Frac sand mining from the sky in Wisconsin
Ted Auch, PhD

Wisconsin’s Nonmetallic Mining Parcel Registration Program

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How the frac sand industry is circumventing local control, plus where the industry is migrating

What is nonmetallic mineral mining?

It was more than a year and half ago that anti-frac sand organizer – and movement matriarch – Pat Popple published a white paper by attorney Elizabeth Feil in her Frac Sand Sentinel newsletter. The paper outlined potential impacts of something the Wisconsin Department of Natural Resources (DNR) calls the “Marketable Nonmetallic Mineral Deposit Registration” (MNMDR) program.

The program, passed in 2000, is outlined in Wisconsin’s administrative code under Subchapter VI “Registration of Marketable Nonmetallic Mineral Deposits (NR 135.53-NR 135.64). This program allows landowners to register parcels that sit atop marketable nonmetallic mineral deposits, such as frac sand, according to a licensed professional geologist. The geologist uses “logs or records of drilling, boring, geophysical surveys, records of physical inspections of outcrops or equivalent scientific data” to outline the quality, extent, depth, accessibility, and current market value of the minerals.

If a mine operator is not the landowner, it must first coordinate registration with the landowner to:

… provide protection against present or future land uses, such as the erection of permanent structures, that would impede their development…to promote more orderly future development of identified nonmetallic mineral resources and minimize conflict among land uses.

Where is frac sand mining occurring in Wisconsin?

Badger frac sand mineBadger Mining’s frac sand mine in Curran, Wisconsin
Badger frac sand mine
Badger frac sand mine
Smart Sand mine
Smart Sand mine
Blair Frac Sand mine
Blair Frac Sand mine
Badger frac sand mine-cropped
Badger frac sand mine-cropped

Photos by Ted Auch, Fractracker Alliance, and aerial support provided by LightHawk

Limitations of the registration program

The only requirement under this program is that the landowner “provide evidence that nonmetallic mining is a permitted or conditional use for the land under zoning in effect on the day in which notice is provided to the zoning authorities.” All registrations must be recorded in the county’s registrar of deeds 120 days before filing the registration. This process results in zoning authorities having a 60-day window to determine if they support or object to registrations in circuit courts.

Once counties are notified, they have no recourse for objection aside from proving that the deposit is not marketable or the parcel is not zoned for mining.

As Ms. Feil wrote, this program “preserves…[parcel] eligibility for nonmetallic mining in the future, even if a local governing body later passes new mining restrictions.” The former will have already been proven by the licensed geologist, and the latter is highly unlikely given lax or non-existent zoning in rural Wisconsin, where many land parcels are outside incorporated townships. Any parcel registered on this program remains in the program for a 10 year period and may be automatically re-registered under the initial geological assessment for another 10 year term “at least 10 days and no more than one year before registration expires.”

After this 20-year period, parcels start from scratch with respect to the registration process.

Initial inquiry and map methodology

As part of her white paper, Ms. Feil noted that in a quick check of her home county’s register of deeds, she found six nonmetallic mineral deposit registrations since 2000 in Trempealeau County and nine in neighboring Chippewa County. As a result of Ms. Feil’s initial inquiry, we decided it would be worth conducting a sweeping search for all nonmetallic parcel registrations in the nine most heavily frac sand-mined Wisconsin counties: Trempealeau, Barron, Crawford, Chippewa, Monroe, Jackson, Clark, Dunn, and Eau Claire.

“Wisconsin Nonmetallic Mineral Deposit Parcel Registrations and Likely Mine Parcels” Map

We were fortunate enough to receive funding from the Save The Hills Alliance (STHA) to conduct this research. We received “boots on the ground” assistance from the likes of Ms. Feil, Ms. Popple, and several other volunteers for acquiring hard copies of registrations as of the summer of 2018.

Our goal was to construct a map that would provide a predictive and dynamic tool for residents, activists, non-profits, researchers, local governments, and journalists to understand the future scale and scope of frac sand mining across West Central Wisconsin. We hope this will inspire a network of citizen scientists and mapping tools that can serve as a model for analogous efforts in Illinois, Minnesota, and Southeastern Michigan.

In addition to identifying parcels falling under Wisconsin DNR’s MNMDR registration program, we also used Wisconsin’s State Cartographer’s Office and Land Information Program “V4 Statewide Parcel Data” to extract all parcels:

  1. Currently owned by active or historically relevant frac sand mine operators and their subsidiaries,
  2. Owned by families or entities that have allowed for mining to occur on their property and/or have registered parcels under the MNMDR program, and,
  3. All cranberry production parcels in Wisconsin frac sand counties – namely Monroe, Jackson, Clark, Wood, and Eau Claire, with Monroe, Jackson, and Wood the state’s top producing counties by acreage.

The latter were included in the map because Wisconsin DNR identified the importance of cranberry bogs in their Silica Sand Mining in Wisconsin January 2012 report. The report defined the “Cranberry Exemption” as follows:

Some of the counties in central Wisconsin that are seeing an increase in frac sand mining are also home to much of the state’s cranberry farming. Mining sand is a routine practice in the process of raising cranberries. Growers use sand in the cranberry beds to provide adequate drainage for the roots of the cranberry plants. The sand prevents root rot and fosters plant growth. Chapter 94.26, Wis. Stats, was established in 1867 and exempts cranberry growers from much of the laws applying to waters of the state under Chapter 30, Wis. Stats. With this exemption in place cranberry growers can, in theory, mine sand wherever and however they desire for use in cranberry production. Some cranberry growers are taking advantage of the high demand for sand and are selling their sand on the frac sand market (emphasis added). However, the Department has recently determined that the exemption in Ch. 94.26, Wis. Stats., from portions of Chapters 30 and 31, Wis. Stats., for cranberry culture is not applicable to non-metallic mining sites where a NR 216, W is. Adm. Code, stormwater permit is required. For those non-metallic mining operations where the material is sold and hauled off site, Chapters 30 and 31, Wis. Stats., jurisdiction will be applied.

Finally, the last data layer we’ve included in this map speaks to the enormous volumes of subsurface water that the industrial sand mining industry has consumed since 2010. This layer includes monthly and annual water volume withdrawals by way of 137 industrial sand mine (i.e., IN 65) high capacity wells (Our thanks to Wisconsin DNR Water Supply Specialist – Bureau of Drinking Water and Groundwater’s Bob Smail for helping us to compile this data.)

We have coupled that data to annual tonnages in order to quantify gallons per ton ratios for several mines across several years.

Results

Below is the completed map of current and potential frac sand mines in West Central Wisconsin, as well as high capacity wells. Click on the features of the map for more details.

View Map Full Screen| How FracTracker maps work 

We identified 4,049 nonmetallic parcel registration and existing sand mine operator parcels totaling 113,985 acres or 178 square miles spread across 14 counties in West Central Wisconsin (Table 1). The largest parcel sizes were U.S. Silica’s 398-acre parcel in Sparta, Monroe County and Badger Mining’s 330-acre parcel in St. Marie, Green Lake County. The average parcel is a mere 28 acres.

To put these figures in perspective, back in 2013 we quantified the full extent of land-use change associated with frac sand mining in this same region and found that the 75 active mines at the time occupied a total of 5,859 acres and averaged roughly 75 acres in size. This means that if current parcel ownership and nonmetallic parcel registrations run their course, the impact of frac sand mining from a land-use perspective could potentially increase by 1,900%!

This is an astounding development and would alter large chunks of West Central Wisconsin’s working landscape, dairy industry, and “Badger State” mentality forever.

Table 1. Nonmetallic or operator-owned frac sand parcels and their total and average acreage in 14 West Central Wisconsin counties

County Number of Parcels Total Acreage Average Parcel Acreage
Barron 267 8,737 33
Buffalo 211 5,902 28
Burnett 4 140 35
Chippewa 580 15,585 27
Clark 74 2,391 32
Dunn 73 2,245 31
Eau Claire 151 4,101 27
Green Lake 74 2,648 36
Jackson 1,128 36,152 32
Monroe 459 11,185 24
Pierce 168 3,415 20
Rusk 2 64 32
Trempealeau 787 19,375 25
Wood 71 2,044 29

As for the “Cranberry Exemption” identified by Wisconsin DNR, we identified an additional 3,090 cranberry operator or family-owned parcels totaling 98,217 acres or 153 square miles – nearly equal to the acreage identified above. Figure 1 shows the extent of cranberry bog parcels and frac sand mines in Monroe, Wood, and Jackson Counties. The two largest parcels in this inquiry were the 275-acre parcel owned by Fairview Cranberry in Monroe County and a 231 acre-parcel owned by Ocean Spray in Wood County. Interestingly, the former is already home to a sizeable (i.e., 266 acres) frac sand mine operated by Smart Sand pictured and mapped in Figure 2.

Figure 1. Cranberry bog parcels and frac sand mines in the Wisconsin counties of Monroe, Jackson, and Wood

Figure 2. Current and potential extent of Smart Sand’s Fairview Cranberry frac sand mine, Tomah, Monroe County, Wisconsin

In total, the potential for mine expansion in West Central Wisconsin could consume an additional 212,202 acres or 331 square miles. Characterized by dairy farms, and also known as The Driftless Area, this region is where Aldo Leopold penned his masterpiece, A Sand County Almanac. To give a sense of scale to these numbers, it is worth noting that this type of acreage would be like clearing an area the size of the Dallas-Fort Worth metropolis.

Project limitations and emerging concerns

After completing this project, Liz Feil, Pat Popple, and I got on the phone to discuss what we perceived to be its limitations, as well as their concerns with the process and the implications of the MNMDR program, which are listed below:

1. Both Liz and Pat found that when they visited certain counties to inquire as to parcel registrations, most of the registrars of deeds had very little, if any, idea as to what they were talking about, which begged the questions:

  • Why does Wisconsin not have a uniform protocol and archival process for such registrations?
  • What are the implications of this program with respect to county and township taxable lands, future zoning, and/or master planning?
  • What does this program mean for surface and mineral rights ownership in Wisconsin, a state where these two are coupled or decoupled on a parcel by parcel basis?

