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Updated PA Data and Trends

By Matt Kelso, Manager of Data and Technology

The FracTracker Alliance periodically takes a deeper look into the unconventional oil and gas data in Pennsylvania, in order to provide updates for some frequently requested statistics on the industry. Here we provide updated PA data and trends as of December 4, 2014. Since unconventional drilling began in the Commonwealth permits have been issued to drill 15,573 unconventional wells, according to data from the Pennsylvania DEP. Many – 8,696 (56%) – of those permits have actually been drilled. In terms of violations, there have been 5,983 entries on the statewide Compliance Report for unconventional wells throughout the state, which are attributed to 1,790 distinct wells.

Pennsylvania Shale Viewer Map


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Additional Stats

The number of permits, wells, and violations vary significantly from month to month, but each category is well off of its peak. The largest number of unconventional permits issued in a single month was 402, which was in December 2010, more than twice as many as were issued last month. In that year, there were six months with 300 or more permits issued, whereas there has only been one such month to date in 2014.

PA unconventional O&G activity per month from Jan. 2009 to Nov. 2014.  Source:  PADEP

PA unconventional O&G activity per month from Jan. 2009 to Nov. 2014. Source: PADEP

The 210 wells spudded (drilled) in August 2011 represents the high water mark, and is more than two times the amount of wells drilled last month. In the 28 months between March 2010 and June 2012, the industry failed to spud 100 wells only once, reaching 98 in April 2011. In the first 11 months of 2014, that plateau was missed three times, with a low of 58 spuds in February.

There was a significant spike in violations appearing on the compliance report from December 2009 through August 2011. More than 100 violations were issued in 17 out of 21 months, including 196 in March 2010. The number of violations issued has slowed down considerably since then, with November 2014 being the 34th straight month with fewer than 100 violations. Only 14 violations were issued in June 2014.

Violations per Well (VpW)

Unconventional violations per well by county in PA, showing the 10 counties with the largest number of violations.  Counties with an above average Violations per Well (VpW) score are highlighted in red.

Unconventional violations per well by county in PA, showing the 10 counties with the largest number of violations. Counties with an above average Violations per Well (VpW) score are highlighted in red.

We often ask whether drilling is more problematic in some areas than others. Since the number of wells varies depending upon the location, we must approach this question by looking at the number of violations issued per well drilled (VpW). However, there is an important caveat to consider. Put simply, what is a violation? The Pennsylvania DEP publishes a Compliance Report for unconventional wells, which has 5,983 incidents listed from 2000 through December 4, 2014. However, it used to be common for the DEP to lump several incidents into the same Violation ID number, although this is not the case for more recent infractions. When the DEP counts violations issued, they look at the total number of unique Violation ID numbers that have been issued, not the total number of incidents on the report. Here, we include the more inclusive list of items on the compliance report.

Of the 10 counties with the largest number of violations issued, only 3 counties have a violations per well mark below the statewide average. Notably, each of those three counties are located in Southwestern Pennsylvania. It is unclear from these numbers what is going on in Potter County, but clearly there is a significant problem in that location – with almost three violations issued per well drilled, Potter County has a VpW score 4.3 times the statewide average.

Operator Trends

Before we look at the operators with the most violations, there is an additional caveat to consider: It is relatively common for wells to change hands over their operational lifetimes. This characteristic could be due to one company buying another out, or simply transferring some of their assets. Still, wells changing from one operator to another is a normal aspect of the oil and gas industry. Such a fact matters for this analysis because while violations issued always stick with the responsible party in the DEP data, the name of the operator changes on the Spud Report to the current operator.

Unconventional violations per well by operator in PA, showing the 10 operators with the largest number of violations.  Operators with an above average Violations per Well (VpW) score are highlighted in red.

Unconventional violations per well by operator in PA, showing the 10 operators with the largest number of violations. Operators with an above average Violations per Well (VpW) score are highlighted in red.

Because of how these datasets are maintained, we see that East Resources has 261 violations for zero wells, which is of course an impossibly large ratio. That is because East sold off its stake in the Marcellus to Royal Dutch Shell, which does business as SWEPI in Pennsylvania. SWEPI, by the way, is 13th on the list of violations in its own right, with 154 violations for 675 wells, resulting in a 0.23 VpW. If the legacy violations for the old East wells were included, the result would be a 0.61 ViW score, which is almost three times as high, but still below the statewide average. FracTracker doesn’t do the analysis that way, both because it is unfair to the new operator to charge them with violations that they had nothing to do with, as well as being nearly impossible to keep track of the various transactions that result in wells changing hands over the years.


Cover image by Pete Stern, 2013.

