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H 2 O Where Did It Go?

March 19, 2014/by FracTracker Alliance

By Mary Ellen Cassidy, Community Outreach Coordinator, FracTracker Alliance

A Water Use Series

Many of us do our best to stay current with the latest research related to water impacts from unconventional drilling activities, especially those related to hydraulic fracturing. However, after attending presentations and reading recent publications, I realized that I knew too little about questions like:

How much water is used by hydraulic fracturing activities, in general?
How much of that can eventually be used for drinking water again?
How much is removed from the hydrologic cycle permanently?

To help answer these kinds of questions, FracTracker will be running a series of articles that look at the issue of drilling-related water consumption, the potential community impacts, and recommendations to protect community water resources.

Ceres Report

We have posted several articles on water use and scarcity in the past here, here, here and here. This article in the series will share information primarily from Monika Freyman’s recent Ceres report, Hydraulic Fracturing & Water Stress: Water Demand by the Numbers, February 2014. If you hunger for maps, graphs and stats, you will feast on this report. The study looks at oil and gas wells that were hydraulically fractured between January 2011 and May 2013 based on records from FracFocus.

Class 2 UI Wells

Water scarcity from unconventional drilling is a serious concern. According to Ceres analysis, horizontal gas production is far more water intensive than vertical drilling. Also, the liquids that return to the surface from unconventional drilling are often disposed of through deep well injection, which takes the water out of the water cycle permanently. By contrast, water uses are also high for other industries, such as agriculture and electrical generation. However, most of the water used in agriculture and for cooling in power plants eventually returns to the hydrological cycle. It makes its way back into local rivers and water sources.

In the timeframe of this study, Ceres reports that:

97 billion gallons of water were used, nearly half of it in Texas, followed by Pennsylvania, Oklahoma, Arkansas, Colorado and North Dakota, equivalent to the annual water need of 55 cities with populations of ~ 5000 each.
Over 30 counties used at least one billion gallons of water.
Nearly half of the wells hydraulically fractured since 2011 were in regions with high or extremely high water stress, and over 55% were in areas experiencing drought.
Over 36% of the 39,294 hydraulically fractured wells in the study overlay regions experiencing groundwater depletion.
The largest volume of hydraulic fracturing water, 25 billion gallons, was handled by service provider, Halliburton.

Water withdrawals required for hydraulic fracturing activities have several worrisome impacts. For high stress and drought-impacted regions, these withdrawals now compete with demands for drinking water supplies, as well as other industrial and agricultural needs in many communities. Often this demand falls upon already depleted and fragile aquifers and groundwater. Groundwater withdrawals can cause land subsidence and also reduce surface water supplies. (USGS considers ground and surface waters essentially a single source due to their interconnections). In some areas, rain and snowfall can recharge groundwater supplies in decades, but in other areas this could take centuries or longer. In other areas, aquifers are confined and considered nonrenewable. (We will look at these and additional impact in more detail in our next installments.)

Challenges of documenting water consumption and scarcity

Tracking water volumes and locations turns out to be a particularly difficult process. A combination of factors confuse the numbers, like conflicting data sets or no data, state records with varying criteria, definitions and categorization for waste, unclear or no records for water volumes used in refracturing wells or for well and pipeline maintenance.

Along with these impediments, “chain of custody” also presents its own obstacles for attempts at water bookkeeping. Unconventional drilling operations, from water sourcing to disposal, are often shared by many companies on many levels. There are the operators making exploration and production decisions who are ultimately liable for environmental impacts of production. There are the service providers, like Halliburton mentioned above, who oversee field operations and supply chains. (Currently, service providers are not required to report to FracFocus.) Then, these providers subcontract to specialists such as sand mining operations. For a full cradle-to-grave assessment of water consumption, you would face a tangle of custody try tracking water consumption through that.

To further complicate the tracking of this industry’s water, FracFocus itself has several limitations. It was launched in April 2011 as a voluntary chemical disclosure registry for companies developing unconventional oil and gas wells. Two years later, eleven states direct or allow well operators and service companies to report their chemical use to this online registry. Although it is primarily intended for chemical disclosure, many studies, like several of those cited in this article, use its database to also track water volumes, simply because it is one of the few centralized sources of drilling water information. A 2013 Harvard Law School study found serious limitations with FracFocus, citing incomplete and inaccurate disclosures, along with a truly cumbersome search format. The study states, “the registry does not allow searching across forms – readers are limited to opening one PDF at a time. This prevents site managers, states, and the public from catching many mistakes or failures to report. More broadly, the limited search function sharply limits the utility of having a centralized data cache.”

To further complicate water accounting, state regulations on water withdrawal permits vary widely. The 2011 study by Resources for the Future uses data from the Energy Information Agency to map permit categories. Out of 30 states surveyed, 25 required some form of permit, but only half of these require permits for all withdrawals. Regulations also differ in states based on whether the withdrawal is from surface or groundwater. (Groundwater is generally less regulated and thus at increased risk of depletion or contamination.) Some states like Kentucky exempt the oil and gas industry from requiring withdrawal permits for both surface and groundwater sources.

Can we treat and recycle oil and gas wastewater to provide potable water?

Will recycling unconventional drilling wastewater be the solution to fresh water withdrawal impacts? Currently, it is not the goal of the industry to recycle the wastewater to potable standards, but rather to treat it for future hydraulic fracturing purposes. If the fluid immediately flowing back from the fractured well (flowback) or rising back to the surface over time (produced water) meets a certain quantity and quality criteria, it can be recycled and reused in future operations. Recycled wastewater can also be used for certain industrial and agricultural purposes if treated properly and authorized by regulators. However, if the wastewater is too contaminated (with salts, metals, radioactive materials, etc.), the amount of energy required to treat it, even for future fracturing purposes, can be too costly both in finances and in additional resources consumed.

It is difficult to find any peer reviewed case studies on using recycled wastewater for public drinking purposes, but perhaps an effective technology that is not cost prohibitive for impacted communities is in the works. In an article in the Dallas Business Journal, Brent Halldorson, a Roanoke-based Water Management Company COO, was asked if the treated wastewater was safe to drink. He answered, “We don’t recommend drinking it. Pure distilled water is actually, if you drink it, it’s not good for you because it will actually absorb minerals out of your body.”

Can we use sources other than freshwater?

How about using municipal wastewater for hydraulic fracturing? The challenge here is that once the wastewater is used for hydraulic fracturing purposes, we’re back to square one. While return estimates vary widely, some of the injected fluids stay within the formation. The remaining water that returns to the surface then needs expensive treatment and most likely will be disposed in underground injection wells, thus taken out of the water cycle for community needs, whereas municipal wastewater would normally be treated and returned to rivers and streams.