2. Liz and Pat felt they ended up teaching county registrars more about this registration process during this exercise than they ended up learning themselves.

3. Given the potential ramifications of these types of programs, such registrations should be centrally archived rather than archived at disparate sites across the state. Registrations should be explicitly bolted onto efforts like the aforementioned statewide V4 Statewide Parcel Data, given the fact that the MNMDR parcels are registered for 10 years.

The footprint of frac sand mining at any one point is just a glimpse into how vast its influence could be in the future. Mapping parcel ownership like we’ve done gives people a more realistic sense for the scale and scope of mining in the future and is a more realistic way to analyze the costs/benefits of such an industry. This type of mapping exercise would have greatly benefited those that live in the coal fields of Appalachia and the Powder River Basin as they began to debate and regulate mining, rather than the way they were presented with proposals as smaller discrete operations.

This piecemeal process belies the environmental and social impact of any industrial process, which frac sand mining very much is.

Industrial sand mining and high capacity wells

There is a growing concern, based on a thorough analysis of the data, that the High Volume Hydraulic Fracturing (HVHF) industry’s unquenchable thirst for freshwater is growing at an unsustainable rate. Here at FracTracker, we have been quantifying the exponential increase in HVHF water use, namely in Ohio’s Muskingum River Watershed and northern West Virginia, for more than five years now. More recently, Duke University’s Avner Vengosh has conducted a thorough national analysis of this trend.

While the trends in HVHF water use and waste production are disturbing, such analysis leaves out the water industry uses to mine and process frac sand, or “proppant” in places like Wisconsin, Minnesota, and Illinois. Failure to incorporate such values in an analysis of HVHF’s impact on freshwater, both surface and subsurface, grossly underestimates the industry’s impact on watersheds and competing water uses.

Figure 3 shows monthly and cumulative water demand of frac sand mining. The first thing to point out is the marked seasonal disparities in water withdrawals due to the fact that many of Wisconsin’s frac sand mines go dormant during the winter and ramp up as soon as the ground thaws. The most important result of this work is that we finally have a sense for the total volumes of water permanently altered by the frac sand mining industry:

An astounding 30 billion gallons of water were used between January 2010 and December 2017

This figure is equivalent to the annual demand of ~72,500 US residents (based on an assumption of 418,184 gallons per year). This figure is also equivalent to between 2,179 and 3,051 HVHF wells in Ohio/West Virginia.

Figure 3. Cumulative and monthly water demand by Wisconsin’s frac sand mine Hi-Cap wells, January 2010-December 2017

A graph of water use trends for frac sand mining which shows significant increase in monthly and cumulative water consumptionFigure 4 shows water use by operator. The worst actors with respect to water withdrawals over this period were two wells serving Hi-Crush’s active Wyeville mine that in total used 9.6 billion gallons of subsurface water. Covia Holdings, formerly Unimin and Fairmount Santrol, utilized 5.8 billion gallons in processing an undisclosed amount of frac sand at their Tunnel City mine. Covia’s neighboring mine in Oakdale, owned by Wisconsin White Sand and Smart Sand, used more than 2.5 billion gallons during this period spread across six high-capacity wells.

Figure 4. Total water usage by operator, January 2010-December 2017

Water Use Graph by Frac Sand Operator, 2010-2017These tremendous water volumes prompted us to ask whether we could determine the amount of water needed to mine a typical ton of Wisconsin frac sand. There are numerous issues with data quality and quantity at the individual mine level and those issues stretch from the USGS all the way down to individual townships. However, some townships do collect tonnage records and/or “Fees Tied to Production” from mine operators which allow us to quantify productivity. Using this scant data and the above water volume data we were able to determine “gallons to tons of sand mined” ratios for the years of 2013, 2014, 2015, and/or 2017 for four mines and those ratios range between 30-39 to as much as 521 gallons of water per ton of sand (Table 2).

Table 2. Gallons of water per ton of sand mined for four Wisconsin frac sand mines, 2013-2017

 

Owner

  

Property

  

City

  

County

 Gallon Per Ton
2013 2014 2015 2017
Wisconsin Industrial Sand Maiden Rock Facility Maiden Rock Pierce 98 90 66 —
Thompson, Terry Thompson Hills Mine Chetek Barron — 30 521 —
Lagesse, Samuel NA Bloomer Chippewa 39 — 48 —
CSP Rice Lake Mine Rice Lake Barron — — — 104

Conclusions

For far too long we’ve been monitoring frac sand mining retrospectively or in the present tense. We’ve had very little data available to allow for prospective planning or to model the impact of this industry and its role in the Hydraulic Fracturing Industrial Complex writ large. Given what we are learning about the fracking industry’s insatiable appetite for water and sand, it is imperative that we understand where frac sand mining will occur if this appetite continues to grow (as we expect it may, given the current political environment at the state and federal level).

Three examples of this growing demand can be found in our work across the Great Lakes:

1) With the new age of what the HVHF industry is calling “Super Laterals”, between 2010 and 2017 we saw average proppant demand jump nearly six-fold to roughly 25-30 thousand tons per lateral.

2) In Le Sueur County, MN Covia – which is a recent merger of silica mining giants Unimin and Fairmount Santrol – has plans and/or parcel ownership speaking to the potential for an 11-fold increase in their mining operations, which would increase acreage from 560 to 6,500 acres (if sand demand increases at its current clip) (Figures 5 and 6).

 

Figure 5. Unimin’s current 560-acre frac sand mine parcel in Kasota, Le Sueur County

 

Figure 6. The potential 6,500 extent of Unimin mining by way of parcel ownership search

 

3) As we’ve previously highlighted, the potential outside Detroit, Michigan for US Silica to expand its current frac sand mining operations would displace hundreds of families. The planned expansion would grow their mine from its current 650-acre footprint to nearly 1,400 acres in the town of South Rockwood, Monroe County (Figure 7).

 

Figure 7. US Silica’s current (642 acres) and potential (1,341 acres) frac sand mine footprint in Monroe County, Michigan.

Given our experience mapping and quantifying the current and future impact of frac sand mining in states with limited mining activity, we felt it was critical that we apply this methodology to the state where industry is mining a preponderance of frac sand. However, this analysis was rendered a bit more complicated by the presence of the MNMDR program and Wisconsin DNR’s “Cranberry Exemption.” Adding to the challenge is the fact that many in Wisconsin’s frac sand communities demanded that we address the tremendous volumes of water being used by the industry and work to incorporate such data into any resulting map.

We hope that this map allows Wisconsin residents to act in a more offensive and prospective way in voicing their concerns, or simply to become better informed on how sand mining has impacted other communities, will influence them, and what the landscape could look like in the future.

It is critical that we see sand mining not as discrete mines with discrete water demands but rather as a continuum, or better yet an ecosystem, that could potentially swallow large up sizeable chunks of Western Wisconsin.

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

P.S. We’ll continue to add MNMDR registered parcels periodically. As parcels change ownership, we will be sure to update both the cranberry bog and industry owned parcel inventory in the comings months and years.

Ted Auch, PhD

Documenting Fracking Impacts: A Yearlong Tour from a Bird’s-Eye-View

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“The aeroplane has unveiled for us the true face of the earth.” by French writer and aviator Antoine de Saint-Exupéry author of Le Petit Prince (The Little Prince)

I always tell people that you can’t really understand or appreciate the enormity, heterogeneity, and complexity of the unconventional oil and gas industry’s impact unless you look at the landscape from the cockpit of a Cessna 172. This bird’s-eye-view allows you to see the grandeur and nuance of all things beautiful and humbling. Conversely, and unfortunately more to the point of what I’ve seen in the last year, a Cessna allows one to really absorb the extent, degree, and intensity of all things destructive.

I’ve had the opportunity to hop on board the planes of some amazing pilots like Dave Warner, a forester formerly of Shanks, West Virginia (Note: More on our harrowing West Virginia flight with Dave later!!), Tim Jacobson Esq. out of La Crosse, Wisconsin, northern Illinois retired commodity and tree farmer Doug Harford, and Target corporate jet pilot Fred Muskol out of the Twin Cities area of Minnesota.

Since joining FracTracker I’ve been fortunate to have completed nearly a dozen of these “morning flights” as I like to call them, and five of those have taken place since August 2017. I’m going to take the next few paragraphs to share what I’ve found in my own words and by way of some of the photos I think really capture how hydraulic fracturing, and all of its tentacles, has impacted the landscape.

The following is by no means an empirical illustration. I’m increasingly aware, however, that often times tables, charts, and graphs fail to capture much of the scale and scope of fossil fuel’s impact. Photos, if properly georeferenced and curated, are as robust a source of data as a spreadsheet or shapefile, both of which are the traditional coins of the realm here at FracTracker.

West Central Wisconsin Frac Sand Mines

August 2, 2017

Figure 1. Wisconsin and Winona, Minnesota silica sand mines, processing facilities, and related operations

It was nearly a year ago today that I met Bloomer, Wisconsin dairy farmer Ken Schmitt at the Chippewa Valley Regional Airport (KEAU) and soon thereafter jumped into Tim Jacobson’s Cessna 172 to get a bird’s-eye-view of the region’s many frac sand mines and their impacts (Figure 1). These sites are spread out over a 12-county region known as West Central Wisconsin (WCW). Ken hadn’t been up to see these mines since October of 2016 and was eager to see how they had “progressed,” knowing what he did about their impact on his neck of the woods in northern Chippewa County.

Ken is one of the smartest guys I’ve ever met, and – befitting a dairy farmer – he is also one of the most conservative and analytical folks I’ve ever met. However, that morning it was clear that his patience with county administrators and the frac sand mining industry had long since run out. He was tired of broken promises, their clear and ubiquitous bullying tactics, and a general sense that his livelihood and the farm he was hoping to leave his kids were at risk due to sand mining’s complete capture of WCW’s residents and administrators.

