JOSHUA DOUBEK / WIKIMEDIA COMMONS
Kyle Ferrar, MPH

Groundwater risks in Colorado due to Safe Drinking Water Act exemptions

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

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

Learn more about Class II injection wells.

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

What exactly are aquifer exemptions?

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

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

Research shows injection wells do fail

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

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

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

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

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

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

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

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

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

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

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

Will existing Class II wells fail?

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

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

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

Aquifer Exemptions in Colorado

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

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

Map 1. Aquifer exemptions in Colorado


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

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

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

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

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

Groundwater Monitoring Data Maps

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

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

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

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

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

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

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

Site Assessments – Exploring Specific Regions

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

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

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

Methods

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

Case of Increasing TDS Readings

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

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

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

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

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

Groundwater Contamination Case in 2007

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

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

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

 

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

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

Areas where lack of data restricted analyses

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

Southeastern Colorado

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

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

Western Colorado

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

Northwestern Colorado

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

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

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

Trends and Future Development

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

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

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

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

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

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

Feature Image: Joshua Doubek / WIKIMEDIA COMMONS

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

 

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

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

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

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

Liquid Waste Disposal

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

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

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

Aquifer Exemption Criteria

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

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

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

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

The Lay of the Land

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

Map of all aquifer exemptions in the U.S.

View map fullscreen | How FracTracker maps work

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

Brine or water roadspreading in WV
Matt Kelso, BA

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

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air quality impact, which is why roadspreading of brine occurs

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

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

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

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

PA Oil and Gas Liquid Waste Road Applications


View map fullscreen | How FracTracker maps work

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

What’s in the brine?

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

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

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

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

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

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

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

What to do?

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

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

Water supplies article
FracTracker Alliance

Risks to Water Supplies in PA’s Susquehanna Basin

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In this series of articles on the Susquehanna River Basin, FracTracker has explored the relationship between oil and gas extraction and the overall health of the watershed relative to oil and gas extraction impacts. We began with a basic overview of likely relationships, followed by an analysis of oil and gas violations relative to resources available for monitoring water quality changes. In the most recent article we assessed the corresponding effects of extraction on deforestation and habitat loss. With the rapid expansion of oil and gas drilling over the past decade, many have also formed legitimate concerns about threats to public and private water supplies. In the final article of the series we look closely at this issue, at the complexities of assessing risks to water supplies, while also highlighting recent research shedding new light on the nature of these risks.

Pennsylvania’s Hydrological System

The Susquehanna River is home to more than 3.3 million people who depend on the river and its tributaries for drinking water. The basin also feeds thousands of businesses that require water for their operations, such as manufacturing facilities, farms, golf courses, and more. In some instances, water supplies are fed by groundwater wells, which are in turn fed by underground aquifers of different depths. In other cases, water supplies are drawn from intake points in nearby lakes, rivers, and streams.

Map of PA's groundwater aquifer system.

Figure 1: Map of PA’s groundwater aquifer system.

While many believe underground and surface water systems are somehow discrete, this is far from the case. Groundwater is a major contributor to rivers, lakes, and wetlands – as they are all connected through the hydrological cycle. Some precipitation runs directly into streams. But much of it filters through soil and rock into shallow and deep aquifers. Aquifers then carry water over the course of months, years, and even centuries, into larger water bodies. The most common discharge points are from springs and from low-lying wetlands. The figures above (figure 1) and below (figure 2) illustrate Pennsylvania’s four major aquifer types, compiled by Penn State Extension.

Figure 3: Types of groundwater aquifers in PA.

Figure 2: Types of groundwater aquifers in PA.

Assessing Groundwater Supply Risks

Managing the overall health of the hydrological cycle is of critical importance to the 3.3 million people who live in the Susquehanna River Basin. However, oil and gas extraction poses significant risks to the state’s water sources. As we have detailed in prior articles in this series, accidents and spills can cause chemicals and hydraulic fracturing fluids to run off into nearby watersheds. Growing evidence also suggests that groundwater can be contaminated by migrating hydraulic fracturing fluids.

Figure 4: Number of household and public water supply groundwater wells by state (DCNR).

Figure 3: Number of household and public water supply groundwater wells by state (DCNR).

In one study, conducted by Columbia University in 2016, researchers found elevated levels of dissolved calcium, chlorine, sulfates and iron in lowland drinking wells within one kilometer of a drilling site compared to baseline averages. In lowland wells more than a kilometer away, they found elevated levels of methane, sodium, and manganese. Elevated levels dropped off in wells on higher ground, which suggests the hydraulic fracturing process affects shallow and deep groundwater sources along different timelines.

According to the PA Department of Conservation and Natural Resources (DCNR), Pennsylvania ranks second in the nation for total number of groundwater wells, second for number of private drinking wells, and third for number of public water supplies dependent on groundwater wells (figure 4). However, determining how many groundwater wells may be at risk to oil and gas extraction is complicated for a variety of reasons. First, DCNR acknowledges that only about half (480,000) of the 1 million groundwater wells in the state are documented. Registration of groundwater wells only began in 1955, and detailed information including latitude and longitudinal coordinates only came into being in the 1980s. These records are now maintained in the PA Groundwater Inventory System (PAGWIS). It is worth noting that the PA Department of Environmental Protection (DEP) does not regulate private drinking water wells. They are only required to respond to pollution complaints.

Correlating O&G Wells to Complaints Data

Despite these data gaps, we can still learn a lot from the wells that are documented in PAGWIS. For instance, we compared the location of groundwater wells to oil and gas related complaints and found some interesting correlations. The below map can be used to explore these relationships.

