Mysterious leak near Porterville Compressor Station, NY

March 27, 2017/by Karen Edelstein

Last month, FracTracker Alliance featured a blog entry and map exploring the controversy around National Fuel’s proposed Northern Access Pipeline (NAPL) project, shown in the map below. The proposed project, which has already received approval from the Federal Energy Regulatory Commission (FERC), is still awaiting another decision by April 7, 2017 — Section 401 Water Quality Certification. By that date, the New York State Department of Environmental Conservation (NYS DEC) must give either final approval, or else deny the project.

Northern Access Pipeline Map

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The NAPL project includes the construction of 97-mile-long pipeline to bring fracked Marcellus gas through New York State, and into Canada. The project also involves construction of a variety of related major infrastructure projects, including a gas dehydration facility, and a ten-fold expansion of the capacity of the Porterville Compressor Station located at the northern terminus of the proposed pipeline, in Erie County, NY.

On three consecutive days in early February, 2017, the New York State Department of Environmental Conservation (NYS DEC) held hearings in Western New York to gather input about the NAPL project. On February 7^th, the day of the first meeting at Saint Bonaventure University in Allegany County, NY, an alarming — and yet to be fully reported — incident widely considered to be a gas leak, occurred at, or near, the Porterville Compressor Station (also known locally as the “Elma Compressor Station”). The incident is thought to be connected to the planned upgrades to the facility, but was not even mentioned as a concern during the public meetings relating to the Northern Access Pipeline in the subsequent hours and days.

What follows is a story of poor communication between the utility company, first responders, and local residents, resulting in confusion and even panic, and has yet to be conclusively explained to the general public.

Incident Description

Area of incident in NY State

We know that a little past 10 AM on February 7^th, people in the villages of Elma and East Aurora, within about a mile of the Porterville Compressor Station, reported strong odors of gas. They filed complaints with the local gas utility (National Fuel), and the local 911 center, which referred the calls to the local Elma Fire Department. The fire department went to the Porterville Compressor station to investigate, remembering a similar incident from a few years earlier. At the compressor station, representatives from National Fuel, the operator of the compressor station, assured the fire company that they were conducting a routine flushing of an odorant line, and the situation was under control, so the fire company departed.

Residents in the area became more alarmed when they noticed that the odor was stronger outside their buildings than inside them. National Fuel then ordered many residents to evacuate their homes. The East Aurora police facilitated the evacuation and instructed residents to gather in the East Aurora Library not far from those homes. Nearby businesses, such as Fisher Price, headquartered in East Aurora, chose to send their employees home for the day, due to the offensive odor and perceived risks.

Around 11:30 in the morning, up to 200 clients at Suburban Adult Services, Inc. (SASi), were evacuated to the Jamison Road Fire Station, where they remained until around 3 PM that afternoon. Over 200 reports were received, some from as far away as Orchard Park, eight miles down-wind of the compressor station.

After East Aurora elementary and middle schools placed complaints, National Fuel told them to evacuate students and staff from their buildings. Realizing that the smell was stronger outside than inside the building, school leaders revised their plans, and started to get buses ready to transport student to the high school, where there had not been reports of the odor. Before the buses could load, however, the police department notified the school that the gas leak had been repaired, and that there was no need to evacuate. School officials then activated the school’s air circulation system to rid the building of the fumes.

Perplexingly, according to one report, National Fuel’s Communications Manager Karen Merkel said “that the company did not reach out into the community to tell people what was going on because the company cannot discourage anyone from making an emergency gas call.”

Merkel noted further, “You never know if the smell being reported is related to work we are doing or another gas leak,” she said. “This wouldn’t be determined until we investigate it.”

That smell…

Some background on gas leaks & odorant additives

Ethyl mercaptan molecule

An odorant, such as ethyl mercaptan, is often added to natural gas in order to serve as an “early warning system” in the event of a leak from the system. Odorants like mercaptan are especially effective because the humans can smell very low concentrations of it in the air. According to the National Cen ter for Biotechnology Information, “The level of distinct odor awareness (LOA) for ethyl mercaptan odorant is 1.4 x10^-4 ppm,” or 0.00014 parts per million. That translates to 0.000000014 percent by volume.

Not all natural gas is odorized, however. According to Chevron Phillips, “mercaptans are required (by state and federal regulations) to be added to the gas stream near points of consumption as well as in pipelines that are near areas with certain population density requirements, per Department of Transportation regulations… Not all gas is odorized, though; large industrial users served by transmission lines away from everyday consumers might not be required to use odorized gas.” Also, because odorants tend to degrade or oxidize when gas is travelling a long distance through transmission lines, they are not always added to larger pipeline systems.

The explosion and flammability concentration limit for natural gas refers to the percentage range at which a gas will explode. At very low concentrations, the gas will not ignite. If the concentration is too high, not enough oxygen is present, and the gas is also stable. This is why gas in non-leaky pipelines does not explode, but when it mixes with air, and a spark is present, the result can be disastrous. Methane, the primary component of natural gas, has a lower explosive level (LEL) of 4.4% and an upper explosive limit (UEL) (above which it will not ignite) of 16.4%. Nonetheless, levels above 1% are still worrisome, and may still be good cause for evacuation.

Therefore, the margin of safety between when natural gas is detectable with an odorant present, and when it may explode, is very broad. This may help to explain why the smell of gas was detected over such a broad distance, but no explosion (very fortunately) took place.

Local memories of gas explosion in East Aurora

Many East Aurora residents have had first-hand experience with the dangers posed by gas lines in their community. Less than 25 years ago, in September 1994, a high-pressure pipeline owned by National Fuel ruptured in an uninhabited area between East Aurora and South Wales along Olean Rd. The blast left a 10-foot-deep, 20-foot-wide crater, and tree limbs and vegetation were burned as far as 50 feet away.

Porterville first-hand accounts and inquiries

FracTracker spoke extensively with one resident of East Aurora, Jennifer Marmion, about her experiences, and efforts to understand what had actually happened the day of this incident.

When personnel from the Jamison Fire Company — who are assumed to be first responders to emergencies of this sort — arrived at the Porterville Compressor Station, they were told by National Fuel that there was no hazard and that their services were not needed. Consequently, these crews left the site. The East Aurora Police Department was given a different explanation by National Fuel; there was a valve malfunction somewhere along Two Rod Road in Marilla. Still later, National Fuel indicated that the pipeline changeover occurred closer to the compressor station itself. The closest distance between anywhere on Two Rod Road and the compressor station, itself, is a mile and a half. And Ms. Marmion was given a still different story by a National Fuel engineer: that the odor, indeed, resulted during the replacement of a 100-foot-long section of aging pipeline at the Porterville (“Elma”) Compressor Station.

