill and equip wells in New Mexico than in Oklahoma, the average well in New Mexico produces more oil or gas than an Oklahoma well. Thus, New Mexico producers are earning more profits per well. Oklahoma producers can afford to compensate surface owners, and so can producers in New Mexico and other states.

TYPICAL SURFACE OWNER PAYMENTS IN OKLAHOMA
Compensation received by surface owners in Oklahoma is tied to the amount of damage caused by the oil and gas activities. This provides a great incentive for companies to minimize the amount of damage that they do when they are building roads, pits and pads.

The amounts awarded range from $7,500 to $50,000. The latter award occurred when it was shown that the operator unreasonably damaged the surface owner's property. Typically, courts have awarded higher damage amounts than appraisers.

• Anna Lee Cloud received $15,000 for damages largely related to diminution in the value of her land as a result of the oil and gas operations.
• John and Geraldine Turner received $8,000 for damages related to a well pad and access road. Two appraisers assessed damages of $8,000, while a third assessed damages at $7,500.
• A well was drilled on a section of Ed and Vicki Stewart's land. Appraisers assessed damages at $8,600.
• Frank Bowlby et al., received surface damages in the amount of $20,000, which was decided by jury. Appraisers had assessed damages at $7,500, but both the mineral and surface owners disputed the findings and demanded the jury trial.
• In some cases, the damages awarded are much higher. In one case, the operator, Andover, disturbed 6 acres of land (construction of a road, pad, and pit site) on the Thompson farm. On the day prior to the actual spudding of the well, Andover abandoned this location in favor of a site on the opposite side of the farm. The preparation of the second well site was similar to the first. Andover utilized an area of a little more than eight acres in the construction of a road, a reserve pit, and a pad, but the second site was on sloping terrain and construction of the pad necessitated moving a large quantity of earth in order to create a level area. At the abandoned site, Andover removed most of the gravel used for the pad and road but was unable to remove all of the substance. In grading the abandoned location, the grade was changed slightly so that water occasionally stands in this particular area, thus making it unsuitable for certain crops, such as alfalfa. After restoration attempts were completed, the Thompsons brought suit against Andover, alleging that Andover had abused their rights by using more of their property than was reasonably necessary, and had failed to restore the property to its original condition. After viewing the property, the jury awarded the Thompsons $50,000 in actual damages.

As shown above, typical payments in Oklahoma are $8,000, unless there has been unreasonable damage done to the surface. This amount is a drop in the bucket in terms of the profits made by oil and gas wells, or when compared to the overall cost of finding and drilling a well. Surface damage payments or bonds are NOT going to make or break an oil or gas operation.

OIL PROFITS
The average New Mexico well produces 8.5 barrels of oil per day. In January 2006, crude oil sold for $60 to 65 barrel. That means that on average, an oil well in New Mexico made $510 to 552 per day. IF AN OIL PRODUCER PAYS A SURFACE OWNER $10,000 IN COMPENSATION, THE PRODUCER WILL COVER THAT COST IN 18 TO 20 DAYS. IF A PRODUCER POSTS A $25,000 BOND, THE PRODUCER WILL COVER THAT COST IN 45 TO 49 DAYS.

GAS PROFITS
The average New Mexico gas well produces 69,900 Mcf of gas a year, or 192 Mcf per day. According to the Energy Information Adminstration, the average wellhead price in December 2005 was $10.02/Mcf. That means that on average, a gas well in New Mexico makes about $1,924 per day. IF A GAS PRODUCER PAYS A SURFACE OWNER $10,000 IN COMPENSATION, THE PRODUCER WILL BE ABLE TO COVER THAT COST IN LESS THAN 6 DAYS. IF A GAS PRODUCER POSTS A $25,000 BOND, THE PRODUCER WILL COVER THAT COST IN LESS THAN 13 DAYS.

DRILLING AND EQUIPPING WELLS
According to statistics from the Independent Petroleum Producers of America (IPAA), it costs approximately $444,000 to drill and equip an oil well and approximately $583,000 to drill a gas well in New Mexico. SO IT IS HIGHLY UNLIKELY THAT AN EXTRA $10,000 WILL STOP A COMPANY FROM DRILLING A WELL.

FINDING AND DEVELOPING OIL AND GAS WELLS
The federal Department of Energy (DOE) collects information from major oil and gas producers in the U.S. The DOE reports that in 2002 it cost producers, on average, $8.5 million to find and develop an oil or gas well. A SURFACE DAMAGE PAYMENT OF $10,000 IS 0.12% OF THE COST OF FINDING AND DEVELOPING A WELL. Even if most producers spend even half that amount to develop a well, it is very clear that $10,000 will not even add add a drop to the overall "bucket" of development costs.

Selected states with surface owner protection laws

• leasing of publicly owned minerals
• federal lease maps and information
• leasing of privately owned minerals

Leasing Public Minerals for Oil and Gas Development

Landowner Notification
The direct notification of individuals who own or lease land located above publicly owned minerals typically does not happen when the leasing of state or federal minerals occurs. Consequently, often surface owners do not realize that the mineral rights have been leased to a company that may use their land to access and produce the oil and gas underneath their property.

Some states do have processes for posting notices about lease sales on state lands. For example, the state agency in Montana will post notices on its web site, in local newspapers and they will send information about leases to a mailing list.

The Interstate Oil and Gas Compact Commission has produced a table that summarizes state oil and gas leasing information, including how the state agencies notify the public about lease sales. This table is available at:

Federal Lease Sale Information and Maps

The BLM posts federal lease sale information and more general maps on various web sites:

• Colorado BLM site.
• Montana, North and South Dakota BLM site.
• New Mexico, Oklahoma, Kansas, Texas BLM site.
• Utah BLM site.
• Wyoming BLM site.

Leasing Private Minerals for Oil and Gas Development

When minerals are owned by a private citizen or entity, oil and gas companies must lease the minerals prior to drilling for oil and gas.

A mineral lease is a contractual agreement between the owner of a mineral estate (known as the lessor), and another party such as an oil and gas company (the lessee). The lease gives an oil or gas company the right to explore for and develop the oil and gas deposits in the area described in the lease.

When you (the lessor) sign a lease you essentially become a partner with that company (the lessee). When a company holds a lease to your mineral property, you cannot lease those mineral rights to another company until the lease term with the first company expires. When the lease terminates, all rights to the minerals revert back to the mineral owner.

As with any partnership, open communication is necessary to maintain a successful relationship. A lease may be something that you may have to live with for many years - perhaps the rest of your life. Consequently, it is in your best interest to maintain a business-like relationship.

• Get everything in writing, and keep the lease in a safe, but easily accessible place. In the event the lease is lost, you should be able to obtain a copy of the lease from the county recorder's office.
• Do your research. Ask neighbors, government agency staff or other mineral owners and landowners about the company, your potential business partner. It is important to know who you are dealing with before entering into a lease.

For more information and tips on leasing your minerals, download or order Chapter 3 of OGAP's landowners guide to oil and gas "Oil and Gas at Your Door?". Also, see the "For More Information" section below, for links to various groups that provide information on mineral leasing and royalty issues.

• Read some landowner stories on health effects potentially related to oil and gas development.
• Find out more about some of the chemicals being used by industry, and the potential health effects associated with these chemicals.
• Read about air contaminants that are released throughout the oil and gas development process.

One of the most hardfought provisions of the noise rule passed in December, 2005 by the Colorado Oil and Gas Conservation Commission, i.e., a requirement to reduce oil and gas noise to 45 decibels in rural, agricultural and residential areas, was struck down at a hearing held on September 18, 2006.

Despite the testimony of several affected landowners, and information indicating that industry could afford to reduce noise to the 45 decibel level, the Commissioners caved to industry's wishes, and overturned the earlier decision to lower noise in rural, agricultural and residential areas. Although this protection was lost, there are still some provisions in the new noise rule that are favorable to landowners in Colorado. Read a summary of how the how the December, 2005 rule benefits landowners

Industry allowed to proceed with challenge of the new Colorado noise rule (February, 2006)

At a hearing held February 13, 2006, the Colorado Oil and Gas Association requested that the COGCC re-open the recently enacted noise rule, and allow them to challenge the provision that requires industry to reduce noise levels in residential areas to 45 decibels (dBA). Many citizens protested this request, and OGAP and the San Juan Citizens Alliance argued that the industry had ample opportunity to raise their issues at the hearings when the noise rule was debated last year. In the end, however, industry won the right to challenge the 45 dBA provision because the COGCC failed to properly advertise the rule. The noise rule hearing will be held in either September or October of 2006. If the industry is unable to convince the Commissioners to change the 45 dBA provision, it will take effect on January 1, 2007, and apply to new oil and gas operations, as planned.

New Colorado noise rule challenged by the Colorado oil and gas industry (January, 2006)

Noise from oil and gas drilling and production is a significant issue for many landowners living in close proximity to these developments. In December of 2005, the Colorado Oil and Gas Conservation Commission (COGCC) amended Rule 802, making it one of the most stringent noise regulations for oil and gas operations in the country. This was a major victory for landowners across the state.

The Colorado Oil and Gas Association, an industry group, will be at the February, 2006 COGCC hearing, asking the Commissioners to reconsider the new rule. COGA wants to do away with one of the most important provisions of the new noise rule, which is the reduction to 45 dBA in residential/rural/agricultural areas. Read COGA's submission.

New Colorado noise rule a victory for landowners (December, 2005)

• Read a summary of how the new rule benefits landowners
• Read the new Colorado oil and gas noise rule
• Read OGAP/SJCA recommendations to the COGCC

General Information on how humans perceive noise

There are some key concepts and facts that will help readers better understand noise:

• what is sound
• how do humans perceive sound
• how is sound quantified
• how sound travels
• all noise is not equally annoying

What is sound?
Noise is often defined as unwanted sound. Sound is defined as any pressure variation heard by the human ear. The sound pressure level (SPL) is a measure of the air vibrations that make up sound. Because the human ear is sensitive to a wide range of pressure levels, the SPL is measured on a logarithmic scale with units of decibels (dB).

How do humans perceive sound?
Healthy human ears perceive pressure variations over a wide range of frequencies -- from low frequencies of 20 Hz to frequencies as high as 20,000 Hz. In terms of sound pressure levels, the human ear's range starts at the threshold of hearing (0 dB) and ends at the threshold of pain (around 140 dB).

The human ear is less sensitive to sounds in the low frequencies compared to the higher frequencies. For example, a 50 Hz (low frequency) tone must be at a level of 85 dB in order to be perceived by the listener as being the same loudness as the higher frequency 1000-Hz tone at a level of 70 dB.

How is sound quantified?
As mentioned above, sound levels are usually measured and expressed in decibels (dB). Most environmental noise does not consist of a single frequency, but rather a broad band of frequencies differing in sound level. The intensities of each frequency add to generate sound. The method commonly used to quantify environmental sounds involves evaluating all of the frequencies of a sound according to a weighting system which reflects that human hearing is less sensitive at low frequencies and extremely high frequencies than at the mid-range frequencies. This is called "A" weighting, and the decibel level measured is called the A-weighted sound level (dBA).

As a rule of thumb, a doubling in the loudness of the sound occurs with every increase of 10 dB in sound pressure. In other words, for most individuals a 60 dBA noise would sound twice as loud as a 50 dBA noise.

How Sound Travels
Sound is caused by changes in air pressure. For example, when a mallet strikes a drum the drumhead begins to move back and forth (vibrate). As the drumhead moves down, air is pulled toward it, and as the head bounces back up it pushes air away. This creates changes in air pressure that move (or propagate) away from the drum, eventually striking our eardrum. These changes in pressure are known as sound waves.

There are a number of factors that affect the propagation of sound. The most important include: distance from source; obstacles such as barriers and buildings; atmospheric absorption;wind direction and speed; temperature and temperature gradient; humidity; precipitation;reflections; and ground absorption.[1]

It is important to understand that noise does not always decrease as one moves away from a noise source. The above factors can work to increase or decrease noise levels. For example, at short distances (up to 160 feet) the wind has a minor influence on the measured sound level.

At distances greater than 1,000 feet from a noise source, noise can become louder on the downwind side by as much as 20 dB, while on the upwind side levels can drop by 20 dB (depending on wind speed and distance).[2]

Other things to consider include the fact that while barriers may act to reduce high frequency sounds, low frequency sounds are difficult to reduce using obstacles or barriers. Additionally, while soft ground surfaces and the atmosphere are effective at absorbing mid-frequency and high frequency noise, these factors do not tend to reduce low frequency noise to the same degree. This means that as one moves away from the source, low frequencies often become much more prominent.[3]

All noise is not equally annoying
Not all noise has the same effect on humans, nor do all humans react in the same way to noise stimuli. Certain noise characteristics can greatly increase the annoyance factor and the potential health impacts associated with noise. In addition to the sound pressure level, these factors include: 1) difference between the new noise and the prior ambient noise environment; 2) the presence tonal noise; 3) low frequency noise; 4) fluctuating, intermittent or periodic sounds; and 5) impulsive sounds.

Noise from oil and gas operations

Noise from oil and gas development comes from a number of sources: truck traffic, drilling and completion activities, well pumps and compressors. For some landowners, noise from oil and gas operations is so loud or of such a different sound quality that it makes them feel as if they are living in an industrial zone.

Noise from wells and compressors led the Van Staverans to move from their home.

For people who live in rural areas, the arrival of a new, industrial noise source can greatly disturb the natural environmental soundscape. Gail and Al Van Staveran were so greatly affected by the noise of nearby wells and compressors that they were driven away from their home.

Landowners often complain about noise levels associated with natural gas compressors. The noise level varies with the size of the compressor and distance from the compressor; and it changes with shifts in wind direction and intensity. According to the Powder River Basin Resource Council, "Depending on the wind direction, the roar of a field compressor can be heard three to four miles from the site. Near the compressor stations, people need to shout to make themselves heard over the sound of the engines."

One Wyoming landowner has described compressor noise in this way:

Now comes the second phase. The dreadful noise generated by a nearby large compressor station. Noise that was so loud that our dog was too frightened to go outside to do his business without a lot of coaxing. Noise that sounds like a jet plane circling over your house for 24 hours a day. Noise that is constant. Noise that drives people to the breaking point. My neighbor called the sheriff, state officials and even the governor and was told nothing could be done about the noise. Like I said, the noise drives people to the breaking point, and my neighbor fired 17 rifle shots toward the station.
--Excerpted from CBM Destroys Retirement Dream.

How loud is oil and gas noise?

A study in La Plata County, Colorado, reported noise levels for a number of oil and gas activities:[4]

The Bureau of Land Management (BLM) published different numbers. At 50 feet from the source, the measured noise levels were: well drilling - 83dBA; pump jack operations - 82 dBA; produced water injection facilities - 71 dBA; and gas compressor facilities - 89 dBA.[5]

In the same study, BLM also reported typical noise levels from construction equipment and oil and gas activity. These are presented in the chart below. Again, the sound levels were taken at a distance of 50 feet (15 meters). Estimates of noise attenuation at distances greater than 50 feet can be made by reducing noise levels by a factor of 6 dBA (A-weighted sound levels) for each doubling of distance. The actual noise levels experienced by a receptor, however, will depend on the distance between the receptor and the equipment, the topography, vegetation, and meteorological conditions (e.g., wind speed and direction, temperature, humidity).

Noise levels reported by the Bureau of Land Management. See endnote [5]

Rationale for a 45 dBA (or lower) residential noise standard

In many residential neighborhoods, especially low density and rural areas, the nighttime noise level is very quiet. According to a Colorado-Based noise consultant, ambient noise levels in residential areas are frequently as low as 35 dBA during the nighttime, and are occasionally lower [6]. In these situations, if oil and gas facilities are allowed to emit noise at 45 dBA, the noise will be perceived by many as being twice as loud as the ambient noise in the area. In Alberta, Canada, it has been estimated that the ambient rural noise level is 35 dBA at night.

Noise standards of 45 dBA LEQ (nighttime) or lower are used in many jurisdictions that have oil and gas operations.

There are several jurisdictions that require oil and gas operators to meet a 45 decibel level during the night-time, in residential areas. Typically, noise measurements are taken outside, at a certain distance from or at the property line of the receiver (e.g., a house, hospital, etc.). These are called "receptor-based" noise standards. In some cases, noise measurements are taken a certain distance from the noise source ("source-based" standards). In 2005, Colorado amended its noise rule from a "receptor-based" to a "source-based" standard, requiring noise measurements to be taken 350 feet from the oil and gas noise source.

Alberta, Canada: Alberta is a major oil and natural gas producing province in Canada. In Alberta, the Energy and Utilities Board has the responsibility for regulating noise from oil and gas operations. The EUB has produced what may be the most comprehensive noise regulations for the oil and gas industry across North America. The EUB essentially has a sliding scale noise standard whereby acceptable noise levels vary with the ambient noise. For example, if a citizen lives in an area where ambient noise is low (e.g., where housing density and traffic noise are low), then the oil and gas operator must ensure that noise reaching the receptor is no louder than 40 dBA. In some instances, if the ambient noise is very low (e.g., 30 dBA), companies may be required to mitigate noise to even lower levels (e.g., 35 dBA).

As ambient noise conditions increase, the allowable noise level increases. The highest allowable level in a residential neighborhood is 56 dBA at night. This noise level applies when there are more than 160 dwellings in a quarter-mile radius, and there is a major traffic source (road, rail, air) within 30 m (90 feet) of any of the dwellings.

World Bank: For onshore well sites, the recommended maximum noise level is 55 dB(A) and 45 dB(A) for day and night, respectively (measured at receptors or the edges of a property boundary, on an average hourly basis). These levels apply to residential, educational and institutional areas. Noise abatement measures should achieve either the levels state above or a maximum increase in background levels of 3 decibels (measured on the A scale) [i.e., dBA].

Sacramento County, CA: Sacramento County is a significant producer of dry natural gas in California. In the county, the allowable noise level is 50 dBA L50 (daytime) and 45 dBA L50 (nighttime), measured at residential properties. This is according to the Noise Element Of The1993 County Of Sacramento General Plan.

City of Longbeach, CA: The allowable exterior noise level in many parts of the city is 45 dBA (nighttime), according to the Longbeach city ordinances. Oil and gas operations must meet this standard, except during drilling and well servicing.

Examples of residential noise requirements of 45 dBA for oil and gas operations

45 dBA is achievable, even as close as 350 feet from the noise source

There are numerous examples that show that 40 - 45 dBA is achievable at 350 feet from the source. The City of Farmington, New Mexico uses "1 dBA over ambient" as a standard for all wells constructed in the city. In January of 2005, OGAP staff conducted sound measurements at well sites in the City of Farmington. Noise levels measured at 300 feet from the noise source varied from 39 to 49 dBA. It is estimated that if measurements had been taken at 350, these sound levels would have been in the range of 37 to 47 dBA. For more information, please download the OGAP/SJCA submission to the COGCC.

