Bird's eye view of an injection well (oil and gas waste disposal)

A Disturbing Tale of Diminishing Returns in Ohio

Utica oil and gas production, Class II injection well volumes, and lateral length trends from 2010-2018

The US Energy Information Administration (EIA) recently announced that Ohio’s recoverable shale gas reserves have magically increased by 11,076 billion cubic feet (BCF). This increase ranks the Buckeye State in the top 5 for changes in recoverable shale natural gas reserves between 2016 and 2017 (pages 31- 32 here). After reading the predictable and superficial media coverage, we thought it was time to revisit the data to ask a pertinent question: What is the fracking industry costing Ohio?

Recent Shale Gas Trends in Ohio

According to the EIA’s report, Ohio currently sits at #7 on their list of proven reserves. It is estimated there are 27,021 BCF of shale gas beneath the state (Figure 1).

Graph of natural gas reserves in different states 2016-2017

Figure 1. Proven and change in proven natural gas reserves from 2016 to 2017 for the top 11 states and the Gulf of Mexico (calculated from EIA’s “U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2017”).

There are a few variations in the way the oil and gas industry defines proven reserves:

…an estimated quantity of all hydrocarbons statistically defined as crude oil or natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proven if economic producibility is supported by either actual production or conclusive formation testing. – The Organization of Petroleum Exporting Countries

… the quantity of natural resources that a company reasonably expects to extract from a given formation… Proven reserves are classified as having a 90% or greater likelihood of being present and economically viable for extraction in current conditions… Proven reserves also take into account the current technology being used for extraction, regional regulations and market conditions as part of the estimation process. For this reason, proven reserves can seemingly take unexpected leaps and drops. Depending on the regional disclosure regulations, extraction companies might only disclose proven reserves even though they will have estimates for probable and possible reserves. – Investopedia

What’s missing from this picture?

Neither of the definitions above address the large volume of water or wastewater infrastructure required to tap into “proven reserves.” While compiling data for unconventional wells and injection wells, we noticed that the high-volume hydraulic fracturing (HVHF) industry is at a concerning crossroads. In terms of “energy return on energy invested,” HVHF is requiring more and more resources to stay afloat.

OH quarterly Utica oil & gas production along with quarterly Class II injection well volumes:

The map below shows oil and gas production from Utica wells (the primary form of shale gas drilling in Ohio). It also shows the volume of wastewater disposed in Class II salt water disposal injection wells.


 View map fullscreen | How FracTracker maps work

Publications like the aforementioned EIA article and language out of Columbus highlight the nominal increases in fracking productivity. They greatly diminish, or more often than not ignore, how resource demand and waste production are also increasing. The data speak to a story of diminishing returns – an industry requiring more resources to keep up gross production while simultaneously driving net production off a cliff (Figure 2).

Graph of Utica permits in Ohio on a cumulative and monthly basis along with the average price of West Texas Intermediate (WTI) and Brent Crude oil per barrel from September, 2010 to December, 2018

Figure 2. Number of Utica permits in Ohio on a cumulative and monthly basis along with the average price of West Texas Intermediate (WTI) and Brent Crude oil per barrel from September 2010 to December 2018

The Great Decoupling of New Year’s 2013

In the following analysis, we look at the declining efficiency of the HVHF industry throughout Ohio. The data spans the end of 2010 to middle of 2018. We worked with Columbus-area volunteer Gary Allison to conduct this analysis; without Gary’s help this work and resulting map, would not have been possible.

A little more than five years ago today, a significant shift took place in Ohio, as the number of producing gas wells increased while oil well numbers leveled off. The industry’s permitting high-water mark came in June of 2014 with 101 Utica permits that month (a level the industry hasn’t come close to since). The current six-month permitting average is 25 per month.

As the ball dropped in Times Square ringing in 2014, in Ohio, a decoupling between oil and gas wells was underway and continues to this day. The number of wells coming online annually increased by 229 oil wells and 414 gas wells.

Graph showing Number of producing oil and gas wells in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Figure 3. Number of producing oil and gas wells in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Graph of Producing oil and gas wells as a percentage of permitted wells in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Figure 4. Producing oil and gas wells as a percentage of permitted wells in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Permits

The ringing in of 2014 also saw an increase in the number of producing wells as a percentage of those permitted. In 2014, the general philosophy was that the HVHF industry needed to permit roughly 5.5 oil wells or 7 gas wells to generate one producing well. Since 2014, however, this ratio has dropped to 2.2 for oil and 1.4 for gas well permits.

Put another way, the industry’s ability to avoid dry wells has increased by 13% for oil and 18% for gas per year. As of Q2-2018, viable oil wells stood at 44% of permitted wells while viable gas wells amounted to 71% of the permitted inventory (Figure 4).

Production declines

from the top-left to the bottom-right

To understand how quickly production is declining in Ohio, we compiled annual (2011-2012) and quarterly (Q1-2013 to Q2-2018) production data from 2,064 unconventional laterals.

First, we present average data for the nine oldest wells with respect to oil and gas production on a per day basis (Note: Two of the nine wells we examined, the Geatches MAH 3H and Hosey POR 6H-X laterals, only produced in 2011-2012 when data was collected on an annual basis preventing their incorporation into Figures 6 and 7 belwo). From an oil perspective, these nine wells exhibited 44% declines from year 1 to years 2-3 and 91% declines by 2018 (Figure 5). With respect to natural gas, these nine wells exhibited 34% declines from year 1 to years 2-3 and 79% declines by 2018 (Figure 5).

Figure 5. Average daily oil and gas production decline curves for the above seven hydraulically fractured laterals in Ohio’s Utica Shale Basin, 2011 to Q2-2018

Four of the nine wells demonstrated 71% declines by the second and third years and nearly 98% declines by by Q2-2018 (Figure 6). These declines lend credence to recent headlines like Fracking’s Secret Problem—Oil Wells Aren’t Producing as Much as Forecast in the January 2nd issue of The Wall Street Journal. Four of the nine wells demonstrated 49% declines by the second and third years and nearly 81% declines by Q2-2018 (Figure 7).

Figure 6. Oil production decline curves for seven hydraulically fractured laterals in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Figure 7. Natural gas production decline curves for seven hydraulically fractured laterals in Ohio’s Utica Shale Basin from 2011 to Q2-2018

Fracking waste, lateral length, and water demand

from bottom-left to the top-right

An analysis of fracking’s environmental and economic impact is incomplete if it ignores waste production and disposal. In Ohio, there are 226 active Class II Salt Water Disposal (SWD) wells. Why so many?

  1. Ohio’s Class II well inventory serves as the primary receptacle for HVHF liquid waste for Pennsylvania, West Virginia, and Ohio.
  2. The Class II network is situated in a crescent shape around the state’s unconventional wells. This expands the geographic impact of HVHF to counties like Ashtabula, Trumbull, and Portage to the northeast and Washington, Athens, and Muskingum to the south (Figure 8).
Map of Ohio showing cumulative production of unconventional wells and waste disposal volume of injection wells

Figure 8. Ohio’s unconventional gas laterals and Class II salt water disposal injection wells. Weighted by cumulative production and waste disposal volumes to Q3-2018.

Disposal Rates

We graphed average per well (barrels) and cumulative (million barrels) disposal rates from Q3-2010 to Q3-2018 for these wells. The data shows an average increase of 24,822 barrels (+1.05 million gallons) per well, each year.

That’s a 51% per year increase (Figure 9).

A deeper dive into the data reveals that the top 20 most active Class II wells are accepting more waste than ever before: an astounding annual per well increase of 728,811 barrels (+30.61 million gallons) or a 230% per year increase (Figure 10). This divergence resulted in the top 20 wells disposing of 4.95 times the statewide average between Q3-2010 and Q2-2013. They disposed 13.82 times the statewide average as recently as Q3-2018 (Figure 11).

All of this means that we are putting an increasing amount of pressure on fewer and fewer wells. The trickle out, down, and up of this dynamic will foist a myriad of environmental and economic costs to areas surrounding wells. As an example, the images below are injection wells currently under construction in Brookfield, Ohio, outside Warren and minutes from the Pennsylvania border.

More concerning is the fact that areas of Ohio that are injection well hotspots, like Warren, are proposing new fracking-friendly legislation. These disturbing bills would lubricate the wheels for continued expansion of fracking waste disposal and permitting. House bills 578 and 393 and Senate Bill 165 monetize and/or commodify fracking waste by giving townships a share of the revenue. Such bills “…would only incentivize communities to encourage more waste to come into their existing inventory of Class II… wells, creating yet another race to the bottom.” Co-sponsors of the bills include Democratic Reps. Michael O’Brien, Glenn Holms, John Patterson, and Craig Riefel.

Lateral Lengths

The above trends reflect an equally disturbing trend in lateral length. Ohio’s unconventional laterals are growing at a rate of 9.1 to 15.6%, depending on whether you buy that this trend is linear or exponential (Figure 12). This author believes the trend is exponential for the foreseeable future. Furthermore, it’s likely that “super laterals” in excess of 3-3.5 miles will have a profound impact on the trend. (See The Freshwater and Liquid Waste Impact of Unconventional Oil and Gas in Ohio and West Virginia.)

This lateral length increase substantially increases water demand per lateral. It also impacts Class II well disposal rates. The increase accounts for 76% of the former and 88% of the latter when graphed against each other (Figure 13).

Figure 12. Ohio Utica unconventional lateral length from Q3-2010 to Q4-2018

Figure 13. Ohio Utica unconventional water demand and Class II SWD injection well disposal volumes vs lateral length from Q3-2010 to Q4-2018.

Conclusion

This relationship between production, resource demand, and waste disposal rates should disturb policymakers, citizens, and the industry. One way to this problem is to more holistically price resource utilization (or stop oil and gas development entirely).

Unfortunately, states like Ohio are practically giving water away to the industry.

Politicians are constructing legislation that would unleash injection well expansion. This would allow disposal to proceed at rates that don’t address supply-side concerns. It’s startling that an industry and political landscape that puts such a premium on “market forces” is unwilling to address these trends with market mechanisms.

We will continue to monitor these trends and hope to spread these insights to states like Oklahoma and Texas in the future.

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance – with invaluable data compilation assistance from Gary Allison


Data Downloads

FracTracker is a proponent of data transparency, and so we often share the data we use to construct our maps analyses. Click on the links below to download the data associated with the present analysis:

  • OH Utica laterals

    Ohio’s Utica HVHF laterals as of December 2018 in length (feet) (zip file)
  • Wastewater disposal volumes

    Inventory of volumes disposed on a quarterly basis from 2010 to Q3-2018 for all 223 active Class II Salt Water Disposal (SWD) Injection wells in Ohio (zip file)
Map of offshore drilling in California

The Feds Trump California’s State Ban on Offshore Oil Drilling

Offshore drilling in the United States federal waters has caused the most environmentally destructive disasters in North America. Yet, new policy is pushing for the expansion of offshore drilling, particularly off the coast of California.

Offshore Drilling History

In 1969, Union Oil’s offshore rig Platform A had a blowout that leaked 100,000 barrels into the Santa Barbara Channel, one of the most biologically diverse marine environments in the world. The spill lasted ten days and killed an estimated 3,500 sea birds, as well as an untold number of marine mammals. Unbelievably, the Santa Barbara spill is only the third largest spill in U.S. waters. It follows the 1989 Exxon Valdez and the 2010 Deepwater Horizon spills. These incidents keep getting bigger.