Key locations in incident report

Some reports indicated an alternate explanation: that the odor originated at the East Aurora Town Hall (J. Marmion, pers. comm., via Channel 7 News), or a leaky valve along a pipeline near Marilla (J. Marmion, pers. comm, via East Aurora Police Department dispatcher). A member of the East Aurora Fire Department surmised that the leak might have been closer to Olean Road, south of the village, where there was a history of other leaks. The day after the incident, National Fuel indicated that the odor originated from the compressor station, and was the result of a routine, scheduled “blowdown” by National Fuel — wherein gas lines at the compressor station are cleared as part of routine maintenance. However, when pressed for more details, they did not provide them.

In need of follow up

More than six weeks have passed since the incident, and there is still no definitive explanation available. Clearly, there was considerable confusion about what the correct, and safe, procedure needed to be, as well as how this information needed to flow to the public. Ultimately, a representative from National Fuel’s Government Affairs office agreed that he would alert the local towns and fire departments when maintenance activities would be occurring. It is surprising that this was not already standard practice.

Although Ms. Marmion is continuing to be a determined citizen activist, she has been met with a frustrating array of ambiguous and often conflicting descriptions, phone calls that go un-answered, voice mailboxes at offices that are either full or not set up to receive messages. Furthermore, although National Fuel has told Marmion that there is an Action Plan to be followed in the event of an emergency, they have been unable to provide her with a written or electronic version of this document, because “the action plan is just known.”

National Fuel points to the weather

National Fuel maintains that the only factor that was out of the ordinary was that during the event, a combination of unusual weather factors caused the released gas to travel in an unusual manner and also not dissipate as quickly as expected. National Fuel also indicated that the strong odor (created by the additive mercaptan) was a benefit to the local community, added to natural gas so that residents would be alerted to problems. It’s important to note that the largest gas transmissions pipelines, like the nearby 26” diameter Tennessee Gas Pipeline to the east of Elma and East Aurora, as well other pipelines that will run to the greatly expanded Porterville Compressor Station as part of the Northern Access Pipeline project, will be without the odorant.

Here’s what FracTracker could verify, based on National Weather Service, and Weather Underground historical data. In the morning and afternoon of February 7^th, the wind was uncharacteristically blowing from the east/northeast — atypical for western New York, when winds normally come from the west. Wind speeds were recorded between 10-15 mph. Humidity was also uncharacteristically high for February — topping out at 93% that day. Warm air aloft, combined with freezing rain, created a temperature inversion. The moist air then trapped the odor, which lingered across the region.

Screen captures of weather statistics on February 7, 2017 (Source: wunderground.com). Note dominant wind direction from ENE, as well as high humidity, during morning and early afternoon, when incident took place.

Who monitors air quality in Western New York?

Calls by FracTracker for clarification from the New York State DEC’s Division of Air Resources have gone unanswered. The only station at which the DEC monitors methane is located more than 275 miles away to the southeast, in the Bronx. In Erie County, where the incident took place, there are only four permanent ambient air pollution monitoring stations. These include stations in:

Amherst: Continuous monitoring of ozone, NO_2.Manual monitoring of PM₅, acid deposition.
Buffalo: Continuous monitoring of SO₂, NO_x, NO, NO_2,NO_y, CO, CPM₅. Manual monitoring of PM_2.5, PM₁₀, toxics
Brookside Terrace/Tonawanda: Continuous monitoring of SO₂, CPM₅. Manual monitoring of toxics and carbonyls
Grand Island (special purpose only): Continuous monitoring of CPM₅. Manual monitoring of toxics and carbonyls

“PM” refers to particulate matter diameter. PM_5,for example, denotes particulate matter 5 microns in diameter, and smaller.

The East Aurora and Elma fire departments lack the appropriate air quality detection instruments to make their own judgements on the explosive nature of these gas plumes. Instead, small towns rely on the expertise of National Fuel to arrive on the scene after a call has been made, so that National Fuel can take measurements and then respond to the community. Some residents waited over three hours for an assessment, but by this time the plume had drifted away two hours ago.

National Fuel, however, has not disclosed any of the air quality data measurements they made on February 7^th when they responded to this complicated incident. Ms. Marmion and others still want to know what levels of methane were measured in the communities involved in this incident, or the specific quantity of gas that entered the air that day.

What’s next?

While National Fuel did not notify the residents or the school district administration in advance of the scheduled “blowdown,” their Government Affairs Representative indicated that in the future, town governments, community leaders, and the local fire companies would be alerted to the upcoming releases and maintenance work. Nonetheless, weeks after the odor incident, National Fuel has neither contacted the local community leaders, nor local law enforcement, to provide complete and detailed answers as to what actually happened on February 7^th.

By Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance. Special thanks to East Aurora resident Jennifer Marmion, for her insights and comments.

34 states with active drilling activity in US map

34 states have active oil & gas activity in U.S. based on 2016 analysis

March 23, 2017/by FracTracker Alliance

Each year, FracTracker Alliance compiles a national well file to try to assess how many wells have been drilled in the U.S. We do this by extracting data from the various state regulatory agencies that oversee drilling in oil and gas producing states. We’re a little late posting the results of our 2016 analysis, but here it is.

Based on data from 2014-2015, 34 states * saw drilling activity, amounting to approximately 1.2 million facilities across the U.S. – from active production wells, to natural gas compressor stations, to processing plants.

The process we used to count these wells and related facilities for the 2016 analysis changed a bit this time around, which obviously impacts the total number of wells in the dataset. 2016’s compilation was created in consultation with Earthworks, for the purpose of informing the Oil and Gas Threat Map project. The scope was more restrictive than previous editions (see our 2014 and 2015 analyses), focusing only on wells that we were reasonably confident were actively producing oil and gas wells, thus excluding wells with inactive or uncertain statuses, as well salt water disposal (SWD) and other Class II injection (INJ) well types.

There are facilities included in this dataset that we don’t normally tally, as well (See Table 1 below). Earthworks was able to determine the latitude and longitude coordinates of a number of compressors and other processing plants, which are included in the dataset below and final map.

In all, the facility counts are reduced from about 1.7 million in 2015 to about 1.2 million in 2016, but this is more a reflection of the definition than substantial changes in the active well inventory in the U.S. You can explore this information by state, and additional results of this project, using Earthworks’ Threats Maps. Additionally, the national well file is available to download below.

Download 2016 National Well File Data

* The zip file separates out TX wells from the rest of the states due to the significant number of TX facilities.

You’ll notice that we don’t refer to the wells in this analysis as “fracked” wells. The primary reason for not using such terminology is because no one common definition exists across those states for what constitutes a hydraulically fractured well. In PA, for example, such wells are considered “unconventional” because drilling occurs in an unconventional formation and usually involves some sort of well stimulation. Contrastingly, in CA, often drillers use “acidizing” not fracking – a similar process that breaks up the ground using acidic injected fluids instead of the high pressure seen in traditional fracking. As such, we included all active oil and gas production instead of trying to limit the analysis to just wells that have been stimulated. We will likely continue to use this process until a federal or national definition of what constitutes a “fracked” well is determined.

