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Photo by Pat Sullivan/AP https://www.houstonchronicle.com/news/houston-texas/houston/article/Fracking-research-hits-roadblock-with-Texas-law-6812820.php

California regulators need to protect groundwater from oil and gas waste this time around

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

California’s 2nd Largest Waste Stream

Every year the oil and gas industry in California generates billions of gallons of wastewater, also known as produced water. According to a study by the California Council on Science and Technology, in 2013, more than 3 billion barrels of produced water were extracted along with some 0.2 billion barrels of oil across the state. This wastewater is usually contaminated with a mixture of heavy metals, hydrocarbons, naturally occurring radioactive materials, and high levels of salts. Yet, contaminated wastewater from oil-field operations is exempt from the hazardous waste regulations enforced by the Resource Conservation and Recovery Act (RCRA).

Operators are, therefore, not required to measure or report the chemistry of this wastewater. Even with these unknowns, it is legally re-injected back into groundwater aquifers for disposal. Once an aquifer is contaminated it can be extremely difficult, if not impossible, to clean up again. Particularly in California, where water resources are already stretched thin, underground injection of oil and gas wastewater is a major environmental and economic concern.

Regulatory Deficiency

Under the Underground Injection Control program, wastewater is supposed to be injected only into geologic formations that don’t contain usable groundwater. However, a loophole in the Safe Drinking Water Act allows oil and gas companies to apply for what’s called an aquifer exemption, which allows them to inject wastewater into aquifers that potentially hold high-quality drinking water. To learn more about aquifer exemptions, see FracTracker’s summary, here.

The California department responsible for managing these aquifer exemption permits – the Division of Oil, Gas, and Geothermal Resources (DOGGR) – has for decades failed in its regulatory capacity. In 2015, for example, DOGGR admitted that at least 2,553 wells had been permitted to inject oil and gas waste into non-exempt aquifers – aquifers that could be used for drinking water. Independent audits of DOGGR showed decades of poor record-keeping, lax oversight, and in some cases, outright defiance of the law – showing the cozy relationship between regulators and the oil and gas industry. While 176 wells (those that were injecting into the cleanest drinking water) were initially shut down, most of the rest of the 2,377 permits were allowed to continue injecting into disputed wells through the following two years of the regulatory process.

The injection wells targeted by the Environmental Protection Agency (EPA), including those that were shut down, are shown in the map below (Figure 1).

Figure 1. Map of EPA-targeted Class II Injection Wells


View map fullscreen | How FracTracker maps work | Map Data (CSV): Aquifer Exemptions, Class II Wells

The timeline of all this is just as concerning. The State of California has known about these problems since 2011, when the EPA audited California’s underground injection program and identified substantial deficiencies in its program, including failure to protect some potential underground sources of drinking water, a one-size-fits-all geologic review, and inadequate and under-qualified staffing for carrying out inspections. In 2014, the Governor’s office requested that the California EPA perform an independent review of the program. EPA subsequently made a specific remediation plan and timeline for DOGGR, and in March of 2015 the State finalized a Corrective Action Plan, to be completed by February 2017.

Scientific Review of CA Oil and Gas Activities

Meanwhile, in 2013, the California Senate passed SB-4, which set a framework for regulating hydraulic fracturing in California. Part of the bill required an independent scientific study to be conducted on oil and gas well stimulation, including acid well stimulation and hydraulic fracturing. The California Council on Science and Technology organized and led the study, in collaboration with the Lawrence Berkeley National Laboratories, which combined original technical data analyses and a review of relevant literature, all of which was extensively peer-reviewed. The report argues that both direct and indirect impacts of fracking must be accounted for, and that major deficiencies and inconsistencies in data remained which made research difficult. They also recommended that DOGGR improve and modernize their record keeping to be more transparent.

Figure 2. Depths of groundwater total dissolved solids (a common measure of groundwater quality) in five oil fields in the Los Angeles Basin. Blue and aqua colors represent protected groundwater; the heavy black horizontal line indicates the shallowest hydraulically fractured well in each field. In three of the five wells (Inglewood, Whittier, and Wilmington), fracking and wastewater injection takes place directly adjacent to, or within, protected groundwater.

Figure 2*. Depths of groundwater total dissolved solids (a common measure of groundwater quality) in five oil fields in the Los Angeles Basin. Blue and aqua colors represent protected groundwater; the heavy black horizontal line indicates the shallowest hydraulically fractured well in each field. In three of the five wells (Inglewood, Whittier, and Wilmington), fracking and wastewater injection takes place directly adjacent to, or within, protected groundwater.

A major component of the SB-4 report covered California’s Class II injection program. Researchers analyzed the depths of groundwater aquifers protected by the Safe Drinking Water Act, and found that injection and hydraulic fracturing activity was occurring within the same or neighboring geological zones as protected drinking water (Figure 2*).

*Reproduced from California Council on Science and Technology: An Independent Scientific Assessment of Well Stimulation in California Vol. 3.

More Exemptions to be Granted

Now, EPA is re-granting exemptions again. Six aquifer exemptions have been granted, and more are on the docket to be considered. In this second time around, it is imperative that regulatory agencies be more diligent in their oversight of this permitting process to protect groundwater resources. At the same time, the 2015 California bill SB 83 mandates the appointment of an independent review panel to evaluate the Underground Injection Control Program and to make recommendations on how to improve the effectiveness of the program. This process is currently in the works and a panel has been assembled, and FracTracker Alliance will be working to provide data, maps and analyses for this panel.

Stay tuned for more to come on which aquifers are being exempted, why, and what steps are being taken to protect groundwater in California.


Feature image by Pat Sullivan/AP

JOSHUA DOUBEK / WIKIMEDIA COMMONS

Groundwater risks in Colorado due to Safe Drinking Water Act exemptions

Oil and gas operators are polluting groundwater in Colorado, and the state and U.S. EPA are granting them permission with exemptions from the Safe Drinking Water Act.

FracTracker Alliance’s newest analysis attempts to identify groundwater risks in Colorado groundwater from the injection of oil and gas waste. Specifically, we look at groundwater monitoring data near Class II underground injection control (UIC) disposal wells and in areas that have been granted aquifer exemptions from the underground source of drinking water rules of the Safe Drinking Water Act (SDWA). Momentum to remove amend the SDWA and remove these exemption.

Learn more about Class II injection wells.

Aquifer exemptions are granted to allow corporations to inject hazardous wastewater into groundwater aquifers. The majority, two-thirds, of these injection wells are Class II, specifically for oil and gas wastes.

What exactly are aquifer exemptions?

The results of this assessment provide insight into high-risk issues with aquifer exemptions and Class II UIC well permitting standards in Colorado. We identify areas where aquifer exemptions have been granted in high quality groundwater formations, and where deep underground aquifers are at risk or have become contaminated from Class II disposal wells that may have failed.

Of note: On March 23, 2016, NRDC submitted a formal petition urging the EPA to repeal or amend the aquifer exemption rules to protect drinking water sources and uphold the Safe Drinking Water Act. Learn more

Research shows injection wells do fail

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Class II injection well in Colorado explodes and catches fire. Photo by Kelsey Brunner for the Greeley Tribune.

Disposal of oil and gas wastewater by underground injection has not yet been specifically researched as a source of systemic groundwater contamination nationally or on a state level. Regardless, this issue is particularly pertinent to Colorado, since there are about 3,300 aquifer exemptions in the US (view map), and the majority of these are located in Montana, Wyoming, and Colorado. There is both a physical risk of danger as well as the risk of groundwater contamination. The picture to the right shows an explosion of a Class II injection well in Greeley, CO, for example.

Applicable and existing research on injection wells shows that a risk of groundwater contamination of – not wastewater – but migrated methane due to a leak from an injection well was estimated to be between 0.12 percent of all the water wells in the Colorado region, and was measured at 4.5 percent of the water wells that were tested in the study.

A recent article by ProPublica quoted Mario Salazar, an engineer who worked for 25 years as a technical expert with the EPA’s underground injection program in Washington:

In 10 to 100 years we are going to find out that most of our groundwater is polluted … A lot of people are going to get sick, and a lot of people may die.

Also in the ProPublic article was a study by Abrahm Lustgarten, wherein he reviewed well records and data from more than 220,000 oil and gas well inspections, and found:

  1. Structural failures inside injection wells are routine.
  2. Between 2007-2010, one in six injection wells received a well integrity violation.
  3. More than 7,000 production and injection wells showed signs of well casing failures and leakage.

This means disposal wells can and do fail regularly, putting groundwater at risk. According to Chester Rail, noted groundwater contamination textbook author:

…groundwater contamination problems related to the subsurface disposal of liquid wastes by deep-well injection have been reviewed in the literature since 1950 (Morganwalp, 1993) and groundwater contamination accordingly is a serious problem.

According to his textbook, a 1974 U.S. EPA report specifically warns of the risk of corrosion by oil and gas waste brines on handling equipment and within the wells. The potential effects of injection wells on groundwater can even be reviewed in the U.S. EPA publications (1976, 1996, 1997).

As early as 1969, researchers Evans and Bradford, who reported on the dangers that could occur from earthquakes on injection wells near Denver in 1966, had warned that deep well injection techniques offered temporary and not long-term safety from the permanent toxic wastes injected.

Will existing Class II wells fail?

For those that might consider data and literature on wells from the 1960’s as being unrepresentative of activities occurring today, of the 587 wells reported by the Colorado’s oil and gas regulatory body, COGCC, as “injecting,” 161 of those wells were drilled prior to 1980. And 104 were drilled prior to 1960!

Wells drilled prior to 1980 are most likely to use engineering standards that result in “single-point-of-failure” well casings. As outlined in the recent report from researchers at Harvard on underground natural gas storage wells, these single-point-of-failure wells are at a higher risk of leaking.

It is also important to note that the U.S. EPA reports only 569 injection wells for Colorado, 373 of which may be disposal wells. This is a discrepancy from the number of injection wells reported by the COGCC.

Aquifer Exemptions in Colorado

According to COGCC, prior to granting a permit for a Class II injection well, an aquifer exemption is required if the aquifer’s groundwater test shows total dissolved solids (TDS) is between 3,000 and 10,000 milligrams per liter (mg/l). For those aquifer exemptions that are simply deeper than the majority of current groundwater wells, the right conditions, such as drought, or the needs of the future may require drilling deeper or treating high TDS waters for drinking and irrigation. How the state of Colorado or the U.S. EPA accounts for economic viability is therefore ill-conceived.

Data Note: The data for the following analysis came by way of FOIA request by Clean Water Action focused on the aquifer exemption permitting process. The FOIA returned additional data not reported by the US EPA in the public dataset. That dataset contained target formation sampling data that included TDS values. The FOIA documents were attached to the EPA dataset using GIS techniques. These GIS files can be found for download in the link at the bottom of this page.

Map 1. Aquifer exemptions in Colorado

View map fullscreen | How FracTracker maps work

Map 1 above shows the locations of aquifer exemptions in Colorado, as well as the locations of Class II injection wells. These sites are overlaid on a spatial assessment of groundwater quality (a map of the groundwater’s quality), which was generated for the entire state. The changing colors on the map’s background show spatial trends of TDS values, a general indicator of overall groundwater quality.

In Map 1 above, we see that the majority of Class II injection wells and aquifer exemptions are located in regions with higher quality water. This is a common trend across the state, and needs to be addressed.

Our review of aquifer exemption data in Colorado shows that aquifer exemption applications were granted for areas reporting TDS values less than 3,000 mg/l, which contradicts the information reported by the COGCC as permitting guidelines. Additionally, of the 175 granted aquifer exemptions for which the FOIA returned data, 141 were formations with groundwater samples reported at less than 10,000 mg/l TDS. This is half of the total number (283) of aquifer exemptions in the state of Colorado.

When we mapped where class II injection wells are permitted, a total of 587 class II wells were identified in Colorado, outside of an aquifer exemption area. Of the UIC-approved injection wells identified specifically as disposal wells, at least 21 were permitted outside aquifer exemptions and were drilled into formations that were not hydrocarbon producing. Why these injection wells are allowed to operate outside of an aquifer exemption is unknown – a question for regulators.

You can see in the map that most of the aquifer exemptions and injection wells in Colorado are located in areas with lower TDS values. We then used GIS to conduct a spatial analysis that selected groundwater wells within five miles of the 21 that were permitted outside aquifer exemptions. Results show that groundwater wells near these sites had consistently low-TDS values, meaning good water quality. In Colorado, where groundwater is an important commodity for a booming agricultural industry and growing cities that need to prioritize municipal sources, permitting a Class II disposal well in areas with high quality groundwater is irresponsible.

Groundwater Monitoring Data Maps

Map 2. Water quality and depths of groundwater wells in Colorado
Groundwater risks in Colorado - Map 2
View live map | How FracTracker maps work

In Map 2, above, the locations of groundwater wells in Colorado are shown. The colors of the dots represent the concentration of TDS on the right and well depth on the left side of the screen. By sliding the bar on the map, users can visualize both. This feature allows people to explore where deep wells also are characterized by high levels of TDS. Users can also see that areas with high quality low TDS groundwater are the same areas that are the most developed with oil and gas production wells and Class II injection wells, shown in gradients of purple.

Statistical analysis of this spatial data gives a clearer picture of which regions are of particular concern; see below in Map 3.

Map 3. Spatial “hot-spot” analysis of groundwater quality and depth of groundwater wells in Colorado
Groundwater risks in Colorado - Map 3
View live map | How FracTracker maps work

In Map 3, above, the data visualized in Map 2 were input into a hot-spots analysis, highlighting where high and low values of TDS and depth differ significantly from the rest of the data. The region of the Front Range near Denver has significantly deeper wells, as a result of population density and the need to drill municipal groundwater wells.

The Front Range is, therefore, a high-risk region for the development of oil and gas, particularly from Class II injection wells that are necessary to support development.

Methods Notes: The COGCC publishes groundwater monitoring data for the state of Colorado, and groundwater data is also compiled nationally by the Advisory Committee on Water Information (ACWI). (Data from the National Groundwater Monitoring Network is sponsored by the ACWI Subcommittee on Ground Water.) These datasets were cleaned, combined, revised, and queried to develop FracTracker’s dataset of Colorado groundwater wells. We cleaned the data by removing sites without coordinates. Duplicates in the data set were removed by selecting for the deepest well sample. Our dataset of water wells consisted of 5,620 wells. Depth data was reported for 3,925 wells. We combined this dataset with groundwater data exported from ACWI. Final count for total wells with TDS data was 11,754 wells. Depth data was reported for 7,984 wells. The GIS files can be downloaded in the compressed folder at the bottom of this page.

Site Assessments – Exploring Specific Regions

Particular regions were further investigated for impacts to groundwater, and to identify areas that may be at a high risk of contamination. There are numerous ways that groundwater wells can be contaminated from other underground activity, such as hydrocarbon exploration and production or waste injection and disposal. Contamination could be from hydraulic fracturing fluids, methane, other hydrocarbons, or from formation brines.

From the literature, brines and methane are the most common contaminants. This analysis focuses on potential contamination events from brines, which can be detected by measuring TDS, a general measure for the mixture of minerals, salts, metals and other ions dissolved in waters. Brines from hydrocarbon-producing formations may include heavy metals, radionuclides, and small amounts of organic matter.

Wells with high or increasing levels of TDS are a red flag for potential contamination events.

Methods

Groundwater wells at deep depths with high TDS readings are, therefore, the focus of this assessment. Using GIS methods we screened our dataset of groundwater wells to only identify those located within a buffer zone of five miles from Class II injection wells. This distance was chosen based on a conservative model for groundwater contamination events, as well as the number of returned sample groundwater wells and the time and resources necessary for analysis. We then filtered the groundwater wells dataset for high TDS values and deep well depths to assess for potential impacts that already exist. We, of course, explored the data as we explored the spatial relationships. We prioritized areas that suggested trends in high TDS readings, and then identified individual wells in these areas. The data initially visualized were the most recent sampling events. For the wells prioritized, prior sampling events were pulled from the data. The results were graphed to see how the groundwater quality has changed over time.

Case of Increasing TDS Readings

If you zoom to the southwest section of Colorado in Map 2, you can see that groundwater wells located near the injection well 1 Fasset SWD (EPA) (05-067-08397) by Operator Elm Ridge Exploration Company LLC were disproportionately high (common). Groundwater wells located near this injection well were selected for, and longitudinal TDS readings were plotted to look for trends in time. (Figure 1.)

The graphs in Figure 1, below, show a consistent increase of TDS values in wells near the injection activity. While the trends are apparent, the data is limited by low numbers of repeated samples at each well, and the majority of these groundwater wells have not been sampled in the last 10 years. With the increased use of well stimulation and enhanced oil recovery techniques over the course of the last 10 years, the volumes of injected wastewater has also increased. The impacts may, therefore, be greater than documented here.

This area deserves additional sampling and monitoring to assess whether contamination has occurred.


Figures 1a and 1b. The graphs above show increasing TDS values in samples from groundwater wells in close proximity to the 1 Fassett SWD wellsite, between the years 2004-2015. Each well is labeled with a different color. The data for the USGS well in the graph on the right was not included with the other groundwater wells due to the difference in magnitude of TDS values (it would have been off the chart).

Groundwater Contamination Case in 2007

We also uncovered a situation where a disposal well caused groundwater contamination. Well records for Class II injection wells in the southeast corner of Colorado were reviewed in response to significantly high readings of TDS values in groundwater wells surrounding the Mckinley #1-20-WD disposal well.

When the disposal well was first permitted, farmers and ranchers neighboring the well site petitioned to block the permit. Language in the grant application is shown below in Figure 2. The petitioners identified the target formation as their source of water for drinking, watering livestock, and irrigation. Regardless of this petition, the injection well was approved. Figure 3 shows the language used by the operator Energy Alliance Company (EAC) for the permit approval, which directly contradicts the information provided by the community surrounding the wellsite. Nevertheless, the Class II disposal well was approved, and failed and leaked in 2007, leading to the high TDS readings in the groundwater in this region.

co_classiipetition

Figure 2. Petition by local landowners opposing the use of their drinking water source formation for the site of a Class II injection disposal well.

 

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Figure 3. The oil and gas operation EAC claims the Glorietta formation is not a viable fresh water source, directly contradicting the neighboring farmers and ranchers who rely on it.

co_fieldinspectionreport_leak

Figure 4. The COGCC well log report shows a casing failure, and as a result a leak that contaminated groundwater in the region.

Areas where lack of data restricted analyses

In other areas of Colorado, the lack of recent sampling data and longitudinal sampling schemes made it even more difficult to track potential contamination events. For these regions, FracTracker recommends more thorough sampling by the regulatory agencies COGCC and USGS. This includes much of the state, as described below.

Southeastern Colorado

Our review of the groundwater data in southeastern Colorado showed a risk of contamination considering the overlap of injection well depths with the depths of drinking water wells. Oil and gas extraction and Class II injections are permitted where the aquifers include the Raton formation, Vermejo Formation, Poison Canyon Formation and Trinidad Sandstone. Groundwater samples were taken at depths up to 2,200 ft with a TDS value of 385 mg/l. At shallower depths, TDS values in these formations reached as high as 6,000 mg/l, and 15 disposal wells are permitted in aquifer exemptions in this region. Injections in this area start at around 4,200 ft.

In Southwestern Colorado, groundwater wells in the San Jose Formation are drilled to documented depths of up to 6,000 feet with TDS values near 2,000 mg/l. Injection wells in this region begin at 565 feet, and those used specifically for disposal begin at below 5,000 feet in areas with aquifer exemptions. There are also four disposal wells outside of aquifer exemptions injecting at 5,844 feet, two of which are not injecting into active production zones at depths of 7,600 and 9,100 feet.

Western Colorado

In western Colorado well Number 1-32D VANETA (05-057-06467) by Operator Sandridge Exploration and Production LLC’s North Park Horizontal Niobara Field in the Dakota-Lokota Formation has an aquifer exemption. The sampling data from two groundwater wells to the southeast, near Coalmont, CO, were reviewed, but we can’t get a good picture due to the lack of repeat sampling.

Northwestern Colorado

http://digital.denverlibrary.org/cdm/ref/collection/p16079coll32/id/346073

A crew from Bonanza Creek repairs an existing well in the McCallum oil field. Photo by Ken Papaleo / Rocky Mountain News

In Northwestern Colorado near Walden, CO and the McCallum oil field, two groundwater wells with TDS above 10,000 ppm were selected for review. There are 21 injection wells in the McCallum field to the northwest. Beyond the McCallum field is the Battleship field with two wastewater disposal wells with an aquifer exemption. West of Grover, Colorado, there are several wells with high TDS values reported for shallow wells. Similar trends can be seen near Vernon. The data on these wells and wells from along the northern section of the Front Range, which includes the communities of Fort Collins, Greeley, and Longmont, suffered from the same issue. Lack of deep groundwater well data coupled with the lack of repeat samples, as well as recent sampling inhibited the ability to thoroughly investigate the threat of contamination.

Trends and Future Development

Current trends in exploration and development of unconventional resources show the industry branching southwest of Weld County towards Fort Collins, Longmont, Broomfield and Boulder, CO.

These regions are more densely populated than the Front Range county of Weld, and as can be seen in the maps, the drinking water wells that access groundwaters in these regions are some of the deepest in the state.

This analysis shows where Class II injection has already contaminated groundwater resources in Colorado. The region where the contamination has occurred is not unique; the drinking water wells are not particularly deep, and the density of Class II wells is far from the highest in the state.

Well casing failures and other injection issues are not exactly predictable due to the variety of conditions that can lead to a well casing failure or blow-out scenario, but they are systemic. The result is a hazardous scenario where it is currently difficult to mitigate risk after the injection wells are drilled.

Allowing Class II wells to expand into Front Range communities that rely on deep wells for municipal supplies is irresponsible and dangerous.

The encroachment of extraction into these regions, coupled with the support of Class II injection wells to handle the wastewater, would put these groundwater wells at particular risk of contamination. Based on this analysis, we recommend that regulators take extra care to avoid permitting Class II wells in these regions as the oil and gas industry expands into new areas of the Front Range, particularly in areas with dense populations.


Feature Image: Joshua Doubek / WIKIMEDIA COMMONS

Article by: Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

 

October 31, 2017 Edit: This post originally cited the Clean Water Act instead of the Safe Drinking Water Act as the source that EPA uses to grant aquifer exemptions.

Oil and Gas Wastes are Radioactive – and Lack Regulatory Oversight

Highlighting the maps of radioactive oil and gas exploration and production wastes created in collaboration with the Western Organization of Research Councils

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance
Scott Skokos, Western Organization of Research Councils

Oil and gas waste can be radioactive, but it is not considered “hazardous,” at least according to the federal government. In this article, we summarize several of the hazardous risks resulting from the current federal policy that fails to regulate this massive waste stream, and the gaps left by states. Of the six states mapped in this assessment, only the state of Montana has initiated any type of rule-making process to manage the waste.

When it comes to unconventional oil and gas waste streams:

Nobody can say how much of any type of waste is being produced, what it is, and where it’s ending up. – Nadia Steinzor, Earthworks

To address some of these gaps, FracTracker Alliance has been working with the Western Organization of Resources Councils (WORC) to map out exactly where radioactive oil and wastes are being dumped, stored, and injected into the ground for disposal. The work is an extension to WORC’s comprehensive No Time to Waste report.