More offshore drilling means a higher risk of catastrophe, additional contamination of air and water locally, and more greenhouse gas emissions globally.

Federal Moratorium on California Offshore Leases

Up until the beginning of 2018, further oil and gas development using offshore oil rig platforms seemed quite unlikely. After the 1969 oil spill from Platform A and the subsequent ban on further leasing in state waters, the risk of another devastating oil spill was too large for even the federal government to consider new leases. The fact that the moratorium lasted through 16 years of Bush presidencies is truly a victory. Across the aisle, expanding offshore operations has been opposed. In Florida, even Republican Governor Rick Scott teamed up with environmental groups to fight the Department of Interior’s recent sales of offshore leases.

Trump’s New Gas Leasing Program

Now, the U.S. Bureau of Ocean Energy Management (BOEM) is preparing a new 2019-2024 national Outer Continental Shelf (OCS) oil and gas leasing program to replace the existing 2017-2022 program. This is an unusual practice, and part of Trump’s America-First Offshore Energy Strategy. The Trump administration opened up most of the US coastal waters for new oil and gas drilling with a recent draft proposal offering 47 new offshore block lease sales to take place between 2019 and 2024.

Where might these new leases occur?

The offshore federal waters that are open for oil and gas leases are shown in dark blue in the map below (Figure 1). Zoom out to see the extent.

Figure 1. Map of Offshore Oil and Gas Extraction


View map fullscreen | How FracTracker maps work | Map Data Download (CSV)

California’s Offshore Oil

Southern California has a legacy of oil extraction, particularly Los Angeles. It’s not just the federal government that is keen on continuing this legacy. While the state has not permitted the leasing of new blocks in offshore waters, Governor Brown’s policies have been very friendly to the oil and gas industry. According to Oil Change International’s Sky’s the Limit report: “Under the Brown administration, the state has permitted the drilling of more than 20,000 new wells,” including 5,000 offshore wells in state waters. About 2,000 of these offshore wells have been drilled since 2012.

This map developed in collaboration with Consumer Watch Dog juxtaposes the offshore wells drilled in CA state waters with those drilled in federal waters.

Southern California is the main target for future offshore leasing. The Monterey Shale formation, which underlies the city of Los Angeles and expands north offshore to the Ventura Coast, is thought to contain the largest conventional oil plays left IN THE WORLD! The map above shows the locations of state and federal offshore oil and gas wells and the rigs that service them. It also shows historical wells off the coast of Northern California.

Northern California, both onshore and offshore, sits on top of major reserves of natural gas, which may also be developed given the political climate. With an increase in the price of natural gas, operators will be developing these gas fields. Some operators, such as Chevron, have already drilled natural gas wells in northern California, but have left the wells “shut in” (capped) until production becomes more profitable.

For a more comprehensive coverage on environmental impacts of offshore operations, including those to sensitive species, check out the Environmental Defense Center’s Dirty Water Report and read our additional coverage of California’s existing offshore drilling, and offshore fracking.

Air Pollution from Oil Rigs

FracTracker, in collaboration with Earthworks, recently teamed up with the Center for Biological Diversity and Greenpeace International to get up close to offshore oil rigs. As a certified Optical Gas Imaging Thermographer, Kyle Ferrar (Western Program Coordinator for FracTracker Alliance and California Community Empowerment Project Organizer for Earthworks), took footage of the offshore oil rigs.

Using infrared technology, we were able to visualize and record emissions and leaks of volatile hydrocarbons and other greenhouse gases coming from these offshore sites. We documented many cases of intense flaring from the rigs, including several cases where the poorly burning flare allowed hydrocarbons to be leaked to the atmosphere prior to complete combustion of CO2.

More complete coverage of this trip can be found here on the Greenpeace website.

Below you can view a compilation of the footage we were able to capture from small pontoon boats.

Conclusion

FracTracker has looked at offshore oil and gas drilling from many different angles. We have looked to the past, and found the most egregious environmental damages in U.S. history. We have analyzed the data and shown where, when, and how much offshore drilling is happening in California. We have demonstrated that much of the drilling and many of the proposed leases are in protected and sensitive habitats. We have looked at policy and found that both Governor Brown and President Trump are aligned to promote more oil and gas development. We have even looked at the rigs in person in multiple spectrums of light and found that these operations continuously leak and emit greenhouse gases and other air toxins.

No matter which way you look at offshore oil and gas drilling, it is clearly one of the most threatening methods of oil and gas extraction in use today.


By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

A map of deficiencies along the Falcon Pipeline Route

The Falcon Pipeline: Technical Deficiencies

Part of the Falcon Public EIA Project

In August 2016, Shell announced plans for the “Falcon Ethane Pipeline System,” a 97-mile pipeline network intended to feed Shell’s ethane cracker facility in Beaver County, Pennsylvania. In response to available data, FracTracker launched the Falcon Public EIA Project in January of 2018 to unearth the environmental and public health impacts of the proposed pipeline. As part of that project, today we explore Shell’s Chapter 105 application and the deficiencies the Pennsylvania Department of Environmental Protection (DEP) cited after reviewing Shell’s application.

Just a heads up… there are a lot.

Shell originally submitted a Chapter 105 application to the DEP to receive a permit for water obstruction and encroachment. The DEP began reviewing the application in January of 2018. On June 1st, they sent Shell technical deficiency letters listing several issues with the application. Shell responded to these deficiencies on August 1st.

Now, it’s up to the DEP to decide if Shell’s response is adequate, and if the department should go ahead and approve the application or require more work from Shell. Explore the technical deficiencies below for more information.

Technical Deficiencies

Below is a map that highlights several of the deficiencies the DEP found with Shell’s application and a brief explanation of each one. Expand the map full-screen to explore more layers – Some layers only become visible when you zoom in due to the level of detail they display.

View Map Full Screen | How Our Maps Work

Next, we’ll walk you through the technical deficiencies, which we have broken down into the following categories:

  1. Wetlands, rivers, streams
  2. Stormwater control
  3. Public health and safety (drinking water & trails)
  4. Conservation areas
  5. Alternative routes
  6. Geological concerns (including mining issues)
  7. Documentation issues
Legend

A = Allegheny County, B = Beaver County, W = Washington County. The numbers reference the number listed in the deficiencies letter.

1. Wetlands, Rivers, & Streams

Water withdrawal from rivers and discharge

  • B2 A2 W2 The project will discharge waste water from an industrial activity to a dry swale, surface water, ground water, or an existing sanitary sewer system or separate storm water system. The DEP requested that Shell identify and describe this discharge, as the DEP’s Clean Water Program must authorize discharges. Shell stated that water will be discharged from hydrostatic testing, (which ensures a pipeline can withstand high pressure by pumping water through it to test for leaks), and a PAG-10 permit (needed for hydrostatic test water discharge) was submitted to the DEP July 27, 2018 with the locations of discharge. Drawings of the discharges are in Attachment O. (The locations of the discharges were not included in Shell’s public response to this deficiency.)
  • B33 A31 W31 Shell will be withdrawing water for hydrostatic testing. The DEP asked Shell to explain the intake and discharge methods so the DEP can decide if these should be included as impacts. The DEP also asked Shell to provide the location of intake and discharge. The DEP’s Clean Water Program must authorize discharges. In response, Shell stated that water will be withdrawn from Raccoon Creek and the Ohio River in West Virginia. The specific locations are listed in the PAG-10 permit, submitted to the DEP in July. Drawings of the discharges are included in Attachment O.

Wetlands and Streams

  • B5 A3 W4 The DEP asked Shell to identify the presence of wetlands within the project area that are identified by the US Fish & Wildlife Service’s National Wetlands Inventory (NWI) data system, and provide data on how they may be impacted by the proposed pipeline.  Shell identified one NWI wetland in Beaver County, but did not delineate or provide information on it, due to safety concerns (it’s on a steep cliff). This wetland will be crossed via HDD (horizontal directional drill). In Allegheny County, there is an NWI wetland that Shell also did not provide data on. This wetland was not initially evident, and when staff returned to survey it, the property owner did not let them access the site because they did not want a pipeline on their property. According to Shell, this NWI wetland is not within the “Project’s Limit of Disturbance.” In Washington County, Shell stated that “all of the NWI-mapped wetlands that were determined not to be wetlands have been accounted for in Washington County. These NWI wetlands were all located in an area that had been previously strip-mined and due to mining activities, those wetlands are no longer there. Data were taken for these areas and included… separately as Attachment D.” Also in Washington County is an NWI wetland located above the Panhandle Trail, which Shell determined to be outside of the study area and therefore did not collect data on it. This wetland is not on the map, but Shell did provide this image of it.
  • B6 A4 W5 The DEP requested that Shell match off-line wetland data with sampling point locations from study area maps. In response, Shell placed offline data sheets in the order that they are in Table 3 in the Wetlands Delineation Report and in Table 4 in the Watercourse Delineation Report.
  • B7 A5 W6 Shell needed to discuss the types and conditions of riverine resources that the project impacts. Specifically, how the conditions of these resources relate to their hydrological functions, biogeochemical functions, and habitat attributes. These are discussed under question 7 for Beaver County, question 5 for Allegheny County, and question 6 for Washington County.
  • B8 A6 W7 Shell needed to discuss the types and conditions of wetlands that the project impacts. Specifically, how the conditions of these wetlands contribute to their hydrological functions, biogeochemical functions, and habitat attributes. Shell also needed to discuss impacts to wetlands that will be temporarily impacted, as it previously only discussed wetlands facing permanent impacts. These are discussed under question 8 for Beaver County, question 6 for Allegheny County, and question 7 for Washington County.
  • B9 A7 W8 The DEP asked Shell to evaluate the impact of open cut installation on wetlands with perched water tables and/or confining layers. Perched water tables have an impermeable confining layer (such as clay) between them and the main water table below. If open cut methods are used, the confining layer is destroyed and this water table will be lost. In Beaver County, Shell identified one wetland (W-PA-170222-MRK-002) will be open cut. If it is perched, Shell states it will replace the confining layer “along the same horizon during pipeline backfilling, and then [compact the layer] so that hydrology may be maintained.” Shell will also put trench plugs “on either side of the wetland on the ROW to prevent water from migrating out on the sides.” In Allegheny County, there are three wetlands potentially on perched water tables that will be open cut: W-PA-160401-MRK-006, W-PA-161220-MRK-001, and W-PA-161220-MRK-002.In Washington County, there are three wetlands potentially on perched water tables that will be open cut: W-PA-160407-JLK-002, W-PA-151203-MRK-005, and W-PA-151203-MRK-006.
  • A11 The DEP asked Shell to evaluate if any wetlands can be classified as “exceptional value” due to their proximity to nesting areas of the northern harrier (a threatened species in Pennsylvania). Wetlands are exceptional value if they serve as habitat for threatened or endangered species, or if they are hydrologically connected to or located within 0.5 miles of wetlands that maintain habitat for the species in the wetland. Shell determined that there are six wetlands that could be nesting areas for northern harriers, and therefore are exceptional value (W-PA-170207-MRK-002, W-PA-161205-WRA-001, W-PA-170207-MRK-003, W-PA-170207-MRK-001, W-PA-170113-MRK-008, W-PA-170113-MRK-001). Three of these wetlands are within the project’s LOD (W-PA-170207-MRK-002, W-PA-161205-WRA-001, W-PA-170207-MRK-003).
  • B13 A10 W11 The DEP asked Shell to evaluate whether the proposed Falcon Pipeline will impact wetlands that are of “exceptional value” based on their proximity to public water systems. Wetlands can be considered “exceptional value” if they are located along public or private drinking water supplies (surface or ground water), and help maintain the quality or quantity of the supply. Shell stated that the (potentially man made) ponds near public water supply A could be considered exceptional value, however, they are located outside of the project’s study area and were not delineated, therefore Shell does not have information on them or their impact to this well. There were no other wetlands Shell considered to be exceptional value based on their proximity to public water systems.
  • B21 There were two protected plant species- harbinger of spring (PA threatened) and purple rocket (PA endangered)- located within the Raccoon Creek floodplain. The DEP asked Shell to evaluate whether there are wetlands in the project area that should be considered “exceptional value” due to their proximity to these species. Wetlands are considered “exceptional value” if they serve as habitat for a threatened or endangered plant or animal species. They are also exceptional value if they are hydrologically connected to or located within 0.5 miles of wetlands that maintain the habitat of the species. There are six wetlands near populations of these plant populations: W-PA-151014-MRK-001, W-PA-151013-MRK-002, -003, and -004, W-PA-170407-JLK-001, W-PA151013-MRK-001. However, Shell stated that the harbinger of spring is not dependent on wetland habitat for survival and the species is considered an upland plant species (because it is not listed on Eastern Mountains and Piedmont List or on the National Wetland Plant List).  Purple rocket is listed as a “Facultative Wetland Plant” (FACW) on both lists. However, Shell stated that, “although it is a FACW, this plant is not one that occurs in wetlands,” and the population of purple rocket was found in an upland, disturbed area. Therefore, Shell determined that none of these wetlands are considered exceptional value.
  • B23 A21 W21 Shell needs to assess cumulative impacts to wetlands from the proposed pipeline and other existing projects and potential future projects. These are discussed in the Cumulative Impact Assessment document, Sections 4.1 and 4.2, and Tables B1 and B2.
  • B24 A22 W22 Shell needed to provide an explanation of how it will restore wetlands and streams disturbed during construction. The explanation needed to include information on seed mixes, shrubs, and trees that will restore stream banks and riparian areas.
  • B26 A24 W24 Shell needed to provide a table that lists, describes, and quantifies permanent impacts to wetlands and watercourses. Shell stated that there are no permanent fills associated with the project, but there will be permanent conversion impacts to the following wetlands. They total 10,862 ft2 or 0.25 acres in Beaver County, 5,166 ft2 (0.12 acres) in Allegheny County, and 4971 ft2 (0.11 acres) in Washington County. (W-PA-151013-JLK-005, W-PA-161202-MRK-001, W-PA-160404-MRK-001, W-PA-160412-CBA-004, W-PA-160412-CBA-001, W-PA-161205-WRA-003, W-PA-160401-MRK-005, W-PA-170213-JLK-003, W-PA-160406-MRK-001, W-PA-170413-RCL-005, W-PA-170214-CBA-005.)
  • B27 A25 W25 Shell needed to provide more information on the Neshannock Creek Restoration site, including a master restoration plan for the entire site. This mitigation is required to offset conversion impacts to wetlands along the pipeline route. The plan for the site is documented here.
  • B28 A26 W26 Shell needed to provide the location and resource crossing number for the HDDs in PA. They are listed in these tables:

