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Shell Pipeline - Not Quite the Good Neighbor

Shell Pipeline: Not Quite the “Good Neighbor”

In August 2016, Shell Pipeline announced plans to develop the Falcon Ethane Pipeline System, a 97-mile pipeline network that will carry more than 107,000 barrels of ethane per day through Pennsylvania, West Virginia, and Ohio, to feed Shell Appalachia’s petrochemical facility currently under construction in Beaver County, PA.

FracTracker has covered the proposed Falcon pipeline extensively in recent months. Our Falcon Public EIA Project explored the project in great detail, revealing the many steps involved in risk assessments and a range of potential impacts to public and environmental health.

This work has helped communities better understand the implications of the Falcon, such as in highlighting how the pipeline threatens drinking water supplies and encroaches on densely populated neighborhoods. Growing public concern has since convinced the DEP to extend public comments on the Falcon until April 15th, as well as to host three public meetings scheduled for early April.

Shell’s response to these events has invariably focused on their intent to build and operate a pipeline that exceeds safety standards, as well as their commitments to being a good neighbor. In this article, we investigate these claims by looking at federal data on safety incidents related to Shell Pipeline.

Contrary to claims, records show that Shell’s safety record is one of the worst in the nation.

The “Good Neighbor” Narrative

Maintaining a reputation as a “good neighbor” is paramount to pipeline companies. Negotiating with landowners, working with regulators, and getting support from implicated communities can hinge on the perception that the pipeline will be built and operated in a responsible manner. This is evident in cases where Shell Pipeline has sold the Falcon in press releases as an example of the company’s commitment to safety in public comments.

Figure 1. Shell flyer

A recent flyer distributed to communities in the path of the Falcon, seen in Figure 1, also emphasizes safety, such as in claims that “Shell Pipeline has a proven track record of operating safely and responsibility and remains committed to engaging with local communities regarding impacts that may arise from its operations.”

Shell reinforced their “good neighbor” policy on several occasions at a recent Shell-sponsored information meeting held in Beaver County, stating that, everywhere they do business, Shell was committed to the reliable delivery of their product. According to project managers speaking at the event, this is achieved through “planning and training with first responders, preventative maintenance for the right-of-way and valves, and through inspections—all in the name of maintaining pipeline integrity.”

Shell Pipeline also recently created an informational website dedicated to the Falcon pipeline to provide details on the project and emphasize its minimal impact. Although, curiously, Shell’s answer to the question “Is the pipeline safe?” is blank.

U.S. Pipeline Incident Data

Every few years FracTracker revisits data on pipeline safety incidents that is maintained by the Pipeline and Hazardous Materials Safety Administration (PHMSA). In our last national analysis we found that there have been 4,215 pipeline incidents resulting in 100 reported fatalities, 470 injuries, and property damage exceeding $3.4 billion.

These numbers were based on U.S. data from 2010-2016 for natural gas transmission and gathering pipelines, natural gas distribution pipelines, and hazardous liquids pipelines. It is also worth noting that incident data are heavily dependent on voluntary reporting. They also do not account for incidents that were only investigated at the state level.

Shell Pipeline has only a few assets related to transmission, gathering, and distribution lines. Almost all of their pipeline miles transport highly-volatile liquids such as crude oil, refined petroleum products, and hazardous liquids such as ethane. Therefore, to get a more accurate picture of how Shell Pipeline’s safety record stacks up to comparable operators, our analysis focuses exclusively on PHMSA’s hazardous liquids pipeline data. We also expanded our analysis to look at incidents dating back to 2002.

Shell’s Incident Record

In total, PHMSA data show that Shell was responsible for 194 pipeline incidents since 2002. These incidents spilled 59,290 barrels of petrochemical products totaling some $183-million in damages. The below map locates where most of these incidents occurred. Unfortunately, 34 incidents have no location data and so are not visible on the map. The map also shows the location of Shell’s many refineries, transport terminals, and off-shore drilling platforms.

Open the map fullscreen to see more details and tools for exploring the data.


View Map Fullscreen | How FracTracker Maps Work

Incidents Relative to Other Operators

PHMSA’s hazardous liquid pipeline data account for more than 350 known pipeline operators. Some operators are fairly small, only maintaining a few miles of pipeline. Others are hard to track subsidiaries of larger companies. However, the big players stand out from the pack — some 20 operators account for more than 60% of all pipeline miles in the U.S., and Shell Pipeline is one of these 20.

Comparing Shell Pipeline to other major operators carrying HVLs, we found that Shell ranks 2nd in the nation in the most incidents-per-mile of maintained pipeline, seen in table 1 below. These numbers are based on the total incidents since 2002 divided by the number of miles maintained by each operator as of 2016 miles. Table 2 breaks Shell’s incidents down by year and number of miles maintained for each of those years.

Table 1: U.S. Pipeline operators ranked by incidents-per-mile

Operator HVL Incidents HVL Pipeline Miles Incidents Per Mile (2016)
Kinder Morgan 387 3,370 0.115
Shell Pipeline 194 3,490 0.056
Chevron 124 2,380 0.051
Sunoco Pipeline 352 6,459 0.049
ExxonMobile 240 5,090 0.048
Colonial Pipeline 244 5,600 0.044
Enbride 258 6,490 0.04
Buckeye Pipeline 231 7,542 0.031
Magellan Pipeline 376 12,928 0.03
Marathan Pipeline 162 5,755 0.029

Table 2: Shell incidents and maintained pipeline miles by year

Year Incidents Pipeline Miles Total Damage Notes
2002 15 no PHMSA data $2,173,704
2003 20 no PHMSA data $3,233,530
2004 25 5,189 $40,344,002 Hurricane Ivan
2005 22 4,830 $62,528,595 Hurricane Katrina & Rita
2006 10 4,967 $11,561,936
2007 5 4,889 $2,217,354
2008 12 5,076 $1,543,288
2009 15 5,063 $11,349,052
2010 9 4,888 $3,401,975
2011 6 4,904 $2,754,750
2012 12 4,503 $17,268,235
2013 4 3,838 $10,058,625
2014 11 3,774 $3,852,006
2015 12 3,630 $4,061,340
2016 6 3,490 $6,875,000
2017 9 no PHMSA data $242,800
2018 1 no PHMSA data $47,000 As of 3/1/18

Cause & Location of Failure

What were the causes of Shell’s pipeline incidents? At Shell’s public informational session, it was said that “in the industry, we know that the biggest issue with pipeline accidents is third party problems – when someone, not us, hits the pipeline.” However, PHMSA data reveal that most of Shell’s incidents issues should have been under the company’s control. For instance, 66% (128) of incidents were due to equipment failure, corrosion, welding failure, structural issues, or incorrect operations (Table 3).

Table 3. Shell Pipeline incidents by cause of failure

Cause Incidents
Equipment Failure 51
Corrosion 37
Natural Forces 35
Incorrect Operation 25
Other 20
Material and/or Weld Failure 15
Excavation Damage 11
Total 194

However, not all of these incidents occurred at one of Shell’s petrochemical facilities. As Table 4 below illustrates, at least 57 incidents occurred somewhere along the pipeline’s right-of-way through public areas or migrated off Shell’s property to impact public spaces. These numbers may be higher as 47 incidents have no mention of the property where incidents occurred.

Table 4. Shell Pipeline incidents by location of failure

Location Incidents
Contained on Operator Property 88
Pipeline Right-of-Way 54
Unknwon 47
Originated on Operator Property, Migrated off Property 3
Contained on Operator-Controlled Right-of-Way 2
Total 194

On several occasions, Shell has claimed that the Falcon will be safely “unseen and out of mind” beneath at least 4ft of ground cover. However, even when this standard is exceeded, PHMSA data revealed that at least a third of Shell’s incidents occurred beneath 4ft or more of soil.

Many of the aboveground incidents occurred at sites like pumping stations and shut-off valves. For instance, a 2016 ethylene spill in Louisiana was caused by lightning striking a pumping station, leading to pump failure and an eventual fire. In numerous incidents, valves failed due to water seeping into systems from frozen pipes, or large rain events overflowing facility sump pumps. Table 5 below breaks these incidents down by the kind of commodity involved in each case.

Table 5. Shell Pipeline incidents by commodity spill volumes

Commodity Barrels
Crude Oil 51,743
Highly Volatile Liquids 6,066
Gas/Diesel/Fuel 1,156
Petroleum Products 325
Total 59,290

Impacts & Costs

None of Shell’s incidents resulted in fatalities, injuries, or major explosions. However, there is evidence of significant environmental and community impacts. Of 150 incidents that included such data, 76 resulted in soil contamination and 38 resulted in water contamination issues. Furthermore, 78 incidents occurred in high consequence areas (HCAs)—locations along the pipeline that were identified during construction as having sensitive environmental habitats, drinking water resources, or densely populated areas.

Table 6 below shows the costs of the 194 incidents. These numbers are somewhat deceiving as the “Public (other)” category includes such things as inspections, environmental cleanup, and disposal of contaminated soil. Thus, the costs incurred by private citizens and public services totaled more than $80-million.