It is not cost prohibitive to achieve 45 dBA at 350 from the noise source

As part of its submission to the Colorado OIl and Gas Conservation Commission noise rule hearing, OGAP prepared a chart of noise mitigation cost estimates for oil and gas facilities that have achieved the 40-45 dBA noise level.

Noise Mitigation Options

There are many proven ways of mitigating noise from oil and gas operations. One only has to look to regions that have fairly stringent noise regulations (e.g., Farmington, New Mexico, Alberta, Canad) to find excellent examples of noise mitigation. There are numerous acoustical or noise abatement companies that provide services to the oil and gas industry.

Noise from pumpjacks

A low-profile pumping unit can replace the conventional unit, which uses a 30- to 40-foot beam and looks like a giant, bobbing horse's head. The conventional pump is run on a gas- or diesel-powered engine, which is noisy and smelly. Alternatives to this large pump include using a pneumatic pumping device that doesn't require an engine, therefore, produces little or no noise. This pump stands about 10 to 15-feet tall. According to one company, pneumatic pumps will not function correctly if a lot of water is extracted while extracting methane gas. Consequently, when larger amounts of water are produced, an alterative to the standard beam pump is the progressive cavity pump. These pumps come in different shapes and sizes, and like the pneumatic pump, they can run on electric motors, and therefore, be much quieter than conventional pumps.

Vehicle Noise

Noise created by operators constantly driving in and out from the well pad to monitor well production can be mitigated using an automated monitoring system, which allows wells to be monitored remotely, e.g., from the company's office. Vehicle noise may also be controlled to some extent by limiting the hours that industry employees use residential roads for accessing wells (e.g., limiting vehicles to the hours of 7:00 a.m. to 9:00 p.m., except in emergency situations).

Engine noise

To mitigate noise impacts from engines, sound barriers made out steel and sound-absorbing insulation (i.e., NOT styrofoam) may be used. Sound barriers may be placed in an L-shape above the engine, and they extend past the sides of the engine. To reduce noise in sensitive areas, pumpjacks, engines, or well-site or field compressors may be entirely enclosed in a sound-insulated building.

Some engines can operate at a constant number of revolutions per minute (RPM), which reduces the often annoying fluctuating noise caused by engines that speed up and slow down. Mufflers, like those used for automobile engines, can be used to minimize engine noise. In noise sensitive situations, hospital-grade mufflers used in series can be more effective at reducing noise from engines.

In some situations, natural gas or diesel engines can be replaced with electric motors. These motors, if properly installed, tend to be much less noisy than their engine counterparts. The use of electrical motors depends on the availability of electricity, and whether or not a company is willing to run an electrical line to the site.

Compressor noise

Noise from compressors can be mitigated most effectively by treating each significant oise source: gas turbines or engines, compressors, exhaust outlets and air inlets, and cooling and ventilation fans. Abatement may involve changing the blades on fans, which can change the frequency of sound emitted, thereby removing the annoying tones. Engine noise can be muffled using automotive-type mufflers, or by housing the engines in acoustically insulated structures. Also, the entire compressor can be housed in an acoustically insulated building.

Cost of Mitigation

Some oil and gas opearators refuse to apply noise mitigation to their sites, using the excuse that mitigation is too expensive. If noise mitigation measures are installed when the site is constructed, rather than attempting to abate the noise after the equipment is installed, the costs are much more affordable. OGAP has compiled some examples of the costs of mitigation.

Examples of companies providing noise mitigation services to oil and gas industry

• ATCO Noise Management
• Acoustical Control, Inc.
• Enviro Noise Control.
• Noise Solutions, Inc.
• If you wold like to have your company added to this list, please contact ogap (lisa [at] ogap [dot] org)

Noise and its Effects on Human Health

There are adverse physical and mental effects from noise. For example, prolonged periods of exposure to 65 dBA can cause mental and bodily fatigue. Furthermore, noise can affect the quantity and quality of sleep; cause permanent hearing damage; contribute to the development or aggravation of heart and circulatory diseases;
and transform a person's initial annoyance into more extreme emotional responses and behavior.[7]

According to the World Health Organization: [8]
Noise annoyance is a global phenomenon. A definition of annoyance is "a feeling of displeasure associated with any agent or ondition, known or believed by an individual or group to adversely affect them."

. . .apart from 'annoyance', people may feel a variety of negative emotions when
exposed to community noise, and may report anger, disappointment, dissatisfaction, withdrawal, helplessness, depression, anxiety, distraction, agitation, or exhaustion.

. . . Social and behavioural effects include changes in overt everyday behaviour patterns (e.g. closing windows, not using balconies, turning TV and radio to louder levels, writing petitions, complaining to authorities); adverse changes in social behaviour (e.g., aggression, unfriendliness, disengagement, non-participation); adverse changes in social indicators (e.g. residential mobility, hospital admissions, drug consumption, accident rates); and changes in mood (e.g. less happy, more depressed).

The World Health Organization also reports that "a large proportion of low-frequency components in noise may increase considerably the adverse effects on health." [9]

Health effects of low frequency noise

Unfortunately, many of the health effects of noise due to oil and gas operations have not been scientifically documented. The lack of scientific study does not mean, however, that noise issues related to oil and gas are insignificant. The loud, continuous noise during the drilling phase; the loud short-term noises from flaring or hydraulic fracturing; the intermittent whine of poorly maintained pump jacks and other equipment; and the loud or low frequency noise from compressors are common complaints related to oil and gas development. Numerous citizens have reported disruption of sleep and increased anxiety caused by noise from oil and gas developments.[10]

Noise and its Effects on Wildlife

Noise effects wildlife in a variety of different ways. It can cause the temporary or permanent displacement of animals and birds from particular areas. It can also have physiological effects that are detrimental to wildlife health.

The Draft Resource Management Plan for leasing federal lands in southern New Mexico states that in some cases, federally threatened and endangered wildlife species may be affected by elevated noise levels. For example:

• High noise levels potentially can mask communications by wildlife that are used to attract mates and defend territories.[11]
• Increased noise and activity levels during construction and development could result in [bird] nest abandonment and decreased reproductive success if such activity occurs during the breeding season.[12]

In the final Environmental Impact Statement for the Jonah natural gas field, the BLM stated that:

It is likely that noise already has contributed to the apparent decrease in wildlife use on and adjacent to the Jonah Infill Drilling Project Area (JIDPA), with observed decreases in raptor nesting activity and productivity, male greater sage-grouse lek attendance and sage-grouse nesting within the JIDPA having been reported over the past several years. Data also suggest that noise may contribute to disturbance and/or departure of greater sage-grouse from area leks. [13]

Workshops
OGAP provides support to communities, landowners and local governments by presenting workshops on the oil and gas development process, including coalbed methane; information on oil and gas regulation; legal issues related to surface owner rights; and alternative practices that can be used to minimize the impacts of oil and gas development. Landowners, community groups and local governments may contact OGAP if you are interested in setting up a workshop in your community.

Landowner Information Pages and Fact Sheets (more will be coming soon)

• Split Estate Information
• Surface Owner Protection Legislation
• Landowner Stories

Publications

Oil and Gas at Your Door? A landowner's guide to oil and gas development
This downloadable, 200-page guide provides detailed information on the oil and gas development process; the potential impacts and issues related to drilling and operations; the regulation of oil and gas; landowner legal issues; negotiating surface use agreements; and numerous landowner stories.

Increasingly, landowners and residents of oil and gas field communities are reporting health impacts that they believe are linked to environmental toxics associated with the oil and gas development activities in their area. These reports include incidents of: asthma, respiratory and cardiovascular illnesses, autoimmune diseases, liver failure, cancer and other ailments such as headaches, nausea, and sleeplessness. For years, OGAP and partner groups have been asking for full disclosure of all these chemicals to public.

In June of 2006, OGAP submitted a letter to the Colorado Oil and Gas Conservation Commission (COGCC) and the Colorado Department of Public Health and the Environment (CDPHE) on behalf of five citizens organizations in Colorado. The groups asked that state agencies require disclosure of the chemicals used and monitoring of chemicals and wastes released by the oil and gas industry in Colorado.

Read OGAP's Letter to COGCC and CDPHE.

The need for disclosure of chemicals is finally making some progress at the state level as the COGCC is considering a rule that would require all operators in Colorado to disclose all chemicals used, stored, or released at any facility. Read COGCC Draft Rule 205. These rule changes could be just in time as The Environmental Working Group and The Endocrine Disruption Exchange just released a report which finds that over 430 million gallons of chemicals have been injected into the state of Colorado-see below.

OGAP and partner groups are supporting the state on this proposed rule in the formal hearing process against the concerns of major industry players such as Halliburton, the Colorado Oil and Gas Association and the Colorado Petroleum Association. Read the prehearing statements and rebuttals from all of these parties! Halliburton has gone so far as to claim it will leave the state of Colorado if forced to disclose the chemicals it uses because the state agencies cannot be trusted with this information.

Latest News:

• The Environmental Working Group and The Endocrine Disruption Exchange release a report that found 430 million gallons of chemical-laced fluids have been injected into more than 9,000 oil and gas wells in Colorado. It is likely that this is only the tip of the iceberg considering there are currently over 35,000 active wells in the state and 90% of these wells have been hydraulically fractured at some point during the lifetime of the well. The report also found that at least 65 chemicals used by natural gas companies in Colorado are listed as hazardous under 6 major federal laws designed to protect Americans from toxic substances.

Read the Report!

• The Endocrine Disruption Exchange (TEDX) Inc., reports on toxic chemicals used in oil and gas development in (click on state for report) :

-Western Colorado

-New Mexico

-Montana

-Wyoming

The chemicals used during oil and gas operations can escape into the environment via a number of pathways: chemical spills release chemicals into air through volatilization, and spills can enter water and soil; chemicals injected into the ground may come in contact with drinking water aquifers; chemicals stored in pits or tanks on surface may escape (e.g., volatilze, leak, leach) into air, water or soil. Additionally, flammable chemicals may burn, releasing a host of toxic by-products into the air.

Without the cooperation of industry regulators in requiring oil and gas companies to disclose the complete make-up and volumes of chemicals in their products, a realistic evaluation of their immediate and long term effects on health and the environment cannot be made. Nor can acutely impacted individuals living in and oil- or gas-patch readily or realistically assess their exposures.

TEDX Analysis of Oil and Gas Chemicals in Colorado

In 2006, The Endocrine Disruption Exchange (TEDX, Inc.) began gathering health and toxicity data related to chemicals used in oil an gas operations in Colorado. The chemical information was compiled primarily from industry Material Satety Data Sheets. Health and toxicity information was derived from the MSDSs, as well as numerous other sources.

The TEDX review revealed some startling information on chemical ingredients, toxicity, and potential health effects related to ingestion, inhalation, and other exposures to these chemicals.

• The analysis conducted by TEDX showed that there are toxic chemicals used throughout the oil and gas development process. While the information is specific to Colorado, many of the chemical products in the TEDX database have been found in oil and gas chemicals used in other states.
• The four most common adverse health effects of the chemicals in the TEDX database are: (1) neurotoxicity; (2) skin/sense organ toxicity; (3) respiratory problems; and (4)gastrointestinal/liver damage.
• Specific ingredients of particular concern that TEDX found present in Western Colorado's oil and gas industry include: 2-mercaptobenzothiazole (2-MBT); 2-(2-methoxyethoxy)ethanol; nonylphenols and toxic metals. These substances are for the most part water soluble, volatile and highly mobile.

Potential health effects of selected chemicals from the TEDX analysis

Ethylene glycol monobutyl ether (also known as 2-Butoxyethanol or 2-BE)

• linked to liver cancer, deadly by inhalation, causes degeneration of testes, reproductive problems, and immediate exposures may result in blood disorders.
• this chemical is found in foaming agents, which are used during hydraulic fracturing operations.

2-(2-methoxyethoxy) ethanol

• suspected carcinogen, known to cause fetal deformities and organ malformations, reduces male fertility.
• Found in a number of products including biocides, hydraulic fracturing fluids and shale stabilizers.

Nonylphenols

• endocrine disruptors, negative impact on male development, reproductive ability and may impede brain development, and causes atrophy of thymus (a critical component of the immune system).
• Ethoxylated Nonylphenol is used in surfactants and additives that increase viscosity.
• according to a presentation by BJ Services, an oilfield services company, the oil and gas industry in other parts of the world have stopped using these chemicals due to their toxicity.

Download the most recent version of the TDEX report (January 15, 2008).

Or visit the TEDX web site for more information on the project.

TEDX Analysis of Oil and Gas Chemicals in New Mexico

Health Effects

TEDX were unable to find health effects associated with 34 of the chemicals on the list. Of these, only 14 had been assigned a chemical identification number (CAS number) by the American Chemical Society enabling us to search the literature. TEDX found no adverse health effects for these. However, TEDX were unable to determine the safety of the other 20 chemicals because they were listed as proprietary or had chemical names that were so general that the specific chemical could not be identified, or were
listed as "no hazardous ingredients."

Many of the chemicals on this list have been tested for lethality and acute toxicity based on short-term contact. The majority have never been tested at realistic, environmentally relevant, chronic exposure levels, or for delayed effects that may not be expressed until long after exposure. Nor have adequate ecological studies been done. For example, most of the chemicals have not been tested for their effects on terrestrial wildlife or birds, fish, and invertebrates. It is reasonable to assume that the health endpoints listed above could very well be seen in wildlife, domestic animals, and pets.

The products labeled as biocides are among the most lethal on the list, and with good reason. Bacterial activity in well casings, pipes and joints can be highly corrosive, costly, and dangerous. Bacteria can also alter the chemical structure of polymers and make them useless. Nonetheless, when these products return to the surface either through deliberate retrieval processes or accidentally they pose a significant danger to workers and those living near the well and evaporation ponds. They can also sterilize the soil
and inhibit normal bacterial and plant growth for many years.

In general, the volatile chemicals have more adverse health effects associated with them than the soluble chemicals. Not only are they more toxic, but in the area of skin and sensory organ toxicity 100% are associated with harm, and over 90 % are associated with harm in the gastrointestinal and liver, and the respiratory system.

The soluble chemicals are associated with more adverse health effects than the total number of chemicals. While they do not show as high a percentage of effects as the volatile chemicals, between 75% and 94% can cause harm to the same systems as listed above.

The use of respirators, goggles and gloves is advised on many of the MSDSs for products on this list. This indicates serious, acute toxicity problems that are not being addressed in the recovery process when the chemicals come back to the surface. It raises concern over possible hazards posed to those living in regions where development activity is taking place.

Download the TEDX Report on Oil and Gas Chemicals Used in New Mexico.

Go to TEDX website for more information.

TEDX Analysis of Oil and Gas Chemicals in Montana

The 104 products contain at least 85 chemicals. Eighty-three percent of the products have one or more adverse health effects. Of these, 17% have one to three possible health effects, and 83% have between four and fourteen possible health effects. Fourteen products have 14 adverse health effects.

Upon plotting the percent of chemicals in each health category, a pattern emerged of the possible health effects for the 85 chemicals. The four categories with the highest exposure risk are (1) eyes, skin, and sensory organs; (2) respiratory system; (3) gastrointestinal tract and liver; and (4) the cardiovascular system and blood.

Thirty-seven chemicals were water soluble. The four categories with the highest exposure risk are (1) eyes, skin, and other sensory organs: (2) gastrointestinal tract and liver; (3) respiratory system; and (4) the cardiovascular system and blood.

Thirty-eight chemicals were volatile. The four categories with the highest exposure risk are (1) respiratory system; (2) eyes, skin, and other sensory organs; (3) the brain and nervous system; and (4) the gastrointestinal tract and liver.

Several reasons led to the lack of data about the health effects of some of the products and chemicals on the spread sheet: (a) Some products list no ingredients. (b) Some products list some or all of the ingredients as "proprietary." (c) No health effect data were found for a particular chemical or product.

The products and chemicals included on this list were compiled from the Tier II reports sent to the state of Montana for the years 2005, 2006, and 2007. Tier II reports are required by the Emergency Planning and Right to Know Act to help local communities protect public health, safety, and the environment from chemical hazards. However, the oil and gas industry is exempt from this requirement. In return for this exemption industry files voluntary Tier II reports that are often "boilerplate" and do not contain all the chemicals used on a particular site.

The information contained in Tier II reports varies from state to state, and, in the case of the Montana Tier IIs, from company to company. Some companies listed all the chemicals in the products stored, though many of the ingredients were cited as proprietary, while other companies only provided a general statement of what was stored on a site, such as "surfactants" or "corrosion inhibitors." Because of the lack of specific information in many reports, the data in this analysis is likely an underestimation of what is actually in use and storage in the state of Montana.

Only 20% of the information about the composition of the products on the list comes from a Material Safety Data Sheet (MSDS). Ingredients on MSDSs are sometimes labeled as "proprietary" or "no hazardous ingredients" even when there are significant health effects listed on the MSDS. This was the case for three of the 21 MSDSs.

Some of the citations used to establish the health effects of the chemicals on this list are old, dating back to the 1970's and 80's. In several cases data were derived from abstracts, not the full report or manuscript. In other cases, citations were taken from toxic chemical databases, such as TOXNET, Chem ID, etc. Many reports submitted to the US Environmental Protection Agency by the manufacturer to register a chemical are not accessible. In some cases it is impossible to track down any health effect for a chemical, especially when the manufacturer provides no Chemical Abstracts Service (CAS) number.

No health effects were found for nine of the chemicals on the list. Of these, only 4 had been assigned a CAS number which facilitates searching the literature. We found no health related literature for these chemicals. It was impossible to determine the safety of the other 5 chemicals either because they were listed as proprietary, or "various," or no chemical was identified (4), or had chemical names that were so general that the specific chemical could not be identified (1).

Download the most recent TEDX report on chemicals from oil and gas in Montana.

Go to the TEDX website for more information.

TEDX Analysis of Oil and Gas Chemicals in Wyoming

This analysis was designed to explore the health effects of the products and chemicals used in drilling a natural gas well, Crosby 25-3, northwest of Clark, Park County, Wyoming. This well was directionally drilled with a total vertical depth of 8,038 feet. Natural gas, petroleum condensate, and drilling fluids were accidentally released from the ground adjacent to the well. The release occurred over a period of about 58 hours between 11 and 13 August 2006 and resulted in surface soil impacts in an area estimated to cover approximately 25,000 square feet.