Meanwhile Mr. Jacobson Esq. was intimately familiar with some of the legal tools residents were using to fight the spread of sand mining in the WCW. This is something he referred to as “anticipatory nuisance” lawsuits, which he and his colleagues were pursuing on behalf of several landowners against OmniTrax’s (f/k/a Terracor) “sand mine, wet and dry processing, a conveyor system to a rail load out with manifest yard” proposal in Jackson County, Wisconsin. I, too, have worked with Tim to inform some of his legal work with respect to the nuisance stories and incidents I’ve documented in my travels, as well as research into the effects of sand mining across Michigan, Illinois, Minnesota, and Wisconsin.

Explore details from our sand mining tour by clicking on the images below:

Wisconsin Proppants frac sand mine and processing infrastructure, Curran, Jackson County, 8/2/2017

Miscellaneous frac sand processing and rail spur, West Central Wisconsin, 8/2/2017

Hi-Crush frac sand processing, conveyor system, and rail spur, Trempealeau County, Wisconsin, 8/2/2017

Hi-Crush frac sand mine highwall, Augusta, Eau Claire County, Wisconsin, 8/2/2017

Hi-Crush frac sand mine, Augusta, Eau Claire County, Wisconsin, 8/2/2017

Fairview Cranberry/Smart Sand Mine, processing infrastructure, and rail loadout spur, Monroe County, Wisconsin, 8/2/2017

Our flight lasted nearly 2.5 hours and stretched out over 4,522 square miles. It included nearly 20 sand mines – and related infrastructure – in the counties of Jackson, Wood, Clark, Eau Claire, Monroe, Trempealeau, and Buffalo. What we saw was a sizeable expansion of the mining complex in the region since the last time I flew the area – nearly four years earlier on October 8, 2013. The number and size of mines that had popped up since that trip were far greater than any of us had expected.

This expansion paralleled the relative – and total –increase in demand for “proppant” from the High Volume Hydraulic Fracturing (HVHF) all across the country (Figure 2).

Figure 1. A map of the likely destination for Wisconsin’s frac sand mines silica sand based on an analysis of Superior Silica Sand’s 2015 SEC 10Ks.

Figure 2. A map of the likely destination for Wisconsin’s frac sand mines silica sand based on an analysis of Superior Silica Sand’s 2015 SEC 10Ks.

West Virginia Panhandle & Southeastern Ohio

January 26, 2018

On the morning of January 26th, I woke up on the west side of Cleveland thinking there was very little chance we were going to get up in the air for our flight with SouthWings’ pilot Dave Warner due to inclement weather. There was a part of me that was optimistic, however, so I decided to make the three hour drive down to the Marshall County Airport (KMPG) in Moundsville, West Virginia from Cleveland in the hopes that the “cold rain and snow” we’d been receiving was purely lake effect stuff and the West Virginia panhandle had not been in the path of the same cold front.

Marshall County, West Virginia Airport (KMPG) staff clearing the runway for our flight with SouthWings pilot Dave Warner, 1/26/2018

Unfortunately, when I arrived at the Moundsville airport I was wrong, and the runway was pretty slick around 8:00 a.m. However, the airport’s staff worked diligently to de-ice and plow the runway and by the time Dave Warner arrived from southern West Virginia conditions were ideal. The goal of this flight was two-fold:

  1. Photograph some of the large-scale high-volume hydraulic fracturing (HVHF) infrastructure in the West Virginia counties of Doddridge, Wetzel, and Marshall owned and operated by MarkWest, and
  2. Allegheny Front’s Julie Grant was doing a story on natural gas gathering pipeline’s impact on waterways, and more specifically the Hellbender Salamander (Cryptobranchus alleganiensis). She was looking to see the impacted landscape from the air.

Both of these goals were achieved efficiently and safely, with the resulting Allegheny Front piece receiving significant interest across multiple public radio and television platforms including PRI’s Living On Earth.

Explore details from our WV / OH tour by clicking on the images below:

Hydraulic fracturing drill rig in a northern West Virginia floodplain, 3/6/2018

Natural gas compressor station and gathering line associated with MarkWest Cracker Facility, West Virginia Panhandle, 3/6/2018

Miscellaneous natural gas compressor station and associated mountaintop removal, West Virginia Panhandle, 3/6/2018

MarkWest Cracker Facility, West Virginia Panhandle, 3/6/2018

Miscellaneous gas gathering line, Belmont County, Ohio, 3/6/2017

Browns Run Coal Impoundment, Benwood, West Virginia, 3/6/2018

On my return drive home that afternoon the one new thing that really resonated with me was the fact that hydraulic fracturing or fracking has come to be defined by 4-5 acre well pads across Appalachian, Texas, Oklahoma, and North Dakota. This is a myth, however, expertly perpetuated by the oil and gas industry and their talking shops. Fracking’s extreme volatility and quick declines in rates of return necessitate that this latest fossil fuel iteration install large pieces of infrastructure like compressor stations and cracking facilities. This all is to ensure timely movement of product from supply to demand and to optimize the “value added” products the global markets demand and plastics industry uses as their primary feedstocks. This large infrastructure was never mentioned at the outset of the shale revolution, and I would imagine if it had been there would be far more resistance.

The one old thing the trip reinforced was the omnipresence and sinuosity of natural gas gathering lines across extremely steep and forested Appalachian geographies. How these pipelines will hold up and what their hasty construction is doing to terrestrial and aquatic wildlife, not to mention humanity, is anyone’s guess; the data is just so darn bad.

Southeastern Ohio

March 5, 2018 – aka, The XTO Powhatan Point Well Pad Explosion Flight

FAA’s Temporary Flight Restriction (TFR) notification

Around 9 a.m. on Thursday, February 15, 2018, an explosion occurred at XTO’s Schnegg frack pad “as the company worked to frack a fourth well” in Powhatan Point, Belmont County, Ohio. Shortly thereafter, a two-mile Temporary Flight Restriction (TFR) was enacted by the Federal Aviation Administration (FAA) around the incident’s location. The TFR was supposed to lapse during the afternoon of March 5, however, due to complications at the site the TFR was extended to the evening of March 8.

We were antsy to see what we could see, so we caught an emergency flight with Dave Warner, only this time under the LightHawk umbrella. We left on the morning of March 5th out of the all too familiar[1] Carroll County-Tolson Airport (KTSO). Although we couldn’t get close to the site, there was a holler valley to the northwest of the pad that allowed us to capture a photo of the ongoing releases. Additionally, within several weeks we obtained by FOIA the raw Ohio State Trooper monitoring footage from their helicopter and posted this footage to our YouTube channel, where it has received 4,787 views since March 19, 2018. This type of web traffic is atypical for anything that doesn’t include kittens, the Kardashians, or the Kardashians’ kittens.

Explore details from our Southeastern Ohio tour by clicking on the images below:

Much like our flight in January the most salient points I got out of Dave’s plane thinking about were:

  • Astonishment regarding the number of gas gathering lines and the fact that they seem to have been installed with very little-to-no reclamation forethought. They are also installed during a time of year when – even if hydroseed is applied – it won’t grow, leaving plenty of chances for predictable spring rains to cause major problems for streams and creeks, and
  • Amazement over the growing inventory of large processing infrastructure required by the HVHF industry. This insfrastructure includes the large Mark West and Blue Racer Midstream processing plants in Cadiz and Lewisville, Ohio, respectively, as well as Texas-based Momentum Midstream’s natural gas liquids-separating complex in Scio along the Carroll and Harrison County borders. That complex is affectionately referred to by the company’s own spokesman as The Beast because of its sheer size.

It is a big plant, a very big plant and far bigger than other plants around here… What’s really amazing that we got it up and running in six months. No one believed that we could do that. – Momentum Midstream spokesman Eric Mize discussing their natural gas liquids-separating complex in Scio, Ohio.

LaSalle County, Illinois

May 24 & 26, 2018

 Frac Sand Mines and The Nature Conservancy’s Nachusa Grasslands Buffalo Herd, Franklin Grove, Illinois

It was during the week of June 20, 2016 that I first visited the frac sand mine capital of the United States: LaSalle County, Illinois. Here is the land of giant silica sand mines owned by even larger multinationals like U.S. Silica, Unimin, and Fairmount Santrol.

Fast forward to the week of May 21st of this year, and I was back in the frac sand capital to interview several folks that live near these mines or have been advocating for a more responsible industry. I conducted a “morning flight” with several journalists and county officials from neighboring Ottawa County.

LaSalle County is an extremely interesting case study for anyone even remotely interested in the food, energy, and water (FEW) conversation that has begun to receive significant attention in the age of the “Shale Revolution.” (Such focus is largely thanks to the extreme amounts of water required during the fracking process.) While LaSalle County has never experienced even a single HVHF permit, it is home to much of the prized silica or “proppant” the HVHF industry prizes. La Salle receives this recognition due to its location above one of the finest sources of silica sand: the St. Peter Sandstone formation. This situation has prompted a significant expansion in the permitting of new silica sand mines and expansion of existing mines throughout the county – from small townships like North Utica and Oglesby to Troy Grove 7 miles north on East 8th Road.

Meanwhile, LaSalle County is home to some of the most productive soils in the United States, due largely to the carbon sequestration capabilities of the tallgrass prairies that once dominated the region. In any given year, the county ranks in the top 5 nationally based on the amount of soybean and corn produced on a per-acre basis. According to an analysis of the most recent USDA agricultural census, total agricultural value in LaSalle County exceeds $175 million or seven times the national average by county of roughly $23 million.