Map of at-risk groundwater wells, public water supplies, and citizen complaints


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The first stage our analysis involved narrowing the PGWIS registered groundwater wells in the Susquehanna Basin to those that are actively used for drinking water, agriculture, and irrigation (66,306 total). We then limited to those within 1 kilometer of an oil and gas well, essentially mirroring the distances used by the Columbia University study. We found 2,551 groundwater wells within this “risk zone” of 1 kilometer.

For our second stage, we utilized research conducted by Public Herald, an investigative reporting team that spent three years reviewing oil and gas related complaints submitted to the DEP from 2004-2016. They found 9,442 total complaints, of which 43% were water related (surface and groundwater), and that the frequency of complaints track with the rise and fall of unconventional oil and gas development (figure 5).

Figure 5: Relationship of complaints to O&G development (Public Herald).

Figure 4: Relationship of complaints to O&G development (Public Herald).

From the Public Herald dataset, we found 1,573 total complaints were in the Susquehanna River Basin, of which 65% were water related complaints — a much higher percentage than the larger dataset’s average. We then compare the location of these complaints to our “risk zone” groundwater wells and found a statistically significant correlation between the number of groundwater wells within 1km of oil and gas activity and higher numbers of complaints by residents. What do these findings tell us?

In short, where we see more groundwater wells in proximity to an oil and gas well, we also see more water related complaints to the DEP.

The below graph illustrates this relationship (figure 6).

Figure 6: Relationship of complaints to at-risk groundwater wells.

Figure 5: Relationship of complaints to at-risk groundwater wells.

Groundwater to Surface Water Risks

DCNR estimates that Pennsylvania’s streams and wetlands get about 2/3 of their flow from groundwater sources. Meanwhile, there are 786 public water suppliers in the Susquehanna River Basin that are fed by different arrangements of groundwater and surface water sources. These suppliers are included in the interactive map for reference.

Assessing risks to public water supply systems is equally complicated to that of groundwater wells. The DEP regulates public water suppliers under the Safe Drinking Water Act, but the general public is not permitted to know the location of actual water sources or intake points due to security risks. This restriction poses a problem for nongovernmental organizations when doing analyses that would benefit from knowing the locations of these source points. Nevertheless, like our breakdown of risk zone groundwater wells, we can still learn a great deal from what we do know of public water supplies.

Figure 6: Wellsboro, PA, public water supply along with O&G wells and water-related citizen complaints in the supply watershed.

Figure 6: Wellsboro, PA, public water supply with O&G wells and citizen complaints in the supply’s watershed.

For instance, the town of Wellsboro, in Tioga County, is home to an estimated 3,300 people. The Wellsboro Municipal Authority supplies water to Wellsboro residents as well as to 1,000 people in surrounding Charleston and Delmar Townships. According to DEP records, groundwater and surface water sources for this system come from Hamilton Lake and tributaries of the Charleston Creek Watershed, much of which is designated as high-quality coldwater fisheries. Nevertheless, there are seven unconventional oil and gas wells in this watershed, one of which is only 400ft from Charleston Creek, just upstream from Hamilton Lake.

The area is also one of the brightest hot-spots for complaints to the DEP in the Public Herald dataset, with 40 water related complaints in Charleston and Delmar townships.

These relationships should be of particular concern to residents who believe their water is protected from extraction industry activities. In addition, while recent research suggests homes values can be negatively affected in neighborhoods dependent on private well water near drilling activity, correlations between potential groundwater and surface water pollution suggest that any changes in home value are more a matter of perceived rather than actual risk—homes on public water supplies should also be considered at risk in communities experiencing extraction.

Conclusion

Returning to the hydrological cycle, we can assume that pollutants from oil and gas extraction, like precipitation, will eventually find their way into larger water bodies, either directly through runoff into watershed tributaries or through groundwater migrations. While this article has primarily focused on the Pennsylvania headwaters of the Susquehanna, home to 570,000 residents, and risks to their water sources, groundwater complaints are not the exclusive problem of residents who are dependent on private drinking water wells. “We all live downstream” as the saying goes, and those who rely on the watershed for their drinking water and other water resource needs throughout the watershed should be concerned by the correlations illustrated in our analysis.

By Kirk Jalbert, Manager of Community based Research & Engagement, FracTracker Alliance

Feature image: Hydrologic cycle graphic by Watershed-Watch.org

Wayne National Forest map and drilling
Guest Author

Wayne National Forest Could Be Deforested – Again

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Guest article by Becca Pollard

Eighty years ago, Southeastern Ohio was a wasteland of barren, eroding hills. During the 18th and 19th centuries this once heavily forested area in the Appalachian foothills had been clear cut and mined beyond recognition. When the Great Depression struck, lowering crop prices made farming unprofitable in the area, and 40% of the population moved away.

In 1933, President Franklin Delano Roosevelt established the Civilian Conservation Corps (CCC), a public work relief program that employed men aged 18-25 to do manual labor related to conservation and development of natural resources such as planting trees, constructing trails, roads, and lodges, fighting wildfires, and controlling erosion. The following year, Ohio’s legislature agreed to allow the federal government to purchase land in the state for the purpose of establishing a national forest. The Forest Service was tasked with restoring the land for what is now called Wayne National Forest (WNF). A tree nursery was established near Chillicothe, and with the help of the CCC and volunteers, including members of the Daughters of the American Revolution, garden clubs, and school children, reforestation began.

