Data driven discussions about gas extraction and related topics.

Who Pays? Health and Economic Impacts of Fracking in 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.

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

 

Rig and house. Westwood Lake Park. Photo by J Williams, 2013.

“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.

https://www.kvpr.org/post/dormant-risky-new-state-law-aims-prevent-problems-idle-oil-and-gas-wells

Idle Wells are a Major Risk

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.

Well plugging

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.

Orphaned wells

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


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.

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
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

 

Table 3. Idle Well Counts by County
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

 

Risks

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

Current regulation

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

Blanket fees:

  • 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.

Conclusions

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

Pennsylvania Drilling Trends in 2018

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.

Screen shot showing spud report for Indiana Township, Allegheny County from 1/1/2017 through 1/4/2019. We suspect these spud dates of 11/29/17 and 11/30/17 are incorrect.

Screen shot showing spud report for Indiana Township, Allegheny County from 1/1/2017 through 1/4/2019. We suspect these spud dates of 11/29/17 and 11/30/17 are incorrect.

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:

Graph of unconventional (fracking) wells drilled in PA, YTD - Drilling trends

Figure 1: Unconventional wells drilled in PA by year: 2005 to 2018

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.

Unconventional wells drilled since 2005 in PA - Drilling trends

Figure 2: This chart shows the percentage of unconventional wells drilled since 2005 with a plugged or regulatory inactive status as of December 31, 2018.

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.

Conclusions

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

Clearing land for shale gas pipeline in PA

Rapid Pipeline Development Affecting Pennsylvanians

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:

Click here to learn more about recent pipeline incidents in Pennsylvania, along with how users of the FracTracker App have helped to chronicle problems associated with them.

Residents keeping track

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.

Why have there been so many problems with pipelines in recent years? 

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.

Are regulators doing enough to help prevent these pipeline development problems?

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.

Pipeline being constructed near a home

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?

What distance is far enough away to escape catastrophic failure in the event of a pipeline fire or blast?

This chart shows varying hazard distances from natural gas pipelines, based on the pipe’s diameter and pressure. Source:  Mark J. Stephens, A Model for Sizing High Consequence Areas Associated with Natural Gas Pipelines

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.

Valve spacing

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.

Conclusion

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.

Virtual Pipelines - Potential Routes to Cayuga

Virtual pipelines: Convenient for Industry, a Burden on Communities

As the natural gas industry faces harsher and more widespread critiques from environmentalists and citizens, pipeline projects are facing delays, fines, and defeat. Aside from the questionable economics behind transporting gas and oil by pipeline, there are broad economic risks associated with pipeline accidents. With an increasing list of pipeline-related accidents in the public eye, including the two this past summer in Texas and Kansas, blasts this fall in Beaver County, PA, and in Boston, MA, scrutiny of new pipeline projects is on the uptick.

That being said, what is the alternative?

Virtual Pipelines?

Virtual Pipeline - Oil and gas truck

Loaded CNG transport vehicle

Industry, not deterred by resistance from regulators and environmentalists, has developed a new work-around method to get their product to market. Rather than build pipelines across rugged, remote, or highly-populated terrain, a new “solution” called “virtual pipelines” has come on the scene, with roots in New England in 2011.

The term “virtual pipeline,” itself, is so new that it is trademarked by Xpress Natural Gas (XNG), Boston, MA. XNG and other virtual pipeline companies use specially-designed tanker trucks to move compressed natural gas (CNG) or liquefied natural gas (LNG) via our public roads and highways. CNG in this system is under very high pressure — up to 3,600 psi when tank trailers are full. Rail and barge shipments are also considered part of the system, and trailers are designed to be easily loaded onto train cars or boats.

For the gas industry, virtual pipelines can be used in locales where gas is only needed for a limited time period, the pipeline network is not developed, or opposition by landowners is too contentious to make eminent domain an option, among other issues. These virtual pipeline trucks are identifiable by the hazard .1 placard they carry: 1971, indicative of flammable, compressed natural gas or methane.

Restricted only by permissible weight limits on roads (up to 80,000 pounds or more), 5-axle trucks may make in excess of 100 round trips a day from the fueling location to their destination — sometimes hundreds of miles away. These trucks, which may travel alone or in caravans, are identifiable by the hazard class 2.1 placard they carry: 1971, indicative of flammable, compressed natural gas or methane. Manufacturers of these virtual pipeline rigs tout the safety considerations that go into their engineered design. These considerations include special pressure monitoring for the dozens of tanks and super-strength materials to protect against ruptures.

Specialized equipment has been created to load compressed gas tanks into the trailers that will carry them to their destinations. Here’s a promotional video from Quantum:

Loading CNG into specialized trailers for transport

Impacts on Communities

Following New York State’s rejection of the Constitution Pipeline in 2016 based on water quality concerns, industry has been looking for ways to move natural gas from Pennsylvania’s Marcellus gas fields to the Iroquois Pipeline. The current strategy is to load the gas in canisters from a special compressor facility, and re-inject the gas to a pipeline at the journey’s endpoint. The extent to which virtual pipelines may be utilized in New York State and New England is not well known, but the natural gas industry does speak in sanguine terms about this strategy as a solution to many of its transportation issues.