In-depth Review of the Statoil Well Pad Fire

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.

Statoil 4

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

Statoil 6

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.

Statoil 7

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.

Statoil 12

Fig. 12. 16 fracturing pumps

Statoil 13

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.

Fracturing wells and land cover in California

By Andrew Donakowski, Northeastern Illinois University

Land cover data can play an important role in spatial analysis; satellite or aerial imagery can effectively demonstrate the extent and make-up of land cover characteristics for large areas of land. For fracking analysis, this can be used to explore important spatial relationships between fracking infrastructure and the area and/or ecosystems surrounding them. Working with FracTracker, I have compiled data concerning land cover classifications and geologic rock areas to examine areas that may be particularly vulnerable to unconventional drilling – e.g. fracking.  After computing the makeup of land cover type for each geologic area, I then mapped locations of known fracking wells for further analysis. This is part of FracTracker’s ongoing interest in understanding changes in ecosystem services and plant/soil productivity associated with well pads, pipelines, retention ponds, etc.

Developed

First, by looking at the Developed areas (below), we can see that, for the most part, hydraulic fracturing is occurring relatively far from large population areas. (That is to say, on this map we can see that these types of wells are not found as often in areas where population density is high (<20 people per square mile) or a Developed land cover classification is predominate as they are in areas with a lower Develop land cover percentage).  However, we can also see that there is quite a large cluster of fracking wells in the southern portion of the state, and many cities fall within 5 or 10 mi of some wells.  While there may not be an immediate danger to cities that fall within this radius, we can see that some areas of the state may be more likely to encounter the effects of fracking and its associated infrastructure than others.

Forested

Next, the map depicting Forested land cover areas is, in my opinion, the most aesthetically groovy of the land cover maps; the variations in forested areas throughout the state provide a cool image.  By looking at this data, we can see that much of California’s forested land lies in the northern part of the state, while most fracking wells are located in the south and central parts of the state.

Cultivated

To me, the most interesting map is the one below showing the location of fracking wells in relation to Cultivated lands (which includes pasture areas and cropland).  What is interesting to note is the fertile Central Valley, where a high percentage of land is covered with agriculture and pasture lands (Note: The Central Valley accounts for 1% of US farmland but 25% of all production by value).  Notably, it is also where many fracking wells are concentrated.  When one stops to think about this, it makes sense: Farmers and rural landowners are often approached with proposals to allow drilling and other non-farming activities on their land.  Yet, it also raises a potential area for concern: A lot of crops grown in this area are shipped across the country to feed a significant number of people.  When we consider the uncertainties of fracking on surrounding areas, we must also consider what effects fracking could have beyond the immediate area and think about how fracking could affect what is produced in that area (in this case, it is something as important as our food supply.)

The Usefulness of Maps

Finally, as previously mentioned, mapping the extent of these land coverage can be useful for future analysis.  Knowing now the areas of relatively large concentrations of forested, herbaceous, and wetland (which can be highly sensitive to ecological intrusions) areas can be good to know down the line to see if those areas are retreating or if the overall coverage is diminishing.  Additionally, by allowing individuals to visualize spatial relationships between fracking areas and land coverage, we can make connections and begin to more closely examine areas that may be problematic. The next step will be: a) parsing forest cover into as many of the six major North American forest types and hopefully stand age, b) wetland type, and c) crop and/or pasture species. All of this will allow us to better quantify the inherent ecosystem services and CO2 capture/storage potential at risk in California and elsewhere with the expansion of the fracking industry. As an example of the importance of the intersection between forest cover and the fracking industry we recently conducted an analysis of frac sand mining polygons in Western Wisconsin and found that 45.8% of Trempealeau County acreage is in agriculture while only 1.8% of producing frac sand mine polygons were in agriculture prior to mining with the remaining acreage forested prior to mining which buttresses our anecdotal evidence that the frac sand mining industry is picking off forested bluffs and slopes throughout the northern extent of the St. Peter Sandstone formation.

A Quick Note on the Data

Datasets for this project were obtained from a few different sources.  First, land cover data were downloaded from the National Land cover Classification Database (NLCD) from the Multi-Resolution Land Character Consortium.  Geologic data were taken from the United States Geologic Survey (USGS) and their Mineral Resources On-Line Spatial Data. Lastly, locations of fracking wells were taken from the FracTracker data portal, which, in turn, were taken from SkyTruth’s database.  Once the datasets were obtained, values from the NLCD data were reclassified to highlight land-coverage types-of-interest using the Raster Calculator tool in ArcMap 10.2.1.  Then, shapefiles from the USGS were overlaid on top of the reclassified raster image, and ArcMaps’s Tabulate Area tool was used to determine the extent of land coverage within each geologic rock classification area.  Known fracking wells downloaded from FracTracker.org were added to the map for comparative analysis.

