The majority of FracTracker’s posts are generally considered articles. These may include analysis around data, embedded maps, summaries of partner collaborations, highlights of a publication or project, guest posts, etc.

Danger Around the Bend

March 2, 2015/by FracTracker Alliance

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:

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.
The routes for these trains often travel through highly populated cities, counties and neighborhoods — as well as near major drinking water sources.
Bakken Formation crude is often shipped in massive amounts — often more than 100 cars, or over 3 million gallons per train.
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

Report written by David Masur and Chloe Coffman – PennEnvironment Research & Policy Center
Data compiled by Brook Lenker, Matt Kelso, and Samantha Malone – FracTracker Alliance
Media Contact – Stephen Riccardi, 810-599-3763, stephen@pennenvironment.org
Protocol for Recording Bakken Crude Trains in your community – Read more

Shale Gas Development on Public Lands

February 25, 2015/by Guest Author

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.

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, 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.

Name that oil and gas storage container [quiz]

February 17, 2015/by Guest Author

By Bill Hughes, WV Community Liaison

We were recently asked if there is a reliable way to determine what constituents are being housed in certain types of oil and gas storage containers. While there is not typically a simple and straightforward response to questions like this, some times we can provide educated guesses based on a few photos, placards, or a trip to the site.

One way to become better informed is to follow the trucks. The origins of the trucks will determine whether the current stage in the extraction process is drilling or fracturing (the containers cannot be for both unless they are delivering fresh water). Combine that with good side-view photos of the trucks will tell you if they are heavier going into the site or heavier leaving. Look for the clearance between the rear tires and the frame. Tanker trucks can typically carry 4000 gallons or 100 barrels.

For a quick guide to oil and gas storage containers, see the “quiz” we have compiled below:

Storage Container Quiz

1. What is in this yellow tank?

Q1: Photo 1

Q1: Photo 2 (same tank zoomed in)

Answer: This yellow 500-barrel wheelie storage tank in photos 1 and 2 is a portable storage tank, identified in the placard in photo 2 as having held oil base drill mud at one time. Drillers prefer to keep certain tanks identified for specific purposes if at all possible. This is especially true if they have paid extra to get a tank “certified clean” to use for fresh water storage. A certified clean tank does not mean that the water is potable (drinkable).

Other storage containers that hold fresh water are shown below:

Shark Tanks

Shark Tanks from the sky

2. What is this truck transporting?

Q2: Truck

Answer: This type of truck is normally used to haul solid waste – such as drill cuttings going to a landfill. Some trucks, however do not make it the whole way to the landfill before losing some of their contents as shown below.

Truck spill in WV

3. How about these yellow tanks?

Q3: Photo 1

Q3: Photo 2

Answer: The above storage containers are 500-barrel liquid storage tanks, also called “frac” tanks.

In photo 2 you can see that at least one tank is connected to others on either side of it. In this case you need to look at the overall operation to see what process is occurring nearby — or what had just finished — to determine what might be in the container presently.

The name plate on photo 1 says “drill mud,” which means that at one time that container might have held exactly that. Now, however, that container would likely have very little to do with drilling waste or drill cuttings. The “GP” and the number on the sign refers to Great Plains and the tank’s number. These type of tanks do not have official placards on them for the purposes of DOT labeling since they are never moved with any significant liquid in them.

4: What about these miscellaneous tanks?

Q4: Photo 1 – Tank farm with 103 blue tanks

Q4: Photo 2 – Red tanks with connecting hoses

Q4: Photo 3 – Red tanks, no connections

Answer: There is no way to know – unless you have been closely following the process in your neighborhood and know the current stage of the well pad’s drilling process. Tank farms are usually just for storage unless there is some type of filtering and processing equipment on site. The drilling crews (for either horizontal or vertical wells) do not mix their fluids with the fracturing crew. That does not mean that one tank farm could not store a selection of flowback brine—or produced water, or drilling fluids. They would be stored in separate tanks or tank groups that are connected together – usually with flex hoses.

Since I am in the area often, I know that the tanks in photos 1 and 2 were storing fresh water. Both sets were associated with a nearby hydraulic fracturing operation, which has very little to do with the drilling process. You will never see big groups of tanks like this on a well pad that is currently being drilled.

The third set of tanks with no connections on an in-production well pad are probably just empty and storing air – but not fresh air. These tanks are just sitting there, waiting for their next assignment – storage only, not in use. Notice that there are no connecting pipes like in photo 2. The tanks in photo 3 could have held any of the following: fresh water, flowback, brine, mixed fracturing fluids, or condensate. Only the operator would know for certain.

Is Carroll Co. truly the king of Ohio’s Utica counties?

February 16, 2015/by Ted Auch, PhD

Yes and No…

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

We know from the most recent Ohio Department of Natural Resources (ODNR) permitting numbers that Carroll County, Ohio is home to 26% (461 of 1,778) of the state’s Utica permits and 43% (312 of 712) of all producing wells as of the end of Q3-2014¹ (Figure 1). But does that mean that the county will continue to see that kind of industrial activity for the foreseeable future? The primary question we wanted to ask with this latest piece is whether the putative “king” of the state’s Utica shale gas counties is indeed Carroll County.

Fig 1. Ohio’s Utica Permits within & adjacent to the Muskingum River Watershed as of February, 2015

To do this we compiled an inventory of annual (2011-2012) and quarterly OH shale gas production numbers for 721 laterals throughout southeast OH.

Permitting and production numbers are not necessarily part and parcel to determine if Carrol Co is truly the king. We decided to investigate the production data and do a simple compare and contrast with the rest of the state’s 409 laterals on one side (ROS) and the 312 Carroll laterals on the other – focusing primarily on days of production and resulting oil, gas, and brine (Table 1 and infographic below).

Carroll vs. ROS Results

Permitting Numbers Breakdown

Monthly and cumulative Utica Shale permitting activity in Carrol County, OH vs. the Rest of State (ROS) between September 2010 and January 2015

Fig 2. Monthly & cumulative Utica Shale permitting activity in Carrol County, OH vs. the ROS between September 2010 & January 2015

Between the initial permitting phase of September 2010 and January 2105 the number of Utica Shale permits issued in the ROS has averaged 29 per month vs. 10 per month in Carroll County. Permitting actually increased twofold in the ROS in the last 12 months (Figure 2). Conversely, permitting in Carroll County seems to have reached some sort of a steady state, with monthly permitting declining by 23% in the last 12 months. Carroll’s Utica permits generally constituted 47% of all permitting in OH but more recently has dipped to 44%. Newer areas of focus include Belmont, Guernsey, Noble, and Columbiana counties, just to name a few.

Production Days

Days in production is a proxy for road activity and labor hours. Carroll’s wells have the rest of the state beat for that metric, with an average of 292 (±188 days) days. The state average is 192 days, with significant well-to-well variability (±177 days). If we assume there was a total of 1,369 possible production days between 2011 and the end of Q3-2014, these averages translate to 21% and 14% of total possible production days for Carroll and ROS, respectively.

Oil Production

Carroll falls short of the ROS on a total and per-day basis of oil production, although the 442-barrel difference in total oil production is likely not significant. Carroll wells are producing 74 barrels of oil per day (OPD) (±73 OPD) compared to 96 OPD (±122 OPD) for the rest of the state; however, well-to-well variability is so large as to make this type of comparison quite difficult at this juncture. Fifty-seven percent of OH’s 11,361,332 barrels of Utica oil has been produced outside of Carroll County to date. This level of production is equivalent to 16,231 rail tanker cars and roughly 00.18% of US oil production between 2011 and 2013.

This number of rail tanker cars is equivalent to 6% of the US DOT-111 fleet, or 184 miles worth of trains – enough to stretch from Columbus to Pittsburgh.

Natural Gas

The natural gas story is mixed, with Carroll’s 312 wells having produced 13,430 MCF more than the ROS wells. On a per-well basis, however, the latter are producing 3,327 MCF per day (MCFPD) (±3,477 MCFPD) relative to the 2,155 MCFPD (±1,264 MCFPD) average for Carroll’s wells. Yet again, well-to-well variability – especially in the case of the 409 ROS wells – is high enough that such simple comparisons would require further statistical analysis to determine whether differences are significant or not.

The natural gas produced here in OH currently amounts to roughly 00.51% of U.S. Natural Gas Marketed Production, according to the latest data from the EIA.

Waste – Brine

From a waste generation point of view, the ROS laterals have produced 41 more barrels of brine per day (BPD) than the Carroll laterals and 1,465 BPD since production began in 2011. On a per-day basis, the ROS laterals are producing more oil than waste at a rate of 1.92 barrels of oil per barrel of brine waste. Conversely, since production began these respective sums result in Carroll County laterals having produced 1.56 barrels of oil for every barrel of brine vs. the 1.40 oil-to-brine ratio for the ROS. Finally, it is worth noting that the 7,775,130 barrels of brine produced here in OH amounts to 13% of all fracking waste processed by the state’s 235+ Class II Injection wells.

What do these figures mean?

As we begin to compare OH’s Utica Shale expectations vs. reality we see that the “sweet spot” of the play is truly a moving target. The train seems to have already left – or is in the process of leaving – the station in Carroll County (Figures 3 and 4). It seems two of the most important questions to ask now are:

How will this rapidly shifting flow of capital, labor, and resources affect future counties deemed the next best thing? and
What will be left in the wake of such hot money flows?

Answers to these questions will be integral to the preparation for the inevitable sudden or slow-and-steady decline in shale gas activity. These dropouts are just the most recent in a long line of boom-bust cycles to have been foisted on Southeast OH and Appalachia. Effects will include questions regarding watershed resilience, local and regional resource utilization (Figures 5 and 6), social cohesion, tax-base uncertainty, roads, and a rapidly changing physical landscape.

Whether Carroll County can maintain its perch on top of the OH shale mountain is far from certain, but whether it will have to begin to – or should have already – prepare for the downside of this cliff is fact based on the above analysis.

Additional Figures and Charts

Table 1. Carroll County, OH production days and production of oil, gas, and brine on a per-day basis and in total between 2011 and Q3-2014 vis à vis the “Rest of State”

Variable	Carroll (312)			Rest of State (409)
Variable	Max	Sum	Mean	Max	Sum	Mean
Total Days	914	91,193	292±188	898	78,430	192±177
Oil (Barrels)
Per Day	453	23,190	74±73	601	39,109	96±122
Total	83,098	4,838,147	15,507	129,005	6,523,185	15,949
Gas (MCF)
Per Day	6,774	672,391	2,155±1,264	18,810	1,360,923	3,327±3,477
Total	2,196,240	168,739,064	540,830	3,181,013	215,706,401	527,400
Brine (Barrels)
Per Day	941	18,516	59±87	810	40,839	100±120
Total	36,917	3,105,260	9,953	99,095	4,669,870	11,418
Oil Per Unit of Brine
Per Day			1.25			1.92
Total			1.56			1.40

Figures 3a-d. Spatial distribution of Carroll County Utica Shale production days, oil (barrels), natural gas (MCF), and brine (barrels) on a per-day basis.

Fig 3a. Spatial distribution of Carroll Co. Utica Shale production days

Spatial distribution of Carroll County Utica Shale oil (barrels) production on a per-day basis

Fig 3b. Spatial distribution of Carroll Co. Utica Shale oil (barrels) production on per-day basis

Spatial distribution of Carroll County Utica Shale natural gas (MCF) production on a per-day basis

Fig 3c. Spatial distribution of Carroll Co. Utica Shale natural gas (MCF) production on per-day basis

Fig 3d. Spatial distribution of Carroll County Utica Shale brine (barrels) production on a per-day basis

Figures 4a-d. Spatial distribution of OH Utica Shale production days, oil (barrels), natural gas (MCF), and brine (barrels) on a per-day basis.

Fig 4a. Ohio Utica Shale Total Production Days, 2011-2014

Fig 4b. Ohio Utica Shale Total Oil Production (Barrels), 2011-2014

Fig 4c. Ohio Utica Shale Total Natural Gas Production (MCF), 2011-2014

Fig 4d. Ohio Utica Shale Total Brine Production (Barrels), 2011-2014

Figures 5a-d. Histograms and Spatial distribution of OH Utica Shale total hydrochloric acid (HCl, gallons) and silica sand (tons) demands.

Fig 5a. Histogram of OH Utica Shale total Hydrochloric Acid (HCl, gallons)

Fig 5b. Spatial distribution of OH Utica Shale total Hydrochloric Acid (HCl, gallons)

Fig 5c. Histogram of OH Utica Shale total Silica Sand (10^3 Tons)

Fig 5d. Spatial distribution of OH Utica Shale total Silica Sand (Tons)

Figures 6a-b. Histograms and Spatial distribution of OH Utica Shale total resource utilization in terms of pounds per lateral.

Fig 6a. Histogram of OH Utica Shale total materials used (10^6 Pounds)

Fig 6b. Spatial distribution of OH Utica Shale total materials used (Pounds)

Endnote

1. Additionally, all of Carroll County’s permitted wells lie within the already – and increasingly so – stressed Muskingum River Watershed (MRW) which has been a significant source of freshwater for the shale gas industry courtesy of the novel pricing schemes of its managing body the Muskingum Watershed Conservancy District (MWCD) (Figure 1). Carroll laterals are requiring 5.41 million gallons per lateral Vs the state average of 6.58 million gallons per lateral.

Pennsylvania Data Discrepancies

February 11, 2015/by Matt Kelso, BA

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

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.

Tour of Visible Air Emissions

February 4, 2015/by FracTracker Alliance

Sand mining operation in Wisconsin, Photo by Ted Auch, 2013

Chieftain’s Wisconsin Frac Sand Mine Proposal

January 31, 2015/by Ted Auch, PhD

Potential Land-Cover Change and Ecosystem Services
By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

Chieftain Metals Corp, a relatively large mining company, recently proposed to develop nine silica sand mines in the Barron County, Wisconsin towns of Sioux Creek and Dovre, as well as adjacent Public Land Survey System (PLSS) parcels.¹ Here we show that the land that Chieftain is proposing to convert into one of the state’s largest collections of adjacent silica sand mine acreage (like the one shown above) currently generates $8-15 million in ecosystem services and commodities per year.

Background

Sand, often silica sand, is used in the hydraulic fracturing process of oil and gas drilling. Including sand in the frac fluid helps to prop open the small cracks that are created during fracking so that the hydrocarbons can be more easily drawn into the well. To supply the growth in the oil and gas industry, bigger and bigger sand mines are being developed with four factors being critical to this expansion:

A Map of the St. Peter Silica Sandstone Geology Across the Minnesota, Wisconsin, Illinois, Missouri, Arkansas, and Oklahoma

Figure 1. St. Peter Silica Sandstone geology across Minnesota, Wisconsin, Illinois, Missouri, Arkansas, and Oklahoma

The average shale lateral is getting longer by 50-55 feet per quarter and the average silica sand demand is increasing in parallel by 85-90 tons per lateral per quarter with current averages per lateral in the range of 3,500-4,300 tons (Note: These figures stem from an analysis of 780 and 1,120 Ohio and West Virginia laterals, respectively.)
The average silica sand mine proposal throughout the Great Lakes is increasing exponentially.
The average sand mine is targeted at non-agricultural parcels disproportionately. As an example we looked at one of the primary Wisconsin frac sand counties and found that even though 6% of the county was forested and nearly 50% was in some form of agriculture, 98.2% of the frac sand mine area was forested prior to mining. An already fragmented landscape with respect to threatened or endangered ecosystems is becoming even more so, as the price of sand hits an exponential phase and the silica industry all but abandons its positions in Oklahoma and Texas.
The primary geology of interest to the silica sand industry is the St. Peter Silica sandstone geology, which includes much of Southern Minnesota, West Central and Southern Wisconsin, as well as significant sections of Missouri and Arkansas (Figure 1).

Learn more about the fracking process

Sand Mine Proposal Land Use Footprint

To quantify the land-cover/land-use change (LULC) of these proposed mines, we extracted the parcel locations from WI DNR’s Surface Water Data Viewer using the company’s construction permit.² These parcels encompass approximately 5,671 acres along the edge of what US Forest Service calls the Eastern Broadleaf Forest (Minnesota & NE Iowa Morainal, Oak Savannah) and Laurentian Mixed Forest provinces (Southern Superior Uplands).

Using a now-defunct WI DNR program called WISCLAND we were able to determine the land-cover within the aforementioned acreage in an effort to determine potential changes in ecosystem services and watershed resilience. The WISCLAND satellite imagery was generated in 1992, so it provided a nice snapshot of what this region’s landscape looks like absent silica sand mining.

In our joining of the PLSS and WISCLAND data we determined that 2,684 acres (47%) are currently covered by forests, namely:

Mixed/Other Broad-leaved Deciduous,
with scattered patches of Sugar Maple (Acer saccharum), and
Jack Pine (Pinus banksiana) in the northeast sections (Figures 2 and 3).

Land-Cover and # of Polygons across ten land-cover catagories across the Chieftain Silica Mine Proposal

Figure 2. Chieftain silica sand mine proposal’s land-cover across 5,671 acres in Barron County, WI

Chieftain Silica Sand Mine Forest Cover Across Six Forest Types

Figure 3. Chieftain proposal’s forest cover across 5,671 acres in Barron County, WI

Forage crops and grasslands occupy 2,010 acres (35%) across 331 polygons averaging 7 acres scattered across the proposed mining area. Corn and other row crops account for 825 acres (15%) of Chieftain’s proposal, randomly distributed across the area of interest. Collectively, these land-cover types account for 22% of all polygons averaging 5.7 and 4.7 acres, respectively. Shrublands account for ≤1% of the Chieftain proposal (36 acres) averaging 3 acres spread across a mere 12 polygons (Figures 4 and 5).

Chieftain Silica Sand Mine Agricultural and Shrubland Cover Across Six Types

Figure 4. Chieftain proposal’s agricultural & miscellaneous cover across 5,671 acres, Barron County, WI

Chieftain Silica Sand Mine Cover Across Six Land-Use Types

Figure 5. Chieftain proposal’s land-cover by acreage across 5,671 acres, Barron County, WI

Chieftain Silica Sand Mine Wetland Cover Across Seven Community Types

Figure 6. Chieftain silica sand mine proposal’s wetland cover across 5,671 acres in Barron County, WI.

Seven types of forested and shrub-dominated wetlands occupy 101 acres (1.8%) of Chieftain’s PLSS parcels, with an average size of four acres spread across 49 discrete polygons. Wetlands are clustered in three sections of the proposed mining area, with the largest continuous polygons being adjacent 160 acre “Wetland, Lowland Shrub, Broad-leaved Deciduous” and 88 acre “Wetland, Emergent/Wet Meadow” polygons along the area of interest’s eastern edge (See Figure 6 right).

Land Value

In an effort to quantify the value of this aggregation of parcels we calculated annual plant and soil productivity, as well as crop productivity, in terms of tons of carbon and nitrogen³ lost using established WI forest, crop, and freshwater productivity values.^4-6

It is worth noting that the following estimates are conservative given that we were not able to determine average above/belowground ecosystem productivity values for the wetland and barren. Additionally, our estimates for crops and grasslands did not include belowground productivity estimates, which likely would increase the following estimates by 20-30%.

1. Forests

The aforementioned-forested polygons accrue 44,274-90,969 tons of aboveground CO₂. This means that if we assume the average forest in this area is 65-85 years old, the Chieftain mine proposal would potentially remove 3.3-6.8 million tons of built up CO₂ equivalents. This figure is equal to the per capita CO₂ emissions of 202,800-416,700 WI residents. The renewable wood generated on this site has a current market value of $418,516 to $654,125.

If we assume that the price of CO₂ is somewhere between $12 and $235 per ton the forested polygons within Chieftain’s proposal currently capture (remove from the atmosphere) $4-17 million worth of CO₂ annually.

Additionally, this area generates 23,262-45,447 tons of CO₂ via soil processes such as litter decomposition and root production (i.e., 1.8-3.4 million tons over the average 65-85 year lifespan of these forests). The annual value of these belowground processes in terms of soil fertility (i.e., soil organic matter, nitrogen, and phosphorus) is somewhere between $569,962 and $1,029,662 or $43-77 million over the 65-85 year period used in this analysis.

2. Forage Crops and Grasslands

The 1,018 acres of forage crops are currently generating 6,526 CO₂ tons per year, which is equivalent to the per capita emissions of 400 WI residents (Note: This carbon has a current value in the range of $417,700-$848,200). The 992 acres of grasslands are capturing 6,600-12,600 tons of CO₂ per year and if we assume the average grassland parcel in WI is 5-15 years of age these polygons have captured CO₂ equivalent to the per capita emissions of 4,000-7,700 Wisconsinites. Together these two land-cover types capture $840,300-2,518,000 worth of CO₂ annually. Again it is worth noting these values do not include any accounting soil processes, which are generally 20-30% of aboveground productivity.

3. Corn, Other Row Crops, Shrublands

The 860 acres of corn, miscellaneous row crops, and shrublands are currently generating 10,450-10,980 CO₂ tons per year, which is equivalent to the per capita emissions of 640-670 WI residents. Using the same assumptions about time in grassland (i.e., average Conservation Reserve Program (CRP) tenure) and the 65-85 year assumption used for forests for shrublands we estimate these three land-cover types annually capture CO₂ equivalent to the per capita emissions of 8,600-11,030 Wisconsinites. Together these three land-cover types capture $682,420-1,498,030 worth of CO₂ annually.

The total average value of commodities produced on the 1,843 acres of cropland is $462 per acre or $851,272 annually.

4. Open Waters

This small fraction of the Chieftain proposal captures 134 tons worth of CO₂ annually with a value of $8,590-17,650.

Total Quantifiable Monetary Value

In summary, the nine Chieftain frac sand mines if approved would use land that currently generates $8.77-16.63 million in ecosystem services and commodities per year. Historical and future land-use potential valuations are generally not accounted for in mineral lease agreements. This analysis demonstrates that such values are nontrivial and should at the very least be incorporated into lease agreements, given that post-mining reclamation strategies result in lands that are 40% less productive. If these lands are converted to sand mines, their annual values would drop to $5.0-9.5 million post-development.

Questions about the impact of such operations on LULC in the Mississippi Valley are becoming more and more frequent. For example, families such as the Schultz in Trempealeau County are signing permanent conservation easements. Doing so allows them to continue farming and allocates some acreage to the restoration of oak savanna and dry prairie, considered by the WI Department of Natural Resources (DNR) as “globally imperiled” and “globally rare,” respectively.

References & Footnotes

It is worth noting that Chieftain is taking a huge gamble with this proposal. It stands to reason that such risky ventures are necessary given that the company’s share price has plummeted to $00.15 per share since its IPO days of around $5.50-6.00. These gambles could either catapult Chieftain into the frac sand mining big leagues or relegate it to the bench, however.
Chieftain Silica Sand Mine Proposal, Barron County, WI Review, page 4
We used carbon and nitrogen as their importance from a greenhouse gas (i.e., CO₂, CH₄, N₂O), biogeochemical, and soil fertility perspective is well established.
Burrows, S.N., Gower, S.T., Norman, J.M., Diak, G., Mackay, D.S., Ahl, D.E., Clayton, M.K., 2003. Spatial variability of aboveground net primary production for a forested landscape in northern Wisconsin. Canadian Journal of Forest Research 33, 2007-2018.
Klopatek, J.M., Stearns, F.W., 1978. Primary Productivity of Emergent Macrophytes in a Wisconsin Freshwater Marsh Ecosystem. American Midland Naturalist 100, 320-332.
Scheiner, S.M., Jones, S., 2002. Diversity, productivity and scale in Wisconsin vegetation. Evolutionary Ecology Research 4, 1097-1117.

Thanks to Jim Lacy at the Wisconsin Sate Cartographer’s Office, University of Wisconsin-Madison.

Regulatory Gaps for Train Spills?

January 29, 2015/by Matt Kelso, BA

By Matt Kelso, Manager of Data & Technology

On January 26, 2015, the Columbian, a paper in Southwestern Washington state, reported that an oil tanker spilled over 1,600 gallons of Bakken Crude in early November 2014. The train spill was never cleaned up, because frankly, nobody knows where the spill occurred. This issue highlights weaknesses in the incident reporting protocol for trains, which appears to be less stringent than other modes of transporting crude.

Possible Train Spill Routes

To follow the most likely train route for this incident, start at the yellow flag, then follow the line west. The route forks at Spokane – the northernmost route would be the most efficient. View full screen map

While there is not a good place for an oil spill of this size, some places are worse than others – and some of the locations along this train route are pretty bad. For example, the train passes through the southern edge of Glacier National Park in Montana, the scenic Columbia River, and the Spokane and Seattle metropolitan areas.

Significant Reporting Delay

The Columbian article mentions that railroads are required to report spills of hazardous materials in Washington State within 30 minutes of spills being noticed. In this case, however, the spill was apparently not noticed until the tanker car in question was no longer in BNSF custody. Therefore, relevant state and federal regulatory agencies were never made aware of the incident.

Both state and federal officials are now investigating, and we will follow up this post with more details when they are made available.

A Bird’s Eye View of Pipeline Oppositions

January 8, 2015/by FracTracker Alliance

By Samantha Malone, FracTracker Alliance

New York State is not the only area where opposition to fracking and its related activities is emerging. A 108-mile proposed PennEast pipeline between Wilkes-Barre, PA and Mercer County, New Jersey is facing municipal movements against its construction, as well. The 36-inch diameter pipeline will likely carry 1 billion cubic feet of natural gas per day. According to some sources, this proposed pipeline is the only one in NJ that is not in compliance with the state’s standard of co-locating new pipelines with an existing right-of-way.¹

PennEast Pipeline Oppositions

Below is a dynamic, clickable map of said opposition by FracTracker’s Karen Edelstein, as well as documentation associated with each municipality’s current stance:

Click here to view map and legend fullscreen.

Additional Projects and Pushback

In Ohio, many communities are working on similar projects to prevent over 40,000 miles of proposed pipelines according to recent news reports.

And in Massachusetts and New Hampshire, municipalities are working to ban, reroute, or regulate heavily the Northeast Energy Direct Pipeline (opposition map shown below):

Northeast Energy Direct Proposed Pipeline Paths and Opposition Resolutions in MA & NH

Why is this conversation important?

Participation in government is a beneficial practice for citizens and helps to inform our regulatory agencies on what people want and need. This surge in opposition against oil and gas activity such as pipelines or well pads near schools highlights a broader question, however:

If not pipelines, what is the least risky form of oil and gas transportation?

Oil and gas-related products are typically transported in one of four ways: Truck, Train, Barge, or Pipeline.

Drilling mud spill from truck accident

Lac-Mégantic oil train derailment

Using a barge to transport frac sand

Gas pipeline construction in PA forest

Trucks are arguably the most risky and environmentally costly form of transport, with spills and wrecks documented in many communities. Because most of these well pads are being built in remote areas, truck transport is not likely to disappear anytime soon, however.

Transport by rail is another popular method, albeit strewn with incidents. Several, major oil train explosions and derailments, such as the Lac-Mégantic disaster in 2013, have brought this issue to the public’s attention recently.

Moving oil and gas products by barge is a different mode that has been received with some public concern. While the chance of an incident occurring could be lower than by rail or truck, using barges to move oil and gas products still has its own risks; if a barge fails, millions of people’s drinking water could potentially be put at risk, as highlighted by the 2014 Elk River chemical spill in WV.

So we are left with pipelines – the often-preferred transport mechanism by industry. Pipelines, too, bring with them explosion and leak potential, but at a smaller level according to some sources.² Property rights, forest loss and fragmentation, sediment discharge into waterways, and the potential introduction of invasive species are but a few examples of the other concerns related to pipeline construction. Alas, none of the modes of transport are without risks or controversy.

Footnotes

Colocation refers to the practice of constructing two projects – such as pipelines – in close proximity to each other. Colocation typically reduces the amount of land and resources that are needed.
While some cite pipelines as relatively safe, incidents do occur quite often: ~1.6 incidents per day.

What is fracking fluid?

December 29, 2014/by FracTracker Alliance