Needless to say, the short-term extraction of silica sands in the name of “energy independence” stands to have a profound impact on long-term “food security” in the U.S. and worldwide. Sadly, this conflict is similar to the one facing the aforementioned West Central Wisconsin, home to similarly productive soils. The cows that feed on the forage those soils produce some of the highest quality dairy anywhere. (As an aside: both regions are facing the realities of their disproportionate support for Donald Trump and the effects his trade war will have on their economies.)

LaSalle County is also home to the 2,630-acre Starved Rock State Park along the south bank of the Illinois River. Much of the park’s infrastructure was built by the Civilian Conservation Core (CCC) back in the early 1900s. Starved Rock is home to 18 canyons featuring:

… vertical walls of moss-covered stone formed by glacial meltwater that slice dramatically through tree-covered sandstone bluffs. More than 13 miles of trails allow access to waterfalls, fed season runoff or natural springs, sandstone overhangs, and spectacular overlooks. Lush vegetation supports abundant wildlife, while oak, cedar and pine grow on drier, sandy bluff tops. – IL DNR

Starved Rock receives more than 2.5 million visitors annually, which is the most of any Illinois state park. However, it is completely surrounded by existing or proposed frac sand mines, including US Silica’s Covel Creek mine. US Silica even recently pitched an expansion to the doorstep of Starved Rock and future plans to nearly engulf the park’s perimeter. What such an expansion would do to the attractiveness of the park and its trickle down economic impact is debatable, but LaSalle County residents Paul Wheeler and photographer Michelle McCray took a stab at illustrating the value of the state park to residents for our audience back in August, 2016:


Our flight with LightHawk pilot and neighboring Mazon, Illinois retired farmer Doug Harford lifted off from Illinois Valley Regional Airport (KVYS) at around 9:00 a.m. local time on the morning of May 24th. We had perfect conditions for taking photos, with no clouds and a comfortable 70-75°F for the duration of a two-hour flight. We covered nearly 200 square miles and ten existing, abandoned, or permitted frac sand mines.

Explore details from our Illinois tour by clicking on the images below:

US Silica Illinois River frac sand mine, Oglesby, LaSalle County, Illinois, 5/24/2018

Illinois River commodity barge terminal, Ottawa, LaSalle County, Illinois, 5/24/2018

Unimin frac sand mine, processing and wastewater, North Utica, LaSalle County, Illinois, 5/24/2018

Unimin frac sand mine, processing and wastewater, North Utica, LaSalle County, Illinois, 5/24/2018

US Silica I80/North Utica frac sand mine and processing, North Utica, LaSalle County, Illinois, 5/24/2018

US Silica I80/North Utica frac sand mine and processing, North Utica, LaSalle County, Illinois, 5/24/2018

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All passengers were struck by how large these mines were and how much several of the mines had expanded since the last time we all flew over them in June of 2016. The mines that had experienced the greatest rates of expansion were US Silica’s LaSalle Voss mine along Interstate 80 and the aforementioned Illinois River mine along with Fairmount Mineral’s major expansion, both in terms of infrastructure and actual mine footprint, in Wedron along the Fox River.

Figure 2. A map of the LaSalle County frac sand mines and associated St. Peter sandstone formation along with the city of Chicago for some geographic perspective.

Figure 3. A map of the LaSalle County frac sand mines and associated St. Peter sandstone formation, along with the city of Chicago for some geographic perspective.

Most of this expansion is due to three critical distinguishing characteristics about the industry in LaSalle County:

  • The processing and export infrastructure (i.e., east-west rail) is in place and allows for mining to take place at times when other sand mining regions are mothballed,
  • Due to the large aggregation of parcels for farming purposes, companies can lease or outright purchase large amounts of land from relatively few landowners, and
  • Only the largest firms are active in the region, and with economies of scale they are not subject to the same types of shocks that smaller firms are when the price of oil collapses (like it did between June 2015 and February 2016). This means that the conflict will only be amplified in the coming months and years as the frac sand mining industry looks to supersede agriculture as LaSalle County’s primary economic driver.

However, all is not lost in North Central Illinois. This hope was stoked during our sojourn – and my subsequent trip in person – up to see The Nature Conservancy’s 3,600 acre preserve in Franklin Grove on the border of Lee and Ogle counties. As someone who is working hard to establish a small plot of prairie grasses and associated wildflowers at my home outside Cleveland, I was hoping to see what an established prairie looks like from the air. My primary goal, however, was to see what a healthy herd of native bison looks like.[2] The Nachusa bison are unique in that they came:

… from Wind Cave National Park in South Dakota and…Unlike most other American bison, animals from the Wind Cave herd have no history of cross-breeding with cattle. Bison from Wind Cave are the species’ most genetically pure and diverse specimens.

We were fortunate during our flight to have spotted the heard at the western edge of the preserve in what volunteer naturalist, Betty Higby, later told me the staff calls Oak Island. While I am not a person of faith, seeing these behemoths roaming freely and doing what 20-30 million of their ancestors used to do across much of North America moved me in a way I was not prepared for. I was immediately overwhelmed with a sense of awe and humility. How was I going to explain this beast’s former ubiquity and current novelty to my 5-year-old son, who shares a love of the North American Bison with me and would most certainly ask me what happened to this majestic creature?

Medina & Stark counties, Ohio NEXUS Pipeline flight

June 25, 2018

Ohio is currently home to 2,840 fracking permits, with 2,370 of these laterals having been drilled since September 2010. The growing concern around the fracking and petrochemicals conversation across much of the Midwest is the increasing number of FERC-permitted natural gas pipeline “proposals”[3] the industry is demanding it needs to maximize potential. Most residents in the path of these pipelines have strong objections to such development, citing the fact that imminent domain should not be invoked for corporate gain.

Much like all of the other patterns and processes we’ve documented and/or photographed at FracTracker, we felt that a flight over the latest FERC-approved pipeline – The NEXUS pipeline – would give us a better understanding of how this critical piece of infrastructure has altered the landscapes of Medina and Stark counties. Given the population density of these two northeastern Ohio counties, we also wanted to document the pipeline’s pathway with respect to urban and suburban centers.

Our flight on June 25th was delayed due to low clouds and last minute changes to the flight plan, but once we took off from Wadsworth Municipal Airport (3G3) with a local flight instructor it was clear that NEXUS is a pipeline that navigates a sinuous path in cities and townships like Green, Medina, Rittman, and Seville – coming dangerously close to thousands of homes and farms, as well as many schools and medical facilities.

Explore details from our NEXUS Pipeline tour by clicking on the images below:

Nexus being built through golf course
Nexus being built through golf course

Will this be the last FERC-approved pipeline to transverse Ohio in the name of “energy independence”? Will this pipeline and its brethren with names like the Utopia and ET Rover be monitored in real-time? If not, why? It is unfortunate, to say the least, that we so flippantly assume these pipelines are innocuous given their proximity to so many Ohioans. And, as if to add insult to injury, imminent domain is invoked. All this for a piece of oil and gas infrastructure that will profit companies on the global market, with only a fraction of the revenue returning to affected communities.

What’s Next?

I don’t know of a better way to understand the magnitude of these pipelines than flying over them at 1,000-1,500 feet, and I will continue to monitor and photograph oil and gas developments from the air with the assistance of amazing pilots like those affiliated with LightHawk and SouthWings.

To this end, I will be returning to West Central Wisconsin for yet another “morning flight” with the aforementioned La Crosse-area pilot and lawyer Tim Jacobson and frequent collaborator University of Wisconsin-Stout professor Tom Pearson.[4] Our flight plan will return us to the northern Wisconsin frac sand counties of Chippewa, Barron, Dunn, Eau Claire, and if we have time we’ll revisit the mines we photographed in August of last year. We’ve been told by Susan Bence, an environmental reporter out of Milwaukee Public Radio, that she is trying to convince the powers that be at NPR in Washington, DC that this is a story the entire country should hear about. Wish us luck!

Flyover Partners

By Ted Auch, Great Lakes Program Coordinator

Bird’s-Eye-View Endnotes

  1. The first of my morning fracking flights was out of this airport back in June, 2012 along with the other passenger on this flight Paul Feezel of Carroll Concerned Citizens and David Beach of the Cleveland Museum of Natural History’s Green City Blue Lakes program.
  2. The Conservancy initially brought at least 30 bison of different ages and genders to Nachusa. The bison graze on approximately 1,500 acres of the prairie and the site currently supports more than 120 bison according to site volunteer naturalist Betty Higby.
  3. I put quotes around this word because in my travels across Ohio interviewing those in the path of these transmission pipelines it is clear that this is not the correct word because ‘proposals’ implies that these pipelines might not happen or are up for debate. Yet, neither could be further from the truth with most folks indicating that it was very clear very early in their interactions with FERC and the pipeline companies that there was never a chance that these pipelines were not going to happen with “imminent domain for private gain” being the common thread throughout my conversations.
  4. Tom is the author of a recently published book on the topic “When the Hills Are Gone.”

Supporting Documentation

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

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

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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

Matt Kelso, BA

Report: Potential Impacts of Unconventional Oil and Gas on the Delaware River Basin

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Report: Potential Impacts of Unconventional Oil and Gas on the Delaware River Basin

White Paper (PDF)
A Hazy Future Report Cover
FracTracker Alliance

A Hazy Future: Pennsylvania’s Energy Landscape in 2045

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Report Calculates Impacts from PA’s Planned Natural Gas Infrastructure

FracTracker Alliance released the report: A Hazy Future: Pennsylvania’s Energy Landscape in 2045 today, which details the potential future impacts of a massive buildout of Marcellus Shale wells and associated natural gas infrastructure.

Industry analysts forecast 47,600 new unconventional oil and gas wells may be drilled in Pennsylvania by 2045, fueling new natural gas power plants and petrochemical facilities in PA and beyond. Based on industry projections and current rates of consumption, FracTracker – a national data-driven non-profit – estimates the buildout would require 583 billion gallons of fresh water, 386 million tons of sand, 798,000 acres of land, 131 billion gallons of liquid waste, 45 million tons of solid waste, and more than 323 million truck trips to drilling sites.