About the Author

Andrew Donakowski is currently studying Geography & Environmental Studies, with a focus on Geographic Information Systems (GIS), at Northeastern Illinois University (NEIU) in Chicago, Ill. These maps were created in conjunction with FracTracker’s Ted Auch and NEIU’s Caleb Gallemore as part of a service-learning project conducted during the spring of 2014 aimed at addressing real-world issues beyond the classroom.

Mapping California’s State Bill 4 (SB4) Well Stimulation Notices

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

Introduction

California passed State Bill 4 (SB4) in September, 2013 to develop and establish a regulatorySanta Barbara Channel_10.7.13 structure for unconventional resource extraction (hydraulic fracturing, acidizing, and other stimulation techniques) for the state.   As a feature of the current version of the regulations, oil and gas drilling/development operators are required to notify the California Department of Conservation’s Division of Oil Gas and Geothermal Resources (DOGGR), as well as neighboring property owners, 30 days prior to stimulating an oil or gas well.  In addition to property owners having the right to request baseline water sampling within the the following 20 days, DOGGR posts the well stimulation notices to their website.

Current State of Oil and Gas Production

The DOGGR dataset of well stimulation notices was downloaded, mapped, the dataset explored, and well-site proximity to certain sites of interest were evaluated using GIS techniques. First, the newest set of well stimulation notices, posted 1/17/14 were compared to a previous version of the same dataset, downloaded 12/27/13. When the two datasets are compared there are several distinct differences. The new dataset has an additional field identifying the date of permit approval and fields for latitude/longitude coordinates. This is an improvement, but there is much more data collected in the DOGGR stimulation notification forms that can be provided digitally in the dataset, including sources of water, amount of water used for stimulation, disposal methods, etc… An additional 60 wells have been added to the dataset, making the total count now 249 stimulation notices, with 37 stimulated by acid matrix (acidizing), 212 hydraulically fractured, and 3 by both. Of the 249, 59 look to be new wells as the API identifcation numbers are not listed in the DOGGR “AllWells.zip” database here, while 187 are reworks of existing wells. A difference of particular interest is the discrepancy in latitudes and longitudes listed for several well-sites. The largest discrepancy shows a difference of almost 10,000 feet for an Aera Energy well (API 3051341) approved for stimulation December 23, 2013. The majority of the well stimulations (246/249) are located in Kern County, and the remaining three are located in Ventura County.

Figure 1. Stimulation Notices and Past/Present Oil and Gas Wells
Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

Well Spacing

As can be seen in Figure 1, the well stimulations are planned for heavily developed oil and gas fields where hydraulic fracturing has been used by operators in the past. California is the 4th largest oil producing state in the nation, which means a high density of oil and gas wells. Many other states limit the amount of wells drilled in a set amount of space in support of safer development and extraction. In Ohio, unconventional wells (>4,000 foot depths) have a 1,000 foot spacing requirement , West Virginia has a 3,000 foot requirement for deep wells , and the Texas Railroad Commission has set a 1,200 foot well spacing requirement. Using Texas’s setback as an example buffer for analysis, 241/249 of the DOGGR new stimulations are within 1,200 feet of an active oil and gas well. Of the 364 hydraulically fractured oil and gas wells DOGGR has listed as “New” (they are not yet producing, but are permitted and may be in development), 351 are within 1,200 feet of a well identified in DOGGR’s database as an active oil and gas well. One of the industry promoted benefits of using stimulations such as hydraulic fracturing is the ability to decrease the number of well-sites necessary to extract resources and therefore decrease the surface impact of wells. This does not look to be the practice in California.

Environmental Media

Following this initial review of oil and gas production/development, three additional maps were created to visualize the environmental media threatened by contamination events such as fugitive emissions, spills or well-casing failures. The maps are focused on themes of freshwater resources, ambient air quality, and conservation areas.