Table 1. Facilities by State and Type

State	Count of Facilities by Type			Grand Total
State	Compressor	Processor	Well	Grand Total
AK		7	3,356	3,363
AL		17	7,016	7,033
AR	231	8	13,789	14,028
AZ			40	40
CA	7	21	92,737	92,765
CO	426	49	50,881	51,356
FL		2	102	104
ID			6	6
IL		5	48,748	48,753
IN			7,374	7,374
KS		9	90,526	90,535
KY		5	11,769	11,774
LA	6,486	94	2,555	9,135
MI		19	16,525	16,544
MO		2	687	689
MS		6	4,556	4,562
MT		5	9,768	9,773
ND		19	13,024	13,043
NE		1	16,202	16,203
NM	902	37	57,839	58,778
NV			176	176
NY			12,244	12,244
OH	29	10	90,288	90,327
OK	856	96	29,042	29,994
OR			56	56
PA	452	11	103,680	104,143
SD			408	408
TN			15,956	15,956
TX	758	315	397,776	398,849
UT		18	20,608	20,626
VA			9,888	9,888
WI		1		1
WV		20	16,118	16,138
WY	325	48	38,538	38,911
Grand Total	10,472	825	1,182,278	1,193,575
* NC facilities are not included because the state did not respond to multiple requests for the data. This exclusion likely does not significantly affect the total number of wells in the table, as historically NC only had 2 oil and gas wells.

For schools and hospitals analysis, 2017

How close are schools and hospitals to drilling activity in West Virginia and Ohio?

March 13, 2017/by Ted Auch, PhD

A review of WV and OH drilling activity and its proximity to schools and medical facilities

Schools and hospitals represent places where vulnerable populations may be put at risk if they are located close to oil and gas activity. Piggybacking on some elegant work from PennEnvironment (2013) and Physicians, Scientists, and Engineers (PSE) Healthy Energy (PDF) in Pennsylvania, below is an in-depth look at the proximity of unconventional oil and gas (O&G) activity to schools and hospitals in Ohio and West Virginia.

Ohio Schools and Medical Facilities

In Ohio, presently there are 13 schools or medical facilities within a half-mile of a Utica and/or Class II injection well and an additional 344 within 2 miles (Table 1 and map below). This number increases to 1,221 schools or medical facilities when you consider those within four miles of O&G related activity.

Map of OH Drilling and Disposal Activity Near Schools, Medical Facilities

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Explore the data used to make this map in the “Data Downloads” section at the end of this article.

Table 1. Number of OH schools and hospitals within certain distances from Utica wells

	Utica		Class II Injection
Well Distance (Miles)	Schools	Medical Facilities	Schools	Medical Facilities
0.5	3	1	9	0
0.5-1	19 (22)	9 (10)	16 (25)	13 (13)
1-2	79 (101)	41 (51)	88 (113)	79 (92)
2-3	84 (185)	49 (100)	165 (278)	122 (214)
3-4	85 (270)	79 (179)	168 (446)	112 (326)
4-5	92 (362)	63 (242)	196 (642)	166 (492)
5-10	388 (750)	338 (580)	796 (1,438)	584 (1,076)

Ohio’s rate of Utica lateral permitting has jumped from an average of 39 per month all-time to 66 per month in the last year. OH’s drilling activity has also begun to spread to outlying counties^[1]. As such, we thought a proactive analysis should include a broader geographic area, which is why we quantified the number of schools and medical facilities within 5 and 10 miles of Utica and Class II activity (Figures 1 and 2). To this end we found that ≥50% of Ohio’s schools, both public and private, are within 10 miles of this industry. Similarly 50% of the state’s medical facilities are within 10 miles of Utica permits or Class II wells.

Footnote 1: Eleven counties in Ohio are currently home to >10 Utica permits, while 23 are home to at least 1 Utica permit.

Figures 1, 2a, 2b (above). Click to expand.

Grade Level Comparisons

With respect to grade level, the majority of the schools in question are elementary schools, with 40-50 elementary schools within 2-5 miles of Ohio Utica wells. This number spikes to 216 elementary schools within ten miles of Utica permits along with an additional 153 middle or high Schools (Figure 3). Naturally, public schools constitute most of the aforementioned schools; there are approximately 75 within five miles of Utica permits and 284 within ten miles of Utica activity (Figure 4).

Figures 3 and 4 (above). Click to expand.

Public Schools in Ohio

We also found that ~4% of Ohio’s public school students attend a school within 2 miles of the state’s Utica and/or Class II Injection wells (i.e., 76,955 students) (Table 2). An additional 315,362 students or 16% of the total public school student population, live within five miles of O&G activity.

Table 2. Number of students in OH’s public schools within certain distances from Utica and Class II Injection wells

	Utica			Class II Injection
Well Distance (Miles)	# Schools	# Students	Avg	# Schools	# Students	Avg
0.5	3	1,360	453	7	3,312	473
<1	21	7,910	377	19	7,984	420
<2	96	35,390	376	90	41,565	462
<3	169	67,713	401	215	104,752	487
<4	241	97,448	404	350	176,067	503
<5	317	137,911	435	505	254,406	504
<10	600	280,330	467	1,126	569,343	506

(Note: Ohio’s population currently stands at 11.59 million people; 2,007,667 total students).

The broadest extent of our study indicates that 42% of Ohio students attend school within ten miles of a Utica or Class II Injection well (Figure 5). As the Ohio Utica region expands from the original 11 county core to include upwards of 23-25 counties, we expect these 5-10 mile zones to be more indicative of the type of student-Utica Shale interaction we can expect to see in the near future.

Photos of drilling activity near schools, and Figure 5 (above). Click to expand.

Private Schools in Ohio

At the present time, less than one percent of Ohio’s private school students attend a school within 2 miles of Utica and/or Class II Injection wells (specifically, 208 students). An additional 11,873 students or 11% of the total student population live within five miles. When you broaden the extent, 26% of Ohio’s private primary and secondary school students attend school daily within ten miles of a Utica or Class II Injection well. Additionally, the average size of schools in the immediate vicinity of Utica production and waste activity ranges between 11 and 21 students, while those within 2-10 miles is 112-159 students. Explore Table 3 for more details.

Table 3. Number of students in Ohio’s private schools within certain distances from Utica and Class II Injection.

