In this forest fragmentation analysis, FracTracker looked at existing vegetation height in the northern portion of Pennsylvania’s Susquehanna River Basin. The vegetation height data is available from LANDFIRE, a resource used by multiple federal agencies to assess wildfire potential by categorizing the vegetation growth in 30 by 30 meter pixels into different categories. In the portion of Pennsylvania’s Susquehanna Basin where we looked, there were 29 total categories based on vegetation height. For ease of analysis, we have consolidated those into eight categories, including roads, developed land, forest, herbs, shrubs, crops, mines and quarries, and open water.
Methods
We compared the ratio of the total number of each pixel type to the type that was found at vertical and horizontal wells in the region. In this experiment, we hypothesized that we would see evidence of deforestation in the areas where oil and gas development is present. Per our correspondence with LANDFIRE staff, the vegetation height data represents a timeframe of about 2014, so in this analysis, we focused on active wells that were drilled prior to that date. We found that the pixels on which the horizontal wells were located had a significantly different profile type than the overall pixel distribution, whereas conventional wells had a more modest departure from the general characteristics of the region.
Figure 1 – Vegetation profile of the northern portion of Pennsylvania’s Susquehanna River Basin. The area is highly impacted by O&G development, a trend that is likely to continue in the coming years.
In Figure 1, we see that the land cover profile where vertical wells (n=6,198) are present is largely similar to the overall distribution of pixels for the entire study area (n=40,897,818). While these wells are more than six times more likely to be on areas classified as mines, quarries, or barren, it is surprising that the impact is not even more pronounced. In terms of forested land, there is essentially no change from the background, with both at about 73%. However, the profile for horizontal wells (n=3,787) is only 51% forested, as well as being four times more likely than the background to be categorized as herbs, which are defined in this dataset as having a vegetation height of around one meter.
Why Aren’t the Impacts Even More Pronounced?
While the impacts are significant, particularly for horizontal wells, it is a bit surprising that evidence of deforestation isn’t even more striking. We know, for example, that unconventional wells are usually drilled in multi-well pads that frequently exceed five acres of cleared land, so why aren’t these always classified as mines, quarries, and barren land, for example? There are several factors that can help to explain this discrepancy.
First, it must be noted that at 900 square meters, each pixel represents almost a quarter of acre, so the extent of these pixels will not always match with the area of disturbance. And in many cases, the infrastructure for older vertical wells is completely covered by the forest canopy, so that neither well pad nor access road is visible from satellite imagery.
The map above shows horizontal and vertical wells in a portion of Centre County, Pennsylvania, an area within our study region. Note that many of the vertical wells, represented by purple dots, appear to be in areas that are heavily forested, whereas all of the horizontal wells (yellow dots) are on a defined well pad in the lower right part of the frame. Panning around to other portions of Centre County, we find that vertical wells are often in a visible clearing, but are frequently near the edge, so that the chances of the 30 by 30 meter pixel that they fall into is much more likely to be whatever it would have been if the well pad were not there.
We must also consider that this dataset has some limitations. First of all, it was built to be a tool for wildfire management, not as a means to measure deforestation. Secondly, there are often impacts that are captured by the tool that were not exactly on the well site. For this reason, it would make sense to evaluate the area around the well pad in future versions of the analysis.
Figure 2 – A close up of a group of wells in the study area. Note that the disturbed land (light grey) does not always correspond exactly with the well locations.
In Figure 2, we see a number of light grey areas –representing quarries, strip mines, and gravel pits –with an O&G well just off to the side. Such wells did not get classified as being on deforested land in this analysis.
And finally, after clarifying the LANDFIRE metadata with US Forest Service personnel involved in the project, we learned that while the map does represent vegetation cover circa 2014, it is actually build on satellite data collected in 2001, which has subsequently been updated with a detailed algorithm. However, the project is just beginning a reboot of the project, using imagery from 2015 and 2016. This should lead to much more accurate analyses in the future.
Why Forest Fragmentation Matters
The clearing of forests for well pads, pipelines, access roads, and other O&G infrastructure that has happened to date in the Susquehanna Basin is only a small fraction of the planned development. The industry operates at full capacity, there could be tens of thousands of new unconventional wells drilled on thousands of well pads in the region through 2030, according to estimates by the Nature Conservancy. They have also calculated an average of 1.65 miles of gathering lines from the well pad to existing midstream infrastructure. With a typical right-of-way being 100 feet wide, these gathering lines would require clearing 20 acres. It isn’t unusual for the total disturbance for a single well pad and the associated access road to exceed ten acres, making the total disturbance about 30 acres per well pad. Based on the vegetation distribution of the region, we can expect that 22 of these acres, on average, are currently forested land. Taking all of these factors into consideration, a total disturbance of 100,000 to 200,000 acres in Pennsylvania’s Susquehanna River Basin due to oil and gas extraction, processing, and transmission may well be a conservative estimate, depending on energy choices we make in the coming years.
This forest fragmentation has a number of deleterious effects on the environment. First, many invasive plant species, such as bush honeysuckle and Japanese knotweed, tend to thrive in recently disturbed open areas, where competing native plants have been removed. The practice also threatens numerous animal species that thrive far from the forest’s edge, including a variety of native song birds. The disturbed lands create significant runoff into nearby rivers and streams, which can have an impact on aquatic life. And the cumulative release of carbon into the atmosphere is staggering – consider that the average acre of forest in the United States contains 158,000 pounds of organic carbon per acre. As the area is 73% forested, the total cumulative impact could result in taking 5.8 to 11.6 million tons of organic carbon out of forested storage. Much of this carbon will find its way into the atmosphere, along with the hydrocarbons that are purposefully being extracted from drilling operations.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/06/Forest-Fragmentation-Feature.jpg400900Matt Kelso, BAhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngMatt Kelso, BA2017-06-06 10:09:452021-04-15 15:03:01Forest Fragmentation and O&G Development in PA’s Susquehanna Basin
How fragmented approvals and infrastructure favor petrochemical development
By Leann Leiter and Lisa Graves-Marcucci
Let’s think back to 2009, when oil and gas companies like Range Resources began drilling the northeast shale plays in earnest. Picture the various stages involved in drilling – such as leasing of land, clearing of trees, boring of wells, siting of compressor stations, and construction of pipelines to gather the gas. Envision the geographic scope of the gas infrastructure, with thousands of wells in Pennsylvania alone, and thousands of miles of pipelines stretching as far as Louisiana.
Figure 1. A pipeline right-of-way snakes behind a residential property in Washington County, PA. Photo credit: Leann Leiter
Now, picture the present, where a homeowner looks out over her yard and wonders how a lease she signed with Shell several years prior made it possible for the company to run an ethane pipeline across her property and between her house and her garage.
Think forward in time, to 2022, the year when a world-scale ethane cracker is set to go online in Beaver County, Pennsylvania, to begin churning through natural gas liquids from wells in PA and others, producing a variety of disposable plastic products.
At each of these moments in gas development, which of the many stakeholders – industry leaders, local governments, state regulatory agencies, or landowners and residents – were granted a view of the full picture?
The proposed Shell ethane cracker in Beaver County is an illustration of the fragmented nature of gas development. From the extensive web of drilling infrastructure required to supply this massive facility, to several years of construction, this project is a case-study in piecemeal permitting. Such fragmentation creates a serious barrier to transparency and to the informed decision-making that relies upon it.
In the first two articles in this series on the petrochemical development in Beaver County, we focused on ethane cracker emergency scenarios and how the area might prepare. In this article, we draw the lens back to take in the larger picture of this region-altering project and highlight the effects of limited transparency.
The “Piecemeal” Nature of Gas Development
All across the Pennsylvania, proposed industrial development – even coal operations – have historically provided to the public, elected officials, and regulatory agencies the extent or footprint of their planned operations. Nonetheless, the oil and gas industry has in several instances undertaken a practice of developing its extensive infrastructure piece-by-piece. Operators of these facilities first acquire a GP-5 General Permit, which is only available to certain oil and gas operations with “minor” emissions and which allows them to avoid having the permit undergo public notice or comment. These operators then add emissions sources and increases through a series of minor amendments. While they are required to obtain a “major” source permit once their modifications result in major emissions, they avoid the scrutiny required for a major source by this fragmented process.
Unlike most other industrial permitting, the gas industry has enjoyed a much less transparent process. Instead of presenting their entire planned operation at the time of initial permit application, gas operators having been seeking – and receiving – incremental permits in a piecemeal fashion. This process puts local decision makers and the women, men, and children who live, work, and go to school near gas development at a severe disadvantage in the following ways:
Without full disclosure of the entirety of the planned project, neither regulatory bodies nor the public can conduct a full and factual assessment of land use impacts;
Incremental approvals allow for ever-expanding operations, including issuance of permits without additional public notification and participation;
Piecemeal approvals allow operations to continuously alter a community and its landscape;
The fragmented approval process prevents consideration of cumulative impacts; and
Without full transparency of key components of the proposed operations, emergency planning is hampered or non-existent.
From the Well to the Ethane Cracker
In the fragmented approval process of gas development, the proposed ethane cracker in Beaver County represents a pertinent example. Developers of this massive, multi-year, and many-stage project have only revealed the size and scope in a piecemeal fashion, quietly making inroads on the project (like securing land leases along the route of the pipeline required for the cracker, years in advance of permit approvals for the facility itself). By rolling out each piece over several years, the entirety of the petrochemical project only becomes clear in retrospect.
A World-Scale Petrochemical Hub
While Shell is still pursuing key approval from the PA Department of Environmental Protection, industry leaders treat the ethane cracker as a foregone conclusion, promising that this facility is but one step in turning the area into a “petrochemical hub.”
The cracker facility, alone, will push existing air pollution levels further beyond their already health-threatening state. Abundant vacant parcels around Shell’s cracker site are attractive sites for additional spin-off petrochemical facilities in the coming “new industry cluster.” These facilities would add their own risks to the equation, including yet-unknown chemical outputs emitted into the air and their resulting cumulative impacts. Likewise, disaster risks associated with the ethane cracker remain unclear, because in the piecemeal permitting process, the industry is not required to submit Preparedness, Prevention, and Contingency (PPC) Plans until after receiving approval to build.
Figure 2. A portion of the extensive US natural gas interstate pipeline system stretching from the petrochemical hubs in the bayous of the Gulf Coast Basin to Pittsburgh’s Appalachian Basin. However, petrochemical development in the northeast may reverse or otherwise change that flow. Visualization created by Sophie Riedel, Carnegie Mellon University, School of Architecture. Data on interstate natural gas supply sourced from Energy Information Administration, Form EIA176 “Annual Report of Natural Gas and Supplemental Gas Supply and Disposition,” 2007.
92.3 Miles of Explosive Pipeline
More than just a major local expansion, communities downriver and downwind will be susceptible to the impacts, including major land disturbance, emissions, and the potential for “incidents,” including explosion. The pipeline required to feed the cracker with highly flammable, explosive ethane would tie the tri-state region into the equation, expanding the zone of risk into Ohio and crossing through West Virginia.