Allegheny County:Table of Resources Falcon Pipeline Crosses by HDD in Allegheny County

Washington County:

Beaver County:

Table of water resources the Falcon pipeline crosses by HDD

2. Stormwater control

  • B3 A1 W1 Shell indicated that the project was in a floodplain project by the Commonwealth, a political subdivision of the commonwealth or a public utility. The DEP asked for an identification of this floodplain project, to which Shell responded that it misunderstood the question and the pipeline will not go through a floodplain project by one of these entities, but rather a floodway. The pipeline will pass many floodways, which are listed in Table 1 in separate documents for Beaver County, Allegheny County, and Washington County.
  • W3 The DEP requested that Shell provide an analysis of impact to Act 167 plans. Act 167 requires counties to create stormwater management plans and municipalities to adopt ordinances to regulate development in accordance with these plans. The pipeline route occurs in areas with Act 167 plans in Chartiers Township, Mount Pleasant Township, and Robinson Township.

3. Public health and safety

  • B1 The proposed pipeline does not meet the provisions of a zoning ordinance or have zoning approval in a particular area. Specifically, in Independence Township, the pipeline is within setback distances of places of congregation and/or of residences. One example is the Beaver County Conservation District, considered a place of congregation. Shell responded to this deficiency, saying it is working with Independence Township to obtain necessary approvals, and the township will “officially remove the pipeline ordinance from their records and no variances or permits will be required.”
  • B10 A8 W9 The DEP requested that Shell evaluate and discuss how the pipeline may impact public water systems that are within 1 mile of the pipeline route. Shell located 12 sites within a mile, most of which are ground water wells. One site is the Ambridge Water Authority, which provides drinking water for an estimated 30,000 people. Shell stated that impacts “might include an Inadvertent Return (IR) causing a bentonite slurry mix to enter the supply, which might contaminate the supply for any wells that are located near an HDD site or construction equipment.” Shell stated that all wells are a minimum of 1000 feet outside construction zones and built in thick bedrock which will minimize threat on contamination. The sites within 1 mile include:
    • Youthtowne Barn
    • Beaver County Conservation District
    • Independence Elementary School
    • Independence Volunteer Fire Department
    • McConnell’s Farm and Market, Inc
    • Ambridge Water Authority- Independence Township
    • Ambridge Water Authority- Raccoon Township
    • Hookstown Free Methodist Church
    • Hookstown Fair
    • Hookstown Grange
    • South Side Memorial Post 952
    • Jack’s Diner
    • NOVA Chemical, Inc
  • B11 A9 W10 The DEP asked Shell to discuss efforts to avoid/minimize impacts to the above public water systems, and suggested that efforts “might include, but are not limited to, considering alternative locations, routings or design for the proposed pipeline; providing provisions for shut-off in the event of break or rupture; etc.” Shell stated that the route avoids direct impacts to groundwater wells and surface water intake. Shell will provide water buffalos if wells are contaminated, and drill new wells if necessary. There are mainline valves approximately 7 to 7.5 miles apart that can automatically shut off the flow of ethane. There will also be staff living within the project area that can quickly respond to issues.
  • B12 The pipeline crosses headwaters of the Ambridge Reservoir and the Reservoir’s raw water service pipeline, which supplies water to 30,000 residents. The DEP noted significant public concern regarding this crossing, and asked Shell to evaluate and discuss the pipeline’s potential to affect the Reservoir and public water supply service. The DEP also asked Shell to elaborate on efforts to avoid/minimize impacts, and what measures will be implemented to mitigate any unavoidable impacts. In response, Shell stated the pipeline will cross the raw water line via an HDD  31 feet below the line. Shell explained that the water service line is made of pre-stressed concrete, which cannot be retrofitted in the field if a break occurs. It can take six weeks for pipe joints to be made and delivered from Ohio if there is a rupture. Shell stated it will supply extra pipe joints so the Ambridge Water Authority can have pieces on deck in case of a break. Shell also outlined the protective coatings and design of the HDD portion of the pipeline that will cross the water line, and said valves that can shut off the pipeline are located 2.4 miles from one side of the water line and 3.5 on the other.
  • A17 W17 The DEP asked Shell to consider the proposed pipeline’s effect on the Montour Trail, a multi-use, recreational trail, and to consider re-routes that would avoid impacts to the Trail. Shell determined that routing around the trail is not feasible. Shell will use conventional bore or HDD methods. If the trail needs to be temporarily closed during construction, operation, or maintenance, Shell will notify the trail owner and provide alternate temporary access for trail users. Shell will also cross the Panhandle Trail by HDD. The entrance and exit sights of the bore will not be on the trail’s property. Shell has “unlimited ingress and egress over Owners property” for inspections, repair and maintenance of the pipeline, and in case of emergency situations.
  • B29 A27 W27 Shell needed to revise the “Shell Pipeline HDD Procedure” to include HDD site feasibility analysis, inadvertent return risk assessment, water supply protection, agency contact information, etc. Shell’s response is included in the document, Inadvertent Returns from HDD: Assessment, Preparedness, Prevention and Response Plan.
  • B30 A28 W28 Shell needed to include a preboring geologic evaluation to determine if drinking water supplies will be impacted around boring locations. Shell also needed to discuss how it will verify that drinking water sources and aquifers are protected and what measures will be taken in the event that they are impacted. Shell’s response is included as Appendix C to this document.

4. Conservation

  • B19 A18 W18 19A 19W – There are many areas important for the region’s biodiversity and natural heritage that the proposed pipeline passes near or through. The DEP asked Shell to evaluate impacts to these areas. Information on them is available from the Pennsylvania Natural Heritage Program. They include:
    • Ambridge Reservoir Valleys Natural Heritage Area
    • Lower Raccoon Creek Natural Heritage Area
    • Raccoon Creek Valley and Wildflower Reserve Natural Heritage Area
    • Raccoon Creek Floodplain Biologically Diverse Area
    • Raccoon Creek Landscape Conservation Area
    • Clinton Wetlands Biologically Diverse Area
    • Raccoon Creek Landscape Conservation Area
    • Raccoon Creek Valley & State Park Important Bird Area – Regarding the Important Bird Area, Shell stated that 23 miles of the pipeline is located within this area. Shell has not been able to get in contact with the National Audobon SW PA office. Shell added that the only waterbody large enough in the project area to support the documented waterfowl is the open water at Beaver County Conservation District. Shell stated that “an outlet has been installed at the far end of the lake to restore it to more of a wetland and less of a lake, as it was originally designed.Raccoon Creek Valley is also a passageway for migratory birds, which are protected under the Migratory Bird Treaty Act. Shell stated that less than 2% of this Important Bird Area will be permanently impacted by pipeline construction and installation.

5. Alternative locations

  • B17 A15 W15 The DEP asked Shell to revise its current alternatives and provide a more detailed “analysis of the alternative locations and routes that were considered to avoid or minimize adverse environmental impacts.” The alternatives are discussed in Section 9 of Shell’s Comprehensive Environmental Assessment.
  • B18 16A 16W According to the DEP, “18.5 of the 45 miles (41%) of the proposed pipeline are parallel to or adjacent to existing right-of-ways (ROWs).” The DEP asked Shell to see if there are additional opportunities to build the pipeline within existing ROWs, with the hope of reducing environmental impacts. In response, Shell discussed the additional ROWs that were considered (along Mariner West) but ultimately rejected. Shell discusses these routes more in Section 9.1 of the Comprehensive Environmental Assessment.
  • B32 A30 W30 The DEP asked Shell to discuss the feasibility of several changes to the proposed pipeline’s route, including avoiding impacts to wetlands, relocating resource crossings, moving valve sites outside of wetlands, moving HDD locations, and evaluating the impact to a coal refuse pile (the pipeline crosses underneath at least one pile via HDD). These reroutes are discussed under question 32 for Beaver County, question 30 for Allegheny County, and question 30 for Washington County.