	Utica			Class II Injection
Distance from Well (Miles)	# Schools	# Students	Avg	# Schools	# Students	Avg
0.5	.	.	.	1	.	.
<1	.	.	.	2	25	13
<2	2	22	11	9	186	21
<3	7	874	125	30	4,460	149
<4	12	1,912	159	45	6,303	140
<5	21	2,471	118	61	9,610	158
<10	60	6,727	112	135	20,836	154

West Virginia Schools and Students

Twenty-eight percent (81,979) of West Virginia’s primary and secondary school students travel to a school every day that is within two miles of the state’s Marcellus and/or Class II Injection wells.

Map of WV Marcellus Activity and Schools

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Explore the data used to make this map in the “Data Downloads” section at the end of this article.

Compared with Ohio, 5,024 more WV students live near this industry (Table 4). An additional 97,114 students, or 34% of the West Virginia student population, live within 5 miles of O&G related wells. The broadest extent of our study indicates that more than 90% of West Virginia students attend school daily within 10 miles of a Marcellus and/or Class II Injection well.

Figure 6. West Virginia primary and secondary schools, Marcellus Shale wells, and Class II Injection wells (Note: Schools that have not reported enrollment figures to the WV Department of Education are highlighted in blue). Click image to expand.

It is worth noting that 248 private schools of 959 total schools do not report attendance to the West Virginia Department of Education, which means there are potentially an additional 69-77,000 students in private/parochial or vocational technology institutions unaccounted for in this analysis (Figure 6). Finally, we were not able to perform an analysis of West Virginia’s medical facility inventory relative to Marcellus activity because the West Virginia Department of Health and Human Resources admittedly did not have an analogous, or remotely complete, list of their facilities. The WV DHHR was only able to provide a list of Medicaid providers and the only list we were able to find was not verifiable and was limited to hospitals only.

Table 4. Number of students in WV schools within certain distances from Shale and Class II Injection wells

	Marcellus			Class II Injection
Distance from Well (Miles)	#	Sum	Avg	#	Sum	Avg
0.5	19	5,674	299	1	.	.
<1	52 (71)	16,992 (22,666)	319	5 (6)	1,544	257
<2	169 (240)	52,737 (75,403)	314	16 (22)	5,032 (6,576)	299
<3	133 (373)	36,112 (111,515)	299	18 (40)	6,132 (12,708)	318
<4	88 (461)	25,037 (136,552)	296	21 (61)	5,235 (17,943)	294
<5	56 (517)	15,685 (152,237)	295	26 (87)	8,913 (26,856)	309
<10	118 (635)	37,131 (189,368)	298	228 (315)	69,339 (96,195)	305
Note: West Virginia population currently stands at 1.85 million people; 289,700 total students with 248 private schools of 959 total schools not reporting attendance, which means there are likely an additional 69-77,000 students in Private/Parochial or Vocational Technology institutions unaccounted for in this analysis.

Conclusion

A Trump White House will likely mean an expansion of unconventional oil and gas activity and concomitant changes in fracking waste production, transport, and disposal. As such, it seems likely that more complex and broad issues related to watershed security and/or resilience, as well as related environmental concerns, will be disproportionately forced on Central Appalachian communities throughout Ohio and West Virginia.

Will young and vulnerable populations be monitored, protected, and educated or will a Pruitt-lead EPA pursue more laissez-faire tactics with respect to environmental monitoring? Stay Tuned!

Analysis Methods

The radii we used to conduct this assessment ranged between ≤ 0.5 and 5-10 miles from a Utica or Marcellus lateral. This range is larger than the aforementioned studies. The point of using larger radii was to attempt to determine how many schools and students, as well as medical facilities, may find themselves in a more concentrated shale activity zone due to increased permitting. Another important, related issue is the fact that shale O&G exploration is proving to be more diffuse, with the industry exploring the fringes of the Utica and Marcellus shale plays. An additional difference between our analysis and that of PennEnvironment and PSE Healthy Energy is that we looked at identical radii around each state’s Class II Injection well inventory. We included these wells given the safety concerns regarding:

their role in induced seismicity,
potential water and air quality issues, and
concomitant increases in truck volumes and speeds.

Data Downloads for Maps Above

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

Oil and Gas Wastes are Radioactive – and Lack Regulatory Oversight

March 9, 2017/by Kyle Ferrar, MPH

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

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

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

When it comes to unconventional oil and gas waste streams:

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

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

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

State Waste Management Maps

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

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

Montana – View map fullscreen

North Dakota – View map fullscreen

Colorado – View map fullscreen

Wyoming – View map fullscreen

Sources of Radioactivity

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

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

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

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

Radioactive Oil and Gas Pathway Life Cycle

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

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

A. Scales

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

B. Produced Waters

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

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

C. Sludges

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

Federal Exemptions

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

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

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

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

State Regulations

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

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

Why can’t the waste be treated?

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

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

Risks

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

Radon inhalation,
External gamma exposure,
Groundwater ingestion,
Surface water ingestion,
Dust inhalation,
Food ingestion, and
Skin beta exposure from particles containing the radioisotopes.

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

Cases of Contamination

North Dakota

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

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

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

Pennsylvania

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

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

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

Action Plans Needed

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

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

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

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

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

Ohio Shale Activity, Waste Disposal, and Public Water Supplies

March 2, 2017/by Ted Auch, PhD

Ohio is unique relative to its Appalachian neighbors in the Marcellus and Utica Shale Basins in that The Buckeye State chose to “diversify” when it came to planning for the hydraulic fracturing revolution. One of the first things financial advisers tell their clients is to “diversify, diversify, diversify.” However, this strategy is usually meant to buffer investors when certain sectors of the economy underperform. Columbus legislators took this strategy to mean that we should drill and hydraulically fracture our geology to extract oil and gas (O&G), as well as taking in vast quantities of liquid and solid O&G waste from Pennsylvania and West Virginia.

Accepting significant quantities of out-of-state waste raises several critical questions, however. How will these materials will be contained? Will such volumes require more and larger waste landfills? And will the injection of liquid brine waste into our geology (photo below) make Ohio the “Oklahoma of Appalachia” with respect to induced seismicity?

Above: Example Class II salt water disposal (SWD) wells in Ohio

Risks to Public Water Supplies

There are also mounting concerns about public water supply (PWS) security, quality, and resilience. These concerns stem from the growing uncertainty surrounding the containment of hydraulically fractured and Class II injection wells.

To begin to assess the risks involved in locating these wells near PWS’s, we compiled and incorporated as many of the state’s PWS’s into our primary Ohio maps. In this post, we explore PWS proximity to Utica drilling activity and Class II salt water disposal (SWD) wells in Ohio.

Waste Disposal & Drilling Near PWS’s

Just how close are public water supplies to Class II waste disposal wells and permitted Utica wells? As of January 15, 2017, there are 13 PWS’s within a half-mile of Ohio’s Class II SWD wells, and 18 within a half-mile of permitted Utica wells. These facilities serve approximately 2,000 Ohioans each, with an average of 112-153 people per PWS (Tables 1 and 5). Within one mile from these wells there are 64 to 66 PWSs serving 18 to 61 thousand Ohioans. That’s an average of 285-925 residents.