Figure 3. The Falcon Pipeline, which would be used to transport ethane to the cracker in Beaver County. At 92.3 miles long, it consists of two “legs,” starting from Scio and Cadiz, Ohio and Houston, PA, respectively, and extending up to the site of Shell’s ethane cracker. Credit: Shell Pipeline Company LP
Renewed Demand at the Wellhead
No one piece of the gas infrastructure stands alone; all work in tandem. According to the Energy Information Administration (EIA), the new US ethane crackers will drive consumption of ethane up by a 26% by the end of 2018. Gas wells in the northeast already supply ethane; new ethane crackers in the region introduce a way to profit from this by-product of harvesting methane without piping it to the Gulf Coast. How this renewed demand for ethane will play out at fracked wells will be the result of complex variables, but it will undoubtedly continue to drive demand at Pennsylvania’s 10,000 existing unconventional oil and gas wells and those of other states, and may promote bringing new ones online.
Figure 4. Excerpt from Executive Summary of IHS Markit Report, “Prospects to Enhance Pennsylvania’s Opportunities in Petrochemical Manufacturing.”
Along with drilling comes a growing network of gathering and transmission lines, which add to the existing 88,000 miles of natural gas pipeline in Pennsylvania alone, fragment wildlife habitat, and put people at risk from leaks and explosions. Facilities along the supply stream that add their own pollution and risks include pump stations along the route and the three cryogenic facilities at the starting points of the Falcon Pipeline (see Fig. 6).
Figure 5. Several yards of the 88,000 miles of gas pipelines cutting through Pennsylvania. Finleyville, PA. Credit: Leann Leiter
The infrastructure investment required for ethane crackers in this region could reach $3.7 billion in processing facilities, pipelines for transmitting natural gas liquids including ethane, and storage facilities. A report commissioned by Team Pennsylvania and the PA Department of Community and Economic Development asserts that “the significant feedstock and transportation infrastructure required” will “exceed what is typically required for a similar facility” in the Gulf Coast petrochemical hub, indicating a scale of petrochemical development that rivals that of the southern states. This begs the question of how the health impacts in Pennsylvania will compare to those in the Gulf Coast’s “Cancer Alley.”
Figure 6. Houston, PA Cryogenic and Fractionation Plant, one of three such facilities supplying feedstock to the proposed Shell ethane cracker. Credit: Garth Lenz, iLCP
Water Impacts, from the Ohio River to the Arctic Ocean
Shell’s facility is only one of the ethane crackers proposed for the region that, once operational, would be permitted to discharge waste into the already-beleaguered Ohio River. This waterway, which traverses six separate states, supplies the drinking water for over 3 million people. Extending the potential water impact even further, the primary product of the Shell facility is plastics, whose inevitable disposal would unnecessarily add to the glut of plastic waste entering our oceans. Plastic is accumulating at the alarming rate of 3,500 pieces a day on one island in the South Pacific and as far away as the waters of the Arctic.
Figure 7. View of the Ohio River, downriver from the site of Shell’s proposed ethane cracker. Existing sources of industrial pollution to the river include the American Electric power plants, coal loading docks, barges, coal ash lagoons, and dry coal ash beds shown in this picture, and at least two fracking operations within the coal plant areas. Credit: Vivian Stockman/ohvec.org; flyover courtesy SouthWings.org.
How does fragmentation favor industry?
The gas and petrochemical industry would likely defend the logistical flexibility the piecemeal process affords them, allowing them to tackle projects, make investments, and involve new players as needed overtime. But in what other ways do the incredibly fragmented approval processes, and the limited requirements on transparency, favor companies like Shell and their region-changing petrochemical projects? And what effect does the absence of full transparency have on local communities like those in Beaver County? We conclude that it:
“Divides and conquers” the region. The piecemeal approach to gas development, and major projects like the Shell ethane cracker, deny any sense of solidarity between the people along the pipeline route resisting these potentially explosive channels cutting through their yards, and residents of Beaver County who fear the cracker’s emissions that will surround their homes.
Makes the project seem a foregone conclusion, putting pressure on others to approve. For example, before Shell formally announced its intention to build the facility in Potter Township, it rerouted a state-owned road to facilitate construction and increased traffic flow. Likewise, though a key permit is still outstanding with the PA DEP, first responders, including local volunteer firefighters, have already begun dedicating their uncompensated time to training with Shell. While this is a positive step from a preparedness standpoint, it is one of many displays of confidence by Shell that the cracker is a done deal.
Puts major decisions in the hands of those with limited resources to carry them out and who do not represent the region to be affected. In the case of the Shell ethane cracker, three township supervisors in Potter Township granted approvals for the project. The impacts, however, extend well beyond Potter or even Beaver county and include major air impacts for Allegheny County and the Pittsburgh area. Effects will also be felt by landowners and residents in numerous counties and two states along the pipeline route, those near cryogenic facilities in Ohio and Pennsylvania, plus those living on the Marcellus and Utica shale plays who will see gas well production continue and potentially increase.
Figures 8a and 8b. Potter Township Supervisors give the go-ahead to draft approval of Shell’s proposed ethane cracker at a January meeting, while confronted with public concern about deficiencies in Shell’s permit applications. Photos courtesy of the Air Quality Collaborative.
The piecemeal, incremental, and fragmented approval processes for the ethane cracker – and other gas-related facilities in the making – create one major problem. They make it nearly impossible for locals, elected officials, and regulatory agencies to see the whole picture as they make decisions. The bit-by-bit approach to gas development amounts to far-reaching development with irreversible impacts to environmental and human health.
We ask readers, as they contemplate the impacts closest to them – be it a fracked well, a hazardous cryogenic facility, the heavily polluted Ohio River, a swath of land taken up for the pipeline’s right-of-way, or Shell’s ethane cracker itself – to insist that they, their elected officials, and regulators have access to the whole picture before approvals are granted. It’s hard to do with a project so enormous and far-reaching, but essential because the picture includes so many of us.
Sincere Appreciation
To The International League of Conservation Photographers, The Ohio Environmental Council, and The Air Quality Collaborative for sharing photographs.
To Sophie Riedel for sharing her visualizations of natural gas interstate pipelines.
To Lisa Hallowell at the Environmental Integrity Project, and Samantha Rubright and Kirk Jalbert at FracTracker, for their review of and and invaluable contributions to this series.
Feature image: Map of US counties and natural gas interstate pipeline system describes the wide-diameter (20-42 inch), high capacity trunklines that carry most of the natural gas that is transported throughout the nation. Visualization created by Sophie Riedel, Carnegie Mellon University, School of Architecture. Data on interstate natural gas supply sourced from Energy Information Administration, Form EIA176 “Annual Report of Natural Gas and Supplemental Gas Supply and Disposition,” 2007.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/05/Pipelines-US-Graphic-Riedel-Feature.jpg400900FracTracker Alliancehttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngFracTracker Alliance2017-05-31 09:12:492021-04-15 15:03:01Piecing Together an Ethane Cracker
Eighty years ago, Southeastern Ohio was a wasteland of barren, eroding hills. During the 18th and 19th centuries this once heavily forested area in the Appalachian foothills had been clear cut and mined beyond recognition. When the Great Depression struck, lowering crop prices made farming unprofitable in the area, and 40% of the population moved away.
In 1933, President Franklin Delano Roosevelt established the Civilian Conservation Corps (CCC), a public work relief program that employed men aged 18-25 to do manual labor related to conservation and development of natural resources such as planting trees, constructing trails, roads, and lodges, fighting wildfires, and controlling erosion. The following year, Ohio’s legislature agreed to allow the federal government to purchase land in the state for the purpose of establishing a national forest. The Forest Service was tasked with restoring the land for what is now called Wayne National Forest (WNF). A tree nursery was established near Chillicothe, and with the help of the CCC and volunteers, including members of the Daughters of the American Revolution, garden clubs, and school children, reforestation began.
Photos Credit: US Forest Service
An Area on the Mend
Today, WNF comprises three units that span 12 Ohio counties in the Unglaciated Allegheny Plateau. The hills are covered in biologically diverse mixed mesophytic forest, which includes approximately 120 species of trees and provides habitat for at least 45 species of mammals, 158 species of birds, 28 species of reptiles, 29 species of amphibians, and 87 species of fish. The US Forest Service estimates that 240,000 people visit this ecological wonder annually, according to Forest Recreation Program Manager, Chad Wilberger, in Nelsonville, Ohio. The restoration of barren public land to its current state is a great achievement. If it continues to be protected, Wayne could one day resemble the old growth forest that thrived here before the arrival of European settlers.
The Bureau of Land Management (BLM), however, has recently decided to lease up to 40,000 acres of Wayne to gas and oil companies for horizontal hydraulic fracturing, or fracking. The first auction took place last December resulting in the lease of 700 acres. A second auction this March leased another 1,200 acres. Nearly all of this land lies within the 60,000 acre Marietta Unit of the forest. This brings Oil & Gas Expressions of Interest (EOI) acreage to roughly 7.5% of all WNF owned parcels in this unit.
Wayne National Forest and Adjacent Existing Oil and Gas Infrastructure Below is a map of the Wayne National Forest, along with parcels owned by WNF (shown in gray) and those that might be subject to unconventional oil and gas development (gray parcels outlined with dashes). We also include existing unconventional oil and gas infrastructure near the park. Explore the map below, or click here to view the map fullscreen.
Gas and oil development is not new to the Wayne. Since the passage of The Federal Land Policy and Management Act of 1976, the US Forest Service’s land management plan for WNF has included conventional drilling, and derricks are a common sight on both public and private land in southeastern Ohio.
Fracking (unconventional drilling), however, has a far greater impact, requiring clear cutting of large areas of land for the construction of concrete well pads, and the use of millions of gallons of water that will become contaminated during the process and then transported by truck to injection wells. Accidents can be catastrophic for workers and nearby residents, and fracking and waste water disposal have been linked to earthquakes in Ohio.
In 2012, BLM updated its WNF Land and Resource Management Plan to allow fracking in the forest without conducting new impact studies.
What is at risk?
The Marietta Unit of the WNF is located in Monroe, Perry, and Washington counties in Southeastern Ohio along the Ohio River. Within its boundary are a wealth of trails used for hiking, backpacking, horseback riding, and mountain biking, campgrounds, and waterways ideal for kayaking and fishing. Both the highest and lowest points in the Wayne lie in this unit, as does the Irish Run Natural Bridge. The area is also known for its exceptional wildflowers, as shown in the photos below.
One popular recreation area, Lamping Homestead, lies directly within an oil and gas Expression Of Interest (EOI) parcel #3040602400 (See Map Above), one of the areas under consideration for lease. In the 1800s, it was the site of the Lamping family’s farm, but today all that remains of the settlers is a small cemetery with an iron gate atop a hill overlooking a small lake. Six campsites are situated around the western side of the lake, and two intersecting hiking loops rise into the wooded hills to the east. On the western side of the parking lot is a covered picnic area. A creek flows out of the lake and into Clear Fork, a tributary of the Little Muskingum River, across the road from the parking lot.