6. Geological concerns

  • B14 12A 12W The pipeline is located in previously coal mined areas. The DEP asked Shell to provide a map of the pipeline that showed these mining areas, and GIS shape files with this information. Shell’s response is included in the HDD Subsurface Investigation Reports, which includes the following table of the extent of mined areas along the pipeline route:
  • B15 A13 W13 The pipeline is located in coal mined areas, which could be susceptible to subsidence and/or mine water discharge. The DEP requested that Shell revise drawings to show the limits of previously mined areas, depth of cover over the mine workings in areas the proposed pipeline crosses through, and the distance between mine workings and the proposed pipeline. Furthermore, the DEP asked Shell to “evaluate and discuss the potential for a subsidence event compromising the utility line, and the potential to create a mine water discharge.” Shell discusses this in Appendix B of this this document and in the Mining Summary Report. Shell also identifies the following areas as being at risk for coal mine discharge: HOU MM 1.2, HOU MM 8.9 (proposed HDD), HOU MM 12.1, HOU MM 12.95, HOU MM 13.1, HOU MM 13.6, HOU MM 17.4, and HOU MM 17.65 (proposed HDD).
  • B16 A14 14W The DEP requested that Shell include areas where the pipeline will cross active mining permit boundaries. There is one active mining permit boundary that intersects the proposed pipeline, the Rosebud Mine in Beaver County.
  • B31 A29 W29 Shell needed to evaluate the potential for the project to encounter areas underlain by carbonate bedrock and landslide prone areas. Carbonate bedrock is indicative of a karst landscape, meaning an area likely to have underground sinkholes and caves. The DEP also asked Shell to discuss precautionary methods taken during construction in these areas. Shell’s response is included in the Carbonate Rock Analysis and Slope Stability and Investigation Report. The Carbonate Rock Analysis report shows that carbonate bedrock was encountered in 20 out of 40 of the borings taken during the analysis.

7. Documentation

  • B4 The PA DEP asked Shell to describe the structures and activities that occur within junction sites. Shell responded that there will be a Junction Custody Transfer Meter Station at the site, and provided maps of the site.
  • B22 20A 20w The DEP requested that Shell revise their Comprehensive Environmental Assessment to include alternatives, impacts, and mitigation items that were previously included in other sections of their environmental assessment.
  • B25 A23 W23 The DEP asked Shell to provide a copy of the Mitigation Bank Credit Availability Letter from First Pennsylvania Resource, LLC. In response, Shell stated the Letter is no longer needed because “the permanent stream and wetland fills have been removed from this project.”
  • B34 A32 W32 The DEP asked Shell to include a copy of the Preparedness, Prevention, and Contingency Plan.
  • B35 A33 W33 Shell needs to include all of the above modifications to the application in the Chapter 103 permit application.

Conclusion

As evidenced by the list above, the proposed Falcon Pipeline poses a variety of threats to Pennsylvania’s natural resources, wildlife, and public health – but this deficiencies list is likely not complete. The pipeline also passes through West Virginia and Ohio, and if completed, will likely attract more pipelines to the area. As it feeds Shell’s ethane cracker plant in Beaver County, it is a major step towards the region becoming a hub for plastic manufacturing. Therefore, the public response to the above deficiencies and the decision the DEP makes regarding them will have major implications for the Ohio River Valley’s future.

Of note: The DEP’s letters and Shell’s response to them are available to the public in separate documents for  Allegheny, Beaver, and Washington Counties. 


By Erica Jackson, Community Outreach and Communications Specialist

The proposed route for the Delmarva Pipeline. Map courtesy of FracTracker Alliance.

The Proposed Delmarva Pipeline: Environmental or economic justice concern?

A new plan is in the works to construct a natural gas pipeline that would run approximately 190 miles through Maryland. Lawmakers said in January they are anxious to see the Delmarva Pipeline built, but still want to exercise caution.

Starting in Cecil County, MD, and terminating in Accomack County, VA, the proposed Delmarva Pipeline is nearly the length of Maryland’s Eastern Shore. North Carolina-based Spectrum Energy wants to piggyback on this infrastructure and build a gas-powered power plant near Denton, MD, according to a report by WBOC 16 News. The combined price tag on the two projects is $1.25 billion, and is funded entirely by private interests based in Baltimore. The target start-up date for the two projects is 2021.

Local Support

Company officials promise the pipeline would bring down energy costs and bring jobs to the area. According to a 2016 Towson University study, the project would create about 100 jobs in Wicomico and Somerset Counties by 2026. In addition, the proposed power plant in Denton, MD would result in 350 construction jobs and 25-30 permanent jobs.

According to lawmaker Carl Anderton:

…it’s great. You know, anytime we can multiply our infrastructure for energy production, it’s something you really want.

Anderton, who claims to also support solar power and offshore wind, is skeptical about the sustainability of renewable energy to stand on its own if “the sun goes down or the wind’s not blowing.”

However, Senator Stephen Hershey emphasized the need to balance infrastructure build-out with costs to the environment. Said Hershey:

We have to make sure we’re taking all the possible steps to protect that.

Similarly, Democratic Delegate Sheree Sample-Hughes indicated the need to keep the well-being and concerns of citizens “at the forefront.”

Grassroots Opposition

The pipeline project has encountered considerable opposition from the grassroots group “No! Eastern Shore Pipeline.” The group has cited concerns about how all fossil fuels add to global warming, and asserted natural gas is not a cleaner alternative to propane or oil.

In fact, current research indicates that as a driver of climate change, methane (natural gas) is up to 100 times more powerful at trapping heat than is CO2 (See also “Compendium of Scientific, Medical, and Media Findings Demonstrating Risks and Harms of Fracking,” p. 21, “Natural gas is a threat to the climate”).

Jake Burdett, a supporter of No! Eastern Shore Pipeline, wants a complete transition to renewable fuels in Maryland by 2035, and argues that in the near-term, climate change impacts will be devastating and not reversible for residents of the Chesapeake Bay area, “the third most at-risk area in the entire country for sea level rise.”

In addition to driving climate change, hydraulic fracturing and the construction of the pipeline along the rural and historic Eastern Shore poses serious threats of fouling ground and surface water through sediment run-off and leaks. The possibility of pipeline explosions also puts nearby communities at risk.

Assessing Risks

H4 Capital Partners, the company contracted to build the pipeline, registered as a corporation in May of 2017, and this may be the first pipeline project it has undertaken. H4’s public relations spokesperson Jerry Sanders claimed that the environmental risks posed by the pipeline — which will drill under rivers and wetlands — will be nothing like those encountered by pipelines such as the Keystone XL. Said Sanders, “It is a gas, not a liquid…[so] you don’t have leak-type issues.”

The actual record about pipeline leaks and explosions suggests otherwise, notably summarized here by FracTracker Alliance in 2016, for combined oil and natural gas projects. That research indicates that since 2010, there have been 4,215 pipeline incidents resulting in 100 reported fatalities, 470 injuries, and property damage exceeding $3.4 billion. Additional records of natural gas transmission and distribution pipeline accidents, and hazardous liquid pipeline accidents collected by PHMSA (Pipeline and Hazardous Materials Safety Administration) have been summarized by the Pipeline Safety Trust.

It is unclear whether Maryland’s Department of the Environment (MDE) has completed an analysis of threats to wetlands and other water bodies, or is relying on industry and perhaps residents to do that work for them. Said MDE spokesperson Jay Apperson, “MDE would encourage the project proponents to come in early and often for discussions of routes so that we can… avoid and minimize impacts to these important natural resources.”

Delmarva Pipeline Map

Therefore, in the map below, we have done an analysis of the Delmarva Pipeline route – which we estimated from documents – and calculated the number of times the proposed pipeline crosses wetlands and streams along its route from northern Maryland to its terminus in Accomack County, VA.


View map fullscreen | How FracTracker maps work

Delmarva Pipeline: Wetland and Stream Crossings

In all, there were 172 stream crossings and 579 traverses of wetlands mapped by the US Fish and Wildlife Service’s National Wetland Inventory. Be sure to zoom in on the map above to view the detail. These wetland and stream crossings included:

in Virginia:

  • 88 forested wetlands
  • 13 emergent wetlands
  • 27 riverine wetlands
  • 9 ponds

And in Maryland:

  • 276 forested wetlands
  • 90 riverine wetlands
  • 35 emergent wetlands
  • 13 estuarine wetlands
  • 11 ponds
  • 5 lakes

Rather than focusing on threats to these natural resources or environmental justice issues associated with the nearly 200-mile pipeline, industry is utilizing a different tactic, preferring to view the project as an “economic justice issue [that] would allow the area to have access to low-cost fuels.”

For the Eastern Shore residents of Maryland and Virginia, it remains to be seen whether potential lower energy costs justify the risks of contaminated waterways, property damage, and a shifting shoreline associated with climate change driven by use of fossil fuels.


By Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance

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

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

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

California’s 2nd Largest Waste Stream

Every year the oil and gas industry in California generates billions of gallons of wastewater, also known as produced water. According to a study by the California Council on Science and Technology, in 2013, more than 3 billion barrels of produced water were extracted along with some 0.2 billion barrels of oil across the state. This wastewater is usually contaminated with a mixture of heavy metals, hydrocarbons, naturally occurring radioactive materials, and high levels of salts. Yet, contaminated wastewater from oil-field operations is exempt from the hazardous waste regulations enforced by the Resource Conservation and Recovery Act (RCRA).

Operators are, therefore, not required to measure or report the chemistry of this wastewater. Even with these unknowns, it is legally re-injected back into groundwater aquifers for disposal. Once an aquifer is contaminated it can be extremely difficult, if not impossible, to clean up again. Particularly in California, where water resources are already stretched thin, underground injection of oil and gas wastewater is a major environmental and economic concern.

Regulatory Deficiency

Under the Underground Injection Control program, wastewater is supposed to be injected only into geologic formations that don’t contain usable groundwater. However, a loophole in the Safe Drinking Water Act allows oil and gas companies to apply for what’s called an aquifer exemption, which allows them to inject wastewater into aquifers that potentially hold high-quality drinking water. To learn more about aquifer exemptions, see FracTracker’s summary, here.

The California department responsible for managing these aquifer exemption permits – the Division of Oil, Gas, and Geothermal Resources (DOGGR) – has for decades failed in its regulatory capacity. In 2015, for example, DOGGR admitted that at least 2,553 wells had been permitted to inject oil and gas waste into non-exempt aquifers – aquifers that could be used for drinking water. Independent audits of DOGGR showed decades of poor record-keeping, lax oversight, and in some cases, outright defiance of the law – showing the cozy relationship between regulators and the oil and gas industry. While 176 wells (those that were injecting into the cleanest drinking water) were initially shut down, most of the rest of the 2,377 permits were allowed to continue injecting into disputed wells through the following two years of the regulatory process.

The injection wells targeted by the Environmental Protection Agency (EPA), including those that were shut down, are shown in the map below (Figure 1).

Figure 1. Map of EPA-targeted Class II Injection Wells


View map fullscreen | How FracTracker maps work | Map Data (CSV): Aquifer Exemptions, Class II Wells

The timeline of all this is just as concerning. The State of California has known about these problems since 2011, when the EPA audited California’s underground injection program and identified substantial deficiencies in its program, including failure to protect some potential underground sources of drinking water, a one-size-fits-all geologic review, and inadequate and under-qualified staffing for carrying out inspections. In 2014, the Governor’s office requested that the California EPA perform an independent review of the program. EPA subsequently made a specific remediation plan and timeline for DOGGR, and in March of 2015 the State finalized a Corrective Action Plan, to be completed by February 2017.

Scientific Review of CA Oil and Gas Activities

Meanwhile, in 2013, the California Senate passed SB-4, which set a framework for regulating hydraulic fracturing in California. Part of the bill required an independent scientific study to be conducted on oil and gas well stimulation, including acid well stimulation and hydraulic fracturing. The California Council on Science and Technology organized and led the study, in collaboration with the Lawrence Berkeley National Laboratories, which combined original technical data analyses and a review of relevant literature, all of which was extensively peer-reviewed. The report argues that both direct and indirect impacts of fracking must be accounted for, and that major deficiencies and inconsistencies in data remained which made research difficult. They also recommended that DOGGR improve and modernize their record keeping to be more transparent.

Figure 2. Depths of groundwater total dissolved solids (a common measure of groundwater quality) in five oil fields in the Los Angeles Basin. Blue and aqua colors represent protected groundwater; the heavy black horizontal line indicates the shallowest hydraulically fractured well in each field. In three of the five wells (Inglewood, Whittier, and Wilmington), fracking and wastewater injection takes place directly adjacent to, or within, protected groundwater.

Figure 2*. Depths of groundwater total dissolved solids (a common measure of groundwater quality) in five oil fields in the Los Angeles Basin. Blue and aqua colors represent protected groundwater; the heavy black horizontal line indicates the shallowest hydraulically fractured well in each field. In three of the five wells (Inglewood, Whittier, and Wilmington), fracking and wastewater injection takes place directly adjacent to, or within, protected groundwater.

A major component of the SB-4 report covered California’s Class II injection program. Researchers analyzed the depths of groundwater aquifers protected by the Safe Drinking Water Act, and found that injection and hydraulic fracturing activity was occurring within the same or neighboring geological zones as protected drinking water (Figure 2*).

*Reproduced from California Council on Science and Technology: An Independent Scientific Assessment of Well Stimulation in California Vol. 3.

More Exemptions to be Granted

Now, EPA is re-granting exemptions again. Six aquifer exemptions have been granted, and more are on the docket to be considered. In this second time around, it is imperative that regulatory agencies be more diligent in their oversight of this permitting process to protect groundwater resources. At the same time, the 2015 California bill SB 83 mandates the appointment of an independent review panel to evaluate the Underground Injection Control Program and to make recommendations on how to improve the effectiveness of the program. This process is currently in the works and a panel has been assembled, and FracTracker Alliance will be working to provide data, maps and analyses for this panel.

Stay tuned for more to come on which aquifers are being exempted, why, and what steps are being taken to protect groundwater in California.


Feature image by Pat Sullivan/AP

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

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

Mariner East 2: More Spills & Sinkholes Too?

The Mariner East 2 (ME2) pipeline, currently being built by Sunoco Pipeline (Energy Transfer Partners), is a massive 350-mile long pipeline that, if completed, will carry 275,000 barrels of propane, ethane, butane, and other hydrocarbons per day from the shale gas fields of Western Pennsylvania to a petrochemical export terminal located on the Delaware River.

ME2 has faced numerous challenges from concerned citizens since Sunoco first announced plans for the project in 2014. Fights over taking private property by eminent domain, eyebrow raising permit approvals with known technical deficiencies, as well as nearly a hundred drilling mud spills — inadvertent returns (IRs) — at horizontal directional drilling (HDD) sites have occurred since work began in 2017.

This article and the accompanying map brings us up-to-date on the number, location, and status of ME2’s HDD spills. We also summarize the growing list of violations and settlements related to these events. Finally, we highlight the most recent concerns related to ME2’s construction: sinkholes emerging along the pipeline’s path in karst geological formations.

Map of ME2 Updated HDDs, IRs & Karst

The map below shows an updated visual of ME2’s IRs, as of the DEP’s latest tally on March 1, 2018. Included on this map are HDDs where DEP ordered Sunoco reevaluate construction sites to prevent additional spills. Also identified on this map are locations where Sunoco was ordered to notify landowners in close proximity to certain HDDs prior to additional drilling. Finally, the below map illustrates how sinkholes are not a problem unique to one site of construction but are, in fact, common to many areas along ME2’s route. These topics are discussed in greater depth below.

Open the map full-screen to view additional layers not available in the embedded version below.

View Map Fullscreen | How FracTracker Maps Work

HDDs & Inadvertent Returns – Redux

In July 2017, the PA Environmental Hearing Board granted a two week halt to ME2’s HDD operations. The temporary injunction was in response to petitions from the Clean Air CouncilMountain Watershed Association, and the Delaware Riverkeeper Network following IRs­­ at more than 60 sites that contaminated dozens of private drinking water wells, as well as nearby streams and wetlands. FracTracker first wrote about these issues in this prior article.

HDD IR in Washington County
(image: Observer-Reporter)

Despite these issues, and despite Sunoco being cited for 33 violations, ME2 was allowed to proceed under an August 7th agreement that stated Sunoco must reevaluate their HDD plans to minimize additional spills. These studies were to include re-examining the site’s geology and conducting seismic surveys. Sites for reevaluation were selected based on factors such as proximity water supplies, nearby streams and wetlands, problematic geologic conditions, and if an IR had occurred at that site previously. Of ME2’s 230 HDDs, 64 were ordered for reevaluation — 22 of these were selected due to prior IRs occurring at the site.

The DEP mandated that Sunoco’s reevaluation studies be put out for public comment. A table of which HDD studies are currently out for comment can be found here. DEP’s settlement also required Sunoco to notify landowners in proximity to certain HDDs prior to commencing construction due to elevated risks. Of the 64 HDD sites under review, Sunoco must notify 17 residents within 450ft of an HDD site, and 22 residents within 150ft of other sites. The HDD reevaluation sites are shown on the FracTracker map above. Below is an illustration of one site where Sunoco is required to notify landowners within 450ft.

One issue residents have raised with these notifications is that Sunoco is allowed to offer landowners the option to connect their homes to a water buffalo during drilling as an alternative to using their groundwater well. The catch is that, if their well does become contaminated, they would also waive their right to have Sunoco drill them a new replacement well.

“Egregious Violations”

In January 2018, the DEP again suspended ME2’s construction, this time indefinitely revoking their permits, due to even more IRs. DEP also cited Sunoco for “egregious and willful” permit violations —mainly executing HDDs at sites where they had no permission to do so. The DEP noted of their decision that, “a permit suspension is one of the most significant penalties DEP can levy.”

Nevertheless, Sunoco was again allowed to resume construction on February 8, 2018, after paying a $12.6 million fine. The DEP press release accompanying the decision assured the public that, “Sunoco has demonstrated that it has taken steps to ensure the company will conduct the remaining pipeline construction activities in accordance with the law and permit conditions, and will be allowed to resume.”

A few weeks later, Sunoco ran a full-page advertisement in the Harrisburg Patriot-News, shown above, lauding their safety record. Among other notables, the piece boasts, “State and federal regulators spent more than 100 inspection days during 2017 on the Mariner East project, more inspection days than on any other pipeline in Pennsylvania.” Critics have noted that the inordinate number of inspections are due to the comedy of errors associated with ME2’s construction.

Karst Formations & Sinkholes

Which brings us to the current ME2 debacle. Last week, the PA Public Utility Commission (PUC) ordered a temporary shutdown of Mariner East 1 (ME1), another natural gas liquids pipeline owned by Sunoco/ETP. ME1 was built in the 1930s and its right-of-way is being used for most of ME2’s route across the state. This latest construction setback comes in the wake of numerous sinkholes that emerged beginning in December along Lisa Drive in West Whitehead Township, a suburb of Philadelphia in Chester County.

The most recent of these sinkholes grew into a 20ft-deep, 15ft-wide chasm that exposed portions of ME1 and came within 10ft of a house. It is worth noting that, until only a few days ago, ME1 was an operational 8in pipeline with a potential impact radius (aka “blast zone”) of some 500ft. The PUC ordered that Sunoco must now run a line inspection on ME1 for a mile upstream and a mile downstream from the sinkhole sites along Lisa Drive, seen in the image below. Note the proximity of these sinkholes to Amtrak’s Keystone rail lines (connecting Pittsburgh to Philadelphia), under which ME2 also runs. The Federal Railway Administration only recently learned of the sink holes from a nearby resident.

The Lisa Drive sinkholes are being credited to Sunoco executing an HDD in an area known to have karst geological formations. Sunoco has been ordered by the PUC to conduct more geophysical testing and seismic analyses of the area because of this. Karst is often called the “Swiss cheese” of geology — notorious for caves, sinkholes, and underground rivers. As these geological formations change shape, pipelines can bend and settle over time, ultimately leading to potentially dangerous gas leakages or explosions. For instance, the 2015 Atex-1 pipeline explosion in Follansbee, WV, was ultimately determined by the Pipeline and Hazardous Materials Safety Administration (PHSA) as having been caused by ground settling. That explosion released some 24,000 barrels of ethane, burning more than five acres of surrounding land.

The US Geological Survey (USGS) maintains fairly detailed maps of rock formations for most states, including formations known to have karst. In PA, there are a number of “carbonate” rock families known for karst features and settlement issues: limestone and dolostone, and, to a lesser extent, shale. Meanwhile, the PA Department of Conservation and Natural Resources (DCNR) has maintained a record of karst “features” — sinkholes and surface depressions — documented since 1985. A great explanation of the different types of karst features can be found here.

Underestimating the Risks

What is concerning about the Lisa Drive sinkholes is that Sunoco had supposedly already conducted additional karst geological reviews of the area as part of the August DEP settlement, subsequently ranking a nearby HDD (#PA-CH-0219) as “low risk” for running into karst issues—despite knowing the HDD runs through a karst formation with sinkholes and surface depressions in the area. For the HDD that runs the length of Lisa Drive (#PA-CH-0256), the study rated its risk as “very low.” These two HDDs are shown below, along with the area of ME1 now under structural review.

The likely result of these inaccurate assessments led to two IRs at Lisa Drive, one in October and another in November 0f 2017. DEP’s writeup of these events note that the total volume of drilling muds spilled remains unknown because Sunoco didn’t report the incident. Then, only a month later, sinkholes emerged in the same locations. An image of the November HDD IR is shown below.

It is important to note two additional things of Sunoco’s karst study, an except of which is seen in their map of the West Whiteland area below. First, Lisa Drive is just on the edge of a karst limestone formation. USGS data suggest the location is actually mica schist, but the USGS data is also only a rough estimate of different formations. This underscores why pipeline companies must be required to conduct detailed geotechnical analysis of all HDD sites at the onset of their projects.

The other notable aspect of Sunoco’s study is that it does not fully represent all rock formations known to have karst features. In Sunoco’s map, we see orange shading for limestone, but this does not include dolostone that underlies the many surface depressions and sinkholes surrounding West Whiteland. FracTracker’s map includes these formations for greater accuracy.

Takeaways

Interestingly, as Anya Litvak of the Pittsburgh Post-Gazette observed in her reporting on the Lisa Drive incident, Sunoco’s updated karst assessment ranked the entire route of the ME2 pipeline through the state as “low to very low” risk for potential issues. Furthermore, Sunoco has tried to downplay the Lisa Drive incident, stating that “all areas have been secured,” and that additional incidents are unlikely to occur.

But the overall relationship between Mariner East 2’s IRs, HDD sites, and known karst features tells a very different story than Sunoco’s about the potential risks of ME2. In addition to the concerns about new sinkholes near Lisa Drive, FracTracker found the following in our analysis:

  • 7 sinkholes and 386 surface depressions are within 1,500ft of a ME2 HDD site.
  • Of the 230 HDDs, 87 are located in carbonate rock areas (52 in limestone/dolostone, 35 in shale).
  • Of the 99 IRs, 39 have occurred in carbonate rock areas (23 in limestone/dolostone, 16 in shale).