Table 6. Costs of damage from Shell Pipeline incidents

Private Property Emergency Response Environmental Cleanup Public (other) Damage to Operator Total Cost
$266,575 $62,134,861 $11,024,900 $7,308,000 $102,778,856 $183,513,192

A number of significant incidents are worth mention. For instance, in 2013, a Shell pipeline rupture led to as much as 30,000 gallons of crude oil spilling into a waterway near Houston, Texas, that connects to the Gulf of Mexico. Shell’s initial position was that no rupture or spill had occurred, but this was later found not to be the case after investigations by the U.S. Coast Guard. The image at the top of this page depicts Shell’s cleanup efforts in the waterway.

Another incident found that a Shell crude oil pipeline ruptured twice in less than a year in the San Joaquin Valley, CA. Investigations found that the ruptures were due to “fatigue cracks” that led to 60,000 gallons of oil spilling into grasslands, resulting in more than $6 million in environmental damage and emergency response costs. Concerns raised by the State Fire Marshal’s Pipeline Safety Division following the second spill in 2016 forced Shell to replace a 12-mile stretch of the problematic pipeline, as seen in the image above.

Conclusion

These findings suggest that while Shell is obligated to stress safety to sell the Falcon pipeline to the public, people should take Shell’s “good neighbor” narrative with a degree of skepticism. The numbers presented by PHMSA’s pipeline incident data significantly undermine Shell’s claim of having a proven track record as a safe and responsible operator. In fact, Shell ranks near the top of all US operators for incidents per HVL pipeline mile maintained, as well as damage totals.

There are inherent gaps in our analysis based on data inadequacies worth noting. Incidents dealt with at the state level may not make their way into PHMSA’s data, nor would problems that are not voluntary reported by pipeline operators. Issues similar to what the state of Pennsylvania has experienced with Sunoco Pipeline’s Mariner East 2, where horizontal drilling mishaps have contaminated dozens of streams and private drinking water wells, would likely not be reflected in PHMSA’s data unless those incidents resulted in federal interventions.

Based on the available data, however, most of Shell’s pipelines support one of the company’s many refining and storage facilities, primarily located in California and the Gulf states of Texas and Louisiana. Unsurprisingly, these areas are also where we see dense clusters of pipeline incidents attributed to Shell. In addition, many of Shell’s incidents appear to be the result of inadequate maintenance and improper operations, and less so due to factors beyond their control.

As Shell’s footprint in the Appalachian region expands, their safety history suggests we could see the same proliferation of pipeline incidents in this area over time, as well.

NOTE: This article was amended on 4/9/18 to include table 2.

Header image credit: AFP Photo / Joe Raedle

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: Methods, Mapping, & Analysis

Part of the Falcon Public EIA Project

FracTracker began monitoring Falcon’s construction plans in December 2016, when we discovered a significant cache of publicly visible GIS data related to the pipeline. At that time, FracTracker was looking at ways to get involved in the public discussion about Shell’s ethane cracker and felt we could contribute our expertise with mapping pipelines. Below we describe the methods we used to access and worked with this project’s data.

Finding the Data

Finding GIS data for pipeline projects is notoriously difficult but, as most research goes these days, we started with a simple Google search to see what was out there, using basic keywords, such as “Falcon” (the name of the pipeline), “ethane” (the substance being transported), “pipeline” (the topic under discussion), and “ArcGIS” (a commonly used mapping software).

In addition to news stories on the pipeline’s development, Google returned search results that included links to GIS data that included “Shell” and “Falcon” in their names. The data was located in folders labeled “HOUGEO,” presumably the project code name, as seen in the screenshot below. All of these links were accessed via Google and did not require a password or any other authentication to view their contents.

Shell’s data on the Falcon remained publicly available at this link up to the time of the Falcon Public EIA Project‘s release. However, this data is now password protected by AECOM.

Google search results related to Falcon pipeline data

Viewing the Data

The HOUGEO folder is part of a larger database maintained by AECOM, an engineering firm presumably contracted to prepare the Falcon pipeline construction plan. Data on a few other projects were also visible, such as maps of the Honolulu highway system and a sewer works in Greenville, NC. While these projects were not of interest to us, our assessment is that this publicly accessible server is used to share GIS projects with entities outside the company.

Within the HOUGEO folder is a set of 28 ArcGIS map folders, under which are hundreds of different GIS data layers pertaining to the Falcon pipeline. These maps could all be opened simply by clicking on the “ArcGIS Online map viewer” link at the top of each page. Alternatively, one can click on the “View in: Google Earth” link to view the data in Google Earth or click on the “View in: ArcMap” link to view the data in the desktop version of the ArcGIS software application. No passwords or credentials are required to access any of these folders or files.

As seen in the screenshot below, the maps were organized topically, roughly corresponding to the various components that would need to be addressed in an EIA. The “Pipeline” folder showed the route of the Falcon, its pumping stations, and work areas. “Environmental” contained data on things like water crossings and species of concern. “ClassLocations” maps the locations of building structures in proximity to the Falcon.

The HOUGEO GIS folders organized by topic

 

Archiving the Data

After viewing the Falcon GIS files and assessing them for relevancy, FracTracker went about archiving the data we felt was most useful for our assessing the project. The HOUGEO maps are hosted on a web server meant for viewing GIS maps and their data, either on ArcOnline, Google Earth, or ArcMap. The GIS data could not be edited in these formats. However, viewing the data allowed us to manually recreate most of the data.

For lines (e.g. the pipeline route and access roads), points (e.g. shutoff valves and shut-off valves), and certain polygons (e.g. areas of landslide risk and construction workspaces), we archived the data by manually recreating new maps. Using ArcGIS Desktop software, we created a new blank layer and manually inputted the relevant data points from the Falcon maps. This new layer was then saved locally so we could do more analysis and make our own independent maps incorporating the Falcon data. In some cases, we also archived layers by manually extracting data from data tables underlying the map features. These tables are made visible on the HOUGEO maps simply by clicking the “data table” link provided with each map layer.

Other layers were archived using screen captures of the data tables visible in the HOEGEO ArcOnline maps. For instance, the table below shows which parcels along the route had executed easements. We filtered the table in ArcGIS Online to only show the parcel ID, survey status, and easement status. Screen captures of these tables were saved as PDFs on our desktop, then converted to text using optical character recognition (OCR), and the data brought into Microsoft Excel. We then recreated the map layer by matching the parcel IDs in our newly archived spreadsheet to parcel IDs obtained from property GIS shapefiles that FracTracker purchased from county deeds offices.

Transparency & Caveats

FracTracker strives to maintain transparency in all of its work so the public understands how we obtain, analyze, and map data. A good deal of the data found in the HOUGEO folders are available through other sources, such as the U.S. Geological Survey, the Department of Transportation, and the U.S. Census, as well as numerous state and county level agencies. When possible, we opted to go to these original sources in order to minimize our reliance on the HOUGEO data. We also felt it was important to ensure that the data we used was as accurate and up-to-date as possible.

For instance, instead of manually retracing all the boundaries for properties with executed easements for the Falcon’s right-of-way, we simply purchased parcel shapefiles from county deeds and records offices and manually identified properties of interest. To read more on how each data layer was made, open any of our Falcon maps in full-screen mode and click the “Details” tab in the top left corner of the page.

Finally, some caveats. While we attempted to be as accurate as possible in our methods, there are aspects of our maps where a line, point, or polygon may deviate slightly in shape or location from the HOUGEO maps. This is the inherent downside of having to manually recreate GIS data. In other cases, we spent many hours correcting errors found in the HOUGEO datasets (such as incorrect parcel IDs) in order to get different datasets to properly match up.

FracTracker also obtained copies of Shell’s permit applications in January by conducting a file review at the PA DEP offices. While these applications — consisting of thousands of pages — only pertain to the areas in Pennsylvania where the Falcon will be built, we were surprised by the accuracy of our analysis when compared with these documents. However, it is important to note that the maps and analysis presented in the Falcon Public EIA Project should be viewed with potential errors in mind.

* * *

Related Articles

For schools and hospitals analysis, 2017

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

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

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

Ohio Schools and Medical Facilities

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

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


View map fullscreen | How FracTracker maps work
Explore the data used to make this map in the “Data Downloads” section at the end of this article.

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

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

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

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


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

Grade Level Comparisons

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


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

Public Schools in Ohio

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

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

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

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

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


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

Private Schools in Ohio

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

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

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

West Virginia Schools and Students

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

Map of WV Marcellus Activity and Schools


View map fullscreen | How FracTracker maps work
Explore the data used to make this map in the “Data Downloads” section at the end of this article.

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

figure6

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

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

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

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

Conclusion

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

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

Analysis Methods

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

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

Data Downloads for Maps Above


By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

Bill Hughes giving tour to students in shale fields, WV

A Cross-Country Ride to Support Oil and Gas Tours in West Virginia

Bill Hughes giving tours of gas fields in West Virginia. Photo by Joe Solomon. https://flic.kr/s/aHskkXZj3z

Bill Hughes giving a tour of gas fields in West Virginia. Photo by Joe Solomon.

As many of you know, educating the public is a FracTracker Alliance core value – a passion, in fact. In addition to our maps and resources, we help to provide hands-on education, as well. The extraordinary Bill Hughes is a FracTracker partner who has spent decades “in the trenches” in West Virginia documenting fracking, well pad construction, water withdrawals, pipeline construction, accidents, spills, leaks, and various practices of the oil and gas industry. He regularly leads tours for college students, reporters, and other interested parties, showing them first-hand what these sites look, smell, and sound like.

While most of us have heard of fracking, few of us have seen it in action or how it has changed communities. The tours that Bill provides allow students and the like to experience in person what this kind of extraction means for the environment and for the residents who live near it.