Both the lake and stream are popular boating and fishing areas. Lamping is an excellent spot for wildlife viewing. The lake, the creeks that flow in and out of it, and the surrounding wooded hills support an impressive variety of plant and animal species. During the day, visitors might spot ducks, geese, great blue herons, red-winged blackbirds, summer tanagers, red spotted newts, box turtles, northern water snakes, garter snakes, deer, rabbits, and muskrats. At night, they could be greeted by a cacophony of voices from frogs, owls, and coyotes.
Species of trees, plants, and fungus are also numerous. In winter, stands of white pine pop out against the bare branches of oak, hickory, maple, buckeye, and other deciduous trees. In spring, eye-catching splotches of blooming dogwood and redbud contrast against the many shades of green. But hikers who pull their gaze away from the brightly colored canopy and look down are rewarded with an abundance of wildflowers and the butterflies they attract, as well as many varieties of mushrooms and fungus, including such edible varieties as morels, wood ear, and dryad’s saddle.
Estimating Disturbances
It is unclear how much surface disturbance would occur on public land if this parcel were to be fracked, but even if the well pad and pipelines were constructed on private land adjacent to the forest, in order to drill under the forest, the public land and its inhabitants and visitors would certainly be impacted.
There is no question that noise and air pollution from traffic and construction would be disruptive both to wildlife and to human visitors. Explore various photos of the oil and gas industry in the gallery below:
The extraction process requires 2 million to 6 million gallons of fresh water each time a well is fracked. The rate at which hydraulic fracturing’s water demand is increasing on a per-well basis here in Ohio reached an exponential state around Q4-2013 and Q1-2014 and continues to rise at a rate of 3.1 million gallons per well per year (Figure 1).
Ohio Hydraulic Fracturing Total and Per Well Freshwater Demand between Q3-2010 and Q3-2016.
In Ohio, oil and gas companies are allowed to pull this water directly from streams and rivers at no cost. All this is possible, despite the fact that after its use it is so contaminated that it must be disposed of via injection wells and is permanently removed from the water cycle. The industry is already pulling water from streams in the Marietta Unit of the WNF for use in fracking on private land. Fracking public land simply means water withdrawals will occur on a much larger scale.
Ohio and West Virginia Shale Water Demand and Injection Waste Disposal This map shows Utica wells weighted by water demand and disposal (and/or production). It also depicts water, sand, and chemical usage as well as injection waste and oil production. Explore the map below, or click here to view map fullscreen.
Inevitable methane leaks, in addition to contributing to climate change, affect humans and wildlife in their immediate vicinity, causing headaches and nausea and even killing trees and plants.
In addition to the anticipated harm that fracking inflicts upon a natural area, there is also a risk of accidents with potentially devastating consequences. Residents of Monroe County have already seen a few in recent years from fracking on private land. In 2014, a well pad fire in the village of Clarington resulted in a chemical spill that contaminated nearby Opossum Creek, killing 70,000 fish. The same year a large gas leak 15 miles south in the village of Sardis resulted in the evacuation of all homes within half mile radius.
Recent studies have shown that extraction wells, in addition to injection wells, can cause earthquakes. Unsurprisingly, Monroe County has seen a spike in seismic activity with the increase in fracking activity in the area. The most recent incident was a 3.0 magnitude earthquake in the forest less than five miles from Lamping Homestead in April of this year.
Supporters of Wayne National Forest
Many people have repeatedly spoken out against BLM’s plan, submitting a petition with more than 100,000 signatures, and protesting outside Wayne National Forest Headquarters and Athens Ranger Station in Nelsonville. They have even organized voters to call and write letters to Regional Forester Kathleen Atkinson and legislators, including Senators Sherrod Brown and Rob Portman, and Governor John Kasich. BLM has not budged on its decision, unfortunately, insisting that leasing this land for fracking, and associated infrastructure buildout, will have “no significant impact.”
This May, the Center for Biological Diversity, Ohio Environmental Council, Ohio Sierra Club, and Heartwood, a regional organization focused on protecting forests, filed a lawsuit against BLM, aiming to void BLM leases and halt all fracking operations within the national forest.
Concerned citizens continue to organize raise awareness as they await the outcome of the suit.
Becca Pollard is Freelance Journalist and Co-founder of Keep Wayne Wild
Data Downloads
Click on the links below to download the data used to create this article’s maps:
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/05/Wayne-National-Forest-Feature.jpg400900Guest Authorhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngGuest Author2017-05-24 11:35:532021-04-15 15:03:02Wayne National Forest Could Be Deforested – Again
The largest accidental release of methane in U.S. history began October 23, 2015 with the blowout of an underground natural gas storage well in Aliso Canyon about 20 miles west of Los Angeles. By the time the well was plugged 112 days later, more than 5.0 billion cubic feet of methane and other pollutants had been released to the atmosphere. It was a disaster for the climate, the environment, California’s energy supply, and the more than 11,000 people that were forced to evacuate.
A new study from the Harvard T. H. Chan School of Public Health – Center for Health and the Global Environment shows that more than one in five of the almost 15,000 active underground gas storage (UGS) wells in the US could be vulnerable to serious leaks due to obsolete well designs – similar in design to the well that failed at the Aliso Canyon storage facility.
Published today in the journal Environmental Research Letters, the study presents a national baseline assessment of underground storage wells in the U.S. and indicates the need for a better understanding of the risks associated with the obsolescence of aging storage wells. The study also highlights the widespread nature of certain age-related risk factors, but indicates that some of the highest priority wells may be located in PA, OH, NY, and WV.
The study shows that the average construction year of largely unregulated active UGS wells in the US is 1963, with potentially obsolete wells that were not originally designed for storage operating in 160 facilities across 19 states. Some of the wells were constructed over 100 years ago – a time period that precedes many modern well containment systems such cement isolation and the use of multiple casings. Some of the oldest active UGS wells were not designed for two-way flow of gas, and therefore may not exhibit sufficient material-grade or redundant precautionary systems to prevent containment loss, as was evident at Aliso Canyon.
An Interview with the Author
Sam, Matt, and Kyle of FracTracker caught up with lead author and former FracTracker colleague, Dr. Drew Michanowicz, now with the Center for Health and Global Environment within the Harvard T. H. Chan School of Public Health to find out more about their study.
When we spoke with Drew, he began the interview by posing the first question to us:
Did you know that about 15% of the natural gas produced in the US is injected back into the ground each year?
While we had all heard of underground gas storage before, we had to admit that we never thought of the process like that before. In other words, some of the natural gas in the US is being produced twice from two different reservoirs before being consumed. And because many of these storage systems utilized depleted oil and gas reservoirs, many of the same pre- and post-conditioning processes, such as dehydrating and compressing, are necessary to bring the gas to market.
The following questions and answers from Drew expand upon the study’s findings:
Q: What prompted you and your colleagues to investigate this topic?
A: After the Aliso Canyon incident, we became interested in the question: ‘Is Aliso Canyon Unique?’ Interestingly, there were plenty of early warning signs at that facility that corrosion issues on very old repurposed wells were becoming a significant issue. Almost a year before the well blowout, Southern California gas went on record in front of California’s Public Utility Commission stating that they needed a rate increase to implement a necessary integrity management plan for their wells, and to be able to move beyond operating in a reactive mode. That unfortunately prophetic document really got us interested in better understanding why their infrastructure was in the state it was in. And like any major accident like this, a logical next step is to assess the prevalence of hazardous conditions elsewhere in the system, in the hope to prevent the next one.
From our research, it appears that a very large portion of the UGS sector may be facing similar obsolescence issues compared to Aliso, such as decades-old wells not originally designed for two-way flow. Our work here, however, is a simplified assessment that focused only on passive barriers or the fixed structures such as the steel pipes likely present in a well. Much more work is needed to fully understand the active-type safety measures in place such as safety valves, tubing/packers, and overall integrity management plans – all important factors for manage risks.
Q: We see that your team developed a well-level database of over 14,000 active UGS wells across 29 states. Because data-collation is a big part of our work here, can you describe that data collection process?
A: Very early on we also realized that underground gas storage was exempt from the Safe Drinking Water Act’s Underground Injection Control (UIC) program – similar to exemption with hydraulic fracturing and the Energy Policy Act of 2015, AKA the Halliburton Loophole. This meant in part that very little aggregate well data was available from the Federal Government or by third-party aggregators like FracTracker and DrillingInfo. Reminiscent of my former extreme data-paucity days at FracTracker, we knew we needed to build a database basically from scratch to effectively perform a hazard assessment that incorporated a spatial component.
We began by gathering what data we could from the U.S. Energy Information Administration (EIA), which gave us good detail at the field or facility level, but the fields were generalized to a county centroid. So to fully evaluate these infrastructure, we needed to figure out how to join the facility-level data to the well data for each state. We relied on NETL’s Energy Data eXchange to identify state-level wellbore data providers where applicable. Once we collected all of the state data, we created a decision-tree framework to join the individual wells to the EIA field names in order to produce a functional geodatabase. Because we had to manage data from so many sources, we had to devote quite a bit of effort to data QA/QC, and that is reflected in the methods and results of the paper. For example, some of our fields and wells had to be joined via visual inspection of company system maps, because of missing identifier information.
Q: We see that some of the oldest repurposed wells you mapped are located in PA, OH, NY, and WV. Was that a surprise to you?
A: That was a surprise considering this story started for us in California, and even more surprising was that some are more than 100 years old. Now, a bit of caution here is warranted when thinking about the age of any engineered system. On the one hand, something that functions for a very long time is an indication that the system was very well suited for its task, and likely has been very well taken care of – think of an antique automobile like a fully functional 1916 Model T Ford, for example. On the other hand, age and construction year relates to the integrity of an engineered system through two processes by:
providing information to how long a system has been exposed to natural degradation processes such as corrosion, and stresses from thermal and abrasive cycles; and by
proxying for knowledge and regulatory safety standards at the time of construction which informs the design, materials, technologies likely used.
To go back to the car example, while an old classic car may still be operational, it may not have certain safety features like antilock brakes, airbags, or safety belts, and generally will not be able to go as fast as a modern car. Therefore, a gas storage well’s integrity is at least indirectly related to its construction year when considering the multitude of technological and safety improvements have occurred over the years. This is how we have been thinking about well integrity from a 5,000 foot perspective. Needless to say, more research is needed to understand the causal effect of age on well integrity.
Q: So if we understand you correctly, these older wells can be maintained with sufficient management practices, but there may be inherent safety features missing on these older wells that don’t adhere to todays’ standards?
A: That’s right. So what we can say about some of these aging wells is that some will not reflect certain modern fail-safe engineering such as sufficient casing design strength and multiple casings or barriers along the full length. And these are permanent structural elements vestigial to the well’s original design, and therefore cannot be undone or redesigned away. In other words, it makes much more sense to drill a new well with new materials than attempt to significantly alter an old well. And the gas storage wells built today are designed with redundant fail-safe systems including multiple barriers and real-time pressure sensors.
But back to my earlier point about lack of federal regulations to set a minimum safety standard – because of that, there is also much uncertainty surrounding how many of these facilities have been dealing with safety and risk management. That is a future direction of this work – to really try to fill in some of regulatory gaps between states and the impending Federal guidelines and identify some best practices to help inform policy makers specifically at the state level.