Above: Photos of SWD wells from the sky

While PWSs on the 5-mile perimeter of our analysis don’t immediately conjure up water quality/quantity concerns, they may in the future; the rate of Utica and Class II permitting is likely to accelerate under a new White House administration more friendly to industry and averse to enforcing or enhancing regulatory hurdles.

A total of 960 and 699 PWSs are currently within five miles of Ohio Class II and Utica wells. These facilities service roughly 1.5 million and one-half million Ohioans each day, which is ~13% and 4% of the state, respectively. The average PWS within range of Class II wells is 37% to 330 times the average PWS within range of Utica wells.

Roland Marily Kemble Class II Salt Water Disposal Well, Muskingum County, Ohio, Muskingum River Watershed, 39.975, -81.845, 1,984,787 Barrels of Waste Disposed Between 2010 and Q3-2016

Fifty-eight (58%) to 69% of the PWSs within range of Class II wells are what the Ohio EPA calls Transient Non-Community (TNC) (Table 2). TNC’s are defined by the OH EPA and OH Department of Agriculture as serving^{[1]^:}

…at least 25 different persons over 60 days per year. Examples include campgrounds, restaurants and gas stations. In addition, drinking water systems associated with agricultural migrant labor camps, as defined by the Ohio Department of Agriculture, are regulated even though they may not meet the minimum number of people or service connections.

Meanwhile 60-89% of PWS’s in the shadow of Ohio’s permitted Utica wells are of the TNC variety. Even larger percentages of these PWS’s are either Groundwater or Purchased Groundwater types. Most of the PWS’s within the range gradient we looked at are privately owned, with only handful owned by federal or state agencies (Table 6).

Above: Example Class II salt water disposal (SWD) wells in Ohio

Of the 24 hydrologic unit codes (HUCs)/watersheds that contain Class II SWD wells, the lion’s share of PWS’s within the shadow of injection wells are the Tuscarawas, Mahoning, and Walhonding (Table 3). Even the Cuyahoga River, which feeds directly in the Great Lakes, is home to up to 138 PWS’s within 5 miles of Class II SWD wells. Conversely, only 13 HUCs currently contain Ohio’s Utica wells. Like Class II-affected HUCs, we see that the Mahoning, Tuscarawas, and Cuyahoga PSW’s contain most of the PWSs of interest (Table 7).

Conclusion

Watershed security/resilience concerns are growing in Eastern Ohio. Residential and agricultural water demands are increasingly coming into conflict with the drilling industry’s growing freshwater demand. Additionally, as oil and gas drilling uses more water, we will see more brine produced (Figures 1 and 2).

This, in turn, will create more demand – on top of an already exponential trend (Figure 3) – for Ohio’s existing Class II wells from across Northern Appalachia, stretching from Southeast Ohio and West Virginia to North Central Pennsylvania.

An understanding of the links between watershed security, O&G freshwater demand, brine production, and frack waste disposal is even more critical in areas like Southeast Ohio’s Muskingum River Watershed (Figure 4).

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
Well Distance (Miles)	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)
HUC Name	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)
County	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
Well Distance (Miles)	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)
HUC Name	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)
County	0.5	<1	<2	<3	<4	<5
Ashtabula					1	1
Belmont	1	2	7	14	15	16
Carroll	6	20	36	43	43	43
Columbiana	4	15	45	72	80	81
Coshocton				7	10	10
Geauga				14	20	25
Guernsey		1	1	2	4	5
Harrison	2	6	16	16	16	16
Holmes			5	13	31	43
Jefferson	2	3	11	22	25	25
Knox			1	1	2	2
Licking			1	1	1	1
Mahoning		2	10	32	44	55
Medina			1	4	5	7
Monroe		2	4	6	6	6
Muskingum		1	1	1	2	3
Noble			2	2	2	2
Portage		2	8	25	49	84
Stark	2	5	40	85	110	122
Summit					6	10
Trumbull		3	23	36	53	65
Tuscarawas	1	2	15	22	28	43
Washington			3	10	12	13
Wayne			5	5	7	21

Footnote

Community (C) = serve at least 15 service connections used by year-round residents or regularly serve at least 25 year-round residents. Examples include cities, mobile home parks and nursing homes; Non-Transient, Non-Community (NTNC) = serve at least 25 of the same persons over six months per year. Examples include schools, hospitals and factories.

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

Northern Access Project: Exporting PA’s Marcellus Gas Northward

February 16, 2017/by Karen Edelstein

In March 2015, the National Fuel Gas Supply Corporation and Empire Pipeline Company filed a joint application with the Federal Energy Resource Commission (FERC) to construct a new natural gas pipeline and related infrastructure, known collectively as the Northern Access Project (NAPL). The pricetag on the project is $455 million, and is funded through international, as well as local, financial institutions. The Public Accountability Initiative recently produced a report detailing the funding for this pipeline project, entitled “The Power Behind the Pipeline“.

The proposed Northern Access Project consists of a 97-mile-long, 24” pipe that would carry Marcellus Shale gas from Sergeant Township (McKean County), PA, to the Porterville Compressor Station in the Town of Elma (Erie County), NY. Nearly 69% of the proposed main pipeline will be co-located in existing pipeline and power line rights-of-way, according to FERC. The agency says this will streamline the project and reduce the need to rely on eminent domain to most efficiently route the project.

A $42 million, 15,400 horsepower Hinsdale Compressor Station along the proposed pipeline route was completed in 2015. In addition to the pipeline itself, the proposed project includes:

Additional 5,350 HP compression at the existing Porterville Compressor Station, a ten-fold increase of the capacity of that station
A new 22,214 HP compressor station in Pendleton (Niagara County), NY
Two miles of pipeline in Pendleton (Niagara County), NY
A new natural gas dehydration facility in Wheatfield (Niagara County), NY
An interconnection with the Tennessee Gas Pipeline in Wales (Erie County), NY, as well as tie-ins in McKean, Allegany, and Cattaraugus counties
A metering, regulation and delivery station in Erie County
Mainline block valves in McKean, Allegany, Cattaraugus and Erie counties; and
Access roads and contractor/staging yards in McKean, Allegany, Cattaraugus and Erie counties

Map of Proposed Northern Access Project

View map fullscreen | How FracTracker maps work

The above map shows the proposed pipeline (green) and related infrastructure (bright pink). The pale yellow and pink lines on the map are the existing pipelines that the Northern Access Project would tie into. Click here to explore the map fullscreen.