In other words, nearly half of the IRs caused by ME2 HDDs were located in areas known to have karst formations. Worth noting is that an additional 15 occurred in sandstone formations, also known to cause settlement over time. The remaining IRs are split across nine other formation types.

Considering that the DEP’s current review of Sunoco’s ability to safely execute future HDDs are based on the same karst study that missed the Lisa Drive HDD and ranked nearby HDDs as a “low” risk, one can only assume that additional spills will occur. There are many more HDD sites yet to be drilled, and also not likely studied fully for potential karst risks. As illustrated by the continuing saga of spills, violations, and omissions, it is clear that Sunoco has not maintained a high standard of construction in building ME2 from the onset.

We thank Eric Friedman from the Middletown Coalition for Community Safety for supplying photos of the Lisa Drive site used in this article.

By Kirk Jalbert, FracTracker Alliance

Aerial image of fracking activity in Marshall County, WV, next to the Ohio River on January 26th, 2018 from approximately 1,000 to 1,200 feet, courtesy of a partnership with SouthWings and pilot Dave Warner. The camera we used was a Nikon D5300. Photo by Ted Auch, FracTracker Alliance, January 2018

Fracking’s Freshwater Supply and Demand in Eastern Ohio

Mapping Hydraulic Fracturing Freshwater Supply and Demand in Ohio

Below is a map of annual and cumulative water withdrawal volumes by the hydraulic fracturing industry across Ohio between 2010 and 2016. It displays 312 unique sites, as well as water usage per lateral. The digital map, which can be expanded fullscreen for more features, includes data up until May 2017 for 1,480 Ohio laterals (vertical wells can host more than one lateral well).


View map fullscreen | How FracTracker maps work

The primary take-home message from this analysis and the resulting map is that we can only account for approximately 73% of the industry’s more than 13-billion-gallon freshwater demand by considering withdrawals alone. Another source or sources must be supplying water for these hydraulic fracturing operations.

Hydraulic fracturing rig on the banks of the Ohio River in Marshall County, West Virginia, Winter 2018 (Flight provided by SouthWings)

When Leatra Harper at Freshwater Accountability Project and Thriving Earth Exchange and I brought up this issue with Ohio Division of Water Resources Water Inventory and Planning Program Manager, Michael Hallfrisch, the following correspondence took place on January 24, 2018:

Mr. Hallfrisch: “Where did the water usage per lateral data come from?  Does the water usage include reused/recycled water?  I know that many of the larger operators reuse a significant amount of their flow back because of the high cost of disposal in class II injection wells.”

FracTracker: “[We’]ve been looking at Class II disposal economics in several states and frankly the costs here in Ohio are quite cheap and many of the same players in Ohio operate in the other states [We]’ve looked at.  Granted they usually own their own Class II wells in those other states (i.e., OK, or CO) but the fact that they are “vertically integrated” still doesn’t excuse the fact that the cost of disposing of waste in Ohio is dirt cheap.  As for recycling that % was always a rounding error and last [we] checked the data it was going down by about 0.25-0.35% per year from an average of about 5.5-8.0%.  [We respectfully] doubt the recycling % would fill this 25% gap in where water is coming from.  This gap lends credence to what Lea and [FracTracker] hear time and again in counties like Belmont, Monroe, Noble etc with people telling us about frequent trenches being dug in 1st and 2nd order streams with operators topping off their demands in undocumented ways/means.  Apologies for coming down hard on this thing but we’ve been looking/mapping this thing since 2012 and increasingly frustrated with the gap in our basic understanding of flows/stocks of freshwater and waste cycling within Ohio and coming into the state from PA and WV.”

Broader Implications

The fracking industry in Ohio uses roughly 10-14 million gallons per well, up from 4-5 million gallon demands in 2010, which means that freshwater demand for this industry is increasing 15% per year (Figures 1 and 2). (This rate is more than double the volumes cited in a recent publication by the American Chemical Society, by the way.) If such exponential growth in hydraulic fracturing’s freshwater demand in Appalachia continues, by 2022 each well in Ohio and West Virginia will likely require[1*] at least 43 million gallons of freshwater (Table 1).

Table 1. Projected annual average freshwater demand per well (gallons) for the hydraulic fracturing industry in Ohio and West Virginia based on a 15% increase per year.

Year Water Use Per Well (gallons)
Ohio West Virginia
2019 19,370,077 19,717,522
2020 23,658,666 23,938,971
2021 28,896,760 29,064,215
2022 35,294,582 35,286,756
2023 43,108,900 42,841,519

Water quantity and associated watershed security issues are both acute and chronic concerns at the local level, where fracking’s freshwater demands equal 14% of residential demands across Ohio. These quantities actually exceed 85% of residential demand in several Ohio counties (e.g., Carroll and Harrison), as well as West Virginia (e.g., Doddridge, Marshall, and Wetzel). Interestingly the dramatic uptick in Ohio freshwater demand that began at the end of 2013 coincides with a 50% decline in the price of oil and gas (Figure 3).  The implication here is that as the price of gas and oil drops and/or unproductive wells are drilled at an unacceptable rate, the industry uses more freshwater and sand to ensure acceptable financial returns on investments.

Figures 1-3

Note: Data from U.S. Energy Information Administration (EIA) Petroleum & Other Liquids Overview

Total Water Used

To date, the fracking industry has taken on average 90 million gallons of freshwater per county out of Ohio’s underlying watersheds, resulting in the production of 9.6 million gallons of brine waste that cannot be reintroduced into waterways. This massive waste stream is destined for one of Ohio’s Class II Injection wells, but the industry spends less than 1.25% of available capital on water demand(s) and waste disposal. All of this means that the current incentive (cost) to become more efficient is too low. Sellers of water to the industry like the Muskingum Watershed Conservancy District, which we’ve chronicled frequently in the past[2], have actually dropped their price for every 1,000 gallons of water – from roughly $9 to now just $4-6 – for the fracking industry in recent years.

Hydraulic fracturing’s demand is becoming an increasingly larger component of total water withdrawals in Ohio, as other industries, agriculture, and mining become more efficient. Oil and gas wells drilled at the perimeter of the Utica Shale are utilizing 1.25 to 2.5 times more water than those that are staged in the shale “Sweet Spots.” Furthermore, the rise in permitting of so called “Super Laterals” would render all of our water utilization projections null and void. Laterals are the horizontal wells that extend out underground from the vertical well. Most well pads are home to multiple laterals in the range of 4-7 laterals per pad across Ohio and West Virginia.

These laterals, which can reach up to 21,000 feet or almost 4 miles, demand as much as 87 million gallons of freshwater each.

Even accounting for the fact that the super laterals are 17-21,000 feet in length – vs. an average of 7,452 feet – such water demand would dwarf current demands and their associated pressures on watershed security and/or resilience; typically, Ohio’s hydraulically fractured laterals require 970-1,080 gallons of freshwater per lateral foot (GPLF), but super laterals would need an astounding 4,470 GLPF.

Conclusions and Next Steps

The map above illustrates the acute pressures being put upon watersheds and public water supplies in the name of “energy independence.” Yet, Ohio regulators and county officials aren’t putting any pressure on the high volume hydraulic fracturing (HVHF) industry to use less water and produce less waste. We can’t determine exactly how water demand will change in the future. The problem is not going away, however, especially as climate change results in more volatile year-to-year fluctuations in temperature and precipitation. This means that freshwater that was/is viewed as a surplus “commodity” will become more valuable and hopefully priced accordingly.

Furthermore, the Appalachian Ohio landscape is undergoing dramatic transformations at the hands of the coal and more recently the HVHF industry with strip-mines, cracking plants, cryogenic facilities, compressor stations, gas gathering lines – and more – becoming ubiquitous.

We are seeing significant acreage of deciduous forests, cropland, or pasture that once covered the region replaced with the types of impervious surfaces and/or “clean fill” soil that has come to dominate HVHF landscapes in other states like North Dakota, Texas, and Oklahoma.

This landscape change in concert with climate change will mean that the region will not be able to receive, processes, and store water as effectively as it has in the past.

It is too late to accurately and/or more holistically price the HVHF’s current and past water demand in Ohio, however, such holistic pricing would do wonders for how the industry uses freshwater in the future. After all, for an industry that believes so devotedly in the laws of supply and demand, one would think they could get on board with applying such laws to their #1 resource demand in Appalachia. The water the HVHF industry uses is permanently removed from the hydrological cycle. Now is the time to act to prevent long term impacts on Ohio’s freshwater quantity and quality.


Relevant Data

  • Ohio hydraulic fracturing lateral freshwater demand by individual well between 2010 and the end of 2016. Download
  • Ohio hydraulic fracturing lateral freshwater withdrawals by site between 2010 and the end of 2016. Download

Endnotes

  1. *Certainty, with respect to this change in freshwater demand, is in the range of 86-90% assuming the exponential functions we fit to the Ohio and West Virginia data persist for the foreseeable future. Downing, Bob, 2014, “Ohio Drillers’ Growing Use of Fresh Water Concerns Environmental Activists”, March 19th, Akron, Ohio
  2. Downing, Bob, 2014, “Group Reacts to Muskingum Watershed Leasing Deal with Antero”, April 22nd, Akron, Ohio

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

The Falcon: Water Crossings & Hazards

Part of the Falcon Public EIA Project

In this section of the Falcon Public EIA Project, we explore the hydrological and geological conditions of the pipeline’s construction areas. We first identify the many streams, wetlands, and ponds the Falcon must cross, as well as describe techniques Shell will likely use in these water crossings. The second segment of this section highlights how the areas in the Falcon’s path are known for their complex geological features, such as porous karst limestone and shallow water tables that can complicate construction.

Quick Falcon Facts

  • Intersects 319 streams; 361 additional streams located only 500ft from construction areas
  • Intersects 174 wetlands; 470 additional wetlands located only 500ft from construction areas
  • Majority of crossings will be open cuts and dry-ditch trenching
  • A total of 19 horizontal directional drilling (HDD) sites; 40 conventional boring sites
  • 25 miles of pipeline overlap karst limestone formations, including 9 HDD sites
  • 240 groundwater wells within 1/4 mile of the pipeline; 24 within 1,000ft of an HDD site

Map of Falcon water crossings and hazards

The following map will serve as our guide in breaking down the Falcon’s risks to water bodies. Expand the map full-screen to explore its contents in greater depth. Some layers only become visible as you zoom in. A number of additional features of the map are not shown by default, but can be turned on in the “layers” tab. These include information on geological features, water tables, soil erosion characteristics, as well as drinking reservoir boundaries. Click the “details” tab in full-screen mode to read how the different layers were created.

View Map Fullscreen | How FracTracker Maps Work

Defining Water Bodies

The parts of Pennsylvania, West Virginia, and Ohio where the Falcon pipeline will be built lie within the Ohio River Basin. This landscape contains thousands of streams, wetlands, and lakes, making it one of the most water rich regions in the United States. Pipeline operators are required to identify waters likely to be impacted by their project. This two-step process involves first mapping out waters provided by the U.S. Geological Survey’s national hydrological dataset. Detailed field surveys are then conducted in order to locate additional waters that may not yet be accounted for. Many of the streams and wetlands we see in our backyards are not represented in the national dataset because conditions can change on the ground over time. Yet, plans for crossing these must also be present in pipeline operator’s permit applications.