Drew put together a map to highlight where some of these active storage wells are in PA, OH, NY, and WV:
This area map of PA, WV, OH, and NY displays where active underground natural gas storage operations are located. The small white points represent active storage wells that have a completion, SPUD, or permit date that occurs after the field was designated for storage indicating that these wells are more likely to have been designed for storage operations. The green points are active storage wells that predate storage operations, indicating that these wells may not have been designed for storage.
There are 121 storage fields connected to at least 6,624 active gas storage wells across these four states. A portion of wells in this region were not included in this final count because they did not contain sufficient status or date information. Pennsylvania has the most individual storage fields of any state with 47, while Ohio boasts the most active storage wells of any state in the country with 3,318 across its 22 active fields. Of the 6,624 active UGS wells across these four states, 1,753 predate storage designation indicating that these wells were likely not originally designed for storage. These ‘repurposed’ wells have a median age of 84 years, with 210 wells constructed over 100 years ago (red points). The 100 year cutoff is not arbitrary, as the year 1917 marks the advent of cement zonal isolation techniques, indicating that these wells may be of the highest priority in terms of design deficiencies related to well integrity, and they are primarily located across the four states pictured above.
Top Counties with Obsolete1/Repurposed2 Wells
Westmoreland, PA (86/93)
Ashland, OH (50/217)
Richland, OH (31/99)
Greene, PA (25/76)
Hocking, OH (18/99)
1Obsolete wells are repurposed wells constructed before 1916 2Repurposed wells predate the storage facility
The well that failed at Aliso Canyon was originally drilled in 1954 for oil production. In 1972, it was repurposed for underground gas storage, which entails both production and injection cycles in a single well. The problem seems to be that because it was not originally constructed to store natural gas, only a single steel pipe separated the flow of gas and the outside rock formation. That meant the well’s passive structural integrity was vulnerable to a single point-of-failure along a portion of its casing. When part of the subsurface well casing failed, there were no redundancies or safety valves in place to prevent or minimize the blow out.
More information related to the Aliso Canyon incident and this study is available here.
More info on the Center for Health and the Global Environment can be found here.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/05/UGS-Map-Feature.jpg400900FracTracker Alliancehttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngFracTracker Alliance2017-05-23 13:12:102021-04-15 15:03:04Underground Gas Storage Wells – An Invisible Risk in the Natural Gas Supply Chain
Air quality in the California Bay Area has been steadily improving over the last decade, and the trend can even be seen over just the course of the last few years. In this article we explore data from the ambient air quality monitoring networks in the Bay Area, including a look at refinery emissions.
From the data and air quality reports we find that that many criteria pollutants such as fine particulate matter (PM2.5) and oxides of nitrogen (NOX) have decreased dramatically, and areas that were degraded are now in compliance.
While air pollution from certain sectors such as transportation have been decreasing, the north coast of the East Bay region is home to a variety of petrochemical industry sites. This includes five petroleum refineries. The refineries not only contribute to these criteria pollutants, but also emit a unique cocktail of toxic and carcinogenic compounds that are not monitored and continue to impact cardiovascular health in the region. This region, aptly named the “refinery corridor” has a petroleum refining capacity of roughly 800,000 BPD (barrels per day) of crude oil.
Petroleum refineries in California’s East Bay have always been a contentious issue, and several of the refineries date back to almost the turn of the 20th century. The refineries have continuously increased their capacities and abilities to refine dirtier crude oil through “modernization projects.” As a result, air quality and health impacts became such a concern that in 2006 and again in 2012, Gayle McLaughlin, a Green Party candidate, was elected as Mayor of the City of Richmond. Richmond, CA became the largest city in the U.S. with a Green Party Mayor. While there have been many strides in the recent decade to clean up these major sources of air pollution, health impacts in the region including cardiovascular disease and asthma, as well as cancer rates, are still disproportionately high.
Regulations
To give additional background on this issue, let’s discuss some the regulations tasked with protecting people and the environment in California, as well as climate change targets.
However – a current proposal will actually allow the refineries to process more crude oil by setting a standard for emissions by volume of crude/petroleum refined, rather than an actual cap on emissions. The current regulatory approach focuses on “source-by-source” regulations of individual equipment, which ignores the overall picture of what’s spewing into nearby communities and the atmosphere. Even the state air resources board has supported a move to block the refineries from accepting more heavy crude from the Canadian tar sands.
New regulatory proposals incentivize refineries to continue expanding operations to refine more oil, resulting in a larger burden on the health of these already disproportionately impacted environmental justice communities. Chevron, in particular, is upgrading their Richmond refinery in a way as to allow it to process dirtier crude in larger volumes from the Monterey Shale and Canada’s Tar Sands. Since the production volumes of lighter crudes are shrinking, heavier dirtier crudes are becoming a larger part of the refinerys’ feedstocks. Heavier crudes require more energy to refine and result in larger amounts of hazardous emissions.
Upgrades are also being implemented to address greenhouse gas emissions. While the upgrades address the carbon emissions, regulatory standards without strict caps for other pollutants will allow emissions of criteria and toxic air pollutants such as VOC’s, nitrosamines, heavy metals, etc… to increase. In fact, newly proposed emissions standards for refineries will make it easier for the refineries to increase their crude oil volumes by regulating emissions on per-barrel standards. Current refining volumes can be seen below in Table 1, along with their maximum capacity.
Table 1. Bay Area refineries average oil processed and total capacity
Refinery
Location
Ave. oil processed Barrels Per Day (2012 est.)
Max. capacity (BPD)
Chevron U.S.A. Inc. Richmond Refinery
Richmond
245,271
>350,000
Tesoro Refining & Marketing, Golden Eagle Refinery
The Bay Area, and in particular the city of Richmond, have been noted in the literature as a place where environmental racism and environmental health disparity exist. The city’s residents of color disproportionately live near the refineries and chemical plants, which is noted in early works on environmental racism by pioneers of the idea, such as Robert Bullard (Bullard 1993a,b).
Since the issue has been brought to national attention by environmental justice groups like West County Toxics Coalition, progress has been made to try to bring justice, but it has been limited. People of color are still disproportionately exposed to toxic, industrial pollution in that area. A recent study showed 93% of respondents in Richmond were concerned about the link between pollution and health, and 81% were concerned about a specific polluter, mainly the Chevron Refinery (Brody et al. 2012). Recent health reports continue to show the trend that these refinery communities suffer disproportionately from cases of asthma and cardiovascular disease and higher mortality rates from a variety of cancers.
Health Impact Studies
Manufacturing and refining are known to produce particularly toxic pollution. Additionally, there has been research done on the specific makeup of pollution in the refinery corridor. The best study to do this is the Northern California Household Exposure Study (Brody et al. 2009). They examined indoor and outdoor air in Richmond, a refinery corridor community, and Bolinas, a nearby but far more rural community. They found 33% more compounds in Richmond, along with higher concentrations of each compound. The study also found very high concentrations of vanadium and nickel in Richmond, some of the highest levels in the state. Vanadium and nickel have been shown to be some of the most dangerous PM2.5 components as we previously stated, which gives reason to believe the air pollution in Richmond is more toxic than in surrounding areas.
Another very similar study compared the levels of endocrine disrupting compounds in Richmond and Bolinas homes, and found 40 in Richmond homes and only 10 in Bolinas (Rudel et al. 2010). This supports the idea that a large variety of pollutants with synergistic effects may be contributing to the increased mortality and hospital visits for communities in this region. This small body of research on pollution in Richmond suggests that the composition of air pollution may be more toxic and thus trigger more pollution-related adverse health outcomes than in surrounding communities.
Air Quality Monitoring
As discussed above and in FracTracker’s previous reports on the refinery corridor, the refinery emissions are a unique cocktail whose synergistic effects may be driving much of the cardiovascular disease, asthma, and cancer risk in the region. Therefore, the risk drivers in the Bay Area need to be prioritized, in particular the compounds of interest emitted by the petrochemical facilities.
The targets for emissions monitoring are compounds associated with the highest risk in the neighboring communities. An expert panel was convened in 2013 to develop plans for a monitoring network in the refinery corridor. Experts found that measurements should be collected at 5 minute intervals and displayed to the public real-time. The gradient of ambient air concentrations is determined by the distance from refinery, so a network of three near-fence-line monitors was recommended. Major drivers of risk are supposed to be identified by air quality monitoring conducted as a part of Air District Regulation 12m Rule 15: Petroleum Refining Emissions tracking. According to the rule, fence-line monitoring plans by refinery operators:
… must measure benzene, toluene, ethyl benzene, and xylenes (BTEX) and HS concentrations at refinery fence-lines with open path technology capable of measuring in the parts per billion range regardless of path length. Open path measurement of SO2, alkanes or other organic compound indicators, 1, 3-butadiene, and ammonia concentrations are to be considered in the Air Monitoring Plan.
The following analysis found that the majority of hazardous pollutants emitted from refineries are not monitored downwind of the facility fence-lines, much less the list explicitly named in the regulations above.
As shown below in Figure 1, the most impacted communities are in those directly downwind of the facility. According to the BAAQMD, each petroleum refinery is supposed to have fence-line monitoring. Despite this regulation developed by air quality and health experts, only two out of the five refineries have even one fence-line monitor. Real-time air monitoring data at the Chevron Richmond fence-line monitor and the Phillips 66 Rodeo fence-line monitor can be found on fenceline.org. Data from these monitors are also aggregated by the U.S. EPA, and along with the other local monitors, can be viewed on the EPA’s interactive mapping platform.
Figure 1. Map of Hydrogen Sulfide Emissions from the Richmond Chevron Refinery
Hazardous Emissions and Ambient Pollution
Since the majority of hazardous chemicals emitted from the refineries are not measured at monitoring sites, or there are not any monitoring sites at the fence-line or downwind of the facility, our mapping exercises instead focus on the hazardous air pollution for which there is data.
As shown in the map of hydrogen sulfide (H2S) above, the communities immediately neighboring the refineries are subjected to the majority of hazardous emissions. The map shows the rapidly decreasing concentration gradient as you get away from the facility. H2S would have been a good signature of refinery emissions throughout the region if there were more than three monitors. Also, those monitors only existed until 2013, when they were replaced with a singular monitor in a much better location, as shown on the map. The 2016 max value is much higher because it is more directly downwind of Chevron Refinery.
The interpolated map layer was created using 2013 monitoring data from three monitors that have since been removed. The 2016 monitoring location is in a different location and has a maximum value more than twice what was recorded at the 2013 location.
Table 2. Inventory of criteria pollutant emissions for the largest sectors in the Bay Area
Annual average tons per day
PM10
PM2.5
ROG
NOX
SOX
CO
Area wide
175.51
52.90
87.95
19.92
0.62
161.86
Mobile
20.33
16.27
183.12
380.52
14.93
1541.50
Total Emissions
16.30
12.14
106.58
50.59
45.95
44.31
Table adapted from the BAAQMD Refinery Report. PM10 = particulate matter less than 10 microns in diameter (about the width of a human hair); PM2.5 = PM less than 2.5 microns in diameter; ROG = reactive organic gases; NOX = nitrogen oxides; SOX = sulfur oxides; CO = carbon monoxide.
Additionally, exposure assessment can also rely on using surrogate emissions to understand where the plumes from the refineries are interacting with the surrounding communities. It is particularly important to also discriminate between different sources of pollution. As we see in Table 2 above, the largest volume of particulate matter (PM), NOX, and CO emissions actually come from mobile sources, whereas the largest source of sulfur dioxide and other oxides (SOX) is from stationary sources. Since the relationship between PM2.5 and health outcomes is most established, the response to ambient levels of PM2.5 in the refinery corridor gives insight into the composition of PM as well as the presence of other species of hazardous air pollution. On the other hand, SO2 can be used as a surrogate for the footprint of un-monitored air toxics.
Pollutants’ Fingerprints
Particulate Matter
Figure 2. Map of fine particulate matter (PM2.5) for the Bay Area Air Quality Management District
Figure 2 above displays ambient levels of PM2.5, and as the map shows, the highest levels of particulate matter surround the larger metro area of downtown Oakland and also track with the larger commuting corridors. The map shows evidence that the largest contributor to PM2.5 is truly the transportation (mobile) sector. PM2.5 is one hazardous air pollutant which negatively impacts health, causing heart attack, or myocardial infarction (MI), among other conditions. PM2.5 is particulate matter pollution, meaning small particles suspended in the air, specifically particles under 2.5 microns in diameter. Exposure to high levels of PM2.5 increases the risk of MI within hours and for the next 1-2 days (Brooks et al. 2004; Poloniecki et al. 1997).While refineries may not be the largest source of PM in the Bay Area, they are still large point sources that contribute to high local conditions of smog.
The chemical make-up of the particulate matter also needs to be considered. In addition, the toxicity of PM from the refineries is of particular concern. Since particulate matter acts like small carbon sponges, the source of PM affects its toxicity. The cocktail of hazardous air toxics emitted by refineries absorb and adsorb to the surfaces of PM. When inhaled with PM, these toxics including heavy metals and carcinogens are delivered deep into lung tissue.
Pooled results of many studies showed that for every 10 micrograms per meter cubed increase in PM2.5 levels, the risk of MI increases 0.4-1% (Brooks et al. 2010). However, this relationship has not been studied in the context of EJ communities. EJ communities are generally low income communities of color (Bullard 1993), which have higher exposures to pollution, more sources of stress, and higher biological markers of stress (Szanton et al. 2010; Carlson and Chamberlein 2005). All of these factors may affect the relationship between PM2.5 and MI, and increase the health impact of pollution in EJ communities relative to what has been found in the literature.
Sulfur Dioxide
Figure 3 below shows the fingerprint of the refinery emissions on the refinery corridor, using SO2 emissions as a surrogate for the cocktail of toxic emissions. The relationship between SO2 and health endpoints of cardiovascular disease and asthma have also been established in the literature (Kaldor et al. 1984).
In addition to assessing SO2 as a direct health stressor, it is also the most effective tracer of industrial emissions and specifically petroleum refineries for a number of reasons. Petroleum refineries are the largest source of SO2 in the BAAQMD by far (Table 1), and there are more monitors for SO2 than any of the other emitted chemical species that can be used to fingerprint the refineries. The distribution of SO2 is therefore representative of the cocktail of a combination of the hazardous chemicals released in refinery emissions.
Figure 3. Map of Sulfur Dioxide for the Bay Area Air Quality Management District
The next step for FracTracker Alliance is to further explore the relationship between health effects in the refinery communities and ambient levels of air pollution emitted by the refineries. Our staff is currently working with the California Department of Public Health to analyze the response of daily emergency room discharges for a variety of health impacts including cardiovascular disease and asthma.
References
Brody, J. G., R. Morello-Frosch, A. Zota, P. Brown, C. Pérez, and R. A. Rudel. 2009. Linking Exposure Assessment Science With Policy Objectives for Environmental Justice and Breast Cancer Advocacy: The Northern California Household Exposure Study. American Journal of Public Health 99:S600–S609.
Brook, R. D., B. Franklin, W. Cascio, Y. Hong, G. Howard, M. Lipsett, R. Luepker, M. Mittleman, J. Samet, S. C. Smith, and I. Tager. 2004. Air Pollution and Cardiovascular Disease. Circulation 109:2655–2671.
Brooks, R. D., S. Rajagopalan, C. A. Pope, J. R. Brook, A. Bhatnagar, A. V. Diez-Roux, F. Holguin, Y. Hong, R. V. Luepker, M. A. Mittleman, A. Peters, D. Siscovick, S. C. Smith, L. Whitsel, and J. D. Kaufman. 2010. Particulate Matter Air Pollution and Cardiovascular Disease. Circulation 121:2331–2378.
Bullard, R. D. 1993a. Race and Environmental Justice in the United States Symposium: Earth Rights and Responsibilities: Human Rights and Environmental Protection. Yale Journal of International Law 18:319–336.
Bullard, R. D. 1993b. Confronting Environmental Racism: Voices from the Grassroots. South End Press.
Carlson, E.D. and Chamberlain, R.M. (2005), Allostatic load and health disparities: A theoretical orientation. Res. Nurs. Health, 28: 306–315. doi:10.1002/nur.20084
Kaldor, J., J. A. Harris, E. Glazer, S. Glaser, R. Neutra, R. Mayberry, V. Nelson, L. Robinson, and D. Reed. 1984. Statistical association between cancer incidence and major-cause mortality, and estimated residential exposure to air emissions from petroleum and chemical plants. Environmental Health Perspectives 54:319–332.
Poloniecki, J. D., R. W. Atkinson, A. P. de Leon, and H. R. Anderson. 1997. Daily Time Series for Cardiovascular Hospital Admissions and Previous Day’s Air Pollution in London, UK. Occupational and Environmental Medicine 54:535–540.
Rudel, R. A., R. E. Dodson, L. J. Perovich, R. Morello-Frosch, D. E. Camann, M. M. Zuniga, A. Y. Yau, A. C. Just, and J. G. Brody. 2010. Semivolatile Endocrine-Disrupting Compounds in Paired Indoor and Outdoor Air in Two Northern California Communities. Environmental Science & Technology 44:6583–6590.
Szanton SL, Thorpe RJ, Whitfield KE. Life-course Financial Strain and Health in African-Americans. Social science & medicine (1982). 2010;71(2):259-265. doi:10.1016/j.socscimed.2010.04.001.
By Daniel Menza, Data & GIS Intern, and Kyle Ferrar, Western Program Coordinator, FracTracker Alliance
Cover photo credit: Claycord.com
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/05/tesoro-refinery_re.jpg400900Kyle Ferrar, MPHhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngKyle Ferrar, MPH2017-05-10 09:48:052021-04-15 15:03:07Tracking Refinery Emissions in California’s Bay Area Refinery Corridor
The Susquehanna River is a 444-mile long waterway extending from the area around Cooperstown, New York to the Chesapeake Bay. In Pennsylvania, the basin includes more than 37,000 miles of streams that feed into the river, which capture the precipitation of more than 20,000 square miles of land, and is home to over 3.3 million people.
The region has been heavily impacted by oil and natural gas extraction in recent years; more than 5,500 unconventional wells and roughly 13,500 conventional wells have been drilled in the PA segment of the basin since 2000. Unconventional wells, in particular, have brought industrial-scaled activity, pollution, and waste products to a wide area of the basin, with especially heavy development occurring in three counties along Pennsylvania’s northern tier – Bradford, Susquehanna, and Tioga.
Several governmental agencies are involved with monitoring impacts to this massive watershed. This article focuses on the Pennsylvania portion of the basin, and examines how capable agency-run monitoring efforts are in capturing oil and gas (O&G) related pollution events. The Pennsylvania Department of Environmental Protection (DEP), the US Geological Survey (USGS), and the Susquehanna River Basin Commission (SRBC) maintain a combined network of 274 monthly “grab sample” monitoring sites and 58 continuous data loggers in the Pennsylvania portion of the river basin. Meanwhile, between January 1, 2000 and February 7, 2017, the DEP logged 6,522 on the O&G violations compliance report within the same region. More than three out of every four of these violations have been assessed to unconventional wells, even though only one out of every four active wells in the basin is categorized as such.
Map of O&G Monitoring & Violations in PA’s Susquehanna River Basin
Grab samples obtained from official monitoring locations are the preferred method for regulatory purposes in understanding the long-term health of the river system. Researchers can test for any number of analytes from samples that are collected in-stream, but analyzed in certified laboratories. However, samples from these locations are collected periodically – usually once per month – and therefore are very likely to miss the effects of a significant spill or issue that may impact surface water chemistry for a number of hours or days before being diluted and washing downstream.
Continuous data loggers give regulators a near real-time assessment of what is happening in selected points in the basin, usually at 15-minute intervals. While there are numerous events that contribute to fluctuations in these measurements, these data loggers would be the most likely instruments available to register an event impacting the surface water within the basin. However, there are unique issues with data loggers. For instance, available data from these data loggers are much more limited in scope, as temperature, pH, and conductivity are typically the only available analytes. In addition, because the analysis occurs on site, the results carry less weight than laboratory results would. Finally, even though data loggers collect data at rapid intervals, only some are equipped to send data real-time to agency offices. Some data loggers must be manually collected on a periodic basis by program managers.
Perhaps the greatest challenge for monitoring in the Susquehanna River Basin is that it is simply not practical to monitor in all places likely to be impacted by oil and gas operations. Testing within the jurisdiction of the Susquehanna River Basin is actually fairly extensive when compared to other regions, such as the Ohio River Basin. The Ohio River Valley Water Sanitation Commission – the equivalent of the SRBC for the Ohio River Basin – only monitors basic analytes like total dissolved solids at 29 locations, all at or near the main stem of the river. However, none of the agencies monitoring water quality in the Susquehanna River Basin have capacity to test everywhere. On average, there is one testing location for every 111 miles of rivers and streams within the basin.
Case Studies
If agency-based monitoring is so limited, then the important question is: How well do these efforts capture oil and gas-related impacts? Some violations are more likely to impact surface water quality than others. This article takes a closer look at some of the bigger problem areas within the basin, including the Dimock region in Susquehanna County, Leroy Township in Bradford County, and Bell Township in Clearfield County.
Dimock
O&G violations and water monitoring near Dimock, PA. Note that multiple violations can occur at the same location. Click to expand map.
The highest concentration of oil and gas violations in the Susquehanna Basin is located in the townships of Dimock and Springville, in Susquehanna County, PA, with a total of 591 incidents reported on the compliance report. This makes the region the highest concentration of O&G violations in the entire state. Many of these violations are related to the systemic failure of well integrity, resulting in the contamination of numerous groundwater supplies. In terms of how these might affect surface water, 443 of the violations are in areas that drain into the Thomas Creek-Meshoppen Creek subwatershed by the southern edge of Springville Township, while most of the rest of the violations drain into the parallel West Branch of Meshoppen Creek.
