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FracTracker Alliance

In-depth Review of the Statoil Well Pad Fire

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Commentary on Shale Gas Operations: First in a Series of Articles
By Bill Hughes, Community Liaison, FracTracker Alliance
Statoil Well Pad Fire: June 28-29, 2014

The early riser residents along Long Ridge Road in Monroe County are among the first in Ohio to see the sun coming up over the West Virginia hills.  It rose about 6:00 am on the morning of June 28th.  Everyone assumed that this would be a normal Saturday morning.  Well, at least as normal as it had been for the better part of two years since the site preparation and drilling started.

For those residents on Long Ridge who were not early risers, the blaring sirens, the smell of acrid smoke, and the presence of fire trucks and other emergency vehicles shortly after 9:00 am must surely have made them wonder if they were in the midst of a nightmare. A quick glance outside toward the Statoil Eisenbarth well pad and they would have seen this view:

Statoil 1

Figure 1. View from the southeast, as the fire spread on Sat. June 28th

The image in Fig. 1 would be enough to make most folks feel somewhat panicky and consider evacuating the neighborhood. That is exactly what soon happened – definitely not the start of a normal Saturday morning.

Adjusting to the New Normal

The traffic in the area had been a problem ever since site preparation started on the nearby well pad. The State expected the drillers to keep up the road. Crews also provided lead escort vehicles to help the many big trucks negotiate the narrow road way and to clear the residential traffic. Access to the well site required trucks to climb a two-mile hill up to the ridge top.

Statoil 2

Fig. 2. Neighbors’ views of the fire

Until June 28th, most folks had become accustomed to the extra noise, diesel fumes, and congestion and delays that always come with any shale gas well exploration and development in the Marcellus shale gas active area. Most of the neighbors had gotten used to the new normal and reluctantly tolerated it. Even that was about to change, dramatically.  As the sun got higher in the eastern sky over WV, around 9:00 AM, suddenly the sky started to turn dark. Very dark. Sirens wailed. Red trucks started a frenzied rush down Long Ridge from all directions. There was a fire on the well pad. Soon it became a very large, all consuming fire.  Smoke, fire, bitter fumes, and no one seemed to know yet exactly what had happened, and what was likely to happen soon.

This gas well location, called the Eisenbarth pad, recently changed operators. In January 2013, the well pad property and its existing well and equipment were bought out by Statoil, a company based in Norway.  Statoil had since drilled seven more wells, and even more were planned.  The original single well was in production.  Now in late spring and early summer of 2014 the new wells were to be “fracked.”  That means they were ready to be hydraulically fractured, a procedure that follows the completion of the drilling process.

Statoil hired as their fracturing sub-contractor Halliburton. All of the fracturing pump trucks, sand kings, Sand Castles, and control equipment were owned and operated by Halliburton.  The fracturing process had been ongoing for some weeks when the fire started. The eastern Ohio neighbors now watched ~$25 million worth of equipment go up in smoke and flames (Fig. 2). The billowing smoke was visible for over 10 miles.

Industrial accidents are not rare in the Ohio Valley

Many of the residents nearby had worked in the coal mining industry, aluminum plants, chemical plants, or the coal fired power plant that were up and down the Ohio River. Many had since retired and had their own industrial accident stories to tell. These were frequently private stories, however, which mostly just their co-workers knew about. In an industrial plant, the common four walls and a roof kept the dangerous processes confined and enabled a trained response to the accidents. The traditional, industrial workplace had well-proven, customized workplace safety standards.  Professional maintenance personnel were always nearby.  In stark contrast, unconventional gas well pads located in our rural communities are very different. They are put in our hayfields, near our homes, in our pastures and just down the road. You cannot hide a community accident like this.

Sept 2014 Update: Video of the fire, Copyright Ed Wade, Jr.

Print Media Coverage of the Fire

Within days, many newspapers were covering the well pad fire story. The two nearby weekly newspapers, one in Monroe County, Ohio and the other in Wetzel County, West Virginia both had detailed, long articles the following week.

Statoil 3

Fig. 3. View from the east as the fire started

The Monroe County Beacon on July 2, 2014 said that the fire spread quickly from the small original fire which was totally surrounded within the tangled complex of equipment and high pressure piping.  Early Saturday morning, the first responder would likely have seen a rather small somewhat localized fire as shown in Fig. 2. The photo to the right (Fig. 3) is the view from the east, where the access road is on Long Ridge road. This point is the only access into the Statoil well pad. The view below, showing some still intact tanker trucks in the foreground, is looking west toward the well location. Pay attention to the couple of trucks still visible.

The Monroe County emergency director said it was his understanding that the fire began with a ruptured hydraulic hose. The fluid then ignited on a hot surface. He said, “…by 9:10 AM the fire had spread to other pumps on the location and was spreading rapidly over the well pad.”   Emergency responders needed water now, lots of it. There is only one narrow public road to the site at the top of a very long, steep hill and only one narrow entrance to the densely congested equipment on the pad.  Many Volunteer Fire Departments from both Ohio and West Virginia responded.  A series of tanker trucks began to haul as much water to the site as possible.  The combined efforts of all the fire departments were at best able to control or contain but not extinguish the powerful, intensely hot and growing blaze.  The Volunteer firemen did all they could. The EMS director and Statoil were very grateful for the service of the Volunteer Fire Departments. There was a major loss of most equipment, but none of the 45-50 workers on site were injured.

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Fig. 4. Well pad entrance

The article from the Wetzel Chronicle also praised the coordinated effort of all the many fire departments. At first they attempted to fight the fire, and then prudently focused on just trying to limit the damage and hoping it did not spread to the well heads and off the well pad itself. The New Martinsville fire chief also said that,  “… the abundance of chemicals and explosives on the site, made attempts to halt the fire challenging, if not nearly impossible… Numerous plans to attack the fire were thwarted each time by the fires and numerous explosions…”  The intense heat ignited anything nearby that was at all combustible. There was not much choice but to let the fire burn out.

Eventually the view at the well pad entrance as seen from the east (Fig. 3) would soon look like the overhead view (Fig. 5). This aerial imagery shows what little remained after the fire was out – just some aluminum scrap melted into the decking is left of the original, white Hydrochloric Acid tanker truck. Everything near it is has almost vaporized.

Statoil 5

Figure 5. Post-fire equipment identification

Efforts to Limit the Fire

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Fig. 6. Protected white trailer

An excellent example of VFD’s successfully limiting the spread of the fire and controlling the extreme heat can be seen in the photo to the right (Fig. 6). This white storage trailer sure seems to be a most favored, protected, special and valuable container. It was.

It was filled with some particularly dangerous inventory. The first EPA report explains it thus:

A water curtain was maintained, using pump lines on site, to prevent the fire from spreading to a trailer containing 1,100 pounds of SP Breaker (an oxidizer), 200 pounds of soda ash and compressed gas cylinders of oxygen (3-2000 lb.), acetylene (2-2000 lb.), propane (6-20 lb.), among miscellaneous aerosol cans.

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Fig. 7. Post-fire pad layout

Yes, this trailer got special treatment, as it should. It contained some hazardous material.  It was also at the far southwest corner of the well pad with minimal combustibles near it.  That was also the closest corner to the nearby holding pond, which early on might have held fresh water. Now the holding pond is surely very contaminated from flowback and runoff.

The trailer location can be seen in the picture to the right in the red box (Fig. 7), which also shows the complete well pad and surrounding area. However, in comparison to the one white storage trailer, the remainder of the well pad did not fare so well. It was all toast, and very burned toast at that.

Columbus Dispatch and the Fish Kill

Besides the two local newspapers, and Wheeling Jesuit researchers, the Columbus Dispatch also covered the story and provided more details on the 3- to 5-mile long fish kill in the stream below the well pad. Additional facts were added by the two EPA reports:

Those reports list in some detail many of the chemicals, explosives, and radiological components on the well pad.  Reader note: Get out your chemical dictionary, or fire up your Google search. A few excerpts from the first EPA report are provided below.

…Materials present on the Pad included but was not limited to: diesel fuel, hydraulic oil, motor oil, hydrochloric acid, cesium-137 sources, hydrotreated light petroleum distillates, terpenes, terpenoids, isoproponal, ethylene glycol, paraffinic solvents, sodium persulfate, tributyl tetradecyl phosphonium chloride and proprietary components… The fire and explosion that occurred on the Eisenbarth Well Pad involved more than 25,000 gallons of various products that were staged and/or in use on the site… uncontained run-off was exiting the site and entering an unnamed tributary of Opossum Creek to the south and west and flowback water from the Eisenbarth Well #7 was spilling onto the well pad.

Reader Warning:  If you found the above list overly alarming, you might choose to skip the next equally disturbing list. Especially since you now know that this all eventually flowed into our Ohio River.

The EPA report continues with more specific chemical products involved in the fire:

Initial reports identified the following products were involved and lost in the fire: ~250 gallons of hydrochloric acid (28%), ~7,040 gallons of GasPerm 1000 (terpenes, terpenoids, isopropanol, citrus extract, proprietary components), ~330 gallons of LCA-1 (paraffinic solvents), ~ 1900 gallons of LGC-36 UC (hydrotreated light petroleum distillate, guar gum), ~1000 gallons of BC-140 (monoethanolamine borate, ethylene glycol), ~3300 gallons of BE-9 (tributyl tetradecyl phosphonium chloride), ~30,000 gallons of WG-36 (polysaccharide gel), ~1,000 gallons of FR-66 (hydrotreated light petroleum distillate), ~9000 gallons of diesel fuel, ~300 gallons of motor and hydraulic oil.

Even more details of the incident and the on-site chemicals are given in the required Statoil 30-day report (PDF).

The EPA reports detail the “sheet” flow of unrestricted contaminated liquids off of the well pad during and after the fire. They refer to the west and south sides. The below Google Earth-based map (Fig. 8) shows the approximate flow from the well pad. The two unnamed tributaries join to form Opossum Creek, which then flows into the Ohio River four miles away.

Statoil 8

Figure 8. Map showing path of unrestricted flow off of the Statoil well pad due to a lack of berm

After describing some of the known chemicals on the well pad, the EPA report discusses the construction of a new berm, and where the liquid components flowed. Below is a selection of many excerpts strung together, from many days, taken directly from the EPA reports:

…unknown quantities of products on the well pad left the Site and entered an unnamed tributary of Opossum Creek that ultimately discharges to the Ohio River. Runoff left the pad at various locations via sheet flow….Initial inspections in the early hours of June 29, 2014 of Opossum Creek approximately 3.5 miles downstream of the site identified dead fish in the creek…. Equipment was mobilized to begin constructing an earthen berm to contain runoff and to flood the pad to extinguish remaining fires…. Once fires were extinguished, construction of a berm near the pad was begun to contain spilled liquids and future runoff from the well pad… Statoil continued construction of the containment berm currently 80% complete. (6-30-14)… Assessment of chemicals remaining on the well pad was completed. The earthen berm around the pad was completed,  (7-2-14)… ODNR Division of Wildlife completed their in stream assessment of the fish kill and reported an estimated 70,000 dead fish from an approximately 5 mile stretch extending from the unnamed tributary just west of the Eisenbarth Well Pad to Opossum Creek just before its confluence with the Ohio River… Fish collection was completed. In total, 11,116 dead fish were collected (20 different species), 3,519 crustaceans, 7 frogs and 20 salamanders.

The overall conclusion is clear. Large quantities of various chemicals, mixed with very large amounts of already contaminated water, when flooding a well pad that had no berms around it, resulted in a significant fish kill over several miles. After the fire Statoil then constructed a berm around the well pad. If there had been a pre-existing berm – just 12 inches high and level – around the well pad, it could have held over 600,000 gallons of runoff. That amount is twice the estimated quantity of water used to fight the fire.  (Note: my old 35 HP farm tractor and a single bottom plow can provide a 12-inch high mound of dirt in one pass.)

The significance for safe, potable drinking water, is that all the chemicals and petroleum products on the well pad either burned and went up in a toxic plume of black smoke, or were released in liquid form down into the well pad or flowed off of it. Since the original liner on the well pad also completely burned and there was no overall berm on the well pad, there was nothing to restrict the flow of polluted liquid. Therefore, it all seeped into the ground and/or ran off of the pad with the 300,000 gallons of water that was estimated to have been sprayed onto the burning equipment fire.

Follow Up Questions

Since this fire happened over 6 weeks ago, there have been many opportunities for nearby citizens and neighbors to meet and discuss their many concerns.  Many of the question have revolved around the overall lack of information about the process of shale gas fracturing, the equipment used, and the degree of risk that it all may present to our communities. These communities include the nearby residents, the travelling public, and all of the first responders. Unless someone has a well pad on or near their property and they are able to actively follow the process, it is usually difficult to find out the details of a specific gas operation. (We have even known of operators that have told landowners to get off of their own property both during drilling and fracturing operations and afterwards.)

Questions that follow incidents like this one typically look like this:

  1. Why was there no perimeter berm?
  2. Why could the fire not be put out quickly and easily? What all was lost? What did this site look like in the beginning?
  3. Why was there so much equipment onsite? Is this typical? What is it all called and how is it used?

1. Lack of Berm

The first and somewhat unanswered question concerns the absence of a simple containment berm around the completed well pad. Statoil must not have thought one would be very helpful, and/or the State of Ohio must not require them.

However, I had raised concern over this very topic more than a year ago from WV. In response, I received a letter in September 2013 from Statoil North America to the WVDEP. It provides some insight into Statoil thinking. Based on my interpretation of that letter, the official position of Statoil last year was that berms around the well pad do not help and are not needed. Given the recent fire, perhaps that position has changed. All we know for sure now is that at least their Eisenbarth well pad now does have a complete perimeter berm. We now have empirical proof, if any was ever needed, that in the presence of spills the absence of berms makes for greater and more expensive downstream problems.

2. An Obstinate Fire

Setting aside the berm problem, I will attempt to address the next set of questions: Why could the fire not be put out quickly and easily? What all was lost ? What did this site look like in the beginning?

The simplest way to start on such questions is to look at other hydraulic fracturing sites to identify what is there and why, and then to compare those with the charred remains on the Statoil Eisenbarth well pad in Monroe County.  Since Statoil’s contractor was Halliburton, it would help to look at their equipment when in process elsewhere.  In Figure 9 below is a clean, bright red and grey Halliburton fracking fleet.

Statoil 9

Figure 9. Example of Halliburton fracking fleet

It needs to be stated up front that I consider Halliburton to be among one of the more reputable, experienced, and dependable fracturing companies. We have seen way worse here in Wetzel County over the past seven years. Halliburton has good equipment and well-trained, safety-conscious employees. It seems to be a well-run operation. If so, then how did this massive fire happen? It simply seems that it is the nature of the beast; there are many inherent dangers to such operations. Plus there is an enormous amount of equipment on site, close coupled and stuffed into a small amount of real estate. Not to mention, the whole setup is temporary – with a lot of fuel and ignition sources. Therefore, many of the available engineered-in safeguards that would normally be installed in an industrial, fixed, permanent location, just cannot be incorporated on my neighbor’s hay field, creek bottom, or farmland.

The whole process has many risks, and many of them cannot be eliminated, just minimized. I do not think that anyone could have predicted a weak hydraulic hose. Some accidents are just that — unpreventable accidents. This is why we need to be very careful with how close we allow these sites in residential areas.

3. Serious Equipment

In Figure 10 below is a wide-angle composite photo of a Halliburton fracturing project in process. Given the shallow angle viewpoint, not all equipment is visible or numbered. The photo is still very representative of frac sites in general and equivalent to what can be seen in the scorched remains on the Statoil Eisenbarth site. The major qualification on the fracturing pumps above and the ones below, is that they are a newer generation of Halliburton dual fuel pumps. They can run on natural gas.

Statoil 10

Figure 10. Halliburton fracturing project in process

Just about everything seen in the above bright red and grey hardware can be seen in Figure 11’s charred leftovers on the Statoil site from July 5, 2014 below (six days after the fire). It is also all Halliburton equipment. The quantities and arrangement are different, but the equipment and process are the same. The numbers on the provided legend or chart should help identify the specific pieces of equipment. The newly constructed containment berm is also clearly visible here.

Statoil 11

Figure 11. Statoil site post-fire equipment identification

The above or a similar photo has been seen by many neighbors both in OH and WV. Hardly anyone can recognize what they are looking at. Even those people who are somewhat familiar with general hydraulic fracturing operations are puzzled. Nothing is obvious when viewing charred remains of burned iron, steel, and melted aluminum. All tires (over 400 of them) have been burned off the rims. Every bit of rubber, foam, composites, plastics and fiberglass truck cabs has been consumed – which is what made the black plume of smoke potentially so dangerous.

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Fig. 12. 16 fracturing pumps

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Fig. 13. 18-wheeler

What might not be so obvious is why the fire could not be extinguished.

If we look at a close-up of a small section of the well pad (Fig. 12) it is easy to see how crowded the well pad is during fracturing. The 16 fracturing pumps are all the size of a full-length 18-wheel tractor trailer (Fig. 13). Note the three fuel tanks.

The fire began between the blender-mixer trucks and the 16 hydraulic fracturing pumps. The blenders were between the fracturing pumps and the sand kings. Halliburton always keeps fire extinguishers available at every truck. They are put on the ground in front of every pump truck. Everyone knows where to find them. However, on any fracking project that location is also the most congested area. The fracturing pumps are usually parked no more than two feet apart. It is just enough room for an operator or maintenance fellow to get between them. With high pressure fluid spraying and the fire already started and now spreading, there is precious little room to maneuver or to work. It is a plumbing nightmare with the dozens of high pressure pipes connecting all the pumps together and then to a manifold. In those conditions, in the face of multiple fuel sources, then the many small explosions, prudence and self-preservation dictates a swift retreat.

To their credit, Halliburton employees knew when to retreat. No one was injured. We just burned up some trucks (and killed some fish). All the employees and all the first responders were able to go home safely, uninjured, to their families and friends. They survived a very dangerous situation to come back again in the service of their employer or their community. We wish them well.

Some Observations and Conclusions

  1. The hydraulic fracturing process is dangerous, even when done properly.
  2. Environmental and employee safeguards must be in place because “accidents will happen.”
  3. Setbacks from personal farm and residential buildings must be great enough to protect all.
  4. Setbacks from streams and creeks and rivers must be taken very seriously, especially when private or municipal water supply systems are downstream.
  5. Our communities must know what all chemicals are being used so that correct lab protocols are established ahead of time to test for contamination.

This now ends this first article addressing the Statoil Fire, its burned fracturing equipment, and the resulting water contamination. Later, I will show many examples of the quantity of equipment used on fracturing sites and why it is there. You patient readers thought this would never end. You now know more about Statoil, well pad fires, and fracturing hardware than you ever wanted to know. We will soon address the more generic questions of fracturing equipment.

FracTracker Alliance

Statoil Eisenbarth Well Pad Fire – An Introduction

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By Bill Hughes, Community Liaison, FracTracker Alliance

Monroe County on the eastern border of the State of Ohio and Wetzel County in West Virginia are very much neighbors. They literally share a very deep connection, at least geologically and physically, as they are separated by a very long, deep, 1000-foot wide valley, filled by the Ohio River. A bridge connects the surface land and its residents.

But if you literally dig a little deeper, actually a lot deeper (as in 7,000 feet down), we are seamlessly joined by the Marcellus shale layer. Below this layer, we are joined by other black shale formations where the natural gas and some of its unwelcome neighbors live.

I live in Wetzel County. From where I am sitting I am surrounded by multiple shale gas operations – and have been for over seven years. I have Chesapeake to the north; EQT to the southeast; Stone Energy to the west; Statoil to the east; and HG Energy to the south. They all are primarily extracting gas from the Marcellus formation, but just a few miles to the north of here is a Utica formation well pad (situated below the Marcellus Shale layer). It is being fracked as I write this article.

Externalizing Business Costs

Setting aside the different political and regulatory differences that might exist when comparing WV & OH, the terrain, topography, and cultural history are very similar. The impact of shale gas extraction in a rural community seems to be the same everywhere it is happening, as well. We have all had traffic congestion, road accidents, problems with air and water quality, and waste disposal challenges. All of the drilling companies use fresh water from the Ohio River or its tributaries. WV gas producers take much of their brine and flowback fluids to injections wells in OH for disposal. The grateful OH drillers truck their waste products to our landfills here in Wetzel County and the operators seem pleased with the arrangement. Externalizing costs to our communities seems to be an accepted and tolerated business model.

About Statoil

Statoil is a large natural gas producer from Norway. They have wells both here in Wetzel, WV and in Monroe County, OH. On June 28 and 29 of 2014, a massive fire burned out of control on a Statoil well pad called Eisenbarth in Monroe County (map below), during a routine hydraulic fracturing operation. The size, impact, and cause of the Statoil Eisenbarth fire deserve a lot of attention. Since I have Statoil well pads near me, I am somewhat concerned. Therefore, I will be writing about this specific fire and some of the implications for all of us.

A Series of Incident Articles

This photo essay will be presented in two sections. The first will describe the fire along with some of the details and published reports. The second part will use the photos and information to help us all better understand what is meant when we simply make comments on “fracking.” Additionally, I will show which components are commonly present during the hydraulic fracturing process. Explore the in-depth look at this incident.

Location of the Eisenbarth Pad where the June 2014 Statoil Fire occurred

Location of the Statoil Eisenbarth fire that occurred in June 2014. Click to explore our Ohio Shale Viewer.

FracTracker Alliance

Florida Citizens Seek Drilling Industry Transparency

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By Maria Rose, Communications Intern, FracTracker Alliance

Pamela Duran waited impatiently in front of a Hampton Inn in Naples, Florida on Wednesday, June 25, 2014, with her husband Jaime, and several of their community members.  They had to wait several days for a press conference with the Florida Department of Environmental Protection (DEP) regarding natural gas drilling in their home town of Collier County.  The original meeting had been postponed and rescheduled from the day before.

Seeking Transparency

Pamela, Jaime, and community members intended to ask the DEP, headed by Secretary Herschel T. Vinyard, about future gas drilling plans in Collier County.  However, when the Durans and other community members asked to speak with the DEP at the Hampton Inn, they were asked to leave.  In an attempt to seek answers to their questions, they then invited the DEP to meet with them outside the Hampton Inn.  The DEP refused, and instead held a closed meeting 20 miles away in Rookery Bay.  Only a select few members of the press were allowed to attend, forcing the Durans and the rest of the concerned community members to return home without answers to any of their questions.  Jamie said:

We were told to move out to the curb—kind of literally being kicked to the curb—and weren’t able to meet with the DEP… There hasn’t been an exchange of ideas;  there’s no back and forth.  They only had a few people from the media which is not a press conference.  The DEP said they’re committed to transparency, but it seems more like they’re committed to invisibility. We get nothing but smoke and mirrors.

Adding Confusion to the Mix

Drilling in Florida. Photo: WeArePowerShift.org

The frustration over transparency and communication with the DEP and Collier County’s Board of Commissioners stemmed from the lack of information and confusion surrounding the recent surge of nearby drilling activity.  Natural gas drilling in Florida has occurred on and offshore since the 1940s, but concerns related to the more intense impacts of  unconventional oil and gas drilling and its associated activities  have only recently surfaced.  Currently, drilling issues are contained to southwest Florida, where seismic testing is being conducted around the Collier and Hendry counties, and outside of Naples.  These areas overlay the Sunniland basin. The fossil fuel rich layer of shale found here makes companies like Dan A. Hughes eager to invest in the area.

In April of 2013, the Durans received a letter from a company called Total Safety.  Total Safety was conducting a contingency plan for the drilling company, Dan A. Hughes.  The letter contained limited information.  The Durans were only told that they were in an evacuation zone and had to provide information to Total Safety for safety precautions.  According to Pamela notes, “We were one of the first homes to get a letter… They didn’t even tell us then, that Dan A. Hughes was a drilling company.  We didn’t know what kind of evacuation zone it even was. We thought it was hurricanes at first. The commissioners didn’t even know.”

Pamela was so surprised that she called the police, and discovered that they were unable to provide sufficient information. It wasn’t until speaking with Jennifer Jones, a representative from Total Safety, that she learned that her family and 45 others were within a one mile-radius evacuation zone around a planned well pad.  The risks of hydrogen sulfide leaks, fires, and explosions, among other things, made it necessary to have an evacuation plan for these families.  At this point, Dan A. Hughes had not yet applied for a drilling permit, but would most likely be drilling by October of 2013.  Pamela noted that,  “This was the first time we’d heard of any drilling. And I was totally overwhelmed by the problems we thought might occur.”   If approved, Dan A. Hughes would be drilling within 1,000 feet from the Durans’ home.

The Durans and several of the neighbors who received similar letters met with the Colliers in late May of 2013 . The Colliers were a family that owned the surrounding land for several generations, including the mineral rights.  The concerned residents expected to have an open dialogue and had two requests:

  1. They wanted the well to be moved so that none of the neighborhood residents would be in an evacuation zone, and
  2. They wanted the drilling company to use farm roads instead of the residential roads to avoid traffic and noise.

The Colliers denied their request, but attention had been brought to the issue, and citizens began to resist drilling in the area.  Pamela commented, “The disregard for human life out here is atrocious. This has become such a big issue because we the citizens decided we’re not just going to sit and take it.”

As the drilling became more and more prominent in the area, the Durans noticed a change in the atmosphere around the neighborhood. Pamela reports that some intimidating activities have occurred, such as workers in Dan A. Hughes’ trucks video-taping certain houses, or cars parked outside of houses for excessive amounts of time.  All of this behavior is new for the area.  Pamela asks, “There are people here in the neighborhood with cars parked in the front or side of their property, and after they call the police, they find out it’s a private investigator. Who hires private investigators?”

Cease and Desist?

The biggest issue arose at the end of 2013. On December 30, 2013, the Dan A. Hughes company began to use acid fracturing to stimulate the Collier Hogan well. In Florida, there is no special permission required to begin fracking.  However, the company had assured a very concerned public and the county commissioners that there would be no fracking.   As a result of this violation, the DEP issued a cease and desist order on January 1 of 2014.   Dan A. Hughes, however, continued to frack until the process was finished.  It wasn’t until April 8, 2014 that the DEP issued a consent order to Dan A. Hughes along with a fine of $25,000 for unauthorized fracking.  All of these details were not released to the public until the consent order was issued in April.  Dr. Karen Dwyer, a resident of Collier County, notes that there have been many opportunities since January to share such information; between January and April.  There was an EPA hearing, a Big Cypress Swamp Advisory Committee meeting, various Collier county commissioner meetings, and several Administrative Judge hearings where the information could have been released to the public.  According to Dr. Dwyer:

The DEP just sat on this information while everyone else was looking closely at other aspects of the Dan A. Hughes drilling.  We’ve had all these meetings looking at how reliable they are and what their training has been, but the DEP never said that Dan A. Hughes had been under this investigation.  That was wrong of the DEP.  Decisions were being made to allow [drilling] while this serious issue was going on, and we didn’t know.

Triggering Resistance

Since then, Collier County’s resistance to gas drilling has taken off.  On April 22nd, the county commissioners voted unanimously to challenge the DEP’s consent order for Dan A. Hughes to drill, which is the first challenge of gas drilling in the area.  Senator Bill Nelson called for a federal review of Dan A. Hughes on May 1st.  The next day, the state called for Dan A. Hughes to cease all of their new operations in Florida.  Two weeks later on May 13th, the county commissioners voted to challenge the Collier-Hogan well, targeting a much more specific project. The commissioners began the legal process of challenging Dan A. Hughes’ consent order on June 10th, insisting on public meetings.

Even though they have seen progress, citizens like Dwyer and the Durans do not feel that change is happening rapidly enough. For example, the state has ordered all of Dan A. Hughes’ new operations stopped, but there are still old wells that can keep producing since their inception occurred prior to this new order. Also, once the commissioners filed their challenge on Dan A. Hughes, they were unable to talk about it publicly. Because of this development, issues surrounding a lack of transparency and communication have resurfaced.

Environmental and Social Justice Concerns

At times, Pamela said she feels like the combination of the Collier County’s geography and demographics have made it an easy target for resource extraction companies.  She describes the area as a multicultural town with many immigrants—Jamaican, Mexican, Hatian, Peruvian, Columbian, and more—and a community comprised of older retirees and very young families building up savings.  These demographics, she feels, may give off the impression that the residents will not come together and fight for their rights.  Speaking to the comments directed at Colliers from the more populous Naples community, Pamela responded by saying, “This is the first time I’ve felt people think we’re poor.  It’s not like we’re an urban location with super poor people surviving on welfare, but yes, lots of people here are foreign, and we don’t have much material wealth.”

According to the Durans, the surge of gas drilling activity in Collier County has drastically altered the day-to-day lifestyle of many of its residents.  Pamela and Jaime have dedicated much of their time to fighting the companies and following discussions surrounding the issue, which takes up a significant amount of their time. Pamela notes:

For the past 14 months, our lives have been on hold, dedicating the past months to stopping drilling.  We wanted to do certain things to our house, but we’ve put it on hold.   Why invest in a home if we might have to leave it for health reasons later? I’m not going to stay and watch us get sick.

Dwyer has similar feelings on the issue.  He is concerned about the human rights aspect of the problem, such as equal access to clean water and air, as well as the difficulty of communicating with large corporations.  Dwyer would like to see the state and federal government buy the mineral rights from Collier Resources and set that land aside as a reserve, which is what it was prior to drilling. Feeling that the drilling will most likely be permitted, Dwyer believes that companies should concentrate on improving procedures and communication.

Dwyer recognizes that even though resisting the industry has proved to be frustrating, she now knows about the issues surrounding gas and is determined to continue informing as many people as possible and is continuing an open dialogue with the county commissioners.  She feels that progress towards stopping gas companies can be made when more people know about the problems that are occurring.

Learn more about the unique aspects of drilling in Florida.

The interviews that served as the basis for this article were conducted in the summer 2014. This article is an update to an article we wrote in 2013. Read more.

Karen Edelstein

Offshore oil and gas exploration federally approved

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By Karen Edelstein, NY Program Coordinator

Right whale (Eubalaena glacialis) with calf

Background

Drilling in the Atlantic Ocean off the coast of the United States has been off-limits for nearly four decades. However, last Friday, the Obama administration’s Bureau of Ocean Energy Management (BOEM) opened the Atlantic outer continental shelf for oil and gas exploration starting in 2018, with oil production commencing in 2026. In a December 2013 report by the American Petroleum Institute (API) , API estimated that offshore exploration and federal lease sales could generate $195 billion between 2017 and 2035.

Problems for marine mammals, sea turtles, fish

Aside from the inherent risks of catastrophic drilling accidents similar to BP’s Deepwater Horizon in April 2010, open ocean oil and gas exploration can pose severe problems for marine life. Environmentalists have voiced alarm over the techniques used to explore for hydrocarbons deep below the ocean floor. Using “sonic cannons” or “‘seismic airguns,” pulses of sound are directed at the sea bottom to detect hydrocarbon deposits.

Underwater communication by marine mammals, such as whales and dolphins, relies on sound transmission over long distances — sometimes thousands of miles. These animals use sound to navigate, find mates and food, and communicate with each other. Noise pollution by common ships and supertankers is known to disrupt and displace marine mammals, but naval sonar has been documented as a cause of inner ear bleeding, hearing loss, tissue rupture, and beach strandings. According to the Ocean Mammal Institute:

These sonars – both low -frequency (LFAS) and mid -frequency can have a source level of 240 dB, which is one trillion times louder than the sounds whales have been shown to avoid. One scientist analyzing underwater acoustic data reported that a single low frequency sonar signal deployed off the coast of California could be heard over the entire North Pacific Ocean.

Natural Resources Defense Council also expressed concern over naval sonar: “By the Navy’s own estimates, even 300 miles from the source, these sonic waves can retain an intensity of 140 decibels – a hundred times more intense than the level known to alter the behavior of large whales.”

As destructive as naval sonar may be, oil and gas exploration sonic cannons–also known as seismic airguns– (at 216 – 230 dB) create disruptions to marine life many orders of magnitude greater. Fish and sea turtles are also affected, with catch rates of fish decreasing up to 70% when airguns were used in a commercial fishing area, according to a study by the Norwegian Institute of Marine Research.

The intensity and duration of the sonic cannon pulses during oil and gas exploration are an important factor in this equation. According to the Huffington Post, “The sonic cannons are often fired continually for weeks or months, and multiple mapping projects are expected to be operating simultaneously as companies gather competitive, secret data.” Collateral damage for the exploration is far from insignificant, the article continues:

The bureau’s environmental impact study estimates that more than 138,000 sea creatures could be harmed, including nine of the 500 north Atlantic right whales remaining in the world. Of foremost concern are endangered species like these whales, which give birth off the shores of northern Florida and southern Georgia before migrating north each year. Since the cetaceans are so scarce, any impact from this intense noise pollution on feeding or communications could have long-term effects, Scott Kraus, a right whale expert at the John H. Prescott Marine Laboratory in Boston, said.

‘No one has been allowed to test anything like this on right whales,” Kraus said of the seismic cannons. “(The Obama administration) has authorized a giant experiment on right whales that this country would never allow researchers to do.’

North Atlantic right whales are one of the most endangered species of cetaceans in the world.

Map of ranges of marine mammals potentially affected and towns opposing sonic cannon exploration for oil and gas

Although currently, the waters off New Jersey and New England are off-limits for exploration, North Carolina, South Carolina, and Virginia encouraged the federal government to open their off-shore waters for oil and gas surveys. Nevertheless,  many ocean-front communities have come out strongly against the use of sonic cannons and their impacts on marine life. To date, 15 communities from New Jersey to Florida have passed resolutions opposing this form of oil and gas exploration.

FracTracker has mapped the locations of these communities, with pop-up links to the resolutions that were passed, as well as the ranges of 17 marine mammals found along the Atlantic seaboard of the US.  These data come from the International Union for Conservation of Nature (IUCN) 2014 Red List of Threatened Species. You can toggle ranges on and off by going to the “Layers” drop-down menu at the top of the map. The default presentation for this map currently shows only the range of North Atlantic right whales. For a full-screen version of this map, with access to the other marine mammal ranges, click here.

Matt Kelso, BA

What’s in PA Senate Bill 1378?

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State Senator Joseph Scarnati III, from north-central Pennsylvania, has introduced a bill that would redefine the distinction between conventional and unconventional oil and gas wells throughout the state.  In Section 1 of the bill, the sponsors try to establish the purpose of the legislation,  making the case that:

  1. Conventional oil and gas development has a benign impact on the Commonwealth
  2. Many of the wells currently classified as conventional are developed by small businesses
  3. Oil and gas regulations, “must permit the optimal development of oil and gas resources,” as well as protect the citizens and environment.
  4. Previous legislation already does, and should, treat conventional and unconventional wells differently
This diagram shows geologic stata in Pennsylvania. The Elk Sandstone is between the Huron and Rhinestreet shale deposits from the Upper Devonian period.

This diagram shows geologic stata in Pennsylvania. The Elk Group is between the Huron and Rhinestreet shale deposits from the Upper Devonian period. Click on the image to see the full version. Source: DCNR

Certainly, robust debate surrounds each of these points, but they are introductory in nature, not the meat and potatoes of Senate Bill 1378.  What this bill does is re-categorize some of the state’s unconventional wells to the less restrictive conventional category, including:

  1. All oil wells
  2. All natural gas wells not drilled in shale formations
  3. All shale wells above (shallower than) the base of the Elk Group or equivalent
  4. All shale wells below the Elk Group from a formation that can be economically drilled without the use of hydraulic fracturing or multi-lateral bore holes
  5. All wells drilled into any formation where the purpose is not production, including waste disposal and other injection wells

The current distinction is in fact muddled, with one DEP source indicating that the difference is entirely due to whether or not the formation being drilled into is above or below the Elk Group, and another DEP source indicates that the difference is much more nuanced, and really depends on whether the volumes of hydraulic fracturing fluid required to profitably drill into a given formation are generally high or low.

This table shows the number of wells in each formation in Pennsylvania that has both conventional and unconventional wells drilled into it. Data source: DEP, downloaded 7/9/2014.

This table shows the number of distinct wells in each producing formation in Pennsylvania that has both conventional and unconventional wells drilled into it. Data source: DEP, downloaded 7/9/2014.

As one might expect, this ambiguity is represented in the data. The chart at the left shows the number of distinct number of wells by formation, for each producing formation that has both conventional and unconventional wells in the dataset.  Certainly, there could be some data entry errors involved, as the vast majority of Bradford wells are conventional, and almost all of the Marcellus wells are unconventional.  But there seems to be some real confusion with regards to the Oriskany, for example, which is not only deeper than the Elk Group, but the Marcellus formation as well.

While an adjustment to the distinction of conventional and unconventional wells in Pennsylvania is called for, one wonders if the definitions proposed in SB 1378 is the right way to handle it.  If the idea of separating the two is based on the relative impact of the drilling operation, then a much more straightforward metric might be useful, such as providing a cutoff in the amount of hydraulic fracturing fluid used to drill a well.  Further, each of the five parts of the proposed definition serve to make the definition of unconventional wells less inclusive, meaning that additional wells would be subject to the less stringent regulations, and that the state would collect less money from the impact fees that were a part of Act 13 of 2012.

Instead, it is worth checking to see whether the definition of unconventional is inclusive enough.  In May of this year, FracTracker posted a blog about conventional wells that were drilled horizontally in Pennsylvania.


Conventional, non-vertical wells in Pennsylvania. Please click the expanding arrows icon at the top-right corner to access the legend and other map controls. Please zoom in to access data for each location.

These wells require large amounts of hydraulic fracturing fluids, and are already being drilled at depths of only 3,000 feet, and could go as shallow as 1,000 feet.  It’s pretty easy to argue that due to the shallow nature of the wells, and the close proximity to drinking water aquifers, these wells are deserving of even more rigorous scrutiny than those drilled into the Marcellus Shale, which generally ranges from 5,000 to 9,000 feet deep throughout the state.

A summary of the different regulations regarding conventional and unconventional wells can be found from PennFuture.  In general, unconventional wells must be further away from water sources and structures than their conventional counterparts, and the radius of presumptive liability for the contamination of water supplies is 2,500 feet instead of 1,000.

SB 1378 has been re-referred to the Appropriations Committee.

 

Photo by Evan Collins and Rachel Wadell
FracTracker Alliance

These Fish Weren’t Playing Opossum (Creek)

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A First-hand Look at the Recent Statoil Well Pad Fire

By Evan Collins and Rachel Wadell, Summer Research Interns, Wheeling Jesuit University

Statoil well pad fire 2205-crop

Monroe Co. Ohio – Site of June 2014 Statoil well pad fire

After sitting in the non-air-conditioned lab on a muggy Monday afternoon (June 30, 2014), we were more than ready to go for a ride to Opossum Creek after our professor at Wheeling Jesuit University mentioned a field work opportunity. As a researcher concerned about drilling’s impacts, our professor has given many talks on the damaging effects that unconventional drilling can have on the local ecosystem. During the trip down route 7, he explained that there had been a serious incident on a well pad in Monroe County, Ohio (along the OH-WV border) on Saturday morning.

About the Incident

Hydraulic tubing had caught fire at Statoil’s Eisenbarth well pad, resulting in the evacuation of 20-25 nearby residents.1 Statoil North America is a relatively large Norwegian-based company, employing roughly 23,000 workers, that operates all of its OH shale wells in Monroe County.2 The Eisenbarth pad has 8 wells, 2 of which are active.1 However, the fire did not result from operations underground. All burning occurred at the surface from faulty hydraulic lines.

Resulting Fish Kill?

Photo by Evan Collins and Rachel Wadell

Several fish from the reported fish kill of Opossum Creek in the wake of the recent well pad fire in Monroe County, OH.

When we arrived at Opossum Creek, which flows into the Ohio River north of New Martinsville, WV, it smelled like the fresh scent of lemon pine-sol. A quick look revealed that there was definitely something wrong with the water. The water had an orange tint, aquatic plants were wilting, and dozens of fish were belly-up. In several shallow pools along the creek, a few small mouth bass were still alive, but they appeared to be disoriented.  As we drove down the rocky path towards the upstream contamination site, we passed other water samplers. One group was from the Center for Toxicology and Environmental Health (CTEH). The consulting firm was sampling for volatile organic compounds, while we were looking for the presence of halogens such as Bromide and Chloride. These are the precursors to trihalomethanes, a known environmental toxicant.

Visiting the Site

After collecting water samples, we decided to visit the site of the fire. As we drove up the ridge, we passed another active well site. Pausing for a break and a peek at the well, we gazed upon the scenic Appalachian hillsides and enjoyed the peaceful drone of the well site. Further up the road, we came to the skeletal frame of the previous Statoil site. Workers and members of consulting agencies, such as CTEH, surrounded the still smoking debris. After taking a few pictures, we ran into a woman who lived just a half-mile from the well site.  We asked her about the fire and she stated that she did not appreciate having to evacuate her home. Surrounding plants and animals were not able to be evacuated, however.

Somehow the fish living in Opossum Creek, just downhill from the well, ended up dead after the fire. The topography of the area suggests that runoff from the well would likely flow in a different direction, so the direct cause of the fish kill is still obscure. While it is possible that chemicals used on the well pad ran into the creek while the fire was being extinguished, the OH Department of Natural Resources “can’t confirm if it (the fish kill) is related to the gas-well fire.”3  In reference to the fire, a local resident said “It’s one of those things that happens. My God, they’re 20,000 feet down in the ground. Fracking isn’t going to hurt anything around here. The real danger is this kind of thing — fire or accidents like that.”4

Lacking Transparency

WV 2014 Photo by Evan Collins and Rachel Wadell

Run by Statoil North America, Eisenbarth well pad in Monroe County, Ohio is still smoking after the fire.

Unfortunately, this sentiment is just another example of the general public being ill-informed about all of the aspects involved in unconventional drilling. This knowledge gap is largely due to the fact that oil and gas extraction companies are not always transparent about their operations or the risks of drilling. In addition to the potential for water pollution, earthquakes, and illness due to chemicals, air pollution from active unconventional well sites is increasing annually.

CO2 Emissions

Using prior years’ data, from 2010 to 2013, we determined that the average CO2 output from unconventional gas wells in 2013 was equal to that of an average coal-fired plant. If growth continued at this rate, the total emissions of all unconventional wells in West Virginia will approximate 10 coal-fired power plants in the year 2030. Coincidentally, this is the same year which the EPA has mandated a 30 percent reduction in CO2 emissions by all current forms of energy production. However, recent reports suggest that the amount of exported gas will quadruple by 2030, meaning that the growth will actually be larger than originally predicted.5 Yet, this number only includes the CO2 produced during extraction. It does not include the CO2 released when the natural gas is burned, or the gas that escapes from leaks in the wells.

Long-Term Impacts

Fires and explosions are just some of the dangers involved in unconventional drilling. While they can be immediately damaging, it is important to look at the long-term impacts that this industry has on the environment. Over time, seepage into drinking water wells and aquifers from underground injection sites will contaminate these potable sources of water. Constant drilling has also led to the occurrence of unnatural earthquakes. CO2 emissions, if left unchecked, could easily eclipse the output from coal-fired power plants – meaning that modern natural gas drilling isn’t necessarily the “clean alternative” as it has been advertised.

References

  1. Willis, Jim ed. (2014). Statoil Frack Trucks Catch Fire in Monroe County, OH. Marcellus Drilling News.
  2. Forbes. (2014). Statoil.
  3. Woods, Jim. (2014). Fish Kill in Eastern Ohio Might be Linked to Fire at Fracking Well. The Columbus Dispatch.
  4. Ibid.
  5. Cushman, John H., Jr. (2014). US Natural Gas Exports No Better for Climate than China’s Coal, Experts Say.
Karen Edelstein

Central Penn Pipeline Under Debate

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By Karen Edelstein, NY Program Coordinator, FracTracker Alliance

Background

PipelineOver the past month and a half, a new pipeline controversy has been stirring in Pennsylvania. The proposed $2 billion “Central Penn Pipeline” will be built to carry shale gas throughout the country. Starting in Susquehanna County, the 178 mile pipeline will run through Lebanon and Lancaster counties to connect the existing Tennessee Pipeline in the north with the Transco Pipeline in the south.

Oklahoma-based Williams Partners, the company proposing the pipeline, says that the project would help move gas from PA to locations as far south as Georgia and Alabama, in addition to adding relief from higher energy bills. The “Atlantic Sunrise Project,” as it is formally known, would also require the construction of two new 30,000 horse-power compressor stations: “Station 605” along the northern leg of the pipeline in Susquehanna County, as well as “Station 610” on the southern part of the pipeline. The northern part of the proposed pipeline will be 30 inches in diameter and run for about 56 miles; the southern portion will be 42 inches in diameter and about 122 miles long.

According to the US Energy Information Agency (EIA), in 2008, PA had over 8,700 miles of pipeline. Since then, that figure has increased significantly as the shale plays in PA continue to be exploited. Industry maintains that pipelines are the safest method for moving gas from the well to market, and has noted that for safety concerns they have intentionally co-located 36% of the northern part of the pipeline within the rights-of-way of Transco’s or other utility’s pipelines.

Despite the sanguine view of this project by industry, residents have rallied against the pipeline since mid-April, when landowners started getting information packets in the mail about the proposal.

Pipeline Proposal Map

While the exact route of the pipeline has yet to be determined, FracTracker has adapted documents from Oklahoma-based Williams Partners Company to provide this interactive map below. The proposed pipeline is shown in red.

For a full-screen version of this map (with legend), click here.

Proposal Concerns

Public awareness and concern about the pipeline continues to build, as was evident when 1,100 residents attended an open house in Millersville, PA on June 10th hosted by Williams. For more information see this article in Lancaster Online.

The Lancaster County Conservancy has advocated moving the pipeline away from various sensitive habitats including the Tucquan Glen Nature Preserve, Shenk’s Ferry Wildflower Preserve, Fishing Creek, Kelly’s Run, and Rock Springs to preserve the wildlife and beauty of those areas. According to Williams:

The pipeline company must evaluate a number of environmental factors, including potential impacts on residents, threatened and endangered species, wetlands, water bodies, groundwater, fish, vegetation, wildlife, cultural resources, geology, soils, land use, air and noise quality…  More

Despite what the website says, Williams admitted to not analyzing the pipeline route for possible sensitive habitat encroachment, and instead, they will simply follow the existing utility routes.

Williams, according to a report by WGAL Channel 8 in PA “relies on the communities affected to bring up any potential problems.” His statement was backed up when residents in a packed hearing room in Lancaster County voiced their opposition, resulting in Williams Partners now considering extending their pipeline by 2 ½ miles to get around the sensitive natural area at Tucquan Glen. An alternate route to avoid Shenk’s Ferry, however, had not been put forward.

Lancaster Farmland Trust is concerned about the plan for the pipeline to pass through several protected farms, and Lebanon County Commissioner Jo Ellen Litz has also taken a strong stand against the current proposed route. The proposed pipeline would not only go through farmlands, but it is also expected to cross the Appalachian Trail, Swatara State Park, and Lebanon Valley Rails to Trails.

Pipeline impacts are not limited to conservation and agriculture. There is increasing concern that the risks posed by large-diameter, high pressure pipelines such as this one may prevent nearby homeowners from keeping their mortgage loans or homeowner’s insurance. Future purchasers of the property may also encounter difficulty being approved for a mortgage loan or homeowner’s insurance.

While the pipeline company can purchase pipeline easements from property owners, industry can also petition the government to take the land by eminent domain from unwilling property owners. Pipeline rights-of-way acquired through eminent domain for these pipelines could potentially complicate a private property owner’s mortgage financing and homeowner’s insurance.

The final decisions about the siting of the pipeline is ultimately up to FERC, the Federal Energy Regulatory Commission.

Resources

Williams’ original maps of the pipelines can be viewed here: SOUTH | NORTH

FracTracker Alliance

Well Worker Safety and Statistics

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By Samantha Malone, MPH, CPH – Manager of Science and Communications, FracTracker Alliance

The population most at risk from accidents and incidents near unconventional drilling operations are the drillers and contractors within the industry. While that statement may seem quite obvious, let’s explore some of the numbers behind how often these workers are in harm’s way and why.

O&G Risks

Oil and Gas Worker Fatalities over Time

Fig. 1. Number of oil and gas worker fatalities over time
Data Source: U.S. Bureau of Labor Statistics, U.S. Department of Labor, 2014

Drilling operations, whether conventional or unconventional (aka fracking), run 24 hours a day, 7 days a week. Workers may be on site for several hours or even days at a time. Simply the amount of time spent on the job inherently increases one’s chances of health and safety concerns. Working in the extraction field is traditionally risky business. In 2012, mining, quarrying, and oil and gas extraction jobs experienced an overall 15.9 deaths for every 100,000 workers, the second highest rate among American businesses. (Only Agriculture, forestry, fishing and hunting jobs had a higher rate.)

According to the Quarterly Census of Employment and Wages of the U.S. Bureau of Labor Statistics, the oil and gas industry employed 188,003 workers in 2012 in the U.S., a jump from 120,328 in 2003. Preliminary data indicate that the upward employment trend continued in 2013. However, between 2003 and 2012, a total of 1,077 oil and gas extraction workers were killed on the job (Fig. 1).

Causes of Injuries and Fatalities in Oil and Gas Field

Reasons for O&G Fatalities 2003-12. Aggregated from Table 1.

Fig. 2. Reasons for O&G Fatalities 2003-12. Aggregated from Table 1.

Like many industrial operations, here are some of the reasons why oil and gas workers may be hurt or killed according to OSHA:

  • Vehicle Accidents
  • Struck-By/ Caught-In/ Caught-Between Equipment
  • Explosions and Fires
  • Falls
  • Confined Spaces
  • Chemical Exposures

If you drill down to the raw fatality-cause numbers, you can see that the fatal worksite hazards vary over time and job type1 (Table 1, bottom). Supporting jobs to the O&G sector are at higher risk of fatal injuries than those within the O&G extraction job category2. The chart to the right shows aggregate data for years 2003-12. Records indicate that the primary risk of death originated from transportation incidents, followed by situations where someone came into contact with physical equipment (Fig. 2).

Silica Research

Silica-Exposed Workers

Fig. 3. Number of total silica-exposed workers and those exposed above PEL – compared across industries
Source: OSHA Directorate of Standards and Guidance

A recent NIOSH study by Esswein et al. regarding workplace safety for oil and gas workers was that the methods being employed to protect workers against respirable crystalline silica3 were not adequate. This form of silica can be found in the sand used for hydraulic fracturing operations and presents health concerns such as silicosis if inhaled over time. According to Esswein’s research, workers were being exposed to levels above the permissible exposure limit (PEL) of ~0.1 mg/m3 for pure quartz silica because of insufficient respirator use and inadequate technology controls on site. It is unclear at this time how far the dust may migrate from the well pad or sand mining site, a concern for nearby residents of the sand mines, distribution methods, and well pads. (Check out our photos of a recent frac sand mine tour.) The oil and gas industry is not the only employer that must protect people from this airborne workplace hazard. Several other classes of jobs result in exposure to silica dust above the PEL (Fig. 3).

References and Additional Resources

1. What do the job categories in the table below mean?

For the Bureau of Labor Statistics, it is important for jobs to be classified into groups to allow for better reporting/tracking. The jobs and associated numbers are assigned according to the North American Industry Classification System (NAICS).

(NAICS 21111) Oil and Gas Extraction comprises establishments primarily engaged in operating and/or developing oil and gas field properties and establishments primarily engaged in recovering liquid hydrocarbons from oil and gas field gases. Such activities may include exploration for crude petroleum and natural gas; drilling, completing, and equipping wells; operation of separators, emulsion breakers, desilting equipment, and field gathering lines for crude petroleum and natural gas; and all other activities in the preparation of oil and gas up to the point of shipment from the producing property. This industry includes the production of crude petroleum, the mining and extraction of oil from oil shale and oil sands, the production of natural gas, sulfur recovery from natural gas, and the recovery of hydrocarbon liquids from oil and gas field gases. Establishments in this industry operate oil and gas wells on their own account or for others on a contract or fee basis. Learn more

(NAICS 213111) Drilling Oil and Gas Wells comprises establishments primarily engaged in drilling oil and gas wells for others on a contract or fee basis. This industry includes contractors that specialize in spudding in, drilling in, redrilling, and directional drilling. Learn more

(NAICS 213112) Support Activities for Oil and Gas Operations comprises establishments primarily engaged in performing support activities on a contract or fee basis for oil and gas operations (except site preparation and related construction activities). Services included are exploration (except geophysical surveying and mapping); excavating slush pits and cellars, well surveying; running, cutting, and pulling casings, tubes, and rods; cementing wells, shooting wells; perforating well casings; acidizing and chemically treating wells; and cleaning out, bailing, and swabbing wells. Learn more

2. Fifteen percent of all fatal work injuries in 2012 involved contractors. Source

3. What is respirable crystalline silica?

Respirable crystalline silica – very small particles at least 100 times smaller than ordinary sand you might encounter on beaches and playgrounds – is created during work operations involving stone, rock, concrete, brick, block, mortar, and industrial sand. Exposures to respirable crystalline silica can occur when cutting, sawing, grinding, drilling, and crushing these materials. These exposures are common in brick, concrete, and pottery manufacturing operations, as well as during operations using industrial sand products, such as in foundries, sand blasting, and hydraulic fracturing (fracking) operations in the oil and gas industry.

4. OSHA Fact Sheet: OSHA’s Proposed Crystalline Silica Rule: General Industry and Maritime. Learn more

Employee health and safety are protected under the following OSHA regulations. These standards require employers to make sure that the workplace is in due order:

Table 1. 2003-2012 U.S. fatalities in oil & gas industries by year, job category, & event/exposure
Year Oil and Gas (O&G) Industriesa Total Fatal Injuries (number)b Event or Exposurec
Violence / injuries by persons / animalsd Transportatione Fires & Explosions Falls, Slips, Trips Exposure to Harmful Substances or Environments Contact w/Objects & Equipment
2012
O&G Extraction 26 0 8 6 5 3 4
Drilling O&G Wells 39 0 10 6 8 3 10
Support Activities 77 0 46 11 5 3 10
Yearly Totals 142 0 64 23 18 9 24
2011
O&G Extraction 13 0 7 0 0 0 3
Drilling O&G Wells 41 0 15 5 4 5 12
Support Activities 58 3 29 7 4 4 11
Yearly Totals 112 3 51 12 8 9 26
2010
O&G Extraction 12 0 5 3 0 3 0
Drilling O&G Wells 47 0 8 14 7 6 12
Support Activities 48 3 28 8 0 0 8
Yearly Totals 107 3 41 25 7 9 20
2009
O&G Extraction 12 0 6 0 0 0 3
Drilling O&G Wells 29 0 9 0 0 4 13
Support Activities 27 0 12 5 0 4 5
Yearly Totals 68 0 27 5 0 8 21
2008
O&G Extraction 21 0 7 4 0 0 5
Drilling O&G Wells 30 0 6 3 4 4 13
Support Activities 69 0 36 11 4 6 12
Yearly Totals 120 0 49 18 8 10 30
2007
O&G Extraction 15 0 5 0 0 0 5
Drilling O&G Wells 42 0 12 0 4 8 16
Support Activities 65 0 33 6 0 5 19
Yearly Totals 122 0 50 6 4 13 40
2006
O&G Extraction 22 0 6 7 0 3 4
Drilling O&G Wells 36 0 11 0 5 4 14
Support Activities 67 0 2 12 0 5 21
Yearly Totals 125 0 19 19 5 12 39
2005
O&G Extraction 17 0 4 5 0 0 4
Drilling O&G Wells 34 0 9 0 7 4 10
Support Activities 47 0 21 5 0 5 13
Yearly Totals 98 0 34 10 7 9 27
2004
O&G Extraction 29 0 17 0 0 0 8
Drilling O&G Wells 30 0 6 0 6 3 11
Support Activities 39 0 22 5 0 0 10
Yearly Totals 98 0 45 5 6 3 29
2003
O&G Extraction 17 0 9 4 0 0 3
Drilling O&G Wells 26 0 5 5 0 0 13
Support Activities 42 0 17 10 0 3 10
Yearly Totals 85 0 31 19 0 3 26
2003-12 TOTAL FATALITIES 1077 6 411 142 63 85 282
a Oil and gas extraction industries include oil and gas extraction (NAICS 21111), drilling oil and gas wells (NAICS 213111), and support activities for oil and gas operations (NAICS 213112).
b Data in event or exposure categories do not always add up to total fatalities due to data gaps.
c Based on the BLS Occupational Injury and Illness Classification System (OIICS) 2.01 implemented for 2011 data forward
d Includes violence by persons, self-inflicted injury, and attacks by animals
e Includes highway, non-highway, air, water, rail fatal occupational injuries, and fatal occupational injuries resulting from being struck by a vehicle.
FracTracker Alliance

Water Use in WV and PA

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Water Resource Reporting and Water Footprint from Marcellus Shale Development in West Virginia and Pennsylvania

Report and summary by Meghan Betcher and Evan Hansen, Downstream Strategies; and Dustin Mulvaney, San Jose State University

GasWellWaterWithdrawals The use of hydraulic fracturing for natural gas extraction has greatly increased in recent years in the Marcellus Shale. Since the beginning of this shale gas boom, water resources have been a key concern; however, many questions have yet to be answered with a comprehensive analysis. Some of these questions include:

  • What are sources of water?
  • How much water is used?
  • What happens to this water following injection into wells?

With so many unanswered questions, we took on the task of using publically available data to perform a life cycle analysis of water used for hydraulic fracturing in West Virginia and Pennsylvania.

Summary of Findings

Some of our interesting findings are summarized below:

  • In West Virginia, approximately 5 million gallons of fluid are injected per fractured well, and in Pennsylvania approximately 4.3 million gallons of fluid are injected per fractured well.
  • Surface water taken directly from rivers and streams makes up over 80% of the water used in hydraulic fracturing in West Virginia, which is by far the largest source of water for operators. Because most water used in Marcellus operations is withdrawn from surface waters, withdrawals can result in dewatering and severe impacts on small streams and aquatic life.
  • Most of the water pumped underground—92% in West Virginia and 94% in Pennsylvania—remains there, lost from the hydrologic cycle.
  • Reused flowback fluid accounts for approximately 8% of water used in West Virginia wells.
  • Approximately one-third of waste generated in Pennsylvania is reused at other wells.
  • As Marcellus development has expanded, waste generation has increased. In Pennsylvania, operators reported a total of 613 million gallons of waste, which is approximately a 70% increase in waste generated between 2010 and 2011.
  • Currently, the three-state region—West Virginia, Pennsylvania, and Ohio—is tightly connected in terms of waste disposal. Almost one-half of flowback fluid recovered in West Virginia is transported out of state. Between 2010 and 2012, 22% of recovered flowback fluid from West Virginia was sent to Pennsylvania, primarily to be reused in other Marcellus operations, and 21% was sent to Ohio, primarily for disposal via underground injection control (UIC) wells. From 2009 through 2011, approximately 5% of total Pennsylvania Marcellus waste was sent to UIC wells in Ohio.
  • The blue water footprint for hydraulic fracturing represents the volume of water required to produce a given unit of energy—in this case one thousand cubic feet of gas. To produce one thousand cubic feet of gas, West Virginia wells require 1-3 million gallons of water and Pennsylvania wells required 3-4 million gallons of water.

Table 1. Reported water withdrawals for Marcellus wells in West Virginia (million gallons, % of total withdrawals, 2010-2012)

WV Water Withdrawals

Source: WVDEP (2013a). Note: Surface water includes lakes, ponds, streams, and rivers. The dataset does not specify whether purchased water originates from surface or groundwater. As of August 14, 2013, the Frac Water Reporting Database did not contain any well sites with a withdrawal “begin date” later than October 17, 2012. Given that operators have one year to report to this database, the 2012 data are likely very incomplete.

As expected, we found that the volumes of water used to fracture Marcellus Shale gas wells are substantial, and the quantities of waste generated are significant. While a considerable amount of flowback fluid is now being reused and recycled, the data suggest that it displaces only a small percentage of freshwater withdrawals. West Virginia and Pennsylvania are generally water-rich states, but these findings indicate that extensive hydraulic fracturing operations could have significant impacts on water resources in more arid areas of the country.

While West Virginia and Pennsylvania have recently taken steps to improve data collection and reporting related to gas development, critical gaps persist that prevent researchers, policymakers, and the public from attaining a detailed picture of trends. Given this, it can be assumed that much more water is being withdrawn and more waste is being generated than is reported to state regulatory agencies.

Data Gaps Identified

We encountered numerous data gaps and challenges during our analysis:

  • All data are self-reported by well operators, and quality assurance and quality control measures by the regulatory agencies are not always thorough.
  • In West Virginia, operators are only required to report flowback fluid waste volumes. In Pennsylvania, operators are required to report all waste fluid that returns to the surface. Therefore in Pennsylvania, flowback fluid comprises only 38% of the total waste which means that in West Virginia, approximately 62% of their waste is not reported, leaving its fate a mystery.
  • The Pennsylvania waste disposal database indicates waste volumes that were reused, but it is not possible to determine exactly the origin of this reused fluid.
  • In West Virginia, withdrawal volumes are reported by well site rather than by the individual well, which makes tracking water from withdrawal location, to well, to waste disposal site very difficult.
  • Much of the data reported is not publically available in a format that allows researchers to search and compare results across the database. Many operators report injection volumes to FracFocus; however, searching in FracFocus is cumbersome – as it only allows a user to view records for one well at a time in PDF format. Completion reports, required by the Pennsylvania Department of Environmental Protection (PADEP), contain information on water withdrawals but are only available in hard copy at PADEP offices.

In short, the true scale of water impacts can still only be estimated. There needs to be considerable improvements in industry reporting, data collection and sharing, and regulatory enforcement to ensure the data are accurate. The challenge of appropriately handling a growing volume of waste to avoid environmental harm will continue to loom large unless such steps are taken.

Report Resources

Complete Report  |  Webinar

This report was written on behalf of Earthworks and was funded by a Network Innovation Grant from the Robert & Patricia Switzer Foundation.

This FracTracker article is part of the Water Use Series

WV Field Visits 2013
FracTracker Alliance

H 2 O Where Did It Go?

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By Mary Ellen Cassidy, Community Outreach Coordinator, FracTracker Alliance

A Water Use Series

Many of us do our best to stay current with the latest research related to water impacts from unconventional drilling activities, especially those related to hydraulic fracturing.  However, after attending presentations and reading recent publications, I realized that I knew too little about questions like:

  • How much water is used by hydraulic fracturing activities, in general?
  • How much of that can eventually be used for drinking water again?
  • How much is removed from the hydrologic cycle permanently?

To help answer these kinds of questions, FracTracker will be running a series of articles that look at the issue of drilling-related water consumption, the potential community impacts, and recommendations to protect community water resources.

Ceres Report

We have posted several articles on water use and scarcity in the past here, here, here and here.  This article in the series will share information primarily from Monika Freyman’s recent Ceres report, Hydraulic Fracturing & Water Stress: Water Demand by the Numbers, February 2014.  If you hunger for maps, graphs and stats, you will feast on this report. The study looks at oil and gas wells that were hydraulically fractured between January 2011 and May 2013 based on records from FracFocus.

Class 2 UI Wells

Class 2 UI Wells

Water scarcity from unconventional drilling is a serious concern. According to Ceres analysis, horizontal gas production is far more water intensive than vertical drilling.  Also, the liquids that return to the surface from unconventional drilling are often disposed of through deep well injection, which takes the water out of the water cycle permanently.   By contrast, water uses are also high for other industries, such as agriculture and electrical generation.  However, most of the water used in agriculture and for cooling in power plants eventually returns to the hydrological cycle.  It makes its way back into local rivers and water sources.

In the timeframe of this study, Ceres reports that:

  • 97 billion gallons of water were used, nearly half of it in Texas, followed by Pennsylvania, Oklahoma, Arkansas, Colorado and North Dakota, equivalent to the annual water need  of 55 cities with populations of ~ 5000 each.
  • Over 30 counties used at least one billion gallons of water.
  • Nearly half of the wells hydraulically fractured since 2011 were in regions with high or extremely high water stress, and over 55% were in areas experiencing drought.
  • Over 36% of the 39,294 hydraulically fractured wells in the study overlay regions experiencing groundwater depletion.
  • The largest volume of hydraulic fracturing water, 25 billion gallons, was handled by service provider, Halliburton.

Water withdrawals required for hydraulic fracturing activities have several worrisome impacts. For high stress and drought-impacted regions, these withdrawals now compete with demands for drinking water supplies, as well as other industrial and agricultural needs in many communities.  Often this demand falls upon already depleted and fragile aquifers and groundwater.  Groundwater withdrawals can cause land subsidence and also reduce surface water supplies. (USGS considers ground and surface waters essentially a single source due to their interconnections).  In some areas, rain and snowfall can recharge groundwater supplies in decades, but in other areas this could take centuries or longer.  In other areas, aquifers are confined and considered nonrenewable.   (We will look at these and additional impact in more detail in our next installments.)

Challenges of documenting water consumption and scarcity

Tracking water volumes and locations turns out to be a particularly difficult process.  A combination of factors confuse the numbers, like conflicting data sets or no data,  state records with varying criteria, definitions and categorization for waste, unclear or no records for water volumes used in refracturing wells or for well and pipeline maintenance.

Along with these impediments, “chain of custody” also presents its own obstacles for attempts at water bookkeeping. Unconventional drilling operations, from water sourcing to disposal, are often shared by many companies on many levels.  There are the operators making exploration and production decisions who are ultimately liable for environmental impacts of production. There are the service providers, like Halliburton mentioned above, who oversee field operations and supply chains. (Currently, service providers are not required to report to FracFocus.)  Then, these providers subcontract to specialists such as sand mining operations.  For a full cradle-to-grave assessment of water consumption, you would face a tangle of custody try tracking water consumption through that.

To further complicate the tracking of this industry’s water, FracFocus itself has several limitations. It was launched in April 2011 as a voluntary chemical disclosure registry for companies developing unconventional oil and gas wells. Two years later, eleven states direct or allow well operators and service companies to report their chemical use to this online registry. Although it is primarily intended for chemical disclosure, many studies, like several of those cited in this article, use its database to also track water volumes, simply because it is one of the few centralized sources of drilling water information.  A 2013 Harvard Law School study found serious limitations with FracFocus, citing incomplete and inaccurate disclosures, along with a truly cumbersome search format.  The study states, “the registry does not allow searching across forms – readers are limited to opening one PDF at a time. This prevents site managers, states, and the public from catching many mistakes or failures to report. More broadly, the limited search function sharply limits the utility of having a centralized data cache.”

To further complicate water accounting, state regulations on water withdrawal permits vary widely.  The 2011 study by Resources for the Future uses data from the Energy Information Agency to map permit categories.  Out of 30 states surveyed, 25 required some form of permit, but only half of these require permits for all withdrawals. Regulations also differ in states based on whether the withdrawal is from surface or groundwater.  (Groundwater is generally less regulated and thus at increased risk of depletion or contamination.)  Some states like Kentucky exempt the oil and gas industry from requiring withdrawal permits for both surface and groundwater sources.

Can we treat and recycle oil and gas wastewater to provide potable water?

WV Field Visits 2013Will recycling unconventional drilling wastewater be the solution to fresh water withdrawal impacts?  Currently, it is not the goal of the industry to recycle the wastewater to potable standards, but rather to treat it for future hydraulic fracturing purposes.  If the fluid immediately flowing back from the fractured well (flowback) or rising back to the surface over time (produced water) meets a certain quantity and quality criteria, it can be recycled and reused in future operations.  Recycled wastewater can also be used for certain industrial and agricultural purposes if treated properly and authorized by regulators.  However, if the wastewater is too contaminated (with salts, metals, radioactive materials, etc.), the amount of energy required to treat it, even for future fracturing purposes, can be too costly both in finances and in additional resources consumed.

It is difficult to find any peer reviewed case studies on using recycled wastewater for public drinking purposes, but perhaps an effective technology that is not cost prohibitive for impacted communities is in the works. In an article in the Dallas Business Journal, Brent Halldorson, a Roanoke-based Water Management Company COO, was asked if the treated wastewater was safe to drink.  He answered, “We don’t recommend drinking it. Pure distilled water is actually, if you drink it, it’s not good for you because it will actually absorb minerals out of your body.”

Can we use sources other than freshwater?

How about using municipal wastewater for hydraulic fracturing?  The challenge here is that once the wastewater is used for hydraulic fracturing purposes, we’re back to square one. While return estimates vary widely, some of the injected fluids stay within the formation.  The remaining water that returns to the surface then needs expensive treatment and most likely will be disposed in underground injection wells, thus taken out of the water cycle for community needs, whereas municipal wastewater would normally be treated and returned to rivers and streams.

Could brackish groundwater be the answer? The United States Geological Survey defines brackish groundwater as water that “has a greater dissolved-solids content than occurs in freshwater, but not as much as seawater (35,000 milligrams per liter*).” In some areas, this may be highly preferable to fresh water withdrawals.  However, in high stress water regions, these brackish water reserves are now more likely to be used for drinking water after treatment. The National Research Council predicts these brackish sources could supplement or replace uses of freshwater.  Also, remember the interconnectedness of ground to surface water, this is also true in some regions for aquifers. Therefore, pumping a brackish aquifer can put freshwater aquifers at risk in some geologies.

Contaminated coal mine water – maybe that’s the ticket?  Why not treat and use water from coal mines?  A study out of Duke University demonstrated in a lab setting that coal mine water may be useful in removing salts like barium and radioactive radium from wastewater produced by hydraulic fracturing. However, there are still a couple of impediments to its use.  Mine water quality and constituents vary and may be too contaminated and acidic, rendering it still too expensive to treat for fracturing needs. Also, liability issues may bring financial risks to anyone handling the mine water.  In Pennsylvania, it’s called the “perpetual treatment liability” and it’s been imposed multiple times by DEP under the Clean Streams Law. Drillers worry that this law sets them up somewhere down the road, so that courts could hold them liable for cleaning up a particular stream contaminated by acid mine water that they did not pollute.

More to come on hydraulic fracturing and water scarcity

Although this article touches upon some of the issues presented by unconventional drilling’s demands on water sources, most water impacts are understood and experienced most intensely on the local and regional level.   The next installments will look at water use and loss in specific states, regions and watersheds and shine a light on areas already experiencing significant water demands from hydraulic fracturing.  In addition, we will look at some of the recommendations and solutions focused on protecting our precious water resources.