Our thoughts and opinions about gas extraction and related topics

Matt Kelso, BA

Severance Tax vs. Impact Fee, Revisited

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It may not seem like it when you head to the pump, but the price of oil has plummeted in recent months. After peaking near $114 in April, the price has fallen all the way to $77.27, as of today. Natural gas, which was $4.27 last month, has fallen 15 percent since then to $3.62. Surely with all of this uncertainty, the Corbett’s proposed impact fee makes more sense than the traditional severance tax which most states use? Perhaps it would be better to take the predictable lump-sum amount than basing that portion of the state’s coffers on the vagaries of the market?

No, not really.

Corbett’s plan allows the counties to charge up to $40,000 per well per year, for a period of up to 10 years per well. According to the Post-Gazette, his administrations figures it could bring in $120 million in the first year, and up to $200 million per year by the sixth year.

Or, as I pointed out in June, we could tax like Texas. Texas imposes a 7.5% severance tax on natural gas and 4.6% tax on oil and condensate. Using yearlong production data for non Marcellus Shale wells in Pennsylvania and the average wellhead price of gas and price per barrel of liquid hydrocarbons for 2010, I estimated that non-Marcellus wells would have brought in $72.5 million if we taxed our resources just like Texas does. What’s more, based on six month production data, I showed that the wells in the Marcellus Shale formation would produce at least $173 million, for a statewide total of $246 million through all formations.

But that was before the bottom fell out of the price of oil and gas. What if we used today’s low prices as a guide?


Estimated six month severance tax from the Marcellus Shale formation in Pennsylvania.

Even with the low energy prices, that six month total is almost as much as Corbett’s administration figures to raise in a year, and it doesn’t even include the tens of thousands of wells that aren’t drilled into the Marcellus Shale.

While the proposed impact fee does more for Pennsylvania than the current nothing-at-all policy, in the scheme of things, it is a great deal for the drilling industry.

And one final aside: does it seem strange to anyone else to let the counties set the impact fee? Is this some sort of attempt to have them compete with each other to keep the prices low? If so, it seems unlikely to work in my opinion. If a county charges the maximum $40,000, that represents only about 0.8 percent of cost of a well that costs $5 million to drill, and that figure is on the low end of the spectrum. The drilling companies will want to drill where the resources are, and whatever fees or taxes are charged will not change that fact.

Matt Kelso, BA

If It’s Unsuitable For Mining, Is Drilling Advisable?

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There are a handful of watersheds, predominantly in central Pennsylvania, that the Department of Environmental Protection has deemed to be unsuitable for mining activities.

According to pages 100-101 of the Oil and Gas Operator’s Manual, a region may be determined to be unsuitable for mining if the mining operation will:

  1. be incompatible with existing State or local land use plans or programs;
  2. affect fragile or historic lands in which such operations could result in significant
    damage to important historic, cultural, scientific and esthetic values and natural
    systems;
  3. affect renewable resource lands in which such operations could result in a
    substantial loss or reduction of long-range productivity of water supply or of
    food or fiber products, and such lands to include aquifers and aquifer recharge
    areas; or
  4. affect natural hazard lands in which such operations could substantially
    endanger life and property, such lands to include areas subject to frequent
    flooding and areas of unstable geology.

Marcellus Shale Permits in Areas Unsuitable for Mining (large)
Marcellus Shale permits that were issued in areas which were deemed to be “unsuitable for mining” according to the PA DEP in 2002.

These seem like worthy goals. So if these areas are unsuitable for coal mining, why is it OK to put gas wells there?


Surface coal mine. Source: http://en.wikipedia.org/wiki/File:Coal_mine_Wyoming.jpg

Granted, drilling a well is not quite the same impact as a surface mining operation, but to protect an area from one mode of mineral extraction and not the other seems inconsistent. After all, many of the problems with coal are still relevant for gas drilling, since the drilling operator must go through the coal seam to get to the gas. The pyrite associated with the coal is still exposed to air, meaning that the drilling mud and drill cuttings probably contain sulfuric acid, the key component of acid mine drainage (AMD).

And it’s not just the drill cuttings that could be a source of problems…it could be the well bore itself. Consider the Hughes Bore Hole, which, according to Wikipedia was drilled in the 1920’s to drain underground mines in the area, then capped in the 1950’s. So what’s the big deal? In the 1970’s, pressure built up and the hole burst open, and has been spewing about 800 gallons per minute of acid mine drainage ever since.


Hughes Bore Hole releasing acid mine drainage. Source: http://en.wikipedia.org/wiki/File:Hughe%27s_Bore_Hole_071.jpg

Could drilling a gas well in the wrong place have the same effect?

Maybe to be safe we ought not drill in areas where geologists have determined that AMD could exist. That wouldn’t affect that many wells, would it?

MS Permits in Areas With AMD Potential (large)
Marcellus Shale permits in areas with acid mine drainage potential. Please click the map for a dynamic view and more information.

Oh. Well then let’s hope the well casing experts don’t have any bad days.

[Note: if you want to watch a video of Hughes Bore Hole and don’t mind salty language, click the Youtube link on the “Hughes Well Bore” link above.]

Matt Kelso, BA

Marcellus Shale Production Decline Over Time in Pennsylvania

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There are now three different Marcellus Shale production reports available on FracTracker’s DataTool:

The production data, which is self-reported by the drilling operators, is also available from the Pennsylvania Department of Environmental Protection.

In this post, we will explore the change in production from the 756 Marcellus Shale wells that reported positive (nonzero) production on each of the three reports. Of these, exactly 300 were flagged as horizontal wells on the most recent report, leaving 456 to be classified as vertical wells.

PA Marcellus Shale Production: 1-11 to 6-11 (large)
Marcellus Shale production in Pennsylvania from January to June, 2011. Please click the image to see a zoomable and dynamic map.
Caveats
It is important to note that the first of the three production cycles is for a one year period, while the other two are for six months each.  Luckily, each report includes not only production in thousands of cubic feet (Mcf), but also the number of days for which each well was in production.  Therefore, we can look at the data in terms of thousands of cubic feet per day (McfPD), which solves not only the 12 month vs. 6 month problem, but also makes sure that we aren’t comparing six months of production to just a handful of days.

One important factor that this analysis does not account for, however, is when the well first entered production. This is significant, because gas wells typically have a very high initial production, which falls steeply in the months and years ahead. This produces a hyperbolic decline curve, such as this Department of the Interior graph found on Wikipedia.

In this case, we only know that the initial production was some time since 2006 and before June 30, 2010. Add to that fact that there are only three date ranges, and the result is definitely not a proper decline curve.

Results
However, there are results, and they do show decline over time. Interestingly, there are some differences to note between horizontal and vertical Marcellus Shale wells.


Average Marcellus Shale production in thousands of cubic feet (Mcf) for wells on all three production reports.


Average Marcellus Shale production showing rates of decline.

The overall production of the sample decreased 40.7 percent from the period ending June 2010 to the one ending one year later.  Interestingly, the vertical wells are declining at a sharper rate than horizontal wells, although not dramatically so.

The chart also highlights the amazing difference in production that horizontal drilling provides to Marcellus Shale wells, with average production values 5.6 to 6.9 times higher than their vertical counterparts.

What’s Missing?
Not all of the Marcellus Shale wells from the July ’09 to June ’10 list were still reporting production for the period that ended one year later. These wells were not included in the above analysis, but are interesting in their own right:


Number of Marcellus Shale wells on the production report for the period ending June 2010 that are also reporting production one year later.

Surprisingly, the rate for horizontal wells no longer producing gas is more than twice as high as their vertical counterparts.  Does this mean that a side effect of horizontal drilling is a shorter well production life, as all of the gas is extracted faster?  We’ll have to wait and see what future data shows to find out.

FracTracker Alliance

Groundwater Contamination Debate

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The Debate: Can the process of hydraulically fracturing underground natural gas wells contaminate groundwater?

Industry Position:  There has never been a documented case of groundwater contamination due to hydraulic fracturing; the process occurs thousands of feet below drinking water aquifers. Therefore, the chemicals used in the fracturing process pose no threat to drinking water.

Opposition Position:  It can and has contributed to pollution of underground drinking water sources.

The Data:  Previous lawsuits from landowners were settled by the industry and the data kept private for various litigation reasons. A U.S. EPA report now indicates that hydraulic fracturing has been linked to at least one case of drinking water contamination in West Virginia in 1987 and could feasibly contribute to future problems.

Future Obligations:  Some improved regulations and protections have been put in place since 1987, but the risk still exists if natural gas drilling is done hastily or if abandoned wells exist nearby. Once pollutants are introduced into underground water aquifers they are very difficult to remove, so significant care and review must be taken if drilling is going to continue. The EPA report further supports the need for increased government and industry transparency across the board. It should also be stated that a large-scale health impact assessment is needed to comprehensively determine the risk that the entire natural gas drilling operation poses to public health.

Compiled by: Samantha Malone, MPH, CPH – Communications Specialist, Center for Healthy Environments and Communities (CHEC), Environmental and Occupational Health (EOH) department, University of Pittsburgh Graduate School of Public Health (GSPH); and Doctoral Student, GSPH

FracTracker Alliance

Comparing & Contrasting Extractive Industry Sectors in Ghana & the US

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By Deanna Bitetti (Common Cause) and Samantha Malone, MPH, CPH (CHEC)

In the quiet of the morning the group we have travelled to Ghana with using a grant from the US Department of State to study extractive industries find ourselves swapping stories – wistfully thinking of American life back home. We find ourselves constantly comparing and contrasting the political environment in which public policy around extractive industries are crafted in both nations. Scratch beneath the surface and you will find that Ghana and the US are not that different after all.

The pernicious influence of special interest money permeates throughout American political culture just as it does in Ghana; compulsory Integration models in the states have allowed for mineral rights to be taken from American citizens, and confusion over the leasing of mineral rights for natural gas extraction has led to uprooted communities. Environmental degradation and costs to local communities have been paramount in both the US and Ghana. These two nations separated by the Atlantic are struggling to balance new extractive industries as an engine for economic growth and protecting communities from the pitfalls associated with the “resource curse.” As both nations forge ahead in developing their oil and gas sectors, how they manage the risk associated with natural gas development will ultimately define how the citizenry thinks about the role of government and government institutions.

Below is a short comparison of some key aspects affecting constituencies in the US and Ghana.

Special Interest Influence

During a recent discussion with a local royal chief in a small village I am reminded that corporate influence is not localized to any specific nation. Here, a gold mining company publicly presents the tribal leaders of a village with keys to two Land Rovers. In America, special interest money floods campaign coffers, exceedingly so in the wake of Citizen United. According to Open Secrets individuals and political action committees affiliated with oil and gas companies have donated $238.7 million to candidates since 1990. From 2010-2011 Exxon Mobil and The Koch Brothers, one of the largest oil and gas conglomerates in the US, spent $384,030 and $318,800 respectively on campaign donations on both sides of the partisan divide to influence environmental legislation aimed at regulating the oil and gas sector. In Pennsylvania, Common Cause’s www.marcellusmoney.org has tracked the significant campaign cash contributions that have flooded campaign coffers, and in New York our recent report “Deep Drilling, Deep Pockets,” highlighted the large amounts industry has spent to lobby our elected officials.

Public Benefits for Public Good

In Ghana only 5% of royalties paid by the extractive industry sector is paid to the State. Out of that 80% of the money goes into the government’s general fund, with only 9% trickling down to effected communities. In the US, Congress has historically rewarded energy companies and those involved in the extractive industry sector with tax breaks, without tangible realization of positive benefits to communities. Nearly two-thirds of US corporations don’t pay any income taxes. According to a study from the non-partisan Government Accountability Office, 83 of the top 100 publicly traded corporations that operate in the US exploit corporate tax havens. Since 2009, America’s most profitable companies, such as ExxonMobil, General Electric, Bank of America and Citigroup, all paid a grand total of $0 in federal income taxes. Even as we write this, Congress is considering offering major subsidies to promote natural gas extraction methods and providing major tax incentives to the industry, speeding up the timeline for extraction and feeding the natural gas boom (and possibly bust) cycle.

Mineral Rights and Extraction

At the heart of the debate over natural gas extraction in the US is the right of landowners to either retain their land or sign leases with companies with the hope of negotiating lucrative contracts for their mineral rights. In Ghana, Article 257 of the Constitution states that public lands and public property are “vested in the President on the behalf of, and in trust for, the people of Ghana.” In essence, the state has claims to mineral rights, not the individual. On the surface the situation in Ghana appears anathema to American values. Forced resettlement programs of thousands of fisherman, farmers and landowners offends our notion of private property and ownership as inviolate. Yet areas in New York and Pennsylvania have allowed for Compulsory Integration where companies were granted the right to drill on lands for which they did not hold leases. Some residents that may own the surface rights but not the mineral rights experience the effects of a “split estate.” Additionally, population displacement often occurs near areas of heavy drilling either because of fear of health effects, noise or pollution, or due to harassment by companies. The important benefits and drawbacks that result from personal ownership of mineral rights must be considered seriously. Further, neither the United States or Ghana require companies to disclose the exact composition of the chemical mixtures used in the process, shrouding it in a cloud of secrecy from the public.

Externalities of Natural Gas Development

In Ghana, as farmland is turned over to industry to pave the way for rapid development, food productivity has begun decreasing – causing food and commodity prices to rise. Housing prices have been steadily increasing as foreigners flock to the areas surrounding the Jubilee oil field, causing a surge in demand for those residences. Prostitution and crime has been on the rise, as well. Even smoking has increased as foreigners bring with them new social norms. In the US we have seen similar externalities imposed on host communities by the extractive industry sector. In Pennsylvania we have already seen the rise in housing shortages due to workers being brought in from out of state, traffic incidences, and roadway degradation. Air quality concerns, drinking water contamination, and stress-related health effects are being documented. Both nations lack clear and updated standards for hazardous waste removal of drilling fluid or drill cuttings. Each country will have to address new pressures placed on transportation infrastructure, including increasing maintenance costs as new roads are created and old roads need constant repair to handle the increase in heavy truck traffic.

Public Health Issues

Residential and operational waste – regardless of its country of origin – is a common postcard to receive from the presence of extractive industries. Improperly handled waste contributes to a multitude of public health issues, such as tainted drinking water, disease transmission, air pollution, and threats to the food supply. One of the differences between Ghana and the U.S. lies in the awareness of where our waste goes. Americans are physically separated from the sources and end products of our distracted commercial lives. Trash is collected by a contractor and taken to dump sites, incinerators, or overseas. Ghanaians face their (and others’) waste on the country’s busy sidewalks, in open sewers, and floating in their magnificent waterways. They witness the neocolonial exploitation of their local resources for the imbalanced consumption and financial gain of other countries. While our processes for extraction and waste disposal differ somewhat, we share a common problem – how to reduce our demand on the entire cycle. Many of the earth’s resources are finite and severely threatened, and so sustainability must be the prescription for healthy development.

Conclusion

This list is not exhaustive, nor it is it meant to be. To move toward a best-practices model for developing extractive industry sectors and managing the high risks associated with doing so means paying close attention to the pace and scope of development, as well as attempting to ameliorate negative externalities imposed on communities. This must include mechanisms for proper oversight and regulation, sustainable planning and development, enhanced civic societal input at the decision- making table, and realistic expectations about the financial promises of oil and gas. In nations such as Ghana, managing these revenues will require more transparency and better management to ensure that revenues do not create large wealth distribution imbalances. In the US, ensuring that industry and government do not form cozy relationships that undermine independent oversight regimes is a major concern.

Deanna Bitetti is the Associate Director of Common Cause/NY. Samantha Malone is the Communications Specialist at the Center for Environmental Healthy Environments and Communities and a doctorate student in the University of Pittsburgh Graduate School of Public Health. They are currently in Ghana as part of a State Department funded research trip on resource extraction hosted by Duquesne University (Pittsburgh, Pennsylvania) and the University of Ghana (Legon, Ghana).

Matt Kelso, BA

Paid Marcellus Programming to Play in West Virginia

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Who doesn’t love a good half hour commercial? But it’s not just for OxiClean and musical compilations of 70’s disco tunes anymore–the West Virginia Oil and Natural Gas Association is getting in on the act too.

In addition to the half hour weekly episode of “Inside Shale”, in which callers ask questions of industry insiders, there will be a “Marcellus Minute” that airs 10 to 20 times per day. Both programs are scheduled to launch on 49 radio stations throughout West Virginia.

Talking about the Marcellus Shale on the radio is certainly not off limits, but the industry sponsored call in show does sound questionable, in that the format mimics a news format, and it could be confused as such.  It’s a shame that the industry didn’t push for actual moderated discussions, with guests arguing from a variety of perspectives.  That is something that there’s a real need for, not just in West Virginia, but wherever shale gas extraction is occurring.

There are real impacts of drilling.  Some people are giddy with prospective royalty checks.  Others are bitter with the presence of compressors, condensers, and fouled water wells on property that they own, but not the mineral rights for.  There’s a lot to talk about, and communities that might be affected by the industry deserve to hear both sides.

FracTracker Alliance

Data Transparency Bill Will Aid Emergency Response

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Fire in Hopewell Township PA,
Southwestern PA on 3-31-10

Earlier this week, a Pennsylvania Senate committee approved a bill that would require natural gas drilling companies to provide emergency response information to local authorities. Here are the key requirements of drilling companies that are being proposed:

  • Post emergency response information at each well site
  • Register distinct geographic coordinates for each drilling site with the PA Department of Environmental Protection and local authorities
  • File response plans with the local authorities, local 911 center, PA DEP, and PA Emergency Management Agency

Inadequate data transparency of this type has been a significant public health concern ever since natural gas drilling first began in the Marcellus Shale region in PA.Marcellus Shale sites are often drilled in rural, remote areas without exact location information or clear emergency plans. If passed into law, this legislation stands to decrease the response time in the event of an emergency at a well site, reducing the impact that drilling incidents may have on public health and the environment.

To demonstrate why improving the quality and expediency of emergency response to shale gas drilling incidents is an important endeavor, below is a map created on FracTracker’s DataTool showing only the location of violations issued by the PA DEP in 2010 to companies that were drilling into the Marcellus Shale layer. If you press “Click to see more details on this map,” you can use the DataTool to filter the dataset even further in order to see which of these violations was an environmental health and safety violation, not just administrative in nature:

(Darker diamonds indicate there was more than one violation issued in that area. Zoom in to learn more.)

Guest Author

The Devil’s Details about Radioisotopes and Other Toxic Contaminants in Marcellus Shale Flowback Fluids

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and Their Appearance in Surface Water Sources and Threats to Recreationalists, Private Well Water Users, and Municipal Water Supplies

By Conrad Dan Volz, DrPH, MPH – Director, Center for Healthy Environments and Communities, University of Pittsburgh Graduate School of Public Health

In yesterday’s FracTracker post, CHEC’s data manager Matt Kelso told the tale of two stories regarding radionuclides in Marcellus Shale flowback water and in river water as sampled by the PA DEP. As he said “the devil is in the details” and here are the “devil’s details” that put both stories into their proper public health context.
There are without doubt higher levels of radioisotopes in Marcellus Shaleflowback fluids than in the fracking fluids, which are injected under highpressure to fracture the shale layer. And in general problems related tonaturally occurring radioisotope buildup in the oil and gas industry arewell documented. The following is a passage from my expert testimony in theMatter of Delaware River Basin Commission Consolidated AdministrativeAdjudicatory Hearing on Natural Gas Exploratory Wells; Filed November23, 2010:

Elevated concentrations of naturally occurring radioactive materials(NORM), including 238U, 232Th and their progeny, are found inunderground geologic deposits and are often encountered during drillingfor oil and gas deposits (Rajaretnam G, and Spitz HB., 2000). Drill cuttingsfrom the Marcellus may be enriched in radium radionuclides and off-gas the radioelement radon. Also, the activity levels and/or availability ofnaturally occurring radionuclides can be significantly altered by processesin the oil, gas and mineral mining industries (B. Heaton and J. Lambley,2000). Scales in drilling and process equipment may become enrichedin radionuclides producing technologically enhanced naturally occurringradioactive materials (TENORM). Exposure to TENORM in drillingequipment may exceed OSHA and other regulatory authority standardsfor the protection of both human and ecological health. The occurrenceof TENORM concentrated through anthropogenic processes in soils atoil and gas wells and facilities represents one of the most challengingissues facing the Canadian and US oil and gas industry today (Saint-Fortet al., 2007). The risk of contamination of surface water and ground waterby TENORM accompanies the risk of soil contamination, as TENORMgenerated may runoff of drilling equipment during rain events or if onthe soil surface into surface water sources and/or enter groundwater bytransport through the unsaturated zone.

In a review article in Environmental Science and Technology (ES&T),authors Karbo, Wilhelm and Campbell (EPA Region III leads and Office ofRadiation and Indoor Air) stated:

New York’s Department of Environmental Conservation (NYDEC) reportedthat thirteen samples of wastewater from Marcellus Shale gas extractioncontained levels of radium-226 (226Ra) as high as 267 times the safedisposal limit and thousands of times the limit safe for people to drink.The New York Department of Health (NYDOH) analyzed three MarcellusShale production brine samples and found elevated gross alpha, grossbeta, and 226Ra in the production brine. Devonian-age shales containnaturally occurring radioactive material (NORM), such as uranium (U)and thorium (Th) and their daughter products, 226Ra and 228Ra. TheMarcellus Shale is considered to have elevated levels of NORMs. NORMsthat have been concentrated or exposed to the accessible environmentas a result of human activities, such as mineral extraction, are defined bythe EPA as technologically enhanced NORM (TENORM). TENORM maybe concentrated because of (1) temperature and pressure changes duringoil and gas production, (2) 226Ra and 228Ra in produced waters reactingwith barium sulfate (BaSO4) to form a scale in well tubulars and surfaceequipment, (3) 226Ra and 228Ra occurring in sludge that accumulates inpits and tanks, and (4) NORM occurring as radon (Rn) gas in the naturalgas stream.

If this flowback-produced water with elevated TENORM is disposed ofin sewage treatment facilities or other ineffective wastewater disposalprocesses – then the TENORM level in surface water (the receiving streamor river) will be largely determined by dilution offered by fluid flows withinthe waste plant and dilution offered by the water flows themselves in theriver or stream.

So, it is entirely possible that Marcellus Shale flowback and produced fluids(yes I hesitate to call it water because it is contaminated fluid – with manyidentified toxic contaminants; if this were coming from other industries itwould be a hazardous liquid waste) will have elevated levels of TENORM and many other contaminants (see explanation in Appendix 1 below) butlevels of TENORM in the surface water it is going into will not exceedbackground levels, seen in the stream or river system, once it is completelymixed in the stream or river.

But here is the devil in the details as Matt said in his article.Recreationalists fish and boat around these outfalls (this is documentedby CHEC in the Allegheny River Stewardship Project and the PittsburghFish Consumption Project), and we have no idea of the levels of TENORM(or other contaminants) in receiving water near the outfalls before fullriver mixing occurs. Additionally we have no idea of the level of long term bioaccumulation of TENORM (and other contaminants) in fish and otheraquatic resources that may frequent or live in areas where this material isdisposed of in.

Concentrations of TENORM and the many other contaminants in the effluent from treatment of oil and gas flowback fluids will vary in receivingstreams and rivers according to the flow of water in the receiving streamor river and their concentrations in the flowback fluids. Therefore, levels ofTENORM in receiving streams and rivers will reach a peak (everything elsebeing equal) during times of low flow – such as a drought or long periodswithout rain or snowmelt – and peak levels will be higher in the surface waternear the outfall then downstream in the river after it is mixed completelywith water flow from the stream or river. The PA DEP river water samplesfor radium were not taken during periods of low flow but during the fallseason when rain was more plentiful. Furthermore, they were not taken near outfallsof plants accepting oil and gas waste fluids for treatment, before completemixing occurs—therefore, peak levels in these areas were not captured bytheir sampling plan.

Additionally, levels of TENORM (and other contaminants) from sewagetreatment plants and inefficient brine treatment plants will be higher inlow volume streams (such as 10 Mile Creek in Greene and WashingtonCounties and Blacklick Creek in Indiana County) than in large volume riversystems like the Monongahela River. We simply don’t know what levels ofTENORM are like at peak levels in low volume streams during periods oflow flow or in areas just downstream of effluent outfalls before completemixing takes place.

CHEC has data showing that levels of bromides, barium and strontiumexiting the McKeesport POTW (a sewage treatment plant) vary over a day’s sampling; they aredependent on when the slug of produced-flowback brine is introduced intothe system and the slug’s rate of entry into the treatment system. At theMcKeesport POTW, it is customary that the slug of oil and gas waste fluidis introduced into the treatment system at 7pm. One sees that the levels ofthese contaminants in outfall effluent raises sharply over a short period oftime and then falls back to baseline (See CHEC figures 1, 2 and 3), whenthe slug is through the system. Any TENORM, in the oil and gas waste fluidbeing treated, not taken out by the treatment system will reasonably followthe same pattern. That is it will come and go quickly and we have no ideaof peak levels of TENORM or any other contaminants in the stream or rivernear the treatment plant outfall.

What is the solution to all this? Are we to sample continuously – at alltreatment plant outfalls, in river and stream segments between treatmentplant outfalls and water intakes, at all water intakes and in all finisheddrinking water (and I might add in private well water systems that may pullin contaminants from nearby streams and rivers) across the entire areaMarcellus Shale waste fluids are being disposed of? (This would includePennsylvania, New York, Ohio, and West Virginia). This is exactly whatis necessary to be done to assure protection of drinking water supplies,recreationalists, and the health of aquatic resources if we continue to allowoil and gas flowback water to be disposed of in sewage treatment andinefficient brine treatment plants.

NO – this would be cost prohibitive and impractical to do on the scale thatis necessary to protect public health and aquatic resources. We must usethe precautionary principal here and insist that sewage treatment plants notaccept oil and gas wastewater, period. Batches of oil and gas wastewaterneed to be tested continuously for levels of TENORM and all other possiblecontaminants so that a determination can be made of where the fluids canbe adequately and safely disposed of. Fluids that are determined to behazardous and/or toxic should be transported only by certified haulers andloads need to be properly manifested so there is an accurate accounting ofthe volumes of waste and where it is being sent for ultimate treatment. Thetechnical capabilities and acceptance of brine fluids, of and by, oil and gaswaste fluid treatment facilities must be matched exactly to the realities oflevels of contaminants in the brine fluids.

The intent of the Resource Conservation and Recovery Act (RCRA) wasto ensure that there is a “cradle to grave” system to document, handleand dispose of all hazardous and toxic waste from all industries and evenmunicipal authorities in a safe and effective manner. RCRA is basically anextension of the environmental public health precautionary principal – andif implemented and enforced thoughtfully and comprehensively preventsthe formation of new Superfund sites and will assure that the publicand environmental receptors are protected from contaminants in oil andgas waste fluids- be they called flowback or produced water, or brine oranything else.

Figure 1, Time-plot of Barium concentration in effluent from the McKeesportPOTW, sampled beginning 10/19/2010. Hour 1 begins at 19:00 (7:00 PM).A sample was taken on the hour, every hour, for a period of 24 hours. (To zoom in, click on the image.)

Figure 2, Time-plot of Strontium concentration in effluent from the McKeesport POTW, sampled beginning 10/19/2010. Hour 1 begins at 19:00 (7:00 PM). A sample was taken on the hour, every hour, for a period of 24 hours. (To zoom in, click on the image.)


Figure 3, Time-plot of bromides concentration in effluent from the McKeesport POTW, sampled beginning 10/19/2010. Hour 1 begins at 19:00 (7:00 PM). A sample was taken on the hour, every hour, for a period of 24 hours. (To zoom in, click on the image.)

Appendix 1, Background Information

Hydraulic fracturing (HF) of shale gas deposits uses considerable masses of chemicals, for a variety of purposes to open and keep open pathways through which natural gas, oil and other production gases and liquids can flow to the well head. HF, also known as slick-water fracturing, introduces large volumes of amended water at high pressure into the gas bearing shale where it is in close contact with formation materials that are enriched in organic compounds, heavy metals and other elements, salts and radionuclides. Typically, about 1 million gallons and from 3-5 million gallons of amended water are needed to fracture a vertical well and horizontal well, respectively (Hayes, T; 2009, Vidic, R.; 2011). Fluids recovered from these wells can represent from 25% to 100% of the injected amended water solution (Vidic R., 2011) and are called “flowback” or “produced” water depending on the time period of their return.

Flowback and produced water contain high levels of total dissolved solids, chloride, heavy metals and elements as well as enriched levels of organic chemicals, bromide and radionuclides – in addition to the frac chemicals used to make the water slick-water. Levels of contaminants in flowback water generally increase with increasing time in contact with formation materials. There is abundant evidence that fluids recovered from this operation have high levels of total dissolved solids, barium and strontium, chlorides and bromides

While there is at present considerable scientific inquiry and even controversy regarding the potential of vertical or horizontal fracturing of shale gas reservoirs to contaminate shallow or confined groundwater aquifers (thus exposing municipal or private well water users to chemicals used in the hydrofracturing process and/or toxic elements, organic compounds, and radionuclides that exist in the formation materials); disposal of oil and gas wastewater/ Marcellus shale brine water in sewage treatment plants or inefficient brine wastewater treatment facilities is a direct exposure threat to public health through ingestion, inhalation and dermal absorption exposure pathways.

Matt Kelso, BA

Two Tales of Radioactivity

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There’s a disagreement brewing about whether or not there are radioactive materials in the Marcellus Shale wastewater. On February 26, 2011, Ian Urbina’s New York Times article reported:

Of more than 179 wells producing wastewater with high levels of radiation, at least 116 reported levels of radium or other radioactive materials 100 times as high as the levels set by federal drinking-water standards. At least 15 wells produced wastewater carrying more than 1,000 times the amount of radioactive elements considered acceptable.



Gross Alpha Particles. This map is based on the Pennsylvania wells which were reported to have high levels of radiation by the New York Times on February 26, 2011.  Please click the “i” icon and then one of the wells above for more information.  Please click the gray compass rose and double carat (^) to hide those menus.

On March 7, 2011, the Pennsylvania Department of Environmental Protection (DEP) issued a statement that would appear to contradict the New York Times data.  According to Acting DEP Secretary Michael Krancer, the situation is as follows:

We deal in facts based on sound science. Here are the facts: all samples were at or below background levels of radioactivity; and all samples showed levels below the federal drinking water standard for Radium 226 and 228.

Can Both Claims Be True?

Of the apparent discrepancy, the Marcellus Drilling News had this blunt proclamation:

It seems that The New York Times’ contention that Pennsylvania is poisoning waterways with radioactivity from Marcellus Shale wastewater was fiction and not science, as is now proven by test results from the Department of Environmental Protection (DEP).

But sound-byte media wars aside, there isn’t necessarily any discrepancy at all. As is usually the case, the devil is in the details.

First of all, it is important to understand that the two organizations are referencing entirely different datasets. More to the point, while the New York Times data is about the produced water itself, the DEP report tested river water. What’s more, in a follow-up article on March 7th, Mr. Urbina wrote:

The Times found that samples taken by the state in the Monongahela River — a source of drinking water for parts of Pittsburgh — came from a point upstream from the two sewage treatment plants on that river. The state has said those plants are still accepting significant quantities of drilling waste.

Because that sampling site is upstream, the discharges from those two plants are not captured by the state’s monitoring plans.

With this perspective, the Marcellus Drilling News’ harsh words come across as misguided. While the DEP statement seems to have been carefully worded to give the illusion of countering the claims raised by Mr. Urbina’s article, in fact, it does no such thing.

CHEC’s Perspective

In Mr. Urbina’s March 7th article, Center for Healthy Environments and Communities (CHEC)(1) Director Conrad Volz, DrPH, MPH said:

As long as we are going to allow oil and gas wastewater to enter these streams, there needs to be monitoring weekly at least for a whole host of contaminants, including radium, barium, strontium.

According to Mr. Urbina’s March 7th Times article, the United States Environmental Protection Agency (EPA) seems to agree with this cautionary approach, requiring tests for radioactivity at water intake plants, as well as a call to check for compliance at the facilities that are handling the wastewater.

This seems like a prudent approach. If the DEP has legitimate issues with the February 26th New York Times data, it was not effectively countered by their March 7th statement. The best way to settle this dispute is through targeted data collection, which in this case means setting up an effective water quality testing strategy.

And isn’t that the sort of work that the Department of Environmental Protection and the Environmental Protection Agency should be doing anyway?

  1. CHEC manages the content for FracTracker, including this site, https://www.fractracker.org, and http://data.fractracker.org/
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Hitting Close to Home – Gas Pad Fire in Avella, PA

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By Samantha Malone, MPH, CPH – Communications Specialist, Center for Healthy Environments and Communities (CHEC), University of Pittsburgh Graduate School of Public Health (GSPH); Doctoral Student, GSPH

Shale Gas Violations near Avella, PA (small)
Natural gas industry violations since 2007.
Avella, PA can be found by clicking on the image
and then zooming in on the patch of violations
in the center of the map.
Map created using FracTracker’s DataTool.

On February 23, 2011 a section of a natural gas drilling site in Avella, PA caught fire. Luckily only three workers were injured, but the issue still hits close to home – literally. Avella is my hometown. This quiet, farming area is located roughly 35 miles southwest of Pittsburgh in Washington County, PA. (See the map to the right.) It has a large school district geographically, with a tiny population. Known primarily for its rolling hills, farmland, and a historic landsite called Meadowcroft, Avella very rarely makes the headlines in Pittsburgh. That very fact is what peaked my concern when a TV news program mentioned that an incident had occurred on a Chesapeake Energy well site there.

The PA Department of Environmental Protection is currently investigating the fire. Initial reports indicate that volatile vapors that escaped while workers were flow-testing (part of which involves separating the flowback fluid from the natural gas), ignited and then caught nearby tanks on fire.  Volatile vapors can include a number of constituents, such as propane and benzene, which is a known human carcinogen. While there is little evidence to suggest that water contamination occurred as a result of the accident (like the 2009 spill near Cross Creek lake), air quality was most definitely affected. The smell of chemicals burning during the fire was even reported by some nearby residents. Thankfully, based on witness and on-site reports, the cooperation between the various emergency responders meant that the fire only burned for about three hours.

On a side note, I find it interesting that Chesapeake immediately refuted reports that hydraulic fracturing was the cause of the fire. Hydraulic fracturing, a process that breaks apart the shale layer under the ground to release the gas, had apparently been completed on the site. However, the volatile vapors originated from condensate, a result of hydraulic fracturing. Semantics.

Video Update: 3/1/11