The USGS operates a monthly monitoring location in the middle of the cluster of violations, at the confluence of Burdick and Meshoppen creeks, just north of the Dimock’s southern border. While this location might seem ideal at first, only 180 of the 443 violations in the subwatershed are upstream of the grab sample site. There is another water monitoring location that captures all of these violations in the Meshoppen subwatershed, but it is more than 15 miles downstream. (link to EJ article about Dimock)
Leroy Township
O&G Violations and monitoring near Leroy Township, PA. Click to expand map.
Compared to the huge amount of oil and gas violations throughout the Dimock area, Leroy Township in Bradford County looks relatively quiet. It also appears to be well covered by monitoring locations, including a data logger site near the western edge of the township, a centrally located monthly monitoring location, as well as another monthly grab sample site upstream on Towanda Creek, just beyond the eastern boundary in Franklin Township.
And yet, this area was hit hard in the early part of the decade by two significant spills. On April 19, 2011, Chesapeake Appalachia lost control of the Atlas 2H well, with thousands of gallons of flowback fluid spilling onto the countryside and into the nearby Towanda Creek.
A little over a year later on July 4, 2012, a second major spill in the township saw 4,700 gallons of hydrochloric acid hit the ground. According to the DEP compliance report, this did not make it into the waterways, despite the gas well being located only about 550 feet from Towanda Creek, and less than 300 feet from another unnamed tributary.
Both incidents were within a reasonable distance of downstream monitoring locations. However, as these are grab sample sites that collect data once per month, they can only offer a limited insight into how Towanda Creek and its tributaries were impacted by these notable O&G related spills.
Bell Township
O&G violations and monitoring near Bell Township, PA. Click to expand map.
Bell Township is a small community in Clearfield County along the banks of the West Branch Susquehanna River. The northwestern portion of the township ultimately drains to the Ohio River, but all of the violations in Bell Township are within the Susquehanna River Basin.
Two significant incidents occurred in the township in 2016. On February 18, 2016, Alliance Petroleum Corp lost control of the McGee 11 OG Well, located less than 250 feet from Deer Run. According to the oil and gas compliance report, control of the well was regained five days later, after releasing unspecified quantities of gas, produced fluid, and crude oil. On December 5th of the same year, Exco Resources was cited for allowing 30 barrels (1,260 gallons) of produced fluid to spill at the Clyde Muth M-631 Wellpad in Bell Township.
A United States Geological Survey monthly monitoring location along the West Branch Susquehanna in nearby Greenwood Township is upstream, and could capture the effects of spills throughout much of Bell Township. However, the incident at the Clyde Muth well pad occurred in the Curry Run subwatershed, which meets up with the West Branch Susquehanna downstream of the monitoring location, so any pollution events in that area will not be reflected by monitoring efforts.
Conclusions
In the case of Dimock and Springville townships, we see how official water monitoring efforts capture only a fraction of the notorious cluster of wells that have resulted in hundreds of violations over the past decade. There could scarcely be a better candidate for systematic observation, and yet only a single grab sample site covers the immediate vicinity. Leroy Township does not have the same quantity of impacts as Dimock, but it did see one the worst blowouts in the recent history of O&G operations in Pennsylvania. The area is relatively well covered by grab samples sites, but due to the monthly sampling schedule, these locations would still be unlikely to capture significant changes in water quality. In Bell Township, much of the area is upstream of a monthly grab sample site, but the nearest downstream monitoring location to a major spill of produced fluid that occurred here is more than 17 miles away from the incident as the crow flies.
It should be noted that there are a number of industries and activities that contribute to water pollution in Pennsylvania, and as a result, the monitoring efforts are not specifically designed to capture oil and gas impacts. However, the compliance record shows heavy impacts from oil and gas wells in the basin, particularly from modern unconventional wells.
While the network of government-operated manual monitoring locations and data logger sites are fairly extensive in Susquehanna River Basin, these efforts are not sufficient to capture the full extent of oil and gas impacts in the region. Finding evidence of a small to medium sized spill at a site with monthly testing is unlikely, as contaminated water doesn’t stay in place in a dynamic river system. Data loggers also have a limited capacity, but are a useful tool for identifying substantial changes in water chemistry, and could therefore be employed to identify the presence of substantial spills. As such, it might be beneficial for additional data loggers to be distributed throughout the basin, particularly in areas that are heavily affected by the oil and gas industry. Furthermore, given resource gaps and staff cuts within agencies tasked with protecting the river basin, agencies should strongly consider utilizing networks of volunteers to augment their limited monitoring networks.
By Matt Kelso, Manager of Data and Technology, FracTracker Alliance
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/05/Susquehanna-2-Feature-WP.jpg400900Matt Kelso, BAhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngMatt Kelso, BA2017-05-02 13:17:582021-04-15 15:03:08Violations and Monitoring in Pennsylvania’s Susquehanna River Basin
By Alison Grass, Senior Researcher at Food & Water Watch
Over the past decade, the natural gas industry has experienced a renaissance that has been a boon to energy company profits. But it has altered the quality of life for the rural communities where most new gas wells have been drilled. Now, fracking is fueling a gas-fired power plant boom in Pennsylvania, with 47 new facilities. Most have already been approved, with a handful in commercial operation (see map below).
New research by Pennsylvanians Against Fracking shows, in vivid detail, the scale of this buildout, and the impacts it will have on Pennsylvania communities.
Current & Potential PA Gas-Fired Power Plants & their Emissions
Approximately half of the new gas power plants are located in northeastern region of Pennsylvania, a part of the state already overburdened by the lingering environmental maladies of coal mining and the more recent dangers associated with fracking. These rural communities may see increased drilling, fracking and pipeline construction to support the power plants — and the siting could be strategic. In a StateImpact Pennsylvania article about the first Marcellus shale gas power plant, for example, a company representative admitted that the location was chosen specifically due to its convenient access to shale gas. “This plant was sited precisely where it is because of its access to the abundant, high-quality natural gas that’s found a mile to two miles beneath our feet.”
Drilling Trends
The first modern Marcellus well was drilled in Pennsylvania by Range Resources in 2003, and commercial production began in 2005. Although fracking expanded rapidly in several areas across the country, Pennsylvania has been ground zero of the fracking boom, with just over 10,000 shale gas wells drilled between 2005 and 2016. Since then, however, there has been a rapid downturn in new wells drilled. After the early and dramatic increase in drilling – from 9 shale wells in 2005 to 1,957 shale wells in 2011 – the number dropped to 504 in 2016.
According to Natural Gas Intelligence, natural gas from the Appalachian Basin “…hit a roadblock in 2016, as pipeline projects struggled to move forward and a storage glut slowed the region’s previously rapid production growth.” Thus, it appears that in order to maintain fracking’s profitability, the gas industry is relying on new gas-fired power plants to alleviate the storage glut, while potentially increasing demand for shale gas (which could propagate more drilling and fracking).
Gas-Fired Power Plant Siting
The siting of these power plants also enables companies to use Pennsylvanian fracked gas to generate power for larger regional markets. This is because northeastern Pennsylvania is close to dense populations, including New York City. In Luzerne County, for instance, the new Caithness Moxie Freedom Generating Station gas-fired power plant will supply electricity to not just Pennsylvania residents, but also to New Jersey and New York State. And in the more central region of the state in Snyder County, the Panda Hummel Station will send “much of its power to the New York City market.”
Siting gas-fired power plants in the northeast may also increase drilling and fracking in the region, where gas is predominantly “dry” and less profitable than the “wet” gas found in southwest PA. This trend is largely due to a resurgence in North American petrochemical markets and increased ethane exports that rely on wet gas. (Dry natural gas contains primarily methane and smaller amounts of other hydrocarbons, while wet natural gas has higher concentrations of natural gas liquids. Natural gas liquids — predominantly ethane but also propane, butane, isobutane and pentanes — are the raw materials for manufacturing petrochemicals.)
Well Integrity and Other Risks
However, increased drilling and fracking mean more pollution for the Marcellus shale region of Pennsylvania, where shale gas wells have proven to be more prone to well construction “impairments” and well integrity problems, compared to conventional wells. This risk is especially true in the northeastern part of the state, where over nine percent of shale gas wells have indications of compromised well integrity.
Overall, fracking causes many public health and environmental problems. Methane, fracking fluids, and wastewater can pollute water supplies and imperil the livelihoods of farmers, who rely on clean water. Increased truck traffic and drilling emissions reduce air quality, and methane leaks contribute to global warming. Meanwhile, the proliferation of natural gas derricks and associated infrastructure destroys pristine landscapes (and related tourism and recreation industries).
The last thing that Pennsylvanians need is another way for the oil and gas industry to capitalize on shale at the expense of residents’ health and well-being.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/03/Power-Plants-PA-Feature.jpg400900Guest Authorhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngGuest Author2017-04-21 13:34:192021-04-15 15:03:09Wanted: More Places to Burn Natural Gas
In March 2017, FracTracker Alliance conducted a review of the available Pennsylvania oil and gas fine data released publicly by the PA Department of Environmental Protection (DEP) to identify trends in industry-related fines over time and by particular operators. In total, the DEP has assessed nearly $36 million in fines to oil and gas extraction and pipeline operators since January 1, 2000. Such fines are associated with over 42,000 violations issued1 by DEP in that time frame, covering 204,000 known oil and gas locations,2 as well as 91,000 miles of pipelines3 within the Commonwealth.
Understanding the Data Structure
The amount of money that the Pennsylvania Department of Environmental Protection (DEP) fines oil and gas (O&G) operations is included in the DEP’s compliance report published on their website. Even though fines data are made available, they are not necessarily straight-forward, and caution must be taken not to over-estimate the total number of assessed fines.
Records of fines are associated with enforcement identification codes on the compliance report. A single fine is often applied to numerous violations, and the full amount of the fine is listed on every record in this subset. Therefore, the total dollar amount of fines assessed to O&G companies appears overstated. For example, if a $400,000 fine were assessed to settle a group of 10 violations, that figure will appear on the report 10 times, for an apparent aggregate of $4,000,000 in fines. To get an accurate representation of fines assessed, we need to isolate fines associated with particular enforcement ID numbers, which are used administratively to resolve the fines.
This process is further complicated by the fact that, on occasion, such enforcement ID numbers are associated with more than one operator. This issue could result from a change in the well’s operator (or a change of the operator’s name), a group of wells in close proximity that are run by different operators, or it might point to an energy extraction company and a midstream company sharing responsibility for an incident. Sometimes, the second operator listed under an enforcement ID is in fact “not assigned.” The result is that we cannot first summarize by operator and then aggregate those subtotals without overstating the total amount of the assessed fines. In all, 62 of the enforcement ID numbers apply to more than one operator, but this figure amounts to less than one percent of the nearly 15,000 distinct enforcement ID numbers issued by DEP.
Conventional & Unconventional Violations & Fines
Oil and gas wells in Pennsylvania are categorized as either conventional or unconventional, with the latter category intended to represent the modern, industrial-scaled operations that are commonly referred to as “fracking wells.” Contrastingly, conventional wells are supposed to be the more traditional O&G wells that have been present in Pennsylvania since 1859. The actual definition of these wells leaves some blurring of this distinction, however, as almost all O&G wells now drilled in Pennsylvania are stimulated with hydraulic fracturing to some degree, and some of the conventional wells are even drilled horizontally – just not into formations that are technically defined as unconventional. For the most part, however, unconventional remains a useful distinction indicating the significant scale of operations.