This analysis provides a glimpse at the pattern(s) of possible health hazards for those living in the region. TEDX was able to do this analysis because we were provided the Materials Safety Data Sheets (MSDS) for the products in use at the time of the blowout, and through information provided in the Terracon Remedial Investigation Work Plan Final Draft, dated July 2, 2007, or information disclosed in the Terracon Remedial Investigation Work Plan Amended Draft, dated September 14, 2007. TEDX makes no claim that this list of products is complete.

Health Effects
TEDX found adverse health effects for all the chemicals on this list. This is true even though MSDSs for five of the products stated that they contained no hazardous substances. All of the MSDSs for these products contained information that the ingredients were eye or skin irritants or toxicants, 80% were respiratory toxicants, 40% were dangerous to wildlife, and one was a gastrointestinal toxicant.

In general, the volatile chemicals have more adverse health effects associated with them than the soluble chemicals. Not only are they more toxic, but in the area of skin and sensory organ toxicity, gastrointestinal and liver, and the respiratory system toxicity, 100% of them cause harm.

The soluble chemicals are associated with more adverse health effects than the total number of chemicals. While they do not show as high a percentage of effects as the volatile chemicals, between 80% and 100% can cause harm to the same systems as listed above.

Prior to use, these products must be shipped to and stored somewhere before being transported to the well site. They pose a hazard on our highways, roads, and rail systems, as well as to people living and working near the storage facilities.

Full Disclosure
While this list was compiled primarily from MSDS information, it is still far from a complete picture of what is in use. The limitations of MSDS data are outlined above. Also, this list provides only a hint of the combinations and permutations of mixtures possible and the possible aggregate exposure. Each drilling and fracturing incident is custom designed depending on the geology, depth, and resource available. The chemicals and products used, and the amounts or volumes used can differ from well to well. The only way to get a realistic picture of what is being introduced into
our watersheds and air is for a complete record of information of the specific well site (state, county, township, section, etc.), the formulation of chemicals and products used at each stage, the quantity of each product (weight and/or volume), total volume injected and recovered, and the depths at which material/mixtures were injected and recovered, the composition of the recovered liquids and those liquids and solids removed from site. This needs to be public information. From the data in this list, we know for certain that a great deal more than water and soap is being used to drill a natural gas well.

Download a copy of the TEDX report on chemicals from oil and gas in Wyoming.

Go to the TEDX website for more information.

• How pit pollution occurs
• Soil and water contamination from pits
• Wildlife and livestock mortality related to pits
• Toxic materials stored and disposed of in pits

Visit our Alternatives to Pits web page, to find out how the oil and gas industry can reduce the environmental impacts and hazards posed by oil and gas pits.

How pit pollution occurs

Pits are used to store a variety potentially toxic, as well as non-hazardous liquid and solid wastes associated with oil and gas development.

Solid wastes may contain toxic substances. If left on site they may:

• Leach out of the solids and contaminate groundwater
• Contaminate soils and vegetation
• Sterilize soils and prevent vegetative growth

Liquid wastes may contain toxic substances that can:

• Overflow the sides of the pit (e.g., during a rain event, or due to inadequate storage volume of the pit) and pollute soil and surface waters
• Leach directly into the ground (if stored in unlined pits) and contaminate soil and water.
• Seep into the ground (even if the pits are lined) through tears in liners, allowing substances to leak through to the soil and groundwater. Even if pits are lined, the liners are often improperly installed, or are torn, and frequently leak

Soil and water contamination from pits

Between the mid-1980s and 2003, the New Mexico Environmental Bureau recorded 6,700 cases of pits causing soil and water contamination in that state.[1] In 2005, the New Mexico Oil Conservation Division released data showing that close to 400 incidents of groundwater contamination had been documented from oil and gas pits. Find out more about groundwater contamination from oil and gas industry pits in New Mexico.

The City of Lovington, New Mexico, has experienced soil pollution from oil spills and pits. In recognition of the contamination threats posed by oil and gas drilling wastes, and in an effort to protect its municipal water supply, Lovington recently banned the use of drilling pits on the city's water field. For more information on Lovington, read the OGAP report Pit Pollution.

Soil contamination from pit pollution can inhibit the health and growth of vegetation on-site, which may lead to soil instability and erosion. Also, vegetation may uptake the contaminants and cause health problems for animals that eat the contaminated plants.

Similarly, if the contaminants enter surface or groundwater, organisms (humans, livestock, wildlife, aquatic life, micro-organisms) drinking or living in the water may experience negative health effects or death, depending on the level of contamination.

Between 1996 and 2002, the U.S. Environmental Protection Agency (EPA) in Wyoming, Utah, Colorado, Montana, South Dakota and North Dakota conducted 475 field inspections at sites having one or more production pits or commercial facilities using disposal pits. (Download the EPA report.) Problems were found at 290 (more than 60%) of the sites. Issues of concern included:

• Ongoing discharges to surface and groundwater were documented at 22 % of the sites inspected, and those discharges were unpermitted at 35 of those sites (34% of the sites with ongoing discharges observed).
• Leaks and spills were observed from equipment. · Secondary containment for oil storage tanks was inadequate or non-existent at many sites.
• Pits were improperly designed, located, and operated (including exposed oil on pits)
• Half of the pits observed were either entirely or partially covered in oil. In EPA's view, the number of sites with exposed oil on pits and bird mortality was higher than expected given that advance notice of inspections was provided to site operators.
• There were a number of bird and wildlife deaths related to the pits (142 birds, 42 wildlife).
• There were ineffective or non-existent wildlife exclusion devices at the sites.

One key finding of the EPA report was that almost every commercial facility evaluated had significant environmental issues. Commercial oilfield waste disposal facilities are facilities that receive produced water and other exploration and production wastes for treatment and disposal. Pits, also known as surface impoundments or ponds, are used to holds wastes so that the liquids will evaporate off of the solid waste materials.

Wildlife and Livestock Mortality Related to Pits

In the report Wildlife Mortality Risk in Oil Field Waste Pits(download the pdf version of the report), the U.S. Fish and Wildlife Service (FWS) has documented numerous problems related to contaminants in oil field waste pits. In Wyoming, the U.S. Fish and Wildlife Service has found deer, pronghorn, waterfowl, songbirds and rabbits in oil pits. Even if animals are not killed in the pits, the oil and chemicals in the pits may affect their health. For example, if animals absorb or ingest oil, they may become more susceptible to disease and predation. The U.S. FWS web site contains information on Contaminant Issues - Oil Field Waste Pits. This web site lists numerous wildlife-related problems associated with oil and gas pits, such as:

• Skim ponds are a fatal attraction to migratory birds
• Birds, bats and other wildlife mistake pits for wetlands
• Birds landing on waste pits can get covered with oil
• Oil can weigh birds down and cause them to drown Many bird deaths go undetected because the carcasses sink to the bottom of the pits
• Oil destroys the feathers' ability to insulate the birds resulting in death from heat or cold stress
• Even a light sheen on the water surface can be deadly. Oil on the feathers of female birds can be transferred to their eggs back at the nest, killing the embryo. Small amounts of oil applied externally to an egg shell can be extremely toxic to embryos
• Some birds become victims of pits when they feed on insects trapped in oil covering the surface of the water
• Animals scavenging on dead birds at these pits often succumb to the toxic effects of oil

Examples of wildlife and livestock deaths from pits:

Chris Velasquez, Rancher - Blanco, New Mexico. "I have complained repeatedly to BLM [Bureau of Land Management] about a shallow pit filled with "black gunk" near a gas well operated by Williams. The pit was on my grazing lease and I found cattle tracks to the pit and feared animals might be drinking the oily water. I've found dead cows near oil pits before, and seen lots of dead birds and other wildlife floating in the oil pits so I was worried this cow would drink out of the pit and die too. I lose eight to ten cows each year because of the oil field activity." (San Juan Citizens Alliance and New Mexico Wilderness Alliance A High Price to Pay: Consequences of oil and gas production.)

Eliminating Oilfield Hazards. "Service special agents continued to conduct oilfield task force operations throughout historic petroleum production areas in New Mexico, Oklahoma and Texas. In New Mexico, special agents conducted ground inspections of oil pits in Sandoval, Rio Arriba, and San Juan Counties in April 2001. Netting violations detected at eight production sites were referred to the New Mexico Oil Conservation Division for State follow-up. In August, oil field inspections in the southeastern part of the State documented multiple hazards and recovered 17 oil-covered birds; seven operators paid $6,425 in fines for violating the Migratory Bird Treaty Act. Dead birds were also discovered at several sites on Bureau of Land Management property in the State; the companies holding the oil leases paid over $8,000 in fines. (U.S. Fish and Wildlife Service, Division of Law Enforcement, Annual Report 2001. Download a copy of the report.)

Regional Task Force Continues to Address Open Oil Field Pits and Tanks. "Service Special Agents throughout the region continued to investigate oil field pollution impacting migratory birds and other wildlife on historic oil fields in Oklahoma, Texas , and New Mexico. Three task force inspection operations were recently culminated following joint inspections of problematic well sites "Oil" and "G" initially documented by aerial surveillance. The Central Oklahoma operation resulted in the recovery of 32 oil covered migratory songbird and raptor carcasses from open pits or tanks operated by seven oil companies and the assessment of collateral fines totaling $11,900." (The Federal Wildlife Officer Association Inc. The Federal Wildlife Officer, Vol. 15, Spring 2002)

Is it possible to keep wildlife out of pits?

Measures to protect wildlife and livestock from toxic substances in pits include:

• systems to prevent oil from entering waste pits;
• immediately cleaning up any oil spills that find their way in open pits;
• adequate fencing around waste pits;
• netting to keep birds from entering pits.

Unfortunately, the devices used to keep out livestock and wildlife out of pits are often inadequate. For example, if netting is not installed properly or maintained well enough (e.g., if there are tears in the netting or if it sags into the waste pit, which is common after it snows), birds are still able to access the pits.

Nets should be installed four or five feet above the pits to allow for sagging. Similarly, fencing can be used, but often, wildlife and livestock can still access pit areas.

Toxic Materials Stored and Disposed of in Pits

There are a variety of toxic substances utilized and created during the oil and gas extraction process. These include:

• Drilling fluids and wastes (Coming soon)
• Production chemicals and wastes (Coming soon)
• Produced water (Coming soon)

Potentially hazardous oil and gas wastes that may be found in pits.

• Drilling
• Hydraulic Fracturing
• Waste Pits
• Spills
• Releases to Air

THE DRILLING PROCESS

Drilling involves the use of muds to keep the drill bit cool and lift the rock cuttings out of the well bore. Muds may be water-based, oil-based or synthetic. They typically contain bentonite clay (or a synthetic polymer substitute), as well as other chemical additives that alter the mud properties (thickness, weight, bacteria proliferation, etc.).

Releases of drilling muds and additives to the environment can occur at the well site (spills, leaks from drilling reserve and waste pits/tanks), or mud injected underground can move through formations and contaminate surface or groundwaters.

• Read about how PRESCO drilled a well and had the mud come to the surface in a spring 1/4 mile away.

HYDRAULIC FRACTURING

Hydraulic fracturing 'fracking' is a method of stimulating oil and gas wells. Typically, it involves pumping hundreds of thousands of gallons of fluids and sand into the oil or gas formation. At a certain point, the formation will crack open. Studies have found that anywhere between 25 and 82% of the fluids will return to the surface, but some chemicals are preferentially trapped in the formation. At the surface, the flowback fluids are held in pits or tanks prior to disposal. The sand is left in the formation to hold open the fractures, thus creating larger pathways for the hydrocarbons to flow to the well.

According to data from the Environmental Protection Agency, fracking fluids may contain a number of chemicals that are hazardous to human health.

There are numerous potential pathways for contamination of water and air by fracking fluids.

1. The most direct connection is if fracking fluids are injected directly into rock formations that also serve as freshwater aquifers and underground sources of drinking water. According to EPA, there are coalbed methane formations that undergo hydraulic fracturing, but also serve as freshwater aquifers.
2. Fracking chemicals have the potential to migrate, as liquids or gases, from leaky wellbores into adjacent groundwater aquifers. There is the possibility for migration may occur, as well, through vertical and horizontal fractures into groundwater or even to surface water.
3. Even if the fracking chemicals, themselves, do not migrate into groundwater, the hydraulic fracturing operation may change the underground geology in such a way that new pathways are formed that allow hydrocarbons such as methane, and benzene, to migrate away from their original location. Fracturing, which causes mini-seismic events under ground, may also introduce more sediment into groundwater aquifers, changing the water quality temporarily, or possibly permanently.
4. A final pathway for contamination is if fracking fluids are spilled onto the ground or into waterways. Spills may be of unused fracking chemicals, or used fracking fluids that flow back out of the well after it has been hydraulically fractures. Any volatile compounds in spilled fracking fluids may enter the air and be carried downwind.
   • Read about how the Amos family's water well was contaminated after hydraulic fracturing occurred near their home.
   • Read about a KERR McGEE fracking fluid spill that contaminated surface soils and entered an irrigation ditch.

WASTE PITS AND TANKS

A significant portion of the chemicals injected underground during drilling, hydraulic fracturing or well maintenance return to the surface, where they are stored, at least temporarily, in open pits or tanks. Produced water may also be stored in pits or tanks prior to permanent disposal (e.g., injection into a deep aquifer; discharge to streams). In some cases, produced water is left in open pits to evaporate.

According to an Argonne National Laboratory white paper, produced water contains many organic and inorganic compounds that can lead to toxicity. Naturally occurring contaminants include salts, which can be toxic to plants at high concentrations; hydrocarbons from the oil- or gas-bearing formations; metals, which may be naturally present in the deep groundwater; and naturally occurring radioactive materials (NORM).

A variety of treatment chemicals and additives may be present in produced water. Some of these chemicals can be lethal at levels as low as 0.1 parts per million.

• The treatment chemicals used for gas processing typically include dehydration chemicals, hydrogen sulfide-removal chemicals, and chemicals to inhibit hydrates. Well-stimulation chemicals that may be found in produced water from gas operations can include mineral acids, dense brines, and additives.
• For oil production, treatment chemicals are typically complex mixtures of various molecular compounds. These mixtures can include: corrosion inhibitors and oxygen scavengers to reduce equipment corrosion; scale inhibitors to limit mineral scale deposits; biocides to mitigate bacterial fouling; emulsion breakers and clarifiers to break water-in-oil emulsions and reverse breakers to break oil-in-water emulsions; coagulants, flocculants, and clarifiers to remove solids; and solvents to reduce paraffin deposits.

In Colorado, not all pits are lined, presenting the potential for liquid wastes to seep into soil and groundwater. Both lined pits and steel tanks may also cause contamination through leaks and overflow. Find out more about pits.

Another pathway for exposure to chemicals from waste pits is through volatilization of chemicals sitting in the pits. For example, benzene and other volatile (light) hydrocarbons that are dissolved in liquids will enter the air when the liquid is exposed to the atmosphere.

• Read about how fluids from MARALEX's drilling pit seeped through the earth and contaminated a landowner's drinking water well.

SPILLS

Spills and leaks of raw chemicals or oil and gas wastes may affect land, water and air. In Colorado, the Colorado Oil and Gas Conservation Commission (COGCC) requires companies to report spills of fluids related to any unauthorized release of exploration and production (E&P) wastes that are 5 barrels or more in volume. In some cases, smaller spills are reported, e.g., if the spill enters surface or groundwater.

In the four-year period between June 2002 and June 2006, there were approximately 924 spills of oil and gas chemicals and wastes. Spilled products included: crude oil, condensate, produced water, and "other" products. The other products included diesel fuel, glycol, amine, lubricating oil, hydraulic fracturing fluids, drilling muds, other chemicals, and natural gas leaks.

Roughly estimated, 60% of the spills involved produced water; 34 % involved crude oil or condensate; and 12% involved spills of "other" substances. (Numbers add up to greater than 100% because some of the spills involved more than one type of fluid).

Colorado oil and gas spills affecting water (click here for a larger version of the chart)

Of the 924 oil and gas industry spills, 20% of them contaminated water: 14% of the spills affected groundwater; and 6% of all spills affected surface water.

As the chart shows, a large percentage of spills recorded by the COGCC do find their way into groundwater or surface water.

While some of the spills are accidents, acts of nature (e.g., lightning strikes) there are many spills that are preventable. For example, during the four-year period, Chevron had 57 incidents of produced water and two crude oil leaks caused by corroded pipes or fittings. It is likely that proper maintenance, pipeline integrity testing, and replacement of old equipment could have prevented many of these spills.

Download an OGAP report on Colorado Oil and Gas Industry Spills (June 2002 - June 2006). We are continuining to analyse the COGCC's spill data, so the spills report will be updated from time to time.

TOXIC AIR RELEASES

Venting and fugitive gas emissions
The primary component of natural gas is methane, which is odorless when it comes out of the gas well. At gas processing facilities, chemical odorants such as mercaptans are added to methane, so that consumers are able to smell it in the event of a gas leak. People living next to natural gas wells, however, will not smell any methane released to the atmosphere through venting or fugitive emissions (leaks).

In addition to methane, natural gas typically contains other hydrocarbons such as ethane, propane, butane, and pentanes. Raw natural gas may also contain water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds.

Almost all references to the odor of raw or wellhead natural gas state that it, like methane, is odorless. The Ohio Department of Natural Resources, however, advises landowners that one way to detect an abandoned oil or gas well on their property is if they smell "natural gas" odors coming from their tap water. So, in some cases, there may be a slight hydrocarbon odor associated with venting of natural gas.

If the concentration of H2S in the gas is high enough, there may also be a "rotten egg" odor associated with the gas.

Condensate fumes
Some natural gas wells produce a semi-liquid condensate along with the gas. Condensates are hydrocarbons that are in a gaseous state within the reservoir (prior to production), but become liquid during the production process. Condensates are composed of hydrocarbons (typically those containing five or more carbon molecules), as well as aromatic hydrocarbons such as benzene, toluene, xylenes and ethylbenzene (BTEX).

Condensates may give off a characteristic hydrocarbon or petroleum-type smell. BTEX give off a sweet, aromatic odor. Most people can smell benzene when it reaches levels of approximately 1.5 - 5 parts of benzene per million parts of air (ppm). The Occupational Safety and Health Administration (OSHA) has set maximum exposure levels for workers at 1 ppm (over an 8-hour period) and 5 ppm (over a 15-minute period). At levels above 150 ppm some people may begin to experience serious and irreversible health effects.

The vapors of benzene, toluene and xylenes are heavier than air and may accumulate in low-lying areas.

Odors from waste pits
Prior to disposal, drilling wastes (muds and cements), hydraulic fracturing (fracking) fluids and produced water are often stored in earthen or metal pits that are open to the air. There are hundreds of different chemicals that may be used during drilling, fracking and workover procedures, including acids, biocides, surfactants, solvents, lubricants and others. The odors associated with the chemicals will vary, depending on the concentrations, volumes, and combinations of chemicals used.