Could brackish groundwater be the answer? The United States Geological Survey defines brackish groundwater as water that “has a greater dissolved-solids content than occurs in freshwater, but not as much as seawater (35,000 milligrams per liter*).” In some areas, this may be highly preferable to fresh water withdrawals. However, in high stress water regions, these brackish water reserves are now more likely to be used for drinking water after treatment. The National Research Council predicts these brackish sources could supplement or replace uses of freshwater. Also, remember the interconnectedness of ground to surface water, this is also true in some regions for aquifers. Therefore, pumping a brackish aquifer can put freshwater aquifers at risk in some geologies.

Contaminated coal mine water – maybe that’s the ticket? Why not treat and use water from coal mines? A study out of Duke University demonstrated in a lab setting that coal mine water may be useful in removing salts like barium and radioactive radium from wastewater produced by hydraulic fracturing. However, there are still a couple of impediments to its use. Mine water quality and constituents vary and may be too contaminated and acidic, rendering it still too expensive to treat for fracturing needs. Also, liability issues may bring financial risks to anyone handling the mine water. In Pennsylvania, it’s called the “perpetual treatment liability” and it’s been imposed multiple times by DEP under the Clean Streams Law. Drillers worry that this law sets them up somewhere down the road, so that courts could hold them liable for cleaning up a particular stream contaminated by acid mine water that they did not pollute.

More to come on hydraulic fracturing and water scarcity

Although this article touches upon some of the issues presented by unconventional drilling’s demands on water sources, most water impacts are understood and experienced most intensely on the local and regional level. The next installments will look at water use and loss in specific states, regions and watersheds and shine a light on areas already experiencing significant water demands from hydraulic fracturing. In addition, we will look at some of the recommendations and solutions focused on protecting our precious water resources.

Class II Oil and Gas Wastewater Injection and Seismic Hazards in CA

March 15, 2014/by Kyle Ferrar, MPH

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

In collaboration with the environmental advocacy groups Earthworks, Center for Biological Diversity, and Clean Water Action, The FracTracker Alliance has completed a proximity analysis of the locations of California’s Class II oil and gas wastewater injection wells to “recently” active fault zones in California. The results of the analysis can be found in the On Shaky Ground report, available for download at www.ShakyGround.org.¹

Production of oil and natural gas results in a large and growing waste stream. Using current projections for oil development, the report projects a potential 9 trillion gallons of wastewater over the lifetime of the Monterey shale. In California the majority of wastewater is injected deep underground for disposal in wells deemed Class II wastewater injection. The connection between seismic activity and underground injections of fluid has been well established, but with the current surge of shale resource development the occurrence of earthquakes in typically seismically inactive regions has increased, including a recent event in Ohio covered by the LA Times. While both hydraulic fracturing and wastewater injection wells have been linked to the induction of seismic activity, the impacts of underground injection wells used for disposal are better documented and linked to larger magnitude earthquakes.

Therefore, while hydraulic fracturing of oil and gas wells has also been documented to induce seismic activity, the focus of this report is underground injection of waste fluids.

Active CA Faults

A spatial overview of the wastewater injection activity in California and recently active faults can be viewed in Figure 1, below.

Figure 1. California’s Faults and Wastewater Injection Wells. With this and all maps on this page, click on the arrows in the upper right hand corner of the map to view it fullscreen and to see the legend and more details.

The focus of the On Shaky Ground report outlines the relationship between does a thorough job reviewing the literature that shows how the underground injection of fluids induces seismic activity. The proximity analysis of wastewater injection wells, conducted by The FracTracker Alliance, provides insight into the spatial distribution of the injection wells. In addition, the report M7.8 earthquake along the San Andreas fault could cause 1,800 fatalities and nearly $213 billion in economic damages.² To complement the report and provide further information on the potential impacts of earthquakes in California, FracTracker created the maps in Figure 2 and Figure 3.

Shaking Assessments

Figure 2 presents shaking amplification and shaking hazards assessments. The dataset is generated from seismic evaluations. When there is an earthquake, the ground will amplify the seismic activity in certain ways. The amount of amplification is typically dependent on distance to the earthquake event and the material that comprises the Earth’s crust. Softer materials, such as areas of San Francisco built on landfills, will typically shake more than areas comprised of bedrock at the surface. The type of shaking, whether it is low frequency or high frequency will also present varying hazards for different types of structures. Low frequency shaking is more hazardous to larger buildings and infrastructure, whereas high frequency events can be more damaging to smaller structure such as single family houses. Various assessments have been conducted throughout the state, the majority by the California Geological Survey and the United States Geological Survey.

Figure 2. California Earthquake Shaking Amplification and Class II Injection Wells

Landslide Hazards

Below, Figure 3. Southern California Landslide and Hazard Zones expands upon the map included in the On Shaky Ground report; during an earthquake liquefaction of soil and landslides represent some of the greatest hazards. Liquefaction refers to the solid earth becoming “liquid-like”, whereas water-saturated, unconsolidated sediments are transformed into a substance that acts like a liquid, often in an earthquake. By undermining the foundations of infrastructure and buildings, liquefaction can cause serious damage. The highest hazard areas shown by the liquefaction hazard maps are concentrated in regions of man-made landfill, especially fill that was placed many decades ago in areas that were once submerged bay floor. Such areas along the Bay margins are found in San Francisco, Oakland and Alameda Island, as well as other places around San Francisco Bay. Other potentially hazardous areas include those along some of the larger streams, which produce the loose young soils that are particularly susceptible to liquefaction. Liquefaction risks have been estimated by USGS and CGS specifically for the East Bay, multiple fault-slip scenarios for Santa Clara and for all the Bay Area in separate assessments. There are not regional liquefaction risk estimate maps available outside of the bay area, although the CGS has identified regions of liquefaction and landslide hazards zones for the metropolitan areas surrounding the Bay Area and Los Angeles. These maps outline the areas where liquefaction and landslides have occurred in the past and can be expected given a standard set of conservative assumptions, therefore there exist certain zoning codes and building requirements for infrastructure.