Table 1. Summary of oil and gas wells, violations, and fines in Pennsylvania
Category
Conventional
Unconventional
(blank)
Total
Wells
193,655
10,291
0
203,946
Violations
27,223
6,126
9,026
42,375
Fines
$7,000,203
$13,689,032
$21,563,722
$35,949,495*
Fines per Violation
257
2,235
2,389
848
Fines per Well
36
1330
–
176.27
Violations per Well
0.14
0.60
–
0.21
Wells per Violation
7.11
1.68
–
4.81
* The total fine amount issued is not a summary of the three preceding categories, as some of the fines appear in multiple categories
Ninety-five (95)% of the state’s 204,000 O&G wells are classified as conventional, so it should not be surprising to see that this category of wells accounts for a majority of violations issued by the department. However, fines associated with these violations are less frequent, and often less harsh; the $7 million in fines for this category accounts for only 19% of the total assessed penalties. In contrast, the total penalties that have been assessed to unconventional wells in the state are nearly twice that of conventional wells, despite accounting for just 5% of the state’s well inventory
On the 54,412 records on the compliance report, 10,518 (19%) do not indicate whether or not it is an unconventional well. The list of operators includes some well-known conventional and unconventional drilling operators, and hundreds of names of individuals or organizations where O&G drilling is not their primary mode of business (such as municipal authorities and funeral homes). This category also contains violations for midstream operations, such as pipelines and compressor stations. Altogether, 3,795 operators have entries that were not categorized as either conventional or unconventional on the compliance report, and 124 of these operators were issued fines. One additional complication is that some of the violations and fines that fall into this category are cross-referenced in the conventional and unconventional categories, as well.
The resulting impact of these factors is that the blank category obscures the trends for violations and fines in the other two categories. While tempting to reclassify well data in this category as either conventional or unconventional, this would be a tall task due to the sheer number of records involved, and would likely result in a significant amount of errors. Therefore, the FracTracker Alliance has decided to present the data as is, along with an understanding of the complexities involved.
Most Heavily Fined Operators
Despite the numerous caveats listed above, we can get a clear look at the aggregated fines issued to the various O&G operators in the state by constructing our queries carefully. Table 2 shows the top 12 recipients of O&G-related fines assessed by DEP since 2000. Ten of these companies are on the extraction side of the business, and the total number of well permits issued4 to these companies since 2000 are included on the table. By looking at the permits instead of the drilled wells, we discover the operator that was originally associated with the drilling location, whereas the report of drilled wells associates the current operator associated with the site, or most recent operator in the event that the location is plugged and abandoned.
Stonehenge Appalachia and Williams Field Services operate in the midstream sector. Combining the various business name iterations and subsidiaries would be an enormous task, which we did not undertake here, with the exception of those near the top of the list. This includes Vantage Energy Appalachia, which was combined with records from Vantage Energy Appalachia II, and the compliance history of Rice Energy is the sum of three subsidiaries, the drilling company Rice Drilling B, and two pipeline companies, Rice Midstream Holdings and Rice Poseidon Midstream.
Table 2. Top 12 operators that have been assessed oil and gas-related fines by DEP since 2000
Operator
Total Fines
Conventional Permits
Unconventional Permits
Violations
Fines / Violation
Fines / Permit
Range Resources Appalachia LLC
$5,717,994
2,104
2,206
819
$6,982
$1,327
Chesapeake Appalachia LLC
$3,120,123
18
3,072
754
$4,138
$1,010
Rice Energy*
$2,336,552
442
165
$14,161
$5,286
Alpha Shale Res LP
$1,681,725
3
62
31
$54,249
$25,873
Stonehenge Appalachia LLC
$1,500,000
–
–
294
$5,102
–
Cabot Oil & Gas Corp
$1,407,275
19
902
726
$1,938
$1,528
CNX Gas Co LLC
$1,274,330
1,613
677
387
$3,293
$556
WPX Energy Appalachia LLC
$1,232,500
347
159
$7,752
$3,552
Chevron Appalachia LLC
$1,077,553
2
604
113
$9,536
$1,778
Vantage Energy Appalachia LLC**
$1,059,766
3
300
35
$30,279
$3,498
Williams Field Services Co, LLC
$872,404
–
–
158
$5,522
–
XTO Energy Inc
$739,712
1,962
461
383
$1,931
305
* Fines for Rice Energy here represent the sum of three subsidiaries, the drilling company Rice Drilling B, and two pipeline companies, Rice Midstream Holdings and Rice Poseidon Midstream.
** Fines for Vantage Energy Appalachia were combined with records from Vantage Energy Appalachia II.
Predictably, many of the entries on this list are among the most active drillers in the state, including Range Resources and Chesapeake Appalachia. However, Alpha Shale Resources has the dubious distinction of leading the pack with the highest amount of fines per violation, as well as the highest amount of fines per permit. Fitting in with the theme, the story here is complicated by the fact that Alpha had a joint venture with Rice, before selling them their stake in a group of wells and midstream operations that were fined $3.5 million by DEP.5 On this compliance report, the fines from this incident are split between the two companies.
Fines Issued Over Time
It is worth taking a look at how O&G related fines have varied over time, as well (Figure 1, shown in millions of dollars). Numerous factors could contribute to changes in trends, such as the number of available DEP inspectors,6 the amount of attention being paid to the industry in the media, differing compliance strategies employed by various political administrations, or changes in practices in the field, which could in turn be impacted by significant fines issued in the past.
Figure 1. O&G Fines Issued by DEP, 2000 through 2016
The notable spike in fines issued from 2010 to 2012 corresponds with the peak of unconventional drilling in the state – 4,908 of these industrial scaled wells were drilled during those three years, amounting to 48% of all unconventional wells in PA. In contrast, only 504 unconventional wells were drilled in 2016, or around a quarter of the total for 2011. In this context, the reduction in fines since the early part of the decade seems reasonable.
The association with the number of unconventional wells falls apart a bit in the years 2013 to 2014, however. These two years saw an average of 1,293 unconventional wells drilled, but the fines issued amounted to only 35% of the 2011 total.
Considerable strides have been made in the public accessibility of oil and gas data available from the PA DEP since FracTracker started requesting and reviewing this information in 2009. Still, there are many gaps in the datasets, such as geolocation details for 10 of the 20 largest fines issued by the department. FracTracker hopes external analyses like this one will help to close such gaps and identify operators who, too, need to improve their compliance records.
Pipelines are hailed as the “safest” way to transport crude oil and other refinery products, but federal and state data show that pipeline incidents are common and present major environmental and human health hazards. In light of current events that have green-lighted multiple new pipeline projects, including several that had been previously denied because of the environmental risk they pose, FracTracker Alliance is continuing to focus on pipeline issues.
In this article we look at the record of oil spills, particularly those resulting from pipeline incidents that have occurred in North Dakota, in order to determine the risk presented by the soon-to-be completed Dakota Access Pipeline.
Standing Rock & the DAPL Protest
To give readers a little history on this pipeline, demonstrators in North Dakota, as well as across the country, have been protesting a section of the Dakota Access Pipeline (DAPL) near the Standing Rock Sioux Tribe’s lands since April 2016. The tribe’s momentum has shifted the focus from protests at the build site to legal battles and a march on Washington DC. The pipeline section they are protesting has at this point been largely finished, and is slated to begin pumping oil by April 2017. This final section of pipe crosses under Lake Oahe, a large reservoir created on the Missouri River, just 1.5 miles north of the Standing Rock Sioux Tribal Lands. The tribe has condemned the pipeline because it cuts through sacred land and threatens their environmental and economic well-being by putting their only source for drinking water in jeopardy.
Pipelines
… supposedly safest form of transporting fossil fuels, but …
However, what makes one form of land transport safer than the others is dependent on which factor is being taken into account. When considering the costs of human death and property destruction, pipelines are indeed the safest form of land transportation. However, for the amount of oil spilled, pipelines are second-worst, beaten only by trucks. Now, when it comes to environmental impact, pipelines are the worst.
What is not debatable is the fact that pipelines are dangerous, regardless of factor. Between 2010 and October 2016 there was an average of 1.7 pipeline incidents per day across the U.S. according to data from the Pipeline and Hazardous Materials Safety Administration (PHMSA). These incidents have resulted in 100 reported fatalities, 470 injuries, and over $3.4 billion in property damage. More than half of these incidents were caused by equipment failure and corrosion (See Figures 1 and 2).
Figure 1. Impacts of pipeline incidents in the US. Data collected from PHMSA on November 4th, 2016 (data through September 2016). Original Analysis
Figure 2. Cause of pipeline incidents for all reports received from January 1, 2010 through November 4, 2016. Original Analysis
Recent Spills in North Dakota
To dig into the risks posed in North Dakota more specifically, let’s take a look at some spill data in the state.
Map 1. Locations of Spills in North Dakota, with volume represented by size of markers
In North Dakota alone there have been 774 oil spill incidents between 2010 and September 2016, spilling an average of 5,131 gallons of oil per incident. The largest spill in North Dakota in recent history, and one of the largest onshore oil spills in the U.S., took place in September 2013. Over 865,000 gallons of crude oil spilled into a wheat field and contaminated about 13 acres. The spill was discovered several days later by the farmer who owns the field, and was not detected by remote monitors. The state claims that no water sources were contaminated and no wildlife were hurt. However, over three years of constant work later, only about one third of the spill has been recovered.
Below we have analyzed available spill data for North Dakota, including the location and quantity of such incidents.
North Dakota saw an average of 111 crude oil spills per year, or a total of 774 spills from 2010 to October 2016. The greatest number of spills occurred in 2014 with a total of 163. But 2013 had the largest spill with 865,200 gallons and also the highest total volume of oil spilled in one year of 1.3 million gallons. (Table 1)
Table 1. Data on all spills from 2010 through October 2016. Data taken from PHMSA and North Dakota.
2010
2011
2012
2013
2014
2015
Jan-Oct 2016
Number of Spills
55
80
77
126
163
117
156
Total Volume (gallons)
332,443
467,544
424,168
1,316,910
642,521
615,695
171,888
Ave. Volume/Spill (gallons)
6,044
5,844
5,509
10,452
3,942
5,262
1,102
Largest Spill (gallons)
158,928
106,050
58,758
865,200
33,600
105,000
64,863
The total volume of oil spilled from 2010 to October 2016 was nearly 4 million gallons, about 2.4 million of which was not contained. Most spills took place at wellheads, but the largest spills occurred along pipelines. (Table 2)
Table 2. Spills by Source. Data taken from PHMSA and North Dakota.