Photos Credit: US Forest Service

An Area on the Mend

Today, WNF comprises three units that span 12 Ohio counties in the Unglaciated Allegheny Plateau. The hills are covered in biologically diverse mixed mesophytic forest, which includes approximately 120 species of trees and provides habitat for at least 45 species of mammals, 158 species of birds, 28 species of reptiles, 29 species of amphibians, and 87 species of fish. The US Forest Service estimates that 240,000 people visit this ecological wonder annually, according to Forest Recreation Program Manager, Chad Wilberger, in Nelsonville, Ohio. The restoration of barren public land to its current state is a great achievement. If it continues to be protected, Wayne could one day resemble the old growth forest that thrived here before the arrival of European settlers.

The Bureau of Land Management (BLM), however, has recently decided to lease up to 40,000 acres of Wayne to gas and oil companies for horizontal hydraulic fracturing, or fracking. The first auction took place last December resulting in the lease of 700 acres. A second auction this March leased another 1,200 acres. Nearly all of this land lies within the 60,000 acre Marietta Unit of the forest. This brings Oil & Gas Expressions of Interest (EOI) acreage to roughly 7.5% of all WNF owned parcels in this unit.

Wayne National Forest and Adjacent Existing Oil and Gas Infrastructure
Below is a map of the Wayne National Forest, along with parcels owned by WNF (shown in gray) and those that might be subject to unconventional oil and gas development (gray parcels outlined with dashes). We also include existing unconventional oil and gas infrastructure near the park. Explore the map below, or click here to view the map fullscreen.


View map fullscreen | How FracTracker maps work

Not new, not old

Gas and oil development is not new to the Wayne. Since the passage of The Federal Land Policy and Management Act of 1976, the US Forest Service’s land management plan for WNF has included conventional drilling, and derricks are a common sight on both public and private land in southeastern Ohio.

Fracking (unconventional drilling), however, has a far greater impact, requiring clear cutting of large areas of land for the construction of concrete well pads, and the use of millions of gallons of water that will become contaminated during the process and then transported by truck to injection wells. Accidents can be catastrophic for workers and nearby residents, and fracking and waste water disposal have been linked to earthquakes in Ohio.

In 2012, BLM updated its WNF Land and Resource Management Plan to allow fracking in the forest without conducting new impact studies.

What is at risk?

The Marietta Unit of the WNF is located in Monroe, Perry, and Washington counties in Southeastern Ohio along the Ohio River. Within its boundary are a wealth of trails used for hiking, backpacking, horseback riding, and mountain biking, campgrounds, and waterways ideal for kayaking and fishing. Both the highest and lowest points in the Wayne lie in this unit, as does the Irish Run Natural Bridge. The area is also known for its exceptional wildflowers, as shown in the photos below.

Woodland Stonecrop (Sedum ternatum) in Wayne National Forest

One popular recreation area, Lamping Homestead, lies directly within an oil and gas Expression Of Interest (EOI) parcel #3040602400 (See Map Above), one of the areas under consideration for lease. In the 1800s, it was the site of the Lamping family’s farm, but today all that remains of the settlers is a small cemetery with an iron gate atop a hill overlooking a small lake. Six campsites are situated around the western side of the lake, and two intersecting hiking loops rise into the wooded hills to the east. On the western side of the parking lot is a covered picnic area. A creek flows out of the lake and into Clear Fork, a tributary of the Little Muskingum River, across the road from the parking lot.

Both the lake and stream are popular boating and fishing areas. Lamping is an excellent spot for wildlife viewing. The lake, the creeks that flow in and out of it, and the surrounding wooded hills support an impressive variety of plant and animal species. During the day, visitors might spot ducks, geese, great blue herons, red-winged blackbirds, summer tanagers, red spotted newts, box turtles, northern water snakes, garter snakes, deer, rabbits, and muskrats. At night, they could be greeted by a cacophony of voices from frogs, owls, and coyotes.

Species of trees, plants, and fungus are also numerous. In winter, stands of white pine pop out against the bare branches of oak, hickory, maple, buckeye, and other deciduous trees. In spring, eye-catching splotches of blooming dogwood and redbud contrast against the many shades of green. But hikers who pull their gaze away from the brightly colored canopy and look down are rewarded with an abundance of wildflowers and the butterflies they attract, as well as many varieties of mushrooms and fungus, including such edible varieties as morels, wood ear, and dryad’s saddle.

Estimating Disturbances

It is unclear how much surface disturbance would occur on public land if this parcel were to be fracked, but even if the well pad and pipelines were constructed on private land adjacent to the forest, in order to drill under the forest, the public land and its inhabitants and visitors would certainly be impacted.

There is no question that noise and air pollution from traffic and construction would be disruptive both to wildlife and to human visitors. Explore various photos of the oil and gas industry in the gallery below:

Active Fracking Operation in Belmont County, Ohio

The extraction process requires 2 million to 6 million gallons of fresh water each time a well is fracked. The rate at which hydraulic fracturing’s water demand is increasing on a per-well basis here in Ohio reached an exponential state around Q4-2013 and Q1-2014 and continues to rise at a rate of 3.1 million gallons per well per year (Figure 1).

Ohio Hydraulic Fracturing Total and Per Well Freshwater Demand between Q3-2010 and Q3-2016.

Ohio Hydraulic Fracturing Total and Per Well Freshwater Demand between Q3-2010 and Q3-2016.

In Ohio, oil and gas companies are allowed to pull this water directly from streams and rivers at no cost. All this is possible, despite the fact that after its use it is so contaminated that it must be disposed of via injection wells and is permanently removed from the water cycle. The industry is already pulling water from streams in the Marietta Unit of the WNF for use in fracking on private land. Fracking public land simply means water withdrawals will occur on a much larger scale.

Ohio and West Virginia Shale Water Demand and Injection Waste Disposal
This map shows Utica wells weighted by water demand and disposal (and/or production). It also depicts water, sand, and chemical usage as well as injection waste and oil production. Explore the map below, or click here to view map fullscreen.


View map fullscreen | How FracTracker maps work

Inevitable methane leaks, in addition to contributing to climate change, affect humans and wildlife in their immediate vicinity, causing headaches and nausea and even killing trees and plants.

In addition to the anticipated harm that fracking inflicts upon a natural area, there is also a risk of accidents with potentially devastating consequences. Residents of Monroe County have already seen a few in recent years from fracking on private land. In 2014, a well pad fire in the village of Clarington resulted in a chemical spill that contaminated nearby Opossum Creek, killing 70,000 fish. The same year a large gas leak 15 miles south in the village of Sardis resulted in the evacuation of all homes within half mile radius.

Recent studies have shown that extraction wells, in addition to injection wells, can cause earthquakes. Unsurprisingly, Monroe County has seen a spike in seismic activity with the increase in fracking activity in the area. The most recent incident was a 3.0 magnitude earthquake in the forest less than five miles from Lamping Homestead in April of this year.

Supporters of Wayne National Forest

Many people have repeatedly spoken out against BLM’s plan, submitting a petition with more than 100,000 signatures, and protesting outside Wayne National Forest Headquarters and Athens Ranger Station in Nelsonville. They have even organized voters to call and write letters to Regional Forester Kathleen Atkinson and legislators, including Senators Sherrod Brown and Rob Portman, and Governor John Kasich. BLM has not budged on its decision, unfortunately, insisting that leasing this land for fracking, and associated infrastructure buildout, will have “no significant impact.”

This May, the Center for Biological Diversity, Ohio Environmental Council, Ohio Sierra Club, and Heartwood, a regional organization focused on protecting forests, filed a lawsuit against BLM, aiming to void BLM leases and halt all fracking operations within the national forest.

Concerned citizens continue to organize raise awareness as they await the outcome of the suit.

Becca Pollard is Freelance Journalist and Co-founder of Keep Wayne Wild

Data Downloads

Click on the links below to download the data used to create this article’s maps:

Ethanol and fracking
Ted Auch, PhD

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

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Corn Ethanol and Fracking – Similarities Abound

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

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

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

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

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

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


View map fullscreen | How FracTracker maps work

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

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

Ethanol’s Recent History

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

Benefits of Biofuels

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

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

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

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

Costs of Biofuels

Direct Costs

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Midwest/Great Plains US Ethanol Refineries and Crop Residue Production

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

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

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

Indirect Costs: Fertilizer and Herbicide Costs and Leaching

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

What’s Next?

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Ethanol Tables

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

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

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

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

References and Footnotes

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

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

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

Data Downloads

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

  1. Detailed US Ethanol water, land, chemical fertilizer, and herbicide demand
  2. Estimates of North American Ethanol Refinery’s water and land-use demand
Susquehanna River Basin map article #2
Matt Kelso, BA

Violations and Monitoring in Pennsylvania’s Susquehanna River Basin

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The Susquehanna River is a 444-mile long waterway extending from the area around Cooperstown, New York to the Chesapeake Bay. In Pennsylvania, the basin includes more than 37,000 miles of streams that feed into the river, which capture the precipitation of more than 20,000 square miles of land, and is home to over 3.3 million people.

The region has been heavily impacted by oil and natural gas extraction in recent years; more than 5,500 unconventional wells and roughly 13,500 conventional wells have been drilled in the PA segment of the basin since 2000. Unconventional wells, in particular, have brought industrial-scaled activity, pollution, and waste products to a wide area of the basin, with especially heavy development occurring in three counties along Pennsylvania’s northern tier – Bradford, Susquehanna, and Tioga.

Several governmental agencies are involved with monitoring impacts to this massive watershed. This article focuses on the Pennsylvania portion of the basin, and examines how capable agency-run monitoring efforts are in capturing oil and gas (O&G) related pollution events. The Pennsylvania Department of Environmental Protection (DEP), the US Geological Survey (USGS), and the Susquehanna River Basin Commission (SRBC) maintain a combined network of 274 monthly “grab sample” monitoring sites and 58 continuous data loggers in the Pennsylvania portion of the river basin. Meanwhile, between January 1, 2000 and February 7, 2017, the DEP logged 6,522 on the O&G violations compliance report within the same region. More than three out of every four of these violations have been assessed to unconventional wells, even though only one out of every four active wells in the basin is categorized as such.

Map of O&G Monitoring & Violations in PA’s Susquehanna River Basin


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Limitations of Monitoring Efforts

Grab samples obtained from official monitoring locations are the preferred method for regulatory purposes in understanding the long-term health of the river system. Researchers can test for any number of analytes from samples that are collected in-stream, but analyzed in certified laboratories. However, samples from these locations are collected periodically – usually once per month – and therefore are very likely to miss the effects of a significant spill or issue that may impact surface water chemistry for a number of hours or days before being diluted and washing downstream.

Continuous data loggers give regulators a near real-time assessment of what is happening in selected points in the basin, usually at 15-minute intervals. While there are numerous events that contribute to fluctuations in these measurements, these data loggers would be the most likely instruments available to register an event impacting the surface water within the basin. However, there are unique issues with data loggers. For instance, available data from these data loggers are much more limited in scope, as temperature, pH, and conductivity are typically the only available analytes. In addition, because the analysis occurs on site, the results carry less weight than laboratory results would. Finally, even though data loggers collect data at rapid intervals, only some are equipped to send data real-time to agency offices. Some data loggers must be manually collected on a periodic basis by program managers.

Perhaps the greatest challenge for monitoring in the Susquehanna River Basin is that it is simply not practical to monitor in all places likely to be impacted by oil and gas operations. Testing within the jurisdiction of the Susquehanna River Basin is actually fairly extensive when compared to other regions, such as the Ohio River Basin. The Ohio River Valley Water Sanitation Commission – the equivalent of the SRBC for the Ohio River Basin – only monitors basic analytes like total dissolved solids at 29 locations, all at or near the main stem of the river. However, none of the agencies monitoring water quality in the Susquehanna River Basin have capacity to test everywhere. On average, there is one testing location for every 111 miles of rivers and streams within the basin.

Case Studies

If agency-based monitoring is so limited, then the important question is: How well do these efforts capture oil and gas-related impacts? Some violations are more likely to impact surface water quality than others. This article takes a closer look at some of the bigger problem areas within the basin, including the Dimock region in Susquehanna County, Leroy Township in Bradford County, and Bell Township in Clearfield County.

Dimock

Map of O&G violations and water monitoring near Dimock, PA

O&G violations and water monitoring near Dimock, PA. Note that multiple violations can occur at the same location. Click to expand map.

The highest concentration of oil and gas violations in the Susquehanna Basin is located in the townships of Dimock and Springville, in Susquehanna County, PA, with a total of 591 incidents reported on the compliance report. This makes the region the highest concentration of O&G violations in the entire state. Many of these violations are related to the systemic failure of well integrity, resulting in the contamination of numerous groundwater supplies. In terms of how these might affect surface water, 443 of the violations are in areas that drain into the Thomas Creek-Meshoppen Creek subwatershed by the southern edge of Springville Township, while most of the rest of the violations drain into the parallel West Branch of Meshoppen Creek.

The USGS operates a monthly monitoring location in the middle of the cluster of violations, at the confluence of Burdick and Meshoppen creeks, just north of the Dimock’s southern border. While this location might seem ideal at first, only 180 of the 443 violations in the subwatershed are upstream of the grab sample site. There is another water monitoring location that captures all of these violations in the Meshoppen subwatershed, but it is more than 15 miles downstream. (link to EJ article about Dimock)

Leroy Township

Map of O&G Violations and monitoring near Leroy Township, PA

O&G Violations and monitoring near Leroy Township, PA. Click to expand map.

Compared to the huge amount of oil and gas violations throughout the Dimock area, Leroy Township in Bradford County looks relatively quiet. It also appears to be well covered by monitoring locations, including a data logger site near the western edge of the township, a centrally located monthly monitoring location, as well as another monthly grab sample site upstream on Towanda Creek, just beyond the eastern boundary in Franklin Township.

And yet, this area was hit hard in the early part of the decade by two significant spills. On April 19, 2011, Chesapeake Appalachia lost control of the Atlas 2H well, with thousands of gallons of flowback fluid spilling onto the countryside and into the nearby Towanda Creek.

A little over a year later on July 4, 2012, a second major spill in the township saw 4,700 gallons of hydrochloric acid hit the ground. According to the DEP compliance report, this did not make it into the waterways, despite the gas well being located only about 550 feet from Towanda Creek, and less than 300 feet from another unnamed tributary.

Both incidents were within a reasonable distance of downstream monitoring locations. However, as these are grab sample sites that collect data once per month, they can only offer a limited insight into how Towanda Creek and its tributaries were impacted by these notable O&G related spills.

Bell Township

Map of O&G violations and monitoring near Bell Township, PA. Susquehanna River Basin project

O&G violations and monitoring near Bell Township, PA. Click to expand map.

Bell Township is a small community in Clearfield County along the banks of the West Branch Susquehanna River. The northwestern portion of the township ultimately drains to the Ohio River, but all of the violations in Bell Township are within the Susquehanna River Basin.

Two significant incidents occurred in the township in 2016. On February 18, 2016, Alliance Petroleum Corp lost control of the McGee 11 OG Well, located less than 250 feet from Deer Run. According to the oil and gas compliance report, control of the well was regained five days later, after releasing unspecified quantities of gas, produced fluid, and crude oil. On December 5th of the same year, Exco Resources was cited for allowing 30 barrels (1,260 gallons) of produced fluid to spill at the Clyde Muth M-631 Wellpad in Bell Township.

A United States Geological Survey monthly monitoring location along the West Branch Susquehanna in nearby Greenwood Township is upstream, and could capture the effects of spills throughout much of Bell Township. However, the incident at the Clyde Muth well pad occurred in the Curry Run subwatershed, which meets up with the West Branch Susquehanna downstream of the monitoring location, so any pollution events in that area will not be reflected by monitoring efforts.

Conclusions

In the case of Dimock and Springville townships, we see how official water monitoring efforts capture only a fraction of the notorious cluster of wells that have resulted in hundreds of violations over the past decade. There could scarcely be a better candidate for systematic observation, and yet only a single grab sample site covers the immediate vicinity. Leroy Township does not have the same quantity of impacts as Dimock, but it did see one the worst blowouts in the recent history of O&G operations in Pennsylvania. The area is relatively well covered by grab samples sites, but due to the monthly sampling schedule, these locations would still be unlikely to capture significant changes in water quality. In Bell Township, much of the area is upstream of a monthly grab sample site, but the nearest downstream monitoring location to a major spill of produced fluid that occurred here is more than 17 miles away from the incident as the crow flies.