Figure 3. California Liquefaction/Landslide Hazards and Class II Injection Wells

Press Contacts

For more information about this report, please reach out to one of the following media contacts:

Alan Septoff
Earthworks
(202) 887-1872 x105
aseptoff@earthworksaction.org

Patrick Sullivan
Center for Biological Diversity
(415) 632-5316
psullivan@biologicaldiversity.org

Andrew Grinberg
Clean Water Action
(415) 369-9172
agrinberg@cleanwater.org

References

Arbelaez, J., Wolf, S., Grinberg, A. 2014. On Shaky Ground. Earthworks, Center for Biological Diversity, Clean Water Action. Available at ShakyGround.org
Jones, L.M. et al. 2008. The Shakeout Scenario. USGS Open File Report 2008-1150. U.S. Department of the Interior, U.S. Geological Survey.

What Does Los Angeles Mean for Local Bans and Moratoria in California?

March 4, 2014/by Kyle Ferrar, MPH

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

California Regulations.

As confusing as you may think the regulatory structure is in your state (if you are not fortunate enough to be a Californian), just know that California’s regulatory structure is more complicated. Nothing in California’s recent history has clarified this point like the current debate over “fracking” regulations (hydraulic fracturing, as well as acidizing and other stimulation techniques). Since the passage of California State Bill 4 (SB-4), there have been significant concerns for self-rule and self-determination for individual communities. Further complicating the issue are the fracking activities being conducted from the offshore oil rig platforms located in federal waters. In addition to federal regulation, the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources is the premier regulatory authority for oil and gas drilling and production in the state. The State Water Resources Control Board and the Regional Water Quality Control Board hold jurisdiction over the states surface and groundwater resources, while the California Air Districts regulate air quality along with the California Air Resources Board. It is no surprise that a report published by the Wheeler Institute from the University of California, Berkeley found that this regulatory structure where several state and federal agencies share responsibility is not conducive to ensuring hydraulic fracturing is conducted safely.[1]

A Ban in Los Angeles, CA

The most recent local regulatory activity comes from the Los Angeles City Council. On Friday February 28, 2014, the City Council voted on and passed a resolution to draft language for a citywide ban of all stimulation techniques. The resolution calls for city zoning code to be amended in order to prohibit hydraulic fracturing activities in L.A. until the practices are proven to be safe. A final vote will then be cast to approve the final language. If it passes, Los Angeles will be the largest city in the United States to ban hydraulic fracturing. The FracTracker “Local Actions and Regulations Map” has been updated to include the Los Angeles resolution/ordinance, as well as the resolution supporting a statewide ban by the San Francisco Board of Supervisors, the moratorium in Santa Cruz County, and a resolution by the University of California, Berkeley Student Government. See all California’s local actions and regulations in the figure below. Click on the green checked boxes for a description of each action.

Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

State Bill 4 Preemption

Since the passage of California’s new regulatory bill SB-4, there has been a lot of confusion and debate whether the new state regulations preempt local jurisdictions from passing their own laws and regulations, and specifically moratoriums and bans. The county of Santa Cruz has a moratorium on fracking, but it was passed prior to the enactment of SB-4. Additionally Santa Cruz County is not a hotbed of drilling activity like Los Angeles or Kern. The team of lawyers representing the county of Ventura, where wells are actively being stimulated, came to a very different conclusion than the Los Angeles City Council. After reviewing SB-4, Ventura County came to the conclusion that lower jurisdictions were blocked from enacting local moratoriums. Draft minutes from the December 17, 2013 meeting quote, “The legal analysis provided by County Counsel indicates that the County is largely preempted from actively regulating well stimulation treatment activities at both new and existing wells. However, the County is required under CEQA to assess and address the potential environmental impacts from such activities requiring a discretionary County approval of new well sites.”[2]

On the other hand, independent analyses of the language in California SB-4 show that the legal-ese does not contain any provision that supersedes related local regulations. Rather, the bill preserves the right of local governments to impose additional environmental regulations.[3] The regulations do not expressively comment on the ability of local regulations to pass a moratorium or permanent ban. Additionally, DOGGR has supported a court decision that the SB-4 language expressly prohibits the state regulatory agency from enforcing the California Environmental Quality Act (according to the Division of Oil, Gas and Geothermal Resources).[4] As for local measures, a recent article by Edgcomb and Wilke (2013) provides multiple examples of precedence in California and other states for local environmental bans and regulations in conjunction with less restrictive state law.[3] Of course, any attempt to pass a ban on fossil fuel extraction or development activities where resource development is actively occurring will most likely be met with litigation and a lawsuit from industry groups such as the Western States Petroleum Association. Industry representatives charge that the ordinance is an unconstitutional “taking” of previously leased mineral rights by private property owners.[5,6] Pay close attention to this fight in Los Angeles, as there will be repercussions relevant to all local governments in the state of California, particularly those considering bans or moratoriums.

[1] Kiparsky, Michael and Hein, Jayni Foley. 2013. Regulation of Hydraulic Fracturing in California, a Wastewater and Water Quality Perspective. Wheeler Institute for Water Law and Policy. Center for Law Energy and the Environment, University of California Berkeley School of Law.

[2] Ventura County Board of Supervisors. December 17, 2013. Meeting Minutes and Video. Accessed March 2, 2014. [http://www.ventura.org/bos-archives/agendas-documents-and-broadcasts]

[2] Edgcomb, John D Esq. and Wilke, Mary E Esq. January 10, 2014. Can Local Governments Ban Fracking After New California Fracking Legislation? Accessed March 3, 2014. [http://californiafrackinglaw.com/can-local-governments-ban-fracking-after-new-california-fracking-legislation/]

[3] Hein, Jayni Foley. November 18, 2013. State Releases New Fracking Regulations amid SB 4 Criticism, Controversy. Accessed February 27, 2014. [http://blogs.berkeley.edu/2013/11/18/state-releases-new-fracking-regulations-amid-sb-4-criticism-controversy/]

[4] Fine, Howard. February 28, 2014. L.A. Council Orders Fracking Moratorium Ordinance. Los Angeles Business Journal. [http://labusinessjournal.com/news/2014/feb/28/l-council-orders-fracking-moratorium-ordinance/]

[5] Collier, Robert. March 3, 2014. L.A. fracking moratorium – the difficult road ahead. Climate Speak. Accessed March 4, 2014. [http://www.climatespeak.com/2014/03/la-fracking-moratorium.html]

[6] Higgins, Bill. Schwartz, Andrew. Kautz, Barbara. 2006. Regulatory Takings and Land Use Regulation: A Primer for Public Agency Staff. Institute for Local Government. Available at [http://www.ca-ilg.org/sites/main/files/file-attachments/resources__Takings_1.pdf]

Controversial Pinelands Pipeline Defeated

January 14, 2014/by Karen Edelstein

For many months, a battle has been raging in New Jersey about whether to convert the coal-burning BL England power plant to natural gas. While coal-burning is relatively more polluting (especially in terms of sulfur dioxide, NOx, and carbon dioxide emissions) and more expensive than natural gas, natural gas power plants bring with them other concerns. In order to repower this plant on the shore of Cape May County, a 22-mile-long pipeline was proposed to be built through the 1.1-million acre New Jersey Pinelands National Reserve, a sensitive wetland habitat that straddles the Cape May and Cumberland County lines. The pipeline would have run adjacent to Rt 49, a main highway that bisects the Pinelands. Although the administration of Governor Chris Christie had lobbied strongly for the project, saying that the pipeline would go under and alongside existing roads, opponents of the project felt that that it posed too much of a threat to state- and federally-regulated wetlands and other Natural Heritage sites.

