By Alison Grass, Senior Researcher at Food & Water Watch
Over the past decade, the natural gas industry has experienced a renaissance that has been a boon to energy company profits. But it has altered the quality of life for the rural communities where most new gas wells have been drilled. Now, fracking is fueling a gas-fired power plant boom in Pennsylvania, with 47 new facilities. Most have already been approved, with a handful in commercial operation (see map below).
New research by Pennsylvanians Against Fracking shows, in vivid detail, the scale of this buildout, and the impacts it will have on Pennsylvania communities.
Current & Potential PA Gas-Fired Power Plants & their Emissions
Approximately half of the new gas power plants are located in northeastern region of Pennsylvania, a part of the state already overburdened by the lingering environmental maladies of coal mining and the more recent dangers associated with fracking. These rural communities may see increased drilling, fracking and pipeline construction to support the power plants — and the siting could be strategic. In a StateImpact Pennsylvania article about the first Marcellus shale gas power plant, for example, a company representative admitted that the location was chosen specifically due to its convenient access to shale gas. “This plant was sited precisely where it is because of its access to the abundant, high-quality natural gas that’s found a mile to two miles beneath our feet.”
Drilling Trends
The first modern Marcellus well was drilled in Pennsylvania by Range Resources in 2003, and commercial production began in 2005. Although fracking expanded rapidly in several areas across the country, Pennsylvania has been ground zero of the fracking boom, with just over 10,000 shale gas wells drilled between 2005 and 2016. Since then, however, there has been a rapid downturn in new wells drilled. After the early and dramatic increase in drilling – from 9 shale wells in 2005 to 1,957 shale wells in 2011 – the number dropped to 504 in 2016.
According to Natural Gas Intelligence, natural gas from the Appalachian Basin “…hit a roadblock in 2016, as pipeline projects struggled to move forward and a storage glut slowed the region’s previously rapid production growth.” Thus, it appears that in order to maintain fracking’s profitability, the gas industry is relying on new gas-fired power plants to alleviate the storage glut, while potentially increasing demand for shale gas (which could propagate more drilling and fracking).
Gas-Fired Power Plant Siting
The siting of these power plants also enables companies to use Pennsylvanian fracked gas to generate power for larger regional markets. This is because northeastern Pennsylvania is close to dense populations, including New York City. In Luzerne County, for instance, the new Caithness Moxie Freedom Generating Station gas-fired power plant will supply electricity to not just Pennsylvania residents, but also to New Jersey and New York State. And in the more central region of the state in Snyder County, the Panda Hummel Station will send “much of its power to the New York City market.”
Siting gas-fired power plants in the northeast may also increase drilling and fracking in the region, where gas is predominantly “dry” and less profitable than the “wet” gas found in southwest PA. This trend is largely due to a resurgence in North American petrochemical markets and increased ethane exports that rely on wet gas. (Dry natural gas contains primarily methane and smaller amounts of other hydrocarbons, while wet natural gas has higher concentrations of natural gas liquids. Natural gas liquids — predominantly ethane but also propane, butane, isobutane and pentanes — are the raw materials for manufacturing petrochemicals.)
Well Integrity and Other Risks
However, increased drilling and fracking mean more pollution for the Marcellus shale region of Pennsylvania, where shale gas wells have proven to be more prone to well construction “impairments” and well integrity problems, compared to conventional wells. This risk is especially true in the northeastern part of the state, where over nine percent of shale gas wells have indications of compromised well integrity.
Overall, fracking causes many public health and environmental problems. Methane, fracking fluids, and wastewater can pollute water supplies and imperil the livelihoods of farmers, who rely on clean water. Increased truck traffic and drilling emissions reduce air quality, and methane leaks contribute to global warming. Meanwhile, the proliferation of natural gas derricks and associated infrastructure destroys pristine landscapes (and related tourism and recreation industries).
The last thing that Pennsylvanians need is another way for the oil and gas industry to capitalize on shale at the expense of residents’ health and well-being.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/03/Power-Plants-PA-Feature.jpg400900Guest Authorhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngGuest Author2017-04-21 13:34:192021-04-15 15:03:09Wanted: More Places to Burn Natural Gas
In March 2017, FracTracker Alliance conducted a review of the available Pennsylvania oil and gas fine data released publicly by the PA Department of Environmental Protection (DEP) to identify trends in industry-related fines over time and by particular operators. In total, the DEP has assessed nearly $36 million in fines to oil and gas extraction and pipeline operators since January 1, 2000. Such fines are associated with over 42,000 violations issued1 by DEP in that time frame, covering 204,000 known oil and gas locations,2 as well as 91,000 miles of pipelines3 within the Commonwealth.
Understanding the Data Structure
The amount of money that the Pennsylvania Department of Environmental Protection (DEP) fines oil and gas (O&G) operations is included in the DEP’s compliance report published on their website. Even though fines data are made available, they are not necessarily straight-forward, and caution must be taken not to over-estimate the total number of assessed fines.
Records of fines are associated with enforcement identification codes on the compliance report. A single fine is often applied to numerous violations, and the full amount of the fine is listed on every record in this subset. Therefore, the total dollar amount of fines assessed to O&G companies appears overstated. For example, if a $400,000 fine were assessed to settle a group of 10 violations, that figure will appear on the report 10 times, for an apparent aggregate of $4,000,000 in fines. To get an accurate representation of fines assessed, we need to isolate fines associated with particular enforcement ID numbers, which are used administratively to resolve the fines.
This process is further complicated by the fact that, on occasion, such enforcement ID numbers are associated with more than one operator. This issue could result from a change in the well’s operator (or a change of the operator’s name), a group of wells in close proximity that are run by different operators, or it might point to an energy extraction company and a midstream company sharing responsibility for an incident. Sometimes, the second operator listed under an enforcement ID is in fact “not assigned.” The result is that we cannot first summarize by operator and then aggregate those subtotals without overstating the total amount of the assessed fines. In all, 62 of the enforcement ID numbers apply to more than one operator, but this figure amounts to less than one percent of the nearly 15,000 distinct enforcement ID numbers issued by DEP.
Conventional & Unconventional Violations & Fines
Oil and gas wells in Pennsylvania are categorized as either conventional or unconventional, with the latter category intended to represent the modern, industrial-scaled operations that are commonly referred to as “fracking wells.” Contrastingly, conventional wells are supposed to be the more traditional O&G wells that have been present in Pennsylvania since 1859. The actual definition of these wells leaves some blurring of this distinction, however, as almost all O&G wells now drilled in Pennsylvania are stimulated with hydraulic fracturing to some degree, and some of the conventional wells are even drilled horizontally – just not into formations that are technically defined as unconventional. For the most part, however, unconventional remains a useful distinction indicating the significant scale of operations.
Table 1. Summary of oil and gas wells, violations, and fines in Pennsylvania
Category
Conventional
Unconventional
(blank)
Total
Wells
193,655
10,291
0
203,946
Violations
27,223
6,126
9,026
42,375
Fines
$7,000,203
$13,689,032
$21,563,722
$35,949,495*
Fines per Violation
257
2,235
2,389
848
Fines per Well
36
1330
–
176.27
Violations per Well
0.14
0.60
–
0.21
Wells per Violation
7.11
1.68
–
4.81
* The total fine amount issued is not a summary of the three preceding categories, as some of the fines appear in multiple categories
Ninety-five (95)% of the state’s 204,000 O&G wells are classified as conventional, so it should not be surprising to see that this category of wells accounts for a majority of violations issued by the department. However, fines associated with these violations are less frequent, and often less harsh; the $7 million in fines for this category accounts for only 19% of the total assessed penalties. In contrast, the total penalties that have been assessed to unconventional wells in the state are nearly twice that of conventional wells, despite accounting for just 5% of the state’s well inventory
On the 54,412 records on the compliance report, 10,518 (19%) do not indicate whether or not it is an unconventional well. The list of operators includes some well-known conventional and unconventional drilling operators, and hundreds of names of individuals or organizations where O&G drilling is not their primary mode of business (such as municipal authorities and funeral homes). This category also contains violations for midstream operations, such as pipelines and compressor stations. Altogether, 3,795 operators have entries that were not categorized as either conventional or unconventional on the compliance report, and 124 of these operators were issued fines. One additional complication is that some of the violations and fines that fall into this category are cross-referenced in the conventional and unconventional categories, as well.
The resulting impact of these factors is that the blank category obscures the trends for violations and fines in the other two categories. While tempting to reclassify well data in this category as either conventional or unconventional, this would be a tall task due to the sheer number of records involved, and would likely result in a significant amount of errors. Therefore, the FracTracker Alliance has decided to present the data as is, along with an understanding of the complexities involved.
Most Heavily Fined Operators
Despite the numerous caveats listed above, we can get a clear look at the aggregated fines issued to the various O&G operators in the state by constructing our queries carefully. Table 2 shows the top 12 recipients of O&G-related fines assessed by DEP since 2000. Ten of these companies are on the extraction side of the business, and the total number of well permits issued4 to these companies since 2000 are included on the table. By looking at the permits instead of the drilled wells, we discover the operator that was originally associated with the drilling location, whereas the report of drilled wells associates the current operator associated with the site, or most recent operator in the event that the location is plugged and abandoned.
Stonehenge Appalachia and Williams Field Services operate in the midstream sector. Combining the various business name iterations and subsidiaries would be an enormous task, which we did not undertake here, with the exception of those near the top of the list. This includes Vantage Energy Appalachia, which was combined with records from Vantage Energy Appalachia II, and the compliance history of Rice Energy is the sum of three subsidiaries, the drilling company Rice Drilling B, and two pipeline companies, Rice Midstream Holdings and Rice Poseidon Midstream.
Table 2. Top 12 operators that have been assessed oil and gas-related fines by DEP since 2000
Operator
Total Fines
Conventional Permits
Unconventional Permits
Violations
Fines / Violation
Fines / Permit
Range Resources Appalachia LLC
$5,717,994
2,104
2,206
819
$6,982
$1,327
Chesapeake Appalachia LLC
$3,120,123
18
3,072
754
$4,138
$1,010
Rice Energy*
$2,336,552
442
165
$14,161
$5,286
Alpha Shale Res LP
$1,681,725
3
62
31
$54,249
$25,873
Stonehenge Appalachia LLC
$1,500,000
–
–
294
$5,102
–
Cabot Oil & Gas Corp
$1,407,275
19
902
726
$1,938
$1,528
CNX Gas Co LLC
$1,274,330
1,613
677
387
$3,293
$556
WPX Energy Appalachia LLC
$1,232,500
347
159
$7,752
$3,552
Chevron Appalachia LLC
$1,077,553
2
604
113
$9,536
$1,778
Vantage Energy Appalachia LLC**
$1,059,766
3
300
35
$30,279
$3,498
Williams Field Services Co, LLC
$872,404
–
–
158
$5,522
–
XTO Energy Inc
$739,712
1,962
461
383
$1,931
305
* Fines for Rice Energy here represent the sum of three subsidiaries, the drilling company Rice Drilling B, and two pipeline companies, Rice Midstream Holdings and Rice Poseidon Midstream.
** Fines for Vantage Energy Appalachia were combined with records from Vantage Energy Appalachia II.
Predictably, many of the entries on this list are among the most active drillers in the state, including Range Resources and Chesapeake Appalachia. However, Alpha Shale Resources has the dubious distinction of leading the pack with the highest amount of fines per violation, as well as the highest amount of fines per permit. Fitting in with the theme, the story here is complicated by the fact that Alpha had a joint venture with Rice, before selling them their stake in a group of wells and midstream operations that were fined $3.5 million by DEP.5 On this compliance report, the fines from this incident are split between the two companies.
Fines Issued Over Time
It is worth taking a look at how O&G related fines have varied over time, as well (Figure 1, shown in millions of dollars). Numerous factors could contribute to changes in trends, such as the number of available DEP inspectors,6 the amount of attention being paid to the industry in the media, differing compliance strategies employed by various political administrations, or changes in practices in the field, which could in turn be impacted by significant fines issued in the past.
Figure 1. O&G Fines Issued by DEP, 2000 through 2016
The notable spike in fines issued from 2010 to 2012 corresponds with the peak of unconventional drilling in the state – 4,908 of these industrial scaled wells were drilled during those three years, amounting to 48% of all unconventional wells in PA. In contrast, only 504 unconventional wells were drilled in 2016, or around a quarter of the total for 2011. In this context, the reduction in fines since the early part of the decade seems reasonable.
The association with the number of unconventional wells falls apart a bit in the years 2013 to 2014, however. These two years saw an average of 1,293 unconventional wells drilled, but the fines issued amounted to only 35% of the 2011 total.
Considerable strides have been made in the public accessibility of oil and gas data available from the PA DEP since FracTracker started requesting and reviewing this information in 2009. Still, there are many gaps in the datasets, such as geolocation details for 10 of the 20 largest fines issued by the department. FracTracker hopes external analyses like this one will help to close such gaps and identify operators who, too, need to improve their compliance records.
Pipelines are hailed as the “safest” way to transport crude oil and other refinery products, but federal and state data show that pipeline incidents are common and present major environmental and human health hazards. In light of current events that have green-lighted multiple new pipeline projects, including several that had been previously denied because of the environmental risk they pose, FracTracker Alliance is continuing to focus on pipeline issues.
In this article we look at the record of oil spills, particularly those resulting from pipeline incidents that have occurred in North Dakota, in order to determine the risk presented by the soon-to-be completed Dakota Access Pipeline.
Standing Rock & the DAPL Protest
To give readers a little history on this pipeline, demonstrators in North Dakota, as well as across the country, have been protesting a section of the Dakota Access Pipeline (DAPL) near the Standing Rock Sioux Tribe’s lands since April 2016. The tribe’s momentum has shifted the focus from protests at the build site to legal battles and a march on Washington DC. The pipeline section they are protesting has at this point been largely finished, and is slated to begin pumping oil by April 2017. This final section of pipe crosses under Lake Oahe, a large reservoir created on the Missouri River, just 1.5 miles north of the Standing Rock Sioux Tribal Lands. The tribe has condemned the pipeline because it cuts through sacred land and threatens their environmental and economic well-being by putting their only source for drinking water in jeopardy.
Pipelines
… supposedly safest form of transporting fossil fuels, but …
However, what makes one form of land transport safer than the others is dependent on which factor is being taken into account. When considering the costs of human death and property destruction, pipelines are indeed the safest form of land transportation. However, for the amount of oil spilled, pipelines are second-worst, beaten only by trucks. Now, when it comes to environmental impact, pipelines are the worst.
What is not debatable is the fact that pipelines are dangerous, regardless of factor. Between 2010 and October 2016 there was an average of 1.7 pipeline incidents per day across the U.S. according to data from the Pipeline and Hazardous Materials Safety Administration (PHMSA). These incidents have resulted in 100 reported fatalities, 470 injuries, and over $3.4 billion in property damage. More than half of these incidents were caused by equipment failure and corrosion (See Figures 1 and 2).
Figure 1. Impacts of pipeline incidents in the US. Data collected from PHMSA on November 4th, 2016 (data through September 2016). Original Analysis
Figure 2. Cause of pipeline incidents for all reports received from January 1, 2010 through November 4, 2016. Original Analysis
Recent Spills in North Dakota
To dig into the risks posed in North Dakota more specifically, let’s take a look at some spill data in the state.
Map 1. Locations of Spills in North Dakota, with volume represented by size of markers
In North Dakota alone there have been 774 oil spill incidents between 2010 and September 2016, spilling an average of 5,131 gallons of oil per incident. The largest spill in North Dakota in recent history, and one of the largest onshore oil spills in the U.S., took place in September 2013. Over 865,000 gallons of crude oil spilled into a wheat field and contaminated about 13 acres. The spill was discovered several days later by the farmer who owns the field, and was not detected by remote monitors. The state claims that no water sources were contaminated and no wildlife were hurt. However, over three years of constant work later, only about one third of the spill has been recovered.
Below we have analyzed available spill data for North Dakota, including the location and quantity of such incidents.
North Dakota saw an average of 111 crude oil spills per year, or a total of 774 spills from 2010 to October 2016. The greatest number of spills occurred in 2014 with a total of 163. But 2013 had the largest spill with 865,200 gallons and also the highest total volume of oil spilled in one year of 1.3 million gallons. (Table 1)
Table 1. Data on all spills from 2010 through October 2016. Data taken from PHMSA and North Dakota.
2010
2011
2012
2013
2014
2015
Jan-Oct 2016
Number of Spills
55
80
77
126
163
117
156
Total Volume (gallons)
332,443
467,544
424,168
1,316,910
642,521
615,695
171,888
Ave. Volume/Spill (gallons)
6,044
5,844
5,509
10,452
3,942
5,262
1,102
Largest Spill (gallons)
158,928
106,050
58,758
865,200
33,600
105,000
64,863
The total volume of oil spilled from 2010 to October 2016 was nearly 4 million gallons, about 2.4 million of which was not contained. Most spills took place at wellheads, but the largest spills occurred along pipelines. (Table 2)
Table 2. Spills by Source. Data taken from PHMSA and North Dakota.
Wellhead
Vehicle Accident
Storage
Pipeline
Equipment
Uncontained
All Spills
Number of Spills
694
1
12
54
13
364
774
Total Volume (gallons)
2,603,652
84
17,010
1,281,798
68,623
2,394,591
3,971,169
Ave. Volume/Spill (gallons)
3,752
84
1,418
23,737
5,279
6,579
5,131
Largest Spill (gallons)
106,050
84
10,416
865,200
64,863
865,200
865,200
A. Sensitive Areas Impacted
5,875 square miles
Total Affected Areas (408 linear miles)
Spills that were not contained could potentially affect sensitive lands and waterways in North Dakota. Sensitive areas include Native American Reservations, waterways, drinking water aquifers, parks and wildlife habitat, and cities. Uncontained spill areas overlapped, and potentially contaminated, 5,875 square miles of land and water, and 408 miles of streams.
Drinking Water Aquifers – 2,482.3 total square miles:
Non-Community Aquifer – 0.3 square miles
Community Aquifer – 36 square miles of hydrologically connected aquifer
Surficial Aquifer – 2,446 square miles of hydrologically connected aquifer
A large area of potential drinking water (surficial aquifers) are at risk of contamination. Of the aquifers that are in use, aquifers for community use have larger areas that are potentially contaminated than those for non-community use.
Native American Tribal Reservation
Fort Berthold, an area of 1,569 square miles
Cities – 67 total square miles
Berthold
Dickinson
Flaxton
Harwood
Minot
Petersburg
Spring Brook
Stanley
West Fargo
Map 2. Areas where Oil Spills Present Public Health Threats
Floodplains – 73 square miles of interconnected floodplains
Streams – 408 miles of interconnected streams
Of the 364 oil spills that have occurred since 2010, 229 (63%) were within 1/4 mile of a waterway
Of the 61 Uncontained Brine Spills that have occurred since 2001, 38 (63%) were within 1/4 mile of a waterway.
If a spill occurs in a floodplain during or before a flood and is uncontained, the flood waters could disperse the oil over a much larger area. Similarly, contaminated streams can carry oil into larger rivers and lakes. Explore Map 3 for more detail.
Using ArcGIS software, uncontained spill locations were overlaid on spatial datasets of floodplains, stream beds, groundwater regions, sensitive habitats, and other sensitive regions.
The average extent (distance) spilled oil traveled from uncontained spill sites was calculated to 400 meters. This distance was used as a buffer to approximate contact of waterways, floodplains, drinking water resources, habitat, etc. with uncontained oil spills.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/04/OilSpill_12.16_crop.jpg400900Kyle Ferrar, MPHhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngKyle Ferrar, MPH2017-04-11 16:15:232021-04-15 15:03:11Oil Spills in North Dakota: What does DAPL mean for North Dakota’s future?
By Greg Pace – Columbus Community Bill of Rights, and Julie Weatherington-Rice – Environmental Consultant
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
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.
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.”
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.
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.
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.
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.
Last month, FracTracker Alliance featured a blog entry and map exploring the controversy around National Fuel’s proposed Northern Access Pipeline (NAPL) project, shown in the map below. The proposed project, which has already received approval from the Federal Energy Regulatory Commission (FERC), is still awaiting another decision by April 7, 2017 — Section 401 Water Quality Certification. By that date, the New York State Department of Environmental Conservation (NYS DEC) must give either final approval, or else deny the project.
The NAPL project includes the construction of 97-mile-long pipeline to bring fracked Marcellus gas through New York State, and into Canada. The project also involves construction of a variety of related major infrastructure projects, including a gas dehydration facility, and a ten-fold expansion of the capacity of the Porterville Compressor Station located at the northern terminus of the proposed pipeline, in Erie County, NY.
On three consecutive days in early February, 2017, the New York State Department of Environmental Conservation (NYS DEC) held hearings in Western New York to gather input about the NAPL project. On February 7th, the day of the first meeting at Saint Bonaventure University in Allegany County, NY, an alarming — and yet to be fully reported — incident widely considered to be a gas leak, occurred at, or near, the Porterville Compressor Station (also known locally as the “Elma Compressor Station”). The incident is thought to be connected to the planned upgrades to the facility, but was not even mentioned as a concern during the public meetings relating to the Northern Access Pipeline in the subsequent hours and days.
What follows is a story of poor communication between the utility company, first responders, and local residents, resulting in confusion and even panic, and has yet to be conclusively explained to the general public.
Incident Description
Area of incident in NY State
We know that a little past 10 AM on February 7th, people in the villages of Elma and East Aurora, within about a mile of the Porterville Compressor Station, reported strong odors of gas. They filed complaints with the local gas utility (National Fuel), and the local 911 center, which referred the calls to the local Elma Fire Department. The fire department went to the Porterville Compressor station to investigate, remembering a similar incident from a few years earlier. At the compressor station, representatives from National Fuel, the operator of the compressor station, assured the fire company that they were conducting a routine flushing of an odorant line, and the situation was under control, so the fire company departed.
Residents in the area became more alarmed when they noticed that the odor was stronger outside their buildings than inside them. National Fuel then ordered many residents to evacuate their homes. The East Aurora police facilitated the evacuation and instructed residents to gather in the East Aurora Library not far from those homes. Nearby businesses, such as Fisher Price, headquartered in East Aurora, chose to send their employees home for the day, due to the offensive odor and perceived risks.
Around 11:30 in the morning, up to 200 clients at Suburban Adult Services, Inc. (SASi), were evacuated to the Jamison Road Fire Station, where they remained until around 3 PM that afternoon. Over 200 reports were received, some from as far away as Orchard Park, eight miles down-wind of the compressor station.
After East Aurora elementary and middle schools placed complaints, National Fuel told them to evacuate students and staff from their buildings. Realizing that the smell was stronger outside than inside the building, school leaders revised their plans, and started to get buses ready to transport student to the high school, where there had not been reports of the odor. Before the buses could load, however, the police department notified the school that the gas leak had been repaired, and that there was no need to evacuate. School officials then activated the school’s air circulation system to rid the building of the fumes.
Perplexingly, according to one report, National Fuel’s Communications Manager Karen Merkel said “that the company did not reach out into the community to tell people what was going on because the company cannot discourage anyone from making an emergency gas call.”
Merkel noted further, “You never know if the smell being reported is related to work we are doing or another gas leak,” she said. “This wouldn’t be determined until we investigate it.”
That smell…
Some background on gas leaks & odorant additives
Ethyl mercaptan molecule
An odorant, such as ethyl mercaptan, is often added to natural gas in order to serve as an “early warning system” in the event of a leak from the system. Odorants like mercaptan are especially effective because the humans can smell very low concentrations of it in the air. According to the National Center for Biotechnology Information, “The level of distinct odor awareness (LOA) for ethyl mercaptan odorant is 1.4 x10-4 ppm,” or 0.00014 parts per million. That translates to 0.000000014 percent by volume.
Not all natural gas is odorized, however. According to Chevron Phillips, “mercaptans are required (by state and federal regulations) to be added to the gas stream near points of consumption as well as in pipelines that are near areas with certain population density requirements, per Department of Transportation regulations… Not all gas is odorized, though; large industrial users served by transmission lines away from everyday consumers might not be required to use odorized gas.” Also, because odorants tend to degrade or oxidize when gas is travelling a long distance through transmission lines, they are not always added to larger pipeline systems.
The explosion and flammability concentration limit for natural gas refers to the percentage range at which a gas will explode. At very low concentrations, the gas will not ignite. If the concentration is too high, not enough oxygen is present, and the gas is also stable. This is why gas in non-leaky pipelines does not explode, but when it mixes with air, and a spark is present, the result can be disastrous. Methane, the primary component of natural gas, has a lower explosive level (LEL) of 4.4% and an upper explosive limit (UEL) (above which it will not ignite) of 16.4%. Nonetheless, levels above 1% are still worrisome, and may still be good cause for evacuation.
Therefore, the margin of safety between when natural gas is detectable with an odorant present, and when it may explode, is very broad. This may help to explain why the smell of gas was detected over such a broad distance, but no explosion (very fortunately) took place.
Local memories of gas explosion in East Aurora
Many East Aurora residents have had first-hand experience with the dangers posed by gas lines in their community. Less than 25 years ago, in September 1994, a high-pressure pipeline owned by National Fuel ruptured in an uninhabited area between East Aurora and South Wales along Olean Rd. The blast left a 10-foot-deep, 20-foot-wide crater, and tree limbs and vegetation were burned as far as 50 feet away.
Porterville first-hand accounts and inquiries
FracTracker spoke extensively with one resident of East Aurora, Jennifer Marmion, about her experiences, and efforts to understand what had actually happened the day of this incident.
When personnel from the Jamison Fire Company — who are assumed to be first responders to emergencies of this sort — arrived at the Porterville Compressor Station, they were told by National Fuel that there was no hazard and that their services were not needed. Consequently, these crews left the site. The East Aurora Police Department was given a different explanation by National Fuel; there was a valve malfunction somewhere along Two Rod Road in Marilla. Still later, National Fuel indicated that the pipeline changeover occurred closer to the compressor station itself. The closest distance between anywhere on Two Rod Road and the compressor station, itself, is a mile and a half. And Ms. Marmion was given a still different story by a National Fuel engineer: that the odor, indeed, resulted during the replacement of a 100-foot-long section of aging pipeline at the Porterville (“Elma”) Compressor Station.
Key locations in incident report
Some reports indicated an alternate explanation: that the odor originated at the East Aurora Town Hall (J. Marmion, pers. comm., via Channel 7 News), or a leaky valve along a pipeline near Marilla (J. Marmion, pers. comm, via East Aurora Police Department dispatcher). A member of the East Aurora Fire Department surmised that the leak might have been closer to Olean Road, south of the village, where there was a history of other leaks. The day after the incident, National Fuel indicated that the odor originated from the compressor station, and was the result of a routine, scheduled “blowdown” by National Fuel — wherein gas lines at the compressor station are cleared as part of routine maintenance. However, when pressed for more details, they did not provide them.
In need of follow up
More than six weeks have passed since the incident, and there is still no definitive explanation available. Clearly, there was considerable confusion about what the correct, and safe, procedure needed to be, as well as how this information needed to flow to the public. Ultimately, a representative from National Fuel’s Government Affairs office agreed that he would alert the local towns and fire departments when maintenance activities would be occurring. It is surprising that this was not already standard practice.
Although Ms. Marmion is continuing to be a determined citizen activist, she has been met with a frustrating array of ambiguous and often conflicting descriptions, phone calls that go un-answered, voice mailboxes at offices that are either full or not set up to receive messages. Furthermore, although National Fuel has told Marmion that there is an Action Plan to be followed in the event of an emergency, they have been unable to provide her with a written or electronic version of this document, because “the action plan is just known.”
National Fuel points to the weather
National Fuel maintains that the only factor that was out of the ordinary was that during the event, a combination of unusual weather factors caused the released gas to travel in an unusual manner and also not dissipate as quickly as expected. National Fuel also indicated that the strong odor (created by the additive mercaptan) was a benefit to the local community, added to natural gas so that residents would be alerted to problems. It’s important to note that the largest gas transmissions pipelines, like the nearby 26” diameter Tennessee Gas Pipeline to the east of Elma and East Aurora, as well other pipelines that will run to the greatly expanded Porterville Compressor Station as part of the Northern Access Pipeline project, will be without the odorant.
Here’s what FracTracker could verify, based on National Weather Service, and Weather Underground historical data. In the morning and afternoon of February 7th, the wind was uncharacteristically blowing from the east/northeast — atypical for western New York, when winds normally come from the west. Wind speeds were recorded between 10-15 mph. Humidity was also uncharacteristically high for February — topping out at 93% that day. Warm air aloft, combined with freezing rain, created a temperature inversion. The moist air then trapped the odor, which lingered across the region.
Screen captures of weather statistics on February 7, 2017 (Source: wunderground.com). Note dominant wind direction from ENE, as well as high humidity, during morning and early afternoon, when incident took place.
Who monitors air quality in Western New York?
Calls by FracTracker for clarification from the New York State DEC’s Division of Air Resources have gone unanswered. The only station at which the DEC monitors methane is located more than 275 miles away to the southeast, in the Bronx. In Erie County, where the incident took place, there are only four permanent ambient air pollution monitoring stations. These include stations in:
Amherst: Continuous monitoring of ozone, NO2. Manual monitoring of PM5, acid deposition.
Buffalo: Continuous monitoring of SO2, NOx, NO, NO2, NOy, CO, CPM5. Manual monitoring of PM2.5, PM10, toxics
Brookside Terrace/Tonawanda: Continuous monitoring of SO2, CPM5. Manual monitoring of toxics and carbonyls
Grand Island (special purpose only): Continuous monitoring of CPM5. Manual monitoring of toxics and carbonyls
“PM” refers to particulate matter diameter. PM5, for example, denotes particulate matter 5 microns in diameter, and smaller.
The East Aurora and Elma fire departments lack the appropriate air quality detection instruments to make their own judgements on the explosive nature of these gas plumes. Instead, small towns rely on the expertise of National Fuel to arrive on the scene after a call has been made, so that National Fuel can take measurements and then respond to the community. Some residents waited over three hours for an assessment, but by this time the plume had drifted away two hours ago.
National Fuel, however, has not disclosed any of the air quality data measurements they made on February 7th when they responded to this complicated incident. Ms. Marmion and others still want to know what levels of methane were measured in the communities involved in this incident, or the specific quantity of gas that entered the air that day.
What’s next?
While National Fuel did not notify the residents or the school district administration in advance of the scheduled “blowdown,” their Government Affairs Representative indicated that in the future, town governments, community leaders, and the local fire companies would be alerted to the upcoming releases and maintenance work. Nonetheless, weeks after the odor incident, National Fuel has neither contacted the local community leaders, nor local law enforcement, to provide complete and detailed answers as to what actually happened on February 7th.
By Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance. Special thanks to East Aurora resident Jennifer Marmion, for her insights and comments.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/03/Porterville-Feature.jpg400900Karen Edelsteinhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngKaren Edelstein2017-03-27 08:56:032021-04-15 15:03:36Mysterious leak near Porterville Compressor Station, NY
Each year, FracTracker Alliance compiles a national well file to try to assess how many wells have been drilled in the U.S. We do this by extracting data from the various state regulatory agencies that oversee drilling in oil and gas producing states. We’re a little late posting the results of our 2016 analysis, but here it is.
Based on data from 2014-2015, 34 states * saw drilling activity, amounting to approximately 1.2 million facilities across the U.S. – from active production wells, to natural gas compressor stations, to processing plants.
The process we used to count these wells and related facilities for the 2016 analysis changed a bit this time around, which obviously impacts the total number of wells in the dataset. 2016’s compilation was created in consultation with Earthworks, for the purpose of informing the Oil and Gas Threat Map project. The scope was more restrictive than previous editions (see our 2014 and 2015 analyses), focusing only on wells that we were reasonably confident were actively producing oil and gas wells, thus excluding wells with inactive or uncertain statuses, as well salt water disposal (SWD) and other Class II injection (INJ) well types.
There are facilities included in this dataset that we don’t normally tally, as well (See Table 1 below). Earthworks was able to determine the latitude and longitude coordinates of a number of compressors and other processing plants, which are included in the dataset below and final map.
In all, the facility counts are reduced from about 1.7 million in 2015 to about 1.2 million in 2016, but this is more a reflection of the definition than substantial changes in the active well inventory in the U.S. You can explore this information by state, and additional results of this project, using Earthworks’ Threats Maps. Additionally, the national well file is available to download below.
You’ll notice that we don’t refer to the wells in this analysis as “fracked” wells. The primary reason for not using such terminology is because no one common definition exists across those states for what constitutes a hydraulically fractured well. In PA, for example, such wells are considered “unconventional” because drilling occurs in an unconventional formation and usually involves some sort of well stimulation. Contrastingly, in CA, often drillers use “acidizing” not fracking – a similar process that breaks up the ground using acidic injected fluids instead of the high pressure seen in traditional fracking. As such, we included all active oil and gas production instead of trying to limit the analysis to just wells that have been stimulated. We will likely continue to use this process until a federal or national definition of what constitutes a “fracked” well is determined.
Table 1. Facilities by State and Type
State
Count of Facilities by Type
Grand Total
Compressor
Processor
Well
AK
7
3,356
3,363
AL
17
7,016
7,033
AR
231
8
13,789
14,028
AZ
40
40
CA
7
21
92,737
92,765
CO
426
49
50,881
51,356
FL
2
102
104
ID
6
6
IL
5
48,748
48,753
IN
7,374
7,374
KS
9
90,526
90,535
KY
5
11,769
11,774
LA
6,486
94
2,555
9,135
MI
19
16,525
16,544
MO
2
687
689
MS
6
4,556
4,562
MT
5
9,768
9,773
ND
19
13,024
13,043
NE
1
16,202
16,203
NM
902
37
57,839
58,778
NV
176
176
NY
12,244
12,244
OH
29
10
90,288
90,327
OK
856
96
29,042
29,994
OR
56
56
PA
452
11
103,680
104,143
SD
408
408
TN
15,956
15,956
TX
758
315
397,776
398,849
UT
18
20,608
20,626
VA
9,888
9,888
WI
1
1
WV
20
16,118
16,138
WY
325
48
38,538
38,911
Grand Total
10,472
825
1,182,278
1,193,575
* NC facilities are not included because the state did not respond to multiple requests for the data. This exclusion likely does not significantly affect the total number of wells in the table, as historically NC only had 2 oil and gas wells.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/03/34-states-feature.jpg400900FracTracker Alliancehttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngFracTracker Alliance2017-03-23 09:48:412021-04-15 15:03:3734 states have active oil & gas activity in U.S. based on 2016 analysis
A review of WV and OH drilling activity and its proximity to schools and medical facilities
Schools and hospitals represent places where vulnerable populations may be put at risk if they are located close to oil and gas activity. Piggybacking on some elegant work from PennEnvironment (2013) and Physicians, Scientists, and Engineers (PSE) Healthy Energy (PDF) in Pennsylvania, below is an in-depth look at the proximity of unconventional oil and gas (O&G) activity to schools and hospitals in Ohio and West Virginia.
Ohio Schools and Medical Facilities
In Ohio, presently there are 13 schools or medical facilities within a half-mile of a Utica and/or Class II injection well and an additional 344 within 2 miles (Table 1 and map below). This number increases to 1,221 schools or medical facilities when you consider those within four miles of O&G related activity.
Map of OH Drilling and Disposal Activity Near Schools, Medical Facilities
Table 1. Number of OH schools and hospitals within certain distances from Utica wells
Utica
Class II Injection
Well Distance (Miles)
Schools
Medical Facilities
Schools
Medical Facilities
0.5
3
1
9
0
0.5-1
19 (22)
9 (10)
16 (25)
13 (13)
1-2
79 (101)
41 (51)
88 (113)
79 (92)
2-3
84 (185)
49 (100)
165 (278)
122 (214)
3-4
85 (270)
79 (179)
168 (446)
112 (326)
4-5
92 (362)
63 (242)
196 (642)
166 (492)
5-10
388 (750)
338 (580)
796 (1,438)
584 (1,076)
Ohio’s rate of Utica lateral permitting has jumped from an average of 39 per month all-time to 66 per month in the last year. OH’s drilling activity has also begun to spread to outlying counties[1]. As such, we thought a proactive analysis should include a broader geographic area, which is why we quantified the number of schools and medical facilities within 5 and 10 miles of Utica and Class II activity (Figures 1 and 2). To this end we found that ≥50% of Ohio’s schools, both public and private, are within 10 miles of this industry. Similarly 50% of the state’s medical facilities are within 10 miles of Utica permits or Class II wells.
Footnote 1: Eleven counties in Ohio are currently home to >10 Utica permits, while 23 are home to at least 1 Utica permit.
Figures 1, 2a, 2b (above). Click to expand.
Grade Level Comparisons
With respect to grade level, the majority of the schools in question are elementary schools, with 40-50 elementary schools within 2-5 miles of Ohio Utica wells. This number spikes to 216 elementary schools within ten miles of Utica permits along with an additional 153 middle or high Schools (Figure 3). Naturally, public schools constitute most of the aforementioned schools; there are approximately 75 within five miles of Utica permits and 284 within ten miles of Utica activity (Figure 4).
Figures 3 and 4 (above). Click to expand.
Public Schools in Ohio
We also found that ~4% of Ohio’s public school students attend a school within 2 miles of the state’s Utica and/or Class II Injection wells (i.e., 76,955 students) (Table 2). An additional 315,362 students or 16% of the total public school student population, live within five miles of O&G activity.
Table 2. Number of students in OH’s public schools within certain distances from Utica and Class II Injection wells
Utica
Class II Injection
Well Distance (Miles)
# Schools
# Students
Avg
# Schools
# Students
Avg
0.5
3
1,360
453
7
3,312
473
<1
21
7,910
377
19
7,984
420
<2
96
35,390
376
90
41,565
462
<3
169
67,713
401
215
104,752
487
<4
241
97,448
404
350
176,067
503
<5
317
137,911
435
505
254,406
504
<10
600
280,330
467
1,126
569,343
506
(Note: Ohio’s population currently stands at 11.59 million people; 2,007,667 total students).
The broadest extent of our study indicates that 42% of Ohio students attend school within ten miles of a Utica or Class II Injection well (Figure 5). As the Ohio Utica region expands from the original 11 county core to include upwards of 23-25 counties, we expect these 5-10 mile zones to be more indicative of the type of student-Utica Shale interaction we can expect to see in the near future.
Photos of drilling activity near schools, and Figure 5 (above). Click to expand.
Private Schools in Ohio
At the present time, less than one percent of Ohio’s private school students attend a school within 2 miles of Utica and/or Class II Injection wells (specifically, 208 students). An additional 11,873 students or 11% of the total student population live within five miles. When you broaden the extent, 26% of Ohio’s private primary and secondary school students attend school daily within ten miles of a Utica or Class II Injection well. Additionally, the average size of schools in the immediate vicinity of Utica production and waste activity ranges between 11 and 21 students, while those within 2-10 miles is 112-159 students. Explore Table 3 for more details.
Table 3. Number of students in Ohio’s private schools within certain distances from Utica and Class II Injection.
Utica
Class II Injection
Distance from Well (Miles)
# Schools
# Students
Avg
# Schools
# Students
Avg
0.5
.
.
.
1
.
.
<1
.
.
.
2
25
13
<2
2
22
11
9
186
21
<3
7
874
125
30
4,460
149
<4
12
1,912
159
45
6,303
140
<5
21
2,471
118
61
9,610
158
<10
60
6,727
112
135
20,836
154
West Virginia Schools and Students
Twenty-eight percent (81,979) of West Virginia’s primary and secondary school students travel to a school every day that is within two miles of the state’s Marcellus and/or Class II Injection wells.
Compared with Ohio, 5,024 more WV students live near this industry (Table 4). An additional 97,114 students, or 34% of the West Virginia student population, live within 5 miles of O&G related wells. The broadest extent of our study indicates that more than 90% of West Virginia students attend school daily within 10 miles of a Marcellus and/or Class II Injection well.
Figure 6. West Virginia primary and secondary schools, Marcellus Shale wells, and Class II Injection wells (Note: Schools that have not reported enrollment figures to the WV Department of Education are highlighted in blue). Click image to expand.
It is worth noting that 248 private schools of 959 total schools do not report attendance to the West Virginia Department of Education, which means there are potentially an additional 69-77,000 students in private/parochial or vocational technology institutions unaccounted for in this analysis (Figure 6). Finally, we were not able to perform an analysis of West Virginia’s medical facility inventory relative to Marcellus activity because the West Virginia Department of Health and Human Resources admittedly did not have an analogous, or remotely complete, list of their facilities. The WV DHHR was only able to provide a list of Medicaid providers and the only list we were able to find was not verifiable and was limited to hospitals only.
Table 4. Number of students in WV schools within certain distances from Shale and Class II Injection wells
Marcellus
Class II Injection
Distance from Well (Miles)
#
Sum
Avg
#
Sum
Avg
0.5
19
5,674
299
1
.
.
<1
52 (71)
16,992 (22,666)
319
5 (6)
1,544
257
<2
169 (240)
52,737 (75,403)
314
16 (22)
5,032 (6,576)
299
<3
133 (373)
36,112 (111,515)
299
18 (40)
6,132 (12,708)
318
<4
88 (461)
25,037 (136,552)
296
21 (61)
5,235 (17,943)
294
<5
56 (517)
15,685 (152,237)
295
26 (87)
8,913 (26,856)
309
<10
118 (635)
37,131 (189,368)
298
228 (315)
69,339 (96,195)
305
Note: West Virginia population currently stands at 1.85 million people; 289,700 total students with 248 private schools of 959 total schools not reporting attendance, which means there are likely an additional 69-77,000 students in Private/Parochial or Vocational Technology institutions unaccounted for in this analysis.
Conclusion
A Trump White House will likely mean an expansion of unconventional oil and gas activity and concomitant changes in fracking waste production, transport, and disposal. As such, it seems likely that more complex and broad issues related to watershed security and/or resilience, as well as related environmental concerns, will be disproportionately forced on Central Appalachian communities throughout Ohio and West Virginia.
Will young and vulnerable populations be monitored, protected, and educated or will a Pruitt-lead EPA pursue more laissez-faire tactics with respect to environmental monitoring? Stay Tuned!
Analysis Methods
The radii we used to conduct this assessment ranged between ≤ 0.5 and 5-10 miles from a Utica or Marcellus lateral. This range is larger than the aforementioned studies. The point of using larger radii was to attempt to determine how many schools and students, as well as medical facilities, may find themselves in a more concentrated shale activity zone due to increased permitting. Another important, related issue is the fact that shale O&G exploration is proving to be more diffuse, with the industry exploring the fringes of the Utica and Marcellus shale plays. An additional difference between our analysis and that of PennEnvironment and PSE Healthy Energy is that we looked at identical radii around each state’s Class II Injection well inventory. We included these wells given the safety concerns regarding:
their role in induced seismicity,
potential water and air quality issues, and
concomitant increases in truck volumes and speeds.
By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/03/WV-Schools-Feature.jpg400900Ted Auch, PhDhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngTed Auch, PhD2017-03-13 11:27:562021-04-15 15:03:37How close are schools and hospitals to drilling activity in West Virginia and Ohio?
Highlighting the maps of radioactive oil and gas exploration and production wastes created in collaboration with the Western Organization of Research Councils
By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance
Scott Skokos, Western Organization of Research Councils
Oil and gas waste can be radioactive, but it is not considered “hazardous,” at least according to the federal government. In this article, we summarize several of the hazardous risks resulting from the current federal policy that fails to regulate this massive waste stream, and the gaps left by states. Of the six states mapped in this assessment, only the state of Montana has initiated any type of rule-making process to manage the waste.
When it comes to unconventional oil and gas waste streams:
Nobody can say how much of any type of waste is being produced, what it is, and where it’s ending up. – Nadia Steinzor, Earthworks
Why is accurate waste data so hard to come by? The Earthworks report, Wasting Away explains that the U.S. EPA intentionally exempted oil and gas exploration and production wastes from the federal regulations known as the Resource Conservation and Recovery Act (RCRA) despite concluding that such wastes “contain a wide variety of hazardous constituents.” As a result, there is very little waste tracking and reporting of oil and gas waste data nationally.
State Waste Management Maps
Some data is available at the state level, so we at FracTracker have compiled, cleaned, and mapped what little data we could find.
State-specific maps have been created for Montana, North Dakota, Colorado, and Wyoming – see below:
When we hear about “radioactive waste” associated with the energy industry, nuclear power stations and fission reactors are usually what come to mind. But, as the EPA explains, fracking has transformed the nature of the oil and gas waste stream. Components of fracking waste differ from conventional oil and gas exploration and production wastes in a number of ways:
In general, the waste stream has additional hazardous components, and that transformation includes increased radioactivity.
Fracking has allowed for more intrusive drilling, penetrating deep sedimentary formations using millions of gallons of fluid.
Drilling deeper produces more drill cuttings.
The process of hydraulic fracking introduces millions more gallons of fluid into the ground that then return to the surface. These returns are ultimately contaminated and require disposal.
The formations targeted for unconventional development are mostly ancient seabeds still filled with salty “brines” known as “formation waters.”
In addition to the hazardous chemicals in the fracking fluid pumped into the wells for fracking, these unconventional formations contain larger amounts of heavy metals, carcinogens and other toxics. This also includes more radioisotopes such as Uranium, Thorium, Radium, Potassium-40, Lead-210, and Polonium-210 than the conventional formations that have supplied the majority of oil and gas prior to the shale boom.
A variety of waste products make up the waste stream of oil and gas development, and each is enhanced with naturally occurring radioactive materials (NORM). This waste stream must be treated and disposed of properly. All the oil and gas equipment – such as production equipment, processing equipment, produced water handing equipment, and waste management equipment – also need to be considered as sources of radioactive exposure.
Figure 1 below explains where the waste from fracking goes after it leaves the well pad.
Figure 1. Breakdown of the radioactive oil and gas waste life-cycle
Three facets of the waste stream particularly enhanced with NORMs by fracking include scales, produced waters, and sludges.
A. Scales
When injected into the ground, fracking fluid mixes with formation waters, dissolving metals, radioisotopes and other inorganic compounds. Additionally the fracking liquids are often supplemented with strong acids to reduce “scaling” from precipitate build up (to prevent clogging up the well). Regardless, each oil well generates approximately 100 tons of radioactive scale annually. As each oil and gas reservoir is drained, the amount of scale increases. The EPA reports that lead-210 and polonium-210 are commonly found in scales along with their decay product radon at concentrations estimated to be anywhere from 480 picocuries per gram (pCi/g) to 400,000 pCi/g). Scale can be disposed of as a solid waste, or dissolved using “scale inhibitors.” These radioactive elements then end up in the liquid waste portion of the waste stream, known as produced waters.
B. Produced Waters
In California, strong acids are used to further dissolve formations to stimulate additional oil production. Acidic liquids are able to dissolve more inorganic elements and compounds such as radioisotopes. While uranium and thorium are not soluble in water, their radioactive decay products such as radium dissolve in the brines. The brines return to the surface as “produced water.” As the oil and gas in the formation are removed, much of what is pumped to the surface is formation water.
Consequently, declining oil and gas fields generate more produced water. The ratio of produced water to oil in conventional well was approximately 10 barrels of produced water per barrel of oil. According to the American Petroleum Institute (API), more than 18 billion barrels of waste fluids from oil and gas production are generated annually in the United States. There are several options for managing the liquid waste stream. The waste could be treated using waste treatment facilities, reinjected into other wells to enhance production (a cheaper option), or injected for disposal. Before disposal of the liquid portion, all the solids in the solution must be removed, resulting in a “sludge.”
C. Sludges
The U.S. EPA reports that conventional oil production alone produces 230,000 million tons – or five million ft3 (141 cubic meters) – of TENORM sludge each year. Unconventional processes produce much more sludge waste than conventional processes. The average concentration of radium in sludges is estimated to be 75 pCi/g, while the concentration of lead-210 can be over 27,000 pCi/g. Sludges present a high risk to the environment and a higher risk of exposure for people and other receptors in those environments because sludges are typically very water soluble.
Federal Exemptions
According to the EPA, “because the extraction process concentrates the naturally occurring radionuclides and exposes them to the surface environment and human contact, these wastes are classified as Technologically Enhanced Naturally Occurring Radioactive Material (TENORM).” Despite the conclusions that oil and gas TENORM pose a risk to the environment and humans, the EPA exempts oil and gas exploration and production wastes from the definition of “hazardous” under Resource Conservation and Recovery Act (RCRA) law. In fact, most wastes from all of the U.S. fossil fuel energy industry, including coal-burning and natural gas, are exempt from the disposal standards that hazardous waste normally requires.
The Center for Public Integrity calls this radioactive waste stream “orphan waste,” because no single government agency is fully managing it.
Just last month (January 10, 2017) the U.S. EPA agreed to review federal regulations of oil and gas waste – a process they were meant to do every 3 years for the last 30 years. The EPA has until March 15, 2019, to determine whether or not regulatory changes are warranted for “wastes associated with the exploration, development, or production of crude oil, natural gas, or geothermal energy.” With the recent freeze on all U.S. EPA grants, however, it is not clear whether these regulations will receive the review they need.
State Regulations
Regulation of this waste stream is left up to the states, but most states do not require operators to manage the radioactivity in oil and gas wastes, either. Because of the federal RCRA exemptions most state policies ignore the radioactive issue altogether. Operators are free to dispose of the waste at any landfill facility, unless the landfill tells them otherwise. For detailed analyses of state policies, see pages 10-45 of the No Time to Waste report. FracTracker has also covered these issues in Pennsylvania and Ohio.
Another issue that screams for federal consideration of this waste stream is that states do not have the authority to determine whether or not the wastes can cross their borders. States also do not have the jurisdiction to decide whether or not facilities in their state can accept waste from across state lines. That determination is reserved for federal jurisdiction, and there are not any federal laws regulating such wastes. In fact, these wastes are strategically exempt from federal regulation for just these reasons.
Why can’t the waste be treated?
This type of industrial waste actually cannot be treated, at least not entirely. Unlike organic pollutants that can be broken down, inorganic constituents of the waste cannot be simply disintegrated out of existence. Inorganic components include heavy metals like arsenic and bromides, as well as radioactive isotopes of radium, lead, and uranium. Such elements will continue to emit radiation for hundreds-to-thousands of years. The best option available is to find a location to “isolate” and dispose of these wastes – a sacrifice zone.
Current management practices do their best to separate the liquid portions from the solid portions, but that’s about it. Each portion can then be disposed independently of each other. Liquids are injected into the ground, which is the cheapest option where it is available. If enough of the dissolved components (heavy metals, salts, and radioisotopes) can be removed, wastewaters are discharged into surface waters. The compounds and elements that are removed from the liquid waste stream are hyper-concentrated in the solid portion of the waste, described as “sludge” in the graphic above. This hazardous material can be disposed of in municipal or solid waste landfills if the state regulators do not require the radioactivity or toxicity of this material to be a consideration for disposal. There are not federal requirements, so unless there is a specific state policy regarding the disposal, it can end up almost anywhere with little oversight. These chemicals do not magically disappear. They never disappear.
Risks
There are multiple pathways for contamination from facilities that are not qualified to manage radioactive and hazardous wastes. At least seven different environmental pathways provide potential risks for human exposure. They include:
Radon inhalation,
External gamma exposure,
Groundwater ingestion,
Surface water ingestion,
Dust inhalation,
Food ingestion, and
Skin beta exposure from particles containing the radioisotopes.
According to the EPA, the low-level radioactive materials in drilling waste present a definitive risk to those exposed. High risk examples include dust suppression and leaching. If dust is not continuously suppressed, radioactive materials in dust pose a risk to people at these facilities or those receptors or secondary pathways located downwind of the facilities. Radioactive leachate entering surface waters and groundwaters is also a significant threat. A major consideration is that radioactive waste can last in these landfills far longer than the engineered lifespans of landfills, particularly those that are not designed to retain hazardous wastes.
Cases of Contamination
North Dakota
In North Dakota, the epicenter of the Bakken Oil Fields, regulators were not ready for the massive waste streams that came from the fast growing oil fields. This allowed thousands of wastewater disposal wells be drilled to dispose of salty wastewater without much oversight, and no places in state for companies to dispose of radioactive solid waste. Many of the wastewater disposal wells were drilled haphazardly, and as a result many contaminated surrounding farmland with wastewater. With regard to radioactive solid waste, the state until recently had a de facto ban on solid radioactive waste disposal due to their radioactivity limit being 5 picocuries per gram. The result of this de facto ban made it so companies either had to make one of two decisions: 1. Haul their radioactive solid waste above the limit out of state to facilities in Idaho or Colorado; or 2. Risk getting caught illegally dumping waste in municipal landfills or just plain illegal dumping in roadsides, buildings, or farmland.
In 2014, a massive illegal dumping site was discovered in Noonan, ND when North Dakota regulators found a gas station full of radioactive waste and filter socks (the socks used to filter out solid waste from wastewater, which contain high levels of radioactivity). Following the Noonan, ND incident North Dakota regulators and politicians began discussions regarding the need for new regulations to address radioactive solid waste.
In 2015, North Dakota moved to create rules for the disposal of solid radioactive waste. Its new regulations increase the radioactivity limit from 5 picocuries per gram to 50 picocuries per gram, and sets up new requirements for the permitting of waste facilities accepting radioactive waste and the disposal of radioactive waste in the waste facilities. Dakota Resource Council, a member group of WORC, challenged the rules in the courts, arguing the rules are not protective enough and that the agency responsible for the rules pushed through the rules without following the proper procedures. Currently the rules are not in effect until the litigation is settled.
Pennsylvania
In Pennsylvania, the hotbed of activity for Marcellus Shale gas extraction, the regulatory body was ill equipped and uninformed for dealing with the new massive waste stream when it first arrived on scene. Through 2013, the majority of wastewater was disposed of in commercial and municipal wastewater treatment facilities that discharge to surface waters. Numerous facilities engaged in this practice without amending their federal discharge permits to include this new waste stream.
Waste treatment facilities in Pennsylvania tried to make the waste streams less innocuous by diluting the concentrations of these hazardous pollutants. They did this by mixing the fracking wastes with other waste streams, including industrial discharges and municipal waste. Other specialized facilities also tried to remove these dissolved inorganic elements and filter them from the discharge stream.
As a result of site assessments by yours-truly and additional academic research, these facilities realized that such hazardous compounds do not simply dilute into receiving waters such as the Allegheny, Monongahela, and Ohio rivers. Instead, they partition (settle) into sediments where they are hyper-concentrated. As a result of the lawsuits that followed the research, entire river bottoms in Pennsylvania had to be entirely dug up, removed, and disposed of in hazardous waste landfills.
Action Plans Needed
Massive amounts of solid and liquid wastes are still generated during drilling exploration and production from the Marcellus Shale. There is so much waste, operators don’t know what to do with it. In Pennsylvania, there is not much they can do with it, but it is not just Pennsylvania. Throughout the Ohio River Valley, operators struggle to dispose of this incredibly large waste stream.
Ohio, West Virginia, and Pennsylvania have all learned that this waste should not be allowed to be discharged to surface waters even after treatment. So it goes to other states – those without production or the regulatory framework to manage the wastes. Like every phase of production in the oil and gas industry, operators (drillers) shop around for the lowest disposal costs. In Estill County, Kentucky, the State Energy and Environment Department just recently cited the disposal company Advance Disposal Services Blue Ridge Landfill for illegally dumping hydraulic fracturing waste. The waste had traveled from West Virginia Marcellus wells, and ended up at an ignorant or willfully negligent waste facility.
In summary, there is inadequate federal oversight of potentially hazardous waste coming from the oil and gas industry, and there are serious regulatory gaps within and between states. Data management practices, too, are lacking. How then, is the public health community supposed to assess the risk that the waste stream poses to people? Obviously, a more thorough action plan is needed to address this issue.
Feature image: Drill cuttings being prepared to be hauled away from the well pad. Photo by Bill Hughes, OVEC
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2016/04/PublicIntegrity_Bill-Hughes_re.jpg400900Kyle Ferrar, MPHhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngKyle Ferrar, MPH2017-03-09 13:20:442021-04-15 15:03:39Oil and Gas Wastes are Radioactive – and Lack Regulatory Oversight
Ohio is unique relative to its Appalachian neighbors in the Marcellus and Utica Shale Basins in that The Buckeye State chose to “diversify” when it came to planning for the hydraulic fracturing revolution. One of the first things financial advisers tell their clients is to “diversify, diversify, diversify.” However, this strategy is usually meant to buffer investors when certain sectors of the economy underperform. Columbus legislators took this strategy to mean that we should drill and hydraulically fracture our geology to extract oil and gas (O&G), as well as taking in vast quantities of liquid and solid O&G waste from Pennsylvania and West Virginia.
Accepting significant quantities of out-of-state waste raises several critical questions, however. How will these materials will be contained? Will such volumes require more and larger waste landfills? And will the injection of liquid brine waste into our geology (photo below) make Ohio the “Oklahoma of Appalachia” with respect to induced seismicity?
Above: Example Class II salt water disposal (SWD) wells in Ohio
Risks to Public Water Supplies
There are also mounting concerns about public water supply (PWS) security, quality, and resilience. These concerns stem from the growing uncertainty surrounding the containment of hydraulically fractured and Class II injection wells.
To begin to assess the risks involved in locating these wells near PWS’s, we compiled and incorporated as many of the state’s PWS’s into our primary Ohio maps. In this post, we explore PWS proximity to Utica drilling activity and Class II salt water disposal (SWD) wells in Ohio.
Waste Disposal & Drilling Near PWS’s
Just how close are public water supplies to Class II waste disposal wells and permitted Utica wells? As of January 15, 2017, there are 13 PWS’s within a half-mile of Ohio’s Class II SWD wells, and 18 within a half-mile of permitted Utica wells. These facilities serve approximately 2,000 Ohioans each, with an average of 112-153 people per PWS (Tables 1 and 5). Within one mile from these wells there are 64 to 66 PWSs serving 18 to 61 thousand Ohioans. That’s an average of 285-925 residents.
Above: Photos of SWD wells from the sky
While PWSs on the 5-mile perimeter of our analysis don’t immediately conjure up water quality/quantity concerns, they may in the future; the rate of Utica and Class II permitting is likely to accelerate under a new White House administration more friendly to industry and averse to enforcing or enhancing regulatory hurdles.
A total of 960 and 699 PWSs are currently within five miles of Ohio Class II and Utica wells. These facilities service roughly 1.5 million and one-half million Ohioans each day, which is ~13% and 4% of the state, respectively. The average PWS within range of Class II wells is 37% to 330 times the average PWS within range of Utica wells.
Roland Marily Kemble Class II Salt Water Disposal Well, Muskingum County, Ohio, Muskingum River Watershed, 39.975, -81.845, 1,984,787 Barrels of Waste Disposed Between 2010 and Q3-2016
Fifty-eight (58%) to 69% of the PWSs within range of Class II wells are what the Ohio EPA calls Transient Non-Community (TNC) (Table 2). TNC’s are defined by the OH EPA and OH Department of Agriculture as serving[1]:
…at least 25 different persons over 60 days per year. Examples include campgrounds, restaurants and gas stations. In addition, drinking water systems associated with agricultural migrant labor camps, as defined by the Ohio Department of Agriculture, are regulated even though they may not meet the minimum number of people or service connections.
Meanwhile 60-89% of PWS’s in the shadow of Ohio’s permitted Utica wells are of the TNC variety. Even larger percentages of these PWS’s are either Groundwater or Purchased Groundwater types. Most of the PWS’s within the range gradient we looked at are privately owned, with only handful owned by federal or state agencies (Table 6).
Above: Example Class II salt water disposal (SWD) wells in Ohio
Of the 24 hydrologic unit codes (HUCs)/watersheds that contain Class II SWD wells, the lion’s share of PWS’s within the shadow of injection wells are the Tuscarawas, Mahoning, and Walhonding (Table 3). Even the Cuyahoga River, which feeds directly in the Great Lakes, is home to up to 138 PWS’s within 5 miles of Class II SWD wells. Conversely, only 13 HUCs currently contain Ohio’s Utica wells. Like Class II-affected HUCs, we see that the Mahoning, Tuscarawas, and Cuyahoga PSW’s contain most of the PWSs of interest (Table 7).
Conclusion
Watershed security/resilience concerns are growing in Eastern Ohio. Residential and agricultural water demands are increasingly coming into conflict with the drilling industry’s growing freshwater demand. Additionally, as oil and gas drilling uses more water, we will see more brine produced (Figures 1 and 2).
This, in turn, will create more demand – on top of an already exponential trend (Figure 3) – for Ohio’s existing Class II wells from across Northern Appalachia, stretching from Southeast Ohio and West Virginia to North Central Pennsylvania.
An understanding of the links between watershed security, O&G freshwater demand, brine production, and frack waste disposal is even more critical in areas like Southeast Ohio’s Muskingum River Watershed (Figure 4).
Figure 4. A Dynamic Model of Water Demand Between 2000 and 2020 within the Muskingum River Watershed, Southeast Ohio, Kurtz and Auch 2015
This is a region of the state where we have seen new water withdrawal agreements like the one below between the Muskingum River Watershed Conservancy District (MWCD) and Antero described in last week’s Caldwell Journal-Leader, Noble County, Ohio:
The [MWCD], which oversees 10 lakes in east central Ohio, approved a second short-term water sale from Seneca Lake last week. The deal, with Antero Resources, Inc., could net the district up to $9,000 a day over about a three month period, and allows Antero to draw up to 1.5 million gallons of water a day during the months of August, September and October for a total of 135 million gallons; less than one percent of the lake’s estimated volume of 14.2 billion gallons. Antero plans to use the water in its fracking operations in the area and will pay $6 per 1000 gallons drawn.
Consol Energy’s Cowgill Road Impoundment, Sarahsville, Wills Creek, Muskingum River Watershed, Noble County, Ohio, 39.8212, -81.4061
This agreement will mean an increase in new Class II SWD permits and/or discussion about converting Ohio’s thousands of other Class II wells into SWD wells. What does this change means for communities that have already seen the industry extract the equivalent of nearly 14% – and even 25-80% in several counties – of residential water from their watersheds, only to inject it 6,000+ feet into the state’s geology is unknown? (Figure 5)
It is critical that we establish and frequently revisit the spatial relationship between oil and gas infrastructure the water supplies of Appalachian Ohio. The state of national politics, federal agency oversight and administrations, growing concerns around climate change, and the fact that Southeast Ohio is experiencing more intense and infrequent precipitation events are testaments to that fact. We will be tracking these changes to Ohio’s landscape as they develop. Stay tuned.
Kleese Disposal Class II Salt Water Disposal well from the sky, Trumbull County, Shenango/Mahoning River, 41.244, -80.641. Data suggest 3,548,104 barrels of waste have been disposed of there between 2010 and Q3-2016.
Supplemental Tables
Public Water and Class II Wells
Table 1. Number of Ohio public water supplies and population served at several intervals from Class II Injection wells
Well Distance (Miles)
#
Total Population
Ave Served Per Well
Max People Per Well
0.5
13
1,992
153 (±120)
446
<1
66
60,539
917 (±4,702)
37,456
<2
198
278,402
1,406 (±4,374)
37,456
<3
426
681,969
1,601(±8,187)
148,000
<4
681
1,086,463
1,596 (±8,284)
148,000
<5
960
1,450,865
1,511 (±7,529)
148,000
Table 2. Ohio public water supplies by system type, source, and ownership at several intervals from Class II Injection wells
Well Distance (Miles)
System Type†
Source††
Ownership
NTNC
TNC
C
G
GP
S
SP
Private
Local
Fed
State
0.5
3
9
1
13
13
<1
11
47
8
65
1
61
5
<2
30
118
50
177
16
5
164
34
<3
76
245
105
385
32
8
351
75
<4
122
392
167
628
40
12
574
106
1
<5
162
564
234
878
30
32
19
823
135
1
1
† NTNC = Non-Transient Non-Community; TNC = Transient Non-Community; C = Community
†† G = Groundwater; GP = Purchased Groundwater; S = Surface Water; SP = Purchased Surface Water
Table 3. Ohio public water supplies by hydrologic unit code (HUC) at several intervals from Class II Injection wells
HUC Name
Well Distance (Miles)
0.5
<1
<2
<3
<4
<5
Ashtabula-Chagrin, 799
1
5
18
18
22
Black-Rocky, 859
1
1
2
2
9
Cuyahoga, 832
1
8
20
92
92
138
Grand, 811
12
30
71
71
81
Hocking, 1081
4
18
18
22
Licking, 1010
1
2
17
17
29
Little Muskingum-Middle Island, 1062
1
2
2
6
Lower Maumee, 856
2
2
4
Lower Scioto, 1091
6
6
9
Mahoning, 831
9
17
48
129
129
161
Mohican, 919
1
3
3
4
Muskingum, 1006
1
3
15
15
33
Raccoon-Symmes, 1128
1
Sandusky, 862
3
19
19
27
Shenango, 815
1
2
6
10
10
11
St. Mary’s, 934
3
5
5
7
Tiffin, 837
4
4
7
Tuscarawas, 889
1
9
76
147
147
213
Upper Ohio, 901
3
15
15
23
Upper Ohio-Shade, 1120
4
8
8
9
Upper Ohio-Wheeling, 984
1
1
4
4
5
Upper Scioto, 959
5
13
13
23
Walhonding, 906
1
11
26
69
69
101
Wills, 1009
2
3
12
12
14
Table 4. Ohio public water supplies by county at several intervals from Class II Injection wells
County
Well Distance (Miles)
0.5
<1
<2
<3
<4
<5
Ashtabula
4
9
16
19
22
Athens
1
2
2
3
Auglaize
3
5
5
7
Belmont
1
4
5
6
Carroll
2
9
20
Columbiana
1
2
6
13
20
32
Coshocton
7
8
10
13
Crawford
1
Cuyahoga
1
Delaware
1
Fairfield
4
Franklin
1
3
7
Fulton
2
4
8
Gallia
1
Geauga
8
19
33
60
71
Guernsey
2
4
10
11
11
Harrison
1
1
Henry
2
3
3
Henry
2
3
Hocking
3
10
11
13
Holmes
1
11
34
25
38
47
Jefferson
1
3
3
5
Knox
2
6
8
9
Lake
1
4
7
17
18
Licking
1
2
10
14
26
Lorain
1
4
Mahoning
3
4
13
25
37
48
Medina
1
1
1
2
5
Meigs
4
5
6
7
Morgan
1
1
1
6
17
Morrow
3
8
11
11
Muskingum
3
8
15
Noble
1
2
2
3
Perry
5
6
8
Pickaway
2
3
7
10
Portage
3
12
41
62
90
113
Seneca
1
12
17
21
Stark
1
4
20
52
121
161
Summit
2
12
26
51
Trumbull
3
7
24
32
45
61
Tuscarawas
6
10
22
24
26
Washington
1
2
4
9
Wayne
1
1
9
18
24
54
Wyandot
2
2
2
3
Public Water and Hydraulically Fractured Wells
Table 5. The number of Ohio public water supplies and population served at several intervals from hydraulically fractured Utica Wells
Well Distance (Miles)
#
Total Population
Ave Served Per Well
Max People Per Well
0.5
18
2,010
112 (±72)
31
<1
64
17,879
279 (±456)
2,598
<2
235
116,682
497 (±1,237)
8,728
<3
433
257,292
594 (±2,086)
29,787
<4
572
380,939
666 (±2,404)
29,787
<5
699
496,740
711 (±2,862)
47,348
Table 6. Ohio public water supplies by system type, source, and ownership at several intervals from hydraulically fractured Utica Wells
Well Distance (Miles)
System Type†
Source††
Ownership
NTNC
TNC
C
G
GP
S
SP
Private
Local
Fed
State
0.5
1
16
1
17
1
18
<1
9
45
10
59
3
1
1
58
6
<2
50
137
48
216
6
3
10
206
29
<3
83
265
85
400
14
5
14
381
51
1
<4
109
352
111
534
16
7
15
504
67
1
<5
141
421
137
652
19
9
18
621
77
1
† NTNC = Non-Transient Non-Community; TNC = Transient Non-Community; C = Community
†† G = Groundwater; GP = Purchased Groundwater; S = Surface Water; SP = Purchased Surface Water
Table 7. Ohio public water supplies by hydrologic unit code (HUC) at several intervals from hydraulically fractured Utica wells
HUC Name
Well Distance (Miles)
0.5
<1
<2
<3
<4
<5
Black-Rocky, 859
1
4
4
4
Cuyahoga, 832
2
12
31
54
82
Grand, 811
1
15
18
23
Licking, 1010
2
2
3
3
Little Muskingum-Middle Island, 1062
2
5
10
11
11
Mahoning, 831
2
5
48
105
142
175
Muskingum, 1006
3
7
9
11
Shenango, 815
2
5
10
13
14
Tuscarawas, 889
8
28
87
140
178
220
Upper Ohio, 901
7
20
45
66
72
73
Upper Ohio-Wheeling, 984
1
13
23
27
28
Walhonding, 906
10
15
34
47
Wills, 1009
2
3
5
7
8
Table 8. Ohio public water supplies by county at several intervals from hydraulically fractured Utica wells
County
Well Distance (Miles)
0.5
<1
<2
<3
<4
<5
Ashtabula
1
1
Belmont
1
2
7
14
15
16
Carroll
6
20
36
43
43
43
Columbiana
4
15
45
72
80
81
Coshocton
7
10
10
Geauga
14
20
25
Guernsey
1
1
2
4
5
Harrison
2
6
16
16
16
16
Holmes
5
13
31
43
Jefferson
2
3
11
22
25
25
Knox
1
1
2
2
Licking
1
1
1
1
Mahoning
2
10
32
44
55
Medina
1
4
5
7
Monroe
2
4
6
6
6
Muskingum
1
1
1
2
3
Noble
2
2
2
2
Portage
2
8
25
49
84
Stark
2
5
40
85
110
122
Summit
6
10
Trumbull
3
23
36
53
65
Tuscarawas
1
2
15
22
28
43
Washington
3
10
12
13
Wayne
5
5
7
21
Footnote
Community (C) = serve at least 15 service connections used by year-round residents or regularly serve at least 25 year-round residents. Examples include cities, mobile home parks and nursing homes; Non-Transient, Non-Community (NTNC) = serve at least 25 of the same persons over six months per year. Examples include schools, hospitals and factories.
By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2016/07/ClassIIOhio-Feature.jpg400900Ted Auch, PhDhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngTed Auch, PhD2017-03-02 16:46:592021-04-15 15:03:40Ohio Shale Activity, Waste Disposal, and Public Water Supplies
In March 2015, the National Fuel Gas Supply Corporation and Empire Pipeline Company filed a joint application with the Federal Energy Resource Commission (FERC) to construct a new natural gas pipeline and related infrastructure, known collectively as the Northern Access Project (NAPL). The pricetag on the project is $455 million, and is funded through international, as well as local, financial institutions. The Public Accountability Initiative recently produced a report detailing the funding for this pipeline project, entitled “The Power Behind the Pipeline“.
The proposed Northern Access Project consists of a 97-mile-long, 24” pipe that would carry Marcellus Shale gas from Sergeant Township (McKean County), PA, to the Porterville Compressor Station in the Town of Elma (Erie County), NY. Nearly 69% of the proposed main pipeline will be co-located in existing pipeline and power line rights-of-way, according to FERC. The agency says this will streamline the project and reduce the need to rely on eminent domain to most efficiently route the project.
A $42 million, 15,400 horsepower Hinsdale Compressor Station along the proposed pipeline route was completed in 2015. In addition to the pipeline itself, the proposed project includes:
Additional 5,350 HP compression at the existing Porterville Compressor Station, a ten-fold increase of the capacity of that station
A new 22,214 HP compressor station in Pendleton (Niagara County), NY
Two miles of pipeline in Pendleton (Niagara County), NY
A new natural gas dehydration facility in Wheatfield (Niagara County), NY
An interconnection with the Tennessee Gas Pipeline in Wales (Erie County), NY, as well as tie-ins in McKean, Allegany, and Cattaraugus counties
A metering, regulation and delivery station in Erie County
Mainline block valves in McKean, Allegany, Cattaraugus and Erie counties; and
Access roads and contractor/staging yards in McKean, Allegany, Cattaraugus and Erie counties
The above map shows the proposed pipeline (green) and related infrastructure (bright pink). The pale yellow and pink lines on the map are the existing pipelines that the Northern Access Project would tie into. Click here to explore the map fullscreen.
Project Purpose
National Fuel maintains that the goal of the proposed project would be to supply multiple markets in Western New York State and the Midwest. The project would also supply gas for export to Canada via the Empire Pipeline system, and New York and New England through the Tennessee Gas Pipeline 200 Line. The company anticipates that the project would be completed by late 2017 or early 2018. Proponents are hoping that NAPL will keep fuel prices low, raise tax revenues, and create jobs.
Push-back against this project has been widespread from citizens and environmental groups, including Sierra Club and RiverKeeper. This is despite an environmental assessment ruling in July 2016 that FERC saw no negative environmental impacts of the project. FERC granted a stamp of approval for the project on February 4, 2017.
Concerns about the Proposed Pipeline
The Bufffalo-Niagara Riverkeeper, asserts that the project presents multiple threats to environmental health of the Upper Lake Erie and Niagara River Watersheds. In their letter to FERC, they disagreed with the Commission’s negative declaration that the project would result in “no significant impact to the environment.” The pipeline construction will require crossings of 77 intermittent and 60 perennial streams, 19 of which are classified by the New York State Department of Environmental Conservation (NYS DEC) as protected trout streams. Twenty-eight of the intermittent streams impacted also flow into these protected streams. Resulting water quality deterioration associated with bank destabilization, increased turbidity, erosion, thermal destabilization of streams, and habitat loss is likely to impact sensitive native brook trout and salamanders. Riverkeeper found that National Fuel’s plan on how to minimize impacts to hundreds of wetlands surround the project area was insufficient. FERC’s Environmental Assessment of the project indicated that approximately 1,800 acres of vegetation would affected by the project.
Several groups have also taken issue with the proposed project’s plan to use the “dry crossing” method of traversing waterways. Only three crossings will be accomplished using horizontal directional drilling under the stream bed — a method that would largely protect the pipes from dynamic movement of the stream during floods. The rest will be “trenched” less than 5 feet below the stream bed. Opponents of the project point out that NYSDEC, federal guidelines, and even industry itself discourage pipe trenching, because during times of high stream flow, stream scour may expose the pipes to rocks, trees, and other objects. This may lead to the pipes leaking, or even rupturing, impacting both the natural environment, and, potentially, the drinking water supply.
A December 2016 editorial to The Buffalo News addressed the impacts that the proposed Northern Access Project could have to the Cattaraugus Creek Basin Aquifer, the sole source of drinking water for 20,000 residents in surrounding Cattaraugus, Erie, and Wyoming counties in New York. In particular, because the aquifer is shallow, and even at the surface in some locations, it is particularly vulnerable to contamination. The editorial took issue with the absence of measures in the Environmental Assessment that could have explored how to protect the aquifer.
Other concerns include light and noise pollution, in addition to well-documented impacts on climate change, created by fugitive methane leakage from pipelines and compressors.
NYSDEC has held three public hearings about the project already: February 7th at Saint Bonaventure University (Allegany, NY), February 8th at Iroquois High School (Elma, NY), February 9th at Niagara County Community College (Sanborn, NY). The hearing at Saint Bonaventure was attended by nearly 250 people.
While FERC approved the project on February 4, 2017, the project still requires approvals from NYSDEC – including a Section 401 Water Quality Certification. These decisions have recently been pushed back from March 1 to April 7.
Proponents for the project – particularly the pipefitting industry – have emphasized that it would create up to 1,700 jobs during the construction period, and suggested that because of the experience level of the construction workforce, there would be no negative impacts on the streams. Other speakers emphasized National Fuel’s commitment to safety and environmental compliance.
Seneca Nation President Todd Gates expressed his concerns about the gas pipeline’s impacts on Cattaraugus Creek, which flows through Seneca Nation land (Cattaraugus Indian Reservation), and is downstream from several tributaries traversed by the proposed pipeline. In addition, closer to the southern border of New York State, the proposed pipeline cuts across tributaries to the Allegheny River, which flows through the Allegany Indian Reservation. One of New York State’s primary aquifers lies beneath the reservation. The closest that the proposed pipeline itself would pass about 12 miles from Seneca Nation Territory, so National Fuel was not required contact the residents there.
Concerns about Wheatfield dehydration facility & Pendleton compressor station
According to The Buffalo News, National Fuel has purchased 20 acres of land from the Tonawanda Sportsmen’s Club. The company is building two compressors on this property, totaling 22,000 HP, to move gas through two miles of pipeline that are also part of the proposed project, but 23 miles north of the primary stretch of newly constructed pipeline. Less than six miles east of the Pendleton compressor stations, a dehydration facility is also proposed. The purpose of this facility is to remove water vapor from the natural gas, in accordance with Canadian low-moisture standards. According to some reports from a National Fuel representative, the dehydration facility would run only a few days a year, but this claim, has not been officially confirmed.
Residents of both Pendleton and Wheatfield have rallied to express their concerns about both components of the project, citing potential impacts on public health, safety, and the environment relating to air and water quality.
Northern Access Project Next Steps
The deadline for public comment submission is 5 pm on February 24, 2017 — less than two weeks away. To file a comment, you can either email NYS DEC directly To Michael Higgins at NFGNA2016Project@dec.ny.gov, or send comments by mail to NYS DEC, Attn. Michael Higgins, Project Manager, 625 Broadway, 4th Floor, Albany, NY 12233.
Note: this article originally stated that the Porterville Compressor Station would double its capacity as a result of the NAPL project. In fact, the capacity increase would be ten-fold, from 600 hp to about 6000 hp. We regret this error.
by Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance
Just how close are public water supplies to Class II waste disposal wells and permitted Utica wells? As of January 15, 2017, there are 13 PWS’s within a half-mile of Ohio’s Class II SWD wells, and 18 within a half-mile of permitted Utica wells. These facilities serve approximately 2,000 Ohioans each, with an average of 112-153 people per PWS (Tables 1 and 5). Within one mile from these wells there are 64 to 66 PWSs serving 18 to 61 thousand Ohioans. That’s an average of 285-925 residents.