Freshwater Resources

Figure 2. New Wells, Stimulation Notices and California’s Freshwater Resources
Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

Freshwater resources are limited in arid regions of California, and the state is currently suffering from the worst drought on record. In light of these issues, the FracMapper map “New Well Stimulations and California Freshwater Resources” includes map layers focused on groundwater withdrawals, groundwater availability, Class II wastewater injection wells, watershed basins, and the United States Geological Survey’s (USGS) National Hydrography Data-set (NHD). Since California does not have a buffer rule for streams and waterways, we used the setback regulation from Pennsylvania for an analysis of the proximity of the well stimulation notices to streams and rivers. In Pennsylvania, 300 feet is the minimum setback allowed for hydraulic fracturing near recognized surface waters. Of the 246 wells listed for new stimulation, 26 are within 300 feet of a waterway identified in the USGS’s NHD. The watersheds layer shows the drainage areas for these well locations. As a side note, the state of Colorado does not allow well-sites located within 100 year flood plains after the flash floods in September 2013 that caused over 890 barrels of oil condensates to be spilled into waterways. Also featured in Figure 2 are the predominant shallow aquifers in California. The current well stimulations posted by DOGGR are located in the Elk Hills (Occidental Inc.), Lost Hills (Chevron), Belridge and Ventura (both Aera Production) oil fields and have all exempted out of a groundwater monitoring plans based on aquifer exemptions, even though the aquifers are a source of irrigation for the neighboring agriculture.   Stimulation notices by Vintage Production in the Rose oil field, located in crop fields on farms, are accompanied by a groundwater and surface water monitoring plan. Take notice of the source water wells on the map that provide freshwater for both the acidizing and hydraulic fracturing operations and the Class II oil and gas wastewater injection wells that dispose of the produced waters. Produced wastewaters may also be injected into Class II enhanced oil recovery water flood wells, and several of the stimulation notices have indicated the use of produced waters for hydraulic fracturing.

Ambient Air Quality

Figure 3. California New Wells, Stimulation Notices and Air Quality
Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

Impacts to ambient air quality resulting from oil and gas fields employing stimulation techniques have been documented in areas like Wyoming’s Upper Green River Basin , the Uintah Basin of Utah , and the city of Dish, Texas . Typically, ozone is considered a summertime issue in urban environments, but the biggest threat to air quality in these regions has been elevated concentrations of ozone, particularly in the winter time. Ozone levels in these regions have been measured at concentrations higher than would typically be seen in Los Angeles or New York City. In Figure 3, the state and federal ozone attainment layers show that the areas with the highest concentrations of “new” wells and the DOGGR New Stimulation Notices do not pass ambient air criteria standards to qualify as “attainment” status for either state or federal ambient ozone compliance, meaning their ambient concentrations reach levels above health standards. Other air pollutants known to be released during oil and gas development, stimulation, and production include volatile organic compounds (VOCs) such as Benzene, Toluene, Ethylbenzene and xylene (BTEX); carbon monoxide (CO); hydrogen sulfide (H2S), Nitrogen Oxides (NOx), and sulfur dioxide (SO2), and methane (CH4), a potent greenhouse gas. It is important to point out that ground level ozone is not emitted directly but rather is created by chemical reactions between NOx and VOCs. Besides ozone, all these other air pollutants are in “attainment” in California except NOx in Los Angeles County. There have not been any stimulation notices posted in Los Angeles County, but the South Coast Air Quality Monitoring District identifies 662 recent wells that have been stimulated using hydraulic fracturing, acidizing, or gravel packing. See the Local Actions map of California for these well sites.

Conservation Areas

Figure 4. New Wells, Stimulation Notices and Conservation Areas
Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

The map in Figure 4, “New Well Stimulations and Conservation Lands”, features land use planning maps developed by California and Federal agencies for conservation of the environment for multiple uses, ranging from recreation to farming and agriculture.  Many of the Stimulation Notices as well as “new” well sites located in Kern County are located in or along the boundary of the San Joaquin Valley Conservation Opportunity; land identified by the California Department of Fish and Game, Parks and Recreations, and Transportation (Caltrans) as important for wildlife connectivity. Oil and gas development inevitably results in loss of habitat for native species. Habitat disturbance and fragmentation of the natural ecosystems can pose risks particularly for endangered species like the San Joaquin Kit Fox, California Condor, and the blunt-nosed leopard lizards.

The California Rangeland Priority Conservation Areas layer was created to identify the most important areas for priority efforts to conserve the Oak Savannah grasslands of high diversity that host many grassland birds, native plants, and threatened vernal pool species. The areas of high biodiversity value are marked in red as “critical conservation areas”. The majority of the new well stimulations are encroaching on the borders of these “critical areas,” particularly in the Belridge oil field. The CA Farmland Mapping and Monitoring Program map layer rates land according to soil quality to analyze impacts on California’s agricultural resources. The majority of new stimulations and new oil wells are located on the border of areas designated as “prime farmland,” particularly the Belridge and Lost Hills fields. The Rose field on the other hand is located within the “prime farmland” and “farmland of statewide importance.” Also, well-sites from all fields in Kern County are located on Williamson Act Agricultural Preserve Land Parcels. By enrolling in the program these areas can take advantage of reduced tax rates as they are important buffers to reduce urban sprawl and over-development. Although the point of the act was to protect California’s important farmland and agriculture, some parcels enrolled in the Williamson Agricultural Preserve Act program even house stimulation notice sites and “new” hydraulically fractured wells.