Map of Proposed Pinelands Pipeline plan (defeated). For a full-screen version of this map (including map legend), click here.

On Friday, January 10, the New Jersey Pinelands Commission rejected the proposal by New Jersey Gas to move ahead with the project. According to the New York Times, New Jersey Gas would have been exempt from a ban on additional transmission pipelines through the Pinelands because they were including an offer to acquire and preserve two to three thousand acres of land near the pipeline route. Now, the next decision will be whether to find an alternate route for gas delivery to the plant if it is converted, keep the plant running on coal, or, perhaps, like has been suggested for other sites like the Cayuga and Dunkirk plants in New York State, choose to upgrade the efficiency of transmission lines, and capture energy that is currently lost.

For more information:
New Jersey Pinelands National Reserve National Park Service website
New Jersey Officials Back Pinelands Pipeline NY Post, 12/12/2013
Panel Blocks Gas Pipeline in New Jersey Pinelands New York Times, 1/11/2014
Controversial Repowering of the Cayuga and Dunkirk Coal-fired Power Plants, Earthjustice website
Coal-To-Natural-Gas Switch For Power Generation Is Paying Off In Smaller Carbon Footprint, International Business Times, 1/14/2014

Data sources
National Wetlands Inventory: US Fish and Wildlife Service

Sifting Through Sand Mining

November 1, 2013/by FracTracker Alliance

Note

This post has been archived. It is provided here for informational purposes only.

By Brook Lenker and Ted Auch, FracTracker Alliance

Thirty miles northwest of Eau Claire, Wisconsin the land rolls gently. Wooded hills back orderly farms straight from the world of Norman Rockwell but painted red and gold by October’s cool brush. It seems like agrarian perfection, but the harmony is interrupted by the pits and mounds of a newcomer to America’s Dairyland – sand extraction to support hydraulic fracturing for the oil and natural gas industry.

“Mine, Baby, Mine” reads a bumper sticker on a pickup outside the Baron drying plant of Superior Silica Sands – a frac sand company headquartered in Fort Worth, Texas but with significant activities located in Wisconsin. Ted Auch, Ohio Program Coordinator for FracTracker, and I are on a daylong sand mining tour organized by the West Central Wisconsin Regional Planning Commission (WCWRPC). This, the second Superior drying plant we visited, processes up to 2.4 million tons of sand per year (enough sand to complete 800 typical horizontal gas or oil wells). This is among the largest facilities of its kind in the world.

What is frac sand?

Frac sands (99% silicon dioxide – SiO₂) are meant to “prop” open the rock after fracturing is complete, termed “proppants.” Aside from water, these sands represent the second largest constituent pumped into a typical well to hydraulically fracture the shale. Usage of frac sand as a proppant is increasing due to the rising costs associated with synthetic substitutes like ceramic and related resin-coated materials. Ideally, such sand must be uniformly fine and spherical, crush-resistant, acid soluble, mature, and clay/silt-free. The northern Great Lakes Basin represents the primary stock for high quality frac sand in the world – causing many industry analysts to label the region Sand Arabia.

And where does it come from?

Most of Superior’s total production (4.2 million tons per year) comes from mines in New Auburn and Clinton, Wisconsin – in the middle of the St. Peter (Ottawa) Sandstone. This formation underlies parts of Iowa, Wisconsin, Minnesota, Illinois and Missouri. Known for its uniform and rounded grains – the region has recently surpassed the Hickory (Brady) formation in Texas, which contains sands that are far more angular, blocky and coarse.

To get an idea of the landscape where these sand mining operations are occurring in Wisconsin, see Figure 1 below.

: Wisconsin Sandstone Geology Forest Coverage (%)

: Wisconsin Sandstone Geology Urban Area Coverage (%)

: Wisconsin Sandstone Geology Agricultural Coverage (%)

Figure 1. Land cover types (%) and the location of the mines we visited during our recent frac sands tour of West Central Wisconsin (Note: 1.0 = 100%)

“Thank God for Superior Silica Sands,” said Jim Walker, Director of Operations. He wasn’t directly touting his employer’s virtues, but rather sharing a quote from a landowner pleased with the income derived from leasing their farm for the sand beneath. According to Walker, Superior has over 100,000 acres of mining leases in Wisconsin – enough to support their company’s anticipated needs for the next 30 years. Based on frac sand mine permitting data provided to us by the planning commission, this 100,000 acreage translates to 939,700,000 tons of frac sand (enough for 313,233 horizontal wells). Overall, Wisconsin’s frac sand mines are currently producing 185-211 million tons of frac sand from 128 facilities.

Superior is one of more than six sand companies working in the area. One state resident recently emailed me complaining that “we are being inundated with industrial sand mining.” Her perspective is one of concern, but we are told of farmers who are eager to lease their land for potentially hundreds of thousands of dollars in annual payments. Superior prides itself on hiring from the community. The jobs pay well, nearly twice the regional average, according to the planning commission. Healthcare benefits and a 401k are included. At quick glance, it is an economic boom to a rural region, but will it last? Superior has a 10-year contract to supply sand to Schlumberger, a giant in hydraulic fracturing services. Sand prices – affected by competition and overproduction – are dropping, however.

Sand Mining Risks

Environmental impacts may be the biggest cause for worry. Some mining operations can cover more than 450 acres and often involve the destruction of forests. This may happen piecemeal, perhaps 20 acres at a time, but forest habitat and the associated functions (e.g. carbon storage and accrual) are nevertheless diminished. The land is remediated¹, but the landowner makes the decisions as to how this occurs. They might choose to plant prairie grasses or trees, but a common preference is more cropland – the latter option enabled by a post-mining reduction in topography. Adaptable wildlife like deer may take the changes in stride, but forest-dependent species and vulnerable plant communities will likely suffer. Water quality and quantity issues have also been highlighted by Wisconsin Watch, Minneapolis Star Tribune, and Minnesota Public Radio.