Streams

Streams (and rivers) have three general classifications. “Perennial” streams flow year-round, are typically supplied by smaller up-stream headwaters, and are supplemented by groundwater. In a sense, the Ohio River would be the ultimate perennial stream of the region as all smaller and larger streams eventually end up there. “Intermittent” streams flow for only a portion of the year and are dry at times, such as during the summer when water tables are low. Finally, “ephemeral” streams flow only during precipitation events.

These classifications are important because they can determine the extent of aquatic habitat that streams can support. Working in streams that have no dry period can put aquatic lifeforms at elevated risk. For this and other reasons, many states further designate streams based on their aquatic life “use” and water quality. In Pennsylvania, for instance, the PA DEP uses the designations: Warm Water Fishes (WWF), Trout Stocked (TSF), Cold Water Fisheries (CWF) and Migratory Fishes (MF). Streams with exceptional water quality may receive an additional designation of High Quality Waters (HQ) and Exceptional Value Waters (EV).

Wetlands

Similar to streams, wetlands also have unique designations. These are based on the U.S. Fish and Wildlife Services’ national wetlands inventory. Wetlands are generally defined as “lands transitional between terrestrial and aquatic systems where the water table is usually at or near the surface or the land is covered by shallow water.” As such, wetlands are categorized by their location (such as a tidal estuary or an inland wetland that lacks flowing water), its substrate (bedrock, sand, etc.), and plant life that might be present. While there are hundreds of such categories, only four pertain to the wetlands present in the regions where the Falcon pipeline will be built. Their designations roughly translate to the following:

  • Palustrine Emergent (PEM): Marshes and wet meadows hosting perennial small trees, shrubs, mosses, or lichens
  • Palustrine Shrub (PSS): Similar to PEMs, but characterized by also having well-established shrubs
  • Palustrine Forested (PFO): Similar to PEMs and PSSs, but having trees larger than 6 meters high
  • Palustrine Unconsolidated Bottom (PUB) and Palustrine Opem Water (POW) (aka ponds)

Pipeline operators are required to report the crossing length of each wetland they will encounter, as well as the area of permanent and temporary disturbance that would occur in each of these wetlands. When building the pipeline, operators are required to ensure that all measures are taken to protect wetlands by minimizing impacts to plant life, as well as by taking “upland protective measures” to prevent sedimentation runoff during precipitation events. When undergoing FERC EIA scrutiny, operators are also required to limit the width of wetland construction areas to 75 feet or less.

Crossing Methods

Open-Cut Trenching

Pipeline operators use a variety of methods when crossing streams, wetlands, and ponds. Shorter length crossings often employ a rudimentary trench. After the cuts, construction crews attempts to repair damage done in the process of laying the pipeline. For longer crossings, operators can use boring techniques to go underneath water features.

Open-cut trenching

There are two general types of trenches. The first, “open-cut” crossings, are typically used for smaller waterbodies, such as in intermittent streams where flow may not be present during time of construction, or when construction can be completed in a short period of time (typically 24-48 hours). In this process, a trench is laid through the water body without other provisions in place.

The second type, “dry-ditch” crossing, are required by FERC for waterbodies up to 30 feet wide “that are state-designated as either coldwater or significant coolwater or warmwater fisheries, or federally-designated as critical habitat.” In these spaces, pumps are used to transfer stream flow around the area where trenching occurs. In places where sensitive species are present, dry-ditches must include a flume to allow these species to pass through the work area.

Conventional Boring

Conventional boring consists of creating a tunnel for the pipeline to be installed below roads, waterbodies, and other sensitive resources. Bore pits are excavated on either sides of the site. A boring machine is then used to tunnel under the resource and the pipeline is pushed through the bore hole.

Horizontal Directional Drilling

In more difficult or lengthy crossings, operators may choose to bore under a water feature, road, or neighborhood. Horizontal directional drilling (HDD) involves constructing large staging areas on either side of the crossing. A large drill bit is piloted through the ground along with thousands of gallons of water and bentonite clay for lubricant (commonly referred to as drilling muds). HDDs are designed to protect sensitive areas, but operators prefer not to use them as HDDs can be expensive and require in-depth planning in order for things to go well.

Bentonite sediment pollutes a stream at a Mariner East HDD spill site
(source: Washington, PA, Observer-Reporter)


An example of what happens when things are rushed can be seen in Sunoco’s Mariner East 2 pipeline. The PA DEP has cited Sunoco for over 130 inadvertent returns (accidental releases of drilling muds) since construction began. These spills led to damaged water wells and heavy sedimentation in protected streams, as exemplified in the image above. Making matters worse, Sunoco later violated terms of a settlement that required them to re-survey before recommencing construction. See FracTracker’s article on these spills.

Footprint of the Falcon

The overwhelming majority of Falcon’s water body crossings will be executed with either open-cut or dry-ditch methods. There are 40 locations where conventional boring will be used, but only a 3 are used for crossing water resources. Shell intends to use 19 HDDs and, of these, only 13 are used for crossing water bodies of some kind (the longest of which crosses the Ohio River). All other conventional and HDD boring locations will be used to cross under roads and built structures. This is not entirely unusual for pipelines. However, we noted a number of locations where one would expect to see HDDs but did not, such as in the headwaters of the Ambridge and Tappen Reservoirs, as was seen in the images above.

Stream Impacts

Shell identified and/or surveyed a total of 993 stream sections in planning for the Falcon’s construction. As shown on FracTracker’s map, the pipeline’s workspace and access roads will directly intersect 319 of these streams with the following classifications: perennial (96), ephemeral (79), and intermittent (114). An additional 361 streams are located only 500ft from construction areas.

A number of these streams have special designations assigned by state agencies. For instance, in Pennsylvania, we found 10 stream segments listed as Trout Stocked (TS), which are shown on our interactive map.

Crossing HQ headwater streams of the Ambridge Reservoir

Perhaps more concerning, the Falcon will cross tributaries to the Service Creek watershed 13 times. These feed into three High Quality Cold Water Fishes (HQ/CWF) headwater streams of the Ambridge Reservoir in Beaver County, PA, shown in the image above. They also support the endangered Southern Redbelly Dace (discussed in greater depth here). On the eastern edge of the watershed, the Falcon will cross the raw water line leading out of the reservoir.

The reservoir supplies 6.5 million gallons of water a day to five townships in Beaver County (Ambridge, Baden, Economy, Harmony, and New Sewickley) and four townships in Allegheny County (Leet, Leetsdale, Bell Acres & Edgeworth). This includes drinking water services to 30,000 people.

We found a similar concern in Ohio where the Falcon will cross protected headwaters in the Tappan Reservoir watershed at six different locations. The Tappan is the primary drinking water source for residents in Scio. Below is a page from Shell’s permit applications to the PA DEP outlining the crossing of one of the Ambridge Reservoir’s CWF/HQ headwater streams.

Wetland Impacts

Shell identified a total of 682 wetland features relevant to Falcon’s construction, as well as 6 ponds. Of these, the pipeline’s workspace and access roads will directly intersect 174 wetlands with the following classifications: PEM (141), PSS (13), PFO (7), PUB (10), POW (3). An additional 470 of these wetlands, plus the 6 ponds, are located only 500ft from construction areas.

Example 1: Lower Raccoon Creek

A few wetland locations stand out as problematic in Shell’s construction plans. For instance, wetlands that drain into Raccoon Creek in Beaver County will be particularly vulnerable in two locations. The first is in Potter Township, where the Falcon will run along a wooded ridge populated by half a dozen perennial and intermittent streams that lead directly to a wetland of approximately 14 acres in size, seen below. Complicating erosion control further, Shell’s survey data shows that this ridge is susceptible to landslides, shown in the first map below in dotted red.

Landslide areas along Raccoon Creek wetlands and streams

This area is also characterized by the USGS as having a “high hazard” area for soil erosion, as seen in this second image. Shell’s engineers referenced this soil data in selecting their route. The erosion hazard status within 1/4 mile of the Falcon is a layer on our map and can be activated in the full-screen version.

Shell’s permit applications to the PA DEP requires plans be submitted for erosion and sedimentation control of all areas along the Falcon route. Below are the pages that pertain to these high hazard areas.

Example 2: Independence Marsh

The other wetland area of concern along Raccoon Creek is found in Independence Township. Here, the Falcon will go under the Creek using horizontal drilling (highlighted in bright green), a process discussed in the next section. Nevertheless, the workspace needed to execute the crossing is within the designated wetland itself. An additional 15 acres of wetland lie only 300ft east of the crossing but are not accounted for in Shell’s data.

This unidentified wetland is called Independence Marsh, considered the crown jewel of the Independence Conservancy’s watershed stewardship program. Furthermore, the marsh and the property where the HDD will be executed are owned by the Beaver County Conservation District, meaning that the CCD signed an easement with Shell to cross publicly-owned land.

Independence Marsh, unidentified in Shell’s survey data

 

Groundwater Hazards

The Falcon’s HDD locations offer a few disturbing similarities to what caused the Mariner East pipeline spills. Many of Sunoco’s failures were due to inadequately conducted (or absent) geophysical surveys prior to drilling that failed to identify karst limestone formations and shallow groundwater tables, which then led to drilling muds entering nearby streams and groundwater wells.

Karst Limestone

Karst landscapes are known for containing sinkholes, caves, springs, and surface water streams that weave in and out of underground tunnels. Limestone formations are where we are most likely to see karst landscapes along the Falcon’s route.

In fact, more than 25 of the Falcon’s 97 pipeline miles will be laid within karst landscapes, including 9 HDD sites. However, only three of these HDDs sites are identified in Shell’s data as candidates for potential geophysical survey areas. The fact that the geology of the other 10 HDD sites will not be investigated is a concern.

One site where a geophysical survey is planned can be seen in the image below where the Falcon crosses under PA Highway 576. Note that this image shows a “geological formations” layer (with limestone in green). This layer shows the formation types within 1/4 mile of the Falcon and can activated in the full-screen version of our interactive map.

A potential HDD geophysical survey area in karst limestone

Water Tables

We also assessed the Falcon’s HDDs relative to the groundwater depths and nearby private groundwater wells. The USGS maintains information on minimum water table depths at different times of the year. In the image below we see the optional “water table depth” layer activated on the FracTracker map. The groundwater at this HDD site averages 20ft on its western side and only 8ft deep on the eastern side.

Shallow groundwater and private wells near a planned HDD site

Groundwater Wells

Also seen in the above image is the “groundwater wells” layer from the FracTracker map. We found 240 private water wells within 1/4 mile of the Falcon. This data is maintained by the PA Department of Natural Resources as well as by the Ohio Department of Natural Resources. Comparable GIS data for West Virginia were not readily available thus not shown on our map.

While all of these wells should be assessed for their level of risk with pipeline construction, the subset of wells nearest to HDD sites deserve particular attention. In fact, Shell’s data highlights 24 wells that are within 1,000 feet of a proposed HDD site. We’ve isolated the groundwater wells and HDD sites in a standalone map for closer inspection below. The 24 most at-risk wells are circled in blue.

View Map Fullscreen | How FracTracker Maps Work

* * *

Related Articles

By Kirk Jalbert, FracTracker Alliance

The Falcon: High Consequence Areas & Potential Impact Zones

Part of the Falcon Public EIA Project

In this segment of the Falcon Public EIA Project we continue to explore the different ways that pipelines are assessed for potential risk – in this case, relative to population centers, drinking water systems, and sensitive habitats. We outline methods dictated by the Pipeline and Hazardous Materials Safety Administration (PHMSA) called “high consequence areas” (HCAs) and how they determine potential impact zones for highly volatile liquid (HVL) pipelines. These methods are then applied to the Falcon to understand its possible dangers.

Quick Falcon Facts

  • An estimated 940-foot potential impact radius (PIR)
  • 60 of 97 pipeline miles qualifying as High Consequence Areas (HCA)
  • More than 8,700 people living in the “vapor zone”
  • 5 schools, 6 daycare centers, and 16 emergency response centers in “vapor zone”
  • In proximity to 8 source-water (drinking water) protection areas
  • Affecting habitats populated by 11 endangered, protected, or threatened species

Map of Falcon High Consequence Areas

The following map will serve as our guide in breaking down the Falcon’s High Consequence Areas. Expand the map full-screen to explore its contents in greater depth. Some layers only become visible as you zoom in. A number of additional layers are not shown by default, but can be turned on in the “layers” tab. Click the “details” tab in full-screen mode to read how the different layers were created.

View Map Fullscreen | How FracTracker Maps Work

High Consequence Areas

While Class Locations, discussed in a prior project article, dictate the construction and maintenance of a pipeline, high consequence areas (HCAs) designate when operators must implement integrity management programs (IMP) where pipeline failures could cause major impacts to populated areas, as well as drinking water systems and ecological resources — otherwise defined as unusually sensitive areas (USAs).

Populated Areas

Two considerations are used when determining pipeline proximity to population centers:

  1. High Population Areas – an urbanized area delineated by the Census Bureau as having 50,000 or more people and a population density of at least 1,000 people per square mile; and
  2. Other Populated Areas – a Census Bureau designated “place” that contains a concentrated population, such as an incorporated or unincorporated city, town, village, or other designated residential or commercial area – including work camps.

USAs: Drinking Water

PHMSA’s definition of drinking water sources include things such as:

  • Community Water Systems (CWS) – serving at least 15 service connections and at least 25 year-round residents
  • Non-transient Non-community Water Systems (NTNCWS) – schools, businesses, and hospitals with their own water supplies
  • Source Water Protection Areas (SWPA) for a CWS or a NTNCWS
  • Wellhead Protection Areas (WHPA)
  • Sole-source karst aquifer recharge areas

These locations are typically supplied by regulatory agencies in individual states.

With the exception of sole-source aquifers, drinking water sources are only considered if they lack an alternative water source. However, PHMSA is strict on what alternative source means, stating that they must be immediately usable, of minimal financial impact, with equal water quality, and capable of supporting communities for at least one month for a surface water sources of water and at least six months for a groundwater sources.

One very important note in all of these “drinking water” USA designations is that they do not include privately owned groundwater wells used by residences or businesses.

USAs: Ecological Resource

Ecological resource areas are established based on any number of qualities with different variations. In general terms, they contain imperiled, threatened, or endangered aquatic or terrestrial species; are known to have a concentration of migratory waterbirds; or are a “multi-species assemblage” area (where three or more of the above species can be found).

Calculating HCAs

Like Class locations, HCAs are calculated based on proximity. The first step in this process is to determine the pipeline’s Potential Impact Radius (PIR) — the distance beyond which a person standing outdoors in the vicinity of a pipeline rupture and fire would have a 99% chance of survival; or in which death, injury, or significant property damage could occur. PIR is calculated based on the pipeline’s maximum allowable operating pressure (MAOP), diameter, and the type of gas. An example of this calculation is demonstrated in FracTracker’s recent article on the Mariner East 2 pipeline’s PIR.

Once the PIR is known, operators then determine HCAs in one of two ways, illustrated in the image below:

  • Method 1: A Class 3 or Class 4 location, or a Class 1 or Class 2 location where “the potential impact radius is greater than 660 feet (200 meters), and the area within a potential impact circle contains 20 or more buildings intended for human occupancy”; or a Class 1 or Class 2 location where “the potential impact circle contains an “identified site.”
  • Method 2: An area within PIR containing an “identified site” or 20 or more buildings intended for human occupancy.

Calculating HCAs
(source: PHMSA)

In these definitions, “identified sites” include such things as playgrounds, recreational facilities, stadiums, churches, office buildings, community centers, hospitals, prisons, schools, and assisted-living facilities. However, there is a notable difference in how HCAs are calculated for natural gas pipelines vs. hazardous liquid pipelines.

Beyond just looking at what lies within the PIR, pipelines that contain gasses such as ethane potentially impact a much broader area as vapors flow over land or within a river, stream, lake, or other means. A truly accurate HCA analysis for an ethane pipeline leak requires extensive atmospheric modeling for likely vapor dispersions, such as seen in the example image below (part of a recent ESRI GIS conference presentation).

Vapor dispersion modelling
(source: TRC Solutions)

 

What HCAs Dictate

HCAs determine if a pipeline segment is included in an operator’s integrity management program (IMP) overseen by PHMSA or its state equivalent. IMPs must include risk assessments that identify the most likely impact scenarios in each HCA, enhanced management and repair schedules, as well as mitigation procedures in the event of an accident. Some IMPs also include the addition of automatic shut-off valves and leak detection systems, as well as coordination plans with local first responders.

The Falcon Risk Zones

Shell’s permit applications to the PA DEP state the pipeline:

…is not located in or within 100 feet of a national, state, or local park, forest, or recreation area. It is not located in or within 100 feet of a national natural landmark, national wildlife refuge, or federal, state, local or private wildlife or plant sanctuaries, state game lands. It is also not located in or within 100 feet of a national wild or scenic river, the Commonwealth’s Scenic Rivers System, or any areas designated as a Federal Wilderness Area. Additionally, there are no public water supplies located within the Project vicinity.

This is a partial truth, as “site” and “vicinity” are vague terms here. A number of these notable areas are within the PIR and HCA zones. Let’s take a closer look.

The PIR (or “Blast Zone”)

Shell’s permit applications state a number of different pipeline dimensions will be used throughout the project. Most of the Falcon will be built with 12-inch steel pipe, with two exceptions: 1) The segment running from the Cadiz, OH, separator facility to its junction with line running from Scio, OH, will be a 10-inch diameter pipe; 2) 16-inch diameter pipe will be used from the junction of the Falcon’s two main legs located four miles south of Monaca, PA, to its end destination at the ethane cracker. We also know from comments made by Shell in public presentations that the Falcon’s maximum allowable operating pressure (MOAP) will be 1,440 psi. These numbers allow us to calculate the Falcon’s PIR which, for a 16″ ethane pipeline at 1,440psi, is about 940 feet. We’ve termed this the “blast zone” on our maps.

The HCA (or “Vapor Zone”)

Shell’s analysis uses an HCA impact radius of 1.25 miles. This much larger buffer reflects the fact that vapors from hazardous liquid pipelines can travel unpredictably at high concentrations for long distances before ignition. This expanded buffer might be called the “vapor zone,” a term we used on our map. Within the HCA “vapor zone” we find that 60 of the Falcon’s 97 miles qualify as high consequence areas, with 35 miles triggered due to their proximity to drinking water sources, 25 miles trigger for proximity to populated areas, and 3 miles for proximity to ecological areas.

Populated Areas

Shell’s HCA buffer intersects 14 US Census-designated populated areas, shown in the table below. Falcon’s right-of-way directly intersects two of these areas: Cadiz Village in Harrison County, Ohio, and Southview CDP (Census Designated Place) in Washington County, PA. These areas are listed below. Additionally, we included on the FracTracker map the locations of public facilities that were found inside the HCA buffer. These include 5 public schools, 6 daycare centers, 10 fire stations, and 6 EMS stations.

Area Population State HCA
Pittsburgh Urbanized Area High PA Indirect
Weirton-Steubenville Urbanized Area High WV/OH/PA Indirect
Scio Village Other OH Indirect
Cadiz Village* Other OH Direct
Amsterdam Village Other OH Indirect
Shippingport Borough Other PA Indirect
Industry Borough Other PA Indirect
Hookstown Borough Other PA Indirect
Midway Borough Other PA Indirect
Clinton CDP Other PA Indirect
Imperial CDP Other PA Indirect
Southview CDP* Other PA Direct
Hickory CDP Other PA Indirect
Westland CDP Other PA Indirect
* Indicates an area the Falcon’s right-of-way will directly intersect

While it is difficult to determine the actual number of people living in the PIR and HCA vapor zone, there are ways one can estimate populations. In order to calculate the number of people who may live within the HCA and PIR zones, we first identified U.S. Census blocks that intersect each respective buffer. Second, we calculated the percentage of that census block’s area that lies within each buffer. Finally, we used the ratio of the two to determine the percentage of the block’s population that lies within the buffer.

Based on 2010 Census data, we estimate that 2,499 people live within a reasonable projection of the Falcon’s PIR blast zone. When expanded to the HCA vapor zone, this total increases to 8,738 people. These numbers are relatively small compared to some pipelines due to the fact that a significant portion of the Falcon runs through fairly rural areas in most places.

PIR est. pop. HCA est. pop.
OHIO
Carroll County 11 47
Harrison County 274 915
Jefferson County 334 1,210
Total 619 2,172
WEST VIRGINIA
Hancock County 242 1,155
Total 242 1,155
PENNSYLVANIA
Allegheny County 186 969
Beaver County 990 3,023
Washington County 461 1,419
Total 1,637 5,410
Grand Total 2,499 8,738


Drinking Water Sources

Shell’s data identified a number of drinking water features considered in their HCA analysis. Metadata for this information show these sites were obtained from the Ohio Division of Drinking and Ground Waters, the West Virginia Source Water Assessment and Wellhead Protection Program, and the Pennsylvania DEP Wellhead Protection Program. The exact locations of public drinking water wells and intake points are generally protected by states for safety reasons. However, we duplicated the 5-mile buffer zones used on Shell’s map around these points, presumably denoting the boundaries of source water protection areas, wellhead protection areas, or intake points.

Drinking water buffers in Shell’s HCA analysis

As shown on FracTracker’s interactive map, five of these areas serve communities in the northern portions of Beaver County, shown in the image above, as well as the Cadiz and Weirton-Steubenville designated populated areas. Recall that HCA drinking water analysis only requires consideration of groundwater wells and not surface waters. This is an important distinction, as the Ambridge Reservoir is within the HCA zone but not part of Shell’s analysis — despite considerable risks outlined in our Falcon article on water body crossings.

Ecological Areas

Shell’s permits state that they consulted with the U.S. Fish and Wildlife Service (USFWS), Pennsylvania Game Commission (PGC), Pennsylvania Fish & Boat Commission (PFBC), and the Pennsylvania Department of Conservation and Natural Resources (DCNR) on their intended route in order to determine potential risks to protected species and ecologically sensitive areas.

DCNR responded that the pipeline had the potential to impact six sensitive plant species: Vase-vine Leather-Flower, Harbinger-of-spring, White Trout-Lily, Purple Rocket, Declined Trillium, and Snow Trillium. PFBC responded that the project may impact the Southern Redbelly Dace, a threatened temperate freshwater fish, within the Service Creek watershed. PGC responded that the pipeline had potential impact to habitats used by the Short-Eared Owl, Northern Harrier, and Silver-Haired Bat. Finally, the USFWS noted the presence of freshwater mussels in a number of water features crossed by the Falcon.

The presence of these species, as well as the proximity of protected lands illustrated on our map, factored into the Falcon’s HCA designations. A more detailed analysis of these issues is provided in the Falcon Public EIA Project article on Protected Habitats & Species of Concern.

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By Kirk Jalbert, FracTracker Alliance