Discussion

While allowing hydraulic fracturing, acidizing and other stimulations until January 1, 2015 under temporary regulations, SB4 requires the state of California to complete an Environmental Impact Review (EIR). New regulations will then be developed on the recommendations of the EIR. The regulations will be enforced by the Division of Oil, Gas, and Geothermal Resources (DOGGR), the agency currently responsible for issuing drilling permits to operators in the state. In some municipalities of California, an additional “land-use” development permit is required from the local land-use agency (Air district, Water District, County, other local municipality or any combination) for an operator to be granted permission to drill a well. In most areas of California a “land-use” permit is not required, and only the state permit from DOGGR is necessary. A simple explanation is DOGGR grants the permit for everything that occurs underground, and in some locations a separate regulatory body approves the permit for what occurs above the ground at the surface. The exceptions are San Benito County which has a 500 foot setback from roads and buildings, Santa Cruz County, which passed a moratorium, Santa Barbara with a de facto ban*, and the South Coast Air quality Monitoring District’s notification requirements, permitting a well stimulation (such as “fracking” or “acidizing”).  For the rest of the state permitting a well  stimulation is essentially the same as permitting a conventional well-site, although it should be recognized that some counties like Ventura have setback and buffer provisions for all (conventional and unconventional) oil and gas wells. Additionally, DOGGR’s provisional regulations do require chemical disclosures to FracFocus and public notifications to local residents 30 days in advance, but lacks public health and safety provisions such as setbacks, continuous air monitoring, and the majority of wells in the notices are exempt from groundwater monitoring,   While public notifications and chemical disclosures are all important for liability and tracking purposes, they are no substitute for environmental and engineering standards of practice including setbacks and other primary protection regulations to prevent environmental contamination. The state-sponsored EIR is intended to inform these types of rules, but that leaves a year of development without these protections.
*Santa Barbara County requires all operators using hydraulic fracturing to obtain an oil drilling production plan from the Santa Barbara County Planning Commission. No operator has applied for a permit since the rule’s passing in 2011.

References

  1. DOGGR. 2014. Welcome to the Division of Oil, Gas and Geothermal Resources.  Accessed 1/28/14.
  2. Lawriter Ohio Laws and Rules. 2010. 1501:9-1-04 Spacing of wells. Accessed 1/29/14.
  3. WVDNR. 2013. Regulations. Accessed 1/29/14.
  4. Railroad Commission of Texas. 2013. Texas Administrative Code. Accessed 1/28/14.
  5. PADEP. 2013. Act 13 Frequently Asked Questions.  Accessed 1/29/14.
  6. U.S.EPA. 2008. Wyoming Area Designations for the 2008 Ozone National Ambient Air Quality Standards. Accessed 1/29/14.
  7. UT DEQ. 2014. Uintah Basin. Accessed 1/29/14.
  8. UT DEQ. 2012. 2012 Uintah Basin Winter Ozone & Air Quality Study.
  9. Wolf Eagle Environmental. 2009. Town of Dish, TX Ambient Air Monitoring Analysis.
Well and pipeline data in British Columbia

British Columbia Map Now Available

Increasingly, FracTracker has been receiving requests to map oil and gas data from a variety of locations.  Now for the first time since the roll-out of the ArcGIS Online-based FracMapper platform last year, we have content dedicated to understanding oil and gas data outside of the United States.  Specifically, this map is focused on the extractive – and midstream – activities in British Columbia, Canada.


British Columbia Shale Viewer. Please click the expanding arrows icon in the upper right corner of the map to access the full page map, complete with legend and descriptions.

British Columbia’s Oil and Gas Commission has records for over 29,000 wells, of which over 11,000 are indicated as being directional.  These are the wells included on this map.  While directional drilling is a broader category than horizontal drilling, which is more commonly associated with hydraulic fracturing, it was the most readily available means of finding wells likely to be unconventional in nature.  And indeed, a substantial majority of the directional wells drilled in the province correspond to the unconventional plays in the northeastern portion of British Columbia.

While the available well data was lacking some of the detail that FracTracker prefers, this is made up for by a data type that is difficult to encounter in the United States:  pipeline rights-of-way.  Note that not all of the wells on the map are connected by pipelines.  One explanation is that the pipeline data are from October 30, 2006 onward, while over 3,600 of the directional wells were drilled before that time.