It should be noted that there are a number of industries and activities that contribute to water pollution in Pennsylvania, and as a result, the monitoring efforts are not specifically designed to capture oil and gas impacts. However, the compliance record shows heavy impacts from oil and gas wells in the basin, particularly from modern unconventional wells.

While the network of government-operated manual monitoring locations and data logger sites are fairly extensive in Susquehanna River Basin, these efforts are not sufficient to capture the full extent of oil and gas impacts in the region. Finding evidence of a small to medium sized spill at a site with monthly testing is unlikely, as contaminated water doesn’t stay in place in a dynamic river system. Data loggers also have a limited capacity, but are a useful tool for identifying substantial changes in water chemistry, and could therefore be employed to identify the presence of substantial spills. As such, it might be beneficial for additional data loggers to be distributed throughout the basin, particularly in areas that are heavily affected by the oil and gas industry. Furthermore, given resource gaps and staff cuts within agencies tasked with protecting the river basin, agencies should strongly consider utilizing networks of volunteers to augment their limited monitoring networks.

Project Info

Read more about the Susquehanna River Basin Impacts Project

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

SCOTT STOCKDILL/NORTH DAKOTA DEPARTMENT OF HEALTH VIA AP - for oil spills in North Dakota piece
Kyle Ferrar, MPH

Oil Spills in North Dakota: What does DAPL mean for North Dakota’s future?

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By Kate van Munster, Data & GIS Intern, and
Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

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 …

Pipeline proponents claim that pipelines are the safest method of transporting oil over long distances, whereas transporting oil with trucks has a higher accident and spill rate, and transporting with trains presents a major explosive hazards.

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).

incidentcounts

Figure 1. Impacts of pipeline incidents in the US. Data collected from PHMSA on November 4th, 2016 (data through September 2016). Original Analysis

pipeline incidents causes

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


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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.

Map of Tesoro Spill
Map of Tesoro Spill
http://www.truthdig.com/eartotheground/item/how_much_oil_spilled_on_north_dakota_no_one_knows
http://www.truthdig.com/eartotheground/item/how_much_oil_spilled_on_north_dakota_no_one_knows

This spill in 2013 may never be fully cleaned up. Cleanup attempts have even included burning away the oil where the spill contaminated wetlands.

More recently, a pipeline spilled 176,000 gallons of crude oil into a North Dakota stream about 150 miles away from the DAPL protest camps. Electronic monitoring equipment, which is part of a pipeline’s safety precautions, did not detect the leak. Luckily, a landowner discovered the leak on December 5, 2016 before it got worse, and it was quickly contained. However, the spill migrated nearly 6 miles down the Ash Coulee Creek and fouled a number of private and U.S. Forest lands. It has also been difficult to clean up due to snow and sub-zero temperatures.

Even if a spill isn’t as large, it can still have a major effect. In July 2016, 66,000 gallons of heavy oil, mixed with some natural gas, spilled into the North Saskatchewan River in Canada. North Battleford and the city of Prince Albert had to shut off their drinking water intake from the river and were forced to get water from alternate sources. In September, 2 months later, the affected communities were finally able to draw water from the river again.

Toxicology of Oil

Hydrocarbons and other hazardous chemicals

Crude oil is a mixture of various hydrocarbons. Hydrocarbons are compounds that are made primarily of carbon and hydrogen. The most common forms of hydrocarbons in crude oil are paraffins. Crude oil also contains naphthenes and aromatics such as benzene, and many other less common molecules. Crude oil can also contain naturally occurring radioactive materials and trace metals. Many of these compounds are toxic and carcinogenic.

hydrocarbons

Figure 3. Four common hydrocarbon molecules containing hydrogen (H) and carbon (C). Image from Britannica

Crude oil spills can contaminate surface and groundwater, air, and soil. When a spill is fresh, volatile organic compounds (VOCs), such as benzene, quickly evaporate into the air. Other components of crude oil, such as polycyclic aromatic hydrocarbons (PAHs) can remain in the environment for years and leach into water.

Plants, animals, and people can sustain serious negative physical and biochemical effects when they come in contact with oil spills. People can be exposed to crude oil through skin contact, ingestion, or inhalation. Expsure can irritate the eyes, skin, and respiratory system, and could cause “dizziness, rapid heart rate, headaches, confusion, and anemia.” VOCs can be inhaled and are highly toxic and carcinogenic. PAHs can also be carcinogenic and have been shown to damage fish embryos. When animals are exposed to crude oil, it can damage their liver, blood, and other tissue cells. It can also cause infertility and cancer. Crops exposed to crude oil become less nutritious and are contaminated with carcinogens, radioactive materials, and trace metals. Physically, crude oil can completely cover plants and animals, smothering them and making it hard for animals to stay warm, swim, or fly.

An Analysis of Spills in ND

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


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B. Waterways Where Spills Have Occurred

  • 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.

Map 3. Oil Spills in North Dakota Waterways


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C. Parks & Wildlife Habitat Impacts

1,684 total square miles

Habitat affected

  • National Grasslands – on 1,010 square miles of interconnected areas
  • United States Wildlife Refuges – 84 square miles of interconnected areas
  • North Dakota Wildlife Management Areas – 24 square miles of interconnected areas
  • Critical Habitat for Endangered Species – 566 square miles of interconnected areas

The endangered species most affected by spills in North Dakota is the Piping Plover. Explore Map 4 for more detail.

Map 4. Wildlife Areas Impacted by Oil Spills


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Methods

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.

Oil Spills in North Dakota Analysis References:

Cover Photo: The site of a December 2016 pipeline spill in North Dakota. Credit: Scott Stockdill/North Dakota Department of Health via AP

Koontz Class II Injection Well, Trumbull County, Ohio, (41.22806065, -80.87669281) with 260,278 barrels (10,020,704 gallons) of fracking waste having been processed between Q3-2010 and Q3-2012 (Note: Q1-2016 volumes have yet to be reported!).
Ted Auch, PhD

Ohio Shale Activity, Waste Disposal, and Public Water Supplies

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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

Public water chartJust 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

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).

A Dynamic Model of Water Demand Between 2000 and 2020 within the Muskingum River Watershed, Southeast Ohio, Kurtz, E. 2015

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, Noble County, Ohio, 39.8212, -81.4061

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, Trumbull County, Shenango/Mahoning River, 41.244, -80.641, 3,548,104 Barrels of Waste Disposed Between 2010 and Q3-2016

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

  1. 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

Mariner East Technical Difficulties map
FracTracker Alliance

Remaining Questions on Mariner East Technical Deficiencies

/by

In the summer of 2015, Sunoco Logistics submitted applications to the Pennsylvania Department of Environmental Protection (DEP) to build its massive Mariner East 2 pipeline. The ME 2 pipeline would have the capacity to transport 275,000 barrels a day of propane, ethane, butane, and other hydrocarbons from the shale fields of Western Pennsylvania to the Marcus Hook export terminal, located on the Delaware River.

Sunoco’s applications were to satisfy the state’s Chapter 105 (water obstruction and encroachment) and Chapter 102 (erosion/sediment control and earth disturbance) permitting requirements. The DEP responded to Sunoco’s application, issuing 20 deficiency letters totaling more than 550 pages. Sunoco resubmitted their application in the summer of 2016 and the DEP again rejected many of its plans to disturb streams, ponds, and wetlands. In December, Sunoco resubmitted its revised application for a third time, hoping for final approval.

FracTracker Alliance first wrote about ME 2’s risks to watershed in August 2016, following Sunoco’s second application. Readers who want a general overview of the issues may find that article worth reading. In this new article, we dig deeper into the subject. Along with its December application, Sunoco also supplied the DEP with revised GIS files illustrating ME 2’s new route and documents summarizing its impacts to nearby water bodies. We have created a new map utilizing newly available data and provide contextual analysis valuable in determining how Sunoco responds to the DEP’s review of its prior rejected applications.

Detailed Mapping of Water Body Impacts

At the end of December, the DEP finally released Sunoco’s GIS files detailing water bodies that will be impacted by ME 2, as well as Sunoco’s data tables outlining alternative methods that might mitigate certain impacts. Our map (below) combines these new datasets to show the locations where ME 2’s route has changed since Sunoco’s initial application, presumably in response to the DEP’s technical deficiency letter.

Also on this map are water bodies: 1) implicated in ME 2’s environmental impact assessment, 2) determined by the DEP as likely impacted by construction, and 3) identified by Sunoco as having viable construction alternatives to mitigate impacts.

Mariner East 2 Technical Deficiencies Map


View map fullscreen | How FracTracker maps work

By viewing the map fullscreen and zooming in, one can click on a water feature to reveal its data tables (see below example). These tables contain information on the water body’s flow regime, the extent of permanent and temporary impacts, alternative crossing methods that could be used, and what benefits might come from those alternate methods. Also in the tables are a number of designations such as:

  • USGS Fish and Wildlife wetland classification (see guide). Most common are PEM (palustrine emergent wetland), PSS (palustrine scrub-shrub wetland), PFO (palustrine forested wetland), and PuB (palustrine unconsolidated bottom – i.e. ponds).
  • PA DEP stream designation (see guide). Most common are WWF (warm water fishes), CWF (cold water fishes), HQ (high quality), and EV (exceptional value).
  • PA Fish and Boat Commission classifications (see guide). Most common are ATW (approved trout water), STS (stocked trout stream), Class A (class A water), and WTS (wilderness trout stream).

An example water body data table that can be found on the map:
me2-zoom-screenshot2

Our analysis of this new data reveals the number of water crossings in question is significantly higher than what we estimated in August: now totaling 1,222 streams, 34 ponds, and 708 wetlands crossings. This increase is primarily due to Sunoco’s data also containing information on ephemeral and intermittent waters that are not typically accounted for in USGS data (all that was available at the time of our prior analysis).

Defining Impacts

The DEP’s Chapter 105 Joint Permit Application Instructions break down “impacts” into two broad categories: permanent and temporary. These are primarily used to assess environmental impact fees, but are also valuable in determining what parameters Sunoco will be held to during and after ME 2’s construction.

Permanent impacts: are “areas affected by a water obstruction or encroachment that consist of both direct and indirect impacts that result from the placement or construction of a water obstruction or encroachment and include areas necessary for the operation and maintenance of the water obstruction or encroachment located in, along or across, or projecting into a watercourse, floodway or body of water.”

Permanent impacts are calculated using the pipeline’s 50-foot permanent right-of-way. For streams, all bed and banks are to be restored to pre-construction conditions. For ponds and wetlands, permanent impacts are assumed to remain even if the area is considered restored.

Temporary impacts: are “areas affected during the construction of a water obstruction or encroachment that consists of both direct and indirect impacts located in, along or across, or projecting into a watercourse, floodway or body of water that are restored upon completion of construction.” Temporary impacts consist of areas such as temporary workspaces and access roads.

The below table lists the total impacted acres broken down by county. Of interest here is that more than 175 acres would be permanently impacted — equivalent to 134 football fields — with an additional 82 acres temporarily impacted.

