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Want Not, Waste Not? Fossil Fuel Extraction’s Waste Disposal Challenges

Pennsylvania’s fracking industry is producing record amounts of toxic waste — where does it all go?

Drilling for methane and other fossil fuels is an energy-intensive process with many associated environmental costs. In addition to the gas that is produced through high volume hydraulic fracturing (“unconventional drilling,” or “fracking”), the process generates a great deal of waste at the drill site. These waste products may include several dozen tons of drill cutting at every well that is directionally drilled, in addition to liner materials, contaminated soil, fracking fluid, and other substances that must be removed from the site.

In 2018, Pennsylvania’s oil and gas industry (including both unconventional and conventional wells) produced over 2.9 billion gallons (nearly 69 million barrels) of liquid waste, and 1,442,465 tons of solid waste. In this article, we take a look at where this waste (and its toxic components) end up and how waste values have changed in recent years. We also explore how New York State, despite its reputation for being anti-fracking, isn’t exempt from the toxic legacy of this industry.

Waste that comes back to haunt us

According to a study by Physicians, Scientists and Engineers, over 80% of all waste from oil and gas drilling stays within the state of Pennsylvania. But once drilling wastes are sent to landfills, is that the end of them? Absolutely not!

Drilling waste also gets into the environment through secondary means. According to a recent report by investigative journalists at Public Herald, on average, 800,000 tons of fracking waste from Pennsylvania is sent to Pennsylvania landfills. When this waste is sent to landfills, radioactivity and other chemicals can percolate through the landfill, and are collected as leachate, which is then shipped to treatment plants.

Public Herald documented how fourteen sewage treatment plants in Pennsylvania have been permitted by Pennsylvania’s Department of Environmental Protection (PA DEP) to process and discharge radioactive wastes into more than a dozen Pennsylvania waterways.

Public Herald’s article includes an in-depth analysis of the issue. Their work is supported by a map of the discharge sites, created by FracTracker.

Trends over time

Pennsylvania Department of Environmental Protection maintains a rich database of oil and gas waste and production records associated with their Oil and Gas Reporting Website. The changes in waste disposal from Pennsylvania’s unconventional drilling reveal a number of interesting stories.

Let’s look first at overall unconventional drilling waste.

According to data from the federal Energy Information Administration, gas production in Pennsylvania began a steep increase around 2010, with the implementation of high volume hydraulic fracturing in the Marcellus Shale (see Figure 1). The long lateral drilling techniques allowed industry to exploit exponentially more of the tight shale via single well than was ever before possible with conventional, vertical drilling.

Figure 1. Data summary from FracTracker.org, based on EIA data.

The more recently an individual well is drilled, the more robust the production. We see an overall increase in gas production over time in Pennsylvania over the past decade. Paradoxically, the actual number of new wells drilled each year in the past 4-5 years are less than half of the number drilled in 2011 (see Figure 2).

Figure 2: Data summary from FracTracker.org, based on PA DEP data

Why is this? The longer laterals —some approaching 3 miles or more—associated with new wells allow for more gas to be extracted per site.

With this uptick in gas production values from the Marcellus and Utica Formations come more waste products, including copious amounts drilling waste, “produced water,” and other byproducts of intensive industrial operations across PA’s Northern Tier and southwestern counties.

Comparing apples and oranges?

When we look at the available gas production data compared with data on waste products from the extraction process, some trends emerge. First of all, it’s readily apparent that waste production does not track directly with gas production in a way one would expect.

Recall that dry gas production has increased annually since 2006 (see Figure 1). However, the reported waste quantities from industry have not followed that same trend.

In the following charts, we’ve split out waste from unconventional drilling by solid waste in tons (Figure 3) and liquid waste, in barrels (Figure 4).

Figure 3: Annual tonnage of solid waste from the unconventional oil and gas industry, organized by the state it is disposed in. Data source: PA DEP, processed by FracTracker Alliance

Figure 4: Annual volume of liquid waste from the unconventional oil and gas development, organized by state it is disposed in. One barrel is equivalent to 42 gallons. Data source: PA DEP, processed by FracTracker Alliance

Note the striking difference in disposal information for solid waste, compared with liquid waste, coming from Pennsylvania.

“Disposal Location Unknown”

Until just the last year, often more than 50% of the known liquid waste generated in PA was disposed of at unknown locations. The PA DEP waste report lists waste quantity and method for these unknown sites, depending on the year: “Reuse without processing at a permitted facility,” “Reuse for hydraulic fracturing,” “Reuse for diagnostic purposes,” “Reuse for drilling or recovery,” “Reuse for enhanced recovery,” and exclusively in more recent years (2014-2016), “Reuse other than road-spreading.”

In 2011, of the 20.5 million barrels of liquid waste generated from unconventional drilling, about 56% was allegedly reused on other drilling sites. However, over 9 million barrels—or 44% of all liquid waste—were not identified with a final destination or disposal method. Identified liquid waste disposal locations included “Centralized treatment plant for recycle,” which received about a third of the non-solid waste products.

In 2012, the quantity of the unaccounted-for fracking fluid waste dropped to about 40%. By 2013, the percentage of unaccounted waste coming from fracking fluid dropped to just over 21%, with nearly 75% coming from produced fluid, which is briny, but containing fewer “proprietary”—typically undisclosed—chemicals.

By 2017, accounting had tightened up further. PA DEP data show that 99% of all waste delivered to undisclosed locations was produced fluid shipped to locations outside of Pennsylvania. By 2018, all waste disposal was fully accounted for, according to DEP’s records.

In looking more closely at the data, we see that:

  1. Prior to 2018, well drillers did not consistently report the locations at which produced water was disposed of or reused. Between 2012 and 2016, a greater volume of unconventional liquid waste went unaccounted for than was listed for disposal in all other locations, combined.
  2. In Ohio, injection wells, where liquid waste is injected into underground porous rock formations, accounted for the majority of the increase in waste accepted there: 2.9 million barrels in 2017, and 5.7 million barrels in 2018 (a jump of 97%).
  3. West Virginia’s acceptance of liquid waste increased  significantly in 2018 over 2017 levels, a jump of over a million barrels, up from only 55,000. This was almost entirely due to unreported reuse at well pads.
  4. In 2018, reporting, in general, appears to be more thorough than it was in previous years. For example, in 2017, nearly 692,000 barrels of waste were reused at well pads outside PA, but those locations were not disclosed. Almost 7000 more barrels were also disposed of at unknown locations. In 2018, there were no such ambiguities.

A closer look at Pennsylvania’s fracking waste shipped to New York State

Despite a reputation for being resistant to the fracking industry, for most of this decade, the state of New York has been accepting considerable amounts of fracking waste from Pennsylvania. The greatest percentage shipped to New York State is in the form of drilling waste solids that go to a variety of landfills throughout Central and Western New York.

Looking closely at the bar charts above, it’s easy to notice that the biggest recipients of Pennsylvania’s unconventional liquid drilling waste are Pennsylvania itself, Ohio, as well as a significant quantity of unaccounted-for barrels between 2011 and 2016 (“Disposal location unknown”). The data for disposal of solid waste in New York tells a different story, however. In this case, Pennsylvania, Ohio, and New York State all play a role. We’ll take a look specifically at the story of New York, and illustrate the data in the interactive map that follows.

In this map, source locations in Pennsylvania are symbolized with the same color marker as the facility in New York that received the waste from the originating well pad. In the “Full Screen” view, use the “Layers” drop down menu to turn on and off data from separate years.

View map full screenHow FracTracker maps work

Solid waste transported to New York State

From the early days of unconventional drilling in Pennsylvania, New York State’s landfills provided convenient disposal sites due to their proximity to the unconventional drilling occurring in Pennsylvania’s Northern tier of counties. Pennsylvania and Ohio took the majority of solid wastes from unconventional drilling waste from Pennsylvania. New York State, particularly between 2011-2015, was impacted far more heavily than all other states, combined (Figure 5, below).

Figure 5: Known disposal locations (excluding PA and OH) of Pennsylvania’s solid waste. Data source: PA DEP, processed by FracTracker Alliance

Here’s the breakdown of locations in New York to where waste was sent. Solid waste disposal into New York’s landfills also dropped by half, following the state’s ban on unconventional drilling in 2014. Most of the waste after 2012 went to the Chemung County Landfill in Lowman, New York, 10 miles southeast of Elmira.

Figure 6: Solid waste from unconventional drilling, sent to facilities in NYS. Data source: PA DEP, processed by FracTracker Alliance

Is waste immobilized once it’s landfilled?

The fate of New York State’s landfill leachate that originates from unconventional drilling waste is a core concern, since landfill waste is not inert. If drilling waste contains radioactivity, fracking chemicals, and heavy metals that percolate through the landfill, and the resulting leachate is sent to municipal wastewater treatment plants, will traditional water treatment methods remove those wastes? If not, what will be the impact on public and environmental health in the water body that receives the “treated” wastewater? In Pennsylvania, for example, a case is currently under investigation relating to pollution discharges into the Monongahela River near Pittsburgh. “That water was contaminated with diesel fuels, it’s alleged, carcinogens and other pollutants,” said Rich Bower, Fayette County District Attorney.

Currently, a controversial expansion of the Hakes Landfill in Painted Post, New York is in the news. Sierra Club and others were concerned about oversight of radium and radon in the landfill’s leachate and air emissions, presumably stemming from years of receiving drill cuttings. The leachate from the landfill is sent to the Bath Wastewater Treatment plant, which is not equipped to remove radioactivity. “Treated” wastewater from the plant is then discharged into the Cohocton River, a tributary of the Chesapeake Bay. In April 2019, these environmental groups filed a law suit against Hakes C&D Landfill and the Town of Campbell, New York, in an effort to block the expansion.

Similar levels of radioactivity in leachate have also been noted in leachate produced at the Chemung County Landfill, according to Gary McCaslin, President of People for a Healthy Environment, Inc.

In recent years, much of the solid unconventional waste arriving in New York State has gone to the Chemung County Landfill (see Figure 6, above). Over the course of several years, this site requested permission to expand significantly from 180,000 tons per year to 417,000 tons per year. However, by 2016, the expansion was deemed unnecessary, and according, the plans were put on hold, in part “…because of a decline in the amount of waste being generated due to a slower economy and more recycling than when the expansion was first planned years ago.” The data in Figure 5 above also parallel this story, with unconventional drilling waste disposed in New York State dropping from over 200,000 tons in 2011 to just over 20,000 tons in 2018.

Liquid waste transported to New York State

The story about liquid unconventional drilling waste exported from Pennsylvania to states other than Ohio is not completely clear (see Figure 7, below). Note that the data indicate more than a 2000% increase in waste liquids going from Pennsylvania to West Virginia after 2017. While it has not been officially documented, FracTracker has been anecdotally informed that a great deal of waste was already going to West Virginia, but that the record-keeping prior to 2018 was simply not strongly enforced.

Figure 7: Known disposal locations (excluding Pennsylvania and Ohio) of Pennsylvania’s liquid waste. Data source: PA DEP, processed by FracTracker Alliance

Beginning in the very early years of the Pennsylvania unconventional fracking boom, a variety of landfills in New York State have also accepted liquid wastes originating in Pennsylvania, including produced water and flowback fluids (see Figure 8, below).

Figure 8: Liquid waste from unconventional drilling, sent to facilities in New York State. Data source: PA DEP, processed by FracTracker Alliance

In addition, while this information doesn’t even appear in the PA DEP records (which are publicly available back to 2010), numerous wastewater treatment plants did accept some quantity, despite being fully unequipped to process the highly saline waste before it was discharged back into the environment.

One such facility was the wastewater treatment plant in Cayuga Heights, Tompkins County, which accepted more than 3 million gallons in 2008. Another was the wastewater treatment plant in Auburn, Cayuga County, where the practice of accepting drilling wastewater was initially banned in July 2011, but the decision was reversed in March 2012 to accept vertical drilling waste, despite strong public dissent. Another wastewater treatment plant in Watertown, Jefferson County, accepted 35,000 gallons in 2009.

Fortunately, most New York State wastewater treatment plant operators were wise enough to not even consider adding a brew of unknown and/or proprietary chemicals to their wastewater treatment stream. Numerous municipalities and several counties banned fracking waste, and once the ban on fracking in New York State was instituted in 2014, nearly all importation of liquid unconventional drilling waste into the state ceased.

Nevertheless, conventional, or vertical well drilling also generates briny produced water, which the New York State Department of Environmental Conservation (DEC) permits communities in New York to accept for ice and dust control on largely rural roads. These so-called “beneficial use determinations” (BUDs) of liquid drilling waste have changed significantly over the past several years. During the height of the Marcellus drilling in around 2011, all sorts of liquid waste was permitted into New York State (see FracTracker’s map of affected areas) and was spread on roads. As a result, the chemicals—many of them proprietary, of unknown constituents, or radioactive—were indirectly discharged into surface waters via roadspreading.

Overall, in the years after the ban in 2014 on high volume hydraulic fracturing was implemented, restrictions on Marcellus waste coming into New York have strengthened. Very little liquid waste entered New York’s landfills after 2013, and what did come in was sent to a holding facility owned by Environmental Services of Vermont. This facility is located outside Syracuse, New York.

New York State says “no” to this toxic legacy

Fortunately, not long after these issues of fracking fluid disposal at wastewater treatment facilities in New York State came to light, the practice was terminated on a local level. The 2014 ban on fracking in New York State officially prevented the disposal of Marcellus fluids in municipal wastewater treatment facilities and required extra permits if it were to be road-spread.

In New York State, the State Senate—after 8 years of deadlock—in early May 2019, passed key legislation that would close a loophole that had previously allowed dangerous oil and gas waste to bypass hazardous waste regulation. Read the press release from Senator Rachel May’s office here. However, despite strong support from both the Senate, and the Assembly, as well as many key environmental groups, the Legislature adjourned for the 2019 session without bringing the law to a final vote. Said Elizabeth Moran, of the New York Public Interest Research Group (NYPIRG), “I want to believe it was primarily a question of timing… Sadly, a dangerous practice is now going to continue for at least another year.”

 

See Earthworks’ recent three part in-depth reporting on national, New York, and Pennsylvania oil and gas waste, with mapping support by FracTracker Alliance.

All part of the big picture

As long as hydrocarbon extraction continues, the issues of waste disposal—in addition to carbon increases in the atmosphere from combustion and leakage—will result in impacts on human and environmental health. Communities downstream and downwind will bear the brunt of landfill expansions, water contamination, and air pollution. Impacts of climate chaos will be felt globally, with the greatest impacts at low latitudes and in the Arctic.

Transitioning to net-zero carbon emissions cannot be a gradual endeavor. Science has shown that in order to stay under the 1.5 °C warming targets, it must happen now, and it requires the governmental buy-in to the Paris Climate Agreement by every economic power in the world.

No exceptions. Life on our planet requires it.

We have, at most, 12 years to make a difference for generations to come.

By Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance

If this article was helpful to you, please contribute to FracTracker today. Any amount is greatly appreciated!
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Radium Watersheds a Risk

By Greg Pace – Columbus Community Bill of Rights, and Julie Weatherington-Rice – Environmental Consultant

columbus_classiimap

Figure 1. Map of Columbus, OH Watersheds and Class II Injection Wells

Most Ohio residents are unaware of the frack fluid deep underground injection occurring north of Columbus, underneath the region’s source water protection watersheds (Figure 1).

Materials injected are liquids that have as much as ten times the salt concentration of sea-water. Mixed with this “brine” solution is a combination from hundreds of chemicals that are used in different stages of horizontal hydraulic fracturing, the process used to extract natural gas, petroleum, and hydrocarbon liquids used to make industrial materials such as plastics. BTEX compounds including benzene are always present in the wastewater, along with formaldehyde, bromides, ethylene glycol (antifreeze), and arsenic, with many other carcinogenic and otherwise highly-toxic substances.

Radioactivity of Shale Gas Wastewater

One of the biggest questions in this mix of toxic disposal is how much radioactive content exists. Radium-226 is most worrisome, as it has a very long half-life (1,600 years). It is water-soluble and, once it enters the human body, seeks to find a home in our bones where it will emit its cell-formation-destabilizing effects for the remainder of our lifetime. This radionuclide is known to cause leukemia, bone cancers, blood disorders, and other diseases.

The state of Ohio does not monitor the content of materials that are injected into our Class II injection wells deep in the ground. This oil and gas waste can come from anywhere, including Pennsylvania’s Marcellus shale, which is the most highly-radioactive geology of all the shale plays in the country. Radium-226 readings as high as 15,000 pico-curies per liter have been read in Marcellus shale brines. The EPA drinking water limit for radium-226 is 5 pico-curies per liter, which puts the Marcellus reading at 3,000 times higher than the drinking water limit.

Exposure through drinking water is a pathway to human disease from radium-226. Once oil and gas waste is disposed of underground in a sandstone or limestone layer, the fluids are subject to down-gradient movement, wicking through capillary action, and seepage over time. This means that the highly radioactive wastewater could eventually end up in our underground drinking water sources, creating radium watersheds. This practice is putting our watersheds at risk from radioactive contamination for hundreds of years, at least.

Can injected fluids migrate?

Depending on whether you confer with a geologist who works with the oil and gas industry, or from an independent geologist, you will get a different opinion on the likelihood of such a pollution event occurring. Industry geologists mostly claim that deep injection leaves very low risk of water contamination because it will not migrate from the planned area of injection. On the other hand, independent geologists will tell you that it is not a matter of if the liquids will migrate, but how and when. The ability to confirm the geology of the underground area layer of injection “storage” is not exact, therefore accuracy in determining the probability for migration over time is poor.

Figure 2. Ohio Utica Brine Production and Class II Injection Well Disposal


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We do know, however, that all underground systems in Ohio leak – Research by The Ohio State University and the US Geological Survey show that the age of the water in brine formations is far younger than the age of the rock deposits they are found in. See where wastewater is being created and disposed of in Ohio using the dynamic map above (Figure 2).

Spill Risks to Columbus, OH Water

According to area geologist, Dr. Julie Weatherington-Rice, the source for Columbus’s water to the north is mostly from surface water. This water comes from the Delaware and Morrow county watersheds that feed into sources such as the Hoover and Alum Creek reservoirs. The major threat from injection wells to our watershed is from spills, either from trucks or from storage at the injection well sites themselves.

Dead fish floating in Vienna area pond contaminated by injection well system spill Source: MetropolitanEnegineering Consulting & Forensics-Expert Engineers

Figure 3. Dead fish floating in Vienna area pond contaminated by injection well system spill. Source: MetropolitanEnegineering Consulting & Forensics-Expert Engineers

In April 2015, as much as 8,000 gallons of liquid leaked from a malfunctioning pipe in the storage apparatus of an oil/gas waste storage and injection well site in Vienna, OH. This caused a wildlife kill in two ponds (Figure 3), and the spill was not contained until 2/3 mile downstream in a tributary. The firm who owned the facility was found negligent in that they did not install a required containment liner for spills. The incident was discovered by neighboring residents, but apparently employees knew of the leak weeks before. Of note in this incident was that Ohio Department of Natural Resources, the regulatory agency that oversees all oil/gas production activity in Ohio including injection, stated that there was “minimal impact to wildlife.”

Brine tanker rollover near Barnesville, OH spilled 5,000 gal. of produced brine. Source: Barnesville, OH Fire Department

Figure 4. Brine tanker rollover near Barnesville, OH spilled 5,000 gal. of produced brine. Source: Barnesville, OH Fire Department

In March, 2016, a tanker truck carrying produced waste from a hydraulically fractured well pad overturned outside of the Village of Barnesville, Ohio (Figure 4). The truck spilled 5,000 gallons of liquid waste into a field that led into a tributary, leading the fluids to enter one of the city’s three drinking water supply reservoirs. The water source was shut down for more than two months while regulators determined if water levels were safe for consumption. There was a noted spike in radium-226 levels during water testing immediately after the spill.

Of greatest concern is that, although many millions of gallons of frack waste have been injected into the wells north of Columbus over the past few years, we expect that this activity will increase. For the first time, the United States began exporting its own natural gas in 2016, to regions such as Europe and South America. As the industry consolidates from the depression of oil prices over the past two years and begins to ramp up again, we expect the extraction activity in the Marcellus and especially Utica to increase to levels beyond what we have seen since 2011. The levels of injection will inevitably follow, so that injection wells in Ohio will receive much more than in the past. The probability of spills, underground migration, and human-induced earthquakes may increase steeply, as well.

An Aging Disposal Infrastructure

On our Columbus Community Bill of Rights website, we show pictures of some of the Class II injection wells in Morrow County, most of them converted from legacy production wells. These old wells are located in played out oil/gas fields that may still be producing or have abandoned but not plugged (closed) wells, allowing other routes for injected liquids to migrate into shallow ground water and to the surface. The dilapidated condition of these converted Class II wells makes it hard to believe that they are used to inject millions of gallons of wastewater under high pressure. While many of the wells in the state are as deep as 9,000 feet, all of the injection wells we have seen in Morrow County are only 3,000-4,000 feet deep. This situation puts surface water at greater risk over time, as it is probable that, over the generations, some of the fluids will migrate and wick into the higher subterranean strata.

Figure 5. Ohio Class II Injection Wells by Type


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One well (Power Fishburn unit, photo below) showed signs of poor spill control when we took our October 2015 injection well tour. While we were there, a brine tanker arrived and began pumping their load into the well. The driver took pictures of our license plates while we were there watching him. A year later, there is a whole new structure at the well, including a new storage tower, and an extensively beefed-up spill control berm. Maybe we need to visit all of the facilities when they come by to use them!

Another well (Mosher unit, photo below) which hadn’t been used since 2014 according to available records, showed signs of a spill around the well. The spill control berms look as if they probably had flooded at some point. This well sits on the edge of a large crop field.


Figures 6a and 6b. Photos of Class II injection wells. Click on the images to expand them.

North of Columbus, the city of Delaware’s underground source water is at risk of becoming contaminated from underground migration of disposed wastewater over time, through wicking and seepage effects (as explained earlier in this article). They are also vulnerable to their reservoir being contaminated from surface spill migration through their watershed.

Google maps rendition of Ohio Soil Recycling facility in south Columbus, Ohio, that accepts shale drill cuttings for remediation to cap the landfill. Source: Google Maps/author

Figure 7. Google maps rendition of Ohio Soil Recycling facility in south Columbus, Ohio, that accepts shale drill cuttings for remediation to cap the landfill. Source: Google Maps/author

South of Columbus is another threat – drill cuttings from the drilling process have been authorized for disposal at a “remediation” landfill adjacent to the Alum Creek (Figure 7). The bioremediation treatment used is not indicated to solve the problem of removing radionuclides from the materials. This landfill had been remediated under the Ohio EPA twice when it was a toxic drum dump, after toxins were found to have been leaching into the watershed creek. Columbus’s Alum Creek well, as well as Circleville, are at risk of contamination in their drinking water if radionuclides from the cuttings leach into Alum Creek. Again, this is a long-term legacy of risk to their water.

Radiation Regulatory and Monitoring Gaps

Since The Ohio legislature deemed the radioactive content of shale cuttings to be similar to background levels in the 2013 state budget bill, cuttings can be spread around to all licensed landfills in Ohio with absolutely no accountability for the radium and other heavy metal levels in them. Unfortunately, the measuring protocol used in the pilot study for the Columbus facility to demonstrate to Ohio EPA that radium-226 was below EPA drinking water limits has been shown in a University of Iowa study to be unreliable.  The inadequate protocol was shown to indicate as little as 1% of the radium levels in shale waste samples tested.

As such, there have been hundreds of incidents where truckloads of cuttings have been turned away at landfills with crude radiation monitors. In 2013 alone, 2 loads were turned away in Ohio landfills, and over 220 were turned away from Pennsylvania landfills.

Ohio has a long way to go before it can be considered a clean energy state. The coal industry polluted significant water sources in the past. The fracking industry seems to be following suit, where contaminations will surprise us long into the future and in broader areas.


Map Data for Download

Oil and Gas Wastes are Radioactive – and Lack Regulatory Oversight

Highlighting the maps of radioactive oil and gas exploration and production wastes created in collaboration with the Western Organization of Research Councils

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance
Scott Skokos, Western Organization of Research Councils

Oil and gas waste can be radioactive, but it is not considered “hazardous,” at least according to the federal government. In this article, we summarize several of the hazardous risks resulting from the current federal policy that fails to regulate this massive waste stream, and the gaps left by states. Of the six states mapped in this assessment, only the state of Montana has initiated any type of rule-making process to manage the waste.

When it comes to unconventional oil and gas waste streams:

Nobody can say how much of any type of waste is being produced, what it is, and where it’s ending up. – Nadia Steinzor, Earthworks

To address some of these gaps, FracTracker Alliance has been working with the Western Organization of Resources Councils (WORC) to map out exactly where radioactive oil and wastes are being dumped, stored, and injected into the ground for disposal. The work is an extension to WORC’s comprehensive No Time to Waste report.

Why is accurate waste data so hard to come by? The Earthworks report, Wasting Away explains that the U.S. EPA intentionally exempted oil and gas exploration and production wastes from the federal regulations known as the Resource Conservation and Recovery Act (RCRA) despite concluding that such wastes “contain a wide variety of hazardous constituents.” As a result, there is very little waste tracking and reporting of oil and gas waste data nationally.

State Waste Management Maps

Some data is available at the state level, so we at FracTracker have compiled, cleaned, and mapped what little data we could find.

State-specific maps have been created for Montana, North Dakota, Colorado, and Wyoming – see below:

ND Radioactive Waste mapNorth Dakota – View map fullscreen

co-radioactive-featureColorado – View map fullscreen

Sources of Radioactivity

When we hear about “radioactive waste” associated with the energy industry, nuclear power stations and fission reactors are usually what come to mind. But, as the EPA explains, fracking has transformed the nature of the oil and gas waste stream. Components of fracking waste differ from conventional oil and gas exploration and production wastes in a number of ways:

  • In general, the waste stream has additional hazardous components, and that transformation includes increased radioactivity.
  • Fracking has allowed for more intrusive drilling, penetrating deep sedimentary formations using millions of gallons of fluid.
  • Drilling deeper produces more drill cuttings.
  • The process of hydraulic fracking introduces millions more gallons of fluid into the ground that then return to the surface. These returns are ultimately contaminated and require disposal.
  • The formations targeted for unconventional development are mostly ancient seabeds still filled with salty “brines” known as “formation waters.”
  • In addition to the hazardous chemicals in the fracking fluid pumped into the wells for fracking, these unconventional formations contain larger amounts of heavy metals, carcinogens and other toxics. This also includes more radioisotopes such as Uranium, Thorium, Radium, Potassium-40, Lead-210, and Polonium-210 than the conventional formations that have supplied the majority of oil and gas prior to the shale boom.

A variety of waste products make up the waste stream of oil and gas development, and each is enhanced with naturally occurring radioactive materials (NORM). This waste stream must be treated and disposed of properly. All the oil and gas equipment – such as production equipment, processing equipment, produced water handing equipment, and waste management equipment – also need to be considered as sources of radioactive exposure.

Figure 1 below explains where the waste from fracking goes after it leaves the well pad.

Radioactive Oil and Gas Pathway Life Cycle

Figure 1. Breakdown of the radioactive oil and gas waste life-cycle

Three facets of the waste stream particularly enhanced with NORMs by fracking include scales, produced waters, and sludges.

A. Scales

When injected into the ground, fracking fluid mixes with formation waters, dissolving metals, radioisotopes and other inorganic compounds. Additionally the fracking liquids are often supplemented with strong acids to reduce “scaling” from precipitate build up (to prevent clogging up the well). Regardless, each oil well generates approximately 100 tons of radioactive scale annually. As each oil and gas reservoir is drained, the amount of scale increases. The EPA reports that lead-210 and polonium-210 are commonly found in scales along with their decay product radon at concentrations estimated to be anywhere from 480 picocuries per gram (pCi/g) to 400,000 pCi/g). Scale can be disposed of as a solid waste, or dissolved using “scale inhibitors.” These radioactive elements then end up in the liquid waste portion of the waste stream, known as produced waters.

B. Produced Waters

In California, strong acids are used to further dissolve formations to stimulate additional oil production. Acidic liquids are able to dissolve more inorganic elements and compounds such as radioisotopes. While uranium and thorium are not soluble in water, their radioactive decay products such as radium dissolve in the brines. The brines return to the surface as “produced water.” As the oil and gas in the formation are removed, much of what is pumped to the surface is formation water.

Consequently, declining oil and gas fields generate more produced water. The ratio of produced water to oil in conventional well was approximately 10 barrels of produced water per barrel of oil. According to the American Petroleum Institute (API), more than 18 billion barrels of waste fluids from oil and gas production are generated annually in the United States. There are several options for managing the liquid waste stream. The waste could be treated using waste treatment facilities, reinjected into other wells to enhance production (a cheaper option), or injected for disposal. Before disposal of the liquid portion, all the solids in the solution must be removed, resulting in a “sludge.”

C. Sludges

The U.S. EPA reports that conventional oil production alone produces 230,000 million tons – or five million ft3 (141 cubic meters) – of TENORM sludge each year. Unconventional processes produce much more sludge waste than conventional processes. The average concentration of radium in sludges is estimated to be 75 pCi/g, while the concentration of lead-210 can be over 27,000 pCi/g. Sludges present a high risk to the environment and a higher risk of exposure for people and other receptors in those environments because sludges are typically very water soluble.

Federal Exemptions

According to the EPA, “because the extraction process concentrates the naturally occurring radionuclides and exposes them to the surface environment and human contact, these wastes are classified as Technologically Enhanced Naturally Occurring Radioactive Material (TENORM).” Despite the conclusions that oil and gas TENORM pose a risk to the environment and humans, the EPA exempts oil and gas exploration and production wastes from the definition of “hazardous” under Resource Conservation and Recovery Act (RCRA) law. In fact, most wastes from all of the U.S. fossil fuel energy industry, including coal-burning and natural gas, are exempt from the disposal standards that hazardous waste normally requires.

The Center for Public Integrity calls this radioactive waste stream “orphan waste,” because no single government agency is fully managing it.

Fortunately, the EPA has acknowledged that federal regulations are currently inadequate, though this is nothing new. A U.S. EPA report from the 1980’s reported as much, and gave explicit recommendations to address the issue. For 30 years nothing happened! Then in August, 2015, a coalition of environmental groups (including the Environmental Integrity ProjectNatural Resources Defense CouncilEarthworksResponsible Drilling AllianceWest Virginia Surface Owners’ Rights Organization, and the Center for Health, Environment and Justice) filed a lawsuit against the EPA, and has since reached a settlement.

Just last month (January 10, 2017) the U.S. EPA agreed to review federal regulations of oil and gas waste – a process they were meant to do every 3 years for the last 30 years. The EPA has until March 15, 2019, to determine whether or not regulatory changes are warranted for “wastes associated with the exploration, development, or production of crude oil, natural gas, or geothermal energy.” With the recent freeze on all U.S. EPA grants, however, it is not clear whether these regulations will receive the review they need.

State Regulations

Regulation of this waste stream is left up to the states, but most states do not require operators to manage the radioactivity in oil and gas wastes, either. Because of the federal RCRA exemptions most state policies ignore the radioactive issue altogether. Operators are free to dispose of the waste at any landfill facility, unless the landfill tells them otherwise. For detailed analyses of state policies, see pages 10-45 of the No Time to Waste report. FracTracker has also covered these issues in Pennsylvania and Ohio.

Another issue that screams for federal consideration of this waste stream is that states do not have the authority to determine whether or not the wastes can cross their borders. States also do not have the jurisdiction to decide whether or not facilities in their state can accept waste from across state lines. That determination is reserved for federal jurisdiction, and there are not any federal laws regulating such wastes. In fact, these wastes are strategically exempt from federal regulation for just these reasons.

Why can’t the waste be treated?

This type of industrial waste actually cannot be treated, at least not entirely. Unlike organic pollutants that can be broken down, inorganic constituents of the waste cannot be simply disintegrated out of existence. Inorganic components include heavy metals like arsenic and bromides, as well as radioactive isotopes of radium, lead, and uranium. Such elements will continue to emit radiation for hundreds-to-thousands of years. The best option available is to find a location to “isolate” and dispose of these wastes – a sacrifice zone.

Current management practices do their best to separate the liquid portions from the solid portions, but that’s about it. Each portion can then be disposed independently of each other. Liquids are injected into the ground, which is the cheapest option where it is available. If enough of the dissolved components (heavy metals, salts, and radioisotopes) can be removed, wastewaters are discharged into surface waters. The compounds and elements that are removed from the liquid waste stream are hyper-concentrated in the solid portion of the waste, described as “sludge” in the graphic above. This hazardous material can be disposed of in municipal or solid waste landfills if the state regulators do not require the radioactivity or toxicity of this material to be a consideration for disposal. There are not federal requirements, so unless there is a specific state policy regarding the disposal, it can end up almost anywhere with little oversight. These chemicals do not magically disappear. They never disappear.

Risks

There are multiple pathways for contamination from facilities that are not qualified to manage radioactive and hazardous wastes. At least seven different environmental pathways provide potential risks for human exposure. They include:

  1. Radon inhalation,
  2. External gamma exposure,
  3. Groundwater ingestion,
  4. Surface water ingestion,
  5. Dust inhalation,
  6. Food ingestion, and
  7. Skin beta exposure from particles containing the radioisotopes.

According to the EPA, the low-level radioactive materials in drilling waste present a definitive risk to those exposed. High risk examples include dust suppression and leaching. If dust is not continuously suppressed, radioactive materials in dust pose a risk to people at these facilities or those receptors or secondary pathways located downwind of the facilities. Radioactive leachate entering surface waters and groundwaters is also a significant threat. A major consideration is that radioactive waste can last in these landfills far longer than the engineered lifespans of landfills, particularly those that are not designed to retain hazardous wastes.

Cases of Contamination

North Dakota

In North Dakota, the epicenter of the Bakken Oil Fields, regulators were not ready for the massive waste streams that came from the fast growing oil fields. This  allowed thousands of wastewater disposal wells be drilled to dispose of salty wastewater without much oversight, and no places in state for companies to dispose of radioactive solid waste. Many of the wastewater disposal wells were drilled haphazardly, and as a result many contaminated surrounding farmland with wastewater. With regard to radioactive solid waste, the state until recently had a de facto ban on solid radioactive waste disposal due to their radioactivity limit being 5 picocuries per gram. The result of this de facto ban made it so companies either had to make one of two decisions: 1. Haul their radioactive solid waste above the limit out of state to facilities in Idaho or Colorado; or 2. Risk getting caught illegally dumping waste in municipal landfills or just plain illegal dumping in roadsides, buildings, or farmland.

In 2014, a massive illegal dumping site was discovered in Noonan, ND when North Dakota regulators found a gas station full of radioactive waste and filter socks (the socks used to filter out solid waste from wastewater, which contain high levels of radioactivity). Following the Noonan, ND incident North Dakota regulators and politicians began discussions regarding the need for new regulations to address radioactive solid waste.

In 2015, North Dakota moved to create rules for the disposal of solid radioactive waste. Its new regulations increase the radioactivity limit from 5 picocuries per gram to 50 picocuries per gram, and sets up new requirements for the permitting of waste facilities accepting radioactive waste and the disposal of radioactive waste in the waste facilities. Dakota Resource Council, a member group of WORC, challenged the rules in the courts, arguing the rules are not protective enough and that the agency responsible for the rules pushed through the rules without following the proper procedures. Currently the rules are not in effect until the litigation is settled.

Pennsylvania

In Pennsylvania, the hotbed of activity for Marcellus Shale gas extraction, the regulatory body was ill equipped and uninformed for dealing with the new massive waste stream when it first arrived on scene. Through 2013, the majority of wastewater was disposed of in commercial and municipal wastewater treatment facilities that discharge to surface waters. Numerous facilities engaged in this practice without amending their federal discharge permits to include this new waste stream.

Waste treatment facilities in Pennsylvania tried to make the waste streams less innocuous by diluting the concentrations of these hazardous pollutants. They did this by mixing the fracking wastes with other waste streams, including industrial discharges and municipal waste. Other specialized facilities also tried to remove these dissolved inorganic elements and filter them from the discharge stream.

As a result of site assessments by yours-truly and additional academic research, these facilities realized that such hazardous compounds do not simply dilute into receiving waters such as the Allegheny, Monongahela, and Ohio rivers. Instead, they partition (settle) into sediments where they are hyper-concentrated. As a result of the lawsuits that followed the research, entire river bottoms in Pennsylvania had to be entirely dug up, removed, and disposed of in hazardous waste landfills.

Action Plans Needed

Massive amounts of solid and liquid wastes are still generated during drilling exploration and production from the Marcellus Shale. There is so much waste, operators don’t know what to do with it. In Pennsylvania, there is not much they can do with it, but it is not just Pennsylvania. Throughout the Ohio River Valley, operators struggle to dispose of this incredibly large waste stream.

Ohio, West Virginia, and Pennsylvania have all learned that this waste should not be allowed to be discharged to surface waters even after treatment. So it goes to other states – those without production or the regulatory framework to manage the wastes. Like every phase of production in the oil and gas industry, operators (drillers) shop around for the lowest disposal costs. In Estill County, Kentucky, the State Energy and Environment Department just recently cited the disposal company Advance Disposal Services Blue Ridge Landfill for illegally dumping hydraulic fracturing waste. The waste had traveled from West Virginia Marcellus wells, and ended up at an ignorant or willfully negligent waste facility.

In summary, there is inadequate federal oversight of potentially hazardous waste coming from the oil and gas industry, and there are serious regulatory gaps within and between states. Data management practices, too, are lacking. How then, is the public health community supposed to assess the risk that the waste stream poses to people? Obviously, a more thorough action plan is needed to address this issue.


Feature image: Drill cuttings being prepared to be hauled away from the well pad. Photo by Bill Hughes, OVEC

Oklahoma and Kansas Class II Injection Wells and Earthquakes

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance
In collaboration with Caleb Gallemore, Assistant Professor in International Affairs, Lafayette University

The September 3rd magnitude 5.8 earthquake in Pawnee, Oklahoma, is the most violent example of induced seismicity, or “man-made” earthquakes, in U.S. history, causing Oklahoma governor Mary Fallin to declare a state of emergency. This was followed by a magnitude 4.5 earthquake on November 1st prompting the Oklahoma Corporation Commission (OCC) and U.S. EPA to put restrictions on injection wells within a 10-mile radius of the Pawnee quake.

And then on Sunday, November 6th, a magnitude 5.0 earthquake shook central Oklahoma about a mile west of the Cushing Hub, the largest commercial crude oil storage center in North America capable of storing 54 million barrels of crude. This is the equivalent of 2.8 times the U.S. daily oil refinery capacity and 3.1 times the daily oil refinery capacity of all of North America. This massive hub in the North American oil landscape also happens to be the southern terminus of the controversial Keystone pipeline complex, which would transport 590,000 barrel per day over more than 2,000 miles (Fig. 1). Furthermore, this quake demonstrated the growing connectivity between Class II injection well associated induced seismicity and oil transport/storage in the heart of the US version of Saudi Arabia’s Ghawar Oil Fields. This increasing connectivity between O&G waste, production, and processing (i.e., Hydrocarbon Industrial Complex) will eventually impact the wallets of every American.

North American Oil Refinery Capacity, Pipelines, and Cushing, OK

Figure 1. The Keystone Pipeline would transport 590,000 bpd over more than 2,000 miles.

This latest earthquake caused Cushing schools to close. Magellan Midstream Partners, the major pipeline and storage facility operator in the region, also shut down in order to “check the integrity of our assets.” Compounding concerns about induced seismicity, the Cushing Hub is the primary price settlement point for West Texas Intermediate that, along with Brent Crude, determines the global price of crude oil and by association what Americans pay for fuel at the pump, at their homes, and in their businesses.

Given the significant increase in seismic activity across the U.S. Great Plains, along with the potential environmental, public health, and economic risks at stake, we thought it was time to compile an inventory of Class II injection well volumes. Because growing evidence points to the relationship between induced seismicity and oil and gas waste disposal, our initial analysis focuses on Oklahoma and Kansas. The maps and the associated data downloads in this article represent the first time Class II injection well volumes have been compiled in a searchable and interactive fashion for any state outside Ohio (where FracTracker has compiled class II volumes since 2010). Oklahoma and Kansas Class II injection well data are available to the public, albeit in disparate formats and diffuse locations. Our synthesis makes this data easier to navigate for concerned citizens, policy makers, and journalists.

Induced Seismicity Past, Present, and Future

inducedseismicity_figure

Figure 2. Central U.S. earthquakes 1973-August 15, 2015 according to the U.S. Geological Survey (Note: Based on our analysis this exponential increasing earthquakes has been accompanied by a 300 feet per quarter increase in the average depth of earthquakes across Oklahoma, Kansas, and Texas).

Oklahoma, along with Arkansas, Kansas, Ohio, and Texas, is at the top of the induced seismicity list, specifically with regard to quakes in excess of magnitude 4.0. However, as the USGS and Virginia Tech Seismological Observatory (VTSO)[1] have recently documented, an average of only 21 earthquakes of magnitude 3.0 or greater occurred in the Central/Eastern US between 1973 and 2008. This trend jumped to an average of 99 between 2009 and 2013. In 2014 there were a staggering 659 quakes. The exponential increase in induced seismic events can be seen in Figure 2 from a recent USGS publication titled “High-rate injection is associated with the increase in U.S. mid-continent seismicity,” where the authors note:

“An unprecedented increase in earthquakes in the U.S. mid-continent began in 2009. Many of these earthquakes have been documented as induced by wastewater injection…We find that the entire increase in earthquake rate is associated with fluid injection wells. High-rate injection wells (>300,000 barrels per month) are much more likely to be associated with earthquakes than lower-rate wells.”

hydraulic-fracturing-freshwater-demand

Figure 3. Average freshwater demand per hydraulically fractured well across four U.S. shale plays and the annual percent increase in each of those plays.

This trend suggests that induced seismicity is the new normal and will likely increase given that: 1) freshwater demand per hydraulically fractured well is rising all over the country, from 11-15% per year in the Marcellus and Bakken to 20-22% in the Denver and Midland formations, 2) the amount of produced brine wastewater parallels these increases almost 1-to-1, and 3) the unconventional oil and gas industry is using more and more water as they begin to explore the periphery of primary shale plays or in less productive secondary and tertiary plays (Fig. 3).

Oklahoma

The September, 2016, Pawnee County Earthquake

This first map focuses on the September, 2016 Pawnee, OK Magnitude 5.8 earthquake that many people believe was caused by injecting high volume hydraulic fracturing (HVHF) waste into class II injection wells in Oklahoma and Kansas. This map includes all Oklahoma and Kansas Class II injection wells as well as Oklahoma’s primary geologic faults and fractures.

Oklahoma and Kansas Class II injection wells and geologic faults


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Pawnee, Oklahoma 5.8 magnitude earthquake, September, 2016 & Active Class II Injection Wells

Figure 4. The September, 2016 Pawnee, Oklahoma 5.8M earthquake, neighboring active Class II injection wells, underlying geologic faults and fractures.

Of note on this map is the geological connectivity across Oklahoma resulting from the state’s 129 faults and fractures. Also present are several high volume wells including Territory Resources LLC’s Oldham #5 (1.45 miles from the epicenter, injecting 257 million gallons between 2011 and 2014) and Doyle #5 wells (0.36 miles from the epicenter, injecting 61 million gallons between 2011 and 2015), Staghorn Energy LLC’s Hudgins #1 well (1.43 miles from the epicenter, injecting 11 million gallons between 2011 and 2015 into the Red Fork formation), and Cooke Co Production Co.’s Laird #3-35 well (1.41 miles from the epicenter, injecting 6.5 million gallons between 2011 and 2015). Figure 4 shows a closeup view of these wells relative to the location of the Pawnee quake.

Class II Salt Water Disposal (SWD) Injection Well Volumes

This second map includes annual volumes of disposed wastewater across 10,297 Class II injection wells in Oklahoma between 2011 and 2015 (Note: 2015 volumes also include monthly totals). Additionally, we have included Oklahoma’s geologic faults and fractures for context given the recent uptick in Oklahoma and Kansas’ induced seismicity activity.

Annual volumes of class II injection wells disposal in Oklahoma (2011-2015)


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Oklahoma statistics for 2011 to 2015 (Table 1):

  1. Maximum volume to date (for a single Class II injection well): 105,979,598 barrels, or 4,080,214,523 gallons (68,003,574 gallons per month), for the New Dominion, LLC “Chambers #1” well in Oklahoma County.
  2. Total Volume to Date: 10,655,395,179 barrels or 410,232,714,392 gallons (6,837,211,907 gallons per month).
  3. Mean volume to date across the 10,927 Class II injection wells: approximately 975,144 barrels per well or 37,543,044 gallons (625,717 gallons per month).
  4. This map also includes 632 Class II wells injecting waste into the Arbuckle Formation which is believed to be the primary geological formation responsible for the 5.0 magnitude last week in Cushing.

Kansas

Below is an inventory of monthly oil and gas waste volumes (barrels) disposed across 4,555 Class II injection wells in Kansas between 2011 and 2015. This map will be updated in the Spring of 2017 to include 2016 volumes. A preponderance of this data comes from 2015 with a scattering of volume reports across Kansas between 2011 and 2014.

Monthly Class II injection wells volumes in Kansas (2011-2015)


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Kansas statistics for 2015 (Table 1):

  1. Maximum volume to date (for a single Class II injection well): 9,016,471 barrels, or 347,134,134 gallons (28,927,845 gallons per month), for the Sinclair Prairie Oil Co. “H.J. Vohs #8” well in Rooks County. This is a well that was initially permitted and completed between 1949 and 1950.
  2. Total Volume to date: 1,060,123,330 barrels or 40,814,748,205 gallons (3,401,229,017 gallons per month).
  3. Mean volume to date across the 4,555 Class II injection wells: approximately 232,738 barrels per well or 8,960,413 gallons (746,701 gallons per month).

Table 1. Summary of Class II SWD Injection Well Volumes across Kansas and Oklahoma

 

 

Sum Average Maximum
No. of Class II
SWD Wells
Barrels Sum To Date Per Year Sum To Date Per Year
Kansas* 4,555 1.06 BB 232,738 9.02 MB
Oklahoma** 10,927 10.66 BB 975,143 195,029 105.98 MB 21.20 MB

* Wells in the counties of Barton (279 wells), Ellis (397 wells), Rooks (220 wells), Russell (199 wells), and Ness (187 wells) account for 29% of Kansas’ active Class II wells.

** Wells in the counties of Carter (1,792 wells), Creek (946 wells), Pontotoc (684 wells), Seminole (476 wells), and Stephens (1,302 wells) account for 48% of Oklahoma’s active Class II wells.

Conclusion

If the U.S. EPA’s Underground Injection Control (UIC) estimates are to be believed, the above Class II volumes account for 19.3% of the “over 2 billion gallons of brine…injected in the United States every day,” and if the connectivity between injection well associated induced seismicity and oil transport/storage continues to grow, this issue will likely impact the lives of every American.

Given how critical the Cushing Hub is to US energy security and price stability one could easily argue that a major accident there could result in a sudden disruption to fuel supplies and an exponential increase in “prices at the pump” that would make the 240% late 1970s Energy Crisis spike look like a mere blip on the radar. The days of $4.15 per gallon prices the country experienced in the summer of 2008 would again become a reality.

In sum, the risks posed by Class II injection wells and are not just a problem for insurance companies and residents of rural Oklahomans and Kansans, induced seismic activity is a potential threat to our nation’s security and economy.

Downloads

FracTracker Induced Seismicity Infographic (print quality)

Oklahoma Class II SWD Injection Well Annual Volumes 2011 to 2015 (Barrels)

Kansas Class II SWD Injection Well Monthly Volumes 2011 to 2015 (Barrels)

Footnotes

[1] To learn more about Induced Seismicity read an exclusive FracTracker two-part series from former VTSO researcher Ariel Conn: Part I and Part II. Additionally, the USGS has created an Induced Earthquakes landing page as part of their Earthquake Hazards Program.

Wastewater Disposal Facility in Colorado

Groundwater Threats in Colorado

FracTracker has been increasingly looking at oil and gas drilling in Colorado, and we’re finding some interesting and concerning issues to highlight. Firstly, operators in Colorado are not required to report volumes of water use or freshwater sources. Additionally, this analysis looked at how wastewater in Colorado is injected, and found that the majority is injected into Class II disposal wells (85%) while recycling wastewater is not common. Open-air pits for evaporation and percolation of wastewater is still a common practice. Colorado has at least 340 zones granted aquifer exemptions from the Clean Water Act for injecting wastewater into groundwater. The analysis also found that Weld County produces the most oil and gas in the state, while Rio Blanco and Las Animas counties produce more wastewater. And finally, Rio Blanco injects the most wastewater of all Colorado counties. Learn more about groundwater threats in Colorado below:

Introduction

Working directly with communities in Weld County, Colorado the FracTracker Alliance has identified issues concerning oil and gas exploration and production in Colorado that are of particular concern to community stakeholder groups. The issues include air quality degradation, environmental justice concerns for communities most impacted by oil and gas extraction, and leasing of federal mineral estates. Analysis of data for Colorado’s Front Range has identified areas where setback regulations are not followed or are inadequate to provide sufficient protections for individuals and communities and our analysis of floodplains shows where oil and gas operations pose a significant risk to watersheds. In this article we focus on the specific threat to groundwater resources as a result of particular waste disposal methods, namely underground injection and land application in disposal pits and sumps. We also focus on the sources of the immense amount of water necessary for fracking and other extraction processes.

Groundwater Threats

Numerous threats to groundwater are associated with oil and gas drilling, including hydraulic fracturing. Research from other regions shows that the majority of groundwater contamination events actually occur from on-site spills and poor management and disposal of wastes. Disposal and storage sites and spill events can allow the liquid and solid wastes to leach and seep into groundwater sources. There have been many groundwater contamination events documented to have occurred in this manner. For example, in 2013, flooding in Colorado inundated a main center of the state’s drilling industry causing over 37,380 gallons of oil to be spilled from ruptured pipelines and damaged storage tanks that were located in flood-prone areas. There are serious concerns that the oil-laced floodwaters have permanently contaminated groundwater, soil, and rivers.

Waste Management

In Colorado, wastes are managed several ways. If the wastewater is not recycled and used again in other production processes such as hydraulic fracturing, drilling fluids disposal must follow one of three rules:

  1. Treated at commercial facilities and discharged to surface water,
  2. Injected in Class II injection wells, or
  3. Stored and applied to the land and disposal pits at centralized exploration and production waste management facilities.

Additionally the wastes can be dried and buried in additional drilling pits, with restrictions for crop land. For oily wastes, those containing crude oil, condensate or other “hydrocarbon-containing exploration and production waste,” there are additional land application restrictions that mostly require prior removal of free oil. These various sites and facilities are mapped below, along with aquifer exemptions and other map layers related to water quality.

Figure 1. Interactive map of groundwater threats in Colorado


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Injection Wells

In 2015, Colorado injected a total of 649,370,514 barrels of oil and gas wastewater back into the ground. That is 27,273,561,588 gallons, which would fill over 41,000 Olympic sized swimming pools. Injected into the ground in deep formations, this water is forever removed from the water cycle.

Allowable injection fluids include a variety of things you do not want to drink:

  • Produced Water
  • Drilling Fluids
  • Spent Well Treatment or Stimulation Fluids
  • Pigging (Pipeline Cleaning) Wastes
  • Rig Wash
  • Gas Plant Wastes such as:
    • Amine
    • Cooling Tower Blowdown
    • Tank Bottoms

This means that federal exemptions to Underground Injection Control (UIC) regulations for oil and gas exploration and production have nothing to do with environmental chemistry and risk, and only consider fluid source.

Why the concern?

Why are we concerned about these wastes? To quote the regulation, “it is possible for an exempt waste and a non-exempt hazardous waste to be chemically very similar” (RCRA). Since oil and gas development is considered part of the United State’s strategic energy policy, the entire industry is exempt from many federal regulations, such as the Safe Drinking Water Act (SDWA), which protects underground sources of drinking water (USDW).

The Colorado Oil and Gas Conservation Commission has primacy over the UIC permits and the Colorado Department of Public Health and Environment (CDPHE) administers the environmental protection laws related to air quality, waste discharge to surface water, and commercial disposal facilities. Under the UIC program, operators are legally allowed to inject wastewater containing heavy metals, hydrocarbons, radioactive elements, and other toxic and carcinogenic chemicals into groundwater aquifers.

The State of CO Injection Wells

According to the COGCC production reports for the year 2015, there are 9,591 active injection wells with volumes reported to the regulatory agency. Additionally, there are of course distinctions within the UIC rules for different types of injection wells, although the COGCC does not provide comprehensive data to distinguish between these types.

Injecting into the same geological formation or “zone” as producing wells is typically considered EOR, although some of the injected water will ultimately remain in the ground. Injecting into a producing formation is an immediate qualification for receiving an aquifer exemption.

EOR operations require considerably more energy and resources than conventional wells, and therefore have a higher water carbon footprint. If the wastewater is “recycled” as hydraulic fracturing fluid, the injections are exempt from all UIC regulations regardless. These are two options for the elimination of produced wastewater, although much of it will return to the surface in the future along with other formation waters. When the produced waters reach a certain level of salinity the fluid can no longer be used in enhanced recovery or stimulation, so final disposal of wastewater is typically necessary. These liquid wastes may then go to UIC Class II Disposal Wells.

Class II Injection Wells

The wells injecting into non-producing formations are therefore disposal wells, since they are not “enhancing production.” Of the almost 10,000 active injection wells in Colorado there are OVER 670 class II disposal well facilities; 402 facilities are listed as currently active. These facilities may or may not host multiple wells. By filtering the COGCC production and injection well database by target formation, we find that there are over 1,070 wells injecting into non-producing formations. These disposal wells injected at least 66,193,874 barrels (2,780,142,708 gallons) of wastewater in 2015 alone.

Where is the waste going?

A simple life-cycle assessment of wastewater in Colorado shows that the majority of produced water is injected back underground into class II disposal and EOR wells. The percentage of injected produced waters has been increasing since 2012, and in 2015 85% of the total volume of produced water in 2015 was injected.

If we assume that all the volume injected was produced wastewater, this still leaves 60 million barrels of produced water unaccounted for. Some of this volume may have been recycled and used for hydraulic fracturing, but this is rarely the case. Other options for disposal include commercial oilfield wastewater disposal facilities (COWDF) that use wastewater sumps (pits) for evaporation and percolation, as well as land application, to dilute the solid and liquid wastes by mixing them into soil.

Centralized Exploration and Production Waste Management Facilities

Photo by COGCC

Figure 2. Chevron Wastewater Land Application and Pit “Disposal” Facility. Photo by COGCC

According to the COGCC, there are 40 active and 71 total “centralized exploration and production waste management facilities” in Colorado. These facilities, mapped in Figure 1 above, are mostly open-air pits used for storage or disposal, or land-application sites.

As can be seen in the Figure 2 to the right, land application sites are little more than farms that don’t grow anything, where wastewater is mixed with soil. Groundwater monitoring wells around these sites measure the levels of some contaminants. Inspection reports show that sampling of the wastewater is not usually – if ever – conducted. The only regulatory requirement is that oil is not visibly noticeable as a sheen on the wastewater fluids in impoundments, such as the one in Figure 3 below, operated by Linn Operating Inc., which is covered in an oily sheen.

In most other hydrocarbon producing states, open-air pits or sumps are not allowed for a variety of reasons. At FracTracker, we have covered this issue in other states, as well. In New Mexico, for example, the regulatory agency outlawed the use of pits after finding cased where 369 pits were documented to have contaminated groundwater. California is another state that still uses above ground pits for disposal. At sites in California, plumes of contaminants are being monitored as they spread from the facilities into surrounding regions of groundwater. Additionally, these wastewater pit disposal sites present hazards for birds and wildlife. There have been a number of papers documenting bird deaths in pits, and the risk for migratory bird species is of high concern. Other states like California are struggling with the issue of closing these types of open-air pit facilities. Closing these facilities means that more wastewater will be injected in Class II disposal wells.

Linnoilypit

Figure 3. Linn energy oily wastewater disposal pit

Production and Injection Volumes

The data published by the COGCC for well production and injection volumes shows some unique trends. An analysis of injection and production well volumes shows Class II Injection is tightly connected to exploration and production activities. This finding is not surprising. Class II injection wells are considered a support operation for the production wells, and therefore should be expected to be similarly related. Wastewater injection wells are needed where oil and gas extraction is occurring, particularly during the exploration and drilling phases.

Looking at the graphs in Figures 4-6 below, it is obvious that injection volumes have been consistently tied to production of wastewater. It is also clear that the trend since 2012 shows that an increasingly larger percentage of wastewater is being injected each year. This trend follows the sharp increase in high volume hydraulic fracturing activity that occurred in 2012. During this boom in exploration and drilling activity, recycling of flowback for additional hydraulic fracturing activities most likely accounts for some of the discrepancy in accounting for the fact that 200% more wastewater was produced than was injected in 2012.

When Figure 4 (below) is compared to the graphs in Figures 5 and 6 (further below) it is also interesting to note that produced water volumes in 2015 are at a 5-year low as of 2015, while production volumes of both natural gas and oil are at a 5-year high. Wastewater volumes are linked to production volumes, but there are many other factors, including geological conditions and types of extraction technologies being used, that have a massive affect on wastewater volumes.

CO wastewater Volumes by year

Figure 4. Colorado wastewater volumes by year (barrels)

The graphs in Figures 5 and 6 below show different trends. Gas production in Colorado has remained relatively constant over the last five years with a sharp increase in 2015, while oil production volumes have been continually increasing, with the largest increase of 49% from 2014 to 2015, and 46% the year prior.

Figures 5-6

Colorado’s Front Range, specifically Weld County, is increasing oil production at a fast rate. New multi-well well-pads are being permitted in neighborhoods and urban and suburban communities without consideration for even elementary schools. Weld County currently has 2,169 new wells permitted within the county. The figure is higher than the next 9 counties combined. The other top three counties with the most well permits are 2. Garfield (1,130) and 3. Rio Blanco (189), for perspective. Additionally, 74% of pending permits for new wells are located in Weld County.

How Counties Compare

The top 10 counties for oil production are very similar to the top 10 counties for both produced and injected volumes, although there are some inconsistencies (Table 1). For example, Las Animas County produces the second largest amount of produced wastewater, but is not in the top 10 of oil producing counties. This is because the majority of wells in Las Animas County produce natural gas. Natural gas wells do not typically produce as much wastewater as oil wells. The counties and areas with the most oil and gas production are also the regions with the most injection and surface waste disposal, and therefore surface water and groundwater degradation.

Table 1. Top 10 CO counties for gas production, oil production, wastewater production, and injection volumes in 2015.

Gas Production Oil Production Wastewater Production Injection Volumes
Rank County Gas1 County Oil2 County Water2 County Water2
1 Weld 568,919,168 Weld 112,898,400 Rio Blanco 113,132,037 Rio Blanco 138,502,742
2 Garfield 556,855,359 Rio Blanco 4,412,578 Las Animas 45,868,907 Weld 50,360,796
3 La Plata 322,029,940 Gardield 1,744,900 Weld 37,665,571 Garfield 29,022,147
4 Las Animas 78,947,042 Araahoe 1,661,204 Garfield 34,704,673 La Plata 23,211,646
5 Rio Blanco 57,284,876 Lincoln 1,194,435 Washington 25,075,998 Washington 15,105,886
6 Mesa 32,200,936 Cheyenne 1,192,162 La Plata 23,352,861 Las Animas 13,706,555
7 Yuma 25,960,947 Adams 664,530 Cheyenne 9,326,944 Cheyenne 10,309,413
8 Archuleta 13,648,006 Moffat 419,893 Moffat 7,712,323 Logan 5,930,937
9 Moffat 13,610,219 Washington 413,603 Logan 5,606,828 Mesa 5,611,075
10 Gunnison 4,805,541 Jackson 407,537 Morgan 4,197,849 La Plata 4,992,391
1. Units are in MCF = Thousand cubic feet of natural gas;
2. Units are in Barrels

Aquifer Exemptions

Operators are given permission by the U.S. EPA to inject wastewater into groundwater aquifers in certain locations where groundwater formations are particularly degraded or when operators are granted aquifer exemptions. Aquifer exemptions are not regions where the groundwater is not suitable for use as drinking water. Quite the contrary, as any aquifer with groundwaters above a 10,000 ppm total dissolved solids (TDS) threshold are fast-tracked for injection permits. When the TDS is below 10,000 ppm operators can apply for an exemption from SDWA (safe drinking water act) for USDWs (underground sources of drinking water), which otherwise protects these groundwater sources. An exemption can be granted for any of the following three reasons. The formation is:

  • hydrocarbon producing,
  • too deep to economically access, or
  • too “contaminated” to economically treat.

Since the first requirement is enough to satisfy an exemption, most class II wells are located within oil and gas fields. Other considerations include approval of mineral owners’ permissions within ¼ mile of the well. On the map above, you can see the ¼ mile buffers around active injection wells. If you live in Colorado, and suspect you live within the ¼ mile buffer of an injection well, you can input an address into the search field in the top-right corner of the map to fly to that location.

Sources of Water

The economic driver for increasing wastewater recycling is mostly influenced by two factors. First, states with many class II disposal wells, like Colorado, have much lower costs for wastewater disposal than states like Pennsylvania, for example. Additionally, the cost of water in drought-stricken states makes re-use more economically advantageous.

These two factors are not weighted evenly, though. On the Colorado front range, water scarcity should make recycling and reuse of treated wastewater a common practice. The stress of sourcing fresh water has not yet become a finanacial restraint for exploration and production. Water scarcity is an issue, but not enough to motivate operators to recycle. According to an article by Small, Xochitl T (2015) “Geologic factors that impact cost, such as water quality and availability of disposal methods, have a greater impact on decisions to recycle wastewater from hydraulic fracturing than water scarcity.” As long as it is cheaper to permit new injection wells and contaminate potential USDW’s than to treat the wastewater, recycling practices will be largely ignored. Even in Colorado’s arid Front Range where the demand for freshwater frequently outpaces supply, recycling is still not common.

Fresh Water Use

The majority of water used for hydraulic fracturing is freshwater, and much of it is supplied from municipal water systems. There are several proposals for engineering projects in Colorado to redirect flows from rivers to the specific municipalities that are selling water to oil and gas operators. These projects will divert more water from the already stressed watersheds, and permanently remove it from the water cycle.

The Windy Gap Firming Project, for example, plans to dam the Upper Colorado River to divert almost 10 billion gallons to six Front Range cities including Loveland, Longmont, and Greeley. These three cities have sold water to operators for fracking operations. Greeley in particular began selling 1,500 acre-feet (500 million gallons) to operators in 2011 and that has only increased . The same thing is happening in Fort Lupton, Frederick, Firestone, and in other communities. Additionally, the Northern Integrated Supply Project proposes to drain an additional 40,000 acre feet/year (13 billion gallons) out of the Cache la Poudre River northwest of Fort Collins. The Seaman Reservoir Project by the City of Greeley on the North Fork of the Cache la Poudre River proposes to drain several thousand acre feet of water out of the North Fork and the main stem of the Cache la Poudre. And finally, the Flaming Gorge Pipeline would take up to 250,000 acre feet/year (81 billion gallons) out of the Green and Colorado Rivers systems, among others.

Other Water Sources

Unfortunately, not much more is known about sources and amounts of water for used for fracking or other oil and gas development operations. Such a data gap seems ridiculous considering the strain on freshwater sources in eastern Colorado and the Front Range, but regulators do not require operators to obtain permits or even report the sources of water they use. Legislative efforts to require such reporting were unsuccessful in 2012.

Now that development and fracking operations are continuously moving into urban and residential areas and neighborhoods, sourcing water will be as easy as going to the nearest fire hydrant. Allowing oil and gas operators to use municipal water sources raises concerns of conflicts of interest and governmental corruption considering public water systems are subsidized by local taxpayers, not well sites.

Conclusions

In Colorado, exploration and drilling for oil and natural gas continues to increase at a fast pace, while the increase in oil production is quite staggering. As this trend continues, the waste stream will continue to grow with production. This means more Class II injection wells and other treatment and disposal options will be necessary.

While other states are working to end the practices that have a track record of surface water and groundwater contamination, Colorado is issuing new permits. Colorado has issued 7 permits for CEPWMF’s in 2016 alone, some of them renewals. While there aren’t any eco-friendly methods of dealing with all the wastewater, the use of pits and land application presents high risk for shallow groundwater aquifers. In addition, sacrificing deep groundwater aquifers with aquifer exemptions is not a sustainable solution. These are important considerations beyond the obvious contribution of carbon dioxide and methane to the issue of climate change when considering the many reasons why hydrocarbon fuels need to be eliminated in favor of clean energy alternatives.


By Kyle Ferrar, Western Program Coordinator & Kirk Jalbert, Manager of Community Based Research & Engagement, FracTracker Alliance

Cover photo by COGCC

Koontz Class II Injection Well, Trumbull County, Ohio, (41.22806065, -80.87669281) with 260,278 barrels (10,020,704 gallons) of fracking waste having been processed between Q3-2010 and Q3-2012 (Note: Q1-2016 volumes have yet to be reported!).

OH Class II Injection Wells – Waste Disposal Trends and Images From Around Ohio

By Ted Auch, PhD – Great Lakes Program Coordinator

Hydraulic Fracturing "Fracking" at a well-pad outside Barnesville, Ohio operated by Halliburton

Hydraulic Fracturing “Fracking” at a well-pad outside Barnesville, Ohio operated by Halliburton

The industrial practice of disposing of oil and gas drilling waste into Class II injection wells causes a lot of strife for people on both sides of the fracking debate. This process has exposed many “hidden [geologic] faults” across the US as a result of induced seismicity. It has been linked in recent months and years with increases in earthquake activity in states like Arkansas, Kansas, Texas, and Ohio.

Locally, there is growing evidence in counties – from Ashtabula to Washington – that Ohio Class II injection well volumes and quarterly rates of change are related to upticks in seismic activity (Figs. 1-3). But exactly how much waste are these sites receiving, and where is it coming from? Since it has been a little over a year since last we looked at the injection well landscape here in Ohio, we decided to revisit the issue here.

Figures 1-3. Ohio Class II Injection Well disposal during Q3-2010, Q2-2012, and Q2-2015

The Class II Landscape in Ohio

In Ohio 245+ Class II Salt Water Disposal (SWD) Disposal Wells are permitted to accept unconventional oil and gas waste. Their disposal capacity and number of wells served is by far the most of any state across the Marcellus and Utica Shale plays.

Ohio’s Class II Injection wells have accepted an average of 22,750 barrels per quarter per well (BPQPW) (662,632 gallons) of oil and gas wastewater over the last year. In comparison, our last analysis uncovered a higher quarterly average (29,571 BPQPW) between the initiation of frack waste injection in 2010 and Q2-2015 (Fig. 4). This shift is likely due to the significant decrease in overall drilling activity from 2012 to 2015. Between Q3-2010 and Q1-2016, however, OH’s Class II injection wells saw an exponential increase in injection activity.  In total, 109.4 million barrels (3.8-4.6 billion gallons) of waste was disposed in Ohio. From a financial perspective this waste has generated $3.4 million in revenue for the state or 00.014% of the average state budget (Note: 2.5% of ODNR’s annual budget).

The more important point is that even in slow times (i.e., Q2-2015 to the present) the trend continues to migrate from the bottom-left to the top-right, with each of Ohio’s Class II injection wells seeing quarterly demand increases of 972 BPQPW (34,017-40,821 gallons). This means that the total volume coming into our Class II Wells is increasing at a rate of 8.2-9.8 MGs per year, or the equivalent to the water demand of several high volume hydraulically fractured wells.

With respect to the source of this waste, the story isn’t as clear as we had once thought. Slightly more than half the waste came from out-of-state during the first two years for which we have data, but this statistic plummeted to as low as 32% in the last year-to-date (Fig. 5). This change is likely do to the high levels of brine being produced in Ohio as the industry migrates towards the perimeter of the Utica Shale.

Figures 4 and 5

Freshwater Demand and Brine Production

Map of Ohio Utica Brine Production and Class II Injection Well Disposal

View map fullscreen | How FracTracker maps work | Download map data | Related OH Shale Gas Viewer

Ohio Class II injection well disposal and freshwater demand

Figure 6. Ohio Class II Injection Well disposal as a function of freshwater demand by the shale industry in Ohio between Q3-2010 and Q1-2015

To gain a more comprehensive understanding of what’s going on with Class II wastewater disposal in Ohio, it’s important to look into the relationship between brine and freshwater demand by the hydraulic fracturing industry. The average freshwater demand during the fracking process, accounts for 87% of the trend in brine disposal in Ohio (Fig. 6).

As we mentioned, demand for freshwater is growing to the tune of 405-410,000 gallons PQPW in Ohio, 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.

Conclusion

Essentially, the seismic center of Ohio has migrated eastward in recent years; originally it was focused on Western counties like Shelby, Logan, Auglaize, Darke, and Miami on the Indiana border, but it has recently moved to injection well hotbed counties like Ashtabula, Trumbull, and Washington along the Pennsylvania and West Virginia borders. This growth in “induced seismicity” resulting from the uptick in frack waste disposal puts Ohio in the company of Oklahoma, Arkansas, Colorado, Kansas, New Mexico, and Texas. Each of those states have reported ≥4.0 magnitude “man-made” quakes since 2008. Between 1973 and 2008 an average of 21 earthquakes of ≥M3 were reported in the Central/Eastern US. This number jumped to 99 between 2009 and 2013, with 659 of M3+ in 2014 alone according to the USGS and Virginia Tech Seismological Observatory (VTSO). This “hockey stick moment” is exemplified in the below figure from a recent USGS publication (Fig. 7). Figure 8 illustrates the spatial relationship between recent seismic activity and Class II Injection well volumes here in Ohio. The USGS even went so far as to declare the following:

An unprecedented increase in earthquakes in the U.S. mid-continent began in 2009. Many of these earthquakes have been documented as induced by wastewater injection…We find that the entire increase in earthquake rate is associated with fluid injection wells. High-rate injection wells (>300,000 barrels per month) are much more likely to be associated with earthquakes than lower-rate wells.
– From USGS Report High-rate injection is associated with the increase in U.S. mid-continent seismicity

Figures 7 and 8

The sentiment here in Ohio regarding Class II Injection wells is best summed up by Dr. Ray Beiersdorfer, Distinguished Professor of Geology, Youngstown State University and his wife geologist Susie Beiersdorfer who jointly submitted the following quote regarding the North Star (SWIW #10) Class II Injection Well in Mahoning County, which processed 555,030 barrels (21,368,655 gallons) of fracking waste between Q4-2010 and Q4-2011[1].

The operator, D&L, and the ODNR denied the correlation in space and time between the injection of toxic fracking fluids into the well and earthquakes for over eight months in 2011. The well was shut down on December 30 and the largest seismic event, a 4.0 happened at 3:04 p.m. on December 31, 2011. Though the rules say that a “shut-in” well must be plugged after 60 days, this well is still “open” after 1656 days (July 12, 2016). This well must be plugged [and abandoned] to prevent further risks to the health and safety of the Youngstown community… According to Rick Simmers, the only thing holding this up is bankruptcy procedures. It was drilled into a fault, triggered over five hundred earthquakes, including a Magnitude 4.0 that caused damage to homes. [It is likely] that any other use of this well would trigger additional hazardous earthquakes.

Images From Across Ohio

Click on the images below to explore visual documentation and volumes disposed (as of Q1-2016) into Class II Injection wells in Ohio.

Footnote

  1. This is the infamous Lupo well which was linked to 109 tremors in Youngstown by researchers at the Lamont-Doherty Earth Observatory at Columbia University back in the Summer of 2013. The owner of the well Ben W. Lupo was subsequently charged with violating the Clean water Act.
Photo courtesy of Brian van der Brug | LA Times

More Oil Field Wastewater Pits Found in California!

Who’s in charge here?
By Kyle Ferrar, Western Program Coordinator

FracTracker Alliance recently worked with Clean Water Action to map an update to last year’s report* on the use of unlined, above ground oil and gas waste disposal pits, also known as sumps.

The new report identifies additional oil field wastewater pits and details how California regulators continue to allow these facilities to degrade groundwater, surface waters, and air quality. Other oil and gas production states do not permit or allow these type of operations due to the many documented cases of water contamination. A report published in 2011 identified unlined pits and other surface spills as the largest threat to groundwater quality. The sites are ultimately sacrifice zones, where the contamination from produced water and drilling mud solid wastes leaves a lasting fingerprint.

Central Coast & New Central Valley Pit Data

Ca Central Coast oil field wastewater pits

Figure 1. Central Coast wastewater pits

New data has been released by the Central Coast Regional Water Quality Control Board, identifying the locations of 44 active wastewater facilities and 5 inactive facilities in the California counties of Monterey, Santa Barbara, and San Luis Obispo. The number of pits at each facility is not disclosed, but satellite imagery shows multiple pits at some facilities. The locations of the majority of central coast pits are shown in the map in Figure 1, to the right.

In the web map below (Figure 2), the most updated data shows the number of pits at “active” facilities (those currently operating), shown in red and green, and inactive pits, shown in yellow and orange. The number of pits at each facility in the central valley are shown by the size of the graduated circles. Pit count data for the central coast facilities was not reported, therefore all facilities are shown with a small marker.

Figure 2. Interactive map of California oil field wastewater pits

View Map Fullscreen | How Our Maps Work | Download Map Data (Zip File)

Exploring the new central coast data shows that the operators with the most facilities include Greka Oil & Gas Inc. (14), E & B Natural Resources (10), ERG Operating Company, LLC (6), and Chevron (5). As shown in the table below, the majority of central coast pits are located in Santa Barbara County.

Table 1. Summaries by County

Site Counts by Activity and County
Facility Counts Pit Counts
County Active Inactive Active Inactive
Santa Barbara 35 2 Unknown Unknown
Monterey 9 0 Unknown 0
San Luis Obispo 0 3 0 Unknown
Kern 161 191 673 347
Fresno 8 5 31 14
Tulare 6 1 28 1
Kings 5 0 14 0
San Benito 0 4 0 5
Grand Total 224 206 746 367

Wastewater Pit Regulations

Way back in 1988, the U.S. EPA recognized that the federal regulations governing disposal practices of wastewater are inadequate to protect public health, but has yet to take action (NRDC 2015). There is little chance the U.S. EPA will enact regulations focused on pits. In certain cases, if wastewaters spill or are discharged to surface waters the operations will fall under the jurisdiction of the Clean Water Act and will require a National Pollutant Discharge Elimination System (NPDES) permit. Since the objective of the pit is to contain the wastewater to keep it away from surface waters, pits and the wastewater facilities in California that manage them do not require federal oversight. For now the responsibility to protect health and environment has been left to the states.

Most states have responded and have strict regulations for wastewater management. For the few states that allow unlined pits, the main use is storage of wastewater rather than as an dedicated method of disposal. The majority of high production states have banned or ended the use of unlined pits, including Texas, North Dakota, Pennsylvania, Ohio, and New Mexico, Texas (Heberger & Donnelly 2015). An effective liner will prevent percolation of wastewaters into groundwater. The goal of California oil field wastewater pits is quite the opposite.

For California, percolation is the goal and a viable disposal option.

Therefore other regulations that require monitoring of liquid levels in the pits are moot. In fact there is no evidence of regulation requiring spill reporting in California whatsoever (Kuwayama et al. 2015).

Numerous other extraction states throughout the country have phased out the use of open pits entirely, including those with liners due to the common occurrence of liner failures. The list includes those new players in the shale boom using hydraulic fracturing techniques such as North Dakota, Ohio, Pennsylvania, Wyoming, and Colorado. Rather than using the pits as storage, these states’ regulatory agencies favor instead the protections of closed systems of liquid storage. Wastewaters are stored in large tanks, often the same tanks used to store the fresh water used in the hydraulic fracturing process.

Because hydraulic fracturing in California uses much less water, it should be much easier to manage the flowback fluids and other wastewaters. According to the CCST report, 60% of the produced water from hydraulic fracturing operations was disposed to these unlined pits. Regardless of extraction technique, oil extraction in California produces 15 times the amount of wastewater. In total, an estimated 40% of all produced water was discharged to unlined “percolation” pits. As the 3rd largest oil producing state in the country, this equates to a massive waste stream of about 130 billion gallons/year (Grinberg 2014).

Regulatory Action

The facilities’ permits identify waste discharge requirements (WDRs) that allow for the discharge of oil field wastewater to the “ground surface, into natural drainage channels, or into unlined surface impoundments.” Using the Race Track Hill and Fee 34 Facilities as an example, the WDRS place criteria limits on total dissolved solids (TDS), chlorides, and boron. If you disregard all the other toxic constituents not monitored, the allowable concentration limits set for these three wastewater constituents would be reasonable for a discharge permit on the east coast, where a receiving body of water could provide the volume necessary for dilution. When the wastewater is applied directly to the ground or into a pit, the evaporative loss of water results in elevated concentrations of these contaminants.

Even with these very lax regulations, a number of facilities are in violation of the few restrictions required in their permits. Cease and desist orders have been several operators, most notably to Valley Water Management’s Race Track Hill and Fee 34 Facilities. According to the Regional Water Board documents, the Fee 34 disregarded salinity limitations and other regulations. As a result the Regional Water Board found soil and groundwater contamination that “threatens or creates a condition of pollution in surface and groundwater, and may result in the degradation of water quality.” Reports show that 6 domestic supply and 12 agricultural supply wells are located within 1 mile of the Fee 34 facility. At the Race Track Hill Facility the wastewater is continuously sprayed over several acre fields in a small watershed of the Cottonwood Creek. During a rain, the salt and boron loadings that have accumulated in the soil over the past 60 years of spraying can create increased salt and boron loading in the Kern River and groundwater. This would be a violation of the Clean Water Act (CVRWQCB 2015).

As shown in Table 2, below, the majority of facilities are currently operating without a permit whatsoever (61.2%). Of the 72 facilities that bothered to get permits, 32 (44.4%) received the permit prior to 1975, before the Tulare Basin Plan was implemented to preserve water quality. Of the 183 active facilities in the Central Valley, only 15 facilities have received Cease and Desist (11% of permitted) or Cleanup and Abatement Orders (6% of unpermitted). Only 3 of the 41 active Central Coast facilities operate with a permit (7.3%).

These types of WDR permits that allow pollutants to concentrate in the soil and the groundwater and degrade air quality. Chemicals that pose a public health risk are not being monitored. But at this point, these facilities are not only sites of legacy contamination, but growing threats to groundwater security. Operators say that closing the pits will mean certain doom for oil extraction in California, and recent letters from operators make pleas to DOGGR, that their very livelihood depends on using the pits as dumping grounds. The pits are the cheapest and least regulated mode of disposal.

Table 2. Facility Status Summaries

Facility Status
Activity Permitted Permitted; Cease & Desist Order Unpermitted Unpermitted; Cleanup & Abatement Order Grand Total
Active 75 9 137 6 227
Inactive 20 2 184 3 209
Grand Total 92 11 321 9 433

New Mexico Case Study

Much like the groundwater impacts documented by California’s Central Valley Regional Water Quality Control Board, other states have been forced to deal with this issue. The difference is that other states have actually shut down the polluting facilities. In California, cease and desist orders have been met with criticism and pleas by operators, stating that the very livelihood of the oil and gas industry in California depends on wastewater disposal in pits. The same was said in other states such as New Mexico when these crude and antiquated practices were ended. Figure 3 below shows the locations of wastewater pits in New Mexico and the areas where groundwater was contaminated as a result of the pits.
The New Mexico oil and gas industry predicted in August 2008 that fewer drillers would sink wells in New Mexico, at least in part because of the new pit rule. Pro-industry (oil and gas) state representatives were concerned that new drilling techniques coupled with the pit rules could lead to an industry exodus from New Mexico, hoping that the Governor “would step in to help protect an important state revenue source.” But the state’s average rig count from June — when the pit rule took effect — through December 2008 was 7% higher than it was over the same period in the previous year. Development of oil and gas reserves is independent of such regulation. Read the FracTracker coverage of groundwater contamination in New Mexico, here!

Figure 3. Legacy map of cases where pits contaminated groundwater in New Mexico

View Map Fullscreen | How Our Maps Work

References & Resources

* In case you missed it, the 2014 report on wastewater pits can be found here (Grinberg, A. 2014). FracTracker’s previous coverage of the issue can be found here.

** Feature image of Central Valley oil field wastewater pits courtesy of Brian van der Brug | LA Times

  1. Grindberg, A. 2016. UPDATE ON OIL AND GAS WASTEWATER DISPOSAL IN CALIFORNIA: California Still Allowing Illegal Oil Industry Wastewater Dumping Clean Water Action. Accessed 2/15/16.
  2. Grinberg, A. 2014. In the Pits, Oil and Gas Wastewater Disposal into Open Unlined Pits and the Threat to California’s Water and Air. Clean Water Action. Accessed 12/5/14.
  3. NRDC. 2015. Groups File Notice of Intent to Sue EPA Over Dangerous Drilling and Fracking Waste. NRDC. Accessed 10/1/15.
  4. Heberger, M. Donnelly, K. 2015. Oil, Food, and Water: Challenges and Opportunities for California Agriculture. Pacific Institute. Accessed 2/1/16.
  5. Kuwayama et al. 2015. Pits versus Tanks: Risks and Mitigation Options for On-site Storage of Wastewater from Shale Gas and Tight Oil Development. Resources for the Future. Accessed 2/1/16.
  6. CVRWQCB. 2015. Cease and Desist Order R5-2015-0093. CVRWQCB. Accessed 2/1/16.
Oil wastewater pit

Wastewater Pits Still Allowed in California

By Kyle Ferrar, Western Program Coordinator

Above-ground, unlined, open-air sumps/ponds

It is hard to believe, but disposing of hazardous oil and gas wastewaters in unlined, open-air pits – also known as sumps or ponds – is still a common practice in California. It is also permitted in other states such as Texas and West Virginia. Because these ponds are unlined and not enclosed, they contribute to degraded air quality, are a hazard for terrestrial animals and birds, and threaten groundwater quality. A 2014 report by Clean Water Action, entitled In the Pits provides a thorough summary of the issue in California. Since the report was released, new data has been made available by the Central Valley Regional Water Quality Review Board identifying additional locations of wastewater pits.

With the increase of oil and gas development in unconventional reservoirs, such as the Monterey Shale Play in California, the size of the resultant waste stream of drill cuttings, produced brines, and wastewater has skyrocketed. Operators now drill larger, deeper wells, requiring larger volumes of liquid required for enhanced oil recovery methods, such as steam injection, and stimulations such as hydraulic fracturing and acidizing. While California is the 4th largest oil-producing state, it is 2nd only to Texas in wastewater production. This boom of unconventional development, which may still in its infancy in California, has resulted in an annual waste stream of over 130 billion gallons across the state, 80 billion (62%) from Kern County alone.1

Results of the state mandated California Council on Science and Technology Report found that more than half of the California oil industries waste water is “disposed” in pits.2 As outlined by Clean Water Action, the massive waste-stream resulting from drilling, stimulation, and production is one of the most significant and threatening aspects of oil and gas operations in terms of potential impacts to public health and environmental resources.

Wastewater Facility Details

Last February, the LA Times reported on the pits, identifying a total of 933 in California.3 The most recent data from the Regional Water Quality Control Board of the Central Valley shows:

  • A total of 1,088 pits at 381 different facilities
  • 719 pits are listed as “Active.” 369 are “Idle.”
  • 444/939 (47.3%) ponds do not list a permit.
  • 462 pits are operated by Valley Water Management Corporation.

In Table 1, below, the counts of Active and Idle facilities and pits are broken down further to show the numbers of sites that are operating with or without permits. The same has been done for the operator with the most pits in Table 2, because Valley Wastewater operates nearly 9 times as many pits as the second largest operator, E & B Natural Resources Management Corporation. These two operators, along with California Resources Elk Hills LLC, all operate the same number of facilities (28). The other top 20 operators in Kern County are listed in Table 3, below.

Table 1. Wastewater Pit and Facility Counts by Category
Counts Active Idle
Facilities 180 201
Unpermitted Facilities 102 179
Facility Permitted prior to 1985 37 11
Individual Pits 719 369
Unpermitted Individual Pits 187 257
Pit Permitted prior to 1985 252 63

 

Table 2. Valley Water Wastewater Pit and Facility Counts by Category
Counts Active Inactive
Facilities 21 7
Unpermitted Facilities 2 2
Facility Permitted prior to 1985 9 1
Individual Pits 356 78
Unpermitted Individual Pits 5 9
Pit Permitted prior to 1985 166 35

 

Table 3. Top 20 Operators by Facility Count, with Pond Counts.
Rank Operator Pond Count Facility Count
1 Valley Water Management Company 462 28
2 E & B Natural Resources Management Corporation 53 28
3 California Resources Elk Hills, LLC 31 28
4 Aera Energy LLC 67 25
5 California Resources Corporation 31 23
6 Chevron U.S.A. Inc. 40 14
7 Pyramid Oil Company 21 12
8 Macpherson Oil Company 14 9
9 Schafer, Jim & Peggy 8 8
10 Crimson Resource Management 20 6
11 Bellaire Oil Company 11 6
12 Howard Caywood 11 6
13 LINN Energy 10 6
14 Seneca Resources Corporation 9 6
15 Holmes Western Oil Corporation 6 6
16 Hathaway, LLC 22 5
17 Central Resources, Inc. 15 5
18 Griffin Resources, LLC 13 5
19 KB Oil & Gas 8 5
20 Petro Resources, Inc. 6 5

Maps of the Pit Locations and Details

 

The following maps use the Water Authority data to show the locations details of the wastewater pits. The first map shows the number of pits housed at each facility. Larger markers represent more pits. Zoom in closer using the [+] to see the activity status of the facilities. Click the link below the map to open a new webpage. View the names of the facility operators by turning on the layer in the “Layers” menu at the top of the page. The second and third maps show the activity and permit status of each facility. The fourth map allows you to view both activity status and permit status simultaneously by toggling the layers on and off (Open the map in its own webpage, then use the layers menu at the top of the screen to change views).

Map 1. Facility Pit Counts with the top 10 operators identified as well as facility status

Map 1. To view the legend and map full screen, click here.

Map 2. Facility Activity Status

Map 2. To view the legend and map full screen, click here.

Map 3. Facility Permit Status

Map 3. To view the legend and map full screen, click here.

Map 4. Facilityhttps://maps.fractracker.org/lembed/?appid=7385605f018e437691731c94bb589f0a” width=”800″ height=”500″>
Map 4. To view the legend and map full screen, click here.

References

  1. USGS. 2014. Oil, Gas, and Groundwater Quality in California – a discussion of issues relevant to monitoring the effects of well stimulation at regional scales.. California Water Science Center. Accessed 10/1/15.
  2. CCST. 2015. Well Stimulation in California. California Council on Science and Technology. Accessed 9/1/15.
  3. Cart, Julie. 2/26/15. Hundreds of illicit oil wastewater pits found in Kern County . Los Angeles Times. Accessed 9/1/15.

The Curious Case of the Shrinking Utica Shale Play

Oil, Gas, and Brine Oh My!
By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

It was just three years ago that the Ohio Geological Survey (OGS) and Department of Natural Resources (DNR) were proposing – and expanding – their bullish stance on the potential Utica Shale oil and gas production “play.” Back in April 2012 both agencies continue[d] to redraw their best guess, although as the Ohio Geological Survey’s Chief Larry Wickstrom cautioned, “It doesn’t mean anywhere you go in the core area that you will have a really successful well.”

What we found is that the OGS projections have not held up to their substantial claims. And here is why…

Background

The Geological Survey eventually parsed the Utica play into pieces:

  • a large oil component encompassing much of the central part of the state,
  • natural gas liquids from Ashtabula on the Pennsylvania border southwest to Muskingum, Guernsey, and Noble Counties, and
  • natural gas counties, primarily, along the Ohio River from Columbiana on the Pennsylvania-West Virginia border to Washington County in the Southeast quarter of the state.
Columbus Dispatch Utica Shale "play" map

Columbus Dispatch Utica Shale “play” map

Fast forward to the first quarter of 2015 and we have a very healthy dataset to begin to model and validate/refute these projections. Back in 2009 Wickstrom & Co. only had 53 Utica Shale laterals, while today Ohio is host to 962 laterals from which to draw our conclusions. The preponderance of producing wells are operated by Chesapeake (463), Gulfport (118), Antero Resources (62), Eclipse Resources (41), American Energy Utica (36), Consol (35), and R.E. Gas Development (34), with an additional 13 LLCs and 10 publicly traded companies accounting for the remaining 173 producing laterals. A further difference between the following analysis and the OGS one is that we looked at total production and how much oil and gas was produced on a per-day basis.

Analysis

Using an interpolative geostatistical technique known as Empirical Bayesian Kriging and the 962 lateral dataset, we modeled total and per day oil, gas, and brine production for Ohio’s Utica Shale between 2011 and Q1-2015 to determine if the aforementioned map redrawing holds up, is out-of-date, and/or is overly optimistic as is generally the case with initial O&G “moving target” projections.

Days of Activity & Brine Production

The most active regions of the Utica Shale for well pad activity has been much of Muskingum County and its border with Guernsey and Noble counties; laterals are in production every 1 in 2.1-3.4 days. Conversely, the least active wells have been drilled along the Harrison-Belmont border and the intersection between Harrison, Tuscarawas, and Guernsey counties.

Brine is a form of liquid drilling waste characterized by high salt loads and total dissolved solids. The laterals that have produced the most brine to date are located in a large section of Monroe County and at the intersection of Belmont, Monroe, and Noble counties, with total brine production amounting to 23,292 barrels or 734,000-978,000 gallons (Fig. 1).

Total Ohio Utica Shale Production Days 2011 to Q1-2015

Total Ohio Utica Shale Oil Production 2011 to Q1-2015

Total Ohio Utica Shale Gas Production 2011 to Q1-2015

Total Ohio Utica Shale Brine Production 2011 to Q1-2015

Figure 1. Total Ohio Utica Shale Oil, Gas, and Brine Production 2011 to Q1-2015

This area is also one of the top three regions of the state with respect to Class II Injection volumes; the other two high-brine production regions are Morrow and Portage counties to the west and southwest, respectively (Fig. 2).

Layout & Volume (2010 to Q1-2015, Gallons) of Ohio’s Active Class II Injection Wells

Figure 2. Layout & Volume (2010 to Q1-2015, Gallons) of Ohio’s Active Class II Injection Wells

However, on a per-day basis we are seeing quite a few inefficient laterals across the state, including Devon Energy’s Eichelberger and Richman Farms laterals in Ashland and Medina counties. Ashland and Medina are producing 230-270 barrels (8,453-9,923 gallons) of brine per day. In Carroll County, one of Chesapeake’s Trushell laterals tops the list for brine production at 1,843 barrels (67,730 gallons) per day. One of Gulfport’s Bolton laterals in Belmont County and EdgeMarc’s Merlin 10PPH in Washington County are generating 1,100-1,200 barrels (40,425-44,100 gallons) of brine per day.

Oil & Gas Production

Since the last time we modeled production the oil hotspots have shrunk. They have also become more discrete and migrated southward – all of this in contrast to the model proposed by the OGS in 2012. The areas of greatest productivity (i.e., >26,000 barrels of oil) are not the central part of the state, but rather Tuscarawas, Harrison, Guernsey, and Noble counties (Fig. 1). The intersection of Harrison, Tuscarawas, and Guernsey counties is where oil productivity per-day is highest – in the range of 300-630+ barrels (Fig. 3). The areas that the OGS proposed had the highest oil potential have produced <600 barrels total or <12 barrels per day.

Per Day Ohio Utica Shale Oil Production 2011 to Q1-2015

Per Day Ohio Utica Shale Gas Production 2011 to Q1-2015

Per Day Ohio Utica Shale Brine Production 2011 to Q1-2015

Figure 3. Per-Day Ohio Utica Shale Oil, Gas, and Brine Production 2011 to Q1-2015

The OGS natural gas region has proven to be another area of extremely low oil productivity.

Natural gas productivity in the Utica Shale is far less extensive than the OGS projected back in 2012. High gas production is restricted to discreet areas of Belmont and Monroe counties to the tune of 947,000-4.1 million Mcf to date – or 5,300-18,100 Mcf per day. While the OGS projected natural gas and natural gas liquid potential all the way from Medina to Fairfield and Perry counties, we found a precipitous drop-off in productivity in these counties to <1,028 Mcf per day (<155,000 Mcf total from 2011 to Q1-2015) or a mere 6-11% of the Belmont-Monroe sweet spot.

Conclusion: A Shrinking Utica Shale Play

Simply put, the OGS 2012 estimates:

  • Have not held up,
  • Are behind the times and unreliable with respect to citizens looking to guestimate potential royalties,
  • Were far too simplistic,
  • Mapped high-yield sections of the “play” as continuous when in fact productive zones are small and discrete,
  • Did not differentiate between per day and total productivity, and
  • Did not address brine waste.

These issues should be addressed by the OGS and ODNR on a more transparent and frequent basis. Combine this analysis with the disappointing returns Ohio’s 17 publicly traded drilling firms are delivering and one might conclude that the structural Utica Shale bubble is about to burst. However, we know that when all else fails these same firms can just “lever up,” like their Rocky Mountain brethren, to maintain or marginally increase production and shareholder happiness. Will these Red Queens of the O&G industry stay ahead of the Big Bank and Private Equity hounds on their trail?

Digging into Waste Data

Pennsylvania’s Drilling Waste Distributed to Eight States

By Matt Kelso, Manager of Data & Technology

According to data published by the Pennsylvania Department of Environmental Protection (DEP), Pennsylvania’s unconventional oil and gas waste that was generated in the first half of 2015 found its way to treatment facilities, disposal wells, and landfills in eight different states. While the majority of the waste stayed in-state, neighboring Ohio, New York, and West Virginia all received significant quantities of both solid and liquid waste, and additional disposals were made in the non-contiguous states of Michigan, Texas, Utah, and Idaho.


Waste generated by Pennsylvania’s unconventional oil and gas wells was disposed of in a variety of ways and over a large geographic area. Click on a facility to learn more, or zoom in to access waste generated by individual wells. Click here to access the full screen map with a legend and additional controls.

Unconventional drillers in the state are now required to report production data monthly, rather than in six month increments, but waste quantities generated by the wells is still supposed to be reported biannually. However, a small number of operators have been reporting waste monthly, as well, and those figures have been included in this analysis, after spot-checking for duplication. Each record includes data on how the waste was processed and where it was shipped, so we were able to map the receiving facilities as well, and aggregate their waste totals.

Types of Waste

Waste generated by unconventional wells in Pennsylvania from January to June 2015.

Waste generated by unconventional wells in Pennsylvania from January to June 2015 by type.

There are eight types of waste detailed in the Pennsylvania data, including:

  • Basic Sediment (Barrels) – Impurities that accompany the desired product
  • Drill Cuttings (Tons) – Broken bits of rock produced during the drilling process
  • Flowback Fracturing Sand (Tons) – Sand used to prop open cracks made during hydraulic fracturing that return to the surface
  • Fracing Fluid Waste (Barrels) – Fluid pumped into the well for hydraulic fracturing that returns to the surface. This includes chemicals that were added to the well.
  • Produced Fluid (Barrels) – Naturally occurring brines encountered during drilling that contain various contaminants, which are often toxic or radioactive
  • Servicing Fluid (Barrels) – Various other fluids used in the drilling process
  • Spent Lubricant (Barrels) – Oils used in engines as lubricants
  • General O&G Waste (Tons) – Solid waste types other than drill cuttings or fracturing sand

For the sake of simplicity, this analysis will at times aggregate the waste types into two categories, with all types reporting in tons as solid waste, while those listed in 42 gallon barrels will be considered liquid waste.

Waste Disposal

Waste disposal method for unconventional wells in PA, January to June 2015

Waste disposal method for unconventional wells in PA, January to June 2015

This PA waste gets disposed of in a variety of ways. About 93 percent of all solid waste ends up in landfills. 29 of the 58 operators reporting waste during this cycle reported drill cuttings. In a separate report, the DEP has records for unconventional wells drilled by 28 different operators during the same time frame, so these results seem reasonable, since drill cuttings are generated during the drilling process, whereas other types of waste are produced throughout the life cycle of the well.

Statewide, there over 596,000 tons of drill cuttings produced during a period which saw 422 wells spudded, an average of 1,412 tons of cuttings per well. Not all operators generated the same amount of cuttings per well, however. Vantage Energy reports 3,089 tons of cuttings per well, while Hilcorp Energy manages to average just 119 tons over 23 wells drilled in the six month period. It is worth noting that some wells that were spudded just prior to the reporting period likely still generated drill cuttings during the six months in question, and some wells spudded during the cycle will continue to produce cuttings into the next one.

In terms of liquid waste, nearly two thirds of the amount reported is reused for purposes other than road spreading. This is, unfortunately, a dead end in terms of being able to follow the waste stream in the data, as there are no facilities associated with the 13.8 million barrels of waste that falls into this category. 225,000 barrels are specified as being reused for hydraulic fracturing, while the remainder is simply destined for, “Reuse without processing at a permitted facility.”

The amount used for road spreading, 147 barrels, is relatively small, and all of this waste is reported as going to private roads in Greene County. The total amount of liquid waste produced in the six month period is almost 879 million gallons, or enough to fill 1,331 Olympic-sized swimming pools.

PA Waste Receiving Facilities

Altogether, we know where roughly 7 million of the nearly 21 million barrels of reported liquid waste wound up, as well as 640,000 of the 647,000 tons of solid waste. The top ten destinations for each waste type are as follows:

Top 10 reported recipients of unconventional O&G waste produced in PA during the first half of 2015.

Top 10 reported recipients of unconventional O&G waste produced in PA during the first half of 2015.

Six of the top destinations for liquid waste were located in-state, while seven of the top ten facilities for solid waste stayed in Pennsylvania. The only facility to appear on both lists is Patriot Water Treatment in Warren, Ohio.

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