By-products from flaring
The by-products from burning natural gas vary depending on the composition of the gas and/or condensate being burned. There may also be additional by-products formed if some of the chemicals used during the drilling or hydraulic fracturing process are converted to a gaseous form and are burned along with the natural gas.

It is difficult to find information on the by-products of flaring specific to Colorado. The Ventura County Air Pollution Control District, in California, however, has estimated that the following air pollutants may be released from natural gas flares: benzene, formaldehyde, polycyclic aromatic hydrocarbons (PAHs, including naphthalene), acetaldehyde, acrolein, propylene, toluene, xylenes, ethyl benzene and hexane.

Glycol Dehydrator emissions
If the gas wells use glycol dehydrators to remove water from the gas, you may be smelling some aromatic organic chemicals. Regeneration of the glycol solutions used for dehydrating natural gas can release significant quantities of benzene, toluene, ethylbenzene, and xylene, as well as a wide range of less toxic organics. As mentioned above, BTEX have a sweet chemical odor.

Diesel fumes
Drilling, completion and workover trucks, rigs and equipment such as pumps typically run off of diesel-powered or gasoline engines. The exhaust fumes from gasoline and diesel fuels can produce emissions that are noticeable to people living downwind.

Polycyclic aromatic hydrocarbons (PAHs) are found in exhaust from motor vehicles and other gasoline and diesel engines. A long list of other air pollutants, including BTEX, formaldehyde and metals are also contained in diesel fuel combustion products.

In 2004, Phil Rae, a manager with BJ Services, presented a lecture to the Society of Petroleum Engineers, entitled "Eliminating Environmental Risks in Well Construction and Workovers." In addition to downloading a pdf version of Rae's slides, you can view a webcast of the presentation.

The key points from Rae's presentations included the following:

• more than 2,500 chemicals are being used by the oil and gas industry today.
  
• the chemicals being used have a wide diversity of toxicities and biodegradability
  
• Some of the "serious potential bad guys" found in stimulation (e.g., hydraulic fracturing) chemicals, include acids, corrosion inhibitors, surfactants, biocides, organo-metallic crosslinkers and solvents.
  
• Some oilfield chemicals are known to be endocrine disruptors. They can trigger biological changes at very, very low concentrations, and as a result, they've been implicated in health problems such as cancer and genetic mutations. According to Rae, "There are several of these materials around in our industry: the so-called NPEs - nonylphenyl-ethoxylates. . . , polycyclic aromatics; and phthalates." Rae adds that "nonylphenol ethoxylates have been banned from our industry for quite some time now. In those areas where there is an active environmental protection program we no longer use nonylphenols."
  
• The United States is lagging behind Europe and even some newly industrializing countries when it comes to phasing out harmful oilfield chemicals. Rae states that between 60 and 65% of chemicals in use in the UK are "OK" but it would be simple to raise this figure to 90% because the technology to achieve this already exists. Norway, Denmark and Holland lead the field when it comes to utilizing 'green' technologies in construction, workover and stimulation. "The UK is dragging it's heels but semi-compliant," according to Rae, and the "US - still behind the curve, unfortunately."

Citizens commonly report that drilling and production activities contaminate water wells, surface waters and soils surrounding well sites; and that air emissions from drilling sites, well heads, compressor stations, pipelines and other oil and gas field infrastructure contribute to air quality concerns.

Water Pollution

• Hydraulic fracturing is a practice that may involve the injection of known toxic chemicals into or close to drinking water supplies.
• Storm water runoff during construction or runoff from established well pads can introduce sediment and toxic chemicals into nearby rivers and streams
• Storage and disposal of drilling and production wastes in pits can contaminate groundwater and surface waters

Air Pollution

• A variety of air contaminants are emitted throughout the oil and gas development process. If you think oil and gas production does not affect air quality, THINK AGAIN.

Soil Pollution

• Oil and gas industry wastes, which may contain petroleum hydrocarbons, metals, naturally occurring radioactive materials, salts and toxic chemicals, have the potential to cause soil pollution, and prevent the growth of vegetation.
• Produced water, which may contain high concentrations of salts and other contamiants, is often stored in pits or disposed of in evaporation ponds. Spills of produced water can kill vegetation and sterilize soils.
• Contaminants that enter the soil do not necessarily stay put. They can move down through the soil and contaminate groundwater, or up through the soil and be released to air. Learn about the subsurface transport of oilfield wastes.

• SRHA allows ranchers to homestead (i.e. privatize) lands originally deemed of no value except for livestock grazing and the growing of forage.
• SRHA homesteaders own surface rights to the land, but federal government retains the mineral rights underneath.
• Over 70 million acres of public lands were privatized under SRHA, including 2,986,746 acres in Arizona alone.
• Much of these 70 million acres has since been developed for home sites and subdivided and sold as smaller parcels -- something SRHA never intended.

The 1872 Mining Law -- the Surface Owner's Enemy

Since the Federal Government retains the mineral rights under this act, the 1872 Mining Law applies to these minerals. This means:

• SRHA lands are open to mineral entry even though the surface land is private. As a result, anyone has the right to enter these lands, search for minerals, file a mining claim, and then file a plan of operations to mine.
• Although SRHA was amended in 1993 to require notification of the surface owner before their land is entered, the landowner has no right to prevent entry or stop mining from taking place on the property.
• The Bureau of Land Management (BLM) is charged with administering mining on these lands.

Notification and Entry Requirements

Those intending to file a mining claim are required by law to provide the surface owner notice (referred to as a Notice of Intent to Locate, or NOITL) before they can enter SRHA lands.

Once notice has been given:

• No one -- including the surface owner -- may conduct mineral activities except the person who filed notice.
• The claimant must wait 30 days after a NOITL has been submitted before entering SRHA land.
• While the surface owner is allowed to request that their lands be entered at a convenient time, they may not prevent entry.
• The claimant has a further 60 days to explore and stake mining claims.

Plan of Operation and Bonding

After a mining claim is staked, the mining claimant cannot conduct mineral activities (other than non-surface disturbing activities) without

• written consent from the surface owner,
• or an approved plan of operations from the BLM.

If the claimant submits a plan of operations, the BLM has 60 days to approve the plan, but can get an extension of an unspecified amount of time to comply with other applicable laws.

The claimant must file a reclamation bond to cover tangible losses during operations and/or permanent losses if the land is not returned to pre-mining agricultural production levels. The BLM decides the amount and conditions of the bond. The surface owner cannot be reimbursed for loss of property values as a result of mining claims or operations. During the time that operations take place, the surface owner receives an annual rental payment based on fair market rental conditions for agricultural land.

Landfills and Landfarms

NEW MEXICO STRENGTHENS RULES TO REDUCE CONTAMINATION FROM OIL AND GAS INDUSTRY WASTES

On October 19, 2006, after more than a year of stakeholder meetings, hearings and political pressure, the New Mexico Oil Conservation Commission (OCC) adopted revisions to the state's surface waste facility rules for oil and gas wastes. The industry spent $500,000 in attorney time and hired experts to try to weaken, delay, and ultimately, attempt to eradicate the rules politically. The Oil Conservation Division, New Mexico Citizens for Clean Air and Water (primarily Don Neeper), Controlled Recovery, Inc. (a landfarm operator) and OGAP pushed back to get the rules strengthened and adopted.

Download the OCC hearing summary (R-12460b) and the revised surface waste facility rules.

The new rules set out four types of surface waste management facilities, with rules for each type:

• Landfills: "permanent" disposal site for oilfield wastes that are either non-hazardous or exempt from Subtitle C of the federal Resource Conservation and Recovery Act.
• Centralized facilities: a site operated by an oil and gas operator or its affiliate to manage wastes resulting from its own operations.
• Commercial landfarms: waste treatment sites, e.g., to bioremediate hydrocarbons
• Small landfarms: short-term sites (up to three years), where small quantities of soils contaminated with hydrocarbons are treated.

A number of provisions in the New Mexico rules were strengthened. These include rules pertaining to:

• Notice
• Bonding
• Permit Denial
• Facility Location
• Operational Issues
• Closure Standands

NOTICE: The rule contains improved citizen notice provisions, including surface owners within 1/2 mile, counties, municipalities and tribal lands within 1/2 mile, and any citizen requesting notice.

BONDING: The bond amount is set as the estimated actual costs of closure.

PERMIT DENIAL: A permit may be denied if it may be detrimental to freshwater, public health, safety or the environment. It also may be denied if the applicant is a "bad actor," i.e., has a history of violations of permit conditions, etc.

FACILITY LOCATION:

• No landfill may be located where groundwater is within 100 feet.
• No landfarm may be located where groundwater is within 50 feet.
• No small landfarm may be located where groundwater is within 50 feet.
• None of the facilities may be located within 200 feet of a watercourse, 500 feet of a wetland or 500 feet of a residence, school, etc.
• Only one small landfarm is allowed per section, and it must be within 1 mile of an oil or gas well/facility.

OPERATIONAL ISSUES:

• All tanks 8 feet in diameter or larger must be netted or screened.
• There are specific monitoring requirements for detection of leaks.

CLOSURE STANDARDS: Landfarms and small landfarms have specific numeric closure standards for total petroleum hydrocarbons and chlorides (500 ppm). If the operator cannot meet the closure standards, the contaminated soil must be moved to a landfill.

***Update***

The OCC Wins on Appeal!

The Oil Conservation Commission won an appeal in First Judicial District Court, County of Santa Fe, State of New Mexico against sixteen oil and gas companies that challenged the adoption of revised rules regulating surface waste management in oil and gas operations. "Based on this Court's analysis of the whole record and of Appellants' arguments, the Oil Conservation Commission's Order No. R-12460-B in Case No. 13586, repealing existing rules and adopting new rules governing surface waste management in oil and gas operations, is supported by substantial evidence in the record, is not arbitrary and capricious, and is in accordance with the law and within the scope of the Oil Conservation Commission's authority," stated Daniel A. Sanchez, District Judge, Division VII in his February 26, 2008, decision.[1]

Pits

NEW MEXICO TO CONSIDER REVISIONS TO RULES GOVERNING OIL AND GAS WASTE PITS

A process was initiated in 2006 to revise New Mexico Oil Conservation Commission Rules related to oil- and gas-field pits. The state will be releasing the new and improved pit rule in April 2008. Click here for updates on the New Mexico Pit Rule.

The New Mexico Oil Conservation Division has detected and documented more than 700 hundred incidents of groundwater contamination from oil and gas facilities across the state. The data can be downloaded from the OCD web site (click here to download a pdf version or an Excel spreadsheet version).

NEWS

NEW MEXICO STRENGTHENS RULES TO REDUCE CONTAMINATION FROM OIL AND GAS INDUSTRY WASTES

On October 19, 2006, after more than a year of stakeholder meetings, hearings and political pressure, the New Mexico Oil Conservation Commission (OCC) adopted revisions to the state's surface waste facility rules for oil and gas wastes. The industry spent $500,000 in attorney time and hired experts to try to weaken, delay, and ultimately, attempt to kill the rules politically. The Oil Conservation Division, NM Citizens for Clean Air and Water (primarily Don Neeper), Controlled Recovery, Inc. (a landfarm operator) and OGAP pushed back to get the rules strengthened and adopted. Find out more about the new New Mexico Surface Waste Facility rules.

NEW MEXICO TO CONSIDER REVISIONS TO RULES GOVERNING OIL AND GAS WASTE PITS

A process was initiated in 2006 to revise New Mexico Oil Conservation Commission Rules related to oil- and gas-field pits. The state had hoped to have hearings on the proposed pit rule in the fall of 2006. It is now likely that the pit rule will not be heard until the summer of 2007. Click here for updates on the New Mexico Pit Rule.

REGULATION OF OIL AND GAS WASTES

The disposal of wastes from oil and gas activities are subject to federal and state regulation.

Federal Regulations

In 1980, Congress conditionally exempted oil and gas exploration and production (E&P) wastes from the hazardous waste management requirements of Subtitle C of the Resource Conservation and Recovery Act. This exemption was granted despite the fact that toxic substances are contained in many oil and gas industry wastes, and despite the countless examples of groundwater, surface water, air and soil contamination related to oil and gas waste disposal activities.

In 1988, the EPA published lengthy lists of wastes determined to be either exempt or non-exempt. Examples of exempt wastes include drilling fluids and cuttings, produced water and pit sludge; while non-exempt wastes include unused chemicals as well as used lubricants and hydraulic fluids.

Lists of exempt and non-exempt wastes can be found in the EPA publication Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations. Included in this publication is the admission by EPA that:

In general, the exempt status of an E&P waste depends on how the material was used or generated as waste, not necessarily whether the material is hazardous or toxic. For example, some exempt E&P wastes might be harmful to human health and the environment, and many non-exempt wastes might not be as harmful.

There are three main federal agencies that have some jurisdication over certain aspects of oil and gas waste disposal operations.

• Environmental Protection Agency (EPA) oversees the Resource Conservation and Recovery Act; Clean Water Act; and Safe Drinking Water Act. Provisions in these acts apply to oil and gas waste disposal. Find out more about these regulations.
• Bureau of Land Management (BLM)'s regulations governing onshore oil and gas operationsinclude requirements for oil and gas activities on federal lands to submit information on methods for containment and disposal of waste material. Find out more about BLM regulations.
• Minerals Management Service (MMS) is the federal agency that regulates offshore oil and gas development, including various waste disposal options. Find out more about MMS regulations.

State Regulations

The construction, operation and closure of oil and gas waste disposal operations are regulated at the state level. These regulations vary widely from state to state. For more detailed information on a state-by-state basis, visit the Argonne National Laboratory's Drilling Waste Management Information System Web Site.

WASTE DISPOSAL AND TREATMENT OPTIONS

When soils become contaminated with spilled chemicals, hydrocarbons and other waste materials there are several methods of disposing or treating these wastes. The main disposal method is through burial, either on or off site. Treatment occurs via bioremediation (using micoorganisms to convert toxic compounds into less toxic forms); or thermal technologies (using high temperatures to reclaim or destroy hydrocarbon-contaminated material).

The following types of waste disposal and treatment sites are utilized for oil and gas wastes:

• Pits
• Landfills
• Landfarms
• Land Spreading
• Thermal Technologies
• Undergound (Slurry) Injection
• Salt Caverns

Pits

The types of oil- and gas-field wastes dumped into pits include: drilling wastes; produced water; and production fluids and wastes. Many of these fluids are poisonous to living organisms.

Lined pits for disposal and storage are sometimes used, but mud, drill cuttings and other materials are frequently discharged into unlined pits,allowing potentially toxic substances to seep into the ground. If improperly fenced, these pits can be a hazard for livestock and wildlife. While it is common for oil and gas companies to drain off fluids from drilling mud pits, it is very common for companies to simply bury the remaining solids in place or spread them on the lease site.

When discharged into unlined pits the toxic substances in pits can leach directly into the soil and may contaminate groundwater. Lined pits can also lead to pollution via ruptures in liners or by overflowing the pit area. These events can result in soil and water contamination, which can have a negative effect on both human and ecosystem health. Read about groundwater contamination from pits in New Mexico.

Landfills

Landfills are engineered earthen impoundments used for the permanent disposal of various types of wastes (e.g., municipal, hazardous, and industrial). Drilling wastes and other oil field wastes are disposed of in landfills that are permitted to accept oilfield wastes. An operator that has a large number of wellsites in an are may open and operate its own private landfill to dispose of its wastes. In other cases, commercial operations receive wastes from multiple operators. In other cases, oil companies with a large amount of drilling activity in an area may construct and operate private landfills.

In order to conmay be lined with clay or synthetic liners, and systems established to capture fluids that leach from the wastes. Airborne wastes (e.g., particulate matter and dust from the contaminates soils) may be controled using dust suppressants, or by covering wastes with a layer of clean soil or other inert material.

Landfarms

Landfarms are not permanent waste disposal sites. Rather, they are sites designed to reduce the concentration of The oil and gas industry uses land farming to treat oily (hydrocarbon-rich) wastes. Land farming is the controlled and repeated application of wastes to the soil surface. Naturally occurring or introduced microorganisms in the soil break down the hydrocarbons.

Metals and salts are not broken down by the microorganisms, but some metals may be assimilated into the tissues of microorganisms, which can reduce the mobility of metals through the soil. If the concentrations of metals or salts are too high in the wastes, microbial activity may be inhibited, thus reducing the breakdown of hydrocarbons.

Bioremediation of hydrocarbons may be accomplished using a variety of tillage and composting techniques. In all cases, the breakdown of hydrocarbons is maximized by providing the prime conditions for microbial activity, which requires a proper balance of moisture, and nutrients, as well as soil oxygen (Read the Argonne National Laboratory's Fact Sheet on Bioremediation). Thus, it is often necessary to add water, nutrients and additional soil, and aerate the soil to enhance biodegradation of hydrocarbons. During periods of extended dry conditions, moisture control may also be needed to minimize dust. Application rates of water should be monitored and controlled to minimize the potential for runoff or leaching of contaminants.

Land Spreading

Land spreading is typically a one-time application of wastes to an area of land. Wastes are spread on the land and incorporated into the upper soil zone (typically upper 6-8 inches of soil) to enhance hydrocarbon volatization and biodegradation. It is important that other constituents, such as metals, salts, acids not be present at levels that will sterilize or permanently impair the soil system.

Thermal Technologies

Thermal technologies utilize high temperatures to destroy or remove hydrocarbons from waste materials. Depending on the final fate of the wastes, additional treatment may be needed to remove metals and salts. Thermal treatment technology generally occurs at a permanent or fixed facility, but some efforts are under way to develop mobile thermal treatment units.

There are two main types of thermal technologies:

• Incineration (e.g., rotary or cement kilns) destroys hydrocarbons by heating them to very high temperatures in the presence of air.
• Thermal desorption (e.g., indirect rotary kilns, thermal phase separation, thermal distillation) involves the application of heat to the wastes, to vaporize volatile and semivolatile hydrocarbons. These gases may be combusted to reduce the emission of toxic components, or condensed and separated to recover heavier hydrocarbons.

Underground (Slurry) Injection

In order to inject oil and gas field wastes underground, solids are typically ground into small particles and mixed with water or another liquid to make a slurry. It is this slurry that is injected into underground formations (sometimes at pressures high enough to fracture the rock so that wastes can enter the formation; sometimes at lower pressures, e.g., when an underground formation has ample natural fractures).

There are two methods of injection:

Annular Injection, where wastes are pumped into the space between two casing strings on an oil or gas well (known as the annulus). At the lower end of the outermost casing string, the slurry enters the formation. Typically, wells utilizing annular injection only inject wastes from a single well, and injection lasts only a few weeks or months.