Citizen blogger/activist Bill Huston has compiled a list accidents that have occurred with CNG transport trucks along the virtual pipeline that runs from a “mother station” at Forest Lake, PA to Manheim, NY, near the Iroquois pipeline. While there have been no explosions or loss of life as a result of these accidents, there are a number of reported incidents of trucks tipping or rolling over, sliding off the road, or spontaneously venting.

To move CNG from “Point A” to “Point B,” truck traffic through populated areas is unavoidable. In central New York, public outcry about virtual pipelines is rising, due in large part to the safety issues associated with increased truck traffic on state highways. In rural New York, state highways run through towns, villages, and cities. They are not separated from population centers in the way that interstate highways typically are. Traffic from CNG transport trucks clogs roadways, in some cases burdening the pass-through communities with 100 or more tractor trailers a day. Routes pass directly in front of schools and health care facilities.

In short, virtual pipelines present a public safety hazard that has yet to be addressed.

Virtual Pipelines and the Cayuga Power Plant 

In Lansing, NY, there is an inefficient and economically-beleaguered power plant, currently run on coal, that the power utility would prefer to see shut down. The Cayuga Power Plant was cited in 2016 for exceeding mercury emissions by nearly 2000%. Its inherently inefficient design makes it a significant greenhouse gas contributor. Years ago, it provided considerable tax benefits to its host community of Lansing, and as such has some lingering support. After both a devastating fire in one stack and mechanical failure in another, the plant has been barely running for the past 3 or 4 years. It is currently used as a “peaker plant“, operating only during periods of excessive demand on the electric grid, during summer months.

New York State’s Governor, Andrew Cuomo, has stated that all coal-power plants will be shut down by 2020.

Cayuga Power Plant in Lansing, NY.

Nonetheless, the plant owners are pushing to re-power the Cayuga Power Plant with natural gas. Currently, however, there is no pipeline to deliver the gas to the plant.  Without support by the public nor the Public Service Commission for the construction of a supply pipeline, Cayuga Power Plant has revealed they plan to receive gas deliveries via truck.

Scenario Maps

FracTracker has modeled the five most likely scenarios that would take compressed natural gas from a loading station in northern Pennsylvania to the Cayuga Power Plant in Lansing. All of the scenarios bring the trucks through populated communities, in dangerous proximity to high-risk facilities where both human safety and evacuations are problematic. The routes also pass through intersections and road stretches that have some of the highest accident rates in the area.

Route 1: This route passes within a half mile of homes of 36,669 people in the Villages of Lansing, Candor, Spencer, Owego; Towns of Ithaca, Lansing, Newfield, Danby, Candor, Spencer, Tioga, Owego, Vestal; and the City of Ithaca. Within the half-mile evacuation zone of this route, should there be an accident, are:

  • 17 health care facilities
  • 20 day care centers
  • 4 private school
  • 21 public schools

Click on the tabs in the box above to explore the five potential truck routes with maps.

Interactive Map

For a full interactive map of the potential routes for CNG delivery to the Cayuga Power Plant, and the schools, health care facilities, etc. within a half-mile evacuation zone of the routes, view the interactive map below.

View map fullscreen | How FracTracker maps work

A Call for Alternative Energy

Despite the apparent convenience that virtual pipelines present for the fossil fuel industry, they are not the solution the future energy supply needs. Yes, they present an alternative to pipeline transportation — but they also play a disastrous role in continuing our descent into climate chaos caused by increasing greenhouse gas concentrations in the atmosphere.

Methane leakage is an unavoidable component of the entire life cycle of natural gas usage — from “cradle to grave” — or more precisely, from the moment a well is drilled to when the gas is combusted by its end-user. And methane, as a greenhouse gas, is up to 100 times more potent than carbon dioxide. The Intergovernmental Panel on Climate Change’s (IPCC) recent report (see summary here) is unflinching in its clarion call for immediate, and extreme, cut-backs in greenhouse gas production. If we choose not to heed this call, much of humanity’s future survival is called into question.


By Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance

More of the details about the Cayuga Power Plant will be explained in the upcoming weeks in a related guest blog by environmental activist and organizer, Irene Weiser, of Tompkins County, NY.

 

 

PA Well Pad Violations map

Well Pad Violations in Pennsylvania

Emerging Trends

We are always learning new things at FracTracker. While we have been analyzing and mapping oil and gas (O&G) violations issued by the Department of Environmental Protection (DEP) in Pennsylvania since 2010, we have apparently been under-representing the total amount of issues associated with unconventional drilling in the state.

The reason for the missing violations is that there are inconsistencies with how well pads are classified in the compliance report. Many of these well pads – full of unconventional permits and drilled wells – are indeed categorized as “unconventional” in the DEP compliance data. Others, equally full of unconventional permits and wells, simply leave that field blank.

Therefore, any analysis for unconventional violations is likely to miss some of the incidents that are attributed to the well pad itself, as opposed to any of the wells that are found upon that well pad.

Midas Well Pad unearths issue

While we have heard about missing violation data in the past, I discovered the nature of the issue while researching the Midas Well Pad in Plum Borough, Allegheny County on the DEP resource site eFACTS, noting the presence of multiple violations at the nascent well site. However, when attempting to download the relevant data on the compliance report, the results were missing. I had entered search parameters that made sense to me, limiting results to violations in the proper county and municipality, and including an inspection date range that was broader than what was showing up on eFACTS. I had also limited results to unconventional wells, because while this is Plum’s first unconventional well pad, the back roads are dotted with dozens – if not hundreds – of conventional O&G sites.

The Midas Well Pad, as seem from Coxcomb Hill Rd. in Plum, PA

After that attempt failed, I downloaded the entire state’s worth of data, whether conventional or not, and I was able to find the 31 violations associated with the well pad.

I contacted DEP about this, wondering whether there was some data irregularity that prevented my search in Plum from finding all of the incidents that occurred there. The reply was somewhat helpful, noting that there was no county, municipality, or unconventional value associated with that well pad in the compliance report, explaining why the search result came up negative.

It is worth noting that the separate well pad report does indeed have values for all of these fields for the Midas Well Pad, so there is a lack of consistency on this issue. Even more importantly, it is worth remembering that any compliance report search that limits results using county, municipality, or unconventional variables are likely to result in incomplete results.

The violations at the Midas Well Pad are focused around erosion and sedimentation issues, wetland impacts, failure to follow approved methodology, and failure to fix some of the problems on subsequent site inspections. The compliance report includes a narrative inspection comment, giving the public a glimpse through the inspector’s eyes. Here is one of several such comments at the site:

Follow up inspection related to wetland impact reported on 2/23/18 and 2/24/18. At the time of inspection, the Operator was actively conducting earth disturbance activity associated with the construction of well pad channel 6. The Department gave verbal permission on 2/27/2018 to deviate from the construction sequence and continue with the construction of PCSM wet pond 1. At the time of inspection wet pond 1 was partially constructed. The outlet structure and emergency spillway associated with wet pond 1. At the time of inspection wet pond 1 was holding water, however the slopes were not temporary stabilized. The Operator indicated that additional work was planned for the wet pond and would be temporary stabilized. The Operator indicated a previously unidentified seep located upgradient and outside of the LOD is contributing additional water to wet pond 1. The Department recommended the Operator identify wet weather springs upgradient from wet pond 1. Additionally, the Department recommends the Operator monitor all additional flow and submit a permit modification outlines changes made to the construction sequence and identifies the location of all toe drains to be constructed on site. The Department and Operator agreed to reschedule an onsite meeting to discuss the remediation of the wetland. Th Department recommends the Operator monitor the vegetative growth in the wetland. The Department recommends that the Operator add additional temporary mulch to the disturbed area and continue to perform routine maintenance to the temporary BMPs.

How pervasive is this problem?

The DEP well pad report contains data on 12,600 wells, situated on 3,715 wells pads. On the compliance side, there are 2,689 violations at 390 different sites that contain the words “Well Pad.” 739 of these violations do not have associated Well API Numbers, and are therefore not shown in our Pennsylvania Shale Viewer map. The number of sites with violations per operator is shown below in Figure 1 (click to expand).

Figure 1: Number of well pads appearing on compliance report by operator, through 5/15/2018. Click on the image to see the full-sized version.

There are four things to note about about Figure 1. 

First, this table is not the number of violations on well pads, but merely the count of well pads with violations appearing on the compliance report.

Second, this does not contain any data on wells on those pads that were issued violations – only instances where the well pads themselves were cited are shown.

PA Well Pad Violations: 

View map fullscreen

This map shows oil and gas (O&G) violations in Pennsylvania that are assessed to well pads, as opposed to individual wells. To access the map’s legend and other details, click the double-arrow icon at the top-left corner of the map.

The third thing to note about Figure 1 is that there are instances where the same pad falls into more than one category. Hilcorp Energy, for example, has 10 wells in the unconventional category, 11 wells that are not defined, but only 13 total wells, indicating significant overlap between the categories.

And fourth, there are 31 instances where the phrase “well pad” occurs in the compliance report where the unique Site ID# does not appear on the well pad report. In some cases, the name of the facility indicates that it might be for another facility that is related to the well pad, such as “Southwest System – Well Pad 36 to Bluestone Pipeline.” For other entries, such as “Yarasavage Well Pad”, it remains unclear why the Site ID# does not yield a matching entry from the well pad report.


By Matt Kelso, Manager of Data and Technology, FracTracker Alliance

 

Shell Pipeline - Not Quite the Good Neighbor

Shell Pipeline: Not Quite the “Good Neighbor”

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

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

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

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

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

The “Good Neighbor” Narrative

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

Figure 1. Shell flyer

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

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

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

U.S. Pipeline Incident Data

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

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

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

Shell’s Incident Record

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

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


View Map Fullscreen | How FracTracker Maps Work

Incidents Relative to Other Operators

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

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

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

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

Table 2: Shell incidents and maintained pipeline miles by year

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

Cause & Location of Failure

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

Table 3. Shell Pipeline incidents by cause of failure

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

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

Table 4. Shell Pipeline incidents by location of failure

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

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

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

Table 5. Shell Pipeline incidents by commodity spill volumes

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

Impacts & Costs

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

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

Table 6. Costs of damage from Shell Pipeline incidents

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

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

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

Conclusion

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

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

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

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

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

Header image credit: AFP Photo / Joe Raedle

By Kirk Jalbert, FracTracker Alliance

JOSHUA DOUBEK / WIKIMEDIA COMMONS

Groundwater risks in Colorado due to Safe Drinking Water Act exemptions

Oil and gas operators are polluting groundwater in Colorado, and the state and U.S. EPA are granting them permission with exemptions from the Safe Drinking Water Act.

FracTracker Alliance’s newest analysis attempts to identify groundwater risks in Colorado groundwater from the injection of oil and gas waste. Specifically, we look at groundwater monitoring data near Class II underground injection control (UIC) disposal wells and in areas that have been granted aquifer exemptions from the underground source of drinking water rules of the Safe Drinking Water Act (SDWA). Momentum to remove amend the SDWA and remove these exemption.

Learn more about Class II injection wells.

Aquifer exemptions are granted to allow corporations to inject hazardous wastewater into groundwater aquifers. The majority, two-thirds, of these injection wells are Class II, specifically for oil and gas wastes.

What exactly are aquifer exemptions?

The results of this assessment provide insight into high-risk issues with aquifer exemptions and Class II UIC well permitting standards in Colorado. We identify areas where aquifer exemptions have been granted in high quality groundwater formations, and where deep underground aquifers are at risk or have become contaminated from Class II disposal wells that may have failed.

Of note: On March 23, 2016, NRDC submitted a formal petition urging the EPA to repeal or amend the aquifer exemption rules to protect drinking water sources and uphold the Safe Drinking Water Act. Learn more

Research shows injection wells do fail

co_classiiwellexplosion

Class II injection well in Colorado explodes and catches fire. Photo by Kelsey Brunner for the Greeley Tribune.

Disposal of oil and gas wastewater by underground injection has not yet been specifically researched as a source of systemic groundwater contamination nationally or on a state level. Regardless, this issue is particularly pertinent to Colorado, since there are about 3,300 aquifer exemptions in the US (view map), and the majority of these are located in Montana, Wyoming, and Colorado. There is both a physical risk of danger as well as the risk of groundwater contamination. The picture to the right shows an explosion of a Class II injection well in Greeley, CO, for example.

Applicable and existing research on injection wells shows that a risk of groundwater contamination of – not wastewater – but migrated methane due to a leak from an injection well was estimated to be between 0.12 percent of all the water wells in the Colorado region, and was measured at 4.5 percent of the water wells that were tested in the study.

A recent article by ProPublica quoted Mario Salazar, an engineer who worked for 25 years as a technical expert with the EPA’s underground injection program in Washington:

In 10 to 100 years we are going to find out that most of our groundwater is polluted … A lot of people are going to get sick, and a lot of people may die.

Also in the ProPublic article was a study by Abrahm Lustgarten, wherein he reviewed well records and data from more than 220,000 oil and gas well inspections, and found:

  1. Structural failures inside injection wells are routine.
  2. Between 2007-2010, one in six injection wells received a well integrity violation.
  3. More than 7,000 production and injection wells showed signs of well casing failures and leakage.

This means disposal wells can and do fail regularly, putting groundwater at risk. According to Chester Rail, noted groundwater contamination textbook author:

…groundwater contamination problems related to the subsurface disposal of liquid wastes by deep-well injection have been reviewed in the literature since 1950 (Morganwalp, 1993) and groundwater contamination accordingly is a serious problem.

According to his textbook, a 1974 U.S. EPA report specifically warns of the risk of corrosion by oil and gas waste brines on handling equipment and within the wells. The potential effects of injection wells on groundwater can even be reviewed in the U.S. EPA publications (1976, 1996, 1997).

As early as 1969, researchers Evans and Bradford, who reported on the dangers that could occur from earthquakes on injection wells near Denver in 1966, had warned that deep well injection techniques offered temporary and not long-term safety from the permanent toxic wastes injected.

Will existing Class II wells fail?

For those that might consider data and literature on wells from the 1960’s as being unrepresentative of activities occurring today, of the 587 wells reported by the Colorado’s oil and gas regulatory body, COGCC, as “injecting,” 161 of those wells were drilled prior to 1980. And 104 were drilled prior to 1960!

Wells drilled prior to 1980 are most likely to use engineering standards that result in “single-point-of-failure” well casings. As outlined in the recent report from researchers at Harvard on underground natural gas storage wells, these single-point-of-failure wells are at a higher risk of leaking.

It is also important to note that the U.S. EPA reports only 569 injection wells for Colorado, 373 of which may be disposal wells. This is a discrepancy from the number of injection wells reported by the COGCC.

Aquifer Exemptions in Colorado

According to COGCC, prior to granting a permit for a Class II injection well, an aquifer exemption is required if the aquifer’s groundwater test shows total dissolved solids (TDS) is between 3,000 and 10,000 milligrams per liter (mg/l). For those aquifer exemptions that are simply deeper than the majority of current groundwater wells, the right conditions, such as drought, or the needs of the future may require drilling deeper or treating high TDS waters for drinking and irrigation. How the state of Colorado or the U.S. EPA accounts for economic viability is therefore ill-conceived.

Data Note: The data for the following analysis came by way of FOIA request by Clean Water Action focused on the aquifer exemption permitting process. The FOIA returned additional data not reported by the US EPA in the public dataset. That dataset contained target formation sampling data that included TDS values. The FOIA documents were attached to the EPA dataset using GIS techniques. These GIS files can be found for download in the link at the bottom of this page.

Map 1. Aquifer exemptions in Colorado


View map fullscreen | How FracTracker maps work

Map 1 above shows the locations of aquifer exemptions in Colorado, as well as the locations of Class II injection wells. These sites are overlaid on a spatial assessment of groundwater quality (a map of the groundwater’s quality), which was generated for the entire state. The changing colors on the map’s background show spatial trends of TDS values, a general indicator of overall groundwater quality.

In Map 1 above, we see that the majority of Class II injection wells and aquifer exemptions are located in regions with higher quality water. This is a common trend across the state, and needs to be addressed.

Our review of aquifer exemption data in Colorado shows that aquifer exemption applications were granted for areas reporting TDS values less than 3,000 mg/l, which contradicts the information reported by the COGCC as permitting guidelines. Additionally, of the 175 granted aquifer exemptions for which the FOIA returned data, 141 were formations with groundwater samples reported at less than 10,000 mg/l TDS. This is half of the total number (283) of aquifer exemptions in the state of Colorado.

When we mapped where class II injection wells are permitted, a total of 587 class II wells were identified in Colorado, outside of an aquifer exemption area. Of the UIC-approved injection wells identified specifically as disposal wells, at least 21 were permitted outside aquifer exemptions and were drilled into formations that were not hydrocarbon producing. Why these injection wells are allowed to operate outside of an aquifer exemption is unknown – a question for regulators.

You can see in the map that most of the aquifer exemptions and injection wells in Colorado are located in areas with lower TDS values. We then used GIS to conduct a spatial analysis that selected groundwater wells within five miles of the 21 that were permitted outside aquifer exemptions. Results show that groundwater wells near these sites had consistently low-TDS values, meaning good water quality. In Colorado, where groundwater is an important commodity for a booming agricultural industry and growing cities that need to prioritize municipal sources, permitting a Class II disposal well in areas with high quality groundwater is irresponsible.

Groundwater Monitoring Data Maps

Map 2. Water quality and depths of groundwater wells in Colorado
Groundwater risks in Colorado - Map 2
View live map | How FracTracker maps work

In Map 2, above, the locations of groundwater wells in Colorado are shown. The colors of the dots represent the concentration of TDS on the right and well depth on the left side of the screen. By sliding the bar on the map, users can visualize both. This feature allows people to explore where deep wells also are characterized by high levels of TDS. Users can also see that areas with high quality low TDS groundwater are the same areas that are the most developed with oil and gas production wells and Class II injection wells, shown in gradients of purple.

Statistical analysis of this spatial data gives a clearer picture of which regions are of particular concern; see below in Map 3.

Map 3. Spatial “hot-spot” analysis of groundwater quality and depth of groundwater wells in Colorado
Groundwater risks in Colorado - Map 3
View live map | How FracTracker maps work

In Map 3, above, the data visualized in Map 2 were input into a hot-spots analysis, highlighting where high and low values of TDS and depth differ significantly from the rest of the data. The region of the Front Range near Denver has significantly deeper wells, as a result of population density and the need to drill municipal groundwater wells.

The Front Range is, therefore, a high-risk region for the development of oil and gas, particularly from Class II injection wells that are necessary to support development.

Methods Notes: The COGCC publishes groundwater monitoring data for the state of Colorado, and groundwater data is also compiled nationally by the Advisory Committee on Water Information (ACWI). (Data from the National Groundwater Monitoring Network is sponsored by the ACWI Subcommittee on Ground Water.) These datasets were cleaned, combined, revised, and queried to develop FracTracker’s dataset of Colorado groundwater wells. We cleaned the data by removing sites without coordinates. Duplicates in the data set were removed by selecting for the deepest well sample. Our dataset of water wells consisted of 5,620 wells. Depth data was reported for 3,925 wells. We combined this dataset with groundwater data exported from ACWI. Final count for total wells with TDS data was 11,754 wells. Depth data was reported for 7,984 wells. The GIS files can be downloaded in the compressed folder at the bottom of this page.

Site Assessments – Exploring Specific Regions

Particular regions were further investigated for impacts to groundwater, and to identify areas that may be at a high risk of contamination. There are numerous ways that groundwater wells can be contaminated from other underground activity, such as hydrocarbon exploration and production or waste injection and disposal. Contamination could be from hydraulic fracturing fluids, methane, other hydrocarbons, or from formation brines.

From the literature, brines and methane are the most common contaminants. This analysis focuses on potential contamination events from brines, which can be detected by measuring TDS, a general measure for the mixture of minerals, salts, metals and other ions dissolved in waters. Brines from hydrocarbon-producing formations may include heavy metals, radionuclides, and small amounts of organic matter.

Wells with high or increasing levels of TDS are a red flag for potential contamination events.

Methods

Groundwater wells at deep depths with high TDS readings are, therefore, the focus of this assessment. Using GIS methods we screened our dataset of groundwater wells to only identify those located within a buffer zone of five miles from Class II injection wells. This distance was chosen based on a conservative model for groundwater contamination events, as well as the number of returned sample groundwater wells and the time and resources necessary for analysis. We then filtered the groundwater wells dataset for high TDS values and deep well depths to assess for potential impacts that already exist. We, of course, explored the data as we explored the spatial relationships. We prioritized areas that suggested trends in high TDS readings, and then identified individual wells in these areas. The data initially visualized were the most recent sampling events. For the wells prioritized, prior sampling events were pulled from the data. The results were graphed to see how the groundwater quality has changed over time.

Case of Increasing TDS Readings

If you zoom to the southwest section of Colorado in Map 2, you can see that groundwater wells located near the injection well 1 Fasset SWD (EPA) (05-067-08397) by Operator Elm Ridge Exploration Company LLC were disproportionately high (common). Groundwater wells located near this injection well were selected for, and longitudinal TDS readings were plotted to look for trends in time. (Figure 1.)

The graphs in Figure 1, below, show a consistent increase of TDS values in wells near the injection activity. While the trends are apparent, the data is limited by low numbers of repeated samples at each well, and the majority of these groundwater wells have not been sampled in the last 10 years. With the increased use of well stimulation and enhanced oil recovery techniques over the course of the last 10 years, the volumes of injected wastewater has also increased. The impacts may, therefore, be greater than documented here.

This area deserves additional sampling and monitoring to assess whether contamination has occurred.


Figures 1a and 1b. The graphs above show increasing TDS values in samples from groundwater wells in close proximity to the 1 Fassett SWD wellsite, between the years 2004-2015. Each well is labeled with a different color. The data for the USGS well in the graph on the right was not included with the other groundwater wells due to the difference in magnitude of TDS values (it would have been off the chart).

Groundwater Contamination Case in 2007

We also uncovered a situation where a disposal well caused groundwater contamination. Well records for Class II injection wells in the southeast corner of Colorado were reviewed in response to significantly high readings of TDS values in groundwater wells surrounding the Mckinley #1-20-WD disposal well.

When the disposal well was first permitted, farmers and ranchers neighboring the well site petitioned to block the permit. Language in the grant application is shown below in Figure 2. The petitioners identified the target formation as their source of water for drinking, watering livestock, and irrigation. Regardless of this petition, the injection well was approved. Figure 3 shows the language used by the operator Energy Alliance Company (EAC) for the permit approval, which directly contradicts the information provided by the community surrounding the wellsite. Nevertheless, the Class II disposal well was approved, and failed and leaked in 2007, leading to the high TDS readings in the groundwater in this region.

co_classiipetition

Figure 2. Petition by local landowners opposing the use of their drinking water source formation for the site of a Class II injection disposal well.

 

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Figure 3. The oil and gas operation EAC claims the Glorietta formation is not a viable fresh water source, directly contradicting the neighboring farmers and ranchers who rely on it.

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Figure 4. The COGCC well log report shows a casing failure, and as a result a leak that contaminated groundwater in the region.

Areas where lack of data restricted analyses

In other areas of Colorado, the lack of recent sampling data and longitudinal sampling schemes made it even more difficult to track potential contamination events. For these regions, FracTracker recommends more thorough sampling by the regulatory agencies COGCC and USGS. This includes much of the state, as described below.

Southeastern Colorado

Our review of the groundwater data in southeastern Colorado showed a risk of contamination considering the overlap of injection well depths with the depths of drinking water wells. Oil and gas extraction and Class II injections are permitted where the aquifers include the Raton formation, Vermejo Formation, Poison Canyon Formation and Trinidad Sandstone. Groundwater samples were taken at depths up to 2,200 ft with a TDS value of 385 mg/l. At shallower depths, TDS values in these formations reached as high as 6,000 mg/l, and 15 disposal wells are permitted in aquifer exemptions in this region. Injections in this area start at around 4,200 ft.

In Southwestern Colorado, groundwater wells in the San Jose Formation are drilled to documented depths of up to 6,000 feet with TDS values near 2,000 mg/l. Injection wells in this region begin at 565 feet, and those used specifically for disposal begin at below 5,000 feet in areas with aquifer exemptions. There are also four disposal wells outside of aquifer exemptions injecting at 5,844 feet, two of which are not injecting into active production zones at depths of 7,600 and 9,100 feet.

Western Colorado

In western Colorado well Number 1-32D VANETA (05-057-06467) by Operator Sandridge Exploration and Production LLC’s North Park Horizontal Niobara Field in the Dakota-Lokota Formation has an aquifer exemption. The sampling data from two groundwater wells to the southeast, near Coalmont, CO, were reviewed, but we can’t get a good picture due to the lack of repeat sampling.

Northwestern Colorado

http://digital.denverlibrary.org/cdm/ref/collection/p16079coll32/id/346073

A crew from Bonanza Creek repairs an existing well in the McCallum oil field. Photo by Ken Papaleo / Rocky Mountain News

In Northwestern Colorado near Walden, CO and the McCallum oil field, two groundwater wells with TDS above 10,000 ppm were selected for review. There are 21 injection wells in the McCallum field to the northwest. Beyond the McCallum field is the Battleship field with two wastewater disposal wells with an aquifer exemption. West of Grover, Colorado, there are several wells with high TDS values reported for shallow wells. Similar trends can be seen near Vernon. The data on these wells and wells from along the northern section of the Front Range, which includes the communities of Fort Collins, Greeley, and Longmont, suffered from the same issue. Lack of deep groundwater well data coupled with the lack of repeat samples, as well as recent sampling inhibited the ability to thoroughly investigate the threat of contamination.

Trends and Future Development

Current trends in exploration and development of unconventional resources show the industry branching southwest of Weld County towards Fort Collins, Longmont, Broomfield and Boulder, CO.

These regions are more densely populated than the Front Range county of Weld, and as can be seen in the maps, the drinking water wells that access groundwaters in these regions are some of the deepest in the state.

This analysis shows where Class II injection has already contaminated groundwater resources in Colorado. The region where the contamination has occurred is not unique; the drinking water wells are not particularly deep, and the density of Class II wells is far from the highest in the state.

Well casing failures and other injection issues are not exactly predictable due to the variety of conditions that can lead to a well casing failure or blow-out scenario, but they are systemic. The result is a hazardous scenario where it is currently difficult to mitigate risk after the injection wells are drilled.

Allowing Class II wells to expand into Front Range communities that rely on deep wells for municipal supplies is irresponsible and dangerous.

The encroachment of extraction into these regions, coupled with the support of Class II injection wells to handle the wastewater, would put these groundwater wells at particular risk of contamination. Based on this analysis, we recommend that regulators take extra care to avoid permitting Class II wells in these regions as the oil and gas industry expands into new areas of the Front Range, particularly in areas with dense populations.


Feature Image: Joshua Doubek / WIKIMEDIA COMMONS

Article by: Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

 

October 31, 2017 Edit: This post originally cited the Clean Water Act instead of the Safe Drinking Water Act as the source that EPA uses to grant aquifer exemptions.

Changes to PA Maps feature image

Recent Changes to Pennsylvania Maps

Recently, the Pennsylvania Department of Environmental Protection (DEP) started to offer additional data resources with the introduction of the Open Data Portal. This development, along with the continued evolution of the ArcGIS Online mapping platform that we utilize has enabled some recent enhancements in our mapping of Pennsylvania oil and gas infrastructure. We’ve made changes to the existing Pennsylvania Shale Viewer for unconventional wells, and created a Conventional and Historical Wells in Pennsylvania map.

Unconventional Wells

Rather than defining the newer, industrial-scaled oil and gas wells by specific geological formations, configuration of the well, or the amount of fluid injected into the ground during the hydraulic fracturing process, Pennsylvania’s primary classification is based on whether or not they are considered to be unconventional.

Unconventional Wells – An unconventional gas well is a bore hole drilled or being drilled for the purpose of or to be used for the production of natural gas from an unconventional formation. An unconventional formation is defined as a geologic shale formation below the base of the Elk Sandstone or its geologic equivalent where natural gas generally cannot be produced except by horizontal or vertical well bores stimulated by hydraulic fracturing.

PA Shale Viewer (Unconventional Drilling)

View map fullscreen | How FracTracker maps work

The previous structure of the PA Shale Viewer had separate layers for permits, drilled wells, and violations. This version replaces the first two layers with a single layer of unconventional locations, which we have called “Unconventional Wells and Permits” for the sake of clarity. The violations layer appears in the same format as before. When users are zoomed out, they will see generalized layers showing the overall location of O&G infrastructure and violations in the state, which were formed by creating a one mile buffer around these features. As users zoom in, the generalized layers are then replaced with point data showing the specific wells and violations. At this point, users can click on individual points and learn more about the features they see on the map.

PA Shale Viewer Zoomed In

Figure 1. PA Shale Viewer zoomed in to see individual wells by status

O&G locations are displayed by their well status, as of the time that FracTracker processed the data, including: Abandoned, Active, Operator Reported Not Drilled, Plugged OG Well, Proposed but Never Materialized, and Regulatory Inactive Status. Note that just because a well is classified as Active does not mean that it has been drilled, or even necessarily permitted. These milestones, along with whether or not it has been plugged, can be determined by looking for entries in the permit issue date, spud date, and plug date entries in the well’s popup box.

Conventional and Historical Wells

The map below shows known conventional wells in Pennsylvania along with additional well locations that were digitized from historical mining maps.

Conventional Oil and Gas Wells Map

View map fullscreen | How FracTracker maps work

Although there are over 19,000 unconventional oil and gas locations in Pennsylvania, this figure amounts to just 11% of the total number of wells in the state that the DEP has location data for, the rest being classified as conventional wells. Furthermore, in a state that has been drilling for oil and gas since before the Civil War, there could be up to 750,000 abandoned wells statewide.

The DEP has been able to find the location of over 30,000 of these historical wells by digitizing records from old paper mining maps. This layer has records for 16 different counties, but well over half of these wells are in just three counties – Allegheny, Butler, and Washington. It looks like it would take a lot more work to digitize these historical wells throughout the rest of the state, but even when that happens, we will probably still not know where the majority of the old oil and gas wells in the state are located.


By Matt Kelso, Manager of Data & Technology

Forest fragmentation in PA

Forest Fragmentation and O&G Development in PA’s Susquehanna Basin

In this forest fragmentation analysis, FracTracker looked at existing vegetation height in the northern portion of Pennsylvania’s Susquehanna River Basin. The vegetation height data is available from LANDFIRE, a resource used by multiple federal agencies to assess wildfire potential by categorizing the vegetation growth in 30 by 30 meter pixels into different categories. In the portion of Pennsylvania’s Susquehanna Basin where we looked, there were 29 total categories based on vegetation height. For ease of analysis, we have consolidated those into eight categories, including roads, developed land, forest, herbs, shrubs, crops, mines and quarries, and open water.

Methods

We compared the ratio of the total number of each pixel type to the type that was found at vertical and horizontal wells in the region. In this experiment, we hypothesized that we would see evidence of deforestation in the areas where oil and gas development is present. Per our correspondence with LANDFIRE staff, the vegetation height data represents a timeframe of about 2014, so in this analysis, we focused on active wells that were drilled prior to that date. We found that the pixels on which the horizontal wells were located had a significantly different profile type than the overall pixel distribution, whereas conventional wells had a more modest departure from the general characteristics of the region.

Figure 1 - Vegetation profile of the northern portion of Pennsylvania's Susquehanna River Basin. The area is highly impacted by O&G development, a trend that is likely to continue in the coming years.

Figure 1 – Vegetation profile of the northern portion of Pennsylvania’s Susquehanna River Basin. The area is highly impacted by O&G development, a trend that is likely to continue in the coming years.

In Figure 1, we see that the land cover profile where vertical wells (n=6,198) are present is largely similar to the overall distribution of pixels for the entire study area (n=40,897,818). While these wells are more than six times more likely to be on areas classified as mines, quarries, or barren, it is surprising that the impact is not even more pronounced. In terms of forested land, there is essentially no change from the background, with both at about 73%. However, the profile for horizontal wells (n=3,787) is only 51% forested, as well as being four times more likely than the background to be categorized as herbs, which are defined in this dataset as having a vegetation height of around one meter.

Why Aren’t the Impacts Even More Pronounced?

While the impacts are significant, particularly for horizontal wells, it is a bit surprising that evidence of deforestation isn’t even more striking. We know, for example, that unconventional wells are usually drilled in multi-well pads that frequently exceed five acres of cleared land, so why aren’t these always classified as mines, quarries, and barren land, for example? There are several factors that can help to explain this discrepancy.

First, it must be noted that at 900 square meters, each pixel represents almost a quarter of acre, so the extent of these pixels will not always match with the area of disturbance. And in many cases, the infrastructure for older vertical wells is completely covered by the forest canopy, so that neither well pad nor access road is visible from satellite imagery.


View map fullscreenHow FracTracker maps work

The map above shows horizontal and vertical wells in a portion of Centre County, Pennsylvania, an area within our study region. Note that many of the vertical wells, represented by purple dots, appear to be in areas that are heavily forested, whereas all of the horizontal wells (yellow dots) are on a defined well pad in the lower right part of the frame. Panning around to other portions of Centre County, we find that vertical wells are often in a visible clearing, but are frequently near the edge, so that the chances of the 30 by 30 meter pixel that they fall into is much more likely to be whatever it would have been if the well pad were not there.

We must also consider that this dataset has some limitations. First of all, it was built to be a tool for wildfire management, not as a means to measure deforestation. Secondly, there are often impacts that are captured by the tool that were not exactly on the well site. For this reason, it would make sense to evaluate the area around the well pad in future versions of the analysis.

Figure 2 - A close up of a group of wells in the study area. Note that the disturbed land (light grey) does not always correspond exactly with the well locations.

Figure 2 – A close up of a group of wells in the study area. Note that the disturbed land (light grey) does not always correspond exactly with the well locations.

In Figure 2, we see a number of light grey areas –representing quarries, strip mines, and gravel pits –with an O&G well just off to the side. Such wells did not get classified as being on deforested land in this analysis.

And finally, after clarifying the LANDFIRE metadata with US Forest Service personnel involved in the project, we learned that while the map does represent vegetation cover circa 2014, it is actually build on satellite data collected in 2001, which has subsequently been updated with a detailed algorithm. However, the project is just beginning a reboot of the project, using imagery from 2015 and 2016. This should lead to much more accurate analyses in the future.

Why Forest Fragmentation Matters

The clearing of forests for well pads, pipelines, access roads, and other O&G infrastructure that has happened to date in the Susquehanna Basin is only a small fraction of the planned development. The industry operates at full capacity, there could be tens of thousands of new unconventional wells drilled on thousands of well pads in the region through 2030, according to estimates by the Nature Conservancy. They have also calculated an average of 1.65 miles of gathering lines from the well pad to existing midstream infrastructure. With a typical right-of-way being 100 feet wide, these gathering lines would require clearing 20 acres. It isn’t unusual for the total disturbance for a single well pad and the associated access road to exceed ten acres, making the total disturbance about 30 acres per well pad. Based on the vegetation distribution of the region, we can expect that 22 of these acres, on average, are currently forested land. Taking all of these factors into consideration, a total disturbance of 100,000 to 200,000 acres in Pennsylvania’s Susquehanna River Basin due to oil and gas extraction, processing, and transmission may well be a conservative estimate, depending on energy choices we make in the coming years.

This forest fragmentation has a number of deleterious effects on the environment. First, many invasive plant species, such as bush honeysuckle and Japanese knotweed, tend to thrive in recently disturbed open areas, where competing native plants have been removed. The practice also threatens numerous animal species that thrive far from the forest’s edge, including a variety of native song birds. The disturbed lands create significant runoff into nearby rivers and streams, which can have an impact on aquatic life. And the cumulative release of carbon into the atmosphere is staggering – consider that the average acre of forest in the United States contains 158,000 pounds of organic carbon per acre. As the area is 73% forested, the total cumulative impact could result in taking 5.8 to 11.6 million tons of organic carbon out of forested storage. Much of this carbon will find its way into the atmosphere, along with the hydrocarbons that are purposefully being extracted from drilling operations.