FracTracker has received numerous requests to compile a regional map of natural gas storage wells. In response, we have built the dynamic map below covering storage wells in Pennsylvania, Ohio, and West Virginia:
The colored areas on the map above (pink, blue, and yellow) correspond to gas storage wells in one of the three states. When you first view the map in fullscreen mode you will notice that these wells have been “generalized” into one large layer. That feature allows the map to load more quickly in your browser.
Zoom in further to where the generalized layers change to individual points in order to explore the wells more in depth, as shown in the screenshot below:
Map Metadata: Upper Appalachian Gas Storage Wells
This map shows gas storage wells in Ohio, Pennsylvania, and West Virginia. Due to the large amount of data, generalized layers were created to show the location of the storage fields at statewide zoom levels. To access well data, viewers must zoom in beyond the scale of 1:500,000, or about the size of a large county. Each state’s data includes slightly different data fields.
Data Layers include:
Name: OH Storage Wells
Date: January 2018
Source: Ohio DNR
Notes: Gas storage wells in Ohio. Storage wells selected from a broader dataset by FracTracker Alliance.
Name: PA Storage Wells
Date: January 2018
Source: Pennsylvania DEP
Notes: Gas storage wells in Pennsylvania. Storage wells selected from a broader dataset by FracTracker Alliance.
Name: WV Storage Wells
Date: January 2018
Source: West Virginia DEP
Notes: Gas storage wells in West Virginia. Storage wells selected from a broader dataset by FracTracker Alliance.
Name: State Boundaries
Date: 2018
Source: USDA Geospatial Data Gateway
Notes: State boundaries of states with gas storage wells on this map.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2018/04/StorageWells-Appalachia-Feature.jpg400900FracTracker Alliancehttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngFracTracker Alliance2018-04-11 13:41:432021-04-15 15:01:19New map available showing Upper Appalachian gas storage wells
In August 2016, Shell Pipeline announced plans to develop the Falcon Ethane Pipeline System, a 97-mile pipeline network that will carry more than 107,000 barrels of ethane per day through Pennsylvania, West Virginia, and Ohio, to feed Shell Appalachia’s petrochemical facility currently under construction in Beaver County, PA.
FracTracker has covered the proposed Falcon pipeline extensively in recent months. Our Falcon Public EIA Project explored the project in great detail, revealing the many steps involved in risk assessments and a range of potential impacts to public and environmental health.
Shell’s response to these events has invariably focused on their intent to build and operate a pipeline that exceeds safety standards, as well as their commitments to being a good neighbor. In this article, we investigate these claims by looking at federal data on safety incidents related to Shell Pipeline.
Contrary to claims, records show that Shell’s safety record is one of the worst in the nation.
The “Good Neighbor” Narrative
Maintaining a reputation as a “good neighbor” is paramount to pipeline companies. Negotiating with landowners, working with regulators, and getting support from implicated communities can hinge on the perception that the pipeline will be built and operated in a responsible manner. This is evident in cases where Shell Pipeline has sold the Falcon in press releases as an example of the company’s commitment to safety in public comments.
Figure 1. Shell flyer
A recent flyer distributed to communities in the path of the Falcon, seen in Figure 1, also emphasizes safety, such as in claims that “Shell Pipeline has a proven track record of operating safely and responsibility and remains committed to engaging with local communities regarding impacts that may arise from its operations.”
Shell reinforced their “good neighbor” policy on several occasions at a recent Shell-sponsored information meeting held in Beaver County, stating that, everywhere they do business, Shell was committed to the reliable delivery of their product. According to project managers speaking at the event, this is achieved through “planning and training with first responders, preventative maintenance for the right-of-way and valves, and through inspections—all in the name of maintaining pipeline integrity.”
Shell Pipeline also recently created an informational website dedicated to the Falcon pipeline to provide details on the project and emphasize its minimal impact. Although, curiously, Shell’s answer to the question “Is the pipeline safe?” is blank.
U.S. Pipeline Incident Data
Every few years FracTracker revisits data on pipeline safety incidents that is maintained by the Pipeline and Hazardous Materials Safety Administration (PHMSA). In our last national analysis we found that there have been 4,215 pipeline incidents resulting in 100 reported fatalities, 470 injuries, and property damage exceeding $3.4 billion.
These numbers were based on U.S. data from 2010-2016 for natural gas transmission and gathering pipelines, natural gas distribution pipelines, and hazardous liquids pipelines. It is also worth noting that incident data are heavily dependent on voluntary reporting. They also do not account for incidents that were only investigated at the state level.
Shell Pipeline has only a few assets related to transmission, gathering, and distribution lines. Almost all of their pipeline miles transport highly-volatile liquids such as crude oil, refined petroleum products, and hazardous liquids such as ethane. Therefore, to get a more accurate picture of how Shell Pipeline’s safety record stacks up to comparable operators, our analysis focuses exclusively on PHMSA’s hazardous liquids pipeline data. We also expanded our analysis to look at incidents dating back to 2002.
Shell’s Incident Record
In total, PHMSA data show that Shell was responsible for 194 pipeline incidents since 2002. These incidents spilled 59,290 barrels of petrochemical products totaling some $183-million in damages. The below map locates where most of these incidents occurred. Unfortunately, 34 incidents have no location data and so are not visible on the map. The map also shows the location of Shell’s many refineries, transport terminals, and off-shore drilling platforms.
Open the map fullscreen to see more details and tools for exploring the data.
PHMSA’s hazardous liquid pipeline data account for more than 350 known pipeline operators. Some operators are fairly small, only maintaining a few miles of pipeline. Others are hard to track subsidiaries of larger companies. However, the big players stand out from the pack — some 20 operators account for more than 60% of all pipeline miles in the U.S., and Shell Pipeline is one of these 20.
Comparing Shell Pipeline to other major operators carrying HVLs, we found that Shell ranks 2nd in the nation in the most incidents-per-mile of maintained pipeline, seen in table 1 below. These numbers are based on the total incidents since 2002 divided by the number of miles maintained by each operator as of 2016 miles. Table 2 breaks Shell’s incidents down by year and number of miles maintained for each of those years.
Table 1: U.S. Pipeline operators ranked by incidents-per-mile
Operator
HVL Incidents
HVL Pipeline Miles
Incidents Per Mile (2016)
Kinder Morgan
387
3,370
0.115
Shell Pipeline
194
3,490
0.056
Chevron
124
2,380
0.051
Sunoco Pipeline
352
6,459
0.049
ExxonMobile
240
5,090
0.048
Colonial Pipeline
244
5,600
0.044
Enbride
258
6,490
0.04
Buckeye Pipeline
231
7,542
0.031
Magellan Pipeline
376
12,928
0.03
Marathan Pipeline
162
5,755
0.029
Table 2: Shell incidents and maintained pipeline miles by year
Year
Incidents
Pipeline Miles
Total Damage
Notes
2002
15
no PHMSA data
$2,173,704
2003
20
no PHMSA data
$3,233,530
2004
25
5,189
$40,344,002
Hurricane Ivan
2005
22
4,830
$62,528,595
Hurricane Katrina & Rita
2006
10
4,967
$11,561,936
2007
5
4,889
$2,217,354
2008
12
5,076
$1,543,288
2009
15
5,063
$11,349,052
2010
9
4,888
$3,401,975
2011
6
4,904
$2,754,750
2012
12
4,503
$17,268,235
2013
4
3,838
$10,058,625
2014
11
3,774
$3,852,006
2015
12
3,630
$4,061,340
2016
6
3,490
$6,875,000
2017
9
no PHMSA data
$242,800
2018
1
no PHMSA data
$47,000
As of 3/1/18
Cause & Location of Failure
What were the causes of Shell’s pipeline incidents? At Shell’s public informational session, it was said that “in the industry, we know that the biggest issue with pipeline accidents is third party problems – when someone, not us, hits the pipeline.” However, PHMSA data reveal that most of Shell’s incidents issues should have been under the company’s control. For instance, 66% (128) of incidents were due to equipment failure, corrosion, welding failure, structural issues, or incorrect operations (Table 3).
Table 3. Shell Pipeline incidents by cause of failure
Cause
Incidents
Equipment Failure
51
Corrosion
37
Natural Forces
35
Incorrect Operation
25
Other
20
Material and/or Weld Failure
15
Excavation Damage
11
Total
194
However, not all of these incidents occurred at one of Shell’s petrochemical facilities. As Table 4 below illustrates, at least 57 incidents occurred somewhere along the pipeline’s right-of-way through public areas or migrated off Shell’s property to impact public spaces. These numbers may be higher as 47 incidents have no mention of the property where incidents occurred.
Table 4. Shell Pipeline incidents by location of failure
Location
Incidents
Contained on Operator Property
88
Pipeline Right-of-Way
54
Unknwon
47
Originated on Operator Property, Migrated off Property
3
Contained on Operator-Controlled Right-of-Way
2
Total
194
On several occasions, Shell has claimed that the Falcon will be safely “unseen and out of mind” beneath at least 4ft of ground cover. However, even when this standard is exceeded, PHMSA data revealed that at least a third of Shell’s incidents occurred beneath 4ft or more of soil.
Many of the aboveground incidents occurred at sites like pumping stations and shut-off valves. For instance, a 2016 ethylene spill in Louisiana was caused by lightning striking a pumping station, leading to pump failure and an eventual fire. In numerous incidents, valves failed due to water seeping into systems from frozen pipes, or large rain events overflowing facility sump pumps. Table 5 below breaks these incidents down by the kind of commodity involved in each case.
Table 5. Shell Pipeline incidents by commodity spill volumes
Commodity
Barrels
Crude Oil
51,743
Highly Volatile Liquids
6,066
Gas/Diesel/Fuel
1,156
Petroleum Products
325
Total
59,290
Impacts & Costs
None of Shell’s incidents resulted in fatalities, injuries, or major explosions. However, there is evidence of significant environmental and community impacts. Of 150 incidents that included such data, 76 resulted in soil contamination and 38 resulted in water contamination issues. Furthermore, 78 incidents occurred in high consequence areas (HCAs)—locations along the pipeline that were identified during construction as having sensitive environmental habitats, drinking water resources, or densely populated areas.
Table 6 below shows the costs of the 194 incidents. These numbers are somewhat deceiving as the “Public (other)” category includes such things as inspections, environmental cleanup, and disposal of contaminated soil. Thus, the costs incurred by private citizens and public services totaled more than $80-million.
Table 6. Costs of damage from Shell Pipeline incidents
Private Property
Emergency Response
Environmental Cleanup
Public (other)
Damage to Operator
Total Cost
$266,575
$62,134,861
$11,024,900
$7,308,000
$102,778,856
$183,513,192
A number of significant incidents are worth mention. For instance, in 2013, a Shell pipeline rupture led to as much as 30,000 gallons of crude oil spilling into a waterway near Houston, Texas, that connects to the Gulf of Mexico. Shell’s initial position was that no rupture or spill had occurred, but this was later found not to be the case after investigations by the U.S. Coast Guard. The image at the top of this page depicts Shell’s cleanup efforts in the waterway.
Another incident found that a Shell crude oil pipeline ruptured twice in less than a year in the San Joaquin Valley, CA. Investigations found that the ruptures were due to “fatigue cracks” that led to 60,000 gallons of oil spilling into grasslands, resulting in more than $6 million in environmental damage and emergency response costs. Concerns raised by the State Fire Marshal’s Pipeline Safety Division following the second spill in 2016 forced Shell to replace a 12-mile stretch of the problematic pipeline, as seen in the image above.
Conclusion
These findings suggest that while Shell is obligated to stress safety to sell the Falcon pipeline to the public, people should take Shell’s “good neighbor” narrative with a degree of skepticism. The numbers presented by PHMSA’s pipeline incident data significantly undermine Shell’s claim of having a proven track record as a safe and responsible operator. In fact, Shell ranks near the top of all US operators for incidents per HVL pipeline mile maintained, as well as damage totals.
There are inherent gaps in our analysis based on data inadequacies worth noting. Incidents dealt with at the state level may not make their way into PHMSA’s data, nor would problems that are not voluntary reported by pipeline operators. Issues similar to what the state of Pennsylvania has experienced with Sunoco Pipeline’s Mariner East 2, where horizontal drilling mishaps have contaminated dozens of streams and private drinking water wells, would likely not be reflected in PHMSA’s data unless those incidents resulted in federal interventions.
Based on the available data, however, most of Shell’s pipelines support one of the company’s many refining and storage facilities, primarily located in California and the Gulf states of Texas and Louisiana. Unsurprisingly, these areas are also where we see dense clusters of pipeline incidents attributed to Shell. In addition, many of Shell’s incidents appear to be the result of inadequate maintenance and improper operations, and less so due to factors beyond their control.
As Shell’s footprint in the Appalachian region expands, their safety history suggests we could see the same proliferation of pipeline incidents in this area over time, as well.
NOTE: This article was amended on 4/9/18 to include table 2.
By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance
California’s 2nd Largest Waste Stream
Every year the oil and gas industry in California generates billions of gallons of wastewater, also known as produced water. According to a study by the California Council on Science and Technology, in 2013, more than 3 billion barrels of produced water were extracted along with some 0.2 billion barrels of oil across the state. This wastewater is usually contaminated with a mixture of heavy metals, hydrocarbons, naturally occurring radioactive materials, and high levels of salts. Yet, contaminated wastewater from oil-field operations is exempt from the hazardous waste regulations enforced by the Resource Conservation and Recovery Act (RCRA).
Operators are, therefore, not required to measure or report the chemistry of this wastewater. Even with these unknowns, it is legally re-injected back into groundwater aquifers for disposal. Once an aquifer is contaminated it can be extremely difficult, if not impossible, to clean up again. Particularly in California, where water resources are already stretched thin, underground injection of oil and gas wastewater is a major environmental and economic concern.
The California department responsible for managing these aquifer exemption permits – the Division of Oil, Gas, and Geothermal Resources (DOGGR) – has for decades failed in its regulatory capacity. In 2015, for example, DOGGR admitted that at least 2,553 wells had been permitted to inject oil and gas waste into non-exempt aquifers – aquifers that could be used for drinking water. Independent audits of DOGGR showed decades of poor record-keeping, lax oversight, and in some cases, outright defiance of the law – showing the cozy relationship between regulators and the oil and gas industry. While 176 wells (those that were injecting into the cleanest drinking water) were initially shut down, most of the rest of the 2,377 permits were allowed to continue injecting into disputed wells through the following two years of the regulatory process.
The injection wells targeted by the Environmental Protection Agency (EPA), including those that were shut down, are shown in the map below (Figure 1).
Figure 1. Map of EPA-targeted Class II Injection Wells
The timeline of all this is just as concerning. The State of California has known about these problems since 2011, when the EPA audited California’s underground injection program and identified substantial deficiencies in its program, including failure to protect some potential underground sources of drinking water, a one-size-fits-all geologic review, and inadequate and under-qualified staffing for carrying out inspections. In 2014, the Governor’s office requested that the California EPA perform an independent review of the program. EPA subsequently made a specific remediation plan and timeline for DOGGR, and in March of 2015 the State finalized a Corrective Action Plan, to be completed by February 2017.
Scientific Review of CA Oil and Gas Activities
Meanwhile, in 2013, the California Senate passed SB-4, which set a framework for regulating hydraulic fracturing in California. Part of the bill required an independent scientific study to be conducted on oil and gas well stimulation, including acid well stimulation and hydraulic fracturing. The California Council on Science and Technology organized and led the study, in collaboration with the Lawrence Berkeley National Laboratories, which combined original technical data analyses and a review of relevant literature, all of which was extensively peer-reviewed. The report argues that both direct and indirect impacts of fracking must be accounted for, and that major deficiencies and inconsistencies in data remained which made research difficult. They also recommended that DOGGR improve and modernize their record keeping to be more transparent.
Figure 2*. Depths of groundwater total dissolved solids (a common measure of groundwater quality) in five oil fields in the Los Angeles Basin. Blue and aqua colors represent protected groundwater; the heavy black horizontal line indicates the shallowest hydraulically fractured well in each field. In three of the five wells (Inglewood, Whittier, and Wilmington), fracking and wastewater injection takes place directly adjacent to, or within, protected groundwater.
A major component of the SB-4 report covered California’s Class II injection program. Researchers analyzed the depths of groundwater aquifers protected by the Safe Drinking Water Act, and found that injection and hydraulic fracturing activity was occurring within the same or neighboring geological zones as protected drinking water (Figure 2*).
*Reproduced from California Council on Science and Technology: An Independent Scientific Assessment of Well Stimulation in California Vol. 3.
More Exemptions to be Granted
Now, EPA is re-granting exemptions again. Six aquifer exemptions have been granted, and more are on the docket to be considered. In this second time around, it is imperative that regulatory agencies be more diligent in their oversight of this permitting process to protect groundwater resources. At the same time, the 2015 California bill SB 83 mandates the appointment of an independent review panel to evaluate the Underground Injection Control Program and to make recommendations on how to improve the effectiveness of the program. This process is currently in the works and a panel has been assembled, and FracTracker Alliance will be working to provide data, maps and analyses for this panel.
Stay tuned for more to come on which aquifers are being exempted, why, and what steps are being taken to protect groundwater in California.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2018/03/PatSullivan_AP_Fracwater.png400900Kyle Ferrar, MPHhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngKyle Ferrar, MPH2018-03-22 14:43:392021-04-15 15:01:22California regulators need to protect groundwater from oil and gas waste this time around
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.png00Matt Kelso, BAhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngMatt Kelso, BA2018-03-20 16:25:062021-04-15 15:01:23Report: Potential Impacts of Unconventional Oil and Gas on the Delaware River Basin
The Mariner East 2 (ME2) pipeline, currently being built by Sunoco Pipeline (Energy Transfer Partners), is a massive 350-mile long pipeline that, if completed, will carry 275,000 barrels of propane, ethane, butane, and other hydrocarbons per day from the shale gas fields of Western Pennsylvania to a petrochemical export terminal located on the Delaware River.
ME2 has faced numerous challenges from concerned citizens since Sunoco first announced plans for the project in 2014. Fights over taking private property by eminent domain, eyebrow raising permit approvals with known technical deficiencies, as well as nearly a hundred drilling mud spills — inadvertent returns (IRs) — at horizontal directional drilling (HDD) sites have occurred since work began in 2017.
This article and the accompanying map brings us up-to-date on the number, location, and status of ME2’s HDD spills. We also summarize the growing list of violations and settlements related to these events. Finally, we highlight the most recent concerns related to ME2’s construction: sinkholes emerging along the pipeline’s path in karst geological formations.
Map of ME2 Updated HDDs, IRs & Karst
The map below shows an updated visual of ME2’s IRs, as of the DEP’s latest tally on March 1, 2018. Included on this map are HDDs where DEP ordered Sunoco reevaluate construction sites to prevent additional spills. Also identified on this map are locations where Sunoco was ordered to notify landowners in close proximity to certain HDDs prior to additional drilling. Finally, the below map illustrates how sinkholes are not a problem unique to one site of construction but are, in fact, common to many areas along ME2’s route. These topics are discussed in greater depth below.
Open the map full-screen to view additional layers not available in the embedded version below.
HDD IR in Washington County
(image: Observer-Reporter)
Despite these issues, and despite Sunoco being cited for 33 violations, ME2 was allowed to proceed under an August 7th agreement that stated Sunoco must reevaluate their HDD plans to minimize additional spills. These studies were to include re-examining the site’s geology and conducting seismic surveys. Sites for reevaluation were selected based on factors such as proximity water supplies, nearby streams and wetlands, problematic geologic conditions, and if an IR had occurred at that site previously. Of ME2’s 230 HDDs, 64 were ordered for reevaluation — 22 of these were selected due to prior IRs occurring at the site.
The DEP mandated that Sunoco’s reevaluation studies be put out for public comment. A table of which HDD studies are currently out for comment can be found here. DEP’s settlement also required Sunoco to notify landowners in proximity to certain HDDs prior to commencing construction due to elevated risks. Of the 64 HDD sites under review, Sunoco must notify 17 residents within 450ft of an HDD site, and 22 residents within 150ft of other sites. The HDD reevaluation sites are shown on the FracTracker map above. Below is an illustration of one site where Sunoco is required to notify landowners within 450ft.
One issue residents have raised with these notifications is that Sunoco is allowed to offer landowners the option