Disposal well injection, where wastes are injected down the disposal well to a section of the drilled hole that is below all casing strings, or to a section of the casing that has been perforated with a series of holes at the depth of an injection formation. These wells may inject wastes underground for months or years.

According to the Argonne National Laboratory, few documented cases of environmental damage caused by slurry injection exist, although several large injection jobs have resulted in leakage to either the ground surface or the sea floor. Argonne cautions that in situations involving closely-spaced wells, the potential for communication of fluids between wells should be carefully evaluated, as nearby wells can act as a conduit for injected wastes to flow to the surface. Under the high downhole pressure, injected fluids seek out the pathway of least resistance. If cracks in a well's cement job or geological faults are present, fluids may preferentially migrate upward and contaminate freshwater aquifers or daylight at the surface.

Salt Caverns

Underground salt deposits are found in many parts of the United States and worldwide, typically at depths of 500 to more than 6,000 feet below the surface. Salt caverns are created by dissolving the salt and removing the brine using a process called solution mining. The result is an underground cavern where the salt used to be.

Salt caverns have been used for several decades to store various hydrocarbon products, such as natural gas. More recently, their use as oilfield waste disposal sites has received increased attention. According to Argonne National Laboratory's information on salt caverns, as of the end of 2003 Texas was the only U.S. state to have issued permits for disposal of oil field wastes in salt caverns. Louisiana adopted cavern disposal regulations in May 2003 but has not yet permitted any disposal caverns. Several disposal caverns are also operated in Canada, and, in early 2004, Mexico announced that it was developing regulations for disposal of oil-based muds and cuttings in salt caverns.

The pit rule won broad support from suburban landowners, ranchers, and residents across New Mexico who have suffered water and soil contamination from unlined oil and gas waste pits and buried waste.

Why the pit rule is needed

Between the mid-1980s and 2003, the OCD's Environmental Bureau recorded nearly 7,000 cases of pits causing soil and water contamination.

The OCD released data in 2005 showing that close to 400 incidents of groundwater contamination had been documented from oil and gas pits.

State sampling showed carcinogens in all pit samples and heavy metals in two-thirds of the pit samples. Citizen groups, ranchers and landowners from throughout New Mexico are understandably quite concerned about water quality, exposure to unknown levels of toxic chemicals, stock and wildlife deaths, and a broad range of other issues facing residents who live near oil and gas sites.

What the pit rule does

Under the pit rule:

• unlined pits (see photo above) are banned;
• pit liner requirements are strengthened;
• pit construction must better protect private property and water resources;
• closed loop (i.e. pitless) operations are required when close to water resources and home; and
• all pits must be permitted with the Oil Conservation Division;
• a public inventory of pits is required.

A likely consequence of the rule: industry saving money in the long run by moving to closed-loop (pitless) systems. Mary Ellen Denomy, Petroleum Accountant, told the Oil Conservation Commission that closed-loop systems saved 3% per well. Denomy stated that companies were able to cut costs on construction, water, drilling muds and waste disposal when utilizing closed-loop systems.

The pit rule under attack

Ever since the pit rule was enacted, industry, and their champions in state government, have been fighting to have it weakened.

They have been unsuccessful to date.

However, they are still trying.

Defending the pit rule

Earthworks' Oil & Gas Accountability Project has partnered with the New Mexico Environmental Law Center to defend the pit rule in court. Because the facts are clearly on our side, we have a good chance to preserve the pit rule from legal attacks.

However, with an industry-friendly Governor in place -- and her task force targeting the pit rule for removal -- the pit rule needs political defense as well.

New Mexicans, you can help defend the pit rule from political attack:

Write a letter to the editor of your local paper. Use this online tool to easily compose and send the letter. No stamp licking necessary.

Tell your story. Personal accounts of the negative impacts of oil and gas drilling resonate with the public, the media, and representatives. If you'd like to tell your story -- either in print or in video or both -- contact us.

Support Earthworks' Oil & Gas Accountability Project with a donation. Fighting industry's lawyers/lobbyists/PR machine costs money. $5 or $500, it all helps.

Full public disclosure of all oil and gas drilling, stimulation and workover fluids is necessary -- at a minimum -- for property owners and the public to:

• understand the health risks associated with oil and gas development and production;
• prove a driller has polluted groundwater -- it's difficult to accuse a company of polluting your well with a toxic if they aren't required to admit they're using the toxic in the first place;
• make responsible decisions about whether and how oil and gas drilling/production should occur.

Unfortunately, that minimum is not met by any state or federal agency. Currently the oil and gas industry is injecting millions of gallons of toxics underground, through groundwater and drinking water -- and the public is largely in the dark.

Why drillers can hide their toxics from the public

At the federal level, the Halliburton loophole prevents the Environmental Protection Agency from requiring public disclosure of hazardous drilling chemicals under the Safe Drinking Water Act.

Until the federal government acts to require disclosure, state governments must act -- as they aren't barred from doing so. And within the past two years, several states -- Wyoming, Texas, Montana, Michigan, West Virginia and Arkansas -- have begun to do so. Others -- New York, California and New Mexico -- are considering legislative or regulatory proposals.  And industry has come up with its own voluntary disclosure mechanism as well.

However, these initiatives are inadequate.

What disclosure should include

Practical, hard-won experience by communities living with drilling shows that:

Disclosure must be public

This is includes posting on a publicly accessible and searchable website all chemicals by CAS number, well, and company.

Disclosure must be easily accessible and timely

This includes pre-fracturing notice to landowners, local governments and water providers and the posting of the chemicals actually used to the website in a timely manner.

There should be no obstacles to health care professionals accessing all chemical information in an emergency.

Disclosure must be comprehensive, including maximum concentrations and volumes

This includes all chemicals, not just those appearing on Material Safety Data Sheets (MSDS). MSDS' are designed only for worker safety and not to protect water quality or environmental health.

There should be few, if any, exemptions from disclosure

Any exemptions claimed should have a specific justification and there should be a mechanism for challenging any exemption claims. In short, the burden must be on the operator to demonstrate the economic need for the exemption.

There should be specific enforcement provisions to ensure compliance

The public should be able to enforce the timely reporting of the use of chemicals and not have to rely on the agency to do so

Disclosure must be mandatory, for all companies

We recommend a regulatory incentive to encourage disclosure -- adoption of the presumption that any fracking chemical contamination of water within one mile of an oil or gas well was caused by the well. The only way for the operator to avoid this presumption: prior to well operations, perform and make publicly available baseline monitoring data that shows the presence of the fracking chemicals.

Recent disclosure initiatives are inadequate

So far, industry has blocked removal of the Halliburton loophole in the federal Safe Drinking Water Act, and none of the state disclosure rules have provided full public disclosure.

In particular, the state and industry disclosure initiatives so far are not comprehensive, allow for broad exemption claims and are not publicly accessible on a searchable website.

Federal disclosure initiatives might prove helpful

The Natural Gas Subcommittee of the Secretary of Energy's Advisory Board (established at the request of President Obama) recommends we go beyond just disclosing the chemicals used in hydraulic fracturing. In addition to fracking chemicals, they recommend companies disclose the composition and character of produced water as well as measure and disclose toxic air emissions.

And the Department of Interior has begun a process to consider whether or not they will require the disclosure of fracking chemicals, or other toxic emissions, on oil and gas operations on public lands (even though the EPA isn't allowed to require disclosure through the Safe Drinking Water Act, the Interior Department, as manager of lands owned by the public -- e.g. Recreation Areas -- can require disclosure on lands that it controls).

But when it comes to regulating oil and gas operations, EPA has in some cases abdicated and in other cases been prevented from fullfilling its responsibility.

EPA does not require the oil and gas industry to report its toxic emissions to the Toxics Release Inventory

The Emergency Planning and Community Right-to-Know Act (EPCRA) was enacted in 1986. EPCRA's primary purpose is to inform communities and citizens of chemical hazards in their areas. EPCRA Section 313 requires EPA and the States to annually collect data on releases and transfers of certain toxic chemicals from certain industrial facilities. The data are then made available to the public in the Toxics Release Inventory (TRI). The goal of TRI is to empower citizens, through information, to hold companies and local governments accountable in terms of how toxic chemicals are managed. Oil and gas extraction (SIC code 13) is not on the list of industries that have eto report under the TRI. (See page 7 of EPA's publication The Emergency Planning and Community Right-to-Know Act, Section 313, Release and Other Waste Management Reporting Requirements )

"It's a Catch-22," says the remarkably frank Weston Wilson, an environmental engineer with the EPA's Denver office for the past 32 years. "If the EPA doesn't study the health impacts, then there's no proof that there's anything dangerous happening. It's irrational and corrupt. We used to investigate mysteries, and now we're not. It's sad. It's kind of like we're being paid off with our generous salaries. The American public would be shocked if they knew we [at EPA] make six figures and we basically sit around and do nothing."
--EPA to citizens: Frack you", Salon.Com by Rebecca Clarren, May 5, 2006

EPA doesn't regulate drilling or completion fluids under the Safe Drinking Water Act

How much and what drillers inject into or near aquifers should be regulated under the Safe Drinking Water Act.

Unfortunately, thanks to what is now known as the Halliburton loophole passed as part of the 2005 energy bill, hydraulic fracturing fluids are specifically exempted from regulation under the SDWA.

Drilling fluids, produced water, and other wastes associated with the exploration, development, or production of oil and gas are exempt from federal hazardous waste regulations

The Resource Conservation and Recovery Act is supposed to govern hazardous waste. This exemption is in effect even though in the publication Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations EPA admits that "Some exempt E&P wastes might be harmful to human health and the environment, and many non-exempt wastes might not be as harmful."

Colorado Oil and Gas Health and Toxics: In the News

• Voices from the gas fields, Orion Magazine, Nov/Dec. 2006
• Collatoral damage, Aspen Times, Dec. 3, 2006
• Oil and Gas Drilling Raise Health Concerns in Garfield County, Summit Daily News, Oct. 22, 2006.
• Health is a casualty of drilling, Op Ed. Denver Post, June 18, 2006
• Something in the air? Aspen Daily News, May 3, 2006
• Tempers flare over Barrett pit fires, Glenwood Springs Post Independent, December 29, 2005
• Families fume about gas leaks near Trinidad, Pueblo Chieftan, July 17, 2005
• State OKs study of gas development on health, Glenwood Springs Post Independent, July 12, 2005
• GarCo gas critic takes case to DC, Aspen Daily News, April 22, 2005
• Homeowners lament downside of wells, Grand Junction Daily Sentinel, April 18, 2005
• Oil and water make for shaky mix, Durango Telegraph, March 24, 2005
• Unused well eyed as cause of home blast, Durango Herald, February 15, 2005
• Paradox natural gas rig vents toxic fumes, Telluride Daily Planet, January 19, 2005
• Toxic bubbles trouble Silt, Rocky Mountain News, April 13, 2004

Excerpts from the articles

'Collateral damage' - Residents fear murky effects of energy boom
Aspen Times. December 3, 2006, Judith Kohler (The Associated Press)

Chris Mobaldi is 59, but looks at least 70. In the last decade, she has had two tumors removed from her pituitary gland and endured excruciating pain. . .The Mobaldis believe her neurological system was damaged by drinking water that may have been contaminated by drilling fluids from wells around their former home about 60 miles to the east in Rifle.

. . . Other residents near the epicenter of the Rockies' energy boom are starting to worry about their health, too, and who, exactly, is looking out for them. The federal government leaves much of the regulation up to state officials - and in Colorado, some residents fear there isn't nearly enough oversight to keep them safe.

"We're collateral damage out here," said Bill Solinger, whose family has had respiratory problems, headaches and fatigue since gas drilling exploded in the Rifle area.

Oil and Gas Drilling Raise Health Concerns in Garfield County
Summit Daily News, Oct. 22, 2006, Associated Press

SILT - As they drove home from Rifle after an area natural-gas operator was presented a good-corporate-citizen award recently, Carol and Orlyn Bell encountered a "terrible" smell when they neared their Dry Hollow ranch, south of Silt. "It was the strongest odor we've smelled in the last four years," Carol Bell said. The Bells said the odor came from nearby gas wells and production facilities, something they've seen surround their 110-acre ranch in those four years.

Odor complaints and air pollution concerns are on the rise in Garfield County, where longtime residents often wake up to hazy skies in the Colorado River valley. Many believe the gas industry is responsible, and figures from the Colorado Air Quality Control Commission may back up that claim.

Health is a casualty of gas drilling (Op Ed.)
Denver Post. June 18, 2006, Rebecca Clarren

Veteran oil and gas lawyer Lance Astrella of Denver, who has built a career fighting the industry on behalf of citizens, says he has talked with dozens of people who blame their health problems on the surge of new gas wells.

Between January and March of this year, eight people called the Garfield County oil and gas department to complain about air quality. They asked about black smoke and strong chemical odors that they worried could make them sick. Read more about similar complaints filed with the Colorado Oil and Gas Conservation Commission.

Something in the air?
Aspen Daily News, May 3, 2006, David Frey

Throughout the gas fields of western Garfield County, dozens of residents have complained of health problems they believe are caused by the wells that have spread across the rolling sagebrush landscape. Complaints include dizziness, nausea, difficulty breathing, sinus problems, eye and skin irritation and blistering. More severe concerns have included cancer, neurological disorders and acute chemical sensitivities.

Chris Mobaldi felt burning pains across her body for months, worsening until she could no longer dress herself. She became weak, chronically nauseous and developed a string of debilitating health problems culminating in a pair of pituitary gland tumors. In two years, friends said she aged 20 years. Most puzzling, a rare brain condition called foreign accent syndrome has left her speech sounding like she's from another country, or sometimes reduced to total gibberish. She said she had smelled fumes from the surrounding gas wells for months and complained of tainted well water.

Karen Trulove began complaining of constant fatigue at her home south of Silt, and closed up her framing shop in town when she could no longer go to work. On the well pad above her home, a petroleum smell still fills the air, and on bad days she says the air around their home shares the same odor, accumulating in gullies and valleys on her land. . . Among her neighbors south of Silt, Karen Trulove counts a half-dozen who have removed the batteries from their smoke alarms after they tired of hearing them mysteriously activated. She believes they were tripped by unseen chemicals in the air.

Dee Hoffmeister said the constant rumbling of diesel engines at a well site near her home south of Silt filled her home with fumes. She returned from a month-long family visit to find a gray cloud filling her front porch, she said, and the fumes caused her to pass out.

Tempers flare over Barrett pit fires
Glenwood Springs Post Independent, December 29, 2005, Dennis Webb

The peace and quiet of Beth Dardynski's Christmas Eve was rocked Saturday by one of several burns conducted by Bill Barrett Corp. to deal with problems in natural gas well pits south of Silt. . . Barrett representatives and industry regulators say while the practice has short-term impacts, it will end a longer-running problem of odors associated with buildup of petroleum condensates in pits.

Dardynski said the smell has been bad in her neighborhood, and has made people sick. But she also worries about the health effects of breathing smoke from the burns.

Families fume about gas leaks near Trinidad
The Pueblo Chieftain, July 17, 2005, Mike Garrett

Raton Basin landowners charge that their water wells are being polluted by seeping methane gas from coal-seam outcrops. The ranchers also complain their crop fields and yards are becoming "hot spots" of accumulating gas.

Irma Mondragon, whose son George lives next door, said her lawn just off Colorado 12 "now looks terrible with weeds coming up and everything dying. And we've always had terrible smells even after we cleaned our cesspool." She has concluded methane gas must be seeping into her water well and trailer home since she and her late husband didn't start smelling anything different until the gas industry started drilling activities in the area around 1994-95. "We were getting that smell and having to clean the cesspool all the time because we thought it was that gas," she said. "It has progressively gotten worse. I'm sure that's the smell that's coming up my pipes, especially in the kitchen. I've used a lot of stuff to put in the pipes and it doesn't seem to help."

State OKs study of gas development on health
Glenwood Springs Post Independent, July 12, 2005, Dennis Webb

A state panel Monday approved a $65,000 study to assess the possible effects of natural-gas development on human health in Garfield County. The Colorado Oil and Gas Conservation Commission gave its consent after hearing further complaints by local residents about illnesses they say have resulted from energy-industry activity.

Susan Haire, who lives on Morrisania Mesa near Battlement Mesa, said she has become ill this year since doing irrigation work near a Williams Production gas well. She has dealt with itching of her eyes and face, coughing, leg nerve inflammation that has hindered her ability to walk and other symptoms, many of which have occurred only when she has been near the well, she said. On June 24 she experienced an "extreme exposure" to gases at the well, and suffered a blinding headache, she said. "I don't know what happened at that well. All I know is how sick I am," she said.

Read the entire article.

GarCo gas critic takes case to DC
Aspen Daily News, April 22, 2005, David Frey

Laura Amos plans to meet with legislators this week to urge the Environmental Protection Agency to regulate chemicals used in hydraulic fracturing under the Safe Drinking Water Act.

Amos believes fracking on a nearby EnCana Oil & Gas well disrupted her water well, sending a plume of water in the air and allowing industrial chemicals to enter her drinking water. Amos since suffered a rare adrenal tumor, which she believes was caused by 2-BE, a chemical used in fracking. EnCana officials initially denied the chemical was used, but later admitted it had been. [Colorado Oil & Gas Conservation Commission] COGCC officials said if Amos contacted 2-BE, it might have come from household cleaners like Windex.

Read Laura Amos' story

Homeowners lament downside of wells
Grand Junction Daily Sentinel, April 18, 2005, Sally Spaulding

Garland Anderson is afraid to have his home appraised. The retiree who moved to Grass Mesa so he could live next to Bambi is now the neighbor of a swath of natural-gas wells. "I had no idea what it would mean when it all began," Anderson said. "It's dust, noise, smells, gases that leak out, major concerns about water quality and chemicals in the ground."

Carol Bell said three chemical spills have happened on her property in the last year and a half, with more than 2,000 gallons of diesel fuel emptying onto the property.

Nancy Pitman has lived on Hunter Mesa south of Rifle all her life. The fourth-generation resident on the land now has eight well pads on her property with dozens of wells. "The smell of the open pits they sometimes use is horrible and so bad it makes me sick to my stomach," she said.

Oil and water make for shaky mix
Durango Telegraph, March 24, 2005, Will Sands

Jake Hottle has been dealing with tainted drinking water for several decades. Hottle was born and raised on a farm located on the lower Animas River and remembers having clean well water as a child.

However, that changed when oil and gas drilling began in the Animas River corridor in the 1950s. Hottle says he clearly recalls his mother struggling to drink water that carried a heavy, overpowering odor throughout the 1960s. He also clearly remembers her premature passing at the age of 64 from cancer.