Well and pipeline data in British Columbia
This image shows a closeup of the British Columbia Shale Viewer, highlighting pipeline data

Other notable data types for British Columbia include oil and gas facilities, and a layer showing the extent of individual well sites.  For more information, see the Details section of the map.

Keeping Track of Hydraulic Fracturing in California

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

Environmental regulations in California are considered conservative by most state standards. To name a few practices, the state has developed an air quality review board that conducts independent toxicological assessments on a level competitive with the U.S. EPA, and the state instituted the U.S.’s first green house gas cap and trade program. But most recently the California Department of Conservation’s Division of Oil, Gas and Geothermal Resources (DOGGR) has been criticized in the media for its lack of monitoring of hydraulic fracturing activity. DOGGR has been responsive to criticism and preemptive of legislative action and has begun a full review of all well-sites in California to identify which wells have been hydraulically fractured and plan to monitor future hydraulic fracturing. Additionally they have maintained historical records of all wells drilled, plugged, and abandoned in the state in web-accessible databases, which include data for oil and gas, geothermal, and injection wells, as well as other types of support wells such as pressure maintenance, steam flood etc.. The data is also viewable in map format on the DOGGR’s online mapping system (DOMS).

To understand what is missing from the DOGGR dataset, it was compared to the dataset extracted from FracFocus.org by SkyTruth. The map “Hydraulic Fracturing in California” compares these two datasets, which can be viewed individually or together as one dataset with duplicates removed. It is interesting to note the SkyTruth dataset categorizes 237 wells as hydraulically fractured that DOGGR does not, and identifies three wells (API #’s 11112215, 23727206, and 10120788) not identified in the DOGGR database. For the some of these 237 wells, DOGGR identifies them as new, which means they were recently drilled and hydraulically fractured and DOGGR will be updating their database. Many are identified as active oil and gas wells., while the rest are identified as well types other than oil and gas. Also the SkyTruth dataset from FracFocus data contains additional information about each well-site, which DOGGR does not provide. This includes volumes of water used for hydraulic fracturing and the fracture date, both of which are vital pieces of monitoring information.

The California State Legislature is currently reviewing California Senate Bill 4 (CA SB 4) written by Sen. Fran Pavley (D-Agoura Hills), which would put in place a regulatory structure for permitting and monitoring hydraulic fracturing and other activity.  A caveat for acidification is also included that would require companies to obtain a specific permit from the state before acidizing a well.  The bill has received criticism from both industry and environmentalists.  While it does not call for a moratorium or regulate what chemicals are used, it is the first legislation that requires a full disclosure of all hydraulic fracturing fluid additives, including those considered proprietary.  This is the last of at least seven bills on the issue, the majority of which have been turned down by lawmakers. The most conservative bills (Assemblywoman Mitchell; D-Culver City) proposed moratoriums on hydraulic fracturing in the state. Earlier this year lawmakers approved a bill (Sen. Pavley; D-Agoura Hills) that would direct the state to complete and independent scientific risk assessment of hydraulic fracturing. The bill directs permitters to deny permits if the study is not finished by January 1, 2015, and also requires public notice before drilling as well as disclosure of chemicals (besides those considered proprietary). In May, a bill (Sen. Wold; D-Davis) was passed requiring drillers to file a $100,000 indemnity bond for each well, with an optional blanket indemnity bond of $5 million for operators with over 20 wells. Another bill (Jackson; D-Santa Barbara) that would require monitoring of both transportation and disposal of wastewater was tabled until next year.

Although hydraulic fracturing has been conducted in California for over a decade, it was not monitored or regulated, and the majority of Californians were not aware of it. Industry groups have portrayed the lack of attention as a testament to its environmental neutrality, but Californians living smack dab in the middle of the drilling tend to tell a different story. The issue is now receiving attention because hydraulic fracturing is such a hotbed topic of contention, along with the potential future of the billions of barrels of oil in the Monterey Shale. The unconventional extraction technology necessary to recover the oil from these deep shale formations is state of the art, which means it is not tried and true. The methods include a combination of high tech approaches, such as horizontal drilling, high volume hydraulic fracturing, and acidification to name a few. Realize: if this technology existed for the last 60 years, the Monterey Shale would already have been developed long ago, along with the rest of the U.S. deep shale formations.

FracTracker Alliance’s *NEW* California Shale Viewer

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

The FracTracker Alliance has just recently opened a new office based out of Berkeley, California. As a first step in addressing the unique issues of oil and gas extraction in the Golden State, FracTracker has queried the data that is published by the state’s regulatory agencies, and has translated those datasets into various maps that highlight specific issues. As a first step in this process, FracTracker transcribed the well-site data that is publicly available from the California Department of Conservation’s (DOC) Division of Oil, Gas and Geothermal Resources (DOGGR).

