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FracTracker’s new Pennsylvania oil and gas well map displays conventional and unconventional wells and violations as of January 12, 2022.
Water at Risk
A Digital Atlas Exploring the Impacts of Natural Gas Development in
the Lycoming Creek Watershed of Pennsylvania
Coursing through lush valleys of the Allegheny Plateau, Lycoming Creek flows over 37 miles to its confluence with the West Branch Susquehanna River in Williamsport, Pennsylvania. The 272-square-mile watershed includes idyllic tributaries like Pleasant Stream and Trout Run, names reflecting the intrinsic beauty and bounty of the area. Rock Run in Loyalsock State Forest by some accounts is, “one of the most beautiful streams in all of Pennsylvania.”
The mightier Pine Creek to the west perhaps carries greater notoriety, as does the enchanting Loyalsock to the east. But make no judgement about Lycoming Creek’s smaller stature. Forest covers 81% of the basin and only one percent is developed, with the rest of the land used for agriculture. Through the heart of this rugged terrain, a picturesque waterway beckons anglers and other revelers of the wilds.
The Lenape people called the watershed home before European occupation. They knew the creek as Legani-hanne, meaning “sandy or gravelly stream.” The native residents and those who displaced them used it as a means of transportation, whether traveling by canoe or walking the Sheshequin Path that runs north and east along the shores.
Lumber fueled the regional economy of the 19th century, and Lycoming’s forests fell. By rail and by water, saw logs were sent to Williamsport for milling. Wood-powered wealth gave rise to the city’s “Millionaire’s Row,” but prosperity apexed in the early 20th century. Today, the Williamsport area is home to nearly 30,000 people, down from a peak of around 45,000 in 1950. Comparatively, about 20,000 persons live within the Lycoming Creek watershed.
These days, Williamsport buzzes with breweries, bookstores, and the vitality of an urban hub. The Little League World Series still comes to town every summer, ushering memories of simpler, quieter times.
Nearby, the serene creek surges with life, including the Eastern hellbender—North America’s largest amphibian. But the same water can turn tempestuous and destructive. Notable floods in 1972, 1996, 2011, and 2016 caused loss of life and property damage. As climate change intensifies, heavy downpours and rapid snowmelt exacerbate flood risks.
Unconventional drilling brought new threats to the area: congested truck traffic, exorbitant consumptive water use, myriad air pollution sources, extensive land clearing, and ecological disturbance; and, the dangers of spills, leaks, and water contamination.
This report explores these impacts, underscoring the heavy footprint of extraction—and related activities—on public and private lands throughout the Lycoming Creek watershed.
The Lycoming Creek watershed provides ample opportunities for nature-based recreation. While there are no state parks in the watershed, a 507-acre (0.8 square miles) portion of the Tioga State Forest occupies the northern boundary of the watershed in Tioga County. Further south lies 45,022 acres (71.1 square miles) of the Loyalsock State Forest. This includes 332 acres (0.52 square miles) of the Devil’s Elbow Natural Area, a site known for its many wetlands—home to carnivorous sundew and pitcher plants—waters that feed the stunning Rock Run. The McIntyre Wild Area covers a 7,226 acre (11.3 square mile) expanse of the Loyalsock State Forest, situated entirely in the Lycoming Creek watershed. It includes spectacular waterfalls on streams that feed the aforementioned Rock Run, a tributary known for its vibrant trout population.
The Lycoming Creek watershed provides ample opportunities for nature-based recreation. While there are no state parks in the watershed, a 507-acre (0.8 square miles) portion of the Tioga State Forest occupies the northern boundary of the watershed in Tioga County. Further south lies 45,022 acres (71.1 square miles) of the Loyalsock State Forest. This includes 332 acres (0.52 square miles) of the Devil’s Elbow Natural Area, a site known for its many wetlands—home to carnivorous sundew and pitcher plants—waters that feed the stunning Rock Run.
The McIntyre Wild Area covers a 7,226 acre (11.3 square mile) expanse of the Loyalsock State Forest, situated entirely in the Lycoming Creek watershed. It includes spectacular waterfalls on streams that feed the aforementioned Rock Run, a tributary known for its vibrant trout population.
To the west of Lycoming Creek and State Route 14 is Bodine Mountain, another sweeping feature of the Loyalsock State Forest. Bodine Mountain is a north-to-south ridge rising over 1,300 feet above the Lycoming Creek valley.
In addition to state forests, the watershed contains 238 acres of State Game Land 335 at the northern boundary, and 2,430 acres (3.8 square miles) of State Game Land 133, situated southeast of Bodine Mountain. These conserved lands are designated to protect wildlife—a goal that seems at odds with current oil and gas leasing practices.
Fishing and enjoying mountain streams
Pennsylvania has two separate designations for streams with excellent water quality: exceptional value (EV) and high quality (HQ). The Department of Environmental Protection (DEP) explains that the quality of HQ streams can be lowered, “if a discharge is the result of necessary social or economic development, the water quality criteria are met, and all existing uses of the stream are protected.” The water quality of EV streams cannot be lowered.
Sadly, there are no streams in the beautiful Lycoming Creek watershed with an EV designation, however deserving. On the other hand, 412 miles of streams in its drainage are designated as HQ, representing 76% of the watershed’s 542 total stream miles, according to the state’s official designated use inventory. Statewide, 3,838 out of 86,473 miles (4.4%) of inventoried streams are categorized as EV, while 58,748 miles (67.9%) are HQ, making the Lycoming Creek watershed below average for the former, and above average for the latter.
Prior to industrialization, native brook trout populations were widespread in small, forested streams across Pennsylvania. While many streams are now stocked with several species of trout, the combination of pollution and deforestation has decimated the areas where trout—especially native brook trout—thrive in sustainable wild populations. Suitable streams are designated as Class A trout streams, and they are rare, accounting for just 3,037 miles, or 3.5% of streams across the Commonwealth. The Lycoming Creek watershed contains slightly fewer Class A streams than is typical, with 17.5 miles, representing just 3.2% of all streams in the drainage. Nevertheless, it remains an important respite for trout species and the anglers who seek them.
Split estates and the Clarence Moore lands
Hundreds of thousands of acres of Pennsylvania state forest are under lease agreements for fracked gas extraction, diminishing outdoor experiences and posing ongoing environmental threats. In those situations, the state Department of Conservation and Natural Resources (DCNR) clearly controls the surface and the gas that lies beneath. However, in some areas of the state forest, private interests claim mineral ownership, even in gaseous form—a situation called “split estate.” Loyalsock State Forest contains about 25,000 split estate acres, known as the Clarence Moore Lands.
In the Lycoming Creek watershed, most of the Clarence Moore lands lie east of US Highway 15, occupying areas that drain into Rock Run and Pleasant Stream, including some of the area’s few remaining Class A wild trout waters. Another section of the Clarence Moore lands extends west of Highway 15, on Bodine Mountain’s eastern flank. In their current state, the lands provide invaluable ecological services and—coupled with the Loyalsock Creek to the east—comprise critical source waters for two major watersheds.
Gas drilling requires a significant amount of infrastructure, including multiacre well pads, miles of gathering pipelines, retention ponds, waste processing facilities, and compressor and metering stations. Allowing surface disturbance in the Clarence Moore lands could have lasting, devastating consequences.
Nearly a decade ago, the Anadarko Petroleum Corporation approached DCNR with extensive plans for dozens of fracked gas wells and all the disruptive destruction that accompanies them in a large swatch of the Loyalsock State Forest and the Clarence Moore lands. Over the years, the Clarence Moore players have changed significantly. Southwestern Energy scored a stake, while Anadarko sold their interest to Alta Resources, a privately-held company scheduled for purchase by EQT, the nation’s largest fracked gas company. While the operators play their game of musical chairs, the situation remains a serious threat to some of the few remaining portions of the region that haven’t been spoiled with industrial gas drilling.
Ironically, modern horizontal drilling enables access to Clarence Moore’s reserves from miles away—from well pads on private land. There is no need—nor social license—to expunge the forest for future generations for short-lived, selfish gain. Organizations near and far, led by the Responsible Drilling Alliance and Save PA Forests Coalition, have rallied tirelessly to save this land from development, a truly special place deserving permanent protection.
Figure 2. The Clarence Moore Lands are a complicated split estate situation in the Loyalsock State Forest, including parts of the Lycoming, Loyalsock, and Schrader Creek watersheds.
Unique wetland biomes
Countless wetlands feed Lycoming Creek’s headwaters, providing a unique opportunity to observe aquatic flora and fauna beneath the forested canopy of Penn’s Woods. The US Fish and Wildlife Service (USFWS) explains their importance, as well as their precarious state:
“Wetlands provide a multitude of ecological, economic and social benefits. They provide habitat for fish, wildlife and plants—many of which have a commercial or recreational value—recharge groundwater, reduce flooding, provide clean drinking water, offer food and fiber, and support cultural and recreational activities. Unfortunately, over half of America’s wetlands have been lost since 1780, and wetland losses continue today. This highlights the urgent need for geospatial information on wetland extent, type, and change.”
The geospatial data referred to above is the National Wetland Inventory (NWI), which seeks to document all the wetlands in the United States, based primarily in aerial imagery. According to NWI data, there are 3,136 acres (4.9 square miles) of wetlands in the Lycoming Creek watershed. However, further field research is necessary to properly identify wetland boundaries, particularly in the case of ephemeral wetlands, for example, where the presence of aquatic plants help determine boundaries. All of this suggests that while there is every reason to believe the USFWS’ claim that over half of the nation’s wetlands have been lost since around the time of the Revolutionary War, it is believed the NWI discounts the total acreage.
A University of Vermont team developed another model for calculating wetlands, based primarily on, “2006-2008 leaf-off LiDAR data, 2005-2008 leaf-off orthoimagery, 2013 high-resolution land-cover data, and moderate-resolution predictive wetlands maps, incorporating topography, hydrological flow potential, and climate data.” This model calculates 6,943 wetlands acres (10.8 square miles) in the Lycoming Creek drainage, more than double the NWI’s estimated acreage.
Five trails traverse the Lycoming Creek watershed, crossing 152 miles total. This includes nearly 44 miles of the Loyalsock State Forest Cross-Country Ski Trail system south and east of the McIntyre Wild Area, suitable for hiking, biking, equestrian pursuits, and of course, cross-country skiing. The watershed also contains 33 miles of Bicycle PA Route J, which runs along Lycoming Creek from the confluence with the West Branch Susquehanna River on the southern end, all the way to the wetland border that feeds Lycoming Creek and neighboring Towanda Creek to the northeast. The watershed’s most popular trail may be the famous Old Loggers Path, a coveted backpacking route that meanders nearly 23 miles. The Hawkeye Cross-Country Ski Trail—frequented by hikers, bikers, and skiers—loops over seven miles in the northeastern corner of the watershed. Yet another watershed trail is the Lycoming Creek Bikeway, a mostly straight five-mile stretch from Hepburnville to the West Branch Susquehanna River.
Figure 3. Rock Run in Loyalsock State Forest’s McIntyre Wild Area. Photo by Ann Pinca.
Figure 4. A flyfisher casts in Lycoming Creek right beside Sheshequin Campground in Trout Run. Photo by Rebecca Johnson.
Figure 5. This wetland lies just beyond the northeastern boundary of the Lycoming Creek watershed and is similar to those feeding the headwaters of Rock Run near Devil’s Elbow Natural Area in Loyalsock State Forest. Photo by Shannon Smith.
The commercial oil and gas industry got its start in Pennsylvania in 1859 with the famous Drake Well, followed by a frenzy of drilling in the central and western portions of the state. The DEP has records of over 185,000 conventional oil and gas wells throughout the Commonwealth, and—because the industry preceded permitting requirements by almost a century—yearly estimates range between 480,000 and 760,000 conventional wells have punctured Pennsylvania’s surface. The Lycoming Creek watershed was further east than most of the conventional oil and gas pools, so it has seen very little conventional drilling. Of the 185,000 known well locations, only 25 (0.01%) are within the watershed. Of those, 11 (44%) have a status of “proposed but never materialized,” or “operator reported not drilled.” Eight wells (32%) are plugged, four (16%) have active status, one (four percent) is considered being in a regulatory inactive period, and one (four percent) is on the DEP’s orphan list—awaiting funding to be plugged properly.
The commercial oil and gas industry got its start in Pennsylvania in 1859 with the famous Drake Well, followed by a frenzy of drilling in the central and western portions of the state. The DEP has records of over 185,000 conventional oil and gas wells throughout the Commonwealth, and—because the industry preceded permitting requirements by almost a century—yearly estimates range between 480,000 and 760,000 conventional wells have punctured Pennsylvania’s surface.
The Lycoming Creek watershed was further east than most of the conventional oil and gas pools, so it has seen very little conventional drilling. Of the 185,000 known well locations, only 25 (0.01%) are within the watershed. Of those, 11 (44%) have a status of “proposed but never materialized,” or “operator reported not drilled.” Eight wells (32%) are plugged, four (16%) have active status, one (four percent) is considered being in a regulatory inactive period, and one (four percent) is on the DEP’s orphan list—awaiting funding to be plugged properly.
While drillers had long known about the Marcellus Shale, it wasn’t until 2004 that drilling in the formation became a profitable enterprise, through the combination of industrial-scale hydraulic fracturing and horizontal drilling. Soon thereafter, the Lycoming Creek watershed was no longer on the periphery of oil and gas exploration, but part of a densely drilled cluster of new unconventional wells in northeastern Pennsylvania.
The first unconventional well in the Lycoming Creek watershed was permitted by Range Resources at the Bobst Mountain Hunting Club on May 31, 2007, and drilling started less than two months later.
In the years that followed, 592 unconventional wells have been proposed for the watershed, 586 (99%) of which received permits, with 384 (65%) drilled as of June 28, 2021. Some wells had a short life, with 41 (10.6%) already plugged—a figure slightly higher than the statewide average of 8.7%. Fifteen operators have been active in the watershed.
As with the rest of Pennsylvania, the total number of drilled wells peaked in 2012, with 100 wells drilled that year. In the past seven years, the highest annual total was only one-fourth of that, with 25 wells drilled in 2019. However, these trends do not foretell an end to drilling in the region. The reduced number of wells drilled is offset by drilling each well more intensively, using five times as much water per well for hydraulic fracturing.
Gas production has flooded markets, reducing gas prices and profit margins. At the very start of the Marcellus boom in October 2005, gas prices were $13.42 per million British Thermal Units (BTUs), but have fluctuated between $1.75 and $4.00 per million BTUs in recent years. Many of the 202 wells permitted but not drilled in the watershed are located on existing well pads and can easily be drilled and brought into production as market forces dictate. For these reasons, the area is unlikely to see an end to drilling, pipeline construction, truck convoys—and all the other ancillary activities—any time soon.
Figure 6. Active fracking operation in May 2021 on ARD Operating’s COP Tract 551 A well pad, originally planned by Anadarko E&P in 2014. Photo by Ted Auch.
Figure 7. This video was taken at the same site as Figure 6, capturing ARD Operating’s well pad and the incessant noise it makes during hydraulic fracturing activities. Video footage captured by Brook Lenker.
Figure 8. Permitting, drilling, and plugging summary of unconventional wells in the Lycoming Creek watershed by year. Data through June 28, 2021.
Figure 9. Proposed unconventional wells by current operators in the Lycoming Creek watershed. Data through June 28, 2021. Note that wells that were proposed but not drilled are still associated with the original operator, which are not always still active in the watershed.
Figure 10. FracTracker’s partners at LightHawk provided aerial assistance to fly our photographer over the Lycoming Creek watershed. This video offers a glimpse at the oil and gas industry’s expansion in the watershed, juxtaposed with houses, farms, forests, wetlands, and numerous waterways. FracTracker’s Ted Auch captured still images while LightHawk pilot David Hartnichek gathered video footage, captured May 2021.
TimeSlider of Bodine Mountain
On the right, we see imagery from June 2021, with a substantial number of well pads, impoundments, compressors, pipelines, and access roads. Imagery on the left is from June 2014, with significantly less infrastructure. Users can zoom, pan, and choose different dates to explore the impacts of the industry over time.
In the Lycoming Creek watershed, unconventional wells and the well pads they operate on have been issued 634 violations between 2008 and June 28, 2021. This works out to 1.65 violations per drilled well, considerably above the statewide average of 1.3 violations per well.
Most of the violations (545, or 86%) are considered to negatively impact environmental health and safety, with the remaining 89 (14%) assessed for administrative infractions. However, the distinction between the two categories is murky at best. For example, the most common administrative violation is, “pits and tanks not constructed with sufficient capacity to contain pollutional substances,” an infraction documented 18 times in the watershed—presenting obvious hazards to health, safety, and the environment.
Altogether, there are 66 different violation codes cited within the watershed. The ten most frequent are seen in Figure 11.
For these 634 violations, the DEP has collected fines totaling $2,460,700 from four operators. Range Resources leads the way with $1,461,000 in fines, followed by Seneca Resources with $600,000, East Resources with $380,700, and Chief Oil & Gas with $19,000. For comparison, the average cost of drilling a single well in the Marcellus Shale is $8.3 million, according to 2017 financial data from a major operator in the region. At this rate, while assuming no inflation, the watershed will have to suffer 2,138 violations before the DEP’s penalties equal the cost of drilling and fracking one well.
Clearly, operators are not cowed by receiving violations, nor do they look at the occasional fine as anything more than the cost of doing business. It seems that in practice, the DEP’s regulatory role is chronicling the industry’s misdeeds, instead of protecting the environment and the people who live among the hundreds of wells in the area.
Figure 11. The ten most frequent violations for unconventional wells and well pads in the Lycoming Creek watershed through June 28, 2021.
Fracking’s aquatic impacts
The DEP maintains a statewide list of water resource sites. In the Lycoming Creek watershed, 76 out of 128 (59%) listed water resource facilities are associated with oil and gas activity, including 13 surface water withdrawal sites and 63 interconnections—large impoundments where water is collected and stored for future use. As excessive as these figures are, the state’s water resources data is incomplete. By examining aerial imagery, FracTracker found six impoundments adjacent to oil and gas operations that were not listed in the inventory. The DEP was aware of these facilities and provided data upon request. Multiacre lined impoundments can be identified from such imagery, but the inventory might be missing smaller withdrawal sites occluded from view by the tree canopy.
Overall, 259 wells reported using between 891,900 and 33,193,599 gallons of water as a base for their fracking chemical cocktail.
These numbers only represent the water consumed for hydraulic fracturing and don’t include any water used for pipeline hydrostatic testing, dust suppression on dirt and gravel roads, or any other purpose. For example, the voluminous 33,193,599 gallons used to frack Alta Resources’ Mac North B-3H well pad represents only a fraction of its permitted capacity for fracking operations.
Figure 12. A lined impoundment that does not appear on DEP’s Water Resources inventory. Photo by Karen Edelstein.
The unconventional oil and gas industry dominates water extraction, distribution, and use throughout the watershed. The amount of water used per fracked well has increased dramatically over the years, according to data from the industry’s frack fluid registry, FracFocus.
However, the registry is riddled with some obvious data inaccuracies—perhaps stemming from the fact that the registry is self-reported by the various operators.
For example, there are 272 well reports with latitude and longitude coordinates placing them inside the Lycoming Creek watershed, excluding wells where operators left the water usage field blank. There are some problematic data points with those remaining.
Five wells reported a negative number of gallons used to stimulate wells, including four from Seneca Resources’ Gamble K well pad—with quantities ranging from -214.7 million to -1.18 billion gallons of water—and one well from EXCO Resources’ Emig Unit well pad that registered -859.0 million gallons. At the other end of the spectrum, eight wells reported water consumption over 100 million gallons, including four from Rockdale Marcellus’ Cochran well pad, two from Seneca Resources’ Gamble K well pad, and two from EXCO Resources’ Emig Unit well pad.
As water consumption data of these 13 wells is obviously erroneous, they were excluded from the following analysis.
These withdrawal allowances are truly staggering.
Based on observations of consumptive use permit signs across the watershed, these water withdrawal limits are typical. Taking the 7.62 billion gallons per well pad average from Figure 15, this equates to about 716 billion gallons of permitted water consumption for the 94 well pads in the watershed that have at least one well with an active, regulatory inactive, or plugged well status. Given the average household consumes about 300 gallons of water per day—and that Pennsylvania has just over 5 million households—this volume is nearly equal to the entire residential consumption of the state for 628 days. If this is applied to each of the 125 proposed well pads, that figure rises to about 953 billion gallons, or a little less than the full capacity of Florida’s vast Lake Okeechobee.
Contamination from spills and leaks can affect more than just surface water. In 2014, 75 water wells in Lycoming County—which includes most of the Lycoming Creek watershed—were tested for various contaminants by the United States Geologic Survey (USGS). Six wells with the highest methane concentrations were further analyzed for their ratio of chloride to bromide, with half of that smaller subset showing water chemistry indicative of mixing with oilfield brine. Although the study posited that it could be mixing deep in the aquifer, it did not mention the frenzied drilling in the region at the time of sampling.
Stemming from thousands of complaints across the Marcellus Shale region, there are 378 private water supplies where DEP determined the loss of water quality or quantity was because of oil and gas activities. The public isn’t provided with the exact location of these fouled wells due to privacy concerns of impacted residents, but it is known that 18 incidents occurred in municipalities wholly or partially within the Lycoming Creek watershed.
According to Pennsylvania’s Act 13—an instrumental law governing various aspects of unconventional drilling in the state—oil and gas operators are presumed responsible for water wells negatively affected within 12 months and 2,500 feet of operations. Of course, the actual spread of a pollution plume depends on the characteristics of the aquifer itself, rather than definitions from Act 13, so it is possible that wells further than 2,500 feet from an incident could be negatively impacted—potentially years after the leak or spill occurred.
Of the 18 determination letters issued by DEP, one occurred in Fox Township in Sullivan County, six in Liberty Township in Tioga County, and two in Union Township. In Lycoming County, Eldred Township received three, Hepburn Township got one, Jackson Township received two, and McNett Township got two.
As previously mentioned, DEP also tracks violations of various state oil and gas regulations. The vast majority of incidents in the Lycoming Creek watershed resulted in an impact to surface or groundwater. Of the 634 total citations associated with unconventional wells and well pads: 41 (six percent) related to erosion and sedimentation concerns, which could harm aquatic life; 379 (60%) citations were for spills, leaks, or pollution discharges that degraded surface or groundwater; and 41 (six percent) were for other water issues. The remaining 173 (27%) violations were for various other shortcomings—most issued for improper handling of waste materials. Depending on what happened in the field to merit these violations, many of these incidents may also have had an impact on Pennsylvania’s waters.
Water is a defining characteristic for any watershed. From the expansive wetlands uphill to the brisk trout streams around Rock Run and the McIntyre Wild Area, down to the steep ravines of the Lycoming Creek, water makes this area special. In the rush to accommodate the thirsty and pollutive oil and gas industry, the state has allowed vast portions of the region to be spoiled.
Figure 13. Water consumption per well in the Lycoming Creek watershed has increased nearly five-fold in less than a decade, from 3,679,467 gallons in 2011 to 17,512,356 gallons in 2020, according to FracFocus data downloaded April 28, 2021.
Figure 14. Water consumption postings for six ARD (Alta Resources Development) well pads. Of the five visible signs, water consumption was permitted at 3 to 4 million gallons per pad, per day, for over five years. Photo by Erica Jackson.
Figure 15. The five visible signs in Figure 14 show that well pads are permitted to withdraw over 38.1 billion gallons of water, or an average of 7.62 billion gallons per well pad.
When fossil fuel companies portray fracked gas as “clean,” they better hope the public doesn’t notice the enormous stream of liquid and solid waste. In the Lycoming Creek watershed, operators reported 9,064,377 barrels (380.7 million gallons) of liquid waste and 416,248 tons of solid waste were generated in the drainage between January 2011 and April 2021. As a point of comparison, this volume of liquid waste—from 362 wells in the watershed—is equal to about 577 Olympic-sized swimming pools, or an acre of land covered in toxic waste 1,168 feet deep. In terms of solid waste, disposal of drill cuttings and other substances equals the garbage left behind after 8,672 Kenny Chesney concerts—like having about 2.3 concerts every day. This estimation is based on 330 wells reporting solid waste generation in the watershed.
When fossil fuel companies portray fracked gas as “clean,” they better hope the public doesn’t notice the enormous stream of liquid and solid waste. In the Lycoming Creek watershed, operators reported 9,064,377 barrels (380.7 million gallons) of liquid waste and 416,248 tons of solid waste were generated in the drainage between January 2011 and April 2021.
As a point of comparison, this volume of liquid waste—from 362 wells in the watershed—is equal to about 577 Olympic-sized swimming pools, or an acre of land covered in toxic waste 1,168 feet deep. In terms of solid waste, disposal of drill cuttings and other substances equals the garbage left behind after 8,672 Kenny Chesney concerts—like having about 2.3 concerts every day. This estimation is based on 330 wells reporting solid waste generation in the watershed.
Problems with oil & gas waste
To compare chemical-laden flowback fluid and radioactive brines to pool water based on volume alone does little to communicate the dangers of liquid waste—just as comparing drill cuttings and filter socks to beer cans and food wrappers is insufficient.
Oil and gas waste is much more harmful to human health and the environment than normal household refuse.
Flowback fluid includes a portion of the liquid injected into a wellbore during hydraulic fracturing. As presented in the Water section, the volume of water injected into each well averaged over 17.5 million gallons in 2020. The industry’s chemical registry site FracFocus estimates that between one-half percent and two percent of the injected volumes are composed of various chemical additives. To get an accurate estimate of the volumes of these chemicals, it is necessary to add the water volume and the non-water volume together, then calculate the above range. Unfortunately, only 18 out of the 259 wells in the watershed that provide believable water volumes also provide non-water volumes.
Approximately 25% of these chemical additives could cause cancer, according to recent studies—while others may inflict skin or respiratory damage.
What is now the Marcellus Shale formation was an ancient, shallow seabed around 384 million years ago in the Middle Devonian epoch. As this sea dried out, organic content concentrated, which would eventually be the source of hydrocarbon gasses. Other components saturated with this organic matter—including barium, benzene, chloride, radium, thallium, and more. These contaminants resurface with the oil and gas, either dissolved or suspended in fluid waste called brine. Brine will continue to rise to the surface in significant quantities during a well’s operating lifespan.
Drill cuttings comprise most of the solid waste from oil and gas sites in Pennsylvania. As with brine, these cuttings contain concentrations of the same toxic and radioactive chemicals. Whether used onsite or sent to landfills, these cuttings are problematic when precipitation causes contaminants to leach, posing risks to aquifers and surface waters. Traditionally, landfill leachate is taken to water treatment facilities. However, these facilities are ill-equipped to handle oil and gas waste and cannot effectively remove the contaminant load.
What happens to the waste?
In 2019, FracTracker analyzed and mapped the destination of Pennsylvania’s oil and gas waste from 2011 through 2018 in a project with Earthworks. Most waste stays in Pennsylvania and neighboring states, but this still requires thousands of heavy tankers travelling tens or even hundreds of miles to reach their destinations. The industry ships some waste as far as Texas, Utah, and Idaho, despite enormous transportation costs. The project underscored Pennsylvania’s incapacity to deal with this noxious and problematic waste stream.
This waste is handled in various ways, with about 54% reused at other fracking sites, 30% sent to residual waste processing facilities, and ten percent disposed in injection wells. Most of the remaining six percent is sent to surface impoundments—but it is not clear what happens to the waste from there.
For solid waste, 56% goes to landfills, 34% is reused at well pads, and eight percent goes to residual waste processing facilities—with the rest handled by other methods.
There is record of 124 waste facilities in the Lycoming Creek watershed, including 121 well pads, one landfill, one residual waste processing facility, and one temporary storage site, pending future reuse or disposal.
The Clean Earth facility—a landfill and drilling mud processing facility—has taken 157,457 tons of solid oil and gas waste and 315 barrels of liquid waste from 2013 to 2016. Between 2012 and 2013, the facility operated as Clean Streams, LLC, and accepted 10,610 additional tons of solid waste and 513,894 barrels of liquid waste. At the watershed’s northern border in Tioga County is Rockdale Marcellus’ Harer Beneficial Reuse facility. Beech Resources proposed an additional facility in currently forested land across US Highway 15 from the Clean Earth facilities.
Figure 16. Estimated chemical components of fracking fluid for the 18 wells in the Lycoming Creek watershed that provide non-water volumes. The minimum estimate is 965,434 gallons, based on 0.5% chemical concentrations, while the maximum estimate is 3,861,737 gallons, based on two percent concentrations.
Figure 17. Disposition method of liquid waste from unconventional wells in Pennsylvania in 2020, based on DEP waste reports. The total liquid waste volume was 61,832,431 barrels, or about 2.6 billion gallons.
Figure 18. Disposition of solid waste from unconventional wells in Pennsylvania in 2020. Total statewide mass was 1,397,678 tons.
Mountains of waste
As drilling continues in the Lycoming Creek watershed and nearby, enormous waste streams will continue to be a conundrum. Even reused material might contaminate the land, streams, and groundwater, and harm human health. As wells are fracked with ever-increasing volumes of fluid, they will return ever-increasing volumes of waste, requiring more and more resources to process.
To see more footage & photos from this project:
Field Day Description
On a sunny and brisk Thursday in May 2021, a group of 11 FracTracker staff members and volunteers gathered in the Lycoming watershed outside Williamsport to find and document unconventional oil and gas activities and infrastructure. This field day was in part informed by insights from members of the Responsible Drilling Alliance, a regional organization, and the knowledge and experiences of Peter Petokas, a biology and environmental science professor at Lycoming College who has explored and kept tabs on the area’s hellbender habitats for years. FracTracker’s Matt Kelso used DEP data to develop maps illustrating various infrastructure, including 384 drilled wells on 96 different pads, nine compressor and metering stations, and 67 water facilities related to oil and gas extraction—including 12 surface water withdrawal sites and 55 storage reservoirs. He then divided an area of about 272 square miles into five sections, and at least two participants explored each section. Using Matt’s maps, FracTracker’s mobile app, cameras, decibel and distance measuring apps, and other tools, the group visited and documented various infrastructure—while observing significant truck traffic and other evidence of the industry’s pervasiveness. As the groups navigated rural back roads and small state highways, many were struck by the juxtaposition of a bucolic landscape of rolling hills, green forests, and peaceful farmland with imposing, pollutive, and sometimes noisy and smelly fracking sites. Additional fieldwork was conducted with assistance from Earthworks’ staff and their FLIR technology, as well as aerial photography and videography captured by FracTracker’s Ted Auch—with flying assistance from partners at LightHawk. FracTracker then used the geolocated photos, video, and site-specific descriptions—coupled with variable datasets, research, and other literature—to compile this Story Atlas, an educational tool for concerned residents of the Lycoming Creek watershed, and an insightful resource for others living near fracking activity. The mobile app reports from this reconnaissance—and from locations across the U.S.—are visible on the FracTracker mobile app, available for download on your iOS or Android device, or by visiting the web app at https://app.fractracker.org/.
On a sunny and brisk Thursday in May 2021, a group of 11 FracTracker staff members and volunteers gathered in the Lycoming watershed outside Williamsport to find and document unconventional oil and gas activities and infrastructure.
This field day was in part informed by insights from members of the Responsible Drilling Alliance, a regional organization, and the knowledge and experiences of Peter Petokas, a biology and environmental science professor at Lycoming College who has explored and kept tabs on the area’s hellbender habitats for years.
FracTracker’s Matt Kelso used DEP data to develop maps illustrating various infrastructure, including 384 drilled wells on 96 different pads, nine compressor and metering stations, and 67 water facilities related to oil and gas extraction—including 12 surface water withdrawal sites and 55 storage reservoirs. He then divided an area of about 272 square miles into five sections, and at least two participants explored each section.
Using Matt’s maps, FracTracker’s mobile app, cameras, decibel and distance measuring apps, and other tools, the group visited and documented various infrastructure—while observing significant truck traffic and other evidence of the industry’s pervasiveness. As the groups navigated rural back roads and small state highways, many were struck by the juxtaposition of a bucolic landscape of rolling hills, green forests, and peaceful farmland with imposing, pollutive, and sometimes noisy and smelly fracking sites.
Additional fieldwork was conducted with assistance from Earthworks’ staff and their FLIR technology, as well as aerial photography and videography captured by FracTracker’s Ted Auch—with flying assistance from partners at LightHawk.
FracTracker then used the geolocated photos, video, and site-specific descriptions—coupled with variable datasets, research, and other literature—to compile this Story Atlas, an educational tool for concerned residents of the Lycoming Creek watershed, and an insightful resource for others living near fracking activity.
The mobile app reports from this reconnaissance—and from locations across the U.S.—are visible on the FracTracker mobile app, available for download on your iOS or Android device, or by visiting the web app at https://app.fractracker.org/.
Figure 19. The field day volunteers gathered before exploring the Lycoming Creek watershed. Photo by Shannon Smith, FracTracker Alliance.
Figure 20. This FLIR footage was recorded by Earthworks at NFG Midstream Trout Run LLC’s Hagerman gas processing and metering facility in Trout Run, Pennsylvania in June 2021. This recording captures visible air pollution from combustion and fugitive emissions at the facility.
Much has changed in the Lycoming watershed since unconventional oil and gas exploration ramped up over the last 15 years—in terms of ecological deterioration, as well as the deterioration of locals’ attitudes toward the industry.
At first welcomed by many as a chance for financial gain through mineral rights leasing, some community members—especially those whose families have lived in the area for generations—watched their land drastically degenerated and their sovereign land rights eclipsed by industrial encroachment they did not foresee.
Between 2011 and 2018, unconventional oil and gas drilling—notably, hydraulic fracturing—transformed sections of forest and farmland into comparatively gritty industrial zones.
“They were assured that, after the drilling phase was completed, they would hardly know the wells were there. They were also told that they had to decide quickly, and that everyone around them had already leased. A local anti-drilling advocacy group tried to warn them, but many locals distrusted environmentalists.”
As author and professor Colin Jerolmack references in his recent article for The New Republic, some landowners who willingly leased their mineral rights to oil and gas companies now view the industry’s activities with consternation. Incessant noise, traffic congestion, and foul odors have tarnished the once peaceful countryside. Even more disconcerting for property owners, the industry often operates however they please, with little consultation or consent—making some feel that they have lost their decision-making power and agency.
This disaffection potentially makes room for environmentalists to find common ground with those who embraced the industry, couched not in anti-fracking sentiments—and not necessarily in the essential need to mitigate the climate crisis—but in their shared love for the land.
Another big ecological concern in the punctured watershed centers on the fragile Eastern hellbender populations. Five conservation groups filed a lawsuit on July 1, 2021, challenging a 2019 decision to deny the amphibian protection under the Endangered Species Act.
“The hellbender is an ancient species that deserves better protections,” said Betsy Nicholas, Executive Director of Waterkeepers Chesapeake, one of the groups involved in the lawsuit. “The hellbender reminds us that we all live downstream. As the upstream tributaries are disturbed and polluted, the hellbender disappears. And the same pollution flows downstream to our populated areas, threatening the use and enjoyment of our rivers. We need to pay attention to what happens to the hellbender.”
Once widespread across 15 states, Eastern hellbenders have been eliminated from most of their historic range and continue to face many threats, including low water flow and poor water quality, increasing water pollution, deforestation, residential development, mining—and of course—oil and gas development.
Peter Petokas has been studying Eastern hellbender populations in the Lycoming watershed for 16 years. He is very concerned for the future of the species in the watershed, which holds one of the richest populations in Pennsylvania, concentrated in one of the few remaining streams with optimal water quality. Even so, a drought in 2020 left the area’s waterways with very low flows, which constrains the hellbender’s habitat and stresses the population. Because they lack protection under endangered species status, agencies may be remiss to implement enhanced regulations on discharges and withdrawals in the basin. Petokas remains hopeful that the pending lawsuit against the US Fish & Wildlife Service will restart an assessment for federal endangered/threatened species protection.
“If there’s ever a spill of anything, it’s the end, it would wipe out one of the best hellbender populations in Pennsylvania,” Petokas said.
Besides concerns about low water levels, the watershed is losing tree cover along streams to invasive insects and erosion. Riparian species like ash, sycamore, and river birches provide shade and keep the water cool enough for hellbenders to thrive.
Figure 21. A pipeline path cuts through forest in McNett Township, Lycoming County. Photo by Shannon Smith.
What does the future hold?
Figure 22. Miner’s Run, a stream in the Lycoming Creek watershed. Photo by Tim Palmer.
Thank you to all the inspiring and persistent environmental stewards who have contributed to the creation of this digital atlas:
Project funding provided by:
Clarence Moore Controversy in the Loyalsock – FracTracker Alliance
Karen Melton, Sierra Club, Fracking and a Community Turned Upside-down, June 2021
Colin Jerolmack, This Could Be the Start of a Rural Anti-Fracking Coalition, May 2021
Center for Biological Diversity, etc. lawsuit, July 2021
Middle Susquehanna Riverkeeper, Lawsuit Filed to Overturn Denial of Endangered Species Protection to Eastern Hellbenders, July 2021
[ii] Colin Jermolmack, Up to Heaven and Down to Hell. P. 261
[iii] Colin Jermolmack, Up to Heaven and Down to Hell. P. 266
[iv] Colin Jermolmack, Up to Heaven and Down to Hell. P. 258
[v] Colin Jermolmack, Up to Heaven and Down to Hell. P. 270
[vi] Colin Jermolmack, Up to Heaven and Down to Hell. P. 272
Over the past decade, New York State has seen a steep decline in the quantity of waste products from the fracking industry sent to its landfills for disposal. Explore FracTracker’s 2020 updated data.
New York State Department of Environmental Conservation (DEC) Oil and Gas Database includes records for nearly 45,000 wells in the state, nearly all of which are related to the oil and gas industry. Of these records, only 19,600 include drilling dates; some records simply reflect drilling permits that were applied for and expired, or were cancelled for other reasons. Of the records listed, 99% of those drilled are vertical, “conventional” wells.
Research by Bishop (2013) indicates that there could be more than 30,000 additional oil and gas wells that are not documented in the DEC’s database, and potentially not adequately plugged.
Over the past half-century, drilling activity in New York State has ebbed and flowed. In that period of time, drilling interest in oil and gas saw two main peaks: between 1975 and 1985, and — especially for gas — between 2004 and 2010. Gas drilling activity has currently tailed off to practically nothing since the ban on high-volume hydraulic fracturing was passed in late 2014.
In 2018 and 2019, there was a brief flurry of oil drilling, but that too has dropped off. The causes for the decline in new wells are complicated, but likely reflect a combination of reduced consumption of fossil fuels, as well as steady decreases in the price of oil and gas. Prices in the past several years are up to half what they were previously. In addition, the impact of COVID on the industry has also contributed to this decline, although other sources assert that the fossil fuel industry has benefited from the global pandemic.
In this article we’ll look specifically at spatial and temporal patterns in oil and gas drilling across New York State.
Every year, FracTracker updates the full state-wide dataset of oil, gas, and other assorted (non-drinking water) wells. To see the entire “big picture,” you can explore our interactive map below, which shows all wells in the New York State database, from prior to 1900 through late February 2021.
New York State Oil and Gas Wells
This map shows that, despite New York State banning high volume hydraulic, nearly 45,000 wells have been drilled, according to the Department of Environmental Conservation (DEC). Not all the wells in the DEC’s database were actually drilled; some were sites that were permitted, but never explored. Many have been plugged and abandoned. There may be nearly as many undocumented wells as there are in the database, given that record keeping in earlier years was nowhere near as comprehensive as it is today.
In order to turn layers on and off in the map, use the Layers dropdown menu. This tool is only available in Full Screen view. Data sources can be found in the Details section of the map as well as listed the end of this article.
View Full Screen | Updated February, 2021
FracTracker has also taken a more fine-grained approach to consider the patterns in drilling in New York State both spatially and temporally. Using the DEC wells database, we first filtered out well data for records that had actual spud (drilling) dates between 1970 and the present. Then, using pivot tables in Microsoft Excel, we graphed the data, and also looked for patterns around where the drilling was taking place.
Emergent from this process, we see the following.
Oil and gas hotspots are directly related to the underlying geology of a region. In New York State, the majority of oil wells have been drilled in the Chipmunk and Bradford Formations, followed by the Fulmer Valley, Glade, and Richburg Formations.
Oil Wells in NYS and Their Associated Geological Formations
Updated February 2021
Figure 1. Oil Wells in NYS and Their Associated Geological Formations. Gas wells have historically been most productive in the Medina Formation, followed by the Queenston, and also Trenton-Black River Formations. Data source: New York State DEC Oil and Gas Database.
Gas Wells in NYS and Their Associated Geological Formations
Updated February 2021
Figure 2. Gas wells in NYS and their associated geological formations. Data source: NYS DEC Oil and Gas Database.
Activity in drilling has exhibited distinct patterns over time, as well.
Figure 3. New oil and gas wells in New York State by year (1970-2020). Data source: New York State DEC Oil and Gas Database.
In 1982 and 1983, gas drilling in New York State surged, with 774 and 667 new wells drilled over those two years, respectively. The hot spot was in the Medina Group, which over the years, continued to be a primary focus. Well depths in this section of bedrock average around 3,400 feet at that time, although wells were exploited at a more shallow depth in subsequent years. Starting in 1995, gas was discovered in the Black River shale formation, with reservoirs more than 10,000 feet deep in some places. All of these wells were vertically oriented, but still were exploited using hydraulic fracturing technologies.
The early to mid-1980s marked a relatively high level in oil well drilling in New York State, with a peak occurring in 1984, with 153 wells drilled. After a lull of about 20 years, activity picked up again in 2005, hitting a high point in 2006 when 188 oil wells were drilled. In 2010, there was another peak with 188 wells, followed by a waning period of 4 years. Then, in 2019, interest exploded in a small area of the Bradford oil fields in Cattaraugus County, with 156 wells drilled, and an average production of 319 barrels per well over the course of that year.
According to EIA estimate from 2014, the cost of drilling an onshore oil well is between $4.9 – 8.3 million, however smaller vertical wells like those common in New York State are likely to cost more in the range of $150,000. With the price of oil at $64 a barrel in 2019, in its first year in production, the gross profit of any of these wells in New York, based on reported production, would have been between $0 and $120,000, with an average year around $20,400 per well. It’s hard to imagine how drilling for oil in recent years in New York State could have possibly been profitable, in particular with the steep drop-off in production typically seen after the first year or two.
Figure 4. Example of monthly production decline following drilling of an oil well. Data source: US Energy Information Administration
These simple examples of a localized “oil boom” in New York State provide a stark example of exactly how unsustainable these endeavors are, particularly for small drilling operators. So, despite the enthusiastic rush to oil drilling in 2019, activity after that has been followed by a quick decline, with only 41 oil wells drilled in New York State in 2020, and only 4, so far, in 2021.
Patterns in other types of wells
The increase in dry wells seems to track with the general patterns of oil and gas exploration. Hence, in periods when a lot of oil and gas wells are being drilled, there will be a higher number of wells that are dry, or nonproductive. During the 1970s, there was also a strong peak in disposal wells drilled. We are not certain whether this is, or is not, related to the high number of gas wells drilled during this period.
Figure 5. New oil and gas wells in New York State, by year (1970-2020). Data source: New York State DEC Oil and Gas Database
New York State moving towards better stewardship of legacy wells
Some of the oil and gas wells drilled in the 19th and early 20th century were particularly poorly documented (or not documented at all), and improperly plugged. This creates a public and environmental safety hazard, with more than 30,000 of these undocumented oil and gas wells spread across the state potentially leaking methane into the air and water. Finding the abandoned and orphan wells has been a long term problem because they are often located in rough terrain across central and western New York. Fortunately, the New York State Department of Environmental Conservation has taken new measures to locate and plug these legacy wells, using drone technology. FracTracker reported on a pilot initiative a few years ago that was testing this technique, but the new program is backed by $400,000 in funding from NYSERDA, the New York State Energy Research and Development Authority, in support of New York States ambitious goals to reduce greenhouse gas emissions through the Climate Leadership and Community Protection Act.
One hundred years ago, few people expressed concerns about the environmental hazards associated with oil and gas drilling. Record-keeping was spotty, which has left us with a legacy of wells whose locations are lost to memory, or simply improperly plugged. After several periods of vigorous mineral extraction activity in the 1980s and early 2000s, oil and gas drilling has declined in its profitability, and formerly easily-accessed reserves have been depleted. Today, with unprecedented interest in clean energy sources like wind, geothermal, and solar, society can become less dependent on fossil fuels, and focus on responsibly stewarding the remnants of these “dinosaurs,” using new technologies to help clean up the damages left by them.
Topics in this Article
Datasets used in this article and accompanying maps
Access to reliable data is crucial to our understanding of risky fracking waste disposal, and in turn, our ability to protect public health. But when it comes to oil and gas liquid waste disposal wells in Pennsylvania, despite monitoring by two separate agencies, we are left with an incomplete and inaccurate account.
If we were to emulate the Charles Dickens classic, this article might begin, “It was the best of datasets, it was the worst of datasets.” Unfortunately, even that would be too generous when it comes to describing available data around oil and gas liquid waste disposal wells in Pennsylvania. To fully understand the legacy and current state of these wells, it is necessary to query the two agencies that have a role in overseeing them, the United States Environmental Protection Agency (EPA) and the Pennsylvania Department of Environmental Protection (DEP).
Given the relatively small inventory of these wells compared to other oil and gas producing states, the problems with the two datasets are enormous. Before jumping into these issues, however, it would be useful to review the nature of these wells, why there are two regulatory agencies involved, and why there are so few of them in Pennsylvania in the first place, relatively speaking.
Disposal Wells Categories
To further our industrial exploits of the planet, humans have found it useful to inject all kinds of things into the earth. In the United States, this ultimately falls under the jurisdiction of EPA’s Underground Injection Control (UIC) program, and the point of injection is known as an injection well. Altogether, there are six classes of injection wells, with those related to oil and gas operations falling into Class II.
There are three categories of Class II injection wells, including waste disposal, enhanced recovery, and hydrocarbon storage. There is also an infamous exemption known as the “Haliburton Loophole,” which has allowed oil and gas companies to inject millions of gallons of hydraulic fracturing fluid into oil and gas wells in order to stimulate production without any federal oversight at all.
When most people speak of “injection wells” in an oil and gas context, they are usually referring to waste disposal wells, and this is our focus here. This well type is also referred to as Class II-D (disposal) and salt water disposal wells (SWD). This latter term is used by a majority of state regulators, so we will use that abbreviation here, even though considering this type of toxic and radioactive fluid “salt water” is surely one of the industry’s most egregious euphemisms.
Dealing with Dangerous Fluids
There are two main types of liquid waste that are disposed of at SWD injection wells. As always, these waste types have a number of different names to keep everyone on their toes but for the sake of simplicity will call them “flowback” and “brine,” and both are problematic materials to handle. Additionally, the very act of industrial-scale fluid injection presents problems in its own right.
As mentioned above, when operators pump a toxic stew of water, sand, and chemicals into a well to stimulate oil and gas production, that mixture is known as hydraulic fracturing fluid, or fracking fluid. Some of these chemicals are so secretive that even the operators of the well don’t know what is included in the mix, let alone nearby residents or first responders in the event of an incident.
Between 10% and 100% of this fluid will return to the surface, and is then known as flowback fluid, becoming a waste stream. In Pennsylvania, the average amount of fracking fluid injected into production wells exceeds 10 million gallons in recent years according to data from the industry’s self-reporting registry known as FracFocus. With more than 12,000 of these wells drilled statewide, disposing of this waste stream becomes an enormous concern.
In addition to flowback fluid, there are pockets of ancient fluids encountered by the drilling and fracking processes that return to surface as well. These solutions are commonly referred to as brine due to their extremely high salt content, although this is not the type of fluid that you’d want to baste a Thanksgiving turkey with. Total salt concentrations can reach up to 343 grams per liter, roughly ten times the salt concentration of sea water. These brines include but are not limited to the familiar sodium chloride that we use to season our food, but include other components as well, including significant bromide and radium concentrations.
When Pennsylvania experimented with our public health by authorizing disposal of these fracking brines in municipal plants designed to treat sewer sludge, the bromides in that drilling waste stream became problematic as they interacted with disinfectants to cause a cancerous class of chemicals known as trihalomethanes. This ended the practice of surface “treatment” from these sites into streams in 2011, and along the way caused many water authorities to switch from chlorine to chloramine disinfectant processes. This, in turn, may have exacerbated lead exposure issues in the region, as the water disinfected with chloramine often eats away at the calcium scale deposits covering lead pipes and solder in the region’s older homes.
Figure 1. Radium-226 Decay Chain. Source: National Institute of Standards and Technology
Marcellus and Utica wastewater are also very high in a radioactive isotope of radium known as Ra-226, which has a half-life of 1600 years. After that amount of time, half of the present radium will have emitted an alpha particle, which can cause mutations in strands of DNA when introduced inside the body, through contaminated drinking water, for example. After the hazardous expulsion of the alpha particle, the result become radon gas, which is estimated to cause 20,000 lung cancer deaths per year in the United States. Further down the decay chain is Polonium 210, which was infamously used in the assassination of Russian spy Alexander Litvinenko in London in 2006.
None of this should be injected into formations beneath people’s homes, near drinking water supplies, streams, or really anywhere that we aren’t comfortable sacrificing for the next few thousand years.
Figure 2. Earthquakes in California and Oklahoma by year. Source: United States Geological Survey
On top of all the problems with the water chemistry of both produced water and brine, the very act of injecting these fluids into the ground has triggered a large number of earthquakes in areas with frequent or large volumes of waste injection. This human-caused phenomenon is known as induced seismicity. The most well-known example of this is the previously stable state of Oklahoma which surged to have more magnitude 3.0+ earthquakes than California for a number of years during a drilling boom in that region. The largest of these was the magnitude 5.8 Pawnee earthquake in 2016.
Figure 3. PA Earthquakes and Potential Causes: 1/2000 – 2/2021, Magnitude 2.0 or Greater. Most earthquakes in the eastern portion of the state are associated with Quaternary faults. In the western portion, the causes are less straightforward, and include zipper fracking, mine blasting or collapse, and faults that are more ancient and deeper than the Quaternary faults, many of which remain unmapped. As the use of SWD wells increases, seismic activity may increase as well.
Manmade earthquakes are not limited to Oklahoma. For example, there were approximately 130 seismic events in one year period in the Youngstown, Ohio area due to SWD activity, including one measuring 4.0 on the last day of 2011. Over the years, the regulatory reaction to induced earthquakes seems to walking along the slippery slope from “that can’t happen” to “that can’t happen here” to “they’re all small earthquakes” to “we can mitigate the impact,” despite all evidence to the contrary.
So who gets to be in charge of this dumpster fire? As mentioned above, this is ultimately under the umbrella of EPA’s Underground Injection Control program. However, they have a complicated arrangement with the various states defining who has primary enforcement authority for this type of well.
In Pennsylvania, such wells must obtain a permit from EPA before obtaining a second permit from DEP. In a 2017 hearing in Plum Borough, Allegheny County, furious residents concerned with a variety of issues with a proposed SWD well were told that in Pennsylvania, EPA could only consider whether or not the well would violate the 1972 Clean Water Act when considering the permit, and that the correct audience for everything else would be DEP. Both permits for this well that is near and undear to me were ultimately issued, and operations are expected to begin in the next month if Governor Wolf does not instruct the DEP to reconsider their permit.
There is some precedent for overturning such a permit. In March of 2020, DEP yanked a permit for a SWD well in Grant Township, Indiana County, suddenly respecting a home-rule charter law that the agency had previously sued the Township over.
Without the prospect of royalties or impact fees, no community wants these wells and regulators know that they are nothing but problems. However, the reality is that the regulators oversee an industry that produces a tsunami of this toxic waste – more than 61.8 million barrels of it from unconventional wells in Pennsylvania in 2020 according to self-reported data, which is almost 2.6 billion gallons of the stuff, or slightly more than the capacity of Beaverdam Run Reservoir in Cambria County, a 382 acre lake with an average depth of 20 feet.
Nationally, injection wells are quite common, with over 740,000 such wells in the EPA inventory for 2018 and Class II (O&G) wells represent about a quarter of this figure. Of these Class II injection wells, roughly 20% are for fluid disposal, giving us an estimated 37,000 SWD wells nationwide. This number is expected to go up, as more than three-quarters of the 8,600 permits issued in 2018 were for oil and gas purposes.
However, in Pennsylvania, there have been quite few of these, compared to other states. The primary reason for this is its geology, which has largely been considered unsuitable for this type of activity. For example, a 2009 industry analysis states:
“The disposal of flowback and produced water is an evolving process in the Appalachians. The volumes of water that are being produced as flowback water are likely to require a number of options for disposal that may include municipal or industrial water treatment facilities (primarily in Pennsylvania), Class II injection wells [SWDs], and on-site recycling for use in subsequent fracturing jobs. In most shale gas plays, underground injection has historically been preferred. In the Marcellus play, this option is expected to be limited, as there are few areas where suitable injection zones are available.”
I discussed this topic in a phone call with an official from EPA, who largely confirmed this point of view, but preferred the phrase, “the geology is complicated” instead of the word “unsuitable.” When the UIC program was established from the 1974 Safe Drinking Water Act, there were only seven such wells in operation, and according to EPA’s data, there were still just 11 active SWD wells in the Commonwealth but with more on the way. I was cautioned that the geology wasn’t the only reason, however. Neighboring Ohio had hundreds of these wells, many of which are clustered close to the border with Pennsylvania. The two states have different primacy and permitting arrangements, which is a factor as well.
I have not come across sources mentioning why Pennsylvania’s geology was so unsuitable – or complicated, if we are being generous. However, there are numerous widespread issues that could be a factor, including voids created by karst and legacy coal mines, and formations that might have otherwise trapped gasses and fluids being punctured with up to 760,000 mostly unplugged oil and gas wells and more than one million drinking water wells.
Even when these fluids have been pumped deep underground, they are not necessarily out of sight and out of mind. For example, an abandoned well in Noble County Ohio suddenly began spewing gas field brine just a few weeks ago, resulting in a fish kill in a nearby stream. The incident is believed to be related to SWD wells in the general vicinity even though the closest of these is miles away from the toxic geyser. The waste fluids injected beneath the surface will exploit any pathway available through crumbling or porous rocks to alleviate the pressure built up from the injection process. These fluids don’t care whether the target is an old gas well, mine void, or drinking water aquifer.
Of course, we could ask the question in reverse, and ask what makes the injection of oil and gas fluids suitable in other locations, and the aggregated evidence would lead us to “nothing” as our answer. Nothing, other than the fact that drilling and fracking produces billions of gallons of liquid waste, and that it has to go somewhere.
Although EPA play a major role in permitting and regulating SWD wells in Pennsylvania, they do not publish data related to these wells on their website. FracTracker started hearing rumors about a spate of new SWD permits all over the state that were not accounted for in DEP data. As it turns out, many of these turned out to be other oil and gas wastewater processing facilities, and the public’s confusion about these is completely understandable because these facilities lacked the proper public notice process. These facilities are concerning in their own right – and residents of Pennsylvania should look here to see if one of these 49 facilities are in their neighborhoods – but these are not disposal wells.
To clear up the confusion, I submitted a Freedom of Information Act request to EPA for a spreadsheet of their Class II injection wells in Pennsylvania. This was apparently an onerous task that would require more than ten hours of labor on their behalf. When I mentioned that I was mostly interested in disposal wells, that sped the process up considerably.
Ultimately, I received a portion of the data fields that I had asked for.
|Well API Number||Yes|
|Class II Category (disposal, recovery, storage)||No|
|Date application received||No|
|Application status (e.g., pending, complete)||Yes|
|Application result (e.g., approved, rejected)||No|
|Application result date (date of EPA’s decision)||No|
|Well status (e.g., active, plugged)||Yes|
|Well county name||Yes|
|Well municipality name||No|
Table 1 – Summary of fields requested and received in FracTracker’s FOIA submission with EPA.
I started to compare the EPA dataset to DEP’s SWD well dataset, which is a part of its conventional well inventory. Each source had 23 records. We were off to a good start, but this data victory turned out to be limited in scope as the discrepancies between the two datasets continued to grow. Inconsistencies between the two datasets are as follows:
|County||DEP API||DEP Well Name||EPA API Match||EPA Name Match||Notes|
|Armstrong||005-21675||HARRY L DANDO 1||Y||Y|
|Beaver||007-20027||COLUMBIA GAS OF PENNA INC CGPA5||Y||Y|
|Bedford||009-20039||KENNETH A DIEHL D1||N||N||Not on EPA List|
|Cambria||021-20018||THE PEOPLES NATURAL GAS CO 4627X||N||N||Not on EPA list|
|Clearfield||033-27255||FRANK & SUSAN ZELMAN 1||N||Y||DEP / EPA API Number mismatch|
|033-27257||POVLIK 1||N||Y||No EPA API No.|
|033-00053||IRVIN A-19 FMLY FEE A 19||Y||Y|
|033-22059||SPENCER LAND CO 2||Y||Y|
|Elk||047-23835||FEE SENECA RESOURCES WARRANT 3771 38268||Y||Y|
|047-23885||FEE SENECA RESOURCES WARRANT 3771 38282||N||Y||DEP / EPA API Number mismatch|
|Erie||049-24388||NORBERT CROSS 2||Y||Y|
|049-20109||HAMMERMILL PLT 1||N||N||Not on EPA List|
|049-00013||HAMMERMILL 3||N||N||Not on EPA List|
|049-00012||HAMMERMILL 1||N||N||Not on EPA List|
|Greene||N||N||Not on DEP list. EPA Permit PAS2D210BGRE – no API to match|
|Indiana||063-31807||MARJORIE C YANITY 1025||Y||Y|
|063-20246||T H YUCKENBERG 1||Y||Y|
|Somerset||111-20059||W SHANKSVILLE SALT WATER DISP 1||Y||N|
|111-20006||MORRIS H CRITCHFIELD 1||Y||N|
|Potter||105-20473||H A HEINRICK RW-55||CA||Y||Category Anomaly – Not on DEP SWD list – does appear as Plugged OG Well (consistent w/ EPA status notes)|
|Warren||123-39874||BITTINGER 4||N||Y||API Mismatch (But does match Bittinger #1) Lat/Long match site name|
|123-33914||JOSEPH BITTINGER 1||N||Y||API Mismatch (But does match Bittinger #4) Lat matches site name, Long slightly off|
|123-33944||JOSEPH BITTINGER 2||Y||Y|
|123-33945||JOSEPH BITTINGER 3||CA||Y||Category Anomaly – Not on DEP SWD list – does appear as “Injection”|
|123-34843||SMITH/RAS UNIT 1||CA||Y||Category Anomaly – Not on DEP SWD list – does appear as “Observation”|
|123-22665||LEROY STODDARD & FRANK COFFA 1 WELL||N||N||Not on DEP list of all wells. Does appear on eFACTS. No location data|
Table 2 – Discrepancies between EPA and DEP data for SWD wells in PA.
Altogether, there was at least one data discrepancy on 17 out of 28 wells (61%) on the combined inventories, and this is allowing for significantly different formatting of the well’s name. The DEP list contained five records that were not on the EPA dataset at all, four records where the well’s API number did not match, three instances where the DEP well type was different from EPA’s listing, two wells with matching API numbers but different well names, two wells that were missing the API number on the EPA list, and one well that was on the EPA list that I have not been able to find in any of DEP’s inventories. These last two wells could not be mapped due to the lack of location data.
It isn’t always possible to know which dataset is erroneous, but the EPA list has several obvious omissions and one instance where the API number and well name are in the wrong columns. The quality of DEP data has improved over the years and appear to have some data controls in place to avoid some of these basic errors. For that reason, I suspect that most of the problems stem from the EPA dataset, and I have used DEP coordinates to map these wells.
Waste Disposal Wells in Pennsylvania
This map contains numerous layers that explore the current state of Class II-D Salt Water Disposal (SWD) injection wells for oil and gas waste in Pennsylvania. View the map “Details” tab below in the top left corner to learn more and access the data, or click on the map to explore the dynamic version of this data.
View Full Sized Map | Updated 2/21
The Take Away
In the early 1970s, it was recognized that industrial injection of oil and gas waste underground could lead to risks to human health and the environment, so several major protective laws were put in place, including the Clean Water Act of 1972, the Safe Drinking Water Act of 1974, and the Pennsylvania’s 1971 Environmental Rights Amendment. Decades later, it feels like the Pennsylvania Department of Environmental Protection and the United States Environmental Protection Agency don’t take their regulatory responsibilities very seriously when it comes to oil and gas liquid waste disposal wells. While the state does have fewer of this type of well than other states, there are five that are currently under construction, according to the EPA dataset. Many of these, like the Sedat 3A well in Allegheny County, have come after significant community opposition, and many of the residents’ concerns have not been addressed by either agency.
There will undoubtedly be more of these disposal wells proposed in the near future. Residents would do well to hassle their municipalities to update their ordinances for this type of well if they happen to live in a place where such ordinances are possible. Solicitors should be instructed to regularly scour the Pennsylvania Bulletin and be in contact with EPA for the earliest possible notification of a proposed site, so that there is time to respond within the comment periods.
Additionally, the sloppiness of the datasets calls all sorts of questions into play regarding the co-regulation of these wells. In the case of an incident, it’s not even clear that both agencies have the information on hand to even locate the site in the field. Meanwhile, a 61% error rate between the sites name, API number, and status does not inspire confidence that agencies are keeping a close eye on these facilities, to say the least.
Above all, we must all realize that it isn’t safe to assume that someone will let us know when these types of facilities are proposed. Regulators have shown us through their actions that they are thinking far more about the billions of gallons of waste that needs to be disposed of than of the well-being of dozens or even hundreds of neighbors near each toxic dump site.
References & Where to Learn More
Data supporting this article, as well as the static map in Figure 3, can be found here.
FracTracker Pennsylvania articles, maps, and imagery: https://www.fractracker.org/map/us/pennsylvania/
Topics in this Article
Since the advent of unconventional shale gas drilling, some effects have been immediate, some have emerged over time, and some are just becoming apparent. Two reports recently published by the Delaware Riverkeeper Network advance our understanding of the breadth of the impacts of fracking in Pennsylvania. The first report, written by FracTracker, reviews research on the ways fracking impacts the health of Pennsylvanians. The second report by ECONorthwest calculates the economic costs of the industry.
“Fracking is heavily impacting Pennsylvania in multiple ways but the burden is not being fairly and openly calculated. These reports reveal the health effects and economic costs of fracking and the astounding burdens people and communities are carrying,” said Maya van Rossum, the Delaware Riverkeeper.
Learn what the latest science and analysis tells us about the costs of fracking, who is paying now, and what the future price is forecasted to be.
Access the full reports here:
Health Impact Report
“Categorical Review of Health Reports on Unconventional Oil and Gas Development; Impacts in Pennsylvania,” FracTracker Alliance, 2019 Issue Paper
Economic Impact Report
“The Economic Costs of Fracking in Pennsylvania,” ECONorthwest, 2019 Issue Paper
From the Experts
“The FracTracker Alliance conducted a review of the literature studying the impact of unconventional oil and gas on health. Findings of this review show a dramatic increase in the breadth and volume of literature published since 2016, with 89% of the literature reporting that drilling proximity has human health effects. Pennsylvanian communities were the most studied sample populations with 49% of reviewed journal articles focused on Marcellus Shale development. These studies showed health impacts including cancer, infant mortality, depression, pneumonia, asthma, skin-related hospitalizations, and other general health symptoms were correlated with living near unconventional oil and gas development for Pennsylvania and other frontline communities.”
–Kyle Ferrar, FracTracker Alliance Western Program Coordinator
“Fracking wells have an extensive presence across Pennsylvania’s landscape – 20 percent of residents live within 2 miles of a well. This is close enough to cause adverse health outcomes. Collectively we found annual costs of current fracking activity over $1 billion, with cumulative costs given continued fracking activity over the next 20 years of over $50 billion in net present value for the effects that we can monetize. The regional economic benefits also seem to be less than stated, as the long-term benefits for local economies are quite low, and can disrupt more sustainable and beneficial economic trajectories that might not be available after a community has embraced fracking.”
–Mark Buckley, Senior Economist at the natural resource practice at
These reports on the health effects and economic impacts of unconventional oil and natural gas development yield disheartening results. There are risks of extremely serious health issues for families in impacted areas, and the long term economic returns for communities are negative.
Arming ourselves with knowledge is an important first step towards the renewable energy transformation that is so clearly needed. The stakes are too high to allow the oil and natural gas industries to dictate the physical, social, and economic health of Pennsylvanians.
Designating a well as “idle” is a temporary solution for operators, but comes at a great economic and environmental cost to Californians
Idle wells are oil and gas wells which are not in use for production, injection, or other purposes, but also have not been permanently sealed. During a well’s productive phase, it is pumping and producing oil and/or natural gas which profit its operators, such as Exxon, Shell, or California Resources Corporation. When the formations of underground oil pools have been drained, production of oil and gas decreases. Certain techniques such as hydraulic fracturing may be used to stimulate additional production, but at some point operators decide a well is no longer economically sound to produce oil or gas. Operators are supposed to retire the wells by filling the well-bores with cement to permanently seal the well, a process called “plugging.”
A second, impermanent option is for operators to forego plugging the well to a later date and designate the well as idle. Instead of plugging a well, operators cap the well. Capping a well is much cheaper than plugging a well and wells can be capped and left “idle” for indefinite amounts of time.
Unplugged wells can leak explosive gases into neighborhoods and leach toxic fluids into drinking waters. Plugging a well helps protect groundwater and air quality, and prevents greenhouse gasses from escaping and expediting climate change. Therefore it’s important that idle wells are plugged.
While plugging a well does not entirely eliminate all risk of groundwater contamination or leaking greenhouse gases, (read more on FracTracker’s coverage of plugged wells) it does reduce these risks. The longer wells are left idle, the higher the risk of well casing failure. Over half of California’s idle wells have been idle for more than 10 years, and about 4,700 have been idle for over 25 years. A report by the U.S. EPA noted that California does not provide the necessary regulatory oversite of idle wells to protect California’s underground sources of drinking water.
Wells are left idle for two main reasons: either the cost of plugging is prohibitive, or there may be potential for future extraction when oil and gas prices will fetch a higher profit margin. While idle wells are touted by industry as assets, they are in fact liabilities. Idle wells are often dumped to smaller or questionable operators.
Wells that have passed their production phase can also be “orphaned.” In some cases, it is possible that the owner and operator may be dead! Or, as often happens, the smaller operators go out of business with no money left over to plug their wells or resume pumping. When idle wells are orphaned from their operators, the state becomes responsible for the proper plugging and abandonment.
The cost to plug a well can be prohibitively high for small operators. If the operators (who profited from the well) don’t plug it, the costs are externalized to states, and therefore, the public. For example, the state of California plugged two wells in the Echo Park neighborhood of Los Angeles at a cost of over $1 million. The costs are much higher in urban areas than, say, the farmland and oilfields of the Central Valley.
Since 1977, California has permanently sealed about 1,400 orphan wells at a cost of $29.5 million, according to reports by the Division of Oil, Gas, and Geothermal Resources (DOGGR). That’s an average cost of about $21,000 per well, not accounting for inflation. From 2002-2018, DOGGR plugged about 600 wells at a cost of $18.6 million; an average cost of about $31,000.
Where are they?
Map of California’s Idle Wells
The map above shows the locations of idle wells in California. There are 29,515 wells listed as idle and 122,467 plugged or buried wells as of the most recent DOGGR data, downloaded 3/20/19. There are a total of 245,116 oil and gas wells in the state, including active, idle, new (permitted) or plugged.
Of the over 29,000 wells are listed as idle, only 3,088 (10.4%) reported production in 2018. Operators recovered 338,201 barrels of oil and 178,871 cubic feet of gas from them in 2018. Operators injected 1,550,436,085 gallons of water/steam into idle injection wells in 2018, and 137,908,884 cubic feet of gas.
The tables below (Tables 1-3) provide the rankings for idle well counts by operator, oil field, and county (respectively). Chevron, Aera, Shell, and California Resources Corporation have the most idle wells. The majority of the Chevron idle wells are located in the Midway Sunset Field. Well over half of all idle wells are located in Kern County.
Table 1. Idle Well Counts by Operator
|Operator Name||Idle Well Count|
|1||Chevron U.S.A. Inc.||6,292|
|2||Aera Energy LLC||5,811|
|3||California Resources Production Corporation||3,708|
|4||California Resources Elk Hills, LLC||2,016|
|5||Berry Petroleum Company, LLC||1,129|
|6||E & B Natural Resources Management Corporation||991|
|7||Sentinel Peak Resources California LLC||842|
|8||HVI Cat Canyon, Inc.||534|
|9||Seneca Resources Company, LLC||349|
|10||Crimson Resource Management Corp.||333|
Table 2. Idle Well Counts by Oil Field
|Oil Field||Count by Field|
Table 3. Idle Well Counts by County
|County||Count by County|
|9||San Luis Obispo||202|
According to the Western States Petroleum Association (WSPA) the count of idle wells in California has increased from just over 20,000 idle wells in 2015 to nearly 30,000 wells in 2018! That’s an increase of nearly 50% in just 3 years!
Nobody knows how many orphaned wells are actually out there, beneath homes, in forests, or in the fields of farmers. The U.S. EPA estimates that there are more than 1 million of them across the country, most of them undocumented. In California, DOGGR officially reports that there are 885 orphaned wells in the state.
A U.S. EPA report on idle wells published in 2011 warned that existing monitoring requirements of idle wells in California was “not consistent with adequate protection” of underground sources of drinking water. Idle wells may have leaks and damage that go unnoticed for years, according to an assessment by the state Department of Conservation (DOC). The California Council on Science and Technology is actively researching this and many other issues associated with idle and orphaned wells. The published report will include policy recommendations considering the determined risks. The report will determine the following:
- State liability for the plugging and abandoning of deserted and orphaned wells and decommissioning facilities attendant to such wells
- Assessment of costs associated with plugging and abandoning deserted and orphaned wells and decommissioning facilities attendant to such wells
- Exploration of mechanisms to ameliorate plugging, abandoning, and decommissioning burdens on the state, including examples from other regions and questions for policy makers to consider based on state policies
As of 2018, new CA legislation is in effect to incentivize operators to properly plug and abandon their stocks of idle wells. In California, idle wells are defined as wells that have not had a 6-month continuous period of production over a 2-year period (previously a 5-year period). The new regulations require operators to pay idle well fees. The fees also contribute towards the plugging and proper abandonment of California’s existing stock of orphaned wells. The new fees are meant to act as bonds to cover the cost of plugging wells, but the fees are far too low:
- $150 for each well that has been idle for 3 years or longer, but less than 8 years
- $300 for each well that has been idle for 8 years or longer, but less than 15 years
- $750 for each well that has been idle for 15 years or longer, but less than 20 years
- $1,500 for each well that has been idle for 20 years or longer
Operators are also allowed to forego idle well fees if they institute long-term idle well management and elimination plans. These management plans require operators to plug a certain number of idle wells each year.
In February 2019, State Assembly member Chris Holden introduced an idle oil well emissions reporting bill. Assembly bill 1328 requires operators to monitor idle and abandoned wells for leaks. Operators are also required to report hydrocarbon emission leaks discovered during the well plugging process. The collected results will then be reported publicly by the CA Department of Conservation. According to Holden, “Assembly Bill 1328 will help solve a critical knowledge gap associated with aging oil and gas infrastructure in California.”
While the majority of idle wells are located in Kern County, many are also located in California’s South Coast region. Due to the long history and high density of wells in the Los Angeles, the city has additional regulations. City rules indicate that oil wells left idle for over one year must be shut down or reactivated within a month after the city fire chief tells them to do so.
Who is responsible?
All of California’s wells, from Kern County to three miles offshore, on private and public lands, are managed by DOGGR, a division of the state’s Department of Conservation. Responsibilities include establishing and enforcing the requirements and procedures for permitting wells, managing drilling and production, and at the end of a well’s lifecycle, plugging and “abandoning” it.
To help ensure operator liability for the entire lifetime of a well, bonds or well fees are required in most states. In 2018, California updated the bonding requirements for newly permitted oil and gas wells. These fees are in addition to the aforementioned idle well fees. Operators have the option of paying a blanket bond or a bond amount per well. In 2018, these fees raised $4.3 million.
Individual well fees:
- Wells less than 10,000 feet deep: $10,000
- Wells more than 10,000 feet deep: $25,000
- Less than 50 wells: $200,000
- 50 to 500 wells: $400,000
- 500 to 10,000 wells: $2,000,000
- Over 10,000 wells: $3,000,000
With an average cost of at least $31,000 to plug a well, California’s new bonding requirements are still insufficient. Neither the updated individual nor blanket fees provide even half the cost required to plug a typical well.
Strategies for the managed decline of the fossil fuel industry are necessary to make the proposal a reality. Requiring the industry operators to shut down, plug and properly abandon wells is a step in the right direction, but California’s new bonding and idle well fees are far too low to cover the cost of orphan wells or to encourage the plugging of idle wells. Additionally, it must be stated that even properly abandoned wells have a legacy of causing groundwater contamination and leaking greenhouse gases such as methane and other toxic VOCs into the atmosphere.
By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance
Cover photo: Kerry Klein, Valley Public Radio
With the new year underway, it’s an opportune moment to reflect on the state of unconventional oil and gas extraction in Pennsylvania and examine a few of the drilling trends. A logical place to start is looking at the new wells drilled in 2018.
As always, but perhaps even more so than in previous years, unconventional drilling in Pennsylvania is a tale of two shale plays, with hotspots in the southwestern and northeastern corners of the state. The northeastern hotspot seems to be extending westward, including 25 new wells in Jones Township in Elk County (an area shown in dark red near the “St Marys” label on the map). In the southwestern hotspot, the industry continues to encircle Allegheny County, closing in on the City of Pittsburgh like a constrictor.
Data error? As Pittsburgh-area residents reflect on the past year, some of them must be wondering why a new well pad in Indiana Township, just northeast of the city isn’t shown on the map above. The answer is that the data the Department of Environmental Protection (DEP) has for these wells indicate they were drilled November 29-3o, 2017, although we believe this to be incorrect. FracTracker obtained the data from the Spud Report on January 2, 2019, which indicates seven wells spudded in that two day span on the “Miller Jr. 10602” well pad. This activity drew considerable opposition from families in the Fox Chapel School district in May of 2018, and was therefore widely reported on by the media. An article published on WESA indicates an expected drill date of July 2018, for example.
It turns out the new year is also a good time to remember that our understanding of the oil and gas industry around us is shaped, molded, and limited by the availability and quality of the data. We brought the Indiana Township data error to the attention of DEP, which only confirmed that the operator (Range Resources) entered the spud dates into the DEP’s online system. Perhaps these well were drilled in November of 2018 not 2017? There is even a possibility these wells have yet to be drilled.
Here are a few more dissections of the data, such as it is:
Wells Drilled Over Time
Barring more widespread data issues, the status of a handful of wells in Indiana Township does not have much of an impact on the overall trend of drilling in the state. There were 779 wells on the report, representing just under 40% of the total from the peak year of 2011, when industry drilled 1,958 wells. The year 2019 was the fourth year in a row where the industry failed to drill 1,000 wells, averaging 719 per year over that span. In contrast, the five years between 2010 and 2014 saw an average of 1,497 wells per year, more than twice the more recent average. As mentioned in our Hazy Future report, projections based on very aggressive drilling patterns are already proving to be out of phase with reality, although petrochemical commodity markets might change drastically in the coming decades.
How long before wells are plugged?
We also like to periodically check to see how long these wells stay in service. In Pennsylvania, there are two relevant well statuses worth following: plugged and regulatory inactive. While there are a number of conditions that characterize regulatory inactive wells, they are essentially drilled wells that are not currently in production, but may have “future utility.” Therefore, the wells are not required to be permanently plugged at this time.
In order to understand some of the finer points, it’s best to use Figure 1 (above) in conjunction with Figure 2. We can see that most of the wells drilled in the initial years of the Marcellus boom have already been plugged, although Figure 1 shows us that the sample size is fairly low for these years. In 2005, for example, 7 of the 9 (78%) unconventional wells drilled in the state that year are already plugged. The following year, 24 of the 37 (65%) wells drilled are now plugged, and an additional 4 (11%) wells have a regulatory inactive status as of the end of 2018. The following year, the combined plugged and inactive wells account for just over 50% of the 113 wells drilled that year, and this trend continues along a fairly predictable curve. An exception is the noticeable bump around the most active drilling years of 2010 and 2011, where there are slightly more wells with a plugged or inactive status than might be expected. It is interesting to note that even the most recent wells are not immune to being plugged, including 8 plugged wells and 4 inactive wells drilled in 2018 that were not able to get past their very first year in production.
Overall, of the 11,675 drilled wells accounted for on this graphic, 851 (7%) are plugged already, with an additional 572 (5%) of wells with an inactive status. Unconventional wells that are 11 years old have a roughly 50% chance of being plugged or inactive, and we would therefore expect to see the number of these wells skyrocket in the coming years before leveling off, roughly mirroring the drilling boom and subsequent slowdown of Marcellus Shale extraction in Pennsylvania.
Many factors contribute to fluctuations in drilling trends for the Marcellus Shale and other unconventional wells in Pennsylvania. Very cold winters result in high consumption by residential and commercial users. New gas-fired power plants can increase the demand for additional drilling. Recessions and economic conditions are known to reduce the demand for energy as well, and drillers’ heavy debt burdens can slow down operations appreciably. Additionally, other fossil fuel and renewable energy sources compete with one another, altering the market conditions even further. And finally, every oil and gas play eventually reaches a point where the expected results from new wells are not worth the money required to get the hydrocarbons to the surface, and unconventional wells are much more expensive to develop than more traditional operations.
Because of all of these variables, month to month or even year to year fluctuations are not necessarily that telling. On the other hand, a four-year period where drilling is roughly half of previous extraction is significant, and can’t be easily dismissed as a blip in the data.
By Matt Kelso, Manager of Data and Technology, FracTracker Alliance