His personal experiences and those of his neighbors led him to form the Cedar Hill Clean Water Coalition.

Through investigations, the coalition steadily found poorly cemented wells and open-pit dumping as well as methane gas in 40 percent of the water wells tested. "After a long struggle, the industry finally went back in and properly cemented their wells, and they started lining their pits," Hottle said. While proper cementing and pit lining are now mandated practices, Hottle and many others argue that the industry needs to try still harder.

Unused well eyed as cause of home blast
Durango Herald, February 15, 2005, Shane Benjamin

A gas well with a long history of leaking methane and fouling ground water in Bondad is being studied as a possible cause for a double-wide trailer exploding last weekend. Gas leaking from the well has contaminated shallow ground formations and groundwater in Bondad, Bell said. The commission spent about $200,000 trying to plug the well in the early 1990s and again in 1994.

A 70-year-old man in the home was severely burned, according to a neighbor who called 911. His hair was singed off and his clothes were burned to his body, the neighbor said.

Paradox natural gas rig vents toxic fumes
Telluride Daily Planet, Wednesday, January 19, 2005, D. Dion

Tommy Boylan said the sulphur smell was pungent as he dismantled the barn, which was less than a mile from the drilling rig in Paradox Valley, near Bedrock, Colorado. He was at the site for less than 45 minutes, he said, but as he was leaving he felt a burning sensation between his nose and mouth, and in his lungs. The nosebleed he developed that evening lasted about an hour, longer than the time he had spent being exposed to hydrogen sulfide, a highly toxic gas present in natural gas. "My lungs still hurt, and this happened to me in December."

" It wasn't until after Boylan revisited the site, and experienced a second severe nosebleed, that he learned about the medical condition of Doris Van Ness, another Paradox resident who lives near the rig. Van Ness was treated for exposure to hydrogen sulfide. "That's when I started to really get alarmed," said Boylan.

" State regulators only learned of the venting of the toxic gas on Dec. 17, according to Morris Bell of the Colorado Oil and Gas Conservation Commission (COGCC). Bell said that regulators received complaints from "several individuals" about irritated eyes, nosebleeds and respiratory difficulties.

Toxic bubbles trouble Silt
Rocky Mountain News, April 13, 2004, Gargi Chakrabarty

Residents of Silt began drinking bottled water last Wednesday after natural gas seeped into a nearby creek, and possibly into their wells. The seep was first noticed by residents who reported seeing bubbles welling up in Divide Creek on March 31. The next day, EnCana and state officials confirmed it was natural gas. Benzene, a carcinogen, was found in Divide Creek when a water sample was tested April 1. The result showed its level at 99 micrograms per liter, about 80 times higher than the safe drinking water level of 1.2 micrograms per liter.

Property owner Bracken has asked EnCana to install a big tank on her 60-acre property to store the drinking water. "Ever since the seep, we haven't noticed any fish in the creek," Bracken said. "Even a beaver family has left; we have not seen any dead wildlife, just no wildlife."

As well, the Colorado Oil and Gas Conservation Commission (COGCC) keeps track of spills of oil and gas exploration and production wastes that are more than 5 barrels in volume.

By combing through the COGCC files, Earthworks' Oil & Gas Accountability Project has uncovered and summarized information on chemicals used and released by the oil and gas industry in Colorado.

• Documentation of use of toxics chemicals at Colorado oil and gas sites
• Summary of four recent incidents involving the release of oil and gas chemicals
• Colorado oil and gas industry spills and releases

Documented proof that oil and gas companies are using hazardous chemicals in Colorado

Because companies are not required by state or federal law to automatically disclose what chemical products they are using during drilling, hydraulic fracturing or well workover operations, it is extremely difficult for the public to find out what chemicals are being used by the oil and gas industry.

In Colorado, detailed chemical information appears to be required only when there is some sort of "incident" (e.g., a spill, leak, gas well blowout, etc.).

Earthworks' Oil & Gas Accountability Project has reviewed COGCC spill and remediation files, discovering documentation that toxic chemicals are being used at oil and gas sites in Colorado. The COGCC spill database contains information on incidents where hazardous chemicals such as anhydrous ammonia, glycol, condensate, methanol, lube oils, diesel fuel, and others have spilled, escaped into the atmosphere or leaked into soils or groundwater.

Encana used 2-BE and diesel to fracture wells in Garfield County

During the autumn of 2004, Laura Amos, a resident of Garfield County, asked EnCana whether the company used a chemical called 2-butoxyethanol (2-BE). She was assured by the company that it was not used to hydraulically fracture any of the gas wells near her home.

In December, 2004, an Associated Press news article reported that:

Encana spokesman Walter Lowry said he doesn't believe EnCana used the solvent [2-BE] in "fracing" (pronounced fracking) near the Amos well.
--Landowners unhappy with gas drilling mull legal options, Judith Kohler/Associated Press, December 22, 2004.

Less than two months later, however, the Amos family received a letter from the Colorado Oil and Gas Conservation Commission (COGCC) explaining that 2-BE was indeed used on an "experimental frac" on an EnCana well near the Amos home.

The COGCC also received documentation from EnCana on other chemicals, such as diesel fuel, used to hydraulically fracture the wells near the Amos home. Attached to the letter were Material Safety Data Sheets for the following chemical products:

• XLFC-1: Gelling agent. Contains the hazardous chemical diesel fuel. View the MSDS.
• XLW-30A: Crosslinker. Contains hazardous chemicals petroleum distillates and inorganic borate. View the MSDS.
• Flo-Back 30: Surfactant. No hazardous components were listed on the MSDS.
• GBW-33D: Breaker. No hazardous components listed.
• GBW-5: Breaker. The only hazardous component listed was ammonium persulfate.
• High Perm CRB-LT: Breaker. Listed hazardous components include ammonium persulfate and crystalline silica.
• BF-7L: High ph buffer. The only hazardous component listed was potassium carbonate.
• Magnacide 575: Microbiocide. Hazardous component listed was phosphonium, tetrakis(hydroxymethyl)-,sulfate.

Four incidents involving the release of oil and gas chemicals in Colorado

In June of 2006, Earthworks' reviewed the COGCC spills data, and selected the following four case studies to document the types of environmental releases of oil and gas chemicals and wastes that are occurring in Colorado.

• Drilling mud hits natural fracture and "daylights" in stream
• Fracking fluids affect soil and irrigation ditch
• Drilling fluids contaminate drinking water
• Condensate and flowback products foul the air

NOTE: You can download the pdf version of this summary, to view the footnotes and sources of information for these case studies.

PRESCO drilling mud daylights in stream

In October, 2005, PRESCO, Inc. (PRESCO) was drilling a well on Battlement Mesa, in Garfield County. While drilling a borehole to set the surface casing for the BM 36-23 well, the drilling mud "daylighted." According to the company, the borehole apparently intersected a fracture, which conveyed the drilling mud to the ground surface. The leak was first discovered coming out of a natural spring, on a hillside approximately 1/4 mile from the drilling rig.

According to a report sent by Cordilleran Compliance Services, Inc. to Robert Chesson of the COGCC, "the drilling mud leak eventually made its way to Battlement Creek causing a visible, 'milky-white' color change in the creek due to the turbidity. The effects of the mud leak were visible for at least 3 1/2 miles down stream."

According to Cordilleran, the drilling mud consisted of "fresh water, bentonite gel, polymer, and lime." The Material Safety Data Sheet (MSDS) for the drilling mud Quik-Gel, supplied to Cordilleran, showed that in addition to bentonite, the drilling mud contained three types of crystalline silica (cristobalite, tridymite and quartz). There was no mention of lime in the MSDS.

The National Lime Association's Fact Sheet Lime Safety Precautions states that "care should be taken to avoid accidental mixing of quicklime and water (in any form, including chemicals containing water of hydration) to avoid creating excessive heat. Heat released by this reaction can ignite combustible materials or cause thermal damage to property or person."

The COGCC issued a notice of alleged violation (NOAV) on November 21, 2005, for an "unpermitted discharge of any fluids into water of the State." On the NOAV, the COGCC required the company to describe all operational changes Presco will implement on future drilling operations to mitigate uncontrolled release of E&P fluids from drillsites, including contingency plans to manage a release without resulting in an uncontrolled discharge into surface water of the State. The COGCC case regarding this spill was closed on the same date.

Kerr McGee fracking fluids affect soil and irrigation ditch

On October 4, 2005, a valve on a the wellhead of Cannon Land 7-35 well failed, resulting in the release of between 168-210 gallons of fluids that returned to the surface from an hydraulic fracturing operation. The fluid sprayed into the air and drifted offsite, primarily onto pasture land, resulting in a visible coating that was as much as 1/2 inch thick. The company estimated that 15-20 gallons of the fluid entered the Platteville Lateral irrigation ditch, which contained some standing water but was not flowing at the time that the fluids entered it.

The fracturing fluid contained Potassium Chloride (2%), as well as a surfactant (DWP-931, run at 1.5 gallons/1000 gallons of water), and friction reducer (DWP-601, run at 0.5 gallons/1000 gallons of water). DWP-931 contains a host of potentially toxic substances, including ethoxylated nonylphenol (15-40%); trimethylbenzene (3-7 %), light aromatic naphtha (3-13%); oxyalkylated phenolic resin (15-40%); ethylbenzene (0-2%); xylene (3-13 %); and isobutyl alcohol (10-30%). DWP-601 contains 1-5% ethoxylated nonylphenol.

Despite the presence of these chemicals, an Oct. 4, 2005 email from a COGCC employee to the Water Quality Control Division of CDPHE stated that this spill/release "would be classified as non-significant."

Maralex drilling fluids in drinking water

On October 30, 2005, a landowner in La Plata county contacted COGCC regarding potential contamination of his water well. According the landowner, in response to his initial complaint he was told by COGCC staff that his water probably tasted bad because of changes to his water caused by an earthquake or the drought.

An unlined drilling reserve pit for the Keegan Patrick 33-7-11 #2A well, which was operated by Maralex Resources, Inc., was located about 350 feet uphill from the affected water well. Based on water samples taken over a five month period, the agency eventually concluded that "it appears that fluids from the unlined reserve pit infiltrated into the shallow groundwater, flowed downhill and impacted the . . . water well."

Water quality samples from the landowner's well revealed elevated concentrations of calcium, chloride and total dissolved solids compared to neighboring water wells, and concentrations of chlorides that exceeded Colorado water quality standards.

According to data that COGCC obtained from Maralex, calcium hydroxide, potassium chloride and about 20 other chemical products were used during various phases of the company's drilling operation.

COGCC requested of Maralex copies of the MSDSs for the chemical additives and products used during their drilling operations. The request was made in December of 2005, and COGCC received the information a few months later.

Earthworks' Oil & Gas Accountability Project obtained copies of the MSDSs from COGCC. There were at least 19 products used during the drilling of the Maralex well. Many of the products contained chemicals known to be harmful to human health and the environment. For example, products contained ethoxylated nonylphenols, isopropanol, 2-bromo-2-nitropropane-1,3-diol, acrylamide, heavy aromatic petroleum naphtha, and dipropylene glycol monomethyl ether. Additionally, hydrochloric and hydrofluoric acids were used at various stages during the drilling process.

At no time after receiving the MSDSs, did the COGCC require the company to sample for any of the more complex chemical additives used during the drilling process (e.g., nonylphenol, acrylamide, etc.). The water quality sampling regime for consisted of the standard inorganic analysis (e.g., for salts, metals), and during the initial sampling period the company was required to sample for volatile organic compounds.

The COGCC request for information did not result in the full disclosure of all chemical products used by Maralex in their drilling operations. MSDSs were not included for two Halliburton products, HAI-81M (only a Transportation Emergency Response Information sheet was submitted for this product; it did not contain specific chemical names) and Halad-344 (data submitted by the company to COGCC shows that this product was used during the drilling process).

Based on preliminary research into these two products, Earthworks' Oil & Gas Accountability Project has found that they likely contain chemicals that are harmful to human health.

• HAI-81M is an acid inhibitor product from Halliburton. BJ Services, a competing company, has produced an acid inhibitor that it touts as being 'greener' than HAI-81M. The BJ Services product, CI-27, "contains no nonyl phenol ethoxyolates, quaternaries, aromatic solvents or heavy metals."
• Halad-344 may contain N,N-dimethylformamide, 2-acrylamido-2-methylpropane sulfonic acid; and N,N-dimethyl acrylamide. N,N-dimethylformamide is a suspected toxicant for many physiological systems (respiratory, skin, eyes, liver, cardiovascular, and several others).

As of the end of June 29, 2006, the landowner says that his water still has a strange, metallic taste to it.

Barrett condensate and flowback products in air

Citizen Complaints

Between September and December, 2005, the COGCC documented 10 complaints from eight separate households related to odors emanating from wells being drilled and completed by Bill Barrett Corporation ('Barrett').

9/16/2005: Elizabeth Vath, Gayle Hartop and Teran Hughes complained separately to the COGCC about smoke/haze/odors from a nearby well pad. In the COGIS Complaint report for this incident, it is revealed that additional cementing work had to be done on a Barrett well, so pressure in the well was released. Typically, Barrett would sparge the accumulated gases through reserve pit fluid. In this case, however, because the pit was almost empty, the gases were vented directly to the atmosphere. There was no mention of any air quality monitoring occurring at the complainants' homes or at the well site.

9/22/2005: Oni Butterfly, a landowner living near Barrett's Louthan well, complained of fumes/odors that left her 'gagging.' The 'stench' was so bad that she found it difficult to be at home, especially outside.

10/18/2005: Dion and Debbie Enlow complained about odors from a Barrett wellpad upwind from their home. The pad had four wells that were undergoing completion/hydraulic fracturing. COGCC staff investigated and found flowback in one half of the unlined pit. The other side of the pit was "really dark and oily in appearance." The complaint report states that the "Enlow residence is down in a hollow, 1/4 miles or so from well-pad. Fumes and such can accumulate there. . . [Barrett is] trying to complete this loc[ation] ASAP." According to Dion Enlow, he complained to the company that the smell was so bad that "I can't go outside and breathe." Enlow was not aware of either the company or any agencies actually sampling the air quality in response to his complaints.

10/19/2005: Oni Butterfly filed another complaint about the odors from the Barrett wells. There had recently been a problem with a nearby well location, and with tanks overflowing. According to the COGCC Complaint report on this incident, Garfield county environment staff would install monitoring equipment at her house to take a monthly air quality reading, and leave a Suma air sampler to that Ms. Butterfly could take an air sample when the odors were especially bad. This is the only example, in these COGCC complaints, of air samples being taken in response to odors from Barrett pits.

10/25/2006: COGCC was called by the Enslow family, who related that odors were so severe that they could not remain outside to cook on their grill. Debbie Enslow also said that she and her husband were "not prone to headaches but have been getting them due to pit odor/vapors," and that they were also "feeling rundown and listless." Jay Krabacher of COGCC and a Barrett representative went to the Enslow residence and according to Krabacher, "we all could smell intermittent (but persistent) odors." Krabacher investigated options for mitigating pit odors, and was told that "Schumberger and BJ [Services] have 'industrial strength' powdered bleach which, when added to the pit fluid, is pumped and circulated. . . works quickly." Krabacher visited the Wilson pad near the Enslows and stuck a finger in the pit; in the complaint report he notes that "there was a slight condensate odor which could be detected on my finger hours later."

11/1/2005: Sherry Tardiff contacted the COGCC regarding "nauseating odors from Anchondo pad." COGCC staff, Jay Krabacher, went to the location to 'sniff around,' and detected a 'slight odor.' He was told by a Barrett employee that Anchondo was a 'real active well,' and that during the day the gas was being vented under the pit surface to a tank. Krabacher also reports that that hot flowback water "becomes very steamy upon hitting surface, and there was some odor."

11/1/2005: Dion Enslow reported "a large cloud of steam/vapor" extending for approximately 1/4 mile from the Wilson pad, which was undergoing a workover prior to hydraulic fracturing. The Enslows were "somewhat apprehensive of the contents of the cloud." The crew foreman speculated that the steam cloud could be the result of hot (170 - 190º F) produced water hitting the cold air, which sounded 'reasonable' to Krabacher and the Enslows. There was no investigation into what compounds might be volatilizing when the hot produced water hit the surface.

11/15/2005: The Enslows left a message for COGCC at 5:30 in the morning, stating that "odor worse than it's been." Enslow had gone up to the Wilson pad location and had observed 'gnarly/oily' fluid in the pit. Barrett had just completed its final hydraulic fracturing flowback operation at that site. The well had been hydraulic fractured with 'slickwater,' which according to Jennifer Miskimins of the Colorado School of Mines, may contain chemicals such as "a friction reducer, surfactants, and clay stabilizers." Jay Krabacher of COGCC noticed a 'slight odor' at the Wilson well pad, and was assured by the company that the location would be completed and pit reclamation would begin soon thereafter. Enslow reports that the flow-tester working for Barrett assured him that if the Enslows had any problem he'd "take care of it."

11/21/2005: Oni Butterfly contacted the COGCC several times to complain about odors from area wells. Ms. Butterfly asked about the 'stuff' on the surface of the Louthan pit, and was given the "guar gum tutorial" by Jay Krabacker. She was told that the stuff on pit surfaces is "mostly environmentally benign," although sometimes odiferous.

12/05/2006 - 12/29/06: Ms. Butterfly called the COGCC to complaint about "a different sort of stench, still very bad." The next day she called again, referring to it as a "benzene smell." She asked that the COGCC try to procure a full-time, outdoor air-monitoring device and an air pollution control device for the inside of her house. On the 29th of December, Ms. Butterfly called COGCC again, to report a strong odor experienced at 4:30 that morning. On December 30, Butterfly was informed by Garfield County that an air quality sample had been taken on Chipperfield Lane, which was fairly close to the Laughlin Pit, on October 25, 2005. Results from the sampling showed that benzene and xylenes exceeded the U.S. Environmental Protection Agency's 'non-cancer risk levels' for these compounds - at 67 µg/m3, benzene was present at more than double the risk level. Other detectable compounds included acetone, toluene and ethylbenzene.

Notices of Alleged Violation (NOAVs)

Between October 18 and December 28, 2005, Barrett was issued nine NOAVs. The violations included transporting condensate wastes offsite without a permit; burning wastes at a site not authorized as a waste disposal site; allowing fluids to fill pits above allowable levels; not reporting the spill of "frac flowback" fluid outside of a pit; and not removing condensate from the pit within 24 hours. Some well sites received a couple of NOAVs during this time period.

In one of the COGCC NOAV reports, it was documented that a Barrett employee said he was unaware that he was violating a COGCC rule by filling the pit too full.