Biking to Support FracTracker and Bill Hughes

Dave Weyant at the start of his cross-country bike trip in support of WV tours

Dave Weyant at the start of his cross-country Pedal for the Planet bike trip

In the classic spirit of non-profit organizations, we work in partnership with others whenever possible. Right now, as you read this posting, another extraordinary Friend of FracTracker, Dave Weyant (a high school teacher in San Mateo, CA), is finishing his cross-country cycling tour – from Virginia to Oregon in 70 days.

Dave believes strongly in the power of teaching to reach the hearts of students and shape their thinking about complicated issues. As such, he has dedicated his journey to raising money for FracTracker. He set up a GoFundMe campaign in conjunction with his epic adventure, and he will donate whatever he raises toward Bill’s educational tours.

Help us celebrate Dave Weyant’s courage, vision, and generosity – and support Bill Hughes’s tireless efforts to open eyes, evoke awareness, and foster communication about fracking – by visiting Dave’s GoFundMe page and making a donation. Every gift of any size is most welcome and deeply appreciated.

100% of the funds raised from this campaign will go to support Bill’s oil and gas tours in West Virginia. FracTracker Alliance is a registered 501(c)3 organization. Your contribution is tax deductible.

And to those of you who have already donated, thank you very much for your support!

Clearing land for shale gas pipeline in PA

A Push For Pipelines

By Bill Hughes, WV Community Liaison

For anyone who even casually follows Marcellus and Utica shale gas exploration and production, such as in the active gas fields of West Virginia or Southwestern PA or Ohio, we know there are many concerns surrounding the natural gas production process. These issues range from air pollution, water consumption and contamination, to waste disposal. We know that, after all well the pad drilling and construction traffic are done, we must also have pipelines to get the gas to compressor stations, processing plants, and to markets in the Eastern United States (and likely Europe and Asia in the near future). Gas companies in Wetzel County, WV, and in neighboring tri-state counties, are convinced that building pipelines – really big pipelines – will be the silver bullet to achieving some semblance of stability and profitability.

Problems With Proposed Pipelines

One of the new, very large diameter (42”) proposed gas pipelines getting attention in the press is the Mountain Valley Pipeline, which will originate in the village of Mobley in eastern Wetzel County, WV and extend Southeast, through national forests and over the Appalachian Mountains into the state of Virginia. Even if the residents of Wetzel County and other natural gas fields are guinea pigs for experiments with hydraulic fracturing, we know how to build pipelines, don’t we? The equipment, knowledge, and skill sets needed for pipeline construction is readily available and commonly understood compared to high pressure horizontal drilling with large volumes of slick water. So, what could go wrong?

I can answer that question first hand from my hayfield in Wetzel County. Almost two years ago, EQT wanted to survey my property for a similar proposed pipeline – this one 30” in diameter, called the Ohio Valley Connector (OVC). The application for this project has now been filed with the Federal Energy Regulatory Commission (FERC). The below map shows a section of the OVC as proposed almost two years ago. The red outlined area is my property. The yellow line shows one proposed pathway of the 30” pipeline that would cross our land. Multiple routes were being explored at first. Were this version approved, it would have gone right through my hayfield and under our stream.

A section of the OVC as proposed almost two years ago.

A section of the OVC as proposed almost two years ago. The red outlined area is my property. The yellow line shows one proposed pathway of the 30” pipeline that would cross our land.

Pipeline opponents express concern about habitat fragmentation, the crossing of pristine streams and rivers, erosion and sedimentation issues, spills, gas leaks, and possible explosions. These are all very valid concerns. But the potential for other logistical errors in the building process – from very simple to potentially serious ones – are also worth consideration. In this article I will use my recent personal experience as a detailed and documented example of how a professionally surveyed location on my property contained an error of almost one mile – over 4,000 feet – as part of a pipeline construction planning project. Yes, you read that right.

Part I: How Did We Get To This Point

Before we get to my story, I should review my first contact with EQT on this issue. In February of 2014, an EQT land agent asked me for permission to walk my property for preliminary evaluation of a route that would send their 30” high-pressure pipe through our land, from south to north.

It is important to keep in mind that almost every landowner in Wetzel County has been contacted by mail, phone or in person, by land agents promising cash with a verbal assurance that all will be well. The goal is to get a landowner’s signature on a loosely worded “right of way” (RoW) lease contract, with terms favorable to the gas company, and move on. Unfortunately, pipeline lease offers cannot be ignored. Not objecting or not questioning can sometime leave the landowner with fewer choices later. This is because many of the bigger interstate transmission lines are being proposed as FERC lines. When final approval is granted by FERC, these pipelines will have the legal power of eminent domain, where the property owner is forced to comply. Just filing a FERC application does not grant eminent domain in West Virginia, as it seems to in Virginia, but the potential for eminent domain gives land agents power over landowners.

I was not ready to give them surveying permission (to drive stakes or other permanent markers). Since a natural gas pipeline would affect all my neighbors, however, I agreed to allow a preliminary walk through my property and to hang surveyor ribbons in exchange for answering my questions about the project. For instance, one of my biggest concerns was the potential for significant habitat fragmentation, splitting up the forest and endangering wildlife habitat.

There are many questions residents should consider when approached by land agent. A list of these questions can be found in the appendix below.

I never did get answers to most of my questions in the few e-mail exchanges and phone conversations with EQT. I never saw the surveyors either. They simply came and left their telltale colored ribbons. Later, at a public meeting an EQT representative said the closest they would run the pipe to any residence would be 37.5 feet. That number is correct. I asked twice. They said they had the right to run a pipeline that close to a residence but would do their best not to. The 37.5 feet is just one half of the permanent RoW of 75 feet, which was also only part of a 125 foot RoW requested for construction. A few months later, a very short e-mail said that the final pipeline route had changed and they would not be on my property. For a time we would enjoy some peace and quiet.

A Word On Surveyors

Most folks can relate to the work and responsibility of bookkeepers or Certified Public Accountants (CPAs). They measure and keep track of money. And their balance sheets and ledgers actually have to, well, BALANCE. Think of Surveyors as the CPAs of the land world. When they go up a big hill and down the other side, the keep track of every inch — they will not tolerate losing a few inches here and there. They truly are professionals, measuring and documenting everything with precision. Most of the surveyors I have spoken with are courteous and respectful. They are a credit to their profession. They are aware of the eminent domain threat and their surveying success depends on treating landowners with respect. They are good at what they do. However, as this article will show, their professional success and precision depends on whether or not they are given the correct route to survey.

Part II: Surveyor Stakes and Flags

Over the next year we enjoyed peace and quiet with no more surveyors’ intrusions. However, in my regular travels throughout the natural gas fields here, countless signs of surveyor activity were visible. Even with the temporary slowdown in drilling, the proposed pipeline installations kept these surveyors busy. Assorted types of stakes and ribbons and markings are impossible to miss along our roads. I usually notice many of the newer surveyor’s flags and the normal wooden stakes used to mark out future well pads, access roads, compressor stations, and more recently pipelines. Given that survey markings are never taken down when no longer needed, the old ones sometimes hide the new ones.

It can be difficult keeping track of all of them and hard at first to identify why they are there. Even if sometimes I am not sure what a stake and flag might indicate, when one shows up very unexpectedly in what is essentially my front yard, it is impossible to not see it. That is what happened in August of 2015. Despite being unable to get our hay cut due to excessive rain the previous month, the colored flags were highly visible. Below shows one of the stakes with surveyor’s tape, and the hay driven down where the surveyors had parked their trucks in my field alongside my access road.

A surveyor stake alongside my access road.

A surveyor stake alongside my access road.

To call it trespassing might not be legally defensible yet. The stakes were, after all, near a public roadway – but the pins and stakes and flags were on my property. Incidents like this, whether intentional or accidental, are what have given the natural gas companies a reputation as bad neighbors. There were surveyors’ stakes and flags at two different locations, my hay was driven down, and I had no idea what all this meant given that I had no communication from anyone at EQT in over 18 months. I consider myself fortunate that the surveyors did not stray into wooded areas where trees might have been cut. It’s been known to happen.

Below shows the two sets of wooden stakes, roughly 70-80 feet apart, with flags and capped steel rebar pins. Both stakes were near the road’s gravel lane, which is a public right of way. Nevertheless, the stakes were clearly on my property. The markings on one side of the stake identify the latitude, longitude, and the elevation above sea level of the point. The other side of the stake identified it as locating the OVC pipeline (seen here as “OVC 6C):

These identifying numbers are unique to this pin which is used to denote a specific type of location called a “control point.” Control points are usually located off to the side of the center-line of the pipeline:

A control point, located off to the side of the center-line of the pipeline.

A control point, located off to the side of the center-line of the pipeline.

It seemed that somehow, without informing me or asking permission to be on my land, EQT had changed their mind on the OVC route and were again planning to run a pipeline through my property. If this was intentional, both EQT and I had a problem. If this was some kind of mistake, then only EQT would have a problem. Either way I could not fathom how this happened. Trespassing, real or perceived, is always a sensitive topic. This is especially true since, when I had initially allowed the surveyor to be on my property, I had not given permission for surveying. Given concerns about eminent domain, I wanted answers quickly. I documented all this with detailed pictures in preparation for contacting EQT representatives in Pittsburgh, PA, with my complaints.

Part III: What Happened & How?