This first phase of analysis is presented in FracMapper on the California page, here. FracTracker has translated the entire DOGGR database into a map layer that can be viewed on the California Shale Viewer map, here. The California Shale Viewer will be continuously updated to map the expanding oil and gas development as it occurs. Featured map layers on the California Shale Viewer focus on hydraulic fracturing in the state of California. The hydraulic fracturing well-site data comes from two sources. First, the layer “CA Hydraulically Fractured Wells Identified by DOGGR” portrays the maps identified by regulatory agency as having been hydraulically fractured. The DOGGR is aware that their dataset is not complete in terms of identifying all wells that have been hydraulically fractured. The second source of data is from our friends at SkyTruth, and provided in the layer “CA Hydraulically Fractured Wells Identified by SkyTruth”. Using a crowd-source platform, SkyTruth has generated a dataset based on the information reported to FracFocus.org. FracFocus.org refuses to provide aggregated datasets of their well-site data. These hydraulically fractured well-sites can be viewed as a individual datasets in the California Shale Viewer, or as a combined layer in the map “California Hydraulically Fractured and Conventional Oil and Gas Wells” map, where you are also able to view the dataset of wells FracFocus identifies as hydraulically fractured, but DOGGR does not.

More information concerning the many different types of wells drilled in California and the status of these wells (whether they are planned, active, idle or plugged) can be found in the “Well Type” map and “Well Status” map, also available on the FracTracker California page.

Determination Letters Added to PADEP Groundwater Complaints Map

A couple of months ago, Laura Legere of the Scranton Times-Tribune published an article showing her research into determination letters sent by the Pennsylvania Department of Environmental Protection (PADEP) in response to people who claimed that their groundwater had been impacted by oil and gas activity in the state.  Of the 973 complaints represented on this dataset, the PADEP has determined a causality between the oil and gas activity and the water complaint in 162 instances.  Note that not all of these complaints are necessarily as a result of the hydraulic fracturing (a.k.a. fracking) stage of operations.

The FracTracker Alliance assisted in the project by creating an interactive map of the instances throughout the state.  As the Scranton Times-Tribune has now made digital scans of each of the 973 records available on their servers, we have been able to link to them on the map.

In this screen capture, the popup box for the first of eleven complaints mapped at this location is shown.  In order to access the determination letter, the user must simply click on the PDF logo.

In this screen capture, the popup box for the first of eleven complaints mapped at this location is shown. In order to access the determination letter, the user must simply click on the PDF logo.

Names, addresses, and other personal information about the complainants have been removed from this dataset in order to protect their privacy.  And because the locations are drawn at the center-point of the municipality in which they live, we can get a general sense for the distribution of the events without being able to zoom in one the affected parties’ houses.

To get an idea of what the determination letters look like, here is one example in which the PADEP indicates that someone’s water supply has been impacted by gas drilling:

A portion of one of the determination letters sent by PADEP to a landowner in response to a complaint about groundwater.  Click the image to access the full PDF file.

A portion of one of the determination letters sent by PADEP to a landowner in response to a complaint about groundwater. Click the image to access the full PDF file.

Here is the dynamic version of the map of the complaints:


Please click on the Fullscreen icon to load our full suite of controls.

This updated data has also been added to the US Map of Suspected Well Water Impact project:

US Map of Suspected Well Water Impacts

Launch of National Mapping Project Designed to Show Possible Impacts of Oil and Gas Drilling on Well Water

FOR IMMEDIATE RELEASE
US Map of Suspected Well Water Impacts
Contacts: Brook Lenker, Executive Director, FracTracker Alliance, (717) 303-0403; and
Samantha Malone, Manager of Science and Communications, FracTracker Alliance, (412) 802-0273

May 1, 2013 – The US Map of Suspected Well Water Impacts is a project that will attempt to piece together recent complaints of well water quality impacts that people believe are attributed to unconventional gas and oil operations. Research has demonstrated potential risks to ground and drinking water posed by faulty well casings, surface spills, and hydraulic fracturing. From across the country, in areas where gas and oil development is occurring, accounts of possible well water contamination have been reported but not been collected all in one place – yet. The FracTracker Alliance and cooperating organizations are providing that opportunity.

Inspired by other “crowd-sourced” data and mapping projects, this project aims to collect ongoing stories, narratives, and data from individual homeowners living on well water near drilling operations and map the general location of these reports online.  The first version of the dynamic map (shown below) is available at www.fractracker.org/usmap.