Burning the Condensate

One case, in particular, should be highlighted for its air quality issues. On or within a few days of December 24, 2005, condensate from a Barrett owned well was transported to the Werner 44A-23-692 well site and burned. According to COGCC rules, operators are not allowed to haul condensate from one pit to another for disposal purposes without a permit. Barrett had not obtained a permit to use the Werner site as a centralized location for waste disposal purposes. Barrett was issued a Notice of Alleged Violation for transporting the wastes to the Werner pit.

The burning of condensate created smoke that sparked complaints from nearby residents. Brian Macke, COGCC director, told the Glenwood Springs Post Independent (the Post) that burning condensate "does get rid of the odor problem quickly, which we thought was beneficial." The Post also reported Garfield County environmental health manager as saying "I felt pretty good that there was no direct impacts to anybody in the area."

Yet, despite the apparent lack of concern on the part of the Garfield County staff, on December 29, the Air Pollution Control Division (APCD) of the Colorado Department of Public Health and Environment revoked the burning permits that it had issued to Barrett. According the Post, this was done after the APCD learned of complaints made to Garfield County about the pit fires. There is no information on whether the state agencies or Garfield County conducted air quality monitoring during the burn operations.

Colorado Oil and Gas Industry Spills and Releases

Spills and leaks of raw chemicals or oil and gas wastes may affect land, water and air. The Colorado Oil and Gas Conservation Commission (COGCC) requires companies to report spills of fluids related to any unauthorized release of exploration and production (E&P) wastes that are 5 barrels or more in volume. In some cases, smaller spills are reported, e.g., if the spill enters surface or groundwater.

In the four-year period between June 2002 and June 2006, there were approximately 924 spills of oil and gas chemicals and wastes. Spilled products included: crude oil, condensate, produced water, and "other" products. The other products included diesel fuel, glycol, amine, lubricating oil, hydraulic fracturing fluids, drilling muds, other chemicals, and natural gas leaks.

Roughly estimated, 60% of the spills involved produced water; 34 % involved crude oil or condensate; and 12% involved spills of "other" substances. (Numbers add up to greater than 100% because some of the spills involved more than one type of fluid).

Colorado oil and gas spills affecting water

Of the 924 oil and gas industry spills, 20% of them contaminated water: 14% of the spills affected groundwater; and 6% of all spills affected surface water.

As the chart shows, a large percentage of spills recorded by the COGCC do find their way into groundwater or surface water.

While some of the spills are accidents, acts of nature (e.g., lightning strikes) there are many spills that are preventable. For example, during the four-year period, Chevron had 57 incidents of produced water and two crude oil leaks caused by corroded pipes or fittings. It is likely that proper maintenance, pipeline integrity testing, and replacement of old equipment could have prevented many of these spills.

Regulatory gaps put public health at risk

Citizens in Colorado are worried about the hazardous chemicals used during drilling and production, and the health impacts of the pollution released from oil and gas operations.

Lack of disclosure

Lack of chemical disclosure and monitoring leave Colorado communities in the dark about oil and gas health impacts.

Many Colorado residents are experiencing health impacts that they believe are directly related to the release of oil and gas industry chemicals and wastes.

Residents, as well, are experiencing frustration with the lack of monitoring and information provided by industry and government representatives, when spills or chemical releases occur.

Unfortunately, there are regulatory gaps that prevent emergency preparedness staff, water utilities, local and environmental staff, medical professionals, health departments, and people living in close proximity to oil and gas facilities from obtaining complete information on the oil and gas industry chemicals that are being transported through, stored, and used and released in their communities.

Cause for citizen concern

The chemical products used throughout the exploration, drilling and production phases of Colorado's oil and gas development are made up of a wide variety of chemical compounds.

Although it is common to hear from industry and some state agency representatives that drilling and production chemicals and wastes are benign, there is competing industry information indicating that toxic chemicals are used and released throughout the development process.

• In a 2004 presentation by BJ Services, one of the world's largest oilfield service companies, it was reported that about 2,500 chemicals are being used by the oil and gas industry; and that globally, the United States is behind other countries when it comes to phasing out the more toxic chemicals.
• By combing through the files of the Colorado Oil and Gas Conservation Commission, it is possible to find proof that Colorado companies are using toxic compounds such as diesel fuel, which contains cancer-causing chemicals, and 2-BE, which is a chemical that interfere's with the endocrine systems of living organisms. This information is not routinely gathered by the COGCC.

The Endocrine Disruption Exchange, Inc. (TEDX) reviewed oil and gas industry chemicals being used in Western Colorado. The TEDX data indicated that numerous oil and gas industry chemicals present risks to human and environmental health.

There are a variety of sources of contamination and pathways for oil and gas contaminants to enter the environment and affect human health, and ample evidence that these chemicals are being released to the environment via air and water.

What citizens can do

In June of 2006, OGAP submitted a letter to the Colorado Oil and Gas Conservation Commission (COGCC) and the Colorado Department of Public Health and the Environment (CDPHE) on behalf of five citizens organizations in Colorado. The groups asked that state agencies to require disclosure of the chemicals used and monitoring of chemicals and wastes released by the oil and gas industry in Colorado.

• Download a copy of the original letter sent to the COGCC and CDPHE
• Download the most recent summary of Colorado oil and gas chemical toxicity and health data
• Download Colorado oil and gas chemical and waste incidents

The five organizations include:

• San Juan Citizens Alliance
• Western Colorado Congress
• Western Slope Environmental Resource Council
• Grand Valley Citizens Alliance
• Earthworks' Oil and Gas Accountability Project

Contact the group nearest you to find out how you can participate in this effort.

How does it form?

At metal mines, the target ore (like gold, silver, copper, etc) is often rich in sulfide minerals.

When the mining process exposes the sulfides to water and air, together they form sulfuric acid.

This acid can and often does dissolve other harmful metals and metalloids (like arsenic) in the surrounding rock.

Acid mine drainage can be released anywhere on the mine where sulfides are exposed to air and water -- including waste rock piles, tailings, open pits, underground tunnels, and leach pads.

Acid drainage is often marked by "yellow boy", an orange-yellow substance (visible in the photo on this page), that occurs when the pH of water drops low enough so that previously dissolved iron precipitates out.

Harm to fish & other aquatic life

Acid mine drainage can have severe impacts on fish, animals and plants. Many impacted streams have a pH of 4 or lower -- similar to battery acid.

For example, acid and metals runoff from the Questa molybdenum mine in New Mexico has harmed biological life in eight miles of the Red River.

Perpetual pollution

Acid mine drainage is especially harmful because it can occur indefinitely -- long after mining has ended. Hardrock mines across the western United States may require water treatment in perpetuity.

For example, government officials have determined that acid drainage at the Golden Sunlight mine will continue for thousands of years.

Water treatment can be a significant economic burden if a company files for bankruptcy or refuses to cover water treatment costs.

For example, acid runoff from the Summitville Mine in Colorado killed all biological life in a 17-mile stretch of the Alamosa River. The site was designated a federal Superfund site, and the EPA is spending $30,000 a day to capture and treat acid runoff.

Geologic formations may contain large quantities of oil or gas, but have a poor flow rate due to low permeability, or from damage or clogging of the formation during drilling. This is particularly true for tight sands, shales and coalbed methane formations.

Hydraulic fracturing (aka fracking, which rhymes with cracking) stimulates wells drilled into these formations, making profitable otherwise prohibitively expensive extraction. Within the past decade, the combination of hydraulic fracturing with horizontal drilling has opened up shale deposits across the country and brought large-scale natural gas drilling to new regions.

The fracking process occurs after a well has been drilled and steel pipe (casing) has been inserted in the well bore. The casing is perforated within the target zones that contain oil or gas, so that when the fracturing fluid is injected into the well it flows through the perforations into the target zones. Eventually, the target formation will not be able to absorb the fluid as quickly as it is being injected. At this point, the pressure created causes the formation to crack or fracture. Once the fractures have been created, injection ceases and the fracturing fluids begin to flow back to the surface. Materials called proppants (e.g., usually sand or ceramic beads), which were injected as part of the frac fluid mixture, remain in the target formation to hold open the fractures.

Typically, a mixture of water, proppants and chemicals is pumped into the rock or coal formation. There are, however, other ways to fracture wells.  Sometimes fractures are created by injecting gases such as propane or nitrogen, and sometimes acidizing occurs simultaneously with fracturing. Acidizing involves pumping acid (usually hydrochloric acid), into the formation to dissolve some of the rock material to clean out pores and enable gas and fluid to flows more readily into the well.

Some studies have shown that anywhere from 20-85% of fracking fluids may remain underground. Used fracturing fluids that return to the surface are often referred to as flowback, and these wastes are typically stored in open pits or tanks at the well site prior to disposal.

Hydraulic fracturing - Issues and impacts

The process of fracturing a well is far from benign. The following sections provide an overview of some of the issues and impacts related to this well stimulation technique.

Fracking operation, Grass Mesa, Colorado. Photo Credit: Peggy Utesch.

• Water use
• Sand and proppants
• Toxic chemicals
• Health concerns
• Surface water and soil contamination
• Groundwater contamination
• Air quality
• Waste disposal
• Chemical disclosure

Water Use

In 2010, the U.S. Environmental Protection Agency estimated that 70 to 140 billion gallons of water are used to fracture 35,000 wells in the United States each year. This is approximately the annual water consumption of 40 to 80 cities each with a population of 50,000. Fracture treatments in coalbed methane wells use from 50,000 to 350,000 gallons of water per well, while deeper horizontal shale wells can use anywhere from 2 to 10 million gallons of water to fracture a single well. The extraction of so much water for fracking has raised concerns about the ecological impacts to aquatic resources, as well as dewatering of drinking water aquifers.

It has been estimated that the transportation of a million gallons of water (fresh or waste water) requires 200 truck trips. Thus, not only does water used for hydraulic fracturing deplete fresh water supplies and impact aquatic habitat, the transportation of so much water also creates localized air quality, safety and road repair issues.

Sand and Proppants

Conventional oil and gas wells use, on average, 300,000 pounds of proppant, coalbed fracture treatments use anywhere from 75,000 to 320,000 pounds of proppant and shale gas wells can use more than 4 million pounds of proppant per well.

Frac sand mines are springing up across the country, from Wisconsin to Texas, bringing with them their own set of impacts. Mining sand for proppant use generates its own range of impacts, including water consumption and air emissions, as well as potential health problems related to crystalline silica.

Toxic Chemicals

In addition to large volumes of water, a variety of chemicals are used in hydraulic fracturing fluids.  The oil and gas industry and trade groups are quick to point out that chemicals typically make up just 0.5 and 2.0% of the total volume of the fracturing fluid.  When millions of gallons of water are being used, however, the amount of chemicals per fracking operation is very large. For example, a four million gallon fracturing operation would use from 80 to 330 tons of chemicals.[1]

As part of New York State’s Draft Supplemental Generic Environmental Impact Statement (SGEIS) related to Horizontal Drilling and High-Volume Hydraulic Fracturing in the Marcellus Shale, the Department of Environmental Conservation complied a list of chemicals and additives used during hydraulic fracturing. The table below provides examples of various types of hydraulic fracturing additives proposed for use in New York. Chemicals in brackets [ ] have not been proposed for use in the state, but are known to be used in other states or shale formations.

Many fracturing fluid chemicals are known to be toxic to humans and wildlife, and several are known to cause cancer.  Potentially toxic substances include petroleum distillates such as kerosene and diesel fuel (which contain benzene, ethylbenzene, toluene, xylene, naphthalene and other chemicals); polycyclic aromatic hydrocarbons; methanol; formaldehyde; ethylene glycol; glycol ethers; hydrochloric acid; and sodium hydroxide.

Very small quantities of some fracking chemicals are capable of contaminating millions of gallons of water.  According to the Environmental Working Group, petroleum-based products known as petroleum distillates such as kerosene (also known as hydrotreated light distillates, mineral spirits, and a petroleum distillate blends) are likely to contain benzene, a known human carcinogen that is toxic in water at levels greater than five parts per billion (or 0.005 parts per million).

Other chemicals, such as 1,2-Dichloroethane are volatile organic compounds (VOCs). Volatile organic constituents have been shown to be present in fracturing fluid flowback wastes at levels that exceed drinking water standards. For example, testing of flowback samples from Pennsylvania have revealed concentrations of 1,2-Dichloroethane as high as 55.3 micrograms per liter, which is more than 10 times EPA’s Maximum Contaminant Level for 1,2-Dichloroethane in drinking water.

VOCs not only pose a health concern while in the water, the volatile nature of the constituents means that they can also easily enter the air. According to researchers at the  University of Pittsburgh's Center for Healthy Environments and Communities, organic compounds brought to the surface in the fracturing flowback or produced water often go into open impoundments (frac ponds), where the volatile organic chemicals can offgas into the air.

When companies have an excess of unused hydraulic fracturing fluids, they either use them at another job or dispose of them.  Some Material Safety Data Sheets (MSDSs) include information on disposal options for fracturing fluids and additives. The table below summarizes the disposal considerations that the company Schlumberger Technology Corp. ("Schlumberger") includes in its MSDSs.[2]

As seen in the table, Schlumberger recommends that many fracturing fluid chemicals be disposed of at hazardous waste facilities. Yet these same fluids (in diluted form) are allowed to be injected directly into or adjacent to USDWs. Under the Safe Drinking Water Act, hazardous wastes may not be injected into USDWs. Moreover, even if hazardous wastes are decharacterized (for example, diluted with water so that they are rendered non-hazardous), wastes must still be injected into a formation that is below the USDW.

Clearly, some hydraulic fracturing fluids contain chemicals deemed to be "hazardous wastes." Even if these chemicals are diluted it is unconscionable that EPA is allowing these substances to be injected directly into underground sources of drinking water.

Health Concerns

Human exposure to fracking chemicals can occur by ingesting chemicals that have spilled and entered drinking water sources, through direct skin contact with the chemicals or wastes (e.g., by workers, spill responders or health care professionals), or by breathing in vapors from flowback wastes stored in pits or tanks.

In 2010, Theo Colborn and three co-authors published a paper entitled Natural Gas Operations from a Public Health Perspective. Colborn and her co-authors summarized health effect information for 353 chemicals used to drill and fracture natural gas wells in the United States. Health effects were broken into 12 categories: skin, eye and sensory organ, respiratory, gastrointestinal and liver, brain and nervous system, immune, kidney, cardiovascular and blood, cancer, mutagenic, endocrine disruption, other, and ecological effects.  The chart below illustrates the possible health effects associated with the 353 natural gas-related chemicals for which Colborn and her co-authors were able to gather health-effects data.

Colborn’s paper provides a list of 71 particularly nasty drilling and fracturing chemicals, i.e., those that are associated with 10 or more health effects.

Natural gas drilling and hydraulic fracturing chemicals with 10 or more health effects

While Colborn and her co-workers focused on chemicals used in natural gas development, the chemicals used to fracture oil wells are very similar or the same.  Looking at some of the oil wells that have been developed in the Bakken Shale in North Dakota, the fracturing fluid mixtures include some of the chemicals shown by Colborn to have the potential to cause 10 or more adverse health effects. Information posted hydraulic fracturing fluid chemicals on the FracFocus web site indicates that Bakken Shale oil wells may contain toxic chemicals such as hydrotreated light distillate, methanol, ethylene glycol, 2-butoxyethanol (2-BE), phosphonium, tetrakis(hydroxymethyl)-sulfate (aka phosphonic acid),  acetic acid, ethanol, and napthlene.[3]

Surface Water and Soil Contamination

Spills of fracturing chemicals and wastes during transportation, fracturing operations and waste disposal have contaminated soil and surface waters.  This section provides a few examples of spills related to hydraulic fracturing that have led to environmental impacts.

• Two spills kill fish: In September 2009, Cabot Oil and Gas spilled hydraulic fracturing fluid gel LGC-35 twice at the company’s Heitsman gas well. The two incidents released a total of 8,000 gallons of the fracturing fluid, polluting Stevens Creek and resulting in a fish kill.  LGC-35, a well lubricant used during the fracturing process. A third spill of LGC-35 occurred a week later, but did not enter the creek.
• Fracturing fluid taints a high quality watershed: In December 2009, a wastewater pit overflowed at Atlas Resources’ Cowden 17 gas well, and an unknown quantity of hydraulic fracturing fluid wastes entered Dunkle Run, a “high quality watershed”. The company failed to report the spill. In August 2010 the Pennsylvania Department of Environmental Protection (DEP) levied a $97,350 fine against Atlas Resources
• Another fracturing fluid spill impacts a high quality waterway: In May 2010, Range Resources was fined was fined $141,175 for failing to immediately notify the Pennsylvania Department of Environmental Protection when the company spilled 250 barrels of diluted fracturing fluids due to a broken joint in a transmission line. The fluids flowed into an unnamed tributary of Brush Run, killing at least 168 fish, salamanders and frogs.  The watercourse is designated as a warm-water fishery under Pennsylvania’s special protection waters program.
• Fracturing fluids affect soil and irrigation ditch: In October 2005 a valve on the wellhead of a Kerr-McGee well in Colorado failed.  As a result, between168 and 210 gallons of flowback fluids sprayed into the air and drifted offsite, primarily onto pasture land, resulting in a visible coating that was as much as 1/2 inch thick.

Groundwater Contamination

As mentioned previously, hydraulic fracturing is used in many coalbed methane (CBM) production areas. Some coal beds contain groundwater of high enough quality to be considered underground sources of drinking water (USDWs).

Chemicals in fracking fluids. Source: EPA
Click to view larger version

In 2004, the U.S. Environmental Protection Agency (EPA) released a final study on Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs. In the study, EPA found that ten out of eleven CBM basins in the U.S. are located, at least in part, within USDWs. Furthermore, the EPA determined that in some cases, hydraulic fracturing chemicals are injected directly into USDWs during the course of normal fracturing operations. (Read Laura Amos's story to learn how hydraulic fracturing has affected her family's life.)

Calculations performed by EPA in the draft version of its study show that at least nine hydraulic fracturing chemicals may be injected into or close to USDWs at concentrations that pose a threat to human health. The chart below is a reproduction of the data from the EPA draft study. As seen in the chart, chemicals may be injected at concentrations that are anywhere from 4 to almost 13,000 times the acceptable concentration in drinking water.

Not only does the injection of these chemicals pose a short-term threat to drinking water quality, it is quite possible that there could be long-term negative consequences for USDWs from these fracturing fluids. According to the EPA study, studies conducted by the oil and gas industry, and interviews with industry and regulators, 20 to 85% of fracturing fluids may remain in the formation, which means the fluids could continue to be a source of groundwater contamination for years to come.

The potential long-term consequences of dewatering and hydraulic fracturing on water resources have been summed up by professional hydrogeologist who spent 32 years with the U.S. Geological Survey:

At greatest risk of contamination are the coalbed aquifers currently used as sources of drinking water. For example, in the Powder River Basin (PRB) the coalbeds are the best aquifers. CBM production in the PRB will destroy most of these water wells; BLM predicts drawdowns...that will render the water wells in the coal unusable because the water levels will drop 600 to 800 feet. The CBM production in the PRB is predicted to be largely over by the year 2020. By the year 2060 water levels in the coalbeds are predicted to have recovered to within 95% of their current levels; the coalbeds will again become useful aquifers. However, contamination associated with hydrofracturing in the basin could threaten the usefulness of the aquifers for future use.

As mentioned previously, anywhere from 20-85% of fracking fluids remain in the ground. Some fracturing gels remain stranded in the formation, even when companies have tried to flush out the gels using water and strong acids. Also, studies show that gelling agents in hydraulic fracturing fluids decrease the permeability of coals, which is the opposite of what hydraulic fracturing is supposed to do (i.e., increase the permeability of the coal formations).  Other similar, unwanted side effects from water- and chemical-based fracturing include: solids plugging up the cracks; water retention in the formation; and chemical reactions between the formation minerals and stimulation fluids. All of these cause a reduction in the permeability in the geological formations.

For more details on the studies that have looked at stranded fracturing fluids and the potential for hydraulic fracturing to affect underground sources of drinking water, see Our Drinking Water at Risk, Oil and Gas Accountability Project's review of the EPA's study on the impacts of hydraulic fracturing of coalbed methane reservoirs on drinking water.

Air Quality

In many oil and gas producing regions, there has been a degradation of air quality as drilling increases. For example, in Texas, high levels of benzene have been measured in the air near wells in the Barnett Shale gas fields. These volatile air toxics may be originating from a variety of gas-field source such as separators, dehydrators, condensers, compressors, chemical spills, and leaking pipes and valves.

Increasingly, research is being conducted on the potential air emissions released during the fracturing flow back stage, when wastewater returns to the surface. Shales contain numerous organic hydrocarbons, and additional chemicals are injected underground during shale gas drilling, well stimulation (e.g., hydraulic fracturing), and well workovers.

The Pittsburgh University Center for Healthy Environments and Communities (CHEC) has been examining how organic compounds in the shale can be mobilized during fracturing and gas extraction processes. According to the CHEC researchers, these organic compounds are brought to the surface in the fracturing flowback or produced water, and often go into open impoundments (frac ponds), where the waste water, “will offgas its organic compounds into the air. This becomes an air pollution problem, and the organic compounds are now termed Hazardous Air Pollutants (HAP’s).”

The initial draft of the New York draft supplemental environmental impacts statement related to drilling in the Marcellus Shale (which is no longer available on-line) included information on modeling of potential air impacts from fracturing fluid wastes stored in centralized impoundments. One analysis looked at the volatile organic compound methanol, which is known to be present in fracturing fluids such as surfactants, cross-linkers, scale inhibitors and iron control additives. The state calculated that a centralized fracturing flowback waste impoundment serving 10 wells (5 million gallons of flowback per well) could have an annual emission of 32.5 tons of methanol.

The U.S. EPA reports that “chronic inhalation or oral exposure to methanol may result in headache, dizziness, giddiness, insomnia, nausea, gastric disturbances, conjunctivitis, visual disturbances (blurred vision), and blindness in humans.”

Open pits, tanks or impoundments that accept flowback wastes from one well would have a much smaller emission of volatile organic compounds (VOC) like methanol than facilities accepting wastes from multiple wells. But there are centralized flowback facilities like those belonging to Range Resources in Washington County, Pennsylvania that have been designed for “long-term use,” and thus, are likely to accept wastes from more than one well.

New York’s air modeling further suggested that the emission of Hazardous Air Pollutants (HAPs) from centralized flowback impoundments could exceed ambient air thresholds 1,000 meters (3,300 feet) from the impoundment, and could cause the impoundment to qualify as a major source of HAPs.

Methanol is just one of the VOCs contained in flowback water.  The combined emissions from all VOCs present in flowback stored at centralized impoundments could be very large, depending on the composition of the fracturing fluids used at the wells. Data released on flowback water from wells in Pennsylvania reveal that numerous volatile organic chemicals are returning to the surface, sometime in high concentrations.  The Pennsylvania Department of Environmental Protection looked for 70 volatile organic compounds in flowback, and 27 different chemicals showed up.

In a health effects analysis conducted by Theo Colborn and others, 37% of the chemicals used during natural gas drilling, fracturing and production (for which health data were available) were found to be volatile, with the ability to become airborne.  Colborn and her co-authors compared the potential health impacts of volatile chemicals with those chemicals more like to be found in water (i.e., chemicals with high solubilities). They found that “far more of the volatile chemicals (81%) can cause harm to the brain and nervous system.  Seventy one percent of the volatile chemicals can harm the cardiovascular system and blood, and 66% can harm the kidneys,” producing a profile that “displays a higher frequency of health effects than the water soluble chemicals.”  The researchers add that the chance of exposures to volatile chemicals are increased by case they can be inhaled, ingested and absorbed through the skin.

Citizens of the gas field are experiencing health effects related to volatile chemicals from pits.

• In 2005, numerous Colorado residents experienced severe odors and health impacts related to flowback and drilling pits and tanks in Garfield County.  According to Dion and Debbie Enlow complained to the Colorado Oil and Gas Conservation Commission about odors from a Barrett wellpad upwind from their home. The pad had four wells that were undergoing completion/hydraulic fracturing. Dion Enlow complained to the company that the smell was so bad that "I can't go outside and breathe."
• In Pennsylvania, a fracturing flowback wastewater pit just beyond June Chappel’s property line created odors similar to gasoline and kerosene, which forced her inside, left a greasy film on her windows, on one occasion created a white dust that fell over her yard. Chappel and her neighbors lived with the noxious odors until they hired an attorney and Range Resources agreed to remove the impoundment.
• In March 2010, a fracturing flowback wastewater impoundment in Washington County, Pennsylvania caught fire and exploded producing a cloud of thick, black smoke that could be seen miles away. For several days prior to the explosion nearby citizens had tried to alert state officials about noxious odors from the impoundment that were sickening their families, but “their voicemail boxes were full.”

Waste Disposal

It has been reported that anywhere from 25 – 100% of the chemical-laced hydraulic fracturing fluids return to the surface from Marcellus Shale operations. This means that for some shale gas wells, millions of gallons of wastewater are generated, and require either treatment for re-use, or disposal.

In 2009, the volume of fracturing flowback and brines produced in Pennsylvania was estimated to be 9 million gallons of wastewater per day, and this figure was expected to increase to 19 - 20 million gallons/day in 2011.

The sheer volume of wastes, combined with high concentrations of certain chemicals in the flowback from fracturing operations, are posing major waste management challenges for the Marcellus Shale states. 
Also, the US Geological Survey has found that flowback may contain a variety of formation materials, including brines, heavy metals, radionuclides, and organics, which can make wastewater treatment difficult and expensive.

According to an article in ProPublica, New York City’s Health Department has raised concerns about the concentrations of radioactive materials in wastewater from natural gas wells. In a July, 2009 letter obtained by ProPublica, the Department wrote that “Handling and disposal of this wastewater could be a public health concern.” The letter also mentioned that the state may have difficulty disposing of the waste, that thorough testing will be needed at water treatment plants, and that workers may need to be monitored for radiation as much as they might be at nuclear facilities.

Options for disposal of radioactive flowback or produced water include underground injection in Class II UIC wells and offsite treatment. The U.S. Environmental Protection Agency has indicated that Class II UIC injection disposal wells are uncommon in New York, and existing wells aren't licensed to receive radioactive waste. In terms of offsite treatment, it is not known if any of New York’s water treatment facilities are capable of handling radioactive wastewater. ProPublica contacted several plant managers in central New York who said they could not take the waste or were not familiar with state regulations.

Pennsylvania state regulators and the natural gas industry are also facing challenges regarding how to ensure proper disposal of the millions of gallons of chemical-laced wastewater generated daily from hydraulic fracturing and gas production in the Marcellus shale.

Drinking water treatment facilities in Pennsylvania are not equipped to treat and remove many flowback contaminants, but rather, rely on dilution of chlorides, sulfates and other chemicals in surface waters used for drinking water supplies.

During the fall of 2008, the disposal of large volumes of flowback and produced water at publicly owned treatment works (POTWs) contributed to high total dissolved solids (TDS) levels measured in Pennsylvania’s Monongahela River and its tributaries. Studies showed that in addition to the Monongahela River, many of the other rivers and streams in Pennsylvania had a very limited ability to assimilate additional TDS, sulfate and chlorides, and that the high concentrations of these constituents were harming aquatic communities. Research by Carnegie Mellon University and Pittsburgh Water and Sewer Authority experts suggests that the natural gas industry has contributed to elevated levels of bromide in the Allegheny and Beaver Rivers.  Bromides react with disinfectants used by municipal treatment plants to create brominated trihalomethanes, which have been linked to several types of cancer and birth defects.

In August of 2010, Pennsylvania enacted new rules limiting the discharge of wastewater from gas drilling to 500 milligrams per liter of total dissolved solids (TDS) and 250 milligrams per liter for chlorides.  The number of municipal facilities allowed to take drilling and fracking wastewater has dropped from 27 in 2010 to 15 in 2011.

Disposal of drilling and fracking waste water is going to continue to present a challenge to local and state governments as more wells are developed across the country.

Chemical Disclosure

One potentially frustrating issue for surface owners is that it has not been easy to find out what chemicals are being used during the hydraulic fracturing operations in your neighborhood. According to the Natural Resources Defense Council, in the late 1990s and early 2000s attempts by various environmental and ranching advocacy organizations to obtain chemical compositions of hydraulic fracturing fluids were largely unsuccessful because oil and gas companies refused to reveal this "proprietary information."

In the mid-2000s, the Oil and Gas Accountability Project and The Endocrine Disruption Exchange (TEDX) began to compile information on drilling and fracturing chemicals from a number of sources, including Material Safety Data Sheets obtained through Freedom of Information Act requests of state agencies. TEDX subsequently produced reports on the toxic chemicals used in oil and gas development in several western states including Montana, New Mexico, Wyoming and Colorado, and worked with the Environmental Working Group to produce a report on chemicals injected into oil and gas wells in Colorado.

In 2006, the first effort to require disclosure of chemicals was launched. In June of 2006, the Oil and Gas Accountability Project submitted a letter to the Colorado Oil and Gas Conservation Commission (COGCC) and the Colorado Department of Public Health and the Environment (CDPHE) on behalf of five citizens organizations in Colorado.  The groups asked that state agencies require disclosure of the chemicals used and monitoring of chemicals and wastes released by the oil and gas industry in Colorado.
Since that time the Oil and Gas Accountability Project and others have worked to get disclosure bills passed in states across the country. Wyoming, Arkansas, Pennsylvania, Michigan and Texas now require a certain level of disclosure, although trade secret laws still prevent full disclosure in most states.

Hydraulic Fracturing Best Practices

From a public health perspective, if hydraulic fracturing stimulation takes place, the best option is to fracture formations using sand and water without any additives, or sand and water with non-toxic additives. Non-toxic additives are being used by the offshore oil and gas industry, which has had to develop fracturing fluids that are non-toxic to marine organisms.

It is common to use diesel in hydraulic fracturing fluids. This should be avoided, since diesel contains the carcinogen benzene, as well as other harmful chemicals such as naphthalene, toluene, ethylbenzene and xylene.

According to the company Halliburton, "Diesel does not enhance the efficiency of the fracturing fluid; it is merely a component of the delivery system." It is technologically feasible to replace diesel with non-toxic "delivery systems," such as plain water. According to the EPA, "Water-based alternatives exist and from an environmental perspective, these water-based products are preferable."

Torn pit liners can lead to
groundwater contamination.

Oil and gas wastes are often flowed back to and stored in pits on the surface. Often these pits are unlined. But even if they are lined, the liners can tear and contaminate soil and possibly groundwater with toxic chemicals. (Read more about pits.)

As mentioned above, toxic chemicals are used during hydraulic fracturing operations. The same chemicals that are injected come back to the surface in the flowed-back wastes. As well, hydrocarbons from the fractured formation may flow back into the waste pits. A preferable way of storing wastes would be to flow them back into steel tanks.

Tips for Landowners

Obtaining fracking chemical information: The law requires that all employees have access to a Material Safety Data Sheet (MSDS), which contains information on health hazards, chemical ingredients, physical characteristics, control measures, and special handling procedures for all hazardous substances in the work area. The MSDSs are produced and distributed by the chemical manufacturers and distributors. It should be noted that MSDSs may not list all of the chemicals or chemical constituents being used (if they are trade secrets). Landowners may be able to obtain copies of MSDSs from company employees, the chemical manufacturers, or possibly from state agency representatives.

Prior to the enactment of some state laws regarding the disclosure of hydraulic fracturing and other drilling chemicals, there were two sources of information on chemicals used during oil and gas development. These sources were:  Material Safety Data Sheets and Tier II reports.  Now, limited chemical information can be obtained, as well, via web sites such as Frac Focus or state agency sites.  But criticisms have been raised regarding fracturing fluid registries, such as they do not provide enough detailed information on chemical concentrations and volumes, nor do they provide information in a format that is easy to use.

• Matearial Safety Data Sheets (MSDSs):  The law requires that all employees have access to Material Safety Data Sheets, which contain information on health hazards, chemical ingredients, physical characteristics, control measures, and special handling procedures for all hazardous substances in the work area. MSDSs are produced and distributed by the chemical manufacturers and distributors. Citizens may be able to obtain copies of MSDSs from company employees, chemical manufacturers, local or state agency representatives, or via some web sites.
• Tier II Reports: The federal Emergency Planning and Community Right-to-Know Act (EPCRA) requires facilities that store chemicals to report products that contain hazardous substances. Some chemicals do not have to be reported, if they are below a certain threshold.

Theo Colborn of The Endocrine Disruption Exchange has enumerated several problems with the information in MSDS and Tier II reports.

MSDSs and Tier II reports are fraught with gaps in information about the formulation of the products. The U.S. Occupational Safety and Health Administration (OSHA) provides only general guidelines for the format and content of MSDSs. The manufacturers of the products are left to determine what information is revealed on their MSDSs. The forms are not submitted to OSHA for review unless they are part of an inspection under the Hazard Communication Standard (U.S. Department of Labor 1998). Some MSDSs report little to no information about the chemical composition of a product. Those MSDSs that do may only report a fraction of the total composition, sometimes less than 0.1%. Some MSDSs provide only a general description of the content, such as “plasticizer”, “polymer”, while others describe the ingredients as “proprietary” or just a chemical class. Under the present regulatory system all of the above “identifiers” are permissible. Consequently, it is not surprising that a study by the U.S. General Accounting Office (1991) revealed that MSDSs could easily be inaccurate and incomplete. Tier II reports can be similarly uninformative, as reporting requirements vary from state to state, county to county, and company to company. Some Tier II forms include only a functional category name (e.g., “weight materials” or “biocides”) with no product name. The percent of the total composition of the product is rarely reported on these forms.

The oil and gas industry is the only industry in America that is allowed by EPA to inject known hazardous materials -- unchecked -- directly into or adjacent to underground drinking water supplies.

This exemption from the SDWA has become known as the "Halliburton loophole" because it is widely perceived to have come about as a result of the efforts of Vice President Dick Cheney's Energy Task Force.

Before taking office, Cheney was CEO of Halliburton -- which patented hydraulic fracturing in the 1940s, and remains one of the three largest manufacturers of fracturing fluids. Halliburton staff were actively involved in review of the 2004 EPA report on hydraulic fracturing.

State regulation

Several oil and gas producing states have regulations governing some aspects of hydraulic fracturing, but they rarely, if ever, do they require companies to provide detailed information on types and quantities of chemicals being used, and whether the amount injected underground returns to the surface or remains underground.

Additionally, in most states companies do not have to prove that fractures have stayed within the target formations. Nor do companies have to monitor water quality when there are drinking water formations in close proximity to areas where hydraulic fracturing occurs.

The history of federal regulation

In 1997, the U.S. Court of Appeals for the 11th Circuit (Atlanta) ordered the EPA to regulate hydraulic fracturing under the Safe Drinking Water Act. This decision followed a 1989 CBM fracturing operation in Alabama that landowners say contaminated a residential water well.

In 2000, in response to the 1997 court decision, the EPA initiated a study of the threats to water supplies associated with the fracturing of coal seams for methane production. The primary goal of the study was to assess the potential for fracturing to contaminate underground drinking water supplies.

Meanwhile, in 2001, a special task force on energy policy convened by Vice President Dick Cheney recommended that Congress exempt hydraulic fracturing from the Safe Drinking Water Act.

The EPA completed its study in 2004, finding that fracturing "poses little or no threat" to drinking water. The EPA also concluded that no further study of hydraulic fracturing was necessary.

The 2004 EPA study has been called "scientifically unsound" by EPA whistleblower Weston Wilson. In an October 2004 letter to Colorado's congressional delegation, Wilson recommended that EPA continue investigating hydraulic fracturing and form a new peer review panel that would be less heavily weighted with members of the regulated industry. In March of 2005, EPA Inspector General Nikki Tinsley found enough evidence of potential mishandling of the EPA hydraulic fracturing study to justify a review of Wilson's complaints.

The Oil and Gas Accountability Project (OGAP) has conducted a review of the EPA study. As reported in Our Drinking Water at Risk, we found that EPA removed information from earlier drafts that suggested unregulated fracturing poses a threat to human health, and that the Agency did not include information that suggests fracturing fluids may pose a threat to drinking water long after drilling operations are completed.

OGAP's review of relevant data on hydraulic fracturing suggests that there is insufficient information for EPA to have concluded that hydraulic fracturing does not pose a threat to drinking water.

Efforts to close the Halliburton loophole

In 2005, a national energy bill included the exemption of hydraulic fracturing from the Safe Drinking Water Act. This bill passed, with the exemption, although it left the door open for the EPA to regulate the use of diesel in hydraulic fracturing operations.

Representatives DeGette, Salazar and Hinchey, and Senators Casey and Schumer have introduced legislation to protect drinking water from oil and gas development -- including ending hydraulic fracturing's exemption to the Safe Drinking Water Act.

H.R. 1084 and S. 587, the Fracking Responsibility and Awareness of Chemicals Act (FRAC Act), would close the Halliburton loophole and require oil and gas companies to disclose the chemicals they use during the fracking process.

Local governments have written resolutions and letters supporting ending the hydraulic fracturing exemption to the Safe Drinking Water Act and requiring public disclosure of hydraulic fracturing chemicals.