I think it is safe to say that, in light of my well-known activism in documenting all things Marcellus, I am not your average surface owner. I have over 10,000 photographs of Marcellus operations in Wetzel County and I document every aspect of it. Frequently this leads to contacting many state agencies and gas operators directly about problems. I knew which gas company was responsible and I also knew exactly who in Pittsburgh to contact. To their credit, the person I contacted at EQT, immediately responded and it took most of the day to track down what had happen. The short story was that it was all a simple mistake—a 4,300 foot long mistake—but still just a mistake. The long story follows.

The EQT representative assured me that someone would be out to remove their stakes, flags and the steel pins. I told them that they needed to be prompt and that I would not alter or move their property and locating points. The next day, when I got home, the stakes with flags were gone. Just a small bare patch of dirt remained near the white plastic fencepost I had placed to mark the location. However, since I am a cultivated skeptic—adhering to the old Russian proverb made famous by President Reagan, “Trust but Verify”—I grabbed a garden trowel, dug around a bit, and clink, clink. The steel pin had just been driven deeper to look good, just waiting for my tiller to locate someday. I profusely re-painted the pin, photographed it, and proceeded to send another somewhat harsh e-mail to EQT. The pin was removed the next day.

After all the stakes, ribbons, and steel pins were removed, EQT provided further insights into what had transpired. Multiple pipeline routes were being evaluated by EQT in the area. Gas companies always consider a wide range of constraints to pipeline construction such as road and stream crossings, available access roads, permission and cooperation of the many landowners, steepness of terrain, etc. At a certain point in their evaluation, a final route was chosen. But for unknown reasons the surveyor crew was given the old, now abanoned, route on which to establish their control points. The magnitiude of the error can be seen on the map below. The bright blue line is the original path of the OVC pipeline through my property and the red line shows where the FERC filed pipeline route will go. A new control point has now been established near the highway where the pipeline was meant to cross.

The FERC filed OVC pipeline route vs. the accidentally surveyed route.

The FERC filed OVC pipeline route vs. the accidentally surveyed route.

 

Part IV: Lessons To Be Learned

Given the likely impact of many proposed large-diameter, very long, pipelines being planned, it seems useful to examine how these errors can happen. What can we learn from my personal experience with the hundreds of miles of new pipelines constructed in Wetzel County over the past eight years? First, it is important to ask whether or not similar problems are likely to happen elsewhere, or if this was this just an isolated incident. Can we realistically expect better planning on the proposed Mountain Valley Pipeline, which will run for over 300 miles? Can the residents and landowners living along these pipeline RoWs expect more responsible construction and management practices?

In general, many of the pipeline projects with which landowners, such as those in Wetzel County, are familiar with fall into the unregulated, gathering line category. They might be anywhere from six inches in diameter up to sixteen inches. As we review their track record, we have seen every imaginable problem, both during construction and after they were put into operation. We have had gas leaks and condensate spills, hillside mud slips, broken pipes, erosion and sedimentation both during construction and afterwards.

Now for some apparently contradictory assumptions—I am convinced that, for the most part, truck drivers, pipeliners, equipment operators, drilling and fracturing crews, well tenders and service personnel at well sites, all do the best job they can. If they are given the proper tools and materials, accurate directions with trained and experienced supervision, the support resources and the time to do a good job, then they will complete their tasks consistently and proudly. A majority of employees in these positions are dedicated, trained, competent, and hard working. Of course, there are no perfect contractors out there. These guys are human too. And on the midnight shift, we all get tired. In the context of this story, some pipeline contractors are better and more professional than others, some are more experienced, and some have done the larger pipelines. Therefore, despite best intentions, significant errors and accidents will still occur.

The Inherent Contradictions

It seems to me that the fragile link in natural gas production and pipeline projects is simply the weakness of any large organization’s inherent business model. Every organization needs to constantly focus on what I refer to as the “four C’s—Command and Control, then Coordination and Communication—if they are to be at all successful. It is a challenge to manage these on a daily basis even when everyone is in the same big building, working for the same company, speaking the same language. This might be in a university, or a large medical complex, or an industrial manufacturing plant.

But the four C’s are nearly impossible to manage due to the simple fact that the organizational structure of the natural gas industry depends completely on hundreds of sub-contractors. And those companies, in turn, depend on a sprawling and transient, expanding and collapsing, network of hundreds of other diverse and divergent independent contractors. For example, on any given well pad, during the drilling or fracturing process, there might be a few “company” men on site. Those few guys actually work for the gas company in whose name the operating permit is drawn. Everyone else is working for another company, on site temporarily until they are ready to move on, and their loyalty is elsewhere.

In the best of situations, it is next to impossible to get the right piece of information to the right person at just the right time. Effective coordination among company men and contractors is also next to impossible. I have seen this, and listened in, when the drilling company is using one CB radio channel and the nearby pipeline company is using some private business band radio to talk to “their people.” In that case, the pipeline contractors could not talk to the well pad—and it did not matter to them. In other cases, the pilot vehicle drivers will unilaterally decide to use another CB radio channel and not tell everyone. I have also watched while a massive drill rig relocation was significantly delayed simply because a nearby new gas processing plant was simultaneously running at least a hundred dump trucks with gravel on the same narrow roadway. Constant communication is a basic requirement for traffic coordination, but next to impossible to do properly and consistently when these practices are so prevalent.

These examples illustrate how companies are often unable to coordinate their operations. Now, if you can, just try to picture this abysmal lack of command and control, and minimal communication and coordination, in the context of building a 300-mile length of pipeline. The larger the pipeline diameter, and the greater the overall length of the pipeline, the more contractors will be needed. With more contractors and sub-contractors, the more coordination and communication are essential. A FERC permit cannot fix this, nor would having a dozen FERC permits. Unfortunately, I do not envision the four Cs improving anytime soon in the natural gas industry. It seems to be the nature of the beast. If, as I know from personal experience, a major gas company can arrange to locate a surveyed control point 4,300 feet from where it should have been, then good luck with a 300 mile pipeline. Even with well-intentioned, trained employees, massive problems are still sure to come.

The FERC approvals for these pipelines might not be a done deal, but I would not bet against them. So vigilance and preparation will still be of the essence. Citizen groups must be prepared to observe, monitor, and document these projects as they unfold. If massive pipelines like the MVP and OVC are ever built, they should become the most photographed, measured, scrutinized, and documented public works projects since the aqueducts first delivered water to ancient Rome. For the sake of protecting the people and environment of Wetzel County and similar communities, I hope this is the case.

By Bill Hughes, WV Community Liaison, FracTracker Alliance
Read more Field Diary articles.

Appendix: Questions to Ask When Approached by a Land Agent (Landsman)

These questions can be modified to suit your location. The abbreviation “Gas Corp.” is used below to reference a typical natural gas company or a pipeline subsidiary to a natural gas company.  These subsidiaries are frequently called Midstream Companies. Midstream companies build and manage the pipelines, gas processing, and some compressor stations on behalf of natural gas companies.

  1. Please provide a Plain English translation of your landowner initial contract.
  2. What will Gas Corp. be allowed to do, and not allowed to do, short term and long term?
  3. What will Gas Corp. be required to do, and not required to do?
  4. What is the absolute minimum distance this pipeline will be placed away from any dwelling anywhere along its entire length?
  5. What restrictions will there be on the my land after you put in the pipelines?
  6. Who will be overseeing and enforcing any environmental restrictions (erosion and sedimentation, slips, stream crossings, etc.)?
  7.  Who will be responsible for my access road upkeep?
  8. Who will be responsible for long term slips and settlements of surface?
  9. When would this construction begin?
  10. When would all work be completed?
  11. Who would be responsible for long term stability of my land?
  12. Will the pipeline contractor(s) be bound to any of our agreements?
  13. Who are the pipeline contractor(s)?
  14. What will be transported in the pipeline?
  15. Will there be more than one pipe buried?
  16. How wide is the temporary work RoW?
  17. How wide is the permanent RoW?
  18. How deep will the pipeline(s) be buried?
  19. What size pipe will it be; what wall  thickness?
  20. How often will the welds on the individual pipe segments be inspected?
  21. Will there be any above ground pipeline components left visible?
  22. Where will the pipe(s) originate and where will they be going to?
  23. What will the average operating pressure be?
  24. What will the absolute maximum pressure ever be?
  25. At this pressure and diameter, what is the PIR—Potential Impact Radius?
  26. Will all pipeline and excavating and laying equipment be brought in clean and totally free from any invasive species?
  27. How will the disturbed soil be reclaimed?
  28. Will all top soil be kept separate and replaced after pipeline is buried?
  29. Also, After all the above is settled, how much will I be paid per linear foot of pipeline?

Surveyor Symbols & Signs – A Guide

The following guide is a simplified description of a variety of markings that are used by land surveyors. Throughout an active shale gas field, the first signs of pending expansions are the simple markings of stakes, flags, and pins. Many months or even years before the chain saw fells the first tree or the first dozer blade cuts the dirt at a well pad location, the surveyors have “marked the target” on behalf of their corporate tactical command staff.

The three most commonly used markings are the simple stakes, flags and pins. These surveyor symbols are common to any construction project and guarantee that everything gets put in the right place. In an active gas field, these marking tools are used for all aspects of exploration and production:

  • access roads to well pads,
  • widening the traveled portion of the roadway,
  • well locations,
  • ponds and impoundment locations,
  • temporary water pipeline paths,
  • surface disturbance limits,
  • compressor stations,
  • gas processing sites, and
  • rights-of-way for roads and pipelines.

Quite frequently these simple markings are undecipherable by themselves, especially by non-professionals. One cannot just know what is happening, what is likely to occur, or how concerned one should be. Context and additional information are usually needed. Sometimes the simple colors and combinations of colored tapes might only make sense in conjunction with similar markings nearby. Sometimes public notices in the newspaper and regulatory permits must be used to decipher what is planned.

For an example, the proposed 30″ diameter EQT pipeline called the Ohio Valley Connector seems to be regularly marked using a combination of blue and white (see figure 10 below) surveyors tape to mark the actual pipeline location, then green and white (see figure 4 below) to mark all the proposed access roads along the routes that will be used to get pipe trucks and excavation equipment into the right of way. These access roads might be public roadways or cut across private leased property.

Common surveyor symbols & signs (click on images to zoom in)

Surveyor flags and tape: Sometime the flags or streamers are just attached to trees, fence posts, or put on a stake to make them visible above the weeds. There might be no markings on the stake, or only simple generic markings. This could just mean that this is the correct road and turn here. It could also signal a proposed or approximate location for some future work.

Simple surveyor’s flags or tape

Simple surveyor’s flags or tape

Surveyor flags and tapes: These are a selection of typical surveyor tapes, also called flags or ribbons. Many other specialty color combinations are available to the professional surveyor.

A selection of surveyor tapes

Stakes with simple markings: Flags with some type of identification (it might be names or numbers). This one was used for a proposed well pad access road location. There are no dimensions given on these.

Stake with simple markings

Stakes with simple flags and basic identification: The stakes shown here all indicate an access route to be used for equipment and trucks to get to a proposed pipeline right of way. The “H310″ is the EQT name for the 30” OVC pipeline.

Stakes indicating an access route

Control points: These three stakes are identifying a control point that is outside the limits of disturbance (LoD). These markings surround a pin to be used for reference.

Control point stakes

Controls points: This stake is also identifying a control point location. All control points will have some type of driven metal rod, usually with a plastic cap identifying the surveyor. Frequently there are three stakes with extra flags or tape. They are always set off to the side of the intended work area. They are not to be disturbed.

Control point stake and pin

Control points: Another set of three stakes marking a Control Point location. It is common to see triple stakes with elaborate, multiple flags. Even if only two stakes are present, there always will be a driven steel pin and identifying cap.

Control point stakes and pin

Control points: This shows a close-up of the identifying cap on a metal driven steel pin. Control point locations are not meant to be disturbed as they are for future and repeated reference. They might give the latitude and longitude on the stake plus the altitude above sea level.

Control point pin and cap

Control points: This is another, older control point location. This represents a typical arrangement where the stakes somewhat try to protect the metal pin from a bulldozer blade by warning its operator.

Control point pin protection

Limit of disturbance: The “L O D” here means the limits of disturbance. Beyond this point there should not be any trees cut or dirt moved. The stakes shown here indicates that this is the outside limit of where the contractor will be disturbing the original contour of the surface soil.

Limit of disturbance stakes

Limit of disturbance: The “L O D” means the limits of disturbance of the proposed pipeline right of way. Beyond this point there should not be any trees cut or dirt moved. This could also be used for the outside edge of well pads or access roads or pond locations.

Limit of disturbance ROW stakes

Pipelines: Stakes with flags and “center line” markings are usually for pipelines. Here you see the symbol for center line: a capital letter “C” imposed on the letter “L”.

Pipelines center line

Pipelines: Again you see the capital letter “C” super imposed on top of the letter “L” used frequently for pipe line center lines, but can also be used for proposed access roads.

Pipelines center line

Pipelines: As shown here, “C” and “L” center line flags can also be used for future well pad access roads.

Road access center line

Precise location markings: Stakes like this will usually have a steel pin also associated with it. This stake gives the latitude, longitude, and elevation of the site.

Precise location stake

Permanent property lines: You may also find markings, like this one inch steel rod with an alum cap, that denote permanent property lines and corners of property.

Permanent property rod

Permanent property lines: Another kind of permanent property line or corner marker is the “boundary survey monument.” This is likely an aluminum cap on top of a one inch diameter steel bar.

Boundary survey monument

Landfill disposal of drill cuttings

Landfill Disposal of WV Oil and Gas Waste – A Report Review

By Bill Hughes, WV Community Liaison

As oil and gas drilling increases in West Virginia, the resulting waste stream must also be managed. House Bill 107 required the Secretary of the West Virginia Department of Environmental Protection to investigate the risks associated with landfill disposal of solid drilling waste. On July 1, 2015, a massive report was issued that details the investigation and its results: Examination of Leachate, Drill Cuttings and Related Environmental, Economic and Technical Aspects Associated with Solid Waste Facilities in West Virginia, by Marshall University.

While I must commend the State for looking into this important issue, much more needs to be done, and I have serious concerns about the validity of several aspects of this study. Since the report is almost 200 pages long, I will summarize its findings and my critiques below.

Summary of Waste Disposal Concerns in Report

The page numbers that I reference below refer to the page numbers found within the PDF version of the full study.

  1. Marcellus shale cuttings are radioactive: pgs. 17, 139, 142, 154
  2. We do not know if there is a long term problem: pg. 19
  3. About 30 million tons of waste in next few decades: pg. 176
  4. Landfill liners leak: pg. 20
  5. Owning & operating their own landfill would be expensive & risky for gas companies: pgs. 186-7
  6. Toxicity and biotic risk from drill cuttings is uncharted territory: pg. 78
  7. Landfill leachate is toxic to plants & invertebrates: pgs. 16, 95, 97
  8. Other landfills also have radioactive waste: pgs. 14-15
  9. We have no idea if this will get worse: pgs. 96, 154
  10. If all systems at landfills work as designed, leachate might not affect ground water: pg. 41

Introduction

WV Field Visits 2013

Drilling rig behind a wastewater pond in West Virginia

Any formal report comprised of 195 pages generated by a reputable school like Marshall University with additional input from Glenville State College – supported by over 2,300 pages of semi-raw data and graphs and charts and tables – requires some serious investigation prior to making comprehensive and final conclusions. However, some initial observations are needed to provide independent perspective and to help reflect on how sections of this report might be interpreted.

The overarching perspective that must be kept in mind is that the complete study was first limited by exactly what the legislature told the WV Department of Environmental Protection DEP to do. Secondly, the DEP then added other research guidelines and determined exactly what needed to be in the study and what did not belong. There were also budget and time constraints. The most constricting factor was the large body of existing data possessed by the DEP that was provided to the researchers and report writers. Because of the time restrictions, only a small amount of additional raw data could be added.

And most importantly, similar to the WVU Water Research Institute (WVU WRI) report from two years ago, it must be kept in mind that these types of studies, initiated by those elected to our well-lobbied legislature and funded and overseen by a state agency, do not occur in a political power vacuum. It was surely anticipated that the completed report might have the ability to affect the growing natural gas industry – which is supported by most in the political administration. Therefore, we must be cautious here. The presence and influence of political and economic factors need to be considered. Also, for universities to receive research contracts and government paid study requests, the focus must include keeping the customer satisfied.

My comments below on the report’s methods and findings are organized into three broad and overlapping categories:

  • GOOD  –  positive aspects, good suggestions, important observations
  • GENERAL  –  general comments
  • FLAW  –  problems, flaws, limitations
  • MOVING FORWARD  – my suggestions & recommendations

I. Water Quality: EPA Test Protocols & Datasets

Marcellus Shale (at the surface)

Marcellus Shale (at the surface)

GENERAL  It is obvious that a very smart and well-trained set of researchers put a lot of long, detailed thought into analyzing all of the available data. There must be tens of thousands of data points. Meticulous attention was put into how to assemble all of the existing years’ worth of leachate chemical and radiological information.

GOOD  There is an elaborate and detailed discussion of how to best analyze everything and how to utilize the best statistical methods and generate a uniform and integrated report. This was made difficult with non-uniform time intervals, some non-detect values, and some missing items. The researchers used a credible process, explaining how they applied the various appropriate statistical analysis methods to all the data. They provided some trends and observations and draw some conclusions.

FLAW 1  The most glaring flaw and the greatest limitation pertaining to the data sets is the nature of the very data set, which was provided to the researchers from the DEP. It is to the commendable credit of the DEP that the leachate at landfills receiving black shale drill cuttings from the Marcellus and other shale formations were, from the beginning, required to start bi-monthly testing of leachate samples at landfills that were burying drill waste products. And in general, when compared to on-site disposal as done for conventional wells, it was initially a good requirement to have the drill cuttings put into some type of landfill; that way we could keep track of where the drill cuttings are located when there are future problems.

To the best of my knowledge, until the states in the Marcellus region started allowing massive quantities of black shale waste material to be put into local landfills, we have never knowingly deposited large quantities of known radioactive industrial waste products into generic municipal waste landfills. The various waste products and drill cuttings of Marcellus black shales have been known for decades by geologists and radiochemists to be radioactive. We know better than to depose of hazardous radioactive waste in an improper way. Therefore, it is very understandable that we might not know how to best solve the problems of this particular waste product. This was and still is new territory.

FLAW 2  All of the years of leachate test samples were processed for radioactivity using what is called the clean drinking water test protocols, also referred to as the EPA 900 series. Three years ago, given the unfamiliarity of regulatory agencies with the uniqueness of this waste problem, we chose the wrong test protocol for assessing leachate samples. We speculated that the commonly used and familiar clean drinking water test procedure would work. So now we have a massive set of test results all derived from using the wrong test protocol for the radiologicals. Fortunately, all of the chemistry test results should still be reasonably useful and accurate.

At first, three years ago, this was understandable and possibly not an intentional error. Now it is widely known by hydrogeologists and radiochemists, however, that the plain EPA 900 series of test methods for determining the radioactivity of contaminated liquids do not work on liquids with high TDS — Total Dissolved Solids. Method 900.0 is designed for samples with low dissolved solid like finished drinking water supplies.

Despite this major and significant limitation, the effort by Marshall University still has some utility. For example, doing comparisons between and among the various landfills accepting drill waste might provide some interesting observations and correlations. It is clearly known now, however, that the protocols that were used for all samples from the start when testing for gross alpha, gross beta and radium-226 and radium-228 in leachate, can only result in very inaccurate, under-reported data. Therefore, it is not possible to draw any valid conclusions on several very important topics, including:

  • surface water quality,
  • potential ground water contamination,
  • exposure levels at landfills and public health implications,
  • and policy and regulations considerations.

Labs certified to test for radiological compounds and elements are very familiar with the 900 series of EPA test procedures. These protocols are intended to be used on clean drinking water. They are not intended to be used on “sludgy” waters or liquids contaminated with high dissolved solids like all the many liquid wastes from black shale operations like flowback and produced water and brines and leachate. The required lab process for sample size, preparation, and testing will guarantee that the results will be incorrect.

In no place in the final 195 page report have I seen any discussion of which EPA test protocol was used for the newer samples and why was it used. It has also not yet been seen in the 2,300+ pages of supportive statistical and analytical results, either. The fact that the wrong protocol was used three years ago is very understandable. However, this conventional EPA 900 series was still being used on the additional very recent (done in fall of 2014 and spring of 2015) samples that were included in the final report. The researchers, without any justification or discussion or explanations continued to use the wrong test protocol.

The clean drinking water procedures should have been used along with the 901.1M (gamma spec) process, for comparison. It is understandable for the new data to be consistent and comparable with the very large existing dataset that a case could be made for using the incorrect protocol and the proper one also. There should have been a detailed discussion of what and why any test method was being used, however. That discussion is usually one of the first topics investigated and explained in the Methods section. Having that type of discussion and justification seems to represent a basic science method and accepted research process – and that omission is a serious flaw.

MOVING FORWARD  We all know that if we want to bake an appetizing and attractive cake we must use the correct measuring cups for the ingredients. If we want to take our child’s temperature we need an accurate thermometer. When our doctor helps us understand our blood test results, we all want to be confident the right test was used at the lab. The proper test instrument, recently calibrated and designed for the specific sample, is crucial to get useable test results from which conclusions can be drawn and policy enacted.

It seems that the best suggestion so far to test high TDS liquids similar to leachate would be to use what is referred to as Gamma-ray Spectrometry with a high purity germanium instrument with at least a 21-day hold period (30 days are better), while the sample is sealed then counted for at least 16 hours. Many of the old leachate test results indicate high uncertainties that might be attributed to short hold times and short counting times. This procedure is referred to as the 901.1 M (modified). If the sample is sealed, the sample will reach about 99% equilibrium after 30 days. Radon 222 (a gas) must not be allowed to escape.

The potential environmental impacts to water quality section of this report seems to demonstrate that if you do not want to find out something, there are always justifiable options to avoid some inconvenient facts. Given the very narrow scope as defined, some the Marshall University folks did not seem to have the option to stray into important scientific foundational assumptions and, for the most part, just had to work with the stale data sets given to them. All of which, as we have known for close to a year now, have used the wrong test protocol. Therefore we have incorrect results of limited value.

II. Marcellus is Radioactive

GOOD 1  Of course, geologists have known that the Marcellus Shale is radioactive for many decades, but also for decades there has been great reluctance by the natural gas exploration and production companies to acknowledge this fact to the public. And finally we now have a public report that clearly and unambiguously states that Marcellus shale is radioactive. Interestingly enough, it was not much more than a year ago that some on the WV House of Delegates Judiciary Committee, seemed to be echoing the industry’s intentional deception by declaring that:

…it was only dirt and rock…

So this report represents progress and provides a very valuable contribution to beginning to recognize some of the potential problems with shale wastes and their disposal challenges.

GOOD 2  Another very important advance is that finally after eight years of drilling here in Wetzel County, we now have a test sample from near the horizontal bore. The WVU WRI study researchers were never given access to any samples taken from the horizontal bore material itself, however. That was, of course, what they were supposed to have been allowed to do, but they were only given access to study material from the vertical section of the well bore. This report describes how we are getting closer to actually testing good samples of the black shale. It seems that we have gotten closer – but let’s see how close.

Page 11 describes that only three Antero wells in Doddridge County were chosen as the place to try to obtain samples from the horizontal bore. Considering that over 1,000 deviated/horizontal wells or wells with laterals have been drilled in the past few years, that number represents a very small fraction of wells drilled: less than .3%. Even if a high quality sample could have been obtained it might be a challenge to extrapolate test results to the waste being produced from the other wells in WV. These limitations are completely ignored in the report, however. Given the available documentation from the DEP, this seems to be a serious flaw that compromises the reliability of the entire report.

III. Samples From Vertical vs. Horizontal Well Bores

FLAW  The actual samples tested from at least two of the three wells used in the study do not seem to be from the horizontal bore material. The sample from the third well might have come from the horizontal bore, but just barely. There is no way to know for sure. I will try to show this within the below chart using information provided by Antero to DEP Office of Oil & Gas. This information is in state records on Antero’s well plats, which become part of the well work application and also part of the final permit.

Table 1. Details about the samples taken from three Antero wells in Doddridge County, WV – and my concerns about the sampling process*

Antero well ID API # Sample’s drilling depth Marcellus depth** Horizontal bore length** Comments / Issues
Morton 1H 47-017-06559 6,856 ft. 7,900 TVD*** 10,600 ft. ~1,044 ft. short of reaching Marcellus formation
McGee 2H 47-017-06622 6,506 ft. 6,900 TVD 8,652 ft. ~394 ft. short of reaching Marcellus
Wentz1 H 47-017-06476 8,119 ft. 7,900 TVD 8,300 ft. Just drilled into Marcellus by 219 ft.
* Original chart found on page 11 of report
** Based on information from Antero’s well plat
*** TVD = Total Vertical Depth

Antero is an active driller in Doddridge County. If any company knows where to find the Marcellus formation it is that company. Well plats are very detailed, technical documents provided to the DEP by the operator regarding the well location, watershed, and leased acres and property boundaries. We need to trust that the information on those plats is accurate and has been reviewed and approved by the permitting agency. Those plats also give the depth of the Marcellus and the length and heading of the lateral or horizontal bore. The Marshall University report gives the drilling depth when the sample was taken on the surface. Using these available well plat records from the DEP it appears that at two of the wells the sample (and its test results included in the report) came from material produced when the experienced drilling operator was not yet into the shale formation.

On the third well, Wentz 1H, the numbers seem to indicate that the sample was taken when the driller said that they were just barely within the shale layer – by 219 feet. Since the drill cuttings take some time to return to the surface from over 7,000 feet down, drilling just a few hundred feet would not at all guarantee that the returned cuttings were totally from the black shale. The processing of the drill cuttings at the shaker table and separator and centrifuge and the mixing in the tubs all cast some doubt on whether the sample, wherever it was taken from, was truly from the horizontal bore material.

On page 11 there is a clear and unambiguous statement:

Three representative sets of drill cuttings from the horizontal drilling activities within the Marcellus Shale formation were collected.

A successful attempt to get three such samples might have then allowed an appropriate waste characterization to be done as needed to accomplish the five required research topics listed in the report’s cover letter. Only an accurate chemical and radiological waste characterization would have allowed scientifically justifiable conclusions to be formulated and then allow for accurate legislation and regulations. It does not seem that West Virginia yet has the required scientific data upon which to confidently formulate laws and regulations to protect public health with regard to shale waste disposal.

Would it not seem prudent – if one wanted a good, representative sample – to make absolutely sure that the operator was, in fact, drilling in the black shale and that the cuttings returning to the surface were, in fact, from the Marcellus bore? That approach would have been eminently defensible and easily accomplished by just waiting for drilling to progress into the lateral bore far enough that the drill cuttings returning to the surface were in fact from the black shale. There might be plausible explanations for this apparent inconsistency or error. Of course, it might be speculated that the Antero-provided information on the well plats is incorrect and not intended to be accurate, or perhaps the driller is not really sure yet where the Marcellus layer starts. There may be many other possible scenarios of explanations. Time will tell.

IV. Research Observations Review

Landfill disposal of drill cuttings

Landfill disposal of drill cuttings

GOOD There are a number of recommendations and suggestions in the study on landfills and leachate related conditions. It seems that a number of these proposals are very accurate and should be implemented. For example:

The report clearly restates that drill cuttings are known to contain radioactive compounds. Since all landfill liners will eventually leak, and since landfills already have ground water test wells for monitoring for potential ground water contamination due to leaking liners, then the well samples should be tested for radiological isotopes. Good idea. They are not required to do that now, but this recommendation should be implemented immediately (pgs. 17 and 21).

GOOD The report recommends that the Publicly Owned Treatment Works (POTW) or in the case of Wetzel County, the on-site wastewater treatment plants, should also test their effluent for radioactive isotopes. This is very important since there is no way to efficiently filter out many of the radioactive isotopes. Such contaminants will pass through traditional wastewater treatment plants.

It is also very useful that the report recommends that all the National Pollution Discharge Elimination System (NPDES) limits at the POTWs be reviewed and required to take into consideration the significantly more challenging chemical and radiological makeup of the shale waste products.

V. Economic Considerations on an Industry Supported Mono-Fill

The legislature asked that the DEP evaluate the feasibility of the natural gas industry to build, own, or operate its own landfill solely for the disposal of the known radioactive waste. This request seems to be a very reasonable approach, since for decades we have only put known radioactive waste products into dedicated landfills that are exclusively and specifically designed for the long term storage of the special waste material.

The discussion of the economic considerations is extremely complete and detailed. They are given in Appendix I and take into consideration a very thorough economic feasibility study of such a proposed endeavor. This section seems to have been compiled by a very talented professional team.

FLAW  However, some of the basic assumptions are a bit askew. For example:

The initial Abstract of the financial analysis states that two new landfills would be needed because we do not want to have the well operators to drive any further than they do now. Interesting. This seems to be not too different than a homeowner while in search for privacy and quiet, builds a home far out into the country and then expects the public sewage lines to be extended miles to his new home so he would not have to incur the cost of a septic system. Homebuilders in rural settings should know they will have to incur expenses for their waste disposal needs. Should gas companies expect that communities to provide cheap waste disposal for them?

More than 15 pages later, the most important aspect is clearly stated that, “…the most salient benefit of establishing a separate landfill sited specifically to receive (radioactive) drill cuttings would be the preservation of existing disposal capacity of existing fills for future waste disposal”. Meaning for my (our) grandchildren. See page 175.

Comprehensive and sound financial details later explain that having the natural gas operators build, operate, and eventually close their own radioactive waste depository landfill would involve a lot of their capital and involve some risk to them. It is stated that their money would be better used drilling more wells. The conclusion then seems to be that, all around, it is simply cheaper and less risky for the gas industry to put all their waste products into our Municipal Waste Landfills, and later residents should incur the costs and risk to build another land fill for their household garbage when needed.

VI. Report Omissions

  1. Within the report section dealing with the leachate test results, it is casually mentioned that not only do the landfills receiving shale waste materials have radioactive contaminated leachate, but the other tested landfills do, as well. However, rather than raising a very red flag and expressing concern over a problem that no one has looked into, the report implies we should not worry about any radioactive waste because it might be in all landfills (pg. 139).
  2. Nowhere within the radiological discussion is there any mention of what might be called speciation of radioactive isotopes. The report does state that the test for both gross alpha and gross beta, are considered a “scanning procedure.” The speciation process is sort of a slice and dice procedure, showing exactly what isotopes are responsible for the activity that is being indicated. This process, however, does not seem to have been done on the landfill leachate test samples. The general scanning process cannot do that. Appendix H, pages 141-142, contains detailed facts on radiation dose, risk, and exposure. This might have been a good place to also discuss the proper EPA testing protocols, used or not used, and why.
  3. A short discussion of the DEP-required landfill entrance radiation monitors is included on page 146. The installed monitors are the goalpost type. Trucks drive between them at the entrance and when they cross the scales. It seems that the report should have emphasized that that type of monitor will primarily only detect high-energy gamma radiation. However what is omitted on page 144 is that the primary form of decay for radium-226 is releasing alpha particles. The report is ambiguous in saying the decay products of radium-226 include both alpha particles and some gamma radiation, but radium-266 is not a strong gamma emitter. It is very unlikely that a normal steel enclosed roll-off box would ever trip the alarm setting with a load of drill cuttings. However those monitors are still useful since they will detect the high-energy gamma radiation from a truck carrying a lot of medical waste (pg. 17).
  4. It is stated on page 144 that the greatest health risk due to the presence of radium-226 is the fact that its daughter product is radon-222. Radium-226 has a half-life of 1,600 years, compared to radon’s 3.8 days. This difference might seem to imply that radon is less of a concern. Given the multitude of radium-226 going into our landfills means that we will be producing radon for a very long time.

VII. Resource Referenced in Article

Examination of Leachate, Drill Cuttings and Related Environmental, Economic and Technical Aspects Associated with Solid Waste Facilities in West Virginia, by Marshall University.

Proposed Atlantic Coast Pipeline route

An urgent need? Atlantic Coast Pipeline Discussion and Map

By Karen Edelstein, Eastern Program Coordinator

This article was originally posted on 10 July 2015, and then updated on 22 January 2016 and 16 February 2016.

Proposed Pipeline to Funnel Marcellus Gas South

In early fall 2014, Dominion Energy proposed a $5 billion pipeline project, designed provide “clean-burning gas supplies to growing markets in Virginia and North Carolina.” Originally named the “Southeast Reliability Project,” the proposed pipeline would have a 42-inch diameter in West Virginia and Virginia. It would narrow to 36 inches in North Carolina, and narrow again to 20 inches in the portion that would extend to the coast at Hampton Roads. Moving 1.5 billion cubic feet per day of gas, with a maximum allowable operating pressure of 1440 psig (pounds per square inch gage), the pipeline would be designed for larger customers (such as manufacturers and power generators) or local gas distributors supplying homes and businesses to tap into the pipeline along the route, making the pipeline a prime mover for development along its path.

The project was renamed the Atlantic Coast Pipeline (ACP) when a coalition of four major US energy companies—Dominion (45% ownership), Duke Energy (40%), Piedmont Natural Gas (15%), and AGL Resources (5%)— proposed a joint venture in building and co-owning the pipeline. Since then, over 100 energy companies, economic developers, labor unions, manufacturers, and civic groups have joined the new Energy Sure Coalition, supporting the ACP. The coalition asserts that the pipeline is essential because the demand for fuel for power generation is predicted more than triple over the next 20 years. Their website touts the pipeline as a “Path to Cleaner Energy,” and suggests that the project will generate significant tax revenue for Virginia, North Carolina, and West Virginia.

Map of Proposed Atlantic Coast Pipeline


View map fullscreen – including legend and measurement tools.

Development Background

Lew Ebert, president of the North Carolina Chamber of Commerce, optimistically commented:

Having the ability to bring low-cost, affordable, predictable energy to a part of the state that’s desperately in need of it is a big deal. The opportunity to bring a new kind of energy to a part of the state that has really struggled over decades is a real economic plus.

Unlike older pipelines, which were designed to move oil and gas from the Gulf Coast refineries northward to meet energy demands there, the Atlantic Coast Pipeline would tap the Marcellus Shale Formation in Ohio, West Virginia and Pennsylvania and send it south to fuel power generation stations and residential customers. Dominion characterizes the need for natural gas in these parts of the country as “urgent,” and that there is no better supplier than these “four homegrown companies” that have been economic forces in the state for many years.

In addition to the 550 miles of proposed pipeline for this project, three compressor stations are also planned. One would be at the beginning of the pipeline in West Virginia, a second midway in County Virginia, and the third near the Virginia-North Carolina state line.  The compressor stations are located along the proposed pipeline, adjacent to the Transcontinental Pipeline, which stretches more than 1,800 miles from Pennsylvania and the New York City Area to locations along the Gulf of Mexico, as far south as Brownsville, TX.

In mid-May 2015, in order to avoid requesting Congressional approval to locate the pipeline over National Park Service lands, Dominion proposed rerouting two sections of the pipeline, combining the impact zones on both the Blue Ridge Parkway and the Appalachian Trail into a single location along the border of Nelson and Augusta Counties, VA. National Forest Service land does not require as strict of approvals as would construction on National Park Service lands. Dominion noted that over 80% of the pipeline route has already been surveyed.

Opposition to the Pipeline on Many Fronts

The path of the proposed pipeline crosses topography that is well known for its karst geology feature—underground caverns that are continuous with groundwater supplies. Environmentalists have been vocal in their concern that were part of the pipeline to rupture, groundwater contamination, along with impacts to wildlife could be extensive. In Nelson County, VA, alone, 70% of the property owners in the path of the proposed pipeline have refused Dominion access for survey, asserting that Dominion has been unresponsive to their concerns about environmental and cultural impacts of the project.

On the grassroots front, 38 conservation and environmental groups in Virginia and West Virginia have combined efforts to oppose the ACP. The group, called the Allegany-Blue Ridge Alliance (ABRA), cites among its primary concerns the ecologically-sensitive habitats the proposed pipeline would cross, including over 49.5 miles of the George Washington and Monongahela State Forests in Virginia and West Virginia. The “alternative” version of the pipeline route would traverse 62.7 miles of the same State Forests. Scenic routes, including the Blue Ridge Parkway and the Appalachian Scenic Trail would also be impacted. In addition, it would pose negative impacts on many rural communities but not offset these impacts with any longer-term economic benefits. ABRA is urging for a programmatic environmental impact statement (PEIS) to assess the full impact of the pipeline, and also evaluate “all reasonable, less damaging” alternatives. Importantly, ABRA is urging for a review that explores the cumulative impacts off all pipeline infrastructure projects in the area, especially in light of the increasing availability of clean energy alternatives.