US Map of Suspected Well Water Impacts - V1

US Map of Suspected Well Water Impacts
Read more about Version 1 of the map

Once received, submissions will be reviewed to the extent possible by cooperating researchers and organizations. Not all reported cases of water contamination, however, have been or will be able to be substantiated. According to Brook Lenker, Executive Director of FracTracker Alliance:

The reports we are collecting are not necessarily indisputable evidence that drilling has contaminated drinking water sources. Some accounts are irrefutable. Others remain unsubstantiated, but that doesn’t mean the well owner isn’t experiencing serious problems. Even where proof may be elusive, perception of risk can tell us much about an issue and the level of concern by the community.  This information will likely help to identify pre-existing problems or conditions that were not previously well known.  Such outreach is needed to permit citizens, local agencies, and others to work together to address pre-existing concerns, improve local regulations or standards, conduct proper baseline testing and monitoring, and make informed decisions.

As unconventional natural gas and oil extraction expands internationally, an Internet-based project like the US Map of Suspected Well Water Impacts can help to share on a global scale how people in the U.S. view – and may be impacted by – unconventional drilling. If everyone contributed their stories, the public’s understanding of gas and oil extraction’s impacts on well water could expand dramatically.

Anyone wishing to submit their story should visit www.fractracker.org/usmap or call (202) 639-6426. A complete list of current project partners is available on the website.

# # #

Downloadable Press Release (PDF)
Read more about Version 1 of the map

US Map of Suspected Well Water Impacts - V1

Introducing the US Map of Suspected Well Water Impacts

About the Map

The FracTracker Alliance has been working with nine different community partners on a project to map instances where oil and gas activity are suspect of impacting groundwater supplies in the United States. The US Map of Suspected Well Water Impacts is now ready for its initial release, and consists of the following data layers:

  • Visitor Submitted Impacts. This layer consists of viewer submitted form data describing suspected incidents of groundwater contamination by oil and gas extraction and related industries.  The locations have been determined using the centroids or geometric center-points of the zip code in which the suspected incident occurred.  If you are aware of additional incidents, please submit them here.
  • Pipeline Incidents Contaminating Groundwater. This data layer includes hazardous liquid pipeline incidents that were indicated as resulting in groundwater contamination between 1/1/2010 and 3/29/2013.  The data were obtained by the US Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA).  The data have been altered by the FracTracker Alliance in that it only includes incidents leading to groundwater contamination, and by the removal of several dozen columns of data about the incident for the sake of brevity.  There are 30 incidents on this list.
  • NRDC Suspected Contamination Events. Amy Mall of the Natural Resources Defense Council compiled a list of 37 incidents where hydraulic fracturing is suspected of contributing to groundwater contamination.   The list was compiled in December 2011, and each entry is linked to news reports of the event.   This layer was mapped by the FracTracker Alliance based on the centroids or geographic center-points of the municipality, county, or state of the incident, depending on the best information available.
  • List of the Harmed Suspected Water Incidents. Jenny Lisak, co-director of the Pennsylvania Alliance for Clean Water and Air, maintains a list of people claiming to be harmed by hydraulic fracturing or related processes, called the List of the Harmed (LotH).  This data layer is based on the February 23, 2013 update of the list, and contains only the events in which water is the suspected exposure pathway.  This data was mapped by the FracTracker Alliance based on the centroids or geographic center-points of the municipality, county, or state of the incident, depending on the best information available.
  • NM Pit Contamination Events. This layer consists of events where the New Mexico Oil Conservation Division determined that substances from oil and gas pits contaminated groundwater.  Altogether, there are 369 incidents included in the data.  The document on which this map was based was published in 2008.  This data was mapped by the FracTracker Alliance based on the centroids or geographic center-points of the PLSS section, meaning that the points should be accurate within 0.72 miles.

US Map of Suspected Well Water Impacts – Version 1

It is important to note that the standard for inclusion in the map is simply whether or not someone suspects that well water has been impacted by oil and gas extraction-related activity.  Specifically, items on the Visitor Submitted Impacts, NRDC Suspected Contamination Events, and List of the Harmed Suspected Water Incidents should be thought of as perceived  impacts by oil and gas activity, not confirmed ones.  The NRDC and LotH lists were built with links to one or more media reports about the event.

On the other hand, the New Mexico document on which the pit contamination event layer was built simply says, “Cases Where Pit Substances Contaminated New Mexico’s Ground Water,” and it is worth noting that it was published by a state regulatory agency. Likewise, the PHMSA pipeline data is published by an administration within the US Department of Transportation.  Between these two layers, there are 399 incidents with the authority of a regulatory agency behind them.

Future versions of this map can be found on the project’s landing page.