Project Purpose

National Fuel maintains that the goal of the proposed project would be to supply multiple markets in Western New York State and the Midwest. The project would also supply gas for export to Canada via the Empire Pipeline system, and New York and New England through the Tennessee Gas Pipeline 200 Line. The company anticipates that the project would be completed by late 2017 or early 2018. Proponents are hoping that NAPL will keep fuel prices low, raise tax revenues, and create jobs.

Push-back against this project has been widespread from citizens and environmental groups, including Sierra Club and RiverKeeper. This is despite an environmental assessment ruling in July 2016 that FERC saw no negative environmental impacts of the project. FERC granted a stamp of approval for the project on February 4, 2017.

Concerns about the Proposed Pipeline

The Bufffalo-Niagara Riverkeeper, asserts that the project presents multiple threats to environmental health of the Upper Lake Erie and Niagara River Watersheds. In their letter to FERC, they disagreed with the Commission’s negative declaration that the project would result in “no significant impact to the environment.” The pipeline construction will require crossings of 77 intermittent and 60 perennial streams, 19 of which are classified by the New York State Department of Environmental Conservation (NYS DEC) as protected trout streams. Twenty-eight of the intermittent streams impacted also flow into these protected streams. Resulting water quality deterioration associated with bank destabilization, increased turbidity, erosion, thermal destabilization of streams, and habitat loss is likely to impact sensitive native brook trout and salamanders. Riverkeeper found that National Fuel’s plan on how to minimize impacts to hundreds of wetlands surround the project area was insufficient. FERC’s Environmental Assessment of the project indicated that approximately 1,800 acres of vegetation would affected by the project.

Several groups have also taken issue with the proposed project’s plan to use the “dry crossing” method of traversing waterways. Only three crossings will be accomplished using horizontal directional drilling under the stream bed — a method that would largely protect the pipes from dynamic movement of the stream during floods. The rest will be “trenched” less than 5 feet below the stream bed. Opponents of the project point out that NYSDEC, federal guidelines, and even industry itself discourage pipe trenching, because during times of high stream flow, stream scour may expose the pipes to rocks, trees, and other objects. This may lead to the pipes leaking, or even rupturing, impacting both the natural environment, and, potentially, the drinking water supply.

A December 2016 editorial to The Buffalo News addressed the impacts that the proposed Northern Access Project could have to the Cattaraugus Creek Basin Aquifer, the sole source of drinking water for 20,000 residents in surrounding Cattaraugus, Erie, and Wyoming counties in New York. In particular, because the aquifer is shallow, and even at the surface in some locations, it is particularly vulnerable to contamination. The editorial took issue with the absence of measures in the Environmental Assessment that could have explored how to protect the aquifer.

Other concerns include light and noise pollution, in addition to well-documented impacts on climate change, created by fugitive methane leakage from pipelines and compressors.

NYSDEC has held three public hearings about the project already: February 7^th at Saint Bonaventure University (Allegany, NY), February 8^th at Iroquois High School (Elma, NY), February 9^th at Niagara County Community College (Sanborn, NY). The hearing at Saint Bonaventure was attended by nearly 250 people.

While FERC approved the project on February 4, 2017, the project still requires approvals from NYSDEC – including a Section 401 Water Quality Certification. These decisions have recently been pushed back from March 1 to April 7.

Proponents for the project – particularly the pipefitting industry – have emphasized that it would create up to 1,700 jobs during the construction period, and suggested that because of the experience level of the construction workforce, there would be no negative impacts on the streams. Other speakers emphasized National Fuel’s commitment to safety and environmental compliance.

Seneca Nation President Todd Gates expressed his concerns about the gas pipeline’s impacts on Cattaraugus Creek, which flows through Seneca Nation land (Cattaraugus Indian Reservation), and is downstream from several tributaries traversed by the proposed pipeline. In addition, closer to the southern border of New York State, the proposed pipeline cuts across tributaries to the Allegheny River, which flows through the Allegany Indian Reservation. One of New York State’s primary aquifers lies beneath the reservation. The closest that the proposed pipeline itself would pass about 12 miles from Seneca Nation Territory, so National Fuel was not required contact the residents there.

Concerns about Wheatfield dehydration facility & Pendleton compressor station

According to The Buffalo News, National Fuel has purchased 20 acres of land from the Tonawanda Sportsmen’s Club. The company is building two compressors on this property, totaling 22,000 HP, to move gas through two miles of pipeline that are also part of the proposed project, but 23 miles north of the primary stretch of newly constructed pipeline. Less than six miles east of the Pendleton compressor stations, a dehydration facility is also proposed. The purpose of this facility is to remove water vapor from the natural gas, in accordance with Canadian low-moisture standards. According to some reports from a National Fuel representative, the dehydration facility would run only a few days a year, but this claim, has not been officially confirmed.

Residents of both Pendleton and Wheatfield have rallied to express their concerns about both components of the project, citing potential impacts on public health, safety, and the environment relating to air and water quality.

Northern Access Project Next Steps

The deadline for public comment submission is 5 pm on February 24, 2017 — less than two weeks away. To file a comment, you can either email NYS DEC directly To Michael Higgins at NFGNA2016Project@dec.ny.gov, or send comments by mail to NYS DEC, Attn. Michael Higgins, Project Manager, 625 Broadway, 4th Floor, Albany, NY 12233.

Note: this article originally stated that the Porterville Compressor Station would double its capacity as a result of the NAPL project. In fact, the capacity increase would be ten-fold, from 600 hp to about 6000 hp. We regret this error.

by Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance

Power Plants & Other Facilities Now on Ohio Oil & Gas Map

February 13, 2017/by Ted Auch, PhD

Over the last few months we’ve been busy working on some updates to our Ohio Oil & Gas Map. Check out what we’ve added recently and explore the map below!

New: Power Plants & ATEX Pipeline

We now have the locations of eight of the credible natural gas power plants proposed in Ohio, along with the jobs they cite during construction and operations. We also now have a complete inventory of 118 existing power plants, including 25 natural gas facilities. Together, these plants would produce 7,660 megawatts, around 957 per facility.

Six of these plants are either in the heart of Ohio’s Utica Shale or within several miles of the 1,200+ mile Appalachia-to-Texas (ATEX) pipeline. ATEX was installed to transport 190,000 barrels per day (BPD) of natural gas liquids (NGLs) from the Marcellus and Utica region to the Texas and Louisiana Gulf Goast refinery corridor. The 360 mile segment of this pipeline that runs from Pennsylvania to south central Jackson County, Indiana is also now shown on the Ohio Oil & Gas Map.

Late Permitting Increases

Cumulative and Monthly Ohio Utica Hydraulic Fracturing Well Permits

Figure 1. Cumulative and monthly hydraulic fracturing well permits in Ohio’s Utica Shale

While many shale plays across the United States are experiencing a period of contraction (with low gas prices often cited as the primary reason), drilling activity in Ohio’s Utica Shale has been experiencing a slow and steady expansion. The region has seen more than 2,700 permitted wells as of the end of January 2017. Incidentally, roughly 59% of these wells are producing either oil or gas as of Q3-2016. For more information on that subject, explore our production map.

