Tag Archive for: Pennsylvania

Proposed Atlantic Coast Pipeline route
Karen Edelstein

An urgent need? Atlantic Coast Pipeline Discussion and Map

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By Karen Edelstein, Eastern Program Coordinator

This article was originally posted on 10 July 2015, and then updated on 22 January 2016 and 16 February 2016.

Proposed Pipeline to Funnel Marcellus Gas South

In early fall 2014, Dominion Energy proposed a $5 billion pipeline project, designed provide “clean-burning gas supplies to growing markets in Virginia and North Carolina.” Originally named the “Southeast Reliability Project,” the proposed pipeline would have a 42-inch diameter in West Virginia and Virginia. It would narrow to 36 inches in North Carolina, and narrow again to 20 inches in the portion that would extend to the coast at Hampton Roads. Moving 1.5 billion cubic feet per day of gas, with a maximum allowable operating pressure of 1440 psig (pounds per square inch gage), the pipeline would be designed for larger customers (such as manufacturers and power generators) or local gas distributors supplying homes and businesses to tap into the pipeline along the route, making the pipeline a prime mover for development along its path.

The project was renamed the Atlantic Coast Pipeline (ACP) when a coalition of four major US energy companies—Dominion (45% ownership), Duke Energy (40%), Piedmont Natural Gas (15%), and AGL Resources (5%)— proposed a joint venture in building and co-owning the pipeline. Since then, over 100 energy companies, economic developers, labor unions, manufacturers, and civic groups have joined the new Energy Sure Coalition, supporting the ACP. The coalition asserts that the pipeline is essential because the demand for fuel for power generation is predicted more than triple over the next 20 years. Their website touts the pipeline as a “Path to Cleaner Energy,” and suggests that the project will generate significant tax revenue for Virginia, North Carolina, and West Virginia.

Map of Proposed Atlantic Coast Pipeline


View map fullscreen – including legend and measurement tools.

Development Background

Lew Ebert, president of the North Carolina Chamber of Commerce, optimistically commented:

Having the ability to bring low-cost, affordable, predictable energy to a part of the state that’s desperately in need of it is a big deal. The opportunity to bring a new kind of energy to a part of the state that has really struggled over decades is a real economic plus.

Unlike older pipelines, which were designed to move oil and gas from the Gulf Coast refineries northward to meet energy demands there, the Atlantic Coast Pipeline would tap the Marcellus Shale Formation in Ohio, West Virginia and Pennsylvania and send it south to fuel power generation stations and residential customers. Dominion characterizes the need for natural gas in these parts of the country as “urgent,” and that there is no better supplier than these “four homegrown companies” that have been economic forces in the state for many years.

In addition to the 550 miles of proposed pipeline for this project, three compressor stations are also planned. One would be at the beginning of the pipeline in West Virginia, a second midway in County Virginia, and the third near the Virginia-North Carolina state line.  The compressor stations are located along the proposed pipeline, adjacent to the Transcontinental Pipeline, which stretches more than 1,800 miles from Pennsylvania and the New York City Area to locations along the Gulf of Mexico, as far south as Brownsville, TX.

In mid-May 2015, in order to avoid requesting Congressional approval to locate the pipeline over National Park Service lands, Dominion proposed rerouting two sections of the pipeline, combining the impact zones on both the Blue Ridge Parkway and the Appalachian Trail into a single location along the border of Nelson and Augusta Counties, VA. National Forest Service land does not require as strict of approvals as would construction on National Park Service lands. Dominion noted that over 80% of the pipeline route has already been surveyed.

Opposition to the Pipeline on Many Fronts

The path of the proposed pipeline crosses topography that is well known for its karst geology feature—underground caverns that are continuous with groundwater supplies. Environmentalists have been vocal in their concern that were part of the pipeline to rupture, groundwater contamination, along with impacts to wildlife could be extensive. In Nelson County, VA, alone, 70% of the property owners in the path of the proposed pipeline have refused Dominion access for survey, asserting that Dominion has been unresponsive to their concerns about environmental and cultural impacts of the project.

On the grassroots front, 38 conservation and environmental groups in Virginia and West Virginia have combined efforts to oppose the ACP. The group, called the Allegany-Blue Ridge Alliance (ABRA), cites among its primary concerns the ecologically-sensitive habitats the proposed pipeline would cross, including over 49.5 miles of the George Washington and Monongahela State Forests in Virginia and West Virginia. The “alternative” version of the pipeline route would traverse 62.7 miles of the same State Forests. Scenic routes, including the Blue Ridge Parkway and the Appalachian Scenic Trail would also be impacted. In addition, it would pose negative impacts on many rural communities but not offset these impacts with any longer-term economic benefits. ABRA is urging for a programmatic environmental impact statement (PEIS) to assess the full impact of the pipeline, and also evaluate “all reasonable, less damaging” alternatives. Importantly, ABRA is urging for a review that explores the cumulative impacts off all pipeline infrastructure projects in the area, especially in light of the increasing availability of clean energy alternatives.

Environmental and political opposition to the pipeline has been strong, especially in western Virginia. Friends of Nelson, based in Nelson County, VA, has taken issue with the impacts posed by the 150-foot-wide easement necessary for the pipeline, as well as the shortage of Department of Environmental Quality staff that would be necessary to oversee a project of this magnitude.

Do gas reserves justify this project?

Dominion, an informational flyer, put forward an interesting argument about why gas pipelines are a more environmentally desirable alternative to green energy:

If all of the natural gas that would flow through the Atlantic Coast Pipeline is used to generate electricity, the 1.5 billion cubic feet per day (bcf/d) would yield approximately 190,500 megawatt-hours per day (mwh/d) of electricity. The pipeline, once operational, would affect approximately 4,600 acres of land. To generate that much electricity with wind turbines, utilities would need approximately 46,500 wind turbines on approximately 476,000 acres of land. To generate that much electricity with solar farms, utilities would need approximately 1.7 million acres of land dedicated to solar power generation.

Nonetheless, researchers, as well as environmental groups, have questioned whether the logic is sound, given production in both the Marcellus and Utica Formations is dropping off in recent assessments.

Both Nature, in their article Natural Gas: The Fracking Fallacy, and Post Carbon Institute, in their paper Drilling Deeper, took a critical look at several of the current production scenarios for the Marcellus Shale offered by EIA and University of Texas Bureau of Economic Geology (UT/BEG). All estimates show a decline in production over current levels. The University of Texas report, authored by petroleum geologists, is considerably less optimistic than what has been suggested by the Energy Information Administration (EIA), and imply that the oil and gas bubble is likely to soon burst.

Natural Gas Production Projections for Marcellus Shale

Natural Gas Production Projections for Marcellus Shale

David Hughes, author of the Drilling Deeper report, summarized some of his findings on Marcellus productivity:

  • Field decline averages 32% per year without drilling, requiring about 1,000 wells per year in Pennsylvania and West Virginia to offset.
  • Core counties occupy a relatively small proportion of the total play area and are the current focus of drilling.
  • Average well productivity in most counties is increasing as operators apply better technology and focus drilling on sweet spots.
  • Production in the “most likely” drilling rate case is likely to peak by 2018 at 25% above the levels in mid-2014 and will cumulatively produce the quantity that the Energy Information Administration (EIA) projected through 2040. However, production levels will be higher in early years and lower in later years than the EIA projected, which is critical information for ongoing infrastructure development plans.
  • The EIA overestimates Marcellus production by between 6% and 18%, for its Natural Gas Weekly and Drilling Productivity reports, respectively.
  • Five out of more than 70 counties account for two-thirds of production. Eighty-five percent of production is from Pennsylvania, 15% from West Virginia and very small amounts from Ohio and New York. (The EIA has published maps of the depth, thickness and distribution of the Marcellus shale, which are helpful in understanding the variability of the play.)
  • The increase in well productivity over time reported in Drilling Deeper has now peaked in several of the top counties and is declining. This means that better technology is no longer increasing average well productivity in these counties, a result of either drilling in poorer locations and/or well interference resulting in one well cannibalizing another well’s recoverable gas. This declining well productivity is significant, yet expected, as top counties become saturated with wells and will degrade the economics which have allowed operators to sell into Appalachian gas hubs at a significant discount to Henry hub gas prices.
  • The backlog of wells awaiting completion (aka “fracklog”) was reduced from nearly a thousand wells in early 2012 to very few in mid-2013, but has increased to more than 500 in late 2014. This means there is a cushion of wells waiting on completion which can maintain or increase overall play production as they are connected, even if the rig count drops further.
  • Current drilling rates are sufficient to keep Marcellus production growing on track for its projected 2018 peak (“most likely” case in Drilling Deeper).

Post Carbon Institute estimates that Marcellus predictions overstate actual production by 45-142%. Regardless of the model we consider, production starts to drop off within a year or two after the proposed Atlantic Coast Pipeline would go into operation. This downward trend leads to some serious questions about whether moving ahead with the assumption of three-fold demand for gas along the Carolina coast should prompt some larger planning questions, and whether the availability of recoverable Marcellus gas over the next twenty years, as well as the environmental impacts of the Atlantic Coast Pipeline, justify its construction.

Next steps

The Federal Energy Regulatory Commission, FERC, will make a final approval on the pipeline route later in the summer of 2015, with a final decision on the pipeline construction itself expected by fall 2016.

UPDATE #1: On January 19, 2016, the Richmond Times-Dispatch reported that the United States Forest Service had rejected the pipeline, due to the impact its route would have on habitats of sensitive animal species living in the two National Forests it is proposed to traverse.

UPDATE #2: On February 12, 2016, Dominion Pipeline Company released a new map showing an alternative route to the one recently rejected by the United States Forest Service a month earlier. Stridently condemned by the Dominion Pipeline Monitoring Coalition as an “irresponsible undertaking”, the new route would not only cross terrain the Dominion had previously rejected as too hazardous for pipeline construction, it would–in avoiding a path through Cheat and Shenandoah Mountains–impact terrain known for its ecologically sensitive karst topography, and pose grave risks to water quality and soil erosion.

Northeast Ohio Class II injection wells taken via FracTracker's mobile app, May 2015
Ted Auch, PhD

OH Class II Injection Wells – Waste Disposal and Industry Water Demand

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By Ted Auch, PhD – Great Lakes Program Coordinator

Waste Trends in Ohio

Map of Class II Injection Volumes and Utica Shale Freshwater Demand in Ohio

Map of Class II Injection Volumes and Utica Shale Freshwater Demand in Ohio. Explore dynamic map

It has been nearly 2 years since last we looked at the injection well landscape in Ohio. Are existing disposals wells receiving just as much waste as before? Have new injection wells been added to the list of those permitted to receive oil and gas waste? Let’s take a look.

Waste disposal is an issue that causes quite a bit of consternation even amongst those that are pro-fracking. The disposal of fracking waste into injection wells has exposed many “hidden geologic faults” across the US as a result of induced seismicity, and it has been linked recently with increases in earthquake activity in states like Arkansas, Kansas, Texas, and Ohio. Here in OH there is growing evidence – from Ashtabula to Washington counties – that injection well volumes and quarterly rates of change are related to upticks in seismic activity.

Origins of Fracking Waste

Furthermore, as part of this analysis we wanted to understand the ratio of Ohio’s Class II waste that has come from within Ohio and the proportion of waste originating from neighboring states such as West Virginia and Pennsylvania. Out of 960 Utica laterals and 245+ Class II wells, the results speak to the fact that a preponderance of the waste is coming from outside Ohio with out-of-state shale development accounting for ≈90% of the state’s hydraulic fracturing brine stream to-date. However, more recently the tables have turned with in-state waste increasing by 4,202 barrels per quarter per well (BPQPW). Out-of-state waste is only increasing by 1,112 BPQPW. Such a change stands in sharp contrast to our August 2013 analysis that spoke to 471 and 723 BPQPW rates of change for In- and Out-Of-State, respectively.

Brine Production

Ohio Class II Injection Well trends In- and Out-Of-State, Cumulatively, and on Per Well basis (n = 248).

Figure 1. Ohio Class II Injection Well trends In- and Out-Of-State, Cumulatively, and on Per Well basis (n = 248).

For every gallon of freshwater used in the fracking process here in Ohio the industry is generating .03 gallons of brine (On average, Ohio’s 758 Utica wells use 6.88 million gallons of freshwater and produce 225,883 gallons of brine per well).

Back in August of 2013 the rate at which brine volumes were increasing was approaching 150,000 BPQPW (Learn more, Fig 5), however, that number has nearly doubled to +279,586 BPQPW (Note: 1 barrel of brine equals 32-42 gallons). Furthermore, Ohio’s Class II Injection wells are averaging 37,301 BPQPW (1.6 MGs) per quarter over the last year vs. 12,926 barrels BPQPW – all of this between the initiation of frack waste injection in 2010 and our last analysis up to and including Q2-2013. Finally, between Q3-2010 and Q1-2015 the exponential increase in injection activity has resulted in a total of 81.7 million barrels (2.6-3.4 billion gallons) of waste disposed of here in Ohio. From a dollars and cents perspective this waste has generated $2.5 million in revenue for the state or 00.01% of the average state budget (Note: 2.5% of ODNR’s annual budget).

Freshwater Demand Growing

Ohio Class II Injection Well disposal as a function of freshwater demand by the shale industry in Ohio between Q3-2010 and Q1-2015.

Figure 2. Ohio Class II Injection Well disposal as a function of freshwater demand by the shale industry in Ohio between Q3-2010 and Q1-2015.

The relationship between brine (waste) produced and freshwater needed by the hydraulic fracturing industry is an interesting one; average freshwater demand during the fracking process accounts for 87% of the trend in brine disposal here in Ohio (Fig. 2). The more water used, the more waste produced. Additionally, the demand for OH freshwater is growing to the tune of 405-410,000 gallons PQPW, which means brine production is growing by roughly 12,000 gallons PQPW. This says nothing for the 450,000 gallons of freshwater PQPW increase in West Virginia and their likely demand for injection sites that can accommodate their 13,500 gallons PQPW increase.

Where will all this waste go? I’ll give you two guesses, and the first one doesn’t count given that in the last month the ODNR has issued 7 new injection well permits with 9 pending according to the Center For Health and Environmental Justice’s Teresa Mills.

Matt Kelso, BA

Unconventional Drilling Activity Down In Pennsylvania

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By Matt Kelso, Manager of Data & Technology

Wells Spudded (Drilled)

The number of newly drilled unconventional wells in Pennsylvania peaked in 2011.

Figure 1: Newly drilled unconventional wells in Pennsylvania peaked in 2011.

Unconventional oil and gas drilling is well established in Pennsylvania, with over 9,200 drilled wells, an additional 7,200 permitted locations that have not yet been drilled, and 5,300 violations all happening since the turn of the millennium. It took a while for the industry to gather steam, with just one unconventional well drilled in 2002, and only eight in 2005. But by 2010, that figure had ballooned to 1,599 wells, which was greater than the previous eight years combined. There were 1,956 wells drilled in 2011, representing the peak for unconventional drilling activity in Pennsylvania (Figure 1).

None of the three full years since then, however, have seen more than 70% of the 2011 total. Halfway through 2015, the industry is on pace to drill only 842 unconventional wells statewide, which would be the lowest total since 2009, and only 43% of the 2011 total.


Pennsylvania Shale Viewer. Click here to access the full screen view with a legend, layer details, and other tools.

Taken cumulatively, the footprint on the state is immense, as is shown in the map above, and impacts remain for some time. Of Pennsylvania’s 9,234 unconventional wells 8,187 (89%) are still active. Only 474 wells have been permanently plugged so far, with 570 given an inactive status, and one well listed as “proposed but never materialized,” despite being included on the spud report.

Permits & Violations

The number of permits and violations issued have been declining over the past five years as well.

Five years of unconventional oil and gas activity in Pennsylvania, July 2010 through June 2015.

Figure 2: Five years of unconventional oil and gas activity in Pennsylvania, July 2010 through June 2015.

Figure 2 shows the monthly totals of permits, wells, and violations over the last 60 months. Linear trendlines were added to the chart to give a visual representation of changes over time if we ignore the noise of the peaks and troughs of activity, which is an inherent attribute of the industry. Each of the three trendlines has a negative slope1, showing downward trends in each category.

In fact, permits for new wells are declining more rapidly than the drilled wells, and violations issued are declining at a still faster rate. Over the course of five years, these declines are substantial. In July 2010, the smoothed totals that are “predicted” by the trendline show 304 permits issued, 159 wells drilled, and 128 violations issued per month.  60 months later, one would expect 213 permits, 81 wells drilled, and just 12 violations issued2.

Location of Drilling Activity

The oil and gas industry has been more selective about where unconventional wells are being drilled in recent years, as well. Altogether, there are unconventional wells in 39 different counties, with 32 counties seeing action in both 2010 and 2011. That number is down to 22 for both 2014 and the first half of 2015. There has been drilling in 443 different municipalities since 2002, with a maximum of 241 municipal regions in 2011, which shrank to 161 last year, and just 88 in the first half of 2015.


Summary of unconventional wells drilled in each Pennsylvania county by year, through June 30, 2015. Click here to access the full screen view with a legend, layer details, and other tools

Clicking on any of the counties above will show the number of unconventional wells drilled in that county by year since the first unconventional well was spudded in Pennsylvania back in 2002.  The color scheme shows the year that the maximum number of unconventional wells were drilled in each county, with blues, greens, and yellows showing counties where the activity has already peaked, oranges showing a peak in 2014, and red showing a peak in 2015, despite only six months of activity.  30 of the 39 counties with unconventional wells in the state saw a peak in activity in 2013 or before.

Notes

  1. The equations for the three trendlines are as follows:
    • Permits: y = -1.5128x + 303.81
    • Wells: y = -1.2939x + 158.95
    • Violations: y = -1.9334x + 127.53
  2. The lowest actual value for each category are as follows:
    • Permits: 117, in July 2012
    • Wells: 43, in February 2015
    • Violations: 16, in August 2014.
Matt Kelso, BA

Utica Drilling in Pennsylvania

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In Pennsylvania, the vast majority of unconventional oil and gas activity is focused on the Marcellus Shale formation, a Devonian period deposit of black shale with a high hydrocarbon content, which requires horizontal drilling and large scale hydraulic fracturing to produce enough oil and gas to make the drilling economically viable.  This formation was created about 390 million years ago, when organic-rich deposits accumulated in what is now the Appalachian Mountains, but was at that time a shallow sea.  Down below the base of the Marcellus lies the Utica Shale, an Ordovician period formation, with almost the same geographic extent as the Marcellus, but the deposits were placed there about 65 million years earlier.


Utica permits and violations in Pennsylvania. Click here to access the legend and other map tools.

In neighboring Ohio, it is the Utica that gets most of the attention, with 937 permitted wells, as opposed to just 20 for the Marcellus.  In Pennsylvania, the reverse is true:  there are 16,110 permitted Marcellus wells, but only 279 permits for Utica wells.  Part of the reason for this is because the subsurface characteristics of these formations vary widely, especially in terms of thickness and depth.  With changes in depth come changes in temperature and pressure, which are key criteria in hydrocarbon formation.  In other words, the same formation that produces considerable quantities of gas and valuable liquid hydrocarbons in eastern Ohio may be economically unviable just a county or two over in western Pennsylvania.

Utica shale permits, drilled wells, violations, and violations per well for Pennsylvania, through June 19, 2015.

Utica shale permits, drilled wells, violations, and violations per well for Pennsylvania, through June 19, 2015.

Utica drilling permits have been issued in 19 different counties in Pennsylvania, with wells having been drilled in 15 of those.  The violations per well (VpW) score for Utica wells in the Keystone State is 0.9, meaning that there are nine violations issued for every 10 wells that have been drilled.  It is worth noting, however, that only 36 of the 114 drilled wells have received violations, meaning that some wells have been cited on multiple occasions.

Of particular note is Bradford county, the site of only one Utica well, but 19 items on the compliance report.  The problematic Bayles 1 well was run by three different operators before being permanently plugged.  This well also has two “Drill Deeper” permits, and as a result, it is likely that the first six violations assessed to this well were issued before it was associated with the Utica Shale, as they precede the most recent spud date for the well in June, 2005.  Most of the violations for this well seem to be for pit violations and discharges to the ground and nearby stream.

Wells drilled into the Utica Formation in Pennsylvania, by year and current status.

Wells drilled into the Utica Formation in Pennsylvania, by year and current status.

In terms of drilling activity, it appears to have peaked in 2012, calling into question whether the industry considers the formation to be economically viable in Pennsylvania.  Of the 28 wells drilled since the beginning of 2014, Tioga County has seen the most activity with 11 wells drilled, followed by five wells in Butler County, then three in Lawrence County.  If we think of drilling activity as a sort of positive feedback from the industry – meaning that they like what they see and want to keep exploring – then only Tioga County seems to be holding the attention of the various operators who have been active in the Utica Shale.  Given the Utica activity in Ohio, one might have thought that counties on the western edge of the state – especially Beaver, Lawrence, and Mercer – would have shown the most promise, but this appears not to be the case.

Landfill disposal of drill cuttings
FracTracker Alliance

Has radioactivity risk from oil and gas activity been underrated?

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Reviewing a Pennsylvania TENORM Study

By Juliana Henao, Communications Intern

Technologically-enhanced, naturally-occurring radioactive materials, also known as TENORM, are produced when radionuclides deep in the earth are brought to the surface by human activity such as oil and gas drilling. The radioactive materials, which include uranium (U), thorium (th), potassium-40 (K-40) and their decay products, occur naturally in the environment. These materials are known to dissolve in produced water, or brine, from the hydraulic fracturing process (e.g. fracking), can be found in drilling muds, and can accumulate in drilling equipment over time.

According to the EPA, ~30% of domestic oil and gas wells produce TENORM. Surveys have shown that 90% of the wells show some TENORM concentrations, while others have nothing at all. However, with increasing natural gas exploration and production in Pennsylvania’s Marcellus Shale, there is a parallel increase in TENORM. According to Dr. Marvin Resnikoff, an international expert on radiation, drilling companies and geologists locate the Marcellus Shale layer by way of its higher level of radiation.

Bringing more of this TENORM to the surface has the potential to greatly impact public health and the environment. Since 2013, the Pennsylvania Department of Environmental Protection (PA DEP) has been gathering raw data on TENORM associated with oil and gas activity in the state. The study was initiated due to the volume of waste containing high TENORM concentrations in the state’s landfills, something that is largely unregulated at the state and federal level.  In January 2015, the PA DEP released a report that outlined their findings and conclusions, including potential exposures, TENORM disposal practices, and possible environmental impacts.

Radioactivity Study Overview

Drilling mud being collected on the well pad

This review touches on the samples tested, the findings, and the conclusions drawn after analysis. The main areas of concern included potential exposure to workers, members of the public, and the environment.

The samples gathered by the DEP came from 38 well sites, conventional and unconventional, by testing solids, liquids, ambient air, soils, and natural gas near oil and gas activity in Pennsylvania. All samples contained TENORM or were in some way impacted by TENORM due to oil and gas operations. The samples were mainly tested for radioactive isotopes, specifically radium, through radiological surveys.

The PA DEP concluded in the cases of well sites, wastewater treatment plants (POTW), centralized wastewater treatment plants, zero liquid discharge plants, landfills, natural gas in underground storage, natural gas fired power plants, compressor stations, natural gas processing plants, radon dosimetry (the calculation and assessment of the radiation dose received by the human body), and oil and gas brine-treated roads that there is little potential for internal radiation exposure to workers and members of the public. In spite of this, each section of the report typically concluded with: however, there is a potential for radiological environmental impacts…

Examples of these findings include:

  • There is little potential for radiological exposure to workers and members of the public from handling and temporary storage of produced water on natural gas well sites. However, there is a potential for radiological environmental impacts from spills of produced water from unconventional natural gas well sites and from spills that could occur from the transportation of this fluid.
  • There is little potential for radiological exposure to workers and members of the public from sediment-impacted soil at landfills that accepted O&G waste for disposal.  However, there may be a radiological environmental impact to soil from the sediments from landfill leachate treatment facilities that treat leachate from landfills that accept O&G waste for disposal.
  • Radium 226 was detected within the hydraulic fracturing fluid ranging from 64.0-21,000 pCi/L. Radium-228 was also detected ranging from 4.5-1,640 pCi/L. The hydraulic fracturing fluid was made up of a combination of fresh water, produced water, and reuse flowback fluid. There is little potential impact for radiological exposure to workers and members of the public from handling and temporary storage of flowback fluid on natural gas well sites. However, there is a potential for radiological environmental impacts from spills of flowback fluid on natural gas well sites and from spills that could occur from the transport of this fluid.
  • Nine influent and seven effluent leachate samples were collected at the nine selected landfills.  Radium was detected in all of the leachate samples. Radium-226 concentrations were detected in produced water samples ranging from 40.5 – 26,600 pCi/L. Radium-228 concentrations were also detected ranging from 26.0 – 1,900 pCi/L. The Ra-226 activity in unconventional well site produced water is approximately 20 times greater than that observed in conventional well site produced water. The ratio of Ra-226 to Ra-228 in unconventional well site produced water is approximately eight times greater than that found in conventional well site produced water.  (Sections 3.3.4 and 3.6.3) (PA DEP TENORM study report section 9.0)

According to Melody Fleck from Moshannon Group- Sierra Club Executive Committee:

While the report comprehensively covers the processes from drilling to end users, the number of samples collected and analyzed are very sparse for a state-wide study. Just to give an idea, only 8 well sites were sampled during the flowback phase and of the 8 only 4 had enough volume to analyze. Of 14 drill mud samples collected, only 5 were analyzed as liquids, and alpha & beta analysis was only done on one sample.

Obtaining the proper sample size is often a major barrier for field studies. Additional research needs to be conducted with a larger sample size and more rigorous exposure monitoring to determine specific risk metrics for workers and the public.

Current Handling of TENORM

From drilling to distribution, there are many topics of concern associated with TENORM; however, we will focus on the current treatment of TENORM waste, the release of data, and the transparency of this issue.

On a federal level, there are no specific regulations governing many aspects of TENORM, such as sludge or solids containing TENORM from water treatment plants. Additionally, if concentrations of U or Th make up less than .05% by weight, they are seen as an “unimportant quantity” and are exempt from NRE regulation. Currently, 13 states regulate TENORM with varying degrees of standards. Hazardous waste facilities in each state can choose to accept TENORM materials as long as they don’t exceed certain concentrations.

Today, about 12 of PA’s 50 landfills accept such radioactive waste from oil and gas activity at a 1:50 dilution ratio (related to their other intake sources). Under RCRA’s Land Disposal Restrictions, “dilution is prohibited as treatment for both listed and characterized wastes.”

According to the DEP report, hydraulic fracturing produces an enormous stream of waste by-products. Safe disposal of this waste has not yet been devised. A few of the conclusions concerning TENORM disposal and treatment in the report listed some areas of concern, identified below:

  1. Filter cake [1] and its radiological environmental impact if spilled, and
  2. The amount of radioactive waste entering the landfills in PA, which reached 430,317 tons in the first 10 months of 2014.

In unison with the conclusions were recommendations, where the report “recommends considering limiting radioactive effluent discharge from landfills, and adding radium-226 and radium-228 to annual sample analysis of leachate from landfills.” Additionally, the report states that if something such as filter cake spills, it will bring into question the safety of long-term disposal and suggest a protocol revision.

Public Health Concerns

The report identified two places where there is a higher than average radioactive exposure risk for workers and community members of the public: specifically at centralized wastewater treatment plants and zero liquid discharge plants that treat oil and gas wastewater. An additional unknown is whether there is a potential inhalation or ingestion hazard from fixed alpha and beta surface radioactivity if materials are disturbed. As a general precaution, they recommend the evaluation of worker’s use of protective equipment under certain circumstances.

Although research has not come to a consensus regarding a safe level of radiation exposure, it should not be assumed that any exposure is safe. Past research has evaluated two types of radiation exposure: stochastic and non-stochastic, both of which have their own risks and are known to be harmful to the human body. The EPA has defined stochastic effects as those associated with long-term, low level exposure to radiation, while non-stochastic effects are associated with short-term, high-level exposure. From past scientific research, radiation is known to cause cancer and alter DNA, causing genetic mutations that can occur from both stochastic and non-stochastic exposure. Radiation sickness is also common, which involves nausea, weakness, damage to the central nervous system, and diminished organ function. Exposure levels set by the EPA and other regulatory agencies fall at 100 millirem (mrem) per year to avoid acute health effects. As a point of reference, medical X-rays deliver less than 10 mrem, and yearly background exposure can be about 300 mrem.

In the report, Radiological Dose and Risk Assessment of Landfill Disposal of TENORM in North Dakota, Argonne National Laboratory researchers suggest that the exposure to workers be limited and monitored. In many of their studies, they found the doses exceed the 100 mrem/year level in the workers when the appropriate attire is not worn during working hours, which raised some concern.

The DEP deems certain radiation levels “allowable”, but it should be noted that allowable doses are set by federal agencies and may be arbitrary. Based on the PA DEP’s report, consumers of produced gas can get up to 17.8% of their yearly radiation allowance, while POTW workers could get up to 36.3% of their yearly allowable dose. According to the Nuclear Information and Resource Service, radiation bio-accumulates in ecosystems and in the body, which introduces a serious confounder in understanding the risk posed by a dose of 17.8% per year.

Transparency of Radiation Risk

The DEP has been gathering data for their TENORM report since 2012. In July of 2014, Delaware Riverkeeper Network filed a Right-to Know request to obtain the information that the DEP had collected in order for their expert to analyze the raw data. The department refused to release the information, insisting that “the release of preliminary invalidated data, including sample locations, could likely result in a substantial and demonstrable risk of physical harm, pose a security risk and lead to erroneous and/or misleading characterizations of the levels and effects of the radioactive risks.” Essentially, the DEP was equating the risks of radioactive material to the risks of releasing raw data — two incomparable risks. DRN appealed, claiming that they simply sought the raw information, which is presumed public unless exempt, and would have no risk on the public. PA DEP was ordered to release their records to DRN within 30 days.

Conclusion

One observation that you could take from this report is the lack of regulatory advancement. The study is filled with suggestions, like:

  • Radium should be added to the PA spill protocol to ensure cleanups are adequately characterized,
  • A limited potential was found for recreationists on roads with oil and gas brine from conventional natural gas wells–further study should be conducted, and
  • More testing is needed to identify areas of contamination and any area should be cleaned up.

Intent doesn’t make the changes; action does. Will any regulations change, at least in Pennsylvania where radioactive materials are returning to the surface on a daily basis? There seems to be no urgency when it comes to regulating TENORM and its many issues at the state level. Are workers, citizens, and the environment truly being protected or will we wait for a disaster to spur action?

Footnotes:

[1] This is the residue deposited on a permeable medium when a slurry, such as a drilling fluid, is forced against the medium under pressure. Filtrate is the liquid that passes through the medium, leaving the cake on the medium.

Washington Co. Production Layout
Matt Kelso, BA

A Closer Look at PA’s Unconventional Production Data

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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.

 

Matt Kelso, BA

Population Near Railroads in Allegheny County, PA

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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.

FracTracker Alliance

Danger Around the Bend

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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

Guest Author

Shale Gas Development on Public Lands

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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.

Matt Kelso, BA

Pennsylvania Data Discrepancies

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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.