Table 1. Impacted Acres by County

County Permanent Impacts (acres) Temporary Impacts (acre)
Allegheny 1.85 0.39
Berks 11.14 4.88
Blair 11.70 6.72
Cambria 20.21 8.48
Chester 10.30 3.92
Cumberland 24.06 7.61
Dauphin 8.12 6.55
Delaware 5.05 3.33
Huntingdon 18.75 8.04
Indiana 11.42 4.73
Juniata 5.25 3.02
Lancaster 4.65 1.66
Lebanon 6.48 2.53
Perry 5.58 2.63
Washington 9.37 2.94
Westmoreland 17.72 12.36
York 3.46 2.16
Total 175.12 81.93

Viable Options to Reduce Impacts

Example of an open cut wet crossing

An open cut wet crossing (image source)

Pipeline companies cross water bodies using a variety of methods depending on their classification. The DEP maintains three general categories for water crossings: minor (in streams less than or equal to 10 feet wide at the water’s edge at the time of construction), intermediate (perennial stream crossings greater than 10 feet wide but less than 100 feet wide at the water’s edge at the time of construction), and major (crossings of more than 100 feet at the water’s edge at the time of construction).

Minor and intermediate crossings often employ rudimentary trenching along “open cut” crossings where the water is either temporarily diverted (wet crossing) or allowed to flow during construction (wet crossing). After the cuts, the company attempts to repair damage done in the process of trenching.

In more sensitive places, such as in exceptional value streams, wetlands, and always in major crossings, a company uses conventional boring to tunnel under a water feature. When boring over long distances, such as under a lake or river, a company turns to Horizontal Directional Drilling (HDD), a more engineered form of boring. An example of HDD boring is seen below (image source):

hdd_crossing_example

We were surprised by the number of water crossings identified by Sunoco as having options to minimize impact. As the table below shows, more than 44% (869) of Sunoco’s crossings have an alternate method identified in the resubmitted applications. In most of these instances, the intended crossing method is either trenching through open cuts or dry crossings. The majority of identified alternatives would reduce impacts simply by altering the trenching route. 53 of the 869 were shown to have feasible conditions for conventional or HDD boring, but Sunoco categorized all of these as impracticable options despite their environmental benefits.

Table 2. Number of Crossings With and Without Viable Alternate Methods

Crossings Assessed but Unimpacted Impacted with No Alternative Impacted with Alternatives Total
Streams 313 925 297 1,535
Ponds 66 3 31 100
Wetlands 963 167 541 1,671
  1,342 1,095 869 3,306

Absorbing the Costs of Environmental Impacts

If executed, these alternative methods would decrease the length of crossings, limit right-of-way encroachments, prevent land fragmentation, and significantly reduce risks to larger water bodies. More likely, Sunoco will pay the impact fees associated with the less complicated crossing methods. We’ve summarized these fees (found in Sunoco’s resubmitted application) in the table below. In total, Sunoco would pay roughly $1.8 million in exchange for nearly 2,000 water body crossings – a fraction of the project’s $2.5 billion estimated cost:

Table 3. Impact Fees for Sunoco’s Preferred Crossings

County Permanent Impacts area (fees) Temporary Impact area (fees) Admin Fees Total Fees
Allegheny $15,200 $1,600 $1,750 $18,550
Berks $89,600 $19,600 $1,750 $110,950
Blair $94,400 $27,200 $1,750 $123,350
Cambria $162,400 $34,000 $1,750 $198,150
Chester $83,200 $16,000 $1,750 $100,950
Cumberland $192,800 $30,800 $1,750 $225,350
Dauphin $65,600 $26,400 $1,750 $93,750
Delaware $40,800 $13,600 $1,750 $56,150
Huntingdon $150,400 $32,400 $1,750 $184,550
Indiana $92,000 $19,200 $1,750 $112,950
Juniata $42,400 $12,400 $1,750 $56,550
Lancaster $37,600 $6,800 $1,750 $46,150
Lebanon $52,000 $10,400 $1,750 $64,150
Perry $44,800 $10,800 $1,750 $57,350
Washington $75,200 $12,000 $1,750 $88,950
Westmoreland $142,400 $50,000 $1,750 $194,150
York $28,000 $8,800 $1,750 $38,550
$1,408,800 $332,000 $29,750 $1,770,550

Conclusion

This week, acting DEP Secretary Patrick McDonnell met with residents who voiced frustration that the agency failed to provide an additional public comment period following Sunoco’s application resubmission. Nevertheless, the DEP is expected to greenlight Sunoco’s plans any day now, adding another to the list of recent pipeline approvals in the region. Sunoco needs its permits now in order to begin clearing trees prior to endangered species bat nesting season, which begins in April.

Meanwhile, communities along the pipeline’s path are preparing for the sudden wave of disruption that may ensue. Some have threatened lawsuits, arguing that the resubmitted application still contains many deficiencies including missing wetlands and private drinking wells that must be accounted for. Indeed, the map and data presented in this article confirms that there is still a lot that the general public does not know about ME 2 – in particular, the extent of water impacts the DEP seems willing to accept and the range of options at Sunoco’s disposal that might mitigate those impacts if it were forced to do so.

Finally, it is encouraging to see that the DEP is becoming more transparent in sharing datasets, compared to other pipeline projects. However, this data is complex and not easily understood without sufficient technical expertise. We are discouraged to think that it is unlikely the public will learn about additional changes to the construction plan until after permits are issued. In order for data to be useful, it must be made available throughout the process, not at the end stages of planning, and done so in a way that it becomes integrated into the agency’s public participation responsibilities.

by Kirk Jalbert, Manager of Community-Based Research & Engagement