Wellhead
Vehicle Accident
Storage
Pipeline
Equipment
Uncontained
All Spills
Number of Spills
694
1
12
54
13
364
774
Total Volume (gallons)
2,603,652
84
17,010
1,281,798
68,623
2,394,591
3,971,169
Ave. Volume/Spill (gallons)
3,752
84
1,418
23,737
5,279
6,579
5,131
Largest Spill (gallons)
106,050
84
10,416
865,200
64,863
865,200
865,200
A. Sensitive Areas Impacted
5,875 square miles
Total Affected Areas (408 linear miles)
Spills that were not contained could potentially affect sensitive lands and waterways in North Dakota. Sensitive areas include Native American Reservations, waterways, drinking water aquifers, parks and wildlife habitat, and cities. Uncontained spill areas overlapped, and potentially contaminated, 5,875 square miles of land and water, and 408 miles of streams.
Drinking Water Aquifers – 2,482.3 total square miles:
Non-Community Aquifer – 0.3 square miles
Community Aquifer – 36 square miles of hydrologically connected aquifer
Surficial Aquifer – 2,446 square miles of hydrologically connected aquifer
A large area of potential drinking water (surficial aquifers) are at risk of contamination. Of the aquifers that are in use, aquifers for community use have larger areas that are potentially contaminated than those for non-community use.
Native American Tribal Reservation
Fort Berthold, an area of 1,569 square miles
Cities – 67 total square miles
Berthold
Dickinson
Flaxton
Harwood
Minot
Petersburg
Spring Brook
Stanley
West Fargo
Map 2. Areas where Oil Spills Present Public Health Threats
Floodplains – 73 square miles of interconnected floodplains
Streams – 408 miles of interconnected streams
Of the 364 oil spills that have occurred since 2010, 229 (63%) were within 1/4 mile of a waterway
Of the 61 Uncontained Brine Spills that have occurred since 2001, 38 (63%) were within 1/4 mile of a waterway.
If a spill occurs in a floodplain during or before a flood and is uncontained, the flood waters could disperse the oil over a much larger area. Similarly, contaminated streams can carry oil into larger rivers and lakes. Explore Map 3 for more detail.
Using ArcGIS software, uncontained spill locations were overlaid on spatial datasets of floodplains, stream beds, groundwater regions, sensitive habitats, and other sensitive regions.
The average extent (distance) spilled oil traveled from uncontained spill sites was calculated to 400 meters. This distance was used as a buffer to approximate contact of waterways, floodplains, drinking water resources, habitat, etc. with uncontained oil spills.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2017/04/OilSpill_12.16_crop.jpg400900Kyle Ferrar, MPHhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngKyle Ferrar, MPH2017-04-11 16:15:232021-04-15 15:03:11Oil Spills in North Dakota: What does DAPL mean for North Dakota’s future?
By Greg Pace – Columbus Community Bill of Rights, and Julie Weatherington-Rice – Environmental Consultant
Figure 1. Map of Columbus, OH Watersheds and Class II Injection Wells
Most Ohio residents are unaware of the frack fluid deep underground injection occurring north of Columbus, underneath the region’s source water protection watersheds (Figure 1).
Materials injected are liquids that have as much as ten times the salt concentration of sea-water. Mixed with this “brine” solution is a combination from hundreds of chemicals that are used in different stages of horizontal hydraulic fracturing, the process used to extract natural gas, petroleum, and hydrocarbon liquids used to make industrial materials such as plastics. BTEX compounds including benzene are always present in the wastewater, along with formaldehyde, bromides, ethylene glycol (antifreeze), and arsenic, with many other carcinogenic and otherwise highly-toxic substances.
Radioactivity of Shale Gas Wastewater
One of the biggest questions in this mix of toxic disposal is how much radioactive content exists. Radium-226 is most worrisome, as it has a very long half-life (1,600 years). It is water-soluble and, once it enters the human body, seeks to find a home in our bones where it will emit its cell-formation-destabilizing effects for the remainder of our lifetime. This radionuclide is known to cause leukemia, bone cancers, blood disorders, and other diseases.
The state of Ohio does not monitor the content of materials that are injected into our Class II injection wells deep in the ground. This oil and gas waste can come from anywhere, including Pennsylvania’s Marcellus shale, which is the most highly-radioactive geology of all the shale plays in the country. Radium-226 readings as high as 15,000 pico-curies per liter have been read in Marcellus shale brines. The EPA drinking water limit for radium-226 is 5 pico-curies per liter, which puts the Marcellus reading at 3,000 times higher than the drinking water limit.
Exposure through drinking water is a pathway to human disease from radium-226. Once oil and gas waste is disposed of underground in a sandstone or limestone layer, the fluids are subject to down-gradient movement, wicking through capillary action, and seepage over time. This means that the highly radioactive wastewater could eventually end up in our underground drinking water sources, creating radium watersheds. This practice is putting our watersheds at risk from radioactive contamination for hundreds of years, at least.
Can injected fluids migrate?
Depending on whether you confer with a geologist who works with the oil and gas industry, or from an independent geologist, you will get a different opinion on the likelihood of such a pollution event occurring. Industry geologists mostly claim that deep injection leaves very low risk of water contamination because it will not migrate from the planned area of injection. On the other hand, independent geologists will tell you that it is not a matter of if the liquids will migrate, but how and when. The ability to confirm the geology of the underground area layer of injection “storage” is not exact, therefore accuracy in determining the probability for migration over time is poor.
Figure 2. Ohio Utica Brine Production and Class II Injection Well Disposal
We do know, however, that all underground systems in Ohio leak – Research by The Ohio State University and the US Geological Survey show that the age of the water in brine formations is far younger than the age of the rock deposits they are found in. See where wastewater is being created and disposed of in Ohio using the dynamic map above (Figure 2).
Spill Risks to Columbus, OH Water
According to area geologist, Dr. Julie Weatherington-Rice, the source for Columbus’s water to the north is mostly from surface water. This water comes from the Delaware and Morrow county watersheds that feed into sources such as the Hoover and Alum Creek reservoirs. The major threat from injection wells to our watershed is from spills, either from trucks or from storage at the injection well sites themselves.
Figure 3. Dead fish floating in Vienna area pond contaminated by injection well system spill. Source: MetropolitanEnegineering Consulting & Forensics-Expert Engineers
In April 2015, as much as 8,000 gallons of liquid leaked from a malfunctioning pipe in the storage apparatus of an oil/gas waste storage and injection well site in Vienna, OH. This caused a wildlife kill in two ponds (Figure 3), and the spill was not contained until 2/3 mile downstream in a tributary. The firm who owned the facility was found negligent in that they did not install a required containment liner for spills. The incident was discovered by neighboring residents, but apparently employees knew of the leak weeks before. Of note in this incident was that Ohio Department of Natural Resources, the regulatory agency that oversees all oil/gas production activity in Ohio including injection, stated that there was “minimal impact to wildlife.”
Figure 4. Brine tanker rollover near Barnesville, OH spilled 5,000 gal. of produced brine. Source: Barnesville, OH Fire Department
In March, 2016, a tanker truck carrying produced waste from a hydraulically fractured well pad overturned outside of the Village of Barnesville, Ohio (Figure 4). The truck spilled 5,000 gallons of liquid waste into a field that led into a tributary, leading the fluids to enter one of the city’s three drinking water supply reservoirs. The water source was shut down for more than two months while regulators determined if water levels were safe for consumption. There was a noted spike in radium-226 levels during water testing immediately after the spill.
Of greatest concern is that, although many millions of gallons of frack waste have been injected into the wells north of Columbus over the past few years, we expect that this activity will increase. For the first time, the United States began exporting its own natural gas in 2016, to regions such as Europe and South America. As the industry consolidates from the depression of oil prices over the past two years and begins to ramp up again, we expect the extraction activity in the Marcellus and especially Utica to increase to levels beyond what we have seen since 2011. The levels of injection will inevitably follow, so that injection wells in Ohio will receive much more than in the past. The probability of spills, underground migration, and human-induced earthquakes may increase steeply, as well.
An Aging Disposal Infrastructure
On our Columbus Community Bill of Rights website, we show pictures of some of the Class II injection wells in Morrow County, most of them converted from legacy production wells. These old wells are located in played out oil/gas fields that may still be producing or have abandoned but not plugged (closed) wells, allowing other routes for injected liquids to migrate into shallow ground water and to the surface. The dilapidated condition of these converted Class II wells makes it hard to believe that they are used to inject millions of gallons of wastewater under high pressure. While many of the wells in the state are as deep as 9,000 feet, all of the injection wells we have seen in Morrow County are only 3,000-4,000 feet deep. This situation puts surface water at greater risk over time, as it is probable that, over the generations, some of the fluids will migrate and wick into the higher subterranean strata.
One well (Power Fishburn unit, photo below) showed signs of poor spill control when we took our October 2015 injection well tour. While we were there, a brine tanker arrived and began pumping their load into the well. The driver took pictures of our license plates while we were there watching him. A year later, there is a whole new structure at the well, including a new storage tower, and an extensively beefed-up spill control berm. Maybe we need to visit all of the facilities when they come by to use them!
Another well (Mosher unit, photo below) which hadn’t been used since 2014 according to available records, showed signs of a spill around the well. The spill control berms look as if they probably had flooded at some point. This well sits on the edge of a large crop field.
Figures 6a and 6b. Photos of Class II injection wells. Click on the images to expand them.
North of Columbus, the city of Delaware’s underground source water is at risk of becoming contaminated from underground migration of disposed wastewater over time, through wicking and seepage effects (as explained earlier in this article). They are also vulnerable to their reservoir being contaminated from surface spill migration through their watershed.
Figure 7. Google maps rendition of Ohio Soil Recycling facility in south Columbus, Ohio, that accepts shale drill cuttings for remediation to cap the landfill. Source: Google Maps/author
South of Columbus is another threat – drill cuttings from the drilling process have been authorized for disposal at a “remediation” landfill adjacent to the Alum Creek (Figure 7). The bioremediation treatment used is not indicated to solve the problem of removing radionuclides from the materials. This landfill had been remediated under the Ohio EPA twice when it was a toxic drum dump, after toxins were found to have been leaching into the watershed creek. Columbus’s Alum Creek well, as well as Circleville, are at risk of contamination in their drinking water if radionuclides from the cuttings leach into Alum Creek. Again, this is a long-term legacy of risk to their water.
Radiation Regulatory and Monitoring Gaps
Since The Ohio legislature deemed the radioactive content of shale cuttings to be similar to background levels in the 2013 state budget bill, cuttings can be spread around to all licensed landfills in Ohio with absolutely no accountability for the radium and other heavy metal levels in them. Unfortunately, the measuring protocol used in the pilot study for the Columbus facility to demonstrate to Ohio EPA that radium-226 was below EPA drinking water limits has been shown in a University of Iowa study to be unreliable. The inadequate protocol was shown to indicate as little as 1% of the radium levels in shale waste samples tested.
As such, there have been hundreds of incidents where truckloads of cuttings have been turned away at landfills with crude radiation monitors. In 2013 alone, 2 loads were turned away in Ohio landfills, and over 220 were turned away from Pennsylvania landfills.
Ohio has a long way to go before it can be considered a clean energy state. The coal industry polluted significant water sources in the past. The fracking industry seems to be following suit, where contaminations will surprise us long into the future and in broader areas.