The permitting trajectory hit a low of 13-16 permits per month between February and January of 2016. Since the presidential election in November, however, permitting rates have more than doubled (Figure 1).

Ohio Oil & Gas Map

Ohio sits on the western edge of both the Utica and Marcellus Shale formations, but conditions are such that the Marcellus Shale is all but being ignored in Ohio. Explore our updated map of OH drilling activity and related facilities below:

View map fullscreen | How FracTracker maps work

Map Layers

The map above is made up of various datasets, from the location of permits to compressor stations. These “map layers” make up the legend. Below we describe each layer on the map, as well as the data source and date range.

Horizontal Marcellus Permits, Laterals
There have been 40+ permits issued for horizontal wells in Ohio’s Marcellus Shale.

Source: Ohio Department of Natural Resources
Date Range: December 2009 – Present

Horizontal Utica Permits
An aggregate of ODNR’s monthly cumulative Utica and Marcellus permits as well as a more detailed weekly Risk Based Data Management System (RBDMS) Microsoft Access inventory. At the present time Ohio is home to 2,160+ permitted Utica Wells with the wells broken out by status. Additionally this layer contains depth, water usage, sand usage, HCl, and Gelling Agent percentage for 249 wells based on data provided to FracFocus. Finally, we have incorporated production in various units from individual industry press releases and the ODNR annual report.

Source: Ohio Department of Natural Resources
Date Range: December 2009 – Present

Horizontal Utica Permits actual and straight line laterals
An aggregate of ODNR’s monthly cumulative Utica and Marcellus permits as well as a more detailed weekly Risk Based Data Management System (RBDMS) Microsoft Access inventory. At the present time we have straight line laterals for all drilled, drilling, and producing wells as well as actual PLAT laterals for 341 of the wells.

Source: Ohio Department of Natural Resources
Date Range: December 2009 – Present

High Volume Hydraulic Fracturing Gathering Lines
All gathering lines servicing Ohio’s inventory of High Volume Hydraulic Fracturing (HVHF) wells.

Source: Herbert Hoover Foundation grant
Date Range: December 2009 – 2015

High Volume Hydraulic Fracturing Well Pads
The well-pads of all Ohio’s drilled or producing High Volume Hydraulic Fracturing (HVHF) wells.

Source: Herbert Hoover Foundation grant
Date Range: December 2009 – 2015

High Volume Hydraulic Fracturing Well Pad’s Limits Of Disturbance (LOD)
Limits Of Disturbance (LOD) for all Ohio’s drilled or producing High Volume Hydraulic Fracturing (HVHF) well-pads.

Source: Herbert Hoover Foundation grant
Date Range: December 2009 – 2015

Compressor Stations and Cracking Facilities
Boundaries of several confirmed High Volume Hydraulic Fracturing (HVHF) servicing cracking and compressor station facilities.

Source: Herbert Hoover Foundation grant
Date Range: December 2009 – 2015

Ohio Active Class II Injection Wells
This data speaks to the state’s “Active” Class II Injection wells able to accept hydraulic fracturing waste. There are 240+ Active Wells with 51 having yet to receive waste from hydraulic fracturing. For more on Ohio’s Class II Inventory in depth refer to our recent Ohio Fracking Waste Transport & Disposal Network article.

Source: Ohio Department of Natural Resources
Date Range: Historical to October, 2015

Earthquakes of >2.0 Magnitude
This data speaks to the state’s 258 earthquakes with current updates from the Ohio Seismic Network and historical quakes – all >2.0 magnitude. These data come from the department’s inventory. Additionally, we present Ohio earthquakes with <2.0 magnitude courtesy of Environment Canada’s Search the Earthquake Database platform.

Source: Ohio Department of Natural Resources, Division of Geological Survey, The Ohio Seismic Network
Date Range: Historical to Present

Remaining Questions on Mariner East Technical Deficiencies

February 9, 2017/by FracTracker Alliance

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:

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

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):

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

Offshore oil and gas development in CA - Photo by Linda Krop Environmental Defense Center

More offshore drilling and “fracking” in California

February 7, 2017/by Kyle Ferrar, MPH

Offshore oil and gas development is expanding in CA. This article explores the state’s regulatory framework, existing data, and data discrepancies.

Federal Regulations for Offshore Fracking

In the summer of 2016 the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) jointly released an environmental study that reviewed offshore fracking operations. The report found that operations have a minimal impact on marine health. For a review of California’s offshore oil and gas operations, see FracTrackers Alliance’s coverage of the collaborative report with the Environmental Defense Center, the Dirty Water Report.

As ThinkProgress reports, these two federal agencies will now resume the approval of offshore fracking permits. In response, Governor Jerry Brown made a plea to President Obama, to prevent fracking off California’s coast. Governor Brown asked President Obama to institute a permanent ban on all new offshore oil and gas drilling in federal waters, saying:

California is blessed with hundreds of miles of spectacular coastline; home to scenic state parks, beautiful beaches, abundant wildlife and thriving communities,” Brown wrote in a letter to Obama. “Clearly, large new oil and gas reserves would be inconsistent with our overriding imperative to reduce reliance on fossil fuels and combat the devastating impacts of climate change.

A new report by Liza Tucker at Consumer Watchdog has reviewed the state regulatory agency’s own policies under the Brown Administration. The report claims, “Brown has nurtured drilling and hydraulic fracturing in the state while stifling efforts to protect the public.” The report asks Governor Brown to “direct regulators to reject any drilling in a protected coastal sanctuary, ban offshore fracking, and phase out oil drilling in state waters” among other recommendations.

Read "How Green is Jerry Brown?" Report

California Data & Discrepancies

FracTracker Alliance reviewed the data published by DOGGR on permitted offshore wells. (DOGGR refers to the Division of Oil, Gas, & Geothermal Resources, which regulates drilling in CA). Using API identification numbers as a timeline, we actually find that it is likely that 238 wells have been drilled offshore since the start of 2012. The DOGGR database only lists “spud” (drilling) and completion dates for 71 – a mere 1.3% of the 5,435 total offshore wells. DOGGR reports that 1,366 offshore wells are currently active production wells. It must be noted that these numbers are only estimations, since operators have a 2-year window to drill wells after receiving a permit and API number.

Using these methods of deduction, we find that since the beginning of 2012 the majority of offshore wells have been drilled offshore of Los Angeles County in the Wilmington Oil Field (204 in total); followed by 25 offshore in the Huntington Beach field; 7 in the West Montalvo field offshore of Ventura County, and 1 in the Belmont field, also offshore of Ventura County. These wells are shown as bright yellow circles in the map below. Additionally, the Center for Biological Diversity reports that at least 200 of the wells off California’s coast have been hydraulically fractured.

