Pipelines vs Oil Trains

By Juliana Henao, Communications Intern

Media outlets have been very focused recently on reporting oil train derailments and explosions. Additionally, the Keystone XL pipeline has hastened political debates and arguments for years by both political parties since its initial proposal in 2008 – and the May 19th pipeline oil spill in California isn’t helping matters. In the midst of all of this commotion, a million questions are being asked, yet no one can seem to reach a conclusion about what method of transporting oil is truly safest and economically feasible – or if we are just stuck between a rock and a hard place.

Some say the solution to this problem is transporting the volatile crude via pipelines, while others believe it is a matter of increasing regulations, standards, and compliance for transport by train. The answer is simply not simple.

In light of this, a few of the folks at FracTracker gathered some facts on pipelines vs oil trains to lay out this issue in a clearer fashion.

Let’s start with trains.

Benefits

Due to the increasing demand of crude oil supply, there has been increasing activity in the transportation of crude oil by rail, which provides flexibility and quick transportation throughout the U.S. and its 115 refineries. Railroads are also willing to offer shippers shorter contracts than pipelines and other transportation methods, making them a more favorable method of crude oil transportation.

In 2008, U.S. freight trains were delivering somewhere from 9-10,000 carloads of crude oil. In 2013, they delivered roughly 435,560 carloads of crude oil, showing a 20-fold increase in crude oil shipments.

Risks

Oil trains, as well as pipelines, can pose a detrimental risk to communities and public health in the case of an explosion and/or spill. Danger Around the Bend describes in detail the dangers of transporting Bakken Formation crude oil from North Dakota to parts all over the country.

Some of the risks of transporting volatile crude via train have been clearly depicted in the news with announcements of spills, derailments, and explosions in urban and suburban areas, putting many people in harm’s way. Despite the decrease in spills between 1996 and 2007, devastating train accidents like the one on July 6, 2013 have raised questions about the safety of transportation by train.

train_incidents_english

Learn more about this trend and the increasing risk of exploding oil trains in a post by Randy Sargent of CMU.

Trains and train tracks in general can be very dangerous, as demonstrated by the deadly Amtrak train derailment in Philadelphia this May. The total number of incidents in 2014, according to the Federal Railroad Administration, sum up to 11,793 – with 818 of those being fatal. These fatalities have been linked to a range of possible causes, but the numbers depict the gravity of safety issues within the railroad regulations.

Regulations

When it comes to train safety and regulations, the Federal Railroad Administration (FRA) is in charge. Some of the current efforts to increase the safety of oil trains include safer tank car design, adding breaking power, reducing the train speed limits through urban areas and increasing crew size. One of the most important improvements, however, includes an increase in oil spill response, which is managed through the National Oil and Hazardous Substance Contingency Plan.

Now, let’s talk pipelines.

As we all know, finishing the Keystone XL pipeline has stirred years of controversy, since this project was initially proposed back in 2008. On January 31, 2014, the U.S. Department of State released the Final Supplemental Environmental Impact Statement (SEIS) of the Keystone XL Pipeline, which would transport up to 830,000 barrels of tar sand oil per day through an 875-mile long pipeline running from Alberta, Canada, to the Gulf Coast area. Below we have mapped the current and proposed tracks of the Keystone, along with the numerous ports, refineries, and rail lines:


The Keystone XL, Alberta oil sands, North American oil refineries and associated ports. View fullscreen and click Details for the metadata behind this map.

The SEIS discussed the impacts that the proposed pipeline would have on the environment and public health based on research, modeling, and analysis. One of the many purposes of the SEIS is to focus on whether the proposed project serves the national interest by comparing the risks to the benefits – discussed in more detail below.

Risks

The current risks associated with pipelines are similar to the risks associated with other modes of transporting oil across the United States. Oil spills are among the highest risks, but with the XL pipeline, it’s a more profound risk due to the type of oil being carried: tar sand oil. Tar sand oil, also known as heavy oil, is known for its tedious processing and its many environmental implications. Burning one single barrel of oil produced from Canadian tar sands generally emits 170 pounds of greenhouse gases into the atmosphere. It also requires large amounts of energy and water, much of which cannot be recycled, to separate the oil from the tar sands and transform the oil into a form of petroleum that can be processed by refineries.

According to the final SEIS:

The proposed project would emit approximately 24 million metric tons of carbon dioxide per year during the construction period (up to three times as much than producing conventional crude), which would be directly emitted through fuel use in construction vehicles and equipment as well as land clearing activities including open burning, and indirectly from electricity usage.

Additional risks associated with the XL pipeline include potential groundwater contamination of major aquifers – particularly the Ogallala Aquifer – as well as deforestation, habitat destruction, and fragmentation.

In the event of an oil spill from the Keystone XL or other pipelines crossing the U.S., the responsibility for who cleans it up does not fall on TransCanada. According to a report from the Natural Resource Defense Council (NRDC), tar sand oils are exempt from paying into the Oil Spill Liability Trust Fund. Amendments that would require TransCanada to pay the 8-cent-per-barrel fee to the fund have not been passed.

Devastating oil spills such as the one in Santa Barbara in mid May reflect the impact it not only has on wildlife, but on the local culture, especially on those who depend on fisheries and whose lives revolves around surfing in the brisk waters of the Pacific Ocean. 21,000 gallons of crude oil covers roughly 4 miles of Santa Barbara’s coast now, extending about 50 yards into the water.

Benefits

Jobs, jobs, jobs. The economic stimulus is one purported advantage to the XL pipeline. During construction, proposed project spending would support approximately 42,100 jobs, directly and indirectly and around $2 billion in earnings throughout the US, according to the final SEIS. Despite different job creation estimates, any number will contribute significantly to the US gross domestic product, associating a huge economic growth with the construction of the proposed XL pipeline. (TransCanada estimates around 13,000 construction jobs and 7,000 manufacturing jobs, which is about 3 times higher than the State Department’s estimate.) In addition, the cost of paying for the Keystone XL project ($3.3 billion) would not be placed on the U.S. but on Keystone.

According to the Pipeline and Hazardous Materials Safety Administration (PHSMA), the industry and their operators have reduced the risk of hazardous materials transportation incidents with death or major injury by 4% every 3 years, and since 2002, they have reduced the risk of a pipeline spill with environmental consequences by an average of 5% per year.1

Still, there is more work to be done. Safety issues that the pipeline industry is aiming to fix include:

  • Infrastructure: Repair obsolete pipeline infrastructure through a pipeline integrity management program and investigate new technologies that can detect pipeline risks.
  • Improving human error and safety culture: Increase the focus on safety beyond compliance standards and evaluate the potential value of safety management systems.
  • Adding secondary containment: Limit the spread of HAZMAT in the event of a failure in the primary container, and improve leak detection.
  • Transparency: Increasing transparency for companies and their accountability

Check out the infographic below for a summary of all of these pros and cons:

Moving Forward

All methods of transporting oil present various risks and benefits based on the available data. Explaining both sides of this coin allows us to assess each method’s impacts on our economy, environment, and public health. Through these assessments, we can make more informed decisions on what truly serves the nation’s interests. Oil and gas transport is a dangerous business, but all transportation industries are improving their management programs and increasing their regulations to provide citizens peace of mind and the safety they deserve. In light of ongoing issues, however, some would ask if these risks are even necessary.

For example, the growth of safer energy resources such as solar energy would significantly cut down the risks mentioned above in addition to providing jobs and stimulating the overall economy. According to the Bureau of Labor Statistics and the Solar Foundation, the growth in direct industry jobs for solar has outweighed oil and gas for the past 3 years. In 2014, new jobs created for the solar industry were more than twice the jobs created for the oil and gas industry. Based on 2014’s economics, Kepler Cheuvreux stated that all renewables are already more competitive than oil priced at $100 per barrel — This is because renewables have a higher net energy return on capital invested (EROCI).

As a reader and a citizen, it is important to know the pros and cons of the current activities taking place in our country today. We must be aware of loopholes that may be putting our states, cities, or counties into harm’s way, as well as recognize alternative energy sources and regulatory oversight that lessen the threats that oil extraction and transport pose to our health and environment.

Footnote

1. These statistics are based from the Census Bureau analysis and Bureau of Transportation Statistics as of July 2012.

Oil train - Photo by Washinton House Democrats

Increasing Risk from Exploding Crude Trains

By Randy Sargent, Carnegie Mellon CREATE Lab and Samantha Malone, FracTracker Alliance

In the past two years, crude oil trains have exploded 10 times, killing 47 people.

LacMegantic

Lac-Mégantic, Quebec: 47 killed

NewBrunswick

Outside Plaster Rock, New Brunswick

Casselton

Outside Casselton, ND

Aliceville

Outside Aliceville, AL

Lynchburg

Outside Lynchburg, VA

WV

Outside Mt. Carbon, WV

Timmins

Outside Timmins, Ontario

Galena

Outside Galena, IL

 

 

Heimdal

Outside Heimdal, ND

Gogoma

Outside Gogama, Ontario

It could have been much worse. Eight of the ten trains exploded in rural areas. The train that flattened half the business district of the small town of Lac-Mégantic might have killed hundreds of people if it had exploded during business hours.[1] Residents in Philadelphia have dodged a bullet several times already; they’ve seen two oil train derailments there that fortunately did not explode. And last week’s Amtrak train derailment in Philadelphia that killed 8 people and injured more than 200 could have been much worse, had it impacted an oil train in that area.

Today we ship 17 times as much oil by rail as we did in 2010. This past year we shipped 14.5 billion gallons of oil — that’s 6,700 oil trains the size that destroyed Lac-Mégantic:

This chart above and the ones that follow are derived from the U.S. Energy Information Administration’s recently provided data tracking crude oil movements by rail.

Why do oil trains explode so easily?

Like a carbonated beverage with dissolved CO2, oil extracted from Bakken wells naturally has lighter hydrocarbons in it, such as methane, ethane, propane, and butane. Methane — natural gas — is the lightest of the gases and boils out quickly at surface pressure. But ethane, propane, and butanes, known as light ends or natural gas liquids in the oil industry, take time and/or heat to boil out.[2]

In the most prolific oilfield in the U.S. today, North Dakota’s Bakken formation, most of light ends are left in the oil before loading on the train, to maximize value of what is sent to the refinery. But much like a soda bottle, the pressure increases with temperature and motion, with pressurized ethane, propane, and butane at the top. With those highly volatile gases under pressure, all it takes to create an explosion is a leak and a spark, and both commonly happen in a derailment or collision.

All ten exploding crude trains carried oil from the Bakken.

In contrast, shale oilfields in Texas do stabilize crude by removing light ends prior to shipment by rail.

Where are the exploding Bakken oil trains going?

Bakken trains travel through much of the US and Canada, heading to refineries on the coasts. Increasingly, they are traveling to East coast refineries, which now handle over half of Bakken crude oil production.

Closer to home for the authors, Pittsburgh is a popular waypoint for Bakken oil trains. Known for its steel industry in the 20th century, Pittsburgh continues to sport a large rail infrastructure. Its rails go through very densely populated areas, a good thing when the rails carried ore and steel and coal for the mills. But it’s a disaster waiting to happen now that the rails are bringing explosive oil trains through the city.

CMU

Oil and compressed gasses transit Carnegie Mellon University multiple times daily, Pittsburgh, PA

Oil trains travel across Pittsburgh's North Shore and Downtown multiple times daily, as well

Oil trains travel across Pittsburgh’s North Shore and Downtown multiple times daily, as well

 

A significant and growing fraction of Bakken oil trains carrying 1 million gallons or more transit Pittsburgh, with ~30 a week based on Pennsylvania Emergency Management Agency data released for five days in October 2014. Prior to the disclosure, volunteers spent a day with us in 2014 recording traffic along one of several routes into the city to learn more about whether / how the trains might pose a risk to city residents and workers. Learn more about what we found here.

Why does this matter?

As crude-by-rail traffic continues to increase, it is only a matter of time before an oil train explodes in a populated area again. Imagine any of the 10 explosions so far taking place instead in downtown Philadelphia or Pittsburgh, or flattening a school in suburban Chicago, for example.

Map of Lac-Mégantic destruction from the Toronto Star’s article, “Where they died”

Map of Lac-Mégantic destruction from the Toronto Star’s article, Where they died. Click to explore the interactive map.

Learn more about the Lac-Megantic disaster through the eyes of those who lived through it.

What can be done

One attempt to make these trains safer, by requiring new tanker cars be built to a safer standard, does not appear to have helped; the most recent 5 exploding trains used the newest, “safer” tanker cars.

But there are effective measures that are in our power to take:


Photo and Video Credits

Endnotes

  1. The direction that the ignited oil flowed after the incident also played a significant role in the path of the damage and fatalities.
  2. Light Ends information
CA Crude Oil by Rail Shipments and Railway Accidents

CA Crude Oil by Rail Shipments and Railway Accidents

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

Incidents in California involving oil-by-rail cars increased from 3 in 2011 to 25 in 2013. There were 24 incidents within the first 6 months of 2014, and oil spills from rail cars increased from 98 in 2010 to 182 in 2013.1 With such an increase in oil train incidents, we have to ask what the state is doing to protect public safety.

CA Crude Oil by Rail – The Status Quo

California is currently far behind states like New Hampshire and Minnesota that have taken more control over in-state hazards, and have passed laws aimed at forcing rail and pipeline companies to abide by more rigorous emergency response measures instead of relying on the federal government and undertaking state-level spill response plans. These state movements are in response to the existing federal oversight, which critics cite as inadequate.2

State environmental health officials have acknowledged the dangers of a derailment, but have downplayed the risk – comparing the hazard of an incident to be similar to ethanol or gasoline, based on volatility. They do not believe oil train derailments are as hazardous as other materials transported by rail such as chlorine or ammonia. The bigger concern, though, is the huge volume of Bakken crude oil that is being shipped by rail. A recent report by the State of California Interagency Rail Safety Working group acknowledged this and identified key vulnerabilities along CA rail lines; Destinations of the crude trains in CA are the Bay Area via the Feather River or Donner Pass, Bakersfield via the Tehachapi Pass, and Los Angeles via the same route. These routes pass through the state’s most densely populated areas, as well as through some of the state’s most sensitive ecological areas, and each route has at least one high hazard area for derailments. Other issues identified include the impact of earthquakes on trains and rail lines and a shortage of emergency response capacity.

At-Risk Populations

A recent report by the Natural Resources Defense Council used census data to identify at risk-populations for communities living near the rail lines that can be used for transporting shipments. The analysis identified a total of nearly four million people in the Bay Area and the Central Valley alone that live within 1 mile (the U.S. DOT isolation zone for a crude tanker fire) of a crude shipment rail line. The authors go on to provide the following recommendations to prevent crude oil train accidents:

  1. Remove Defective, Dangerous Tankers from Crude by Rail Service
  2. Impose Safer Speed Limits
  3. Reroute Around Sensitive Areas
  4. Provide Emergency Responder Resources
  5. Make Additional operational Safety and Oversight Improvements
  6. Exercise Local Government Powers4

Crude Oil Shipment Trends

Support of these recommendations is most important as more crude shipments in CA are on the horizon. A recent permit application by the Phillips 66 oil company included a proposal to use Amtrak passenger lines to transport Bakken crude through the San Francisco Bay Area. A review of the proposal by Hinman Consulting Engineers found that over the next 30 years, there is an approximate 28% risk of derailment in the heavily populated stretches of Berkeley, Emeryville, Oakland, Santa Clara, San Jose and others. This estimate is assuming there is no increase in shipping volumes. The damage of an accident was estimated by the researchers, and the analysis showed that approximately 47,000 households and $22 billion in improved property value lay within the projected blast zone, 1000 feet from the railway. A projection of the damage from a single accident estimated that an average of 117 households along with $244 million in property value could be destroyed. Hinman also stated that “this figure does not include loss of revenue, environmental cleanup costs, loss of human life, or other societal costs.”5 A proposal by Valero Refining Co. plans to ship 100 crude oil tank cars a day through downtown Sacramento and downtown Davis to Benicia.

Responses by CA Regulators and Railroads

To plan for this increase in rail traffic, Sacramento passed a shipping charge to prevent and manage spills that will result in $11 million in 2015. Another bill has been introduced to impose a second shipping fee on oil companies to train and equip first responders to deal with major spills and fires on railroad lines. An additional bill was also authored requiring rail carriers to communicate more closely with state emergency officials about crude oil rail movements.6

The map below shows where spills and train accidents have occurred in CA since 2011. When zoomed out the map shows areas with higher incidence rates of accidents, but when zoomed to a higher resolution the map differentiates the accidents by year.7

CA Crude Oil by Rail and Railroad Accidents

View Full Screen

In the map above, a hot spot analysis shows the frequency of railroad accidents, such as derailments. Areas with the highest incidence rates are shown in yellow. The actual locations and descriptions with dates of these accidents can be seen by zooming in using the plus (+) button in the top left corner of the map, and clicking on a diamond symbol. Shown in red and green are the BNSF and other railroad lines used for the transportation of crude by rail.

BNSF Route

Figure taken from BNSF’s U.S. DOT disclosure to the state of California for emergency preparedness.9

From what little data has been released, it is clear that BNSF railway intends to ship two Bakken crude trains per week carrying more than one million gallons of crude through the CA counties of Butte, Contra Costa, Lassen, Modoc, Placer, Plumas, Sacramento, San Joaquin, and Yuba.8 The same information from Union Pacific Railroad has not been made public by the state of CA. The route shown in the figure to the right has been mapped in the FracTracker Alliance’s California Crude Shipment Routes and Railroad Accidents map above. From the map, you can see that there have been numerous accidents already on this BNSF rail line, particularly near Stockton and in the heavily populated North Bay Area.

References

  1. California Office of Emergency Services. 5/6/14. Historical HazMat Spill Notifications. Accessed 3/8/15.
  2. Douglas E. 6/16/14. 2 States Beef Up Oil-by-Rail and Pipeline Safety After String of Accidents. Inside Climate News. Accessed 3/9/15.
  3. Interagency Rail Safety Working Group. 6/10/14. Oil by Rail Safety in California. California Office of Emergency Services.
  4. Bailey D. 6/2014. It Could Happen Here: The Exploding Threat of Crude by Rail in California. Natural Resources Defense Council. Accessed 3/10/15.
  5. Reis E & Coughlin A. 6/6/2014. New Proposed Oil Transportation Calls for Rational, Risk-Based Mitigation Approach. Hinman Consulting Engineers. Accessed 3/11/15
  6. Bizjak T. 6/16/14. California to impose fee on crude oil rail shipments; funds to be used for spill prevention, cleanup. The Sacramento Bee. Accessed 3/10/15.
  7. U.S. DOT. 5/7/2014. Emergency Order. Docket No. DOT-OST-2014-0067. Accessed 3/10/15.
  8. California Public Utilities Commission. 2015. Railroad Safety and Operations. Accessed 3/8/15.
  9. U.S. DOT. 9/30/14. Re: U.S. Department of Transportation Emergency Order Docket Number DOT-OST-2014-0067 (Issued May 7, 2014). Accessed 3/10/15.
Washington Co. Production Layout

A Closer Look at PA’s Unconventional Production Data

By Matt Kelso, Manager of Data and Technology

Twice per year, the Pennsylvania Department of Environmental Protection (PADEP) releases its unconventional oil and gas production and waste reports, which is a good opportunity to check on what’s happening with the industry as a whole. In the past, FracTracker has analyzed this data as soon as it became available. That strategy proved to be a mistake, however, as it is common for some of the operators to release data after the deadline, meaning that early versions of the report can be incomplete. To mitigate the effects of late reporting, the data in this analysis was downloaded from the PADEP on March 10, 2015, several weeks after the reports were first published.

While the production and waste reports are released together, and appear together on the same map below, the FracTracker Alliance will analyze the data from these two reports in separate blogs, with this one focusing on PA’s unconventional production data.


PA Unconventional O&G Production and Waste – July 1, 2014 to December 31, 2014. Click here to access the full screen map, with legend, details, and additional controls.

Producing Wells

The production report lists the amount of gas produced per well in thousands of cubic feet (Mcf), as well as oil and condensate totals in 42 gallon barrels. Also included are the spud date and the number of days that each well produced in each of the three categories. This allows us to take a look at how the age of the well factors into its daily production rates:

Average daily production values for PA unconventional wells between July and December 2014, sorted by year well was spudded.

Figure 1: Average daily production values for PA unconventional wells between July and December 2014, sorted by year well was spudded.

The average daily production values in Figure 1 were calculated from all wells reporting production for the given commodity type. For example, of the 1,467 wells on the report with a spud date in 2010, 1,221 (83.2%) of those produced some gas in the latest reporting period, and the average daily production of that group is 1,300 Mcf. Only 102 wells spudded that same year reported condensate production, averaging 6 barrels per day, and 35 wells produced oil, also averaging 6 barrels per day. It’s also worth pointing out that the majority of wells drilled last year were not yet in production for the reporting period.

Wells drilled in 2013 produced 38% less gas than wells those drilled in 2014, and the newer wells are producing 4.4 times as much as wells drilled in 2010.

Average daily production (Mcf) for unconventional wells in PA between July and December 2014, sorted by spud year.

Figure 2: Average daily production (Mcf) for unconventional wells in PA between July and December 2014, sorted by spud year.

In Pennsylvania, gas production amounts are quite high, while liquid hydrocarbon returns are fairly modest. In this six month period, operators reported 2.13 trillion cubic feet of gas production, 2.1 million barrels of condensate, and 171 thousand barrels of oil. Over 71% of all oil was produced in Washington County in Southwestern Pennsylvania, while other counties in the western part of the state made up the rest of the production. Washington County also accounts for 94% of all condensate produced from the state’s unconventional wells.

FracTracker wanted to see if there were any liquid production trends when we sorted the data by operator. Of the 1,146 active wells on the report in Washington County, 769 (67%) are operated by Range Resources Appalachia, LLC. Their wells produced 1,955,302 barrels (97%) of the condensate in the county, meaning that the remaining 377 wells from other operators produced a combined 50,915 barrels of condensate.

At first, it seems a bit anomalous that all of the other producers in the county should have such low a total for condensate. Some of this is likely attributable to defining the difference between condensate and oil. The way the data are presented, it seems as if they are two separate liquid hydrocarbon products. However, the difference really amounts to the liquid’s density, with heavier, thicker fluids considered to be oil, while condensates occupy the lighter, less viscous end of the spectrum. Condensate is also legal to export, while crude oil is not.

Oil and condensate production in Washington County from July to December 2014, by operator.

Figure 3: Oil and condensate production in Washington County from July to December 2014, by operator.

With this in mind, when we look at the liquid production in Washington County over the six month period, it seems likely that what Range Resources considered to be condensate was classified as oil by Chesapeake. The complete lack of liquid hydrocarbon production by any of the 259 wells operated by CNX, Rice, or EQT in the county does seem curious at first, but none of the three operators are active in any of the six municipalities reporting 100,000 or more barrels of liquids. Unconventional liquid hydrocarbon production in Washington County – and PA for that matter – is limited geographically, with the highest returns limited to a handful of municipalities close to the northern panhandle of West Virginia.


Unconventional wells reporting liquid production in Washington County from July to December 2014. Among unconventional wells in Pennsylvania, those in Washington County accounts for over 71% of oil production and 94% of condensate production.

Non-Producing Wells

Spudded PA Unconventional wells not producing - July to December 2014

Figure 4: Spudded PA Unconventional wells not producing – July to December 2014

Altogether, there are 2,351 wells on the production report that are listed as spudded but are not producing any of the three commodity types. The report includes a section for operators to explain why there is no production, as well as data about the well’s status. The reason that the majority of these wells are not producing are relatively straightforward; they are either plugged, have an inactive status, are not yet complete, or are shut-in, awaiting a pipeline connection.

In prior discussions with PADEP, active wells were described to us as those that had been spudded and not yet permanently plugged. There are also some conditions that can put the well into an inactive status at the operator’s request, for up to five years.

Figure 5: Operators with the most unconventional active wells that are not in production – excluding observation wells, those that were not completed during the reporting period, or those that are shut-in, awaiting additional infrastructure.

Still, there are a number of active wells that don’t fall into any of these categories, leaving us with no clear idea as to why they are not producing. The 10 operators with with the most active wells not in production – excluding observation, incomplete, and shut-in wells – are listed in Figure 5: Chevron, Chief, Southwestern, Cabot, and Anadarko.

Included in the statewide totals are three wells listed as having the incorrect operator, 32 wells where the reason for no production is listed as “Plugged well” but the well status is active, and 339 wells with active statuses where the reason for no production was left blank. Two operators, Chevron Appalachia and Chief Oil & Gas, account for 46% of these wells where the reason for non-production is uncertain.

 

Population Near Railroads in Allegheny County, PA

By Matt Kelso, Manager of Data and Technology

In a joint project with PennEnvironment earlier this month, we analyzed the number of people who live within a half-mile of active rail lines in Pennsylvania and are therefore potentially at risk of an oil train explosion similar to the recent ones in Lac-Mégantic, Quebec; Lynchburg, Virginia; and Mount Carbon, West Virginia. To take that project one step further, we have taken a closer look at the population near railroads in Allegheny County, the second most populous county in PA with over 1.2 million inhabitants. Of the various figures, we found that Pittsburgh has over 183,000 people that live with half-mile mile of an active rail line.

In Philadelphia, the city’s boundary takes up the entire county of the same name, but in Allegheny County, the municipal boundaries are considerably more fractured. In fact, Pittsburgh is just one of 130 municipalities in Allegheny County; its 305,704 inhabitants represent just 25% of the residents in the county, and 13% of the metropolitan area. For the sake of simplicity, residents from the various cities, boroughs, and townships in the county will often say they are from Pittsburgh when speaking with people from outside the region, although they might actually live in Blawnox, McKees Rocks, or Swissvale, for example.


Estimated population within a half-mile of active rail lines in Allegheny County, PA. Click here to access the legend and other map tools.

Here is a list of the top ten municipalities with the largest estimated population in the at-risk zone:

Municipalities in Allegheny County with the largest estimated population within a half-mile of railroads.

Municipalities in Allegheny County with the largest estimated population within a half-mile of railroads.

Not surprisingly, the most at-risk municipality in Allegheny County is Pittsburgh, with over 183,000 people living within a half-mile of an active rail line. During any given workday, when individuals flock into the city, even more individuals would theoretically be at risk of an oil train disaster. Following Pittsburgh, Baldwin, West Mifflin, and Shaler all share similar numbers at risk, with Baldwin seeing the greatest percentage of its population at risk of the three. While Castle Shannon and Carnegie have lower populations than the other municipalities, a significant proportion of their residents (93-95%) are near rail lines.

Organic farms near drilling activity in the U.S. and Ohio

The US Food, Energy, Water Interface Examined
By Ted Auch, Great Lakes Program Coordinator

With the emergence of concerns about the Food, Energy, Water (FEW) intersection as it relates to oil and gas (O&G) expansion, we thought it was time to dig into the numbers and ask some very simple questions about organic farms near drilling. Below is an analysis of the location and quantity of organic farms with heavy drilling activity in Ohio and nationally. Organic farms rely heavily on the inherent/historical quality of their soils and water, so we wanted to understand whether and how these businesses closest to O&G drilling are being affected.

Key Findings:

  1. Currently 11% of US organic farms are within US O&G Regions of Concern (ROC). However, this number has the potential to balloon to 15-31% if our respective shale plays and basins are exploitated, either partially or in full,
  2. 68-74% of these farms produce crops in states like California, Ohio, Michigan, Pennsylvania, and Texas,
  3. Issues such as soil quality, watershed resilience, and water rights are likely to worsen over time with additional drilling.

Methods

To answer this broad question, we divided organic farms in the United States into three categories, depending on whether they were within the:

  1. Core (O&G Wells < 1 mile from each other),
  2. Intermediate (1-3 miles between O&G Wells), or
  3. Periphery (3-5 miles between O&G Wells) of current activity or Regions of Concern (ROC).1

Additionally, from our experience looking at O&G water withdrawal stresses within the largely agrarian Muskingum River Watershed in OH we decided to add to the ROCs. To this end we worked to identify which sub-watersheds (5-10 miles between O&G Wells) and watersheds (10-20 miles between O&G Wells) might be affected by O&G development.

Together, distance from wells and density of development within particular watersheds make up the 5 Regions of Concern (ROCs) (Table 1).

Table 1. Five ROCs under this investigation and what they look like from a mapping perspective

Label Distance Between Wells Mapping Visual
Core < 1 mi  Table1_1
Intermediate 1-3 mi
Periphery 3-5 mi  Table1_2
Sub-Watershed 5-10 mi  Table1_3
Watershed 10-20 mi

We generated a dataset of 19,515 US organic farms from the USDA National Organic Program (NOP) by using the Geocode Address function in ArcGIS 10.2, which resulted in a 100% match for all farms.2

We also extracted soil order polygons within the above 5 ROCs using the NRCS’ STATSGO Derived Soil Order3 dataset made available to us by Sharon Whitmoyer at the USDA-NRCS-NSSC-Geospatial Research Unit and West Virginia University. For those not familiar with soil classification, soil orders are analogous to the kingdom level within the hierarchy of biological classification. Although, in the case of soils there are 12 soil orders compared to the 6 kingdoms of biology.

The National Organic Farms Map

This map shows organic farms across the U.S. that are located within the aforementioned ROCs. Data include certifying agent, whether or not the farm produces livestock, crops, or wild crops along with contact information, farm name, physical address, and specific products produced. View map fullscreen

National Numbers

Figure 1. Total and incremental number of US organic farms in the 5 O&G ROCs.

Figure 1. Total and incremental number of US organic farms in the 5 O&G ROCs.

Nationally, the number of organic farms near drilling activity within specific regions of concern are as follows (as shown in Figure 1):

  • Watershed O&G ROC – 2,140 organic farms (11% of North American organic farms)
  • Sub-Watershed O&G ROC – 1,319
  • Periphery O&G ROC – 752
  • Intermediate O&G ROC – 455
  • Core O&G ROC – 183

Ohio’s Organic Farms Near Drilling

The following key statistics stood out among the analyses for OH’s 703 (3.6% of US total) organic farms. Figures 2 & 3 show how many farms are near drilling activity and injection (disposal) wells in OH. Click the images to view fullsize graphics:

 Figure 2. OH Organic Farms Proximity to Drilling Activity

Figure 2. OH Organic Farms Proximity to Drilling Activity

 Figure 3. OH Organic Farms Proximity to Injection (Disposal) Wells

Figure 3. OH Organic Farms Proximity to Injection Wells

Potential Trends

If oil and gas extraction continues along the same path that we have seen to-date, it is reasonable to expect that we could see an increase in the number of organic farms near this industrial activity. A few figures that we have worked up are shown below:

  • 2,912 Organic Farms in the US Shale Plays (15% of total organic farms)
    • 2,044 Crop Producers, 918 Livestock operations, 41 Wild Crops
  • 6,179 in US Shale Basins (31%)
    • California, 1,334; Colorado 297; Illinois 286; Indiana 334; Iowa 239; Michigan 504; Missouri 118; New York 834; Ohio 510; Pennsylvania 449; Texas 394; Wisconsin 271
    • 4,100 Crop Producers, 1,386 Livestock operations, 61 Wild Crops
  • 1,346 in US Tight Gas Plays (7%)
    • 948 Crop Producers, 434 Livestock operations, 22 Wild Crops
  • 2,754 in US Tight Gas Basins (14%)
    • 2,010 Crop Producers, 875 Livestock operations, 48 Wild Crops

Soils at Risk Due To Shale Activity

Another way to look at these five ROCs when asking how shale gas build-out will interact with and/or influence organic farming is to look at the soils beneath these ROCs. What types of activity do they currently support? The productivity of organic farms, as well as their ability to be labeled “organic,” are reliant upon the health of their soils even more so than conventional farms. Organic farms cannot rely on synthetic fertilizers, pesticides, herbicides, or related soil amendments to increase productivity. Soil manipulation is prohibitive from a cost and options perspective. Thus, knowing what types of soils the shale industry has used and is moving towards is critical to understanding how the FEW dynamic will play out in the long-term. There is no more important variable to the organic farmer sans freshwater than soil quality and diversity.

The soils of most concern under this analysis are the Prairie-Forest Transition soils of the Great Lakes and Plains, commonly referred to as Alfisols, and the Carbon-Rich Grasslands or Mollisols (Figure 4 & 5). The latter is proposed by some as a soil order worthy of protection given our historical reliance on its exceptional soil fertility and support for the once ubiquitous Tall Grass Prairies. Both soils face a second potential wave of O&G development, with a combined 18,660 square miles having come under the influence of the O&G industry within the Core ROC and an additional 58-108,000 square miles in the Intermediate and Periphery ROCs. If the watersheds within these soils and O&G co-habitat were to come under development, total potential Alfisol and Mollisol alteration could reach 273,200 square miles. This collection of soils currently accounts for 43-47% of the Core and Intermediate O&G ROCs and would “stabilize” at 50-51% of O&G development if the watersheds they reside in were to see significant O&G exploration.

Figure 4. Prairie-Forest Transition soil - Courtesy EarthOnlineMedia

Figure 4. Prairie-Forest Transition soil – Courtesy EarthOnlineMedia

Figure 5. Carbon-Rich Grasslands soil - Courtesy USDA’s NRCS

Figure 5. Carbon-Rich Grasslands soil – Courtesy USDA’s NRCS

Figure6_BakkenSoils

Figure 6. The five soil orders within the Bakken Shale formation in Montana and North Dakota.

These same soils sit beneath or have been cleared for much of our wheat, corn, and soybean fields – not to mention much of the Bakken Shale exploration to date (Figure 6, above)

The three forest soil orders (i.e., Spodosol, Ultisol, and Andisol shown in Figures 7-9) account for 9,680-20,529 square miles of the Core and Intermediate O&G ROCs, which is 22 and 17% of those ROC’s, respectively. If we assume future exploration into the Periphery and Watershed ROC we see that forest soils will become less of a concern, dropping to 14-15% of these outlying potential plays, with the same being true for the two Miscellaneous soil types. The latter will decline from 28% to 25% of potential O&G ROCs.

Figure 7. Ultisol, - Courtesy of the University of Georgia

Figure 7. Ultisol – Courtesy of the University of Georgia

Figure 8. Spodosol - Courtesy of the Hubbard Brook Experimental Forest

Figure 8. Spodosol – Courtesy of the Hubbard Brook Experimental Forest

Figure 9. Andisol – Courtesy of USDA’s NRCS

Figure 9. Andisol – Courtesy of USDA’s NRCS

Figure 10. Histosol, - Courtesy of Michigan State University

Figure 10. Histosol, – Courtesy of Michigan State University

If peripheral exploration were to be realized, another soil type will have to fill this gap. Our analysis demonstrates this gap would be filled by either Organic Wetlands or Histosols, which currently constitute <200 and 529 square miles of the Core and Intermediate ROCs, respectively (Figure 10). For so many reasons wetland soils are crucial to the maintenance and enhancement of ecosystem services, wildlife migration, agricultural productivity, and the capture and storage of greenhouse gases. However, if O&G exploration does expand to the Periphery ROC and beyond we would see reliance on wetland soils increase nearly 15 fold (i.e., 16% of Lower 48 wetland soil acreage).

The quality of these wetlands is certainly up for debate. However, what is fact is that these wetlands would be altered beyond even the best reclamation techniques. We know from the reclamation literature that the myriad difficulties associated with reassembling prior plant wetland communities. Finally, it is worth noting that a similar uptick in O&G reliance on arid (i.e., extremely unproductive but unstable) soils is may occur with future industry expansion. These soils will, as a percent of all ROCs, increase from 7% to 9% (i.e. 10-11% of all lower 48 arid soil acreage).

What do these changes mean for the agriculture industry in OH?

If these future O&G exploration scenarios were to play out, we estimate 20-22% of Southern Acidic Forest, Prairie-Forest Transition, Miscellaneous Recent Origin, and Carbon-Rich Grassland soils will have been effected or dramatically altered due to O&G land-use/land-cover (LULC) change nationally (Figure 11). This decline in productivity is likely familiar to communities currently grappling with how to manage a dramatically different landscape post-shale introduction in counties like Bradford in PA and Carroll in OH. The effects that such alteration has had and will have on landscape productivity, wildlife habitat fragmentation, and hydrological cycles is unknown but worthy of significant inquiry.

These questions are important enough to have received a session at Ohio Ecological Food and Farming Association’s (OEFFA) 2015 conference in Granville last month and were deemed worthy of a significant grant to The FracTracker Alliance from the Hoover Foundation aimed at quantifying the total LULC footprint of the shale gas industry across three agrarian OH counties. Early results indicate that every acre of well-pad requires 5.3 acres of gathering lines along with nearly 14 miles of buried pipelines – most of which are beneath high quality wetlands. This study speaks to the potential for 20-30% of the state’s Core Utica Region – or 10-15% of the Expanded Utica Region4 – being altered by shale gas activity.

Figure 11. National distribution of soil types within the 5 ROCs under consideration: 1) Forest Soils, 2) Prairie/Agriculture soils, 3) Organic Wetlands, 4) Miscellaneous soils, 5) Dry Soils.

Figure 11. National distribution of soil types within the 5 ROCs under consideration: 1) Forest Soils, 2) Prairie/Agriculture soils, 3) Organic Wetlands, 4) Miscellaneous soils, 5) Dry Soils.

Figure 11 Description:

  • Forest Soils – Northern and Southern Acidic Forests, Volcanic Forests,
  • Prairie/Agriculture – Prairie-Forest Transition and Carbon-Rich Grasslands,
  • Organic Wetlands
  • Miscellaneous – Recent and Intermediate Origins,
  • Dry Soils – Dry Calcium Carbonite and Clay-Rich Shrink/Swell Clays

Conclusion

The current and potential interaction(s) between the O&G and organic farming industries is nontrivial. Currently 11% of US organic farms are within what we are calling O&G ROCs. However, this number has the potential to balloon to 15-31% if our respective shale plays and basins are exploited, either partially or in full. Most of these (68-74%) are crop producers in states like California, Ohio, Michigan, Pennsylvania, and Texas.

Issues such as soil quality – specifically Prairie-Forest, Carbon Rich Grasslands, and Wetland soils – watershed resilience, and water rights are likely to become of more acute regional concern as the FEW interactions become increasingly coupled. How and when this will play out is anyone’s guess, but its play out is indisputable. Agriculture is going to face many staunch challenges in the coming years, as the National Science Foundation5 wrote:

The security of the global food supply is under ever-increasing stress due to rises in both human population and standards of living world-wide. By the end of this century, the world’s population is expected to exceed 10 billion, about 30% higher than today. Further, as standards of living increase globally, the demand for meat is increasing, which places more demand on agricultural resources than production of vegetables or grains. Growing energy use, which is connected to water availability and climate change, places additional stress on agriculture. It is clear that scientific and technological breakthroughs are needed to produce food more efficiently from “farm to fork” to meet the challenge of ensuring a secure, affordable food supply.

References and Endnotes

  1. The above regions were determined by generalizing a compilation of Oil & Gas wells generated by FracTracker’s Matt Kelso last March: Over 1.1 Million Active Oil and Gas Wells in the US.
  2. An additional 69 organic farms were geo-referenced in Canada and 7,524 across the globe for a similar global analysis to come.
  3. Description of STATSGO2 Database and associated metadata here.
  4. Core Utica Regions include any county that has ≥10 Utica permits to date and Expanded Utica Region includes any county that has 1 or more Utica permits.
  5. By the Mathematical and Physical Sciences Advisory Committee – Subcommittee on Food Systems in “Food, Energy and Water: Transformative Research Opportunities in the Mathematical and Physical Sciences”

11% of organic farms near drilling in US, potentially 31% in future

By Juliana Henao & Samantha Malone, FracTracker Alliance

Currently, 11% (2,140 of 19,515 total) of all U.S. organic farms share a watershed with active O&G drilling. Additionally, this percentage could rise up to 31% if unconventional O&G drilling continues to grow.

Organic farms represent something pure for citizens around the world. They produce food that gives people more certainty about consuming chemical-free nutrients in a culture that is so accustomed to using pesticides, fertilizers, and herbicides in order to keep up with booming demand. Among their many benefits, organic farms produce food that is high in nutritional value, use less water, replenish soil fertility, and do not use pesticides or other toxic chemicals that may get into our food supply. To maintain their integrity, however, organic farms have an array of regulations and an extensive accreditation process.

What does it mean to be an organic farm?

The accreditation process for an organic farm is quite extensive. USDA organic regulations include:

  • The producer must manage plant and animal materials to maintain or improve soil organic matter content in a manner that does not contribute to contamination of crops, soil, or water by plant nutrients, pathogenic organisms, heavy metals, or residues of prohibited substance.
  • No prohibited substances can be applied to the farm for a period of 3 years immediately preceding harvest of a crop
  • The farm must have distinct, defined boundaries and buffer zones, such as runoff diversions to prevent the unintended application of a prohibited substance to the crop or contact with a prohibited substance applied by adjoining land that is not under organic management.

There are additional regulations that pertain to crop pest, weed, and disease standards; soil fertility and crop nutrient management standards; seeds and planting stock practice standards; and wild-crop harvesting practice standards, to name a few. A violation of any one of these USDA regulations can mean a hold on the accreditation of an organic farm.

The full list of regulations and requirements can be found here.

Threats Posed by Oil & Gas

Nearby oil and gas drilling is one of many threats to organic farms and their crop integrity. With a steady expansion of wells, the O&G industry is using more and more land, requiring significant quantities of fresh water, and emitting air and water pollution from sites (both in permitted and unpermitted cases). O&G activity could not only affect the quality of the produce from these farms, but also their ability to meet the USDA’s organic standards.

To see how organic farms and the businesses surrounding wells are being affected, Ted Auch analyzed certain dynamics of organic farms near drilling activity in the United States, and generated some key findings. His results showcase how many organic farms are at risk now and in the future if O&G drilling expands. Below we describe a few of his key findings, but you can also read the entire article here.

Key Findings – Organic Farms Near Oil & Gas Activity

Explore this dynamic map of the U.S. organic farms (2,140) within 20 miles of oil & gas drilling. To view the legend and see the map fullscreen, click here.

Of the 19,515 U.S. organic farms in the U.S., 2,140 (11%) share a watershed with oil and gas activity – with up to 31% in the path of future wells in shale areas. Why look at oil and gas activity at the watershed level? Watersheds are key areas from which O&G companies pull their resources or into which they emit pollution. For unconventional drilling, hydraulic fracturing companies need to obtain fresh water from somewhere in order to frack the wells, and often the local watershed serves as that source. Spills can and do occur on site and in the process of transporting the well pad’s products, posing risks to soils and waterways, as well.

Figure 1, below, demonstrates the number of organic farms near active oil & gas wells in the U.S. – broken down by five location-based Regions of Concern (ROC).

Farm-Chart1

Figure 1: Total and incremental numbers of US organic farms in the 5 O&G Regions of Concern (ROC).

The most at-risk farms are located in five states: California, Ohio, Michigan, Texas and Pennsylvania. Learn more about the breakdown of the types of organic farms that fall within these ROCs, including what they produce.

Out of Ohio’s 703 organic farms, 220 organic farms are near drilling activity, and 105 are near injection (waste disposal) wells.

Conclusion

More and more O&G drilling is being permitted to operate near organic farms in the United States. The ability for municipalities to zone out O&G varies by state, but there is currently no national restriction that specifically protects organic farms from this industrial activity. As the O&G industry expands and continues to operate at such close proximities to organic farms in the US, there are a variety of potential impacts that we could see in the near future. The following list and more is explained in further detail in Auch’s research paper:

  • A complete alteration in soil composition and quality,
  • A need to restore wetland soils that are altered beyond the best reclamation techniques,
  • A dramatic decline in organic farm and land productivity,
  • A changing landscape,
  • Wildlife habitat fragmentation, and
  • Watershed resilience … to name a few.

PA feature image taken by Sara Gillooly, 2013

Danger Around the Bend

The Threat of Oil Trains in Pennsylvania

A PennEnvironment Report – Read Full Report (PDF)

On the heels of the West Virginia oil train explosion, this new study and interactive map show populations living in the evacuation zone of a potential oil train crash.

PA Oil Train Routes Map


This dynamic map shows the population estimates in Pennsylvania that are within a half-mile of train tracks – the recommended evacuation distance in the event of a crude oil rail car explosion. Zoom in for further detail or view fullscreen.

Danger Around the Bend Summary

The increasingly common practice of transporting Bakken Formation crude oil by rail from North Dakota to points across the nation—including Pennsylvania—poses a significant risk to the health, well-being, and safety of our communities.

This risk is due to a confluence of dangerous factors including, but not limited to:

  1. Bakken Formation crude oil is far more volatile and combustible than typical crude, making it an incredibly dangerous commodity to transport, especially over the nation’s antiquated rail lines.
  2. The routes for these trains often travel through highly populated cities, counties and neighborhoods — as well as near major drinking water sources.
  3. Bakken Formation crude is often shipped in massive amounts — often more than 100 cars, or over 3 million gallons per train.
  4. The nation’s existing laws to protect and inform the public, first responders, and decision makers are woefully inadequate to avert derailments and worst-case accidents from occurring.
Lac-Mégantic derailment. Source: http://en.wikipedia.org/wiki/Lac-M%C3%A9gantic_derailment

Lac-Mégantic derailment, July 2013. Source

In the past few years, production of Bakken crude oil has dramatically increased, resulting in greater quantities of this dangerous fuel being transported through our communities and across the nation every day. This increase has led to more derailments, accidents, and disasters involving oil trains and putting local com- munities at risk. In the past 2 years, there have been major disasters in Casselton, North Dakota; Lynchburg, Virginia; Pickens County, Alabama; and most recently, Mount Carbon, West Virginia. The worst of these was the town of Lac-Mégantic, in Canada’s Quebec Province. This catastrophic oil train accident took place on July 6, 2013, killing 47 people and leveling half the town.

Oil train accidents have not just taken place in other states, they have also happened closer to home. Pennsylvania has had three near misses in the last two years alone — one near Pittsburgh and two in Philadelphia. In all three cases, trains carrying this highly volatile Bakken crude derailed in densely populated areas, and in the derailment outside of Pittsburgh, 10,000 gallons of crude oil spilled. Fortunately these oil train accidents did not lead to explosions or fires.

All of these incidents point to one fact: that unless we take action to curb the growing threat of oil trains, the next time a derailment occurs an unsuspecting community may not be so lucky.

Bakken oil train routes often travel through high-density cities and neighborhoods, increasing the risk of a catastrophic accident for Pennsylvania’s residents. Reviewing GIS data and statewide rail routes from Oak Ridge National Laboratory, research by FracTracker and PennEnvironment show that millions of Pennsylvanians live within the potential evacuation zone (typically a half-mile radius around the train explosion ). Our findings include:

  • Over 3.9 million Pennsylvania residents live within a possible evacuation zone for an oil train accident.
  • These trains travel near homes, schools, and day cares, putting Pennsylvania’s youngest residents at risk. All told, more than 860,000 Pennsylvania children under the age of 18 live within the 1⁄2 mile potential evacuation zone for an oil train accident.
  • Philadelphia County has the highest at-risk population — Almost 710,000 people live within the half-mile evacuation zone. These areas include neighborhoods from the suburbs to Center City.
  • 16 of the 25 zip codes with the most people at risk — the top percentile in the state — are located in the city of Philadelphia.
  • The top five Pennsylvania cities with the most residents at risk are:
    • Philadelphia (709869, residents),
    • Pittsburgh (183,456 residents),
    • Reading (70,012 residents),
    • Scranton (61,004 residents), and
    • Erie (over 51,058 residents).
Read full report

Danger Around The Bend

 

Bakken Crude Oil

How we get it and why we ship it

Bakken crude oil comes from drilling in the Bakken Formation, located in North Dakota. It contains deposits of both oil and natural gas, which can be accessed by hydraulic fracturing, or “fracking.” Until recent technological developments, the oil contained in the formation was too difficult to access to yield large production. But advances in this extraction technology since 2007 have transformed the area into a major oil producer — North Dakota now ranks second in the U.S. for oil production. The vast expansion of wells over the last 4 years (from 470 wells to over 3,300 today) means that there is more oil to transport to the market, both domestically and abroad. This increase is especially concerning considering that the U.S. Department of Transportation stated in early 2014 that Bakken crude oil may be more flammable than traditional crude, therefore making it more dangerous to transport by rail.

For More Information

Shale Gas Development on Public Lands

By Mark Szybist and George Jugovic, Jr., PennFuture Guest Authors

Citizens for Pennsylvania’s Future (PennFuture) and FracTracker Alliance have collaborated to create a unique GIS map that enables the public to investigate how shale gas development is changing the face of our public lands. The map allows viewers to see, in one place:

  • Pennsylvania’s State Forests, Parks and Game Lands;
  • State Forest tracts containing active oil and gas leases;
  • State Forest areas where the oil and gas rights have been “severed” from the surface lands and are owned by third parties;
  • State Forest lands that are to be protected for recreational use under the federal Land and Water Conservation Fund Act;
  • The location of unconventional shale gas wells that have been drilled on State Forest and State Game Lands; and
  • The boundaries of watersheds that contain one or more High Quality or Exceptional Value streams.

The goal of this project was to develop a resource that would highlight the relationship between unconventional shale gas development and public resources that the State holds in trust for Pennsylvania’s citizens under Article I, Section 27 of the Pennsylvania Constitution. It is our hope that the map will be useful to citizens, conservation groups and others in planning educational, advocacy, and recreational activities.

The Public Lands Map


A full screen version of The Public Lands Map can be found here.

Background

Public lands held in trust by the Commonwealth of Pennsylvania for citizens of the state are managed by various state agencies and commissions. The vast majority of State lands, though, are managed by just two bodies – the Department of Conservation and Natural Resources (DCNR) and the Pennsylvania Game Commission (PGC). Under Act 147 of 2012, the Department of General Services has the authority to lease other lands controlled by the state. In recent years, DCNR and the PGC have made liberal use of their powers to lease State lands for oil and gas development.

DCNR: State Forests, State Parks, and Publicly Owned Streambeds

The DCNR manages approximately 2.2 million acres of State Forest lands and 283,000 acres of State Park lands, as well as many miles of publicly owned streambeds. The Conservation and Natural Resources Act (CNRA) authorizes DCNR to develop oil, gas and other minerals under these lands, so long as the state controls those mineral rights. In some cases, separate persons or entities own the surface of the land and mineral rights. Where DCNR does not control the mineral rights, the owners of the oil and gas have the ability to make reasonable use of the land surface for mineral extraction, subject to restrictions in their property deeds.

Before the start of the Marcellus era, the DCNR leased about 153,268 acres of State Forest lands for mineral development. These leases largely allowed the drilling of “conventional” shallow vertical gas wells. Between 2008 and 2010, the DCNR, under Governor Ed Rendell, leased another 102,679 acres of public lands for natural gas development – but this time the leases were for the drilling of horizontal wells in “unconventional” shale formations using high-volume hydraulic fracturing.

Following the lease sale, DCNR published a report on October 26, 2010 that stated any further gas leasing of State Forest Lands would jeopardize the sustainability of the resource. As a result, Governor Rendell signed Executive Order 2010-05, which placed a moratorium on the sale of any additional leases for oil and gas development on lands “owned and managed by DCNR.

On May 23, 2014, Governor Tom Corbett revoked Governor Rendell’s moratorium, and issued a new Executive Order that allowed the issuance of additional leases for gas development beneath State Lands so long as the leases did not entail “additional surface disturbance on State Forest or State Park lands.” Ultimately, Governor Corbett’s DCNR did not enter into any leases under the new Order. However, between January 2011 and January 2015, Governor Corbett’s DCNR did issue leases for gas extraction beneath a number of publicly owned streambeds, which, according to the Post-Gazette, raised $19 million. Governor Corbett’s DCNR also renewed at least one State Forest lease that otherwise would have expired.

On January 29, 2015, Governor Tom Wolf issued another Executive Order on the matter, which re-established a moratorium on the leasing of State Park and State Forest lands “subject to future advice and recommendations by DCNR.” The Order allows for the continued leasing of publicly owned streambeds. As of the publication of this blog, the DCNR is fighting two lawsuits concerning the leasing of the lands it manages, one by the Pennsylvania Environmental Defense Foundation and one by the Delaware Riverkeeper Network.

Drilling in Loyalsock State Forest, PA. Photo by Pete Stern 2013

Drilling in Loyalsock State Forest, PA. Photo by Pete Stern 2013.

PGC: State Game Lands

The PGC manages more than 1.5 million acres of State Game Lands that it may lease for gas development under the Pennsylvania Game and Wildlife Code. The PGC can also exchange mineral rights beneath State Game Lands for “suitable lands having an equal or greater value.” To date, the PGC has entered into surface and non-surface leases (technically, cooperative agreements for the exercise of oil and gas production rights) for natural gas development totaling 92,000 acres, of which about 45,000 acres were leased since 2008.

Land and Water Conservation Fund Act Lands

The LWCF Act is a federal law administered by the National Park Service (NPS) that authorizes federal grants to state and local governments for “outdoor recreation.” When a state accepts money for a recreational project, it agrees to protect the recreational value of the area supported by the grant. If the state later decides to take or allow actions that would “convert” parts of the protected area to a non-recreational use (1) the state must seek prior approval from the NPS, and (2) the NPS must perform an environmental assessment of the proposed conversion under the National Environmental Policy Act. The NPS may approve a conversion of LWCF-supported lands only if those lands will be replaced with “other recreation properties of at least equal fair market value and of reasonably equivalent usefulness and location.”

Between 1978 and 1986, Pennsylvania received three LWCF grants (Project Numbers 42-00580, 42-01235, and 42-01351) to support recreational opportunities on State Forest lands. Most of the money was used to improve roads in various State Forests to improve access for hunters, hikers and anglers. The LWCF layer on the Public Lands map represents those areas that Pennsylvania agreed to protect in exchange for these grants.

In 2009 and 2010, Pennsylvania entered into leases opening up about 11,718 acres of LWCF-protected areas to unconventional gas development. On the map, these areas can be highlighted by selecting “Land and Water Conservation Fund Lands” and “SF Lands – DCNR Leases”; the purplish, overlapping areas represent the leased LWCF lands.

Governor Corbett’s DCNR refused to recognize that shale gas development on public lands constituted a “conversion” under the LWCF Act. The Sierra Club was the first to identify this problem in a 2011 letter to the NPS and the DCNR. That letter requested, among other things, that the NPS formally determine the extent to which DCNR leasing of LWCF-protected State Forest lands has violated the LWCF Act. Nearly four years later, the NPS has yet to determine whether drilling and fracking of unconventional gas wells and construction of the necessary support structures constitutes a “conversion” and loss of recreational opportunities under the LWCF Act.

Old Loggers Path

Old Loggers Path, a favorite among hikers

A Note on the Map Layers

The sources of the GIS layers in the Public Lands map are explained in the “Details” section of the map. For the most part, PennFuture and FracTracker obtained or created the layers from public sources and through open records requests to the DCNR. In all cases, the layers came from the DCNR with a disclaimer as to the accuracy of the data and a warning about relying on the data.

GIS layers that are not currently on the map, but that this project hopes to add, include:

  • State Game Lands that have been leased for drilling;
  • State Park and Game Lands where the oil and gas rights have been “severed” and not controlled by the State;
  • Publicly owned streambeds that the State has leased for oil and gas development;
  • Public lands containing areas of significant ecologic value; and
  • Compressor stations, natural gas and water pipelines, and fresh water and wastewater impoundments.

Persons having access to this data are invited to contact PennFuture or FracTracker.

Pennsylvania Data Discrepancies

By Matt Kelso, Manager of Data & Technology

The Pennsylvania Department of Environmental Protection (PADEP) publishes oil and gas well data in two different places: on their own website’s Spud Data Report, and in the Oil and Gas Locations file published on the PA Spatial Data Access repository, also known as PASDA. Because these two sources are both ultimately published by PADEP, it would stand to reason that the data sources would match up. Unfortunately, that is not the case. Learn more about the data discrepancies we uncovered:


This map shows those wells in Pennsylvania that only show up on one of the two data sources. Pink dots show wells that appear on PASDA but not the PADEP site, while the reverse is true for blue wells. Click here for the full screen view with additional map tools.

Methodology

Both of these data sources have existed for years. When FracTracker does analyses of PA, we usually use data directly from the PADEP site, because it includes far more information about the wells, such as the spud date, county, municipality, well configuration, and whether or not the well is classified as unconventional. Even though it has less information about each well, the data on PASDA is useful for expediently mapping the inventory of wells in the Keystone State. In this current analysis, we looked at both sources, and found significant discrepancies between the two.

Individual oil and gas wells have been given unique API numbers since the 1950’s. The overwhelming majority of items on both lists that we examined have these numbers, and those that do not have other numeric identifiers in their place. The uniqueness of the data in these columns is what we used to determine the number of wells on both lists. These columns in both data sources were then tested against one another using Microsoft Excel in order to determine which wells were included on both lists.

The data on PASDA is described as “Oil and Gas Locations,” and nothing in available metadata made it clear as to whether wells that were permitted but not yet drilled might be included in this or not. Additionally, we are mostly interested in wells that are still operational, assuming that there might be accuracy issues for historical wells in an industry that has been operational in the state since before the Civil War. We did, however, include orphaned and abandoned wells, as they remain a source of impact throughout the state.

Summary

PADEP_PASDA_descrep

Number of wells in PA in various categories. For brevity, “Total wells – Drilled and not plugged” is shown as “TW-DnP.”

We found 3,315 records of drilled, unplugged wells with location information on the PASDA dataset that are not on the PADEP search tool, and 96 such wells on the PADEP site that aren’t found on PASDA. Additionally, there are 35,434 drilled and unplugged wells in the PADEP data that lack location data, although six of these wells are actually on the PASDA site, meaning that there is some location data for them somewhere at PADEP.

For those of you who might be looking for discrepancies in our discrepancy table, one might expect the number of both wells that appear on both lists (the second to last row on the chart) to be identical. The biggest reason that they are not is that some wells appear in the PASDA dataset multiple times. There are 6,997 fewer unique wells than there are entries on the full file, or a 95.74% match rate. In comparison, the PADEP spud report only has 19 duplicates for over 204,000 wells, a 99.99% match between the number of wells and the number of records. Indeed, when we filter for unique wells, the difference between the two lists shrinks to only 40 records, which might be explained by differences is well statuses that were used to shape our analysis.

This chart shows the number of wells drilled per year in Susquehanna County, through 2/11/15.

Number of wells drilled per year in Susquehanna Co., through 2/11/15.

Undoubtedly, it will take some effort to get the two datasets to reflect the full set of wells in PA, but that is certainly a task than can be accomplished. The wells lacking location data are likely to be much more of a challenge. If we include all status types, there are 75,508 wells on the spud report that lack latitude and longitude values altogether, leaving us with only the county and municipality to determine where these wells are located. Hopefully, this crucial data exists somewhere in the PADEP inventory, and these wells are not in fact lost.

Finally, there are a couple of things to note about dates. Since the PASDA dataset does not include spud dates, it is impossible to determine the age of the majority of the mismatched wells. Looking at the pink dots on the interactive map above, though, it is clear that a large number of these mismatched PASDA wells are in the northeastern corner of the state that has been booming since the recent development of the Marcellus, but saw little to no development before that time – at least according to the spud report.

Of the 96 wells that are on the spud report but not PASDA, 67 are given the date “1/1/1800,” which seems to be a default date; over 94,000 wells on the report have this listed as the spud date. Most of the other wells that don’t match are relatively old wells, with spud dates ranging between 1960 and 1984. One of these wells was drilled on May 6, 1999 though, and four more were drilled on August 19, 2014.

The mismatched data can be accessed here for those who are interested.