Environmental and political opposition to the pipeline has been strong, especially in western Virginia. Friends of Nelson, based in Nelson County, VA, has taken issue with the impacts posed by the 150-foot-wide easement necessary for the pipeline, as well as the shortage of Department of Environmental Quality staff that would be necessary to oversee a project of this magnitude.

Do gas reserves justify this project?

Dominion, an informational flyer, put forward an interesting argument about why gas pipelines are a more environmentally desirable alternative to green energy:

If all of the natural gas that would flow through the Atlantic Coast Pipeline is used to generate electricity, the 1.5 billion cubic feet per day (bcf/d) would yield approximately 190,500 megawatt-hours per day (mwh/d) of electricity. The pipeline, once operational, would affect approximately 4,600 acres of land. To generate that much electricity with wind turbines, utilities would need approximately 46,500 wind turbines on approximately 476,000 acres of land. To generate that much electricity with solar farms, utilities would need approximately 1.7 million acres of land dedicated to solar power generation.

Nonetheless, researchers, as well as environmental groups, have questioned whether the logic is sound, given production in both the Marcellus and Utica Formations is dropping off in recent assessments.

Both Nature, in their article Natural Gas: The Fracking Fallacy, and Post Carbon Institute, in their paper Drilling Deeper, took a critical look at several of the current production scenarios for the Marcellus Shale offered by EIA and University of Texas Bureau of Economic Geology (UT/BEG). All estimates show a decline in production over current levels. The University of Texas report, authored by petroleum geologists, is considerably less optimistic than what has been suggested by the Energy Information Administration (EIA), and imply that the oil and gas bubble is likely to soon burst.

Natural Gas Production Projections for Marcellus Shale

Natural Gas Production Projections for Marcellus Shale

David Hughes, author of the Drilling Deeper report, summarized some of his findings on Marcellus productivity:

  • Field decline averages 32% per year without drilling, requiring about 1,000 wells per year in Pennsylvania and West Virginia to offset.
  • Core counties occupy a relatively small proportion of the total play area and are the current focus of drilling.
  • Average well productivity in most counties is increasing as operators apply better technology and focus drilling on sweet spots.
  • Production in the “most likely” drilling rate case is likely to peak by 2018 at 25% above the levels in mid-2014 and will cumulatively produce the quantity that the Energy Information Administration (EIA) projected through 2040. However, production levels will be higher in early years and lower in later years than the EIA projected, which is critical information for ongoing infrastructure development plans.
  • The EIA overestimates Marcellus production by between 6% and 18%, for its Natural Gas Weekly and Drilling Productivity reports, respectively.
  • Five out of more than 70 counties account for two-thirds of production. Eighty-five percent of production is from Pennsylvania, 15% from West Virginia and very small amounts from Ohio and New York. (The EIA has published maps of the depth, thickness and distribution of the Marcellus shale, which are helpful in understanding the variability of the play.)
  • The increase in well productivity over time reported in Drilling Deeper has now peaked in several of the top counties and is declining. This means that better technology is no longer increasing average well productivity in these counties, a result of either drilling in poorer locations and/or well interference resulting in one well cannibalizing another well’s recoverable gas. This declining well productivity is significant, yet expected, as top counties become saturated with wells and will degrade the economics which have allowed operators to sell into Appalachian gas hubs at a significant discount to Henry hub gas prices.
  • The backlog of wells awaiting completion (aka “fracklog”) was reduced from nearly a thousand wells in early 2012 to very few in mid-2013, but has increased to more than 500 in late 2014. This means there is a cushion of wells waiting on completion which can maintain or increase overall play production as they are connected, even if the rig count drops further.
  • Current drilling rates are sufficient to keep Marcellus production growing on track for its projected 2018 peak (“most likely” case in Drilling Deeper).

Post Carbon Institute estimates that Marcellus predictions overstate actual production by 45-142%. Regardless of the model we consider, production starts to drop off within a year or two after the proposed Atlantic Coast Pipeline would go into operation. This downward trend leads to some serious questions about whether moving ahead with the assumption of three-fold demand for gas along the Carolina coast should prompt some larger planning questions, and whether the availability of recoverable Marcellus gas over the next twenty years, as well as the environmental impacts of the Atlantic Coast Pipeline, justify its construction.

Next steps

The Federal Energy Regulatory Commission, FERC, will make a final approval on the pipeline route later in the summer of 2015, with a final decision on the pipeline construction itself expected by fall 2016.

UPDATE #1: On January 19, 2016, the Richmond Times-Dispatch reported that the United States Forest Service had rejected the pipeline, due to the impact its route would have on habitats of sensitive animal species living in the two National Forests it is proposed to traverse.

UPDATE #2: On February 12, 2016, Dominion Pipeline Company released a new map showing an alternative route to the one recently rejected by the United States Forest Service a month earlier. Stridently condemned by the Dominion Pipeline Monitoring Coalition as an “irresponsible undertaking”, the new route would not only cross terrain the Dominion had previously rejected as too hazardous for pipeline construction, it would–in avoiding a path through Cheat and Shenandoah Mountains–impact terrain known for its ecologically sensitive karst topography, and pose grave risks to water quality and soil erosion.

Where have all the guardrails gone?

Guardrails vs. Trucks

Wetzel County in northwestern West Virginia is remarkable for its steep, knobby hills and long narrow winding valleys – providing residents and visitor alike with beautiful views. Along with these scenic views, however, comes difficult roadways and dangerous traveling.

Two two-lane roads traverse the county from the west, along the Ohio River, to the east. There are very few connecting roads going north-south between these two main highways, and only one of them is semi-paved. This road is called Barker Run Road — treacherous, steep and winding. There is at least a 400-foot change in elevation in about ½ mile at one point, with multiple switchbacks.

Switchbacks have a reputation for swallowing up the long trailer component of the tractor-trailer combos, which now comprise a larger part of the traffic on Barker Run Road. Many of these trucks are heading to the HG Energy drilling sites on the ridges at the top. HG Energy has a significant footprint up there. On the east ridge there are four well pads in place and two additional pads being completed to the east, and two large ones on the ridge to the west of Barker Run Road. All that traffic must use Barker Run Road. Until the recent expansion of natural gas exploration in the area, however, I had never seen a tractor and trailer come up either side of the very steep road.

The first casualty caused by the large, long trailer trucks needed to service these well pads is always the full-time sentinels of our traffic safety – our faithful guard rails that are designed to take a beating before we and our vehicle descend over the hillside sideways or rolling over. A good example of a damaged but still useful guardrail is shown below from February on 2012 – wrinkled but useful. The very sharp turn in the roadway is also obvious here.

Figure 1. Switchback curve on Barker Run Road has seen its share of damage from the increase in truck traffic.

Figure 1. Switchback curve on Barker Run Road has seen its share of damage from the increase in truck traffic.

After leaving Route 7 heading south on Barker Run Road, one encounters a particularly sharp and steep switchback curve as shown in Figure 1. It is this kind of turn that is so sharp that it allows the driver of an overlong truck to be able to look back and check the lug nuts on the rear wheels.

On a few occasions, I have been able to actually witness the attempt of our full-time guards as they try to keep a truck somewhat close to the roadway. The below photo shows that the guardrail was barely able to keep the trailer from going completely over the hillside. The truck was stuck, causing the road to be closed for hours till help could arrive (Figure 2, below).

When that incident was over, the photo below from a few weeks later, on March 16, 2013, shows the final damaged rail (Figure 3). The guardrail and posts were replaced and were largely intact when the rail was pushed over again in May of 2013 by another oversized truck trying to get up the hill and around the turn (Figure 4). Ongoing impacts with the guardrail eventually rendered it useless. Figure 5 below is a photo taken in August of 2013.

Infrastructure Damage & Costs

When the Marcellus shale gas drilling began here in Wetzel County eight years ago, it quickly became apparent that the rapidly expanding Chesapeake Energy drilling footprint in north central Wetzel County was leaving scars in the neighborhood, particularly on the roadways. The most visible damages were the road signs, guardrails, and pavement. These effects resulted in a three-layer, road bonding program implemented by the West Virginia Department of Highways. The stipulation requires that any of the large natural gas drillers or operators must post a $1-million bond to cover them statewide, or a single highway district bond for $250,000. This bonding only applies to secondary roads. The third option is to post a bond for fixed, limited miles along specific roads. Some of the pipeline contractors who might be working in a smaller area will use the latter option. Since the DOH generally knows which companies are using the roads, the department usually knows who to approach to pay for damage. In a few cases the companies have reported the damage to the Highway department, and at other times the truckers’ insurance companies report an accident or insurance claim. .

During a recent conversation with a WV-DOH representative, I was told that he quite frequently gets good cooperation from the gas industry companies in paying for damages. He said this is true even when a number of different companies and dozens of their subcontractors are using the same road.

Usually the guardrails just need to be fixed or replaced and new posts installed. Sometimes it is not critical that it be done immediately. However, at times the repairs should be done now. A good example of when repairs are needed soon is shown below in Figure 7, right. This remnant is the shredded, mangled, twisted remains of the stubborn effort of the steel to stop a truck.

The rail has now been totally sliced open, making it an extraordinary danger to the traveling public. As we enter the winter season with a bit of snow and ice on this steep road above this section, any of my neighbors could slide into this. I am optimistic that it will be replaced soon and have had several conversations with the WV-DOH to speed up the process.

By Bill Hughes, WV Community Liaison, FracTracker Alliance
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