Offshore Oil and Gas Development and SB4-Approved Well Stimulations

View map fullscreen | How FracTracker maps work

In total, DOGGR data shows 5,435 offshore oil and gas wells. Of those listed as active, new or idle, they break down into well types as shown in Table 1 below.

Table 1. Offshore oil and gas well types

Well Type	Count
Oil and Gas Production	1,539
Dry Gas	5
Waste Disposal	14
Steam Flood	2
Water Flood	813
Pressure Maintenance	3
Observation	8

New Fracking under SB4 Rules

The map above also shows several datasets that detail the stimulation activity that has been occurring in California since the passage of SB4 under Jerry Brown. Prior to the adoption of the new stimulation regulations on July 1, 2015, operators submitted applications and received permits for a total of 2,130 wells. These well permits are shown in the map labeled “CA SB4 Interim Well Stimulation Permits.” Since July of 2015, 596 of these permitted wells have been stimulated. In the map above, the layer “CA SB4 Well Stimulation Disclosures” shows the time series of these wells. An additional 31 well stimulation treatment permit applications have been submitted to DOGGR, since the adoption of the final rules on July 1, 2015. They are shown in the map, labeled “CA SB4 Well Stimulation Treatment Permit Applications.”

Offshore drilling cover photo by Linda Krop, Environmental Defense Center

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

Pipeline Under Debate in Louisiana Bayou

January 3, 2017/by Karen Edelstein

The 30-inch Bayou Bridge Pipeline began operations in April of 2016, with a short leg of pipeline that ran from Nederland, Texas to refineries in Lake Charles, Louisiana. But this 60-mile long pipeline, operated by Sunoco Logistics Partners, was just the first step in a much lengthier, and more controversial, 24-inch diameter pipeline project (jointly owned by Sunoco Logistics Partners, as well as Phillips 66 Partners and Energy Transfer Partners). Nonetheless, Bayou Bridge Pipeline, LLC argues that transport of crude oil by pipeline rather than by tanker or train, is the safest transportation option, as they continue to advocate and justify more pipeline construction in the name of “energy independence.” They compare its necessity to that of FedEx, a mere “delivery system”—one that would carry 280,000 barrels of light or heavy crude across the Acadiana terrain. The company building the pipeline, in fact, distances itself from problems that could result after oil starts flowing:

The pipeline is merely a delivery system, similar to FedEx, to help fill a need that already exists to ship the crude to refiners and market. We do not own the crude in the pipeline,” Alexis Daniel, of Granado Communications Group, a public relations firm in Dallas, wrote in an email response to questions posed to Energy Transfer Partners. Source

Developers hope that second phase of the proposed Bayou Bridge Pipeline will be put into operation during the second half of 2017. It would run 162 miles from Lake Charles, LA to refineries in St James, LA. It would cross the 11 Louisiana parishes and over 700 acres of fragile wetlands, and watersheds that supply drinking water for up to 300,000 people. Pump stations are planned for Jefferson Davis and St. Martin parishes. St. James is located on the western bank of the Mississippi River, about 50 miles upstream of New Orleans. In addition, the proposed pipeline crosses the state-designated Coastal Zone Boundary, an area targeted by Louisiana for special consideration relating to ecological and cultural sustainability.

Map of Proposed Louisiana Bayou Bridge Pipeline

View map fullscreen | How FracTracker maps work

Zoom in closer to the area around the Bayou Bridge Pipeline, and the National Wetlands Inventory data should appear. Use the “Bookmarks” tab to zoom in close to the refinery sites, and also to zoom back out to the full extent of the proposed Bayou Bridge Pipeline.

What’s the connection to the DAPL?

The 2010 BP Gulf oil spill resulted in $18 billion in settlements and penalties. With protests in the news about the impacts the Dakota Access Pipeline (DAPL) could pose to drinking water for the Standing Rock Sioux Reservation should another oil spill occur along the Missouri River, it’s no surprise that environmentalists are also calling for an environmental impact statement about the proposed extension of the Bayou Bridge Pipeline.

Acadiana is already criss-crossed by a dense network of pipelines leading to Gulf Coast refineries. Nonetheless, the process of building the proposed Bayou Bridge pipeline, the Atchafalaya Basin, a major watershed of the Gulf of Mexico, will see additional and significant impacts. Even if the construction process happens without a hitch, 77 acres of wetlands would be permanently affected, and 177 acres would be temporarily affected, along with the wildlife and aquatic species that live there. Within a 5-mile buffer area of the pipeline, National Wetlands Inventory has mapped over 600 square miles of forested wetlands, nearly 300 square miles of estuarine wetlands, and 63 square miles of freshwater emergent wetlands. Essential ecosystem services that the wetlands provide, absorbing floodwaters, could be compromised, leading to increased erosion and sedimentation downstream. Impacts to these wetlands could be greatly magnified into the already environmentally stressed Gulf.

The connection between DAPL and Bayou Bridge is both figurative and literal. Like most new pipelines, concerns about spills loom large in the minds of many. A new pipeline represents more money that is not being directed toward clean energy alternatives.

Energy Transfer Partners, the same company building DAPL, is also building the Bayou Bridge, which the final leg of the Dakota Access Pipeline, 1300 miles to the north. The two pipelines would be connected by a 700+-mile-long stretch of Energy Transfer Partner’s 30-inch Trunkline. This pipeline, which has been a gas transmission line, was proposed in 2012 for conversion from gas to crude transport. The project was cancelled in 2014, and reworked to use 678 miles of the original Trunkline, and also add 66 miles of new pipeline. When it is online, the flow direction of the Trunkline pipeline would reversed to accommodate the south-flowing crude.

Other unanticipated impacts

Interestingly, if crude oil transport to Gulf Coast refineries is diverted to pipelines rather than traditional rail or barge transport, some industry analysts predict that transportation using those modes of conveyance will shift more to the Atlantic and Pacific coasts.

A chance for public input

Environmental groups, including a coalition the comprises the Sierra Club, the Gulf Restoration Network, and the Louisiana Bucket Brigade, the Atchafalaya Basinkeeper, as well as concerned citizens, and landowners (some of whom already have multiple pipelines crossing their properties) are making their resistance to the pipeline heard, loud and clear about the need for a full environmental impact statement that will address the cumulative and indirect impacts of the project.

Note

In response to public outcry, the Louisiana Department of Environmental Quality has agreed to hold a public hearing about the Bayou Bridge Pipeline extension. The meeting will take place at 6 p.m. on January 12 in the Oliver Pollock Room of the Galvez Building, 602 North 5th St. in Baton Rouge.

Update, 6 February 2017. Here’s an article that features information about the January 12 public meeting, which was packed to capacity.

By Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance