2021 Production from Pennsylvania’s Oil and Gas Wells
FracTracker has released an analysis of Pennsylvania’s 2021 oil and gas production totals and the impacts of orphaned and abandoned wells.
Data driven discussions about gas extraction and related topics.
FracTracker has released an analysis of Pennsylvania’s 2021 oil and gas production totals and the impacts of orphaned and abandoned wells.
FracTracker’s new Pennsylvania oil and gas well map displays conventional and unconventional wells and violations as of January 12, 2022.
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.
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.
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.
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.
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
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.
NYS gas wells, 19 February 2021
NYS oil wells, 19 February 2021
NYS monitoring wells, 19 February 2021
NYS dry holes, 19 February 2021
NYS disposal wells_19 February 2021
NYS storage wells, 19 February 2021
NYS brine wells, 19 February 2021
NYS other wells_19 February 2021
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.
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.
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.
Asked For | Received |
Well Name | Yes |
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 |
Well latitude | Yes |
Well longitude | Yes |
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 |
Allegheny | 003-21223 | SEDAT 3A | Y | Y | |
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) |
Venango | 121-44484 | LATSHAW 9 | Y | Y | |
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.
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
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.
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/
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.
“Categorical Review of Health Reports on Unconventional Oil and Gas Development; Impacts in Pennsylvania,” FracTracker Alliance, 2019 Issue Paper
“The Economic Costs of Fracking in Pennsylvania,” ECONorthwest, 2019 Issue Paper
“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
ECONorthwest
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.
View map fullscreen | How FracTracker maps work
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.
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 |
Oil Field | Count by Field | |
1 | Midway-Sunset | 5,333 |
2 | Unspecified | 2,385 |
3 | Kern River | 2,217 |
4 | Belridge, South | 2,075 |
5 | Coalinga | 1,729 |
6 | Elk Hills | 958 |
7 | Buena Vista | 887 |
8 | Lost Hills | 731 |
9 | Cymric | 721 |
10 | Cat Canyon | 661 |
County | Count by County | |
1 | Kern | 17,276 |
2 | Los Angeles | 3,217 |
3 | Fresno | 2,296 |
4 | Ventura | 2,022 |
5 | Santa Barbara | 1,336 |
6 | Orange | 752 |
7 | Monterey | 399 |
8 | Kings | 212 |
9 | San Luis Obispo | 202 |
10 | Sutter | 191 |
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:
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:
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.
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:
Blanket fees:
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:
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.
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
In recent years, Pennsylvanians have had to endure numerous massive pipeline projects in the Commonwealth. Some of these, such as the Mariner East 2, the Revolution, and the Atlantic Sunrise, have been beset with continuous problems. In fact, both the Mariner East 2 and the Revolution projects had their operations suspended in 2018. The operators have struggled to grapple with a variety of issues – ranging from sinkholes near houses, erosion and sediment issues, hundreds of bentonite spills into the waters and upland areas of Pennsylvania, and more.
Part of the reason for the recent spate of incidents is the fact that so many pipelines are being built right now. These lines are traversing through undermined areas and land known to have underground karst formations, which are prone to subsidence and sinkholes. With more than 90,000 miles of pipelines and 84,000 miles of streams in Pennsylvania, substantial erosion and runoff issues are unfortunately quite common.
Map of pipeline routes in southwestern PA, various pipeline incidents, and karst formations:
Many residents have been trying to document issues in their region of Pennsylvania for a long time. Any pipeline incident should be reported to the Department of Environmental Protection (DEP), but in some instances, people want other residents to know and see what is going on, and submission to DEP does not allow for that. FracTracker’s Mobile App allow users to submit a detailed report, including photographs, which are shared with the public. App users have submitted more than 50 photographs of pipelines in Pennsylvania, including these images below.
The FracTracker Mobile App uses crowd-sourced data to document and map a notoriously nontransparent industry. App users can also report violations, spills, or whatever they find striking. For example, the first image shows construction of the Mariner East 2 in extreme proximity to high density housing. While regulators did approve this construction, and it is therefore not a violation, the app user wanted others to see the impact to nearby residents. Other photos do show incidents, such as the second photo on the second row, showing the sinkhole that appeared along the Mariner East 1 during the construction of the nearby Mariner East 2 pipeline.
Please note that app submissions are not currently shared with DEP, so if you happen to submit an incident on our app that you think they should know about, please contact their office, as well. The FracTracker Mobile App provides latitude and longitude coordinates to make it easier for regulators to find the issue in question.
Drillers in Pennsylvania’s Marcellus Shale and other unconventional formations predicted that they would find a lot of natural gas, and they have been right about that. However, the large resulting supply of natural gas from this industrial-scaled drilling is more than the region can use. As a result, gas prices remain low, making drilling unprofitable in many cases, or keep profit margins very low in others.
The industry’s solution to this has been two-pronged. First, there is a massive effort underway to export the gas to other markets. Although there are already more than 2.5 million miles of natural gas pipelines in the United States, or more than 10 times the distance from the Earth to the Moon, it was apparently an insufficient network to achieve the desired outcome in commodity prices. The long list of recent and proposed pipeline projects, complete with information about their status, can be downloaded from the Energy Information Administration (Excel format).
The industry’s other grand effort is to create demand for natural gas liquids (NGLs, mostly ethane, propane, and butane) that accompanies the methane produced in the southwestern portion of the state. The centerpiece of this plan is the construction of multiple ethane crackers, such as the one currently being built in Beaver County by Royal Dutch Shell, for the creation of a new plastics industry in northern Appalachia. These sites will be massive consumers of NGLs which will have to be piped in through pressurized hazardous liquid routes, and would presumably serve to lock in production of unconventional gas in the region for decades to come.
In 2010, the Pipeline and Hazardous Materials Safety Administration (PHMSA) led the formation of an advisory group called Pipelines and Informed Planning Alliance (PIPA), comprised mostly of industry and various state and local officials. Appendix D of their report includes a long list of activities that should not occur in pipeline rights-of-way, from all-terrain vehicle use to orchards to water wells. These activities could impact the structural integrity of the pipeline or impede the operator’s ability to promptly respond to an incident and excavate the pipe.
However, we find this list to be decidedly one-directional. While the document states that these activities should be restricted in the vicinity of pipelines, it does not infer that pipelines shouldn’t be constructed where the activities already occur:
This table should not be interpreted as guidance for the construction of new pipelines amongst existing land uses as they may require different considerations or limitations. Managing land use activities is a challenge for all stakeholders. Land use activities can contribute to the occurrence of a transmission pipeline incident and expose those working or living near a transmission pipeline to harm should an incident occur.
While we understand the need to be flexible, and we certainly agree that every measure should be taken by those engaging in the dozens of use types listed in the PIPA report, it equally makes sense for the midstream industry to take its own advice, and refrain from building pipelines where these other land uses are already in place, as well. If a carport is disallowed because, “Access for transmission pipeline maintenance, inspection, and repair activities preclude this use,” then what possible excuse can there be to building pipelines adjacent to homes?
It turns out that it depends pretty dramatically on the diameter and pressure of the pipe, as well as the nature of the hydrocarbon being transported. A 2000 report estimates that it could be as little as a 150-foot radius for low-pressure 6-inch pipes carrying methane, whereas a 42-inch pipe at 1,400 pounds per square inch (psi) could be a threat to structures more than 1,000 feet away on either side of the pipeline. There is no way that the general public, or even local officials, could know the hazard zone for something so variable.
While contacting Pennsylvania One Call before any excavation is required, many people may not consider a large portion of the other use cases outlined in the PIPA document to be a risk, and therefore may not know to contact One Call. To that end, we think that hazard placards would be useful, not just at the placement of the pipeline itself, but along its calculated hazard zone, so that residents are aware of the underlying risks.
If there is an incident, it is obviously critical for operators to be able to respond as quickly as possible. In most cases, a part of this process will be shutting off the flow at the nearest upstream valve, thereby stopping the flow of the hydrocarbons to the atmosphere in the case of a leak, and cutting the source of fuel in the event of a fire. Speed is only one factor in ameliorating the problem, however, with the spacing between shutoff valves being another important component.
Comprehensive datasets on pipeline valves are difficult to come by, but in FracTracker’s deep dive into the Falcon ethane pipeline project, which is proposed to supply the Shell ethane cracker facility under construction Beaver County, we see that there are 18 shutoff valves planned for the 97.5 mile route, or one per every 5.4 miles of pipe. We also know that the Falcon will operate at a maximum pressure of 1,440 psi, and has pipe diameters ranging from 10 to 16 inches. The amount of ethane that could escape is considerable, even if Shell were able to shut the flow off at the valve instantly. It stands to reason that more shutoff valves would serve to lessen the impact of releases or the severity of fires and explosions, by reducing the flow of fuel to impacted area.
Groups promoting the oil and gas industry like to speak of natural gas development as clean and safe, but unless we are comparing the industry to something else that is dirtier or more dangerous, these words are really just used to provoke an emotional response. Even governmental agencies like PHMSA are using the rhetoric.
PHMSA’s mission is to protect people and the environment by advancing the safe transportation of energy and other hazardous materials that are essential to our daily lives.
If the safe transportation of hazardous materials sounds oxymoronic, it should. Oil and gas, and related processed hydrocarbons, are inherently dangerous and polluting.
Report | Events | Fatalities | Injuries | Explosions | Evacuees | Total Damages |
Gas Distribution | 29 | 8 | 19 | 12 | 778 | $6,769,061 |
Gas Transmission / Gathering | 30 | 0 | 2 | 2 | 292 | $51,048,027 |
Hazardous Liquids | 49 | 0 | 0 | 1 | 48 | $9,115,036 |
Grand Total | 108 | 8 | 21 | 15 | 1,118 | $66,932,124 |
Impacts of pipeline incidents in Pennsylvania from January 1, 2010 through July 13, 2018. National totals for the same time include 5,308 incidents resulting 125 fatalities, 550 injuries, 283 explosions, and nearly $4 billion in property damage.
Current investments in large-scale transmission pipelines and those facilitating massive petrochemical facilities like ethane crackers are designed to lock Pennsylvania into decades of exposure to this hazardous industry, which will not only adversely the environment and the people who live here, but keep us stuck on old technology. Innovations in renewable energy such as solar and wind will continue, and Pennsylvania’s impressive research and manufacturing capacity could make us well positioned to be a leader of that energy transformation. But Pennsylvania needs to make that decision, and cease being champions of an industry that is hurting us.
By Matt Kelso, Manager of Data and Technology
This is the second article in a two-part series. Explore the first article: PA Pipelines and Pollution Events.