A Hazy Future - Impact Summary

“Only 1,801 of the 10,851 unconventional wells already drilled count as a part of this projection, meaning we could see an additional 45,799 such wells in the coming decades,” commented Matt Kelso, Manager of Data and Technology for FracTracker and lead author on the report.

Why the push for so much more drilling? Out of state – and out of country – transport is the outlet for surplus production.

“The oil and gas industry overstates the need for more hydrocarbons,” asserted FracTracker Alliance’s Executive Director, Brook Lenker. “While other countries and states are focusing more on renewables, PA seems resolute to increase its fossil fuel portfolio.”

The report determined that the projected cleared land for well pads and pipelines into the year 2045 could support solar power generation for 285 million homes, more than double the number that exist in the U.S.

“A Hazy Future shows that a fossil fuel-based future for Pennsylvania would come at the expense of its communities’ health, clean air, water and land. It makes clear that a dirty energy future is unnecessary,” said Earthworks’ Pennsylvania Field Advocate, Leann Leiter. Earthworks endorsed FracTracker’s report. She continued, “I hope Governor Wolf reads this and makes the right choices for all Pennsylvanians present and future.”

A Hazy Future reviews the current state of energy demand and use in Pennsylvania, calculates the footprint of industry projections of the proposed buildout, and assesses what that would look like for residents of the Commonwealth.

Download Report (PDF)

About FracTracker Alliance

Started in 2010 as a southwestern Pennsylvania area website, FracTracker Alliance is a national organization with regional offices across the United States in Pennsylvania, the District of Columbia, New York, Ohio, and California. The organization’s mission is to study, map, and communicate the risks of oil and gas development to protect our planet and support the renewable energy transformation. Its goal is to support advocacy groups at the local, regional, and national level, informing their actions to positively shape our nation’s energy future.

Questions? Email us: info@fractracker.org.

JOSHUA DOUBEK / WIKIMEDIA COMMONS
Kyle Ferrar, MPH

Groundwater risks in Colorado due to Safe Drinking Water Act exemptions

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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

co_classiiwellexplosion

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.

Groundwater risks in Colorado graphs
Groundwater risks in Colorado graphs
Groundwater risks in Colorado graphs
Groundwater risks in Colorado graphs

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.

 

co_eac_uicpermit

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.

Northeast Ohio Class II injection wells taken via FracTracker's mobile app, May 2015
Kyle Ferrar, MPH

What are aquifer exemptions? Permitted exemptions from the Safe Drinking Water Act

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We’d like to give our readers a bit of background on aquifer exemptions, because we’re going to be covering this topic in a few upcoming blog posts. Stay tuned!

Liquid Waste Disposal

Drilling for oil and gas produces both liquid and solid waste that must be disposed of. The liquid waste from this industry is considered a “Class II waste” according to the US EPA. Aquifers are places underground capable of holding or transmitting groundwater. To dispose of Class II waste, operators are granted aquifer exemptions, by the EPA based on the state’s recommendations. The term “exemption,” specifically, refers to the Safe Drinking Water Act, which protects underground sources of drinking water (USDWs).

Therefore, these exemptions grant oil and gas operators the right to contaminate groundwaters, albeit many of the groundwater formations used for disposal in Class II wells are very deep.

Learn more about disposal well classes and aquifer exemptions on this story map by the US EPA

Aquifer Exemption Criteria

There are several qualifiers for a USDW to be granted exempt from the Safe Drinking Water Act. Aquifer exemptions are granted for underground formations that are not currently used as a source of drinking water and meet one of the following criteria:

  • The formation contains commercially producible minerals or hydrocarbons;
  • The formation is so deep that recovery of water for drinking water purposes is economically or technologically impractical; or,
  • The formation is so contaminated that it would be economically or technologically impractical to render the water fit for human consumption.
  • In some states, aquifer exemptions are not approved for formations with Total Dissolved Solids (TDS*) equal to or less than 3,000 mg/l TDS.

If an underground formation qualifies for an exemption, it does not mean that groundwater cannot be used for drinking water, just that it is not currently a source of drinking water. The most precarious criteria requirement, therefore, is the determination that a USDW is simply not “economically viable” or it is “technologically impractical,” meaning that the cost of drilling a groundwater well to the depth of the aquifer (under the condition of the current need for water) may make the investment impractical. In the near future, this water may be needed and highly valued, however.

TDS = Total dissolved solids are inorganic salts (e.g. calcium, magnesium, potassium, sodium, bicarbonates, chlorides, and sulfates), as well as some organic matter, dissolved in water.

The Lay of the Land

Below, we have put together a map of aquifer exemptions in the U.S. Click on the dots and shaded areas to learn more about a particular aquifer.

Map of all aquifer exemptions in the U.S.

View map fullscreen | How FracTracker maps work

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

Brine or water roadspreading in WV
Matt Kelso, BA

Does roadspreading of brine equate to oil and gas waste dumping?

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air quality impact, which is why roadspreading of brine occurs

This 2015 photo from West Virginia illustrates that large trucks on dirt roads create a legitimate dust problem, which impacts both air and water quality.

The application of liquid oil and gas waste from conventional wells onto roadways for dust control and road stabilization is permitted in Pennsylvania, provided that operators adhere to plans approved by the Department of Environmental Protection (DEP). There are brine spreading guidelines that operators are required to follow, but overall, DEP considers roadspreading to be a beneficial use of the liquid oil and gas waste products.

Dust suppression is a legitimate concern, particularly in areas that see a lot of heavy truck traffic on dirt roads, such rural oil and gas fields. Prolonged exposure to airborne dust contributes to a number of different health problems, ranging from temporary irritation to debilitating diseases of the heart, lungs, and kidneys. This road dust can also impact aquatic life, from plants to aquatic insects to fish.

While applying liquid waste from the oil and gas industry undoubtedly seems like a convenient solution to dusty roads, is roadspreading really advisable?

PA Oil and Gas Liquid Waste Road Applications


View map fullscreen | How FracTracker maps work

In the map above, the areas in green are municipalities where liquid waste from Pennsylvania’s conventional wells were applied to roadways in 2016. The purple areas are counties where additional quantities of the liquid waste were applied in cases where the exact municipality was not specified on the 2016 waste report. The majority of the state’s oil and gas roadspreading remains in Pennsylvania, but some of the brine is spread on roads in New York, as well.

What’s in the brine?

In Pennsylvania, the large-scale extraction efforts from deep carbon-rich shales like the Marcellus and Utica formations are classified as unconventional oil and gas, whereas the shallower formations requiring smaller amounts of hydraulic fracturing stimulation to bring the wells into production are considered to be conventional.

While the chemical components of these brines vary from formation to formation, in general they are known for containing high-salinity toxic metals, such as barium and strontium, as well as volatile organic compounds including benzene. Bromide in the brine can interact with purification processes at treatment plants to create carcinogenic compounds called trihalomethanes. These compounds actually created a problem in the early parts of the Marcellus boom in Western Pennsylvania, when large enough quantities of bromide were added to the region’s rivers and streams. And of particular concern is naturally occurring radioactive materials (NORMs), which sometimes occur at very high concentrations, even in brines from conventional wells.

The Pennsylvania Geological Survey commissioned Evan Dresel and Arthur Rose from Penn State to investigate oil and gas brine from a sample of 40 wells in 1985, although the accompanying paper wasn’t published until 2010.  Their samples included dissolved solids of 343,000 milligrams per liter, and radium occurring at up to 5,300 picocuries per liter. As a point of comparison, the US Environmental Protection Agency mandates that drinking water not exceed 5 picocuries per liter, and the authors of this report express concern about the high levels shown in these brines.

Based on the six samples analyzed, radium shows a general correlation with barium and strontium and an inverse correlation with [sulfate], though the correlation is not perfect. The radium values are high enough that a possible radiation hazard exists, especially where radium could be adsorbed on iron oxides and accumulate in brine tanks.

The article’s preface, written in 2010, echoes the concern, stating, ” the very high radium contents indicate that caution should be used in handling these brines.” One imagines that the radium content might also be a concern for people walking their dogs along dirt roads where these brines are spread.

Testing for radiological contamination appears to be insufficient for liquid oil and gas waste. Ben Stout, PhD, a professor of Biology at Wheeling Jesuit University (and a FracTracker Alliance board member) sampled liquid waste from Marcellus Shale wells in 2009. Here is what he found:

In terms of radiation, 9 of the 13 samples exceeded the drinking water standard for radium. Furthermore, 7 of the 13 samples exceeded the drinking water standard for gross alpha particles, which are a strong indicator of radioactivity. Most notably, one sample from a frac pit at the Phillips #20 site in Westmoreland County, PA yielded a gross alpha reading of 4846 +/‐ 994 picocuries per liter (pCi/L), though the drinking water standard is 15 pCi/L. In fact, the same sample had combined radium readings well over 1,000 pCi/L, a multiple in excess of 200 times the (5 pCi/L) standard. It should be noted that none of the samples triggered a response from radiation meters.

What to do?

From environmental concerns of high salinity to health concerns about the toxic and radiological content of oil and gas brines, intentionally introducing this waste product to public spaces is a dubious practice. It is understandable that township supervisors would want to use readily available materials for dealing with dust control on dirt roads, but if you are concerned about the practice and your area is indicated on the map above, you may wish to contact them to find out where this waste is being spread in greater detail.

By Matt Kelso, Manager of Data and Technology, FracTracker Alliance

Ethanol and fracking
Ted Auch, PhD

North American Ethanol’s Land, Water, Nutrient, and Waste Impact

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Corn Ethanol and Fracking – Similarities Abound

Even though it is a biofuel and not a fossil fuel, in this post we discuss the ways in which the corn ethanol production industry is similar to the fracking industry. For those who may not be familiar, biofuel refers to a category of fuels derived directly from living matter. These may include:

  1. Direct combustion of woody biomass and crop residues, which we recently mapped and outlined,
  2. Ethanol1 produced directly from the fermentation of sugarcanes or indirectly by way of the intermediate step of producing sugars from corn or switchgrass cellulose,
  3. Biodiesel from oil crops such as soybeans, oil palm, jatropha, and canola or cooking oil waste,2 and
  4. Anaerobic methane digestion of natural gas from manures or human waste.

Speaking about biofuels in 2006, J. Hill et al. said:

To be a viable substitute for a fossil fuel, an alternative fuel should not only have superior environmental benefits over the fossil fuel it displaces, be economically competitive with it, and be producible in sufficient quantities to make a meaningful impact on energy demands, but it should also provide a net energy gain over the energy sources used to produce it.

Out of all available biofuels it is ethanol that accounts for a lion’s share of North American biofuel production (See US Renewables Map Below). This trend is largely because most Americans put the E-10 blends in their tanks (10% ethanol).3 Additionally, the Energy Independence and Security Act of 2007 calls for ethanol production to reach 36 billion gallons by 2022, which would essentially double the current capacity (17.9 billion gallons) and require the equivalent of an additional 260 refineries to come online by then (Table 1, bottom).

US Facilities Generating Energy from Biomass and Waste along with Ethanol Refineries and Wind Farms


View map fullscreen | How FracTracker maps work

But more to the point… the language, tax regimes, and potential costs of both ethanol production and fracking are remarkably similar. (As evidenced by the quotes scattered throughout this piece.) Interestingly, some of the similarities are due to the fact that “Big Ag” and “Big Oil” are coupled, growing more so every year:

The shale revolution has resulted in declining natural gas and oil prices, which benefit farms with the greatest diesel, gasoline, and natural gas shares of total expenses, such as rice, cotton, and wheat farms. However, domestic fertilizer prices have not substantially fallen despite the large decrease in the U.S. natural gas price (natural gas accounts for about 75-85 percent of fertilizer production costs). This is due to the relatively high cost of shipping natural gas, which has resulted in regionalized natural gas markets, as compared with the more globalized fertilizer market. (USDA, 2016)

Ethanol’s Recent History

For background, below is a timeline of important events and publications related to ethanol regulation in the U.S. in the last four decades: 

Benefits of Biofuels

[Bill] Clinton justified the ethanol mandate by declaring that it would provide “thousands of new jobs for the future” and that “this policy is good for our environment, our public health, and our nation’s farmers—and that’s good for America.” EPA administrator Carol Browner claimed that “it is important to our efforts to diversify energy resources and promote energy independence.” – James Bovard citing Peter Stone’s “The Big Harvest,” National Journal, July 30, 1994.

Of the 270 ethanol refineries we had sufficient data for, we estimate these facilities employ 235,624 people or 873 per facility and payout roughly $6.18-6.80 billion in wages each year, at an average of $22.9-25.2 million per refinery. These employees spend roughly 423,000 hours at the plant or at associated operations earning between $14.63 and $16.10 per hour including benefits. Those figures amount to 74-83% of the average US income. In all fairness, these wages are 13-26% times higher than the farming, fishing, and forestry sectors in states like Minnesota, Nebraska, and Iowa, which alone account for 33% of US ethanol refining.

Additional benefits of ethanol refineries include the nearly 179 million tons of CO2 left in the field as stover each year, which amounts to 654,532 tons per refinery. Put another way – these amounts are equivalent to the annual emissions of 10.7 million and 39,194 Americans, respectively.

Finally, what would a discussion of ethanol refineries be without an estimate of how much gasoline is produced? It turns out that the 280 refineries (for which we have accurate estimates of capacity) produce an average of 71.93 million gallons per year and 20.1 billion gallons in total. That figure represents 14.3% of US gasoline demand.

Costs of Biofuels

Direct Costs

Biofuel expansions such as those listed in the timeline above and those eluded to by the likes of the IPCC have several issues associated with them. One of which is what Pimentel et al. considered an insufficient – and to those of us in the fracking NGO community, familiar sounding – “breadth of relevant expertise and perspectives… to pronounce fairly and roundely on this many-sided issue.”

The above acts and reports in the timeline prompted many American farmers to double down on corn at the expense of soybeans, which caused Indirect Land Use Change (ILUC); the global soy market skyrocketed. This, in turn, prompted the clearing and/or burning of large swaths of the Amazonian rainforests and tropical savannas in Brazil, the world’s second-leading soy producer. More recently, large swaths of Indonesia and Malaysia’s equally biodiverse peatland forests have been replaced by palm oil plantations (Table 2 and Figure 3, bottom). In the latter countries, forest displacement is increasing by 2.7-5.3% per year, which is roughly equal to the the rate of land-use change associated with hydraulic fracturing here in the US4 (Figure 1).

Palm Oil Production in Indonesia between 1960 and 2016.
Palm Oil Production in Indonesia between 1960 and 2016.
Palm Oil Production in Malaysia between 1960 and 2016.
Palm Oil Production in Malaysia between 1960 and 2016.

Figures 1A and 1B. Palm Oil Production in A) Indonesia and B) Malaysia between 1960 and 2016.

There is an increasing amount of connectivity between disparate regions of the world with respect to energy consumption, extraction, and generation. These connections also affect how we define renewable or sustainable:

In a globalized world, the impacts of local decisions about crop preferences can have far reaching implications. As illustrated by an apparent “corn connection” to Amazonian deforestation, the environmental benefits of corn-based biofuel might be considerably reduced when its full and indirect costs are considered. (Science, 2007)

These authors pointed to the fact that biofuel expectations and/or mandates fail to account for costs associated with atmospheric – and leaching – emissions of carbon, nitrogen, phophorus, etc. during the conversion of lands, including diverse rainforests, peatlands, savannas, and grasslands, to monocultures. Also overlooked were:

  • The ethical concerns associated with growing malnourishment from India to the United States,
  • The fact that 10-60%5 more fossil fuel derived energy is required to produce a unit of corn ethanol than is actually contained within this very biofuel, and
  • The tremendous “Global land and water grabbing” occuring in the name of natural resource security, commodification, and biofuel generation.

Sacrificing long-term ecological/food security in the name of short-term energy security has caused individuals and governments to focus on taking land out of food production and putting it into biofuels.

The rationale for ethanol subsidies has continually changed to meet shifting political winds. In the late 1970s ethanol was championed as a way to achieve energy independence. In the early 1980s ethanol was portrayed as salvation for struggling corn farmers. From the mid and late 1980s onward, ethanol has been justified as saving the environment. However, none of those claims can withstand serious examination. (James Bovard, 1995)

This is instead of going the more environmentally friendly route of growing biofuel feedstocks on degraded or abandoned lands. An example of such an endeavor is the voluntary US Conservation Reserve Program (CRP), which has stabilized at roughly 45-57 thousand square miles of enrolled land since 1990, even though the average payout per acre has continued to climb (Figure 2).

The Average Subsidy to Farmers Per Acre of Conservation Reserve Program (CRP) between 1986 and 2015.

Figure 2. The Average Subsidy to Farmers Per Acre of Conservation Reserve Program (CRP) between 1986 and 2015.

The primary goals of the CRP program are to provide an acceptable “floor” for commodity prices, reduce soil erosion, enhance wildlife habitat, ecosystem services, biodiversity, and improve water quality on highly erodible, degraded, or flood proned croplands. Interestingly CRP acreage has declined by 27% since a high of 56 thousand square miles prior to the Energy Independence and Security Act of 2007 being passed. Researchers have pointed to the fact that corn ethanol production on CRP lands would create a carbon debt that would take 48 years to repay vs. a 93 year payback period for ethanol on Central US Grasslands.

To quote Fred Magdoff in The Political Economy and Ecology of Biofuels:

Alternative fuel sources are attractive because they can be developed and used without questioning the very workings of the economic system — just substitute a more “sustainable,” “ecologically sound,” and “renewable” energy for the more polluting, expensive, and finite amounts of oil. People are hoping for magic bullets to “solve” the problem so that capitalist societies can continue along their wasteful growth and consumption patterns with the least disruption. Although prices of fuels may come down somewhat — with dips in the business cycle, higher rates of production, or a burst in the speculative bubble in the futures market for oil — they will most likely remain at historically high levels as the reserves of easily recovered fuel relative to annual usage continues to decline.

Indirect Costs: Ethanol, Fertilizers, and the Gulf of Mexico Dead Zone

This is the Midwest vs. the Middle East. It’s corn farmers vs. the oil companies. – Dwaney Andreas in Big Stink on the Farm by David Greising

Sixty-nine percent6 of North America’s ethanol refineries are within the Mississippi River Basin (MRB). These refineries collectively rely on corn that receives 1.9-5.1 million tons of nitrogen each year, with a current value of $1.06-2.91 billion dollars or 9,570-26,161 tons of nitrogen per refinery per year (i.e. $5.42-14.81 million per refinery per year). These figures account for 27-73% of all nitrogen fertilizer used in the MRB each year. More importantly, the corn acreage receiving this nitrogen leaches roughly 0.81-657 thousand tons of it directly into the MRB. Such a process amounts to 5-44% of all nitrogen discharged into the Gulf of Mexico each year and 1.7-13.8 million tons of algae responsible for the Gulf’s growing Dead Zone.

Midwest/Great Plains US Ethanol Refineries and Crop Residue Production

Leaching of this nitrogen is analogous to flushing $45.7-371.6 million dollars worth of precious capital down the drain. Put another way, these dollar figures translate into anywhere between 55% and an astonishing 4.53 times Direct Costs to the Gulf’s seafood and tourism industries of the Dead Zone itself.

These same refineries rely on corn acreage that also receives 0.53-2.61 million tons of phosphorus each year with a current value of 0.34-1.66 billion dollars. Each refinery has a phosphrous footprint in the range of 2,700 to 13,334 tons per year (i.e., $1.72-8.47 million). We estimate that 25,399-185,201 tons of this fertilizer phosphorus is leached into the the MRB, which is equivalent to 19% or as much as 1.42 times all the phosphorous dischared into the Gulf of Mexico per year. Such a process means $16.13-117.60 million is lost per year.

Together, the nitrogen and phosphorus leached from acreage allocated to corn ethanol have a current value that is between 75% and nearly 6 times the value lost every year to the Gulf’s seafood and tourism industries.

Indirect Costs: Fertilizer and Herbicide Costs and Leaching

The 270 ethanol refineries we have quality production data for are relying on corn that receives 367,772 tons of herbicide and insecticide each year, with a current value of $6.67 billion dollars or 1,362 tons of chemical preventitive per refinery per year (i.e. $24.7 million per refinery per year). More importantly the corn acreage receiving these inputs leaches roughly 15.8-128.7 thousand tons of it directly into surrounding watersheds and underlying aquifers. Leaching of these inputs is analogous to flushing $287 million to $2.3 billion dollars down the drain.

What’s Next?

During the recent Trump administration EPA, USDA, DOE administrator hearings, the Renewable Fuel Standard (RFS) was cited as critical to American energy independence by a bipartisan group of 23 senators. Among these were Democratic senator Amy Klobuchar and Republican Chuck Grassley, who co-wrote a letter to new EPA administrator Scott Pruitt demanding that the RFS remains robust and expands when possible. In the words of Democratic Senator Heidi Heitkamp – and long-time ethanol supporter – straight from the heart of the Bakken Shale Revolution in North Dakota:

The RFS has worked well for North Dakota farmers, and I’m fighting to defend it. As we’re doing today in this letter, I’ll keep pushing in the U.S. Senate for the robust RFS [and Renewable Volume Obligations (RVOs)] we need to support a thriving biofuels industry and stand up for biofuels workers. Biofuels create good-paying jobs in North Dakota and help support our state’s farmers, who rely on this important market – particularly when commodity prices are challenging.

Furthermore, the entire Iowa congressional delegation including the aforementioned Sen. Grassley joined newly minted USDA Secretary Sonny Perdue when he told the Iowa Renewable Fuels Association:

You have nothing to worry about. Did you hear what he said during the campaign? Renewable energy, ethanol, is here to stay, and we’re going to work for new technologies to be more efficient.

How this advocacy will play out and how the ethanol industry will respond (i.e., increase productivity per refinery or expand the number of refineries) is anybody’s guess. However, it sounds like the same language, lobbying, and advertising will continue to be used by the Ethanol and Unconventional Oil and Gas industries. Additional parallels are sure to follow with specific respect to water, waste, and land-use.

Furthermore, as both industries continue their ramp up in research and development, we can expect to see productivity per laborer to continue on an exponential path. The response in DC – and statehouses across the upper Midwest and Great Plains – will likely be further deregulation, as well.

From a societal perspective, an increase in ethanol production/grain diversion away from people’s plates has lead to a chicken-and-egg positive feedback loop, whereby our farmers continue to increase total and per-acre corn production with less and less people. In rural areas, mining and agriculture have been the primary employment sectors. A further mechanization of both will likely amplify issues related to education, drug dependence, and flight to urban centers (Figures 4A and B).

We still don’t know exactly how efficient ethanol refineries are relative to Greenhouse Gas Emissions per barrel of oil. By merging the above data with facility-level CO2 emissions from the EPA Facility Level Information on Greenhouse gases Tool (FLIGHT) database we were able to match nearly 200 of the US ethanol refineries with their respective GHG emissions levels back to 2010. These facilities emit roughly:

  • 195,116 tons of CO2 per year, per facility,
  • A total of 36.97 million tons per year (i.e., 2.11 million Americans worth of emissions), and
  • 22,265 tons of CO2 per barrel of ethanol produced.

Emissions from ethanol will increase to 74.35 million tons in 2022 if the Energy Independence and Security Act of 2007’s prescriptions run their course. Such an upward trend would be equivalent to the GHG emissions of somewhere between that of Seattle and Detroit.

What was once a singles match between Frackers and Sheikhs may turn into an Australian Doubles match with the Ethanol Lobby and Farm Bureau joining the fray. This ‘game’ will only further stress the food, energy, and water (FEW) nexus from California to the Great Lakes and northern Appalachia.

We are on a thinner margin of food security, just as we are on a thinner margin of oil security… The [World] Bank implicitly questions whether it is wise to divert half of the world’s increased output of maize and wheat over the next decade into biofuels to meet government “mandates.” – Ambrose Evans-Pritchard in The Telegraph

Will long-term agricultural security be sacrificed in the name of short-term energy independence?

US and Global Corn Production and Acreage between 1866 and 2015.

Figure 3. US and Global Corn Production and Acreage between 1866 and 2015.

Fig 4A. Mining, Oil & Gas, and Agriculture Sector Laborers between 1947 and 2015.
Fig 4A. Mining, Oil & Gas, and Agriculture Sector Laborers between 1947 and 2015.
Corn Acres, Revenue, and Bushels Per Laborer between 1947 and 2015.
Corn Acres, Revenue, and Bushels Per Laborer between 1947 and 2015.

Figures 4A and 4B. A) Number of Laborers in the US Mining, Oil and Gas, Agriculture, Forestry, Fishing, and Hunting sector and B) US Corn Production Metrics Per Farm Laborer between 1947 and 2015.

Ethanol Tables

Table 1. Summary of our Corn Ethanol Production, Land-Use, and Water Demand analysis

Gallons of Corn Ethanol Produced Per Year 17,847,616,000
Bushels of Corn Needed 6,374,148,571
Percent of US Production 44.73%
Land Needed 104,372,023 acres
“” 163,081 square miles
Percent of Contiguous US Land 5.51%
Percent of US Agricultural Land 11.28%
Gallons of Water Needed 49.76 trillion (i.e. 3.55 million swimming pools)
Gallons of Water Per Gallon of Oil 2,788
Average and Total Site/Industry Capacity
Average Corn Ethanol Production Per Existing or Under Construction Facility (n = 257) 69,717,250
Gallons of Corn Ethanol Produced Per Year 17,847,616,000
Difference Between 2022 Energy Independence and Security Act of 2007 36 Billion Gallon Mandate 18,152,384,000
# of New Refineries Necessary to Get to 2022 Levels 260
Percent Increase Over Current Facility Inventory 1.7
IEA 2009 World Energy Outlook 250-620% Increase Predictions for 2030
250% 44,619,040,000
# of New Refineries Necessary 640
Percent Increase Over Current Facility Inventory 150.00
620% 110,655,219,200
# of New Refineries Necessary 1,587
Percent Increase Over Current Facility Inventory 520.00

Table 2. Global Population Growth and Corn and Soybean Productivity Trends.

Percent Change Metric
+1.13% Global Population Growth Trend
Corn (Bushels Per Acre)
+1.15% Per Year United States
+1.20% Per Year Global
Soybean (Tons Per Acre)
+0.9% Per Year United States
+1.5% Per Year Brazil
Palm Oil (Tons)
+5.1% Per Year Indonesia
+2.7% Per Year Malaysia

References and Footnotes

  1. Ethanol as defined in the Ohio Revised Code (ORC) Corporation Franchise Tax 5733.46 means “fermentation ethyl alcohol derived from agricultural products, including potatoes, cereal, grains, cheese whey, and sugar beets; forest products; or other renewable resources, including residue and waste generated from the production, processing, and marketing of agricultural products, forest products, and other renewable resources that meet all of the specifications in the American society for testing and materials (ASTM) specification D 4806-88 and is denatured as specified in Parts 20 and 21 of Title 27 of the Code of Federal Regulations.”
  2. A) Pyrolysis is included in the biofuel category and involves the anaerobic decay of cellulose rich feedstocks such as switchgrass at high temperatures producing synthetic diesel or syngas, and
    B) According to many researchers biofuels made from waste biomass or crops grown on degraded and abandoned lands with warm-season prairie grasses and legumes incur little or no carbon debt and provide “immediate and sustained Greenhouse Gas (GHG) advantages” by rehabilitating soil health and capturing, rather than emitting by way of increased fertilizer use, various forms of nitrogen including N2O, NO3–, and NO2–.
  3. According to Fred Magdoff, the ethanol complex is lobbying for “more automobile engines capable of using E-85 (85 percent ethanol, 15 percent gasoline) for which there are currently 2,710 fueling stations across the country although 56% of them are in just nine states: 1) Wisconsin (117), 2) Missouri (107), 3) Minnesota (335), 4) Michigan (174), 5) Indiana (172), 6) Illinois (221),  7) Iowa (193), 8) Texas (99), and 9) Ohio (97). Some states are mandating a mixture greater than 10 percent. Ethanol can’t be shipped together with gasoline in pipelines because it separates from the mixture when moisture is present, so it must be trucked to where it will be mixed with gasoline.” The E-85 blend comes with its own costs including higher emissions of CO, VOC, PM10, SOx, and NOx than gasoline.
  4. McClaugherty, C., Auch, W. Genshock, E. and H. Buzulencia. (2017). Landscape impacts of infrastructure associated with Utica shale oil and gas extraction in eastern Ohio, Ecological Society of America, 100th Annual Meeting, Baltimore, MD, August, 2015.
  5. Hill et al. recently indicated “Ethanol yields 25% more energy than the energy invested in its production, whereas biodiesel yields 93% more.”
  6. An additional 9-10 refineries or 73% of all ethanol refineries are within 25 miles of the Mississippi River Basin.

By Ted Auch, PhD, Great Lakes Program Coordinator, FracTracker Alliance

Cover photo, left: Oil and gas well pad, Ohio. Photo by Ted Auch.
Cover photo, right: A typical ethanol plant in West Burlington, Iowa. Photo by Steven Vaughn.

Data Downloads

Click on the links below to download the datasets used to create the maps in this article.

  1. Detailed US Ethanol water, land, chemical fertilizer, and herbicide demand
  2. Estimates of North American Ethanol Refinery’s water and land-use demand
Guest Author

Radium Watersheds a Risk

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By Greg Pace – Columbus Community Bill of Rights, and Julie Weatherington-Rice – Environmental Consultant

columbus_classiimap

Figure 1. Map of Columbus, OH Watersheds and Class II Injection Wells

Most Ohio residents are unaware of the frack fluid deep underground injection occurring north of Columbus, underneath the region’s source water protection watersheds (Figure 1).

Materials injected are liquids that have as much as ten times the salt concentration of sea-water. Mixed with this “brine” solution is a combination from hundreds of chemicals that are used in different stages of horizontal hydraulic fracturing, the process used to extract natural gas, petroleum, and hydrocarbon liquids used to make industrial materials such as plastics. BTEX compounds including benzene are always present in the wastewater, along with formaldehyde, bromides, ethylene glycol (antifreeze), and arsenic, with many other carcinogenic and otherwise highly-toxic substances.

Radioactivity of Shale Gas Wastewater

One of the biggest questions in this mix of toxic disposal is how much radioactive content exists. Radium-226 is most worrisome, as it has a very long half-life (1,600 years). It is water-soluble and, once it enters the human body, seeks to find a home in our bones where it will emit its cell-formation-destabilizing effects for the remainder of our lifetime. This radionuclide is known to cause leukemia, bone cancers, blood disorders, and other diseases.

The state of Ohio does not monitor the content of materials that are injected into our Class II injection wells deep in the ground. This oil and gas waste can come from anywhere, including Pennsylvania’s Marcellus shale, which is the most highly-radioactive geology of all the shale plays in the country. Radium-226 readings as high as 15,000 pico-curies per liter have been read in Marcellus shale brines. The EPA drinking water limit for radium-226 is 5 pico-curies per liter, which puts the Marcellus reading at 3,000 times higher than the drinking water limit.

Exposure through drinking water is a pathway to human disease from radium-226. Once oil and gas waste is disposed of underground in a sandstone or limestone layer, the fluids are subject to down-gradient movement, wicking through capillary action, and seepage over time. This means that the highly radioactive wastewater could eventually end up in our underground drinking water sources, creating radium watersheds. This practice is putting our watersheds at risk from radioactive contamination for hundreds of years, at least.

Can injected fluids migrate?

Depending on whether you confer with a geologist who works with the oil and gas industry, or from an independent geologist, you will get a different opinion on the likelihood of such a pollution event occurring. Industry geologists mostly claim that deep injection leaves very low risk of water contamination because it will not migrate from the planned area of injection. On the other hand, independent geologists will tell you that it is not a matter of if the liquids will migrate, but how and when. The ability to confirm the geology of the underground area layer of injection “storage” is not exact, therefore accuracy in determining the probability for migration over time is poor.

Figure 2. Ohio Utica Brine Production and Class II Injection Well Disposal


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We do know, however, that all underground systems in Ohio leak – Research by The Ohio State University and the US Geological Survey show that the age of the water in brine formations is far younger than the age of the rock deposits they are found in. See where wastewater is being created and disposed of in Ohio using the dynamic map above (Figure 2).

Spill Risks to Columbus, OH Water

According to area geologist, Dr. Julie Weatherington-Rice, the source for Columbus’s water to the north is mostly from surface water. This water comes from the Delaware and Morrow county watersheds that feed into sources such as the Hoover and Alum Creek reservoirs. The major threat from injection wells to our watershed is from spills, either from trucks or from storage at the injection well sites themselves.

Dead fish floating in Vienna area pond contaminated by injection well system spill Source: MetropolitanEnegineering Consulting & Forensics-Expert Engineers

Figure 3. Dead fish floating in Vienna area pond contaminated by injection well system spill. Source: MetropolitanEnegineering Consulting & Forensics-Expert Engineers

In April 2015, as much as 8,000 gallons of liquid leaked from a malfunctioning pipe in the storage apparatus of an oil/gas waste storage and injection well site in Vienna, OH. This caused a wildlife kill in two ponds (Figure 3), and the spill was not contained until 2/3 mile downstream in a tributary. The firm who owned the facility was found negligent in that they did not install a required containment liner for spills. The incident was discovered by neighboring residents, but apparently employees knew of the leak weeks before. Of note in this incident was that Ohio Department of Natural Resources, the regulatory agency that oversees all oil/gas production activity in Ohio including injection, stated that there was “minimal impact to wildlife.”

Brine tanker rollover near Barnesville, OH spilled 5,000 gal. of produced brine. Source: Barnesville, OH Fire Department

Figure 4. Brine tanker rollover near Barnesville, OH spilled 5,000 gal. of produced brine. Source: Barnesville, OH Fire Department

In March, 2016, a tanker truck carrying produced waste from a hydraulically fractured well pad overturned outside of the Village of Barnesville, Ohio (Figure 4). The truck spilled 5,000 gallons of liquid waste into a field that led into a tributary, leading the fluids to enter one of the city’s three drinking water supply reservoirs. The water source was shut down for more than two months while regulators determined if water levels were safe for consumption. There was a noted spike in radium-226 levels during water testing immediately after the spill.

Of greatest concern is that, although many millions of gallons of frack waste have been injected into the wells north of Columbus over the past few years, we expect that this activity will increase. For the first time, the United States began exporting its own natural gas in 2016, to regions such as Europe and South America. As the industry consolidates from the depression of oil prices over the past two years and begins to ramp up again, we expect the extraction activity in the Marcellus and especially Utica to increase to levels beyond what we have seen since 2011. The levels of injection will inevitably follow, so that injection wells in Ohio will receive much more than in the past. The probability of spills, underground migration, and human-induced earthquakes may increase steeply, as well.

An Aging Disposal Infrastructure

On our Columbus Community Bill of Rights website, we show pictures of some of the Class II injection wells in Morrow County, most of them converted from legacy production wells. These old wells are located in played out oil/gas fields that may still be producing or have abandoned but not plugged (closed) wells, allowing other routes for injected liquids to migrate into shallow ground water and to the surface. The dilapidated condition of these converted Class II wells makes it hard to believe that they are used to inject millions of gallons of wastewater under high pressure. While many of the wells in the state are as deep as 9,000 feet, all of the injection wells we have seen in Morrow County are only 3,000-4,000 feet deep. This situation puts surface water at greater risk over time, as it is probable that, over the generations, some of the fluids will migrate and wick into the higher subterranean strata.

Figure 5. Ohio Class II Injection Wells by Type


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One well (Power Fishburn unit, photo below) showed signs of poor spill control when we took our October 2015 injection well tour. While we were there, a brine tanker arrived and began pumping their load into the well. The driver took pictures of our license plates while we were there watching him. A year later, there is a whole new structure at the well, including a new storage tower, and an extensively beefed-up spill control berm. Maybe we need to visit all of the facilities when they come by to use them!

Another well (Mosher unit, photo below) which hadn’t been used since 2014 according to available records, showed signs of a spill around the well. The spill control berms look as if they probably had flooded at some point. This well sits on the edge of a large crop field.

Brine tanker unloading into Power II injection well in Morrow County, OH. Source: Greg Pace
Brine tanker unloading into Power II injection well in Morrow County, OH. Source: Greg Pace
Pipe used to unload tanker trucks into Mosher II well in Morrow County, OH. Source: Ted Auch, The FracTracker Alliance
Pipe used to unload tanker trucks into Mosher II well in Morrow County, OH. Source: Ted Auch, The FracTracker Alliance

Figures 6a and 6b. Photos of Class II injection wells. Click on the images to expand them.

North of Columbus, the city of Delaware’s underground source water is at risk of becoming contaminated from underground migration of disposed wastewater over time, through wicking and seepage effects (as explained earlier in this article). They are also vulnerable to their reservoir being contaminated from surface spill migration through their watershed.

Google maps rendition of Ohio Soil Recycling facility in south Columbus, Ohio, that accepts shale drill cuttings for remediation to cap the landfill. Source: Google Maps/author

Figure 7. Google maps rendition of Ohio Soil Recycling facility in south Columbus, Ohio, that accepts shale drill cuttings for remediation to cap the landfill. Source: Google Maps/author

South of Columbus is another threat – drill cuttings from the drilling process have been authorized for disposal at a “remediation” landfill adjacent to the Alum Creek (Figure 7). The bioremediation treatment used is not indicated to solve the problem of removing radionuclides from the materials. This landfill had been remediated under the Ohio EPA twice when it was a toxic drum dump, after toxins were found to have been leaching into the watershed creek. Columbus’s Alum Creek well, as well as Circleville, are at risk of contamination in their drinking water if radionuclides from the cuttings leach into Alum Creek. Again, this is a long-term legacy of risk to their water.

Radiation Regulatory and Monitoring Gaps

Since The Ohio legislature deemed the radioactive content of shale cuttings to be similar to background levels in the 2013 state budget bill, cuttings can be spread around to all licensed landfills in Ohio with absolutely no accountability for the radium and other heavy metal levels in them. Unfortunately, the measuring protocol used in the pilot study for the Columbus facility to demonstrate to Ohio EPA that radium-226 was below EPA drinking water limits has been shown in a University of Iowa study to be unreliable.  The inadequate protocol was shown to indicate as little as 1% of the radium levels in shale waste samples tested.

As such, there have been hundreds of incidents where truckloads of cuttings have been turned away at landfills with crude radiation monitors. In 2013 alone, 2 loads were turned away in Ohio landfills, and over 220 were turned away from Pennsylvania landfills.

Ohio has a long way to go before it can be considered a clean energy state. The coal industry polluted significant water sources in the past. The fracking industry seems to be following suit, where contaminations will surprise us long into the future and in broader areas.

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