Why is accurate waste data so hard to come by? The Earthworks report, Wasting Away explains that the U.S. EPA intentionally exempted oil and gas exploration and production wastes from the federal regulations known as the Resource Conservation and Recovery Act (RCRA) despite concluding that such wastes “contain a wide variety of hazardous constituents.” As a result, there is very little waste tracking and reporting of oil and gas waste data nationally.

State Waste Management Maps

Some data is available at the state level, so we at FracTracker have compiled, cleaned, and mapped what little data we could find.

State-specific maps have been created for Montana, North Dakota, Colorado, and Wyoming – see below:

ND Radioactive Waste mapNorth Dakota – View map fullscreen

co-radioactive-featureColorado – View map fullscreen

Sources of Radioactivity

When we hear about “radioactive waste” associated with the energy industry, nuclear power stations and fission reactors are usually what come to mind. But, as the EPA explains, fracking has transformed the nature of the oil and gas waste stream. Components of fracking waste differ from conventional oil and gas exploration and production wastes in a number of ways:

  • In general, the waste stream has additional hazardous components, and that transformation includes increased radioactivity.
  • Fracking has allowed for more intrusive drilling, penetrating deep sedimentary formations using millions of gallons of fluid.
  • Drilling deeper produces more drill cuttings.
  • The process of hydraulic fracking introduces millions more gallons of fluid into the ground that then return to the surface. These returns are ultimately contaminated and require disposal.
  • The formations targeted for unconventional development are mostly ancient seabeds still filled with salty “brines” known as “formation waters.”
  • In addition to the hazardous chemicals in the fracking fluid pumped into the wells for fracking, these unconventional formations contain larger amounts of heavy metals, carcinogens and other toxics. This also includes more radioisotopes such as Uranium, Thorium, Radium, Potassium-40, Lead-210, and Polonium-210 than the conventional formations that have supplied the majority of oil and gas prior to the shale boom.

A variety of waste products make up the waste stream of oil and gas development, and each is enhanced with naturally occurring radioactive materials (NORM). This waste stream must be treated and disposed of properly. All the oil and gas equipment – such as production equipment, processing equipment, produced water handing equipment, and waste management equipment – also need to be considered as sources of radioactive exposure.

Figure 1 below explains where the waste from fracking goes after it leaves the well pad.

Radioactive Oil and Gas Pathway Life Cycle

Figure 1. Breakdown of the radioactive oil and gas waste life-cycle

Three facets of the waste stream particularly enhanced with NORMs by fracking include scales, produced waters, and sludges.

A. Scales

When injected into the ground, fracking fluid mixes with formation waters, dissolving metals, radioisotopes and other inorganic compounds. Additionally the fracking liquids are often supplemented with strong acids to reduce “scaling” from precipitate build up (to prevent clogging up the well). Regardless, each oil well generates approximately 100 tons of radioactive scale annually. As each oil and gas reservoir is drained, the amount of scale increases. The EPA reports that lead-210 and polonium-210 are commonly found in scales along with their decay product radon at concentrations estimated to be anywhere from 480 picocuries per gram (pCi/g) to 400,000 pCi/g). Scale can be disposed of as a solid waste, or dissolved using “scale inhibitors.” These radioactive elements then end up in the liquid waste portion of the waste stream, known as produced waters.

B. Produced Waters

In California, strong acids are used to further dissolve formations to stimulate additional oil production. Acidic liquids are able to dissolve more inorganic elements and compounds such as radioisotopes. While uranium and thorium are not soluble in water, their radioactive decay products such as radium dissolve in the brines. The brines return to the surface as “produced water.” As the oil and gas in the formation are removed, much of what is pumped to the surface is formation water.

Consequently, declining oil and gas fields generate more produced water. The ratio of produced water to oil in conventional well was approximately 10 barrels of produced water per barrel of oil. According to the American Petroleum Institute (API), more than 18 billion barrels of waste fluids from oil and gas production are generated annually in the United States. There are several options for managing the liquid waste stream. The waste could be treated using waste treatment facilities, reinjected into other wells to enhance production (a cheaper option), or injected for disposal. Before disposal of the liquid portion, all the solids in the solution must be removed, resulting in a “sludge.”

C. Sludges

The U.S. EPA reports that conventional oil production alone produces 230,000 million tons – or five million ft3 (141 cubic meters) – of TENORM sludge each year. Unconventional processes produce much more sludge waste than conventional processes. The average concentration of radium in sludges is estimated to be 75 pCi/g, while the concentration of lead-210 can be over 27,000 pCi/g. Sludges present a high risk to the environment and a higher risk of exposure for people and other receptors in those environments because sludges are typically very water soluble.

Federal Exemptions

According to the EPA, “because the extraction process concentrates the naturally occurring radionuclides and exposes them to the surface environment and human contact, these wastes are classified as Technologically Enhanced Naturally Occurring Radioactive Material (TENORM).” Despite the conclusions that oil and gas TENORM pose a risk to the environment and humans, the EPA exempts oil and gas exploration and production wastes from the definition of “hazardous” under Resource Conservation and Recovery Act (RCRA) law. In fact, most wastes from all of the U.S. fossil fuel energy industry, including coal-burning and natural gas, are exempt from the disposal standards that hazardous waste normally requires.

The Center for Public Integrity calls this radioactive waste stream “orphan waste,” because no single government agency is fully managing it.

Fortunately, the EPA has acknowledged that federal regulations are currently inadequate, though this is nothing new. A U.S. EPA report from the 1980’s reported as much, and gave explicit recommendations to address the issue. For 30 years nothing happened! Then in August, 2015, a coalition of environmental groups (including the Environmental Integrity ProjectNatural Resources Defense CouncilEarthworksResponsible Drilling AllianceWest Virginia Surface Owners’ Rights Organization, and the Center for Health, Environment and Justice) filed a lawsuit against the EPA, and has since reached a settlement.

Just last month (January 10, 2017) the U.S. EPA agreed to review federal regulations of oil and gas waste – a process they were meant to do every 3 years for the last 30 years. The EPA has until March 15, 2019, to determine whether or not regulatory changes are warranted for “wastes associated with the exploration, development, or production of crude oil, natural gas, or geothermal energy.” With the recent freeze on all U.S. EPA grants, however, it is not clear whether these regulations will receive the review they need.

State Regulations

Regulation of this waste stream is left up to the states, but most states do not require operators to manage the radioactivity in oil and gas wastes, either. Because of the federal RCRA exemptions most state policies ignore the radioactive issue altogether. Operators are free to dispose of the waste at any landfill facility, unless the landfill tells them otherwise. For detailed analyses of state policies, see pages 10-45 of the No Time to Waste report. FracTracker has also covered these issues in Pennsylvania and Ohio.

Another issue that screams for federal consideration of this waste stream is that states do not have the authority to determine whether or not the wastes can cross their borders. States also do not have the jurisdiction to decide whether or not facilities in their state can accept waste from across state lines. That determination is reserved for federal jurisdiction, and there are not any federal laws regulating such wastes. In fact, these wastes are strategically exempt from federal regulation for just these reasons.

Why can’t the waste be treated?

This type of industrial waste actually cannot be treated, at least not entirely. Unlike organic pollutants that can be broken down, inorganic constituents of the waste cannot be simply disintegrated out of existence. Inorganic components include heavy metals like arsenic and bromides, as well as radioactive isotopes of radium, lead, and uranium. Such elements will continue to emit radiation for hundreds-to-thousands of years. The best option available is to find a location to “isolate” and dispose of these wastes – a sacrifice zone.

Current management practices do their best to separate the liquid portions from the solid portions, but that’s about it. Each portion can then be disposed independently of each other. Liquids are injected into the ground, which is the cheapest option where it is available. If enough of the dissolved components (heavy metals, salts, and radioisotopes) can be removed, wastewaters are discharged into surface waters. The compounds and elements that are removed from the liquid waste stream are hyper-concentrated in the solid portion of the waste, described as “sludge” in the graphic above. This hazardous material can be disposed of in municipal or solid waste landfills if the state regulators do not require the radioactivity or toxicity of this material to be a consideration for disposal. There are not federal requirements, so unless there is a specific state policy regarding the disposal, it can end up almost anywhere with little oversight. These chemicals do not magically disappear. They never disappear.

Risks

There are multiple pathways for contamination from facilities that are not qualified to manage radioactive and hazardous wastes. At least seven different environmental pathways provide potential risks for human exposure. They include:

  1. Radon inhalation,
  2. External gamma exposure,
  3. Groundwater ingestion,
  4. Surface water ingestion,
  5. Dust inhalation,
  6. Food ingestion, and
  7. Skin beta exposure from particles containing the radioisotopes.

According to the EPA, the low-level radioactive materials in drilling waste present a definitive risk to those exposed. High risk examples include dust suppression and leaching. If dust is not continuously suppressed, radioactive materials in dust pose a risk to people at these facilities or those receptors or secondary pathways located downwind of the facilities. Radioactive leachate entering surface waters and groundwaters is also a significant threat. A major consideration is that radioactive waste can last in these landfills far longer than the engineered lifespans of landfills, particularly those that are not designed to retain hazardous wastes.

Cases of Contamination

North Dakota

In North Dakota, the epicenter of the Bakken Oil Fields, regulators were not ready for the massive waste streams that came from the fast growing oil fields. This  allowed thousands of wastewater disposal wells be drilled to dispose of salty wastewater without much oversight, and no places in state for companies to dispose of radioactive solid waste. Many of the wastewater disposal wells were drilled haphazardly, and as a result many contaminated surrounding farmland with wastewater. With regard to radioactive solid waste, the state until recently had a de facto ban on solid radioactive waste disposal due to their radioactivity limit being 5 picocuries per gram. The result of this de facto ban made it so companies either had to make one of two decisions: 1. Haul their radioactive solid waste above the limit out of state to facilities in Idaho or Colorado; or 2. Risk getting caught illegally dumping waste in municipal landfills or just plain illegal dumping in roadsides, buildings, or farmland.

In 2014, a massive illegal dumping site was discovered in Noonan, ND when North Dakota regulators found a gas station full of radioactive waste and filter socks (the socks used to filter out solid waste from wastewater, which contain high levels of radioactivity). Following the Noonan, ND incident North Dakota regulators and politicians began discussions regarding the need for new regulations to address radioactive solid waste.

In 2015, North Dakota moved to create rules for the disposal of solid radioactive waste. Its new regulations increase the radioactivity limit from 5 picocuries per gram to 50 picocuries per gram, and sets up new requirements for the permitting of waste facilities accepting radioactive waste and the disposal of radioactive waste in the waste facilities. Dakota Resource Council, a member group of WORC, challenged the rules in the courts, arguing the rules are not protective enough and that the agency responsible for the rules pushed through the rules without following the proper procedures. Currently the rules are not in effect until the litigation is settled.

Pennsylvania

In Pennsylvania, the hotbed of activity for Marcellus Shale gas extraction, the regulatory body was ill equipped and uninformed for dealing with the new massive waste stream when it first arrived on scene. Through 2013, the majority of wastewater was disposed of in commercial and municipal wastewater treatment facilities that discharge to surface waters. Numerous facilities engaged in this practice without amending their federal discharge permits to include this new waste stream.

Waste treatment facilities in Pennsylvania tried to make the waste streams less innocuous by diluting the concentrations of these hazardous pollutants. They did this by mixing the fracking wastes with other waste streams, including industrial discharges and municipal waste. Other specialized facilities also tried to remove these dissolved inorganic elements and filter them from the discharge stream.

As a result of site assessments by yours-truly and additional academic research, these facilities realized that such hazardous compounds do not simply dilute into receiving waters such as the Allegheny, Monongahela, and Ohio rivers. Instead, they partition (settle) into sediments where they are hyper-concentrated. As a result of the lawsuits that followed the research, entire river bottoms in Pennsylvania had to be entirely dug up, removed, and disposed of in hazardous waste landfills.

Action Plans Needed

Massive amounts of solid and liquid wastes are still generated during drilling exploration and production from the Marcellus Shale. There is so much waste, operators don’t know what to do with it. In Pennsylvania, there is not much they can do with it, but it is not just Pennsylvania. Throughout the Ohio River Valley, operators struggle to dispose of this incredibly large waste stream.

Ohio, West Virginia, and Pennsylvania have all learned that this waste should not be allowed to be discharged to surface waters even after treatment. So it goes to other states – those without production or the regulatory framework to manage the wastes. Like every phase of production in the oil and gas industry, operators (drillers) shop around for the lowest disposal costs. In Estill County, Kentucky, the State Energy and Environment Department just recently cited the disposal company Advance Disposal Services Blue Ridge Landfill for illegally dumping hydraulic fracturing waste. The waste had traveled from West Virginia Marcellus wells, and ended up at an ignorant or willfully negligent waste facility.

In summary, there is inadequate federal oversight of potentially hazardous waste coming from the oil and gas industry, and there are serious regulatory gaps within and between states. Data management practices, too, are lacking. How then, is the public health community supposed to assess the risk that the waste stream poses to people? Obviously, a more thorough action plan is needed to address this issue.


Feature image: Drill cuttings being prepared to be hauled away from the well pad. Photo by Bill Hughes, OVEC

AG Pruitt testifies before a congressional committee on issues surrounding energy and the environment

“Polluting Pruitt:” A Wolf to Guard the Hen House?

Guest article by Dakota Raynes, Co-Organizer of Stop Fracking Payne County (OK)

President Trump recently tapped Oklahoma Attorney General Scott Pruitt to head the Environmental Protection Agency (EPA), even though Pruitt is a self-proclaimed “leading advocate against the EPA’s activist agenda.” Pruitt is currently opposing investigation of Exxon Mobile’s handling of climate-change science based on the belief that climate change science is not yet settled and “debate should be encouraged in classrooms, public forums, and the halls of Congress.” Senate confirmation hearings regarding Pruitt’s nomination are currently ongoing – many questions have focused on Pruitt’s legacy as AG of OK and what that tells us about actions he might take as head of the EPA.

Pruitt’s Past as AG

Elected in 2010, Pruitt’s six-year tenure illuminates the full extent of the troubling stances he takes. For instance, he has fought against the overturn of DOMA, same-sex marriage rights, granting legal status to undocumented immigrants, the Affordable Care Act, access to safe and affordable birth control and abortions, and Dodd-Frank Wall Street reform. These actions demonstrate Pruitt’s inability to accept or implement procedures, policies, and programs supported by a majority of US residents, members of the nations’ highest courts, and even his own colleagues.

A Focus on Environmental Issues

More specifically related to environmental issues, he has openly criticized the EPA in congressional hearings and op-ed pieces. Due to his belief that the EPA frequently abuses its authority, Pruitt’s office has filed 14 antiregulatory lawsuits against the EPA. Investigative reporters uncovered that in 13 of these cases co-litigators included companies that had contributed significant amounts of money to Pruitt and/or Pruitt-affiliated political action committees (PACs). He also routinely joins lawsuits against other states. For example, Pruitt and five other Attorneys General challenged a California law banning the sale of eggs laid by hens living in cramped conditions, but a US District Judge ruled they lacked legal standing because they were representing the economic interests of a few industrial egg producers rather than the interests of their broader constituents.

Several such lawsuits are still pending, which legal experts and others claim presents a conflict of interest should Pruitt become the new Director of the EPA. When asked specifically about this issue during Senate confirmation hearings, Pruitt refused to recuse himself from the lawsuits, saying he would leave such a decision up to the EPA’s legal counsel team. Notably, across the course of his six-years as AG, Pruitt’s office has distributed more than 700 news releases announcing the office’s actions, his speeches and public appearances, and efforts to challenge federal regulations. More than 50 of these releases promoted the office’s efforts to sue the EPA, but not once has a release described actions the office has taken to enforce environmental laws or to hold violators accountable for their actions.

Potential Conflicts of Interest

In OK, Pruitt has made many choices, that when viewed together, strongly suggest that his loyalties reside with the industries that have donated hundreds of thousands of dollars to his election campaigns rather than with the people he is sworn to protect. Here is a short list of the most troubling examples:

  • Pruitt’s predecessor had filed suit against Tyson, Cargill, and a number of other poultry producers in OK due to inappropriate disposal of an estimated 300,000 tons of animal waste per year, which was causing toxic algae blooms along the Illinois River. But shortly after his election, Pruitt dropped the case, citing a need for more research. Some have questioned whether his decision was impacted by the fact that the poultry industry had donated at least $40,000 to his campaign that year.
  • He also quickly dismantled the Attorney General’s in-house environmental protection unit, a team of four attorneys and a criminal investigator, and replaced it with the state’s first “federalism unit,” which was created to litigate against overreach by the federal government, mostly the EPA. Pruitt has repeatedly made it clear that he believes states should handle environmental issues, regardless of the fact that environmental issues frequently cause problems that cross geopolitical boundaries such as state lines (OK’s induced seismicity issue1 is a key example, more information about induced seismicity can be found here).
  • In 2013, he created a coalition of 9 Attorneys General, major energy CEOs, and their lawyers and brought them all to OK for a strategizing session regarding how to stop government and citizen responses to the ills of the oil and gas industry; it was an all-expenses paid event funded by Mercatus, a right-wing think tank favored by the Koch brothers.
    1. Notably, the energy industry is Pruitt’s second largest campaign contributor. When he came up for re-election in 2013, he chose Harold Hamm (CEO of Continental Resources, one of the largest oil companies in OK) to co-chair his campaign. Shortly after winning reelection in 2014, Pruitt joined forces with key industry players including Oklahoma Gas and Electric and the Domestic Energy Producers Alliance (chaired by Hamm) to file several antiregulatory lawsuits, which include attempts to block the Clean Power Plan and Waters of the US rule.
    2. Pruitt has also served as leader of the Republican Association of Attorneys General, which has collected at least $4.2 million in donations from fossil-fuel related companies since 2013.
  • Recently, local investigative reporters discovered that Pruitt’s office failed to follow a state law requiring state agencies to disclose spending on outside attorneys. Their examination illuminated that Pruitt has spent more than $1 million on legal fees since FY2012 – a total that does not include costs directly related to lawsuits against the EPA or the Affordable Care Act.

Induced-Seismicity and Wastewater Disposal

OK Map of Recent Earthquakes for Pruitt article

Map of Oklahoma Class II Injection Wells and Volumes 2011 to 2015 (Barrels). Click image to explore a full screen, dynamic map.

Oklahoma recently became the earthquake capital of the world due to a phenomenon referred to as injection-induced seismicity. While OK has not historically been known as a seismically active area, thousands of tremors have shaken the state since the shale gas boom began.

Several researchers have used geospatial analysis to demonstrate how these quakes are caused by the high-pressure injection of oil and gas industry wastes such as the flowback and produced water created by the unconventional oil and gas production process known as hydraulic fracturing. The map above shows where injection wells (tan dots) are located and where earthquakes (green dots) occurred from 2011-2015.

Oklahomans have been harmed by the implicitly pro-fracking stance Pruitt has taken, as evidenced by his lack of action regarding induced seismicity – as well as air, water, and soil contamination due to oil and gas industry activities. Several people, including Johnson Bridgewater (Director of OK Chapter of the Sierra Club) have noted that:

There are various places where the attorney general’s office could have stepped in to fix this overall problem…Its job is to protect citizens. Other states were proactive and took these issues on…[yet] Pruitt has been completely silent in the face of a major environmental problem for the state and its taxpayers.

Specifically, the AG’s office could have responded to the legal question of whether the state could limit or ban transport of fracking-related wastewater, sent by other states for disposal in underground injection wells in OK.

He also did nothing to address the phenomenally low earthquake insurance claim approval rate; after the 5.8M quake shook Pawnee in September of 2016, 274 earthquake damage claims were filed but only 4 paid out. Estimates of statewide approval rates generally suggest that approximately 1% of claimants receive funds to aid repairs.

Lastly, there are a number of class action lawsuits against a variety of industry actors regarding earthquake damages, yet Pruitt’s office has not entered any of these as an intervenor even though AGs in other states have done so.

Pruitt not at fault?

Photo Credit: JIM BECKEL/The Oklahoman

Earthquake damage. Photo Credit: Jim Beckel/The Oklahoman

Pruitt was recently called out by investigative reporters who used open-records requests to reveal that letters, briefs, and lawsuits that he submitted were written in whole or in part by leading energy firms such as Devon (another of OK’s largest oil and gas companies). Pruitt’s response was that he had done nothing wrong, nothing even potentially problematic. Rather, he said, of course he was working closely with industry and isn’t that what he should be doing. Some would argue that as AG what he should be doing is working closely with the people of Oklahoma, especially those whose homes, lives, and livelihoods have crumbled under the weight of attempting to repair earthquake damage due to industry activities.

Historical AG Influence

It is important to remember, though, that what’s happening with Pruitt is not isolated. Rather, as several long-time reporters have noted, increased attention to developing beneficial relationships with AGs is a result of historical processes.

About 20 years ago more than 40 state AGs banded together to challenge the tobacco industry, which led to a historic $206 billion settlement decision. Later, Microsoft, the pharmaceutical industry, and the financial services industry each faced similar multistate challenges regarding the legality or illegality of particular business practices.

As some AGs began hiring outside law firms to investigate and sue corporations, industry leaders realized that AGs’ actions were far more powerful and immediate than those of legislative bodies. So, they began a heretofore unprecedented campaign to massively increase their influence at this level.

Several people have critiqued the ways in which such actions undermine democratic processes, prompt troubling questions about ethics, and negatively impact attorney generals’ abilities to fulfill their duties to the state and its residents.

A Mission at Risk

Those of us on the frontlines here in OK have seen just how powerful such coalitions can be, how much sway they can have on local and state officials, how they destabilize people’s faith and trust in the systems that are supposed to protect them, and how coalitions undercut people’s hope and desire to be civically engaged. The mission of the US Environmental Protection Agency is to protect human health and the environment. If confirmed to lead the EPA, it is very likely Pruitt will prioritize his relationships with industry over the health and welfare of the people and environment he’s directed to protect.

Footnotes

  1. To learn more about induced seismicity read an exclusive FracTracker two-part series from former VTSO researcher Ariel Conn: Part I and Part II. Additionally, the USGS has created an Induced Earthquakes landing page as part of their Earthquake Hazards Program.

Hydrocarbon Industrial Complex Map In Detail

Below is a brand new map from our team that contains multiple data layers that speak to the myriad players and facilities involved in the North American hydrocarbon network – from upstream processing facilities to transporters and export terminals. This map helps us to demonstrate the complexity of the hydrocarbon industry, because we often assume that hydraulic fracturing or related extractive techniques are local issues. However, there is actually a tremendous – and growing – interconnectivity between production, transport, processing, usage, storage, and export.


To see a fullscreen version of this map, along with a legend and description, click on the arrows in the upper right hand corner of the map.

Data Descriptions

EIA Sources: Peak Shavers, Underground Natural Gas Storage, Compressor Station, Natural Gas HUBs, and Pipeline Data

Peak Shavers are:

…used for storing surplus natural gas that is to be used to meet the requirements of peak consumption later during winter or summer. Each peak-shaving facility has a regasification unit attached but may or may not have a liquefaction unit…[they] depend upon tank trucks to bring LNG from other nearby sources to them. Of the approximate 113 active LNG facilities in the United States, 57 are peak-shaving facilities. The other LNG facilities include marine terminals, storage facilities, and operations involved in niche markets such as LNG vehicular fuel. Learn more

The data included in this map include 109 Peak Shavers vs. the aforementioned 57.

  • Regional distribution: 7 Central US, 12 Midwest, 53 Northwest, 24 Southeast, 5 Southwest, 8 Western
  • 106 of which are active and 3 under construction

The Underground Natural Gas Storage Facilities (UNGSF) layer is an EIA-defined collection of 413 facilities1, a definition that includes “pipelines, local distribution companies, producers, and pipeline shippers with an inventory management tool, seasonal supply backup, and access to natural gas needed to avoid imbalances between receipts and deliveries on a pipeline network.” (For a more detailed description of UNGSF, see the EIA’s description)

Compressor Stations are designed to ensure:

…that the natural gas flowing through any one pipeline remains pressurized, compression of this natural gas is required periodically along the pipe…usually placed at 40 to 100 mile intervals along the pipeline. The natural gas enters the compressor station, where it is compressed by either a turbine, motor, or engine…[they] gain their energy by using up a small proportion of the natural gas that they compress.

For a more detailed discussion of the importance and design of compressor stations, refer to NaturalGas.org’s The Transportation of Natural Gas.

  • This layer includes: 1,756 compressor stations with the following regional distribution: 207 Canadian, 344 Central US, 14 Gulf Coast, 169 Midwest, 249 Northeast, 191 Southeast, 450 Southwest, and 132 Western stations
  • The mean and total horsepower across 1,417 of these facilities is 10,411 and 18,282,484, respectively, with average and total throughput of 660 and 1,159 Billion Cubic Feet (BCF)2.

Natural Gas HUBs are broken down by operator type with 26 “Market Center”, 31 “Market Hub”, 3 “Production Hub”, and 3 “Storage Hub” facilities included.

  • Regional distribution: 9 in Canada, 7 across the Central US, 4 in the Midwest, 8 in the Northeast, 4 in the Southeast, 24 in the Southwest, and 7 in the Western US.
  • All facilities were activated between 1994 and 1998
  • Status: 5 Canceled, 13 Inactive, 36 Operational, and 9 Proposed HUBs

Pipeline segments are parsed by type: a) 69 sections totaling 1,627 miles described as “Gathering” at an average diameter of 17 inches, b) 18,905 segments totaling 127,049 miles as “Interstate” with an average diameter of 15 inches, and  c) 15,152 “Intrastate” segments totaling 66,939 miles and an average diameter of 2.8 inches.

Select states statistics:

  1. 7,450 segments were located in Texas with a total length of 44,600 miles,
  2. 1,313 segments were located in California with a total length of 6,370 miles,
  3. 2,738 segments in Louisiana with a  total length of 15,330,
  4. New York and New Jersey are home to a combined 2,315 pipeline segments with a total length of 4,015 miles,
  5. 859 segments and 5,935 miles in Ohio,
  6. Great Lakes bordering states contain 6,841 pipeline segments totaling 33,457 miles,
  7. Pacific Northwest states including Washington, Oregon, Idaho, and Montana contain 1,765 segments totaling 6,121 miles,
  8. Gulf Coast states sans Texas contain 3,886 pipeline segments totaling 25,775 miles.

The above datasets were compiled by Ted Auch and Daniel Berghoff of the FracTracker Alliance or sourced from the US Energy Information Administration via their Natural Gas data portal and their analysts Tu Tran and Robert King.

US River and Coastal Export/Import Ports

US inland (i.e., Mississippi River) and coastal ports are the singular ways in which all manner of hydrocarbons are transported to downstream processing facilities and subsequently used domestically or exported. The data contained herein include 12 Mississippi, 7 Ohio and Tennessee River, and 11 Columbia river ports along with 16 Great Lakes/St. Lawrence river ports (Table 1).

Table 1. Number of inland and coastal US and territories ports as of December 2013.

State

Number of Ports

State

Number of Ports

AK

40

MO

2

AL

7

MS

3

AR

2

NC

2

CA

9

NJ

2

CT

3

NY

6

DE, VA, MD, & DC

6

OH

2

FL

17

OK

2

GA

2

OR

13

HI

7

PA

2

IA

1

PR

1

ID

1

RI

1

IL

4

SC

1

KY

2

TN

4

LA

13

TX

11

MA

3

VI

1

ME

2

WA

6

MI

6

WI

4

MN

4

WV

2

US Coal Plants & Emissions

We were pointed to this data by Source Watch’s “Coal Swarm” project’s Director Ted Nace and researcher Joshua Frank. Learn more. The layer includes coal used, emissions of carbon dioxide (CO2), sulfur dioxide (SO2), methane (CH4), oxides of nitrogen (NOX), and mercury (Hg). Also included are the number of deaths across a variety of categories and emergency room visits attributed to each coal plant, along with estimates of the valuation of each of these. The raw data are available from the the US EPA’s Emissions & Generation Resource Integrated Database (eGRID) comprehensive data portal with the “Version 1.0” ZIP file containing: “spreadsheet files, state import-export files, Technical Support Document, file structure document, Summary Tables, GHG output emission rates, the EUEC2010 paper, and graphical representations of eGRID subregion and NERC region maps. Data in this file encompasses years 2009, 2007, 2005 and 2004.” The data were most recently updated on May 10, 2012 in order to include 2009 data.

Transload Facilities Directory

Directory Description:

Rail-to-truck transload facilities where cargo is transferred between tank trucks and water or rail transportation…These bulk material handling companies also provide information such as products handled, services and equipment available, and methods for dry bulk product transfer…These intermodal locations are owned or operated by trucking companies, railroads, or independent bulk terminal operators. Unless the prohibition is stated, these businesses have indicated they allow outside carriers to load products at their facilities. Learn more

Services Key:

  • Products handled: a. Acids, b. Chemicals (liquid), c. Chemicals (dry), d. Asphalt, e. Foods (liquid), f. Foods (dry), g. Plastics (dry), h. Petroleum products
  • Services/equipment available: a. Air compressor, b. Scale, c. Blending meters, d. Sampling service, e. Hot water heating, f. Steam heating, g. Tank trailer cleaning, h. Liquid storage tanks, i. Liquid pumps
  • Dry bulk product transfer by: a. Vacuum trailer, b. Auger, c. Blower, d. Gravity (trestle), e. Portable vacuum/air conveyor, f. Bulk conveyor

Intermodal Tank Containers

Those facilities “that have actual storage depot operations. The operators specialize in both the handling and storage of ISO containers.” Learn more

Intermodal tanks are:

… intermodal container[s] for the transport of liquids, gases and powders as bulk cargo…built to the [International Organization for Standardization] Standard, making it suitable for different modes of transportation. Both hazardous and non-hazardous products can be transported in tank containers. A tank container is a vessel of stainless steel surrounded by an insulation and protective layer of usually Polyurethane and aluminum. The vessel is in the middle of a steel frame. The frame is made according to ISO standards and is 19.8556 feet (6.05 meters) long, 7.874 feet (2.40 meters) wide and 7.874 feet (2.40 meters) or 8.374 feet (2.55 meters) high. The contents of the tank ranges from 27,000 to 40,000 liters (5,900 to 8,800 imp gal; 7,100 to 11,000 U.S. gal). There are both smaller and larger tank containers, which usually have a size different from the ISO standard sizes. The trade organization @TCO estimates that at the end of 2012 the global fleet of tank containers is between 340,000 and 380,000. (Wikipedia definition)

Services Key: a. Storage, b. Cleaning, c. Container shuttle service, d. Container drayage, e. Steam/electric heat, f. Rail siding, g. Repair/refurbishing, h. American Bureau of Shipping (ABS) certification, i. American Society of Mechanical Engineers (ASME) certification, j. ISO 9000 certification, k. 2.5- and 5-year ABS testing, l. Reefer tank repairs, m. Parts supply

Abbreviations: SC=straddle carrier, TLSL=top-lifting side-loader, D/D=drop-deck

MarkWest Facilities

Facility locational data gathered from the company’s operations website.

Cargo Tank Repair Directory

“Bulk Transporter’s Cargo Tank Trailer Repair Directory…the most comprehensive listing of repair facilities that service tank trucks and tank trailers. Additionally, many of these facilities offer custom fabrication. Most listings include services offered, but tank truck operators are encouraged to contact the facilities directly for more information…The first six items listed on the “Services Key” are the DOT tests and inspections required by federal law. Companies listing “R” or “U” stamps were asked to provide Bulk Transporter with a record of their accreditation. The federal CT registration number also was requested for the tank repair shops in the directory.” Learn more

Repair Services Key:

1. External visual inspection, 2. Internal visual inspection, 3. Lining inspection, 4. Leakage test, 5. Pressure retesting, 6. Thickness testing, 7. MC330/331 retesting, 8. Vapor recovery testing, 9. Bottom-loading conversion, 10. Major barrel repair, 11. Tank passivation, 12. Sandblasting/painting, 13. Tank changeouts, 14. Tank degassing, 15. Tank cleaning (for repair only), 16. Custom fabrication, 17. Purchase wrecked trailers, 18. Pick-up & delivery, 19. Lining repair, 20. ASME “U” stamp, 21. National Board “R” stamp

Soon To Be Added Data:

Tank Cleaning Directory

The Commercial Tank Cleaning Directory…information…was supplied by the operators of commercial and carrier-owned tank wash facilities that provide cargo tank interior cleaning. Directory listings may include product limitations such as “food grade only” or “no hazmat.” Learn more


Footnotes

[1] 407 active and 6 inactive facilities; Region –

  1. 259 “Consuming East” primarily within depleted reservoirs providing supplemental backup and/or peak period supply,
  2. 49 “Consuming West” primarily for domestic US and Alberta gas to flow at constant rates, and
  3. 105 “Producing” facilities which are primarily responsible for hydrocarbon basin export connectivity, transmission, and distribution and allow for the storage of currently redundant natural gas supply; Field Type Affiliation – 43 aquifers, 331 depleted fields, and 39 salt domes. Learn more

[2] These total horsepower and throughput figures are up from 13.4 million and 743 BCF in 1996.

Update from US EPA on Hydraulic Fracturing Study

Update from US EPA on Hydraulic Fracturing Study

Update from US EPA on Hydraulic Fracturing StudyThe U.S. Environmental Protection Agency’s (EPA) Science Advisory Board (SAB) released Federal Register Notices announcing a public meeting and a teleconference where the Hydraulic Fracturing Research Advisory Panel will provide feedback on the Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report. The public will also have the opportunity to provide comments for the Panel’s consideration.

Information on how to view a webcast of the meeting will be posted on the SAB website prior to the meeting. More information on the Science Advisory Board’s Hydraulic Fracturing Research Advisory Panel and its activities is available here.

In addition, EPA’s Federal Register Request for Information to Inform Hydraulic Fracturing Research Related to Drinking Water Resources will be closing on Tuesday, April 30, 2013.

Update from US EPA on Hydraulic Fracturing Study

Summary of EPA Roundtables Available

From the US Environmental Protection Agency:

EPA recently posted a summary of the five technical roundtables held in November 2012 to help inform EPA’s Hydraulic Fracturing Study. Each roundtable focused on a different stage of the hydraulic fracturing water cycle:

  • Water acquisition
  • Chemical mixing
  • Well injection
  • Flowback and produced water
  • Wastewater treatment and waste disposal

Technical roundtables are an important component of EPA’s Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The roundtables allow for external subject-matter experts from a variety of stakeholder groups to discuss the work underway to answer the key research questions of the study, and to identify possible topics for technical workshops.

Map of Pavilion WY

EPA: Fracking and Groundwater Contamination

Map of Pavillion, WY

Pavillion, WY

The Internet is alive today after the U.S. Environmental Protection Agency released a report that indicates hydraulic fracturing (used when drilling for natural gas in tight shale formations) can contaminate groundwater. Residents of Pavillion, WY have been complaining about the state of their groundwater for some time now. The draft EPA report lends credibility to their claims with the finding that chemicals associated with the process were found in some deep water aquifers in the area. And when you look at all of the evidence around this issue – outside of the EPA’s study – the results are even more ‘ground-breaking.’

Having said that, there are a few questions regarding the EPA report/research. No field study could ever account for all of the potential confounders and variables – especially given the amount of resources the EPA had at its disposal to conduct this work. However, some of the most significant questions that I would like to see answered before this draft is finalized include:

  1. How representative is the data from the two monitoring wells in relation to residents’  drinking water wells?
  2. Has the potential for surface contamination of the monitoring wells been ruled out?
  3. Why weren’t the duplicate samples that were analyzed by separate labs also able to detect 2-BE?

These questions (and surely more) are exactly why this is only a draft report. According to the EPA, it will be available for a 45-day public comment period. A subsequent 30-day peer-review process will be led by a panel of independent scientists to ensure that the results that stay on the records are accurate.

Update from US EPA on Hydraulic Fracturing Study

US EPA Proceedings of the Technical Workshops for the Hydraulic Fracturing Study

In its Fiscal Year 2010 Appropriations Report, the U.S. House of Representatives Appropriation Conference Committee identified the need for a focused study on the relationship between hydraulic fracturing and drinking water resources. EPA scientists, under this Administration and at the direction of Congress, are undertaking a study to better understand any potential impacts of hydraulic fracturing (HF) on drinking water resources.

The scope of the proposed research includes the full lifespan of water in HF, from acquisition of the water, through the mixing of chemicals and actual fracturing, to the post-fracturing stage, including the management of flowback and produced water and its ultimate treatment and disposal.

 

EPA held four technical workshops from February through March 2011 to explore the following focus areas:

The goal of the technical workshops was three-fold:

  1. Inform EPA of the current technology and practices being used in hydraulic fracturing,
  2. Identify research related to the potential impacts of hydraulic fracturing on drinking water resources, and
  3. Provide an opportunity for EPA scientists to interact with technical experts. EPA invited technical experts from the oil and natural gas industry, consulting firms, laboratories, state and federal agencies, and environmental organizations to participate in the workshops.

EPA will use the information presented in these abstracts and presentations to inform research that effectively evaluates the relationship between HF and drinking water.  Learn more»

Groundwater Contamination Debate


The Debate
: Can the process of hydraulically fracturing underground natural gas wells contaminate groundwater?

Industry Position:  There has never been a documented case of groundwater contamination due to hydraulic fracturing; the process occurs thousands of feet below drinking water aquifers. Therefore, the chemicals used in the fracturing process pose no threat to drinking water.

Opposition Position:  It can and has contributed to pollution of underground drinking water sources.

The Data:  Previous lawsuits from landowners were settled by the industry and the data kept private for various litigation reasons. A U.S. EPA report now indicates that hydraulic fracturing has been linked to at least one case of drinking water contamination in West Virginia in 1987 and could feasibly contribute to future problems.

Future Obligations:  Some improved regulations and protections have been put in place since 1987, but the risk still exists if natural gas drilling is done hastily or if abandoned wells exist nearby. Once pollutants are introduced into underground water aquifers they are very difficult to remove, so significant care and review must be taken if drilling is going to continue. The EPA report further supports the need for increased government and industry transparency across the board. It should also be stated that a large-scale health impact assessment is needed to comprehensively determine the risk that the entire natural gas drilling operation poses to public health.


Compiled by: Samantha Malone, MPH, CPH – Communications Specialist, Center for Healthy Environments and Communities (CHEC), Environmental and Occupational Health (EOH) department, University of Pittsburgh Graduate School of Public Health (GSPH); and Doctoral Student, GSPH