Public health impacts are perhaps less clear. Superior officials explain that only the finest sand sizes are a legitimate inhalation hazard, and those are atypical to the frac sand industry. A 2012 OSHA hazard alert, however, listed respirable crystalline silica as a significant workplace hazard on unconventional oil and gas well pads, just behind the risk for physical injuries and hydrogen sulfide exposure. At least at Superior, they rigorously monitor the air quality onsite and outside their boundaries. Employees are even monitored for what they breathe. Superior shows data underscoring its outstanding safety and regulatory compliance record. I observe no noticeable blowing of sand or dust on site. While I am on the ground touring, however, Ted enjoys a bird’s eye view courtesy of LightHawk. From the plane, he witnesses aerial movement of material off of other sand mines.

Emissions from increased truck traffic may also present an air quality concern. Dump trucks ply the back roads like worker ants delivering load after heavy load from the mines to the drying plants. The general increase in activity in these forgotten areas may be a lifesaver for some, and a worry for others. Trains with scores of covered, sand-packed cars rumble down the tracks bound for distant shale basins. Texas awaits the trains departing Superior’s Baron plant. Meanwhile, communities express concern about increasing speeds and the safety of crossings.

A Complicated Perspective

For me, the day’s enlightening dialogue and experiences underscore the rough, expanding tendrils of unconventional oil and gas development. They reach far and have complex, often abrasive effects. Here, in the land of Leopold, the father of the Land Ethic, I can’t help but wonder: What would Aldo say about the transformation of his beloved countryside?

: Sand mining from the sky – Wisconsin 2013

: Frac sand up close

: Frac sand mining – Wisconsin 2013

View all photos from tour >

Footnotes

For additional resources and articles on sand mining issues, visit the Land Stewardship Project in Minnesota and Wisconsin Watch.

[1] Reclamation success, permitting, bond release, inspection and enforcement, and land restrictions were put into law by the Carter administration and introduced by Arizona Republican Morris Udall as defined by the Surface Mining Control and Reclamation Act of 1977, which also created the Office of Surface Mining.

USGS Stream Gages Helpful in Monitoring Risks in Shale-gas Extraction Regions

October 22, 2013/by Karen Edelstein

Weld County, CO – 9-14-13: A floating tank leaks an unknown fluid on flooded farm (Photo By Andy Cross/The Denver Post)

By Karen Edelstein, NY Program Coordinator, FracTracker Alliance

We’re now in the aftermath of September’s catastrophic floods in Colorado that hit Boulder and Weld counties notably hard, damaging or destroying 18,000 homes and killing at least 10 people. The gas industry has asserted that relatively little damage occurred; only 37,000 gallons of fluid escaped into the rural landscape, including over 5,200 gallons of crude oil that seeped directly into the South Platte River. According to Conoly Schuller, president of the Colorado Oil and Gas Association, “In the context of hundreds of billions of gallons of rain, and millions of gallons of raw sewage, 37,000 gallons is pretty small.”

Environmentalists, however, say that the long-term impacts of the flooding cannot yet be determined. They also point out how the dangers of placing oil and gas rigs in flood-plain areas are a recipe for disaster. Amy Mall, policy analyst for the Natural Resources Defense Council, noted the sheer luck that most of the flooding occurred in areas where active fracking operations were not actually happening; most of these wells were already in production. About 1,900 wells were “shut in” in preparation for the predicted flooding, but storage tanks and other production-related equipment experienced the impacts of the flood waters.

FracTracker Alliance created the following map of United States Geological Survey (USGS) streamflow gage stations across the Lower 48, in areas of mapped shale plays. Each of the USGS points is interactive. Pop-up bubbles allow the user to link directly to the USGS websites for that particular stream gage. Note that not all of the stream gages are currently active; some show only historic USGS data. Many sites, however, show a wealth of real-time information on stream discharge and allow the user to customize time parameters. USGS also includes stream gage height and contributing drainage area. Zooming into an area, users will also see wetlands delineated as part of the National Wetlands Inventory. These wetlands may also be endangered by floods that pick up waste material from oil and gas extraction sites.

Click here to view the full-screen version of this map.

To view gas wells in a particular state, visit FracTracker’s state-by-state map gallery.

Links to more on the Colorado floods of September 2013:

Almost Heaven

October 16, 2013/by FracTracker Alliance

By Brook Lenker, Executive Director, FracTracker Alliance

Touring Doddrige County, West Virginia

On September 26^th, FracTracker staff and board member, Brian Segee, traveled to Doddridge County, West Virginia for an eye-popping tour. This endeavor was led by Diane Pitcock of West Virginia Host Farms and local activists who are deeply concerned about the fate of their region – an area overwhelmed by shale gas development.

Approaching West Union on route 50, a giant flare roars above the roadway and about every fourth vehicle, mostly pickups, tankers, and dump trucks, suggest association with the shale gas industry. At the café in town, vehicles baring EQT logos fill the lot. Nearby, Middle Island Creek flows thick and brown despite an absence of rain for the past five days. Diane says it’s frequently muddy from the constant pipeline construction upstream.

Mark West site

The first stop is a Mark West complex with a cryogenic plant burning off excess hydrocarbons, a yard for loading CNG on tanker trucks, one well pad, and another in the works (see photo right). To build the latter, a hillside is being disemboweled. The heavy equipment and a train of idling trucks release diesel emissions. A stream once coursed through the field in the foreground, but the previous landowner had filled and relocated it without a permit. Watching and photographing from the adjoining rail trail, irony rules. The trail sign is topped by a company-placed “No Trespassing” sign. From the discussion and observations, it’s clear that the environment is being devalued and degraded in Doddridge County.

The tour continues on to a water withdrawal site. According to the permit numbers plastered beside the conduit, the site hosts approximately 50 unconventional gas wells – each requiring millions of gallons of water to crack the shale and hasten the flow of gas.

Right-of-Way?

Next, we traverse gravelly back roads widened by the industry. The roadway expansion often requires the purchase of right-of-way from landowners. Our guides tell us that if a landowner says no, sometimes they are told “if you don’t sell, we’ll take it by eminent domain.” The threat is hollow if not deceitful, since in such circumstances the industry has no right to exercise eminent domain. The industry does have the right to access mineral rights they may own, however, even if they don’t own the property on the surface. In West Virginia, these “split estate” situations are as common as country music, only they project a much more somber note to the landowner, especially when the gas company comes knocking.

A Neighbor’s Perspective

Well pad visit

A freshly cut and clearcut road travels onward and upward across a half mile or more of former forest where a nice lady owns the land but not the natural gas being accessed more than a mile below. Piles of logs line the roadside, a reminder of what was. The road ends at a fenced impoundment holding thousands of gallons of impaired water. An odor, akin to antifreeze, hangs in the dry, dusty air. The lady tells the group about the wildlife she has seen, including the songbirds that rest on the high fence and likely drink from the poisonous reservoir.

Downhill lies an expansive well pad, big enough for a football game if there wasn’t the metallurgical din and sprawl of a towering drill rig and the pipes and machinery that accompany it. The landowner’s presence enables our group to enter the working well pad where workers, sleeping off a long shift, emerge from a trailer. While over 30 of her roughly 80 acres are affected by drilling-related activities, only a payment for timber is in negotiation. Meanwhile, she pays the taxes on the land – a parcel that will never quite be the same. Tom Bond, a local and well-informed activist, wistfully comments, “This is just the beginning. Eventually there will be well pads everywhere.” He may be right.

Pipeline Construction

A golden afternoon closes crossing steel plates over an open trench and green pipeline. The corridor is an undulating, exposed ribbon of ground spanning ridge to ridge in each direction. There are many more just like it snaking across the hills and hamlets of West Virginia from one compressor station to another.

From witnessing the industry’s heavy footprint to the stories we hear of problems emerging in home water wells, somehow a happy John Denver tune now seems melancholy.

Additional Resources

European Drilling Perspectives

September 23, 2013/by FracTracker Alliance

By Samantha Malone, MPH, CPH – Manager of Science and Communications

In August I spent a little over two weeks in Europe, the first of which was for work in Berlin, Germany and Basel, Switzerland. Now that I have had some time to process my travels and am back on a proper sleep schedule, I thought I’d provide a little wrap up of my impressions of Europe and the issue of unconventional drilling.

Berlin, Germany

In Berlin, I was hosted by two innovative organizations: JF&C and Agora Energiewende. JF&C is a consulting company that advises on international markets and sustainable growth. The roundtable held by JF&C was intended to bring together a diverse group of decision-makers in Germany to discuss potential challenges of heavy drilling in Europe — and they did not disappoint. Participants included representatives from the:

Federal Ministry of Economics and Technology (BMWi) Raw Materials Policy department,
Ecologic Institute,
Federal Environment Agency,
BDEW,
The Nature Conservancy,
Polish Embassy,
Wintershall,
BASF,
Niedersachsen,
Baden-Württemberg, and
BMU Water Management, Waste Management, Soil Conservation department.

The diverse backgrounds of the group led to a heated yet balanced debate on the topic of whether unconventional gas extraction should occur in Germany, as well as the rest of Europe. I was quite impressed by the transparent and matter-of-fact perspectives held by attendees, which as you can see above included governmental, NGO, and industry reps.

My next presentation in Berlin was coordinated by Agora Energiewende. Energiewende refers to Germany’s dedication to transitioning from non-renewable to more sustainable fuels. You can read more about the movement here. This forum was set up in a more traditional format – a talk by me followed by a series of questions from the audience. Many of the attendees at this event were extremely well informed about the field of unconventional drilling, climate change, and economics, so the questions were challenging in many respects. Attendees ranged from renewable energy developers to US Embassy personnel. As a reflection of such diversity, we discussed a variety of topics at this session, including US production trends and ways to manage and prepare databases in the event that heavy drilling commences in Germany and other parts of Europe.

Interestingly, one of the major opponents of this form of gas extraction in Germany, I learned, has been the beer brewers. (They were not able to be at the table that day, sadly enough.) German breweries that adhere to a 4-ingredient purity law referred to as Reinheitsgebot are very concerned and also very politically active. You can read more about beer vs. fracking here, just scroll down that page a bit.

Over decadent cappuccinos the next morning, I met with Green Parliament representatives who wanted to hear firsthand about FracTracker’s experience of drilling in the U.S. Overall, my Berlin tour showed me that many individuals seemed skeptical that unconventional drilling could safely fulfill their energy needs, while also possessing a hearty intellectual craving to learn as much about it as they could.

Basel, Switzerland

The second part of the week was dedicated to attending and presenting at the International Society for Environmental Epidemiology conference in Basel, Switzerland. I participated in a panel that discussed the potential environmental and public health impacts of unconventional gas and oil drilling, as well as methods for prevention and remediation. The audience was concerned about a lack of regulatory and data transparency and the likelihood that such operations could contaminate ground/drinking water supplies. Based on the number of oil and gas wells impacted by the recent Colorado flooding tragedy, I cannot blame them. Most of these attendees were from academia or non-profits, although not entirely; check out coverage from this Polish radio station. (As mentioned in a previous post, Poland is one of the countries in Europe that has the potential for heavy drilling.)

The amount of knowledge I gained – and shared – from this one week alone is more than could have been possible in a year through phone calls and email exchanges. I am incredibly thankful for our funders’ and FracTracker’s support of this endeavor. Being able to discuss complex issues such as unconventional drilling with stakeholders in person is an invaluable key for dynamic knowledge sharing on an international level.

Links to My Presentations (PDFs): JF&C | Agora | ISEE

A few non-work pictures from the second week of my trip…
Dornbirn, Austria	Lake Lugano, Switzerland
The Alps, Switzerland	Milan, Italy

Ethane Cracker Discussion in Regional Air Pollution Report

September 17, 2013/by FracTracker Alliance

Pittsburgh Regional Environmental Threats Analysis (PRETA) Air: Hazardous Air Pollutants

Although now we are an independent non-profit, FracTracker.org actually started as a project of CHEC at the University of Pittsburgh Graduate School of Public Health. At that time, Matt, Kyle, and I worked with researchers such as Drew Michanowicz and Jim Fabisiak of Pitt, as well as Jill Kriesky now of the Southwest PA Environmental Health Project, on a data mapping and analysis project called PRETA. The Pittsburgh Regional Environmental Threats Analysis (PRETA) is intended to inform stakeholders about Southwest Pennsylvania’s major environmental health risks and provide ways to manage them. CHEC worked with key decision makers and other academics to identify, prioritize, and assess these risks. The top three risks identified were ozone, particulate matter (PM), and hazardous air pollutants (HAPs). Due to the extensive time that research like this takes, the final report about hazardous air pollutants was just recently released.

Relevant to our oil and gas readers, the HAPs report included a piece about the proposed ethane cracker slated to be built in Beaver County, PA. Below is an excerpt of PRETA HAPs that discusses how the air quality in our region may change as a result of the removal of the present zinc smelter on that site, in place of the new cracker facility.

Read Full Report (PDF)

Excerpt: The Proposed Monaca, PA Ethane Cracker

Future Trends: New Sources of HAPs in Western Pennsylvania?

All of the previous risk analyses and data discussed [earlier in the report] were drawn using historical data collected in previous years. There is considerable delay around emissions inventory collection, air monitoring data collection, atmospheric modeling, and the calculated risk estimates’ being made public. Hence, these analyses speak best toward past and present trends. They often are less useful in predicting future risks, especially when sources and technologies are constantly changing. For example, better pollution mitigation and retrofitting processes should curtail future emissions from present levels. In addition, changing the profile of various industries within a region also will alter atmospheric chemistry and subsequent risks in future scenarios.

In recent years, there has been an unprecedented expansion of unconventional natural gas development (UNGD) in Western Pennsylvania, Ohio, and West Virginia driven in part by the recent feasibility of hydraulic fracturing, which is part of a drilling procedure that allows for the tapping of the vast methane deposits contained in the Marcellus and Utica shales beneath Pennsylvania and surrounding states. Primarily, drillers are seeking to extract methane (CH₄), the primary component of natural gas. However, a portion of the natural gas present in our area is considered “wet gas,” which includes heavier hydrocarbons like ethane, propane, and butane that are typically dissolved in a liquid phase or condensate. These compounds are separated from the methane to be marketed as such products as liquid propane or used as feedstock in numerous other chemical processes. Therefore, a high demand remains for wet gas deposits regardless of fluctuating natural gas (methane) market prices. Thus, a large-scale expansion in other industries (e.g., chemical manufacturing) is anticipated to follow UNGD; new industrial facilities are needed to support the refining of wet gas condensates. For example, an ethane cracker converts or “cracks” ethane, a by-product of natural gas, into ethylene so that it can be used in the production of plastics.

Located in Monaca, Pa. (Beaver County), about 12 miles east of the West Virginia border, is an aging zinc smelter owned by the Horsehead Corporation. The present Horsehead facility is currently the largest zinc refining site in the United States, producing metallic zinc and zinc oxide from recycled material and steelmaking waste. The plant opened in the 1920s to take advantage of the by-products of steel manufacturing and has expanded and modernized over time. It employed about 600 workers until recently, when the company announced its relocation to a new state-of-the-art facility in North Carolina in the near future. The scope of this metal-refining operation was such that it was a significant source of metals and criteria air pollutants.

Recently, Shell Chemical, U.S. subsidiary of Royal Dutch Shell PLC, announced plans to build an ethane cracker in the northeast to take advantage of UNGD. Lured by substantial tax benefits and other economic incentives, Shell chose the former zinc smelting site in Monaca as its proposed new location for such a facility and, in March 2012, received the approval from Pennsylvania officials to build this petrochemical complex. The cracker, according to industry representatives, will be a multibillion-dollar structure and provide thousands of jobs for Pennsylvanians ^{43, 44}. However, many of these jobs depend on the influx of concurrent industries and technologies, which are projected to follow in the wake of sufficient petrochemical refining facilities like the ethane cracker. Thus, it is not likely to be the sole source of pollutants in the area once constructed. Though plant construction remains years away, regional air pollutant composition and chemistry are poised to change as well. Adding to the issue is the fact that the zinc smelter, ranked as one of the worst air polluters in the country in 2002 ⁴⁵, will be decommissioned and have its operations moved to North Carolina.

Here, we will attempt to compare the pollutant profiles of the old and new air pollution sources in order to deduce potential air pollutant changes to existing air quality in the region. Previous emission inventories are available for the Horsehead zinc smelter (EPA Toxic Release Inventory for 2008) ⁴⁶. Although the proposed cracker facility’s engineering specifics are not available yet, using the records of a similar existing wet gas processing plant, we can approximate the proposed cracker’s yearly emissions. In this case, we have chosen the similarly sized Williams Olefins Cracker Facility currently operating in Geismar, La., whose emissions profiles for 2008 also were available ⁴⁶. This plant, owned by Williams Partners, L.P., processes approximately 37,000 barrels of ethane and 3,000 barrels of propane per day and annually produces 1.35 billion pounds of ethylene.

In assessing the emission inventories at the two sites, we first sought to compare those pollutants that were common to both facilities. Table 5 (above) compares the annual release of criteria pollutants for which National Ambient Air Quality Standards (NAAQS) exist. These include ozone, sulfur dioxide, nitrogen oxides, particulate matter (PM₁₀, PM_2.5), lead, and carbon monoxide, for which health-based regulatory standards exist for their concentration in ambient air¹. Not surprisingly, the zinc smelter released large amounts of lead into the air (five tons per year). The proposed ethane cracker, on the other hand, would release only trace amounts of lead into the air and about 0.1 percent of the sulfur dioxide, 3 percent of the carbon monoxide, and 50 percent of the nitrogen oxides of the zinc smelter. Overall, release of PM would be of a similar order of magnitude at the two sites. Thus, the representative cracker facility by itself emits less NAAQS criteria pollutants than the smelter facility.

Similarly, Table 6 (above) examines similarly reported HAPs released from both of the facilities in question. A comparison of available emissions inventories of HAPs reveals a list of common pollutants, including acrolein, benzene, ethylbenzene, xylene, and volatile organic compounds (VOCs). Note the projected increase in release of acrolein and VOCs by the proposed ethane cracker. The latter are a rather broad class of organic chemicals that have high vapor pressure (low boiling point), allowing appreciable concentrations in the air as a gaseous phase ^{47, 48}. Examples of VOCs include formaldehyde, d-limonene, toluene, acetone, ethanol (ethyl alcohol), 2-propanol (isopropyl alcohol), and hexanal, among others. They are common components of paints, paint strippers, and other solvents; wood preservatives; aerosol sprays; cleansers and disinfectants; moth repellents and air fresheners; stored fuels and automotive products; hobby supplies; and dry-cleaned clothing. They also possess a diverse range of health effects, including, but not limited to, eye and throat irritation, nausea, headaches, nosebleeds, and skin rashes at low doses, and kidney, liver, and central nervous system damage at high doses. Some are known or suspected carcinogens. These chemicals are more often known for their role in indoor air pollution and have been linked to allergies and asthma ⁴⁹. Recall that acrolein is already the primary driver of noncancer respiratory risk in the PRETA area, and releases from the proposed cracker would theoretically add to that burden.

Table 7 shows a compiled list of HAPs that were released from the Geismar plant in 2008 but not from the zinc smelter, highlighting the potential change in the pollutant mixture. For comparison, the pollutants highlighted in yellow represent those that are several orders of magnitude greater than those emitted by the Clairton Coke Works in 2008. Note the rather large emissions of formaldehyde and acetaldehyde that were discussed above as the number one and number five existing cancer drivers in the area.

Other VOCs of note include ethylene glycol, ethylene oxide, methyl-tert-butyl ether and propionaldehyde. While all these pollutants may have toxic effects on their own, one of the primary concerns, especially in outdoor air, should be their ability to form secondary pollutants. For example, we have noted previously that both acetaldehyde and formaldehyde can be formed via photo-oxidation reactions of other hydrocarbons and VOCs. Thus, the direct emissions reported in the table are likely to be significant underestimations of the true burden of acetaldehyde and formaldehyde in the area near the cracker. It also should be mentioned that a complex nonlinear sensitivity exists among VOCs, NO_X, and the production rate of ozone (O₃). Most urban areas are considered NOX saturated or VOC sensitive and therefore have low VOC/NO_X ratios. In these environments, ozone actually decreases with increasing NOX and increases with increasing VOCs—a potentially likely situation within the urban areas of Southwestern Pennsylvania.

In conclusion, it would appear that the replacement of the existing zinc smelter with the proposed ethane cracker has the potential to significantly transform the current pollutant mixture in the region. The elimination of lead and other heavy metal emissions would be replaced by increases in formaldehyde and acetaldehyde. In addition, it does not appear that the proposed ethane cracker alone would increase any of the NAAQS criteria air pollutants, with the possible exception of ozone. On the other hand, the rather large releases of several known cancer drivers, such as formaldehyde and acetaldehyde, from the proposed cracker could increase cancer risk in the immediate proximity. In addition, the large influx of VOCs and fugitive emissions from these operations warrants further predictive analysis, especially with regard to current pollution-mitigating strategies that may not be anticipating a transforming pollutant mix.

Authors and Credits

University of Pittsburgh Graduate School of Public Health
Center for Healthy Environments and Communities
Pittsburgh, PA | August 2013

Authors

Drew Michanowicz, MPH, CPH
Kyle Ferrar, MPH
Samantha Malone, MPH, CPH
Matt Kelso, BA
Jill Kriesky, PhD
James P. Fabisiak, PhD

Technical Support

Department of Communications Services
Marygrace Reder, BA
Alison Butler, BA

Full HAPs Report (PDF) | Ozone (PDF) | Particulate Matter (PDF)
For questions related to the full report, please contact CHEC.

References Mentioned in Excerpt

43. Detrow , S. (2012). What’s an ethane cracker? StateImpact – Pennsylvania. Accessed 12-18-12: http://stateimpact.npr.org/pennsylvania/tag/ethane-cracker.

44. Kelso, M. (2012). Jobs impact of cracker facility likely exaggerated. FracTracker Alliance. Accessed 12-18-12: www.fractracker.org/2012/06/jobs-impact-of-cracker-facility-likely-exaggerated.

45. SCORECARD: The Pollution Information Site. (2002). Environmental Release Report: Zinc Corp. of America Monaca Smelter. Accessed 12-18-12: http://scorecard.goodguide.com/envreleases/facility.tcl?tri_id=15061ZNCCR300FR#major_chemical_releases.

46. U.S. EPA. (2008). Technology Transfer Network, Clearinghouse for Inventories and Emissions Factors The National Emissions Inventory. The National Emissions Inventory. Accessed 1-25-13: www.epa.gov/ttn/chief/net/2008inventory.html.

47. U.S. EPA. (2012). An Introduction to Indoor Air Quality (IAQ). Volatile Organic Compounds. Accessed 12-18-12: www.epa.gov/iaq/voc.html.

48. U.S. EPA. (2012). Volatile Organic Compounds (VOCs). Accessed 12-18-12: www.epa.gov/iaq/voc2.html.

49. Nielsen, G.D., S.T. Larsen, O. Olsen, M. Lovik , L.K. Poulsen, C. Glue , and P. Wolkoff. (2007). Do indoor chemicals promote development of airway allergy? Indoor Air 17: pp. 236–255.

Read Full Report (PDF)

OH National Response Center Data on Shale Gas Viewer

September 12, 2013/by Ted Auch, PhD

By Ted Auch, PhD – Ohio Program Coordinator, FracTracker Alliance

Thanks to the Freedom of Information Act (FOIA), we as US citizens have real-time access to “all oil, chemical, radiological, biological, and etiological discharges into the environment anywhere in the United States and its territories” data via the National Response Center (NRC). The NRC is an:

initial report taking agency…[that] does not participate in the investigation or incident response. The NRC receives initial reporting information only and notifies Federal and State On-Scene Coordinators for response…Verification of data and incident response is the sole responsibility of Federal/State On-Scene Coordinators.[1]

We decided that NRC incident data would make for a useful layer in our Ohio Shale Gas Viewer. As of September 1, 2013 it is included and will be updated bi-monthly. Thanks go out to SkyTruth’s generous researchers Paul Woods and Craig Winters. We have converted an inventory of Ohio reports provided by SkyTruth into a GIS layer on our map, consisting of 1,191 events, including date and type, back to January 2012.

The layer is not visible until you zoom in twice from the default view on the map above. It appears as the silhouette of a person lying on the ground with Skull and crossbones next to it. View fullscreen>

Currently, the layer includes 28 hydraulic fracturing-related events, 61 “Big [Oil and Chemical] Spills,” and 1,102 additional events – most of which are concentrated in the urban centers of Cleveland, Toledo, Columbus, and Toledo OH.

From a Utica Shale corporation perspective, 21 of the 28 reports are attributed to Chesapeake Operating, Inc. (aka, Chesapeake Energy Corporation (CHK)) or 75% of the hydraulic fracturing (HF) events, while CHK only accounts for 48% of all HF drilled, drilling, or producing wells in OH. Anadarko, Devon, Halcon, and Rex are responsible for the remaining 7 reports. They collectively account for 2.7% of the state’s current inventory of unconventional drilled, drilling, or producing wells.

[1] To contact the NRC for legal purposes, email efoia@uscg.mil. The NRC makes this data available back to 1982, but we decided to focus on the period beginning with the first year of Utica permits here in Ohio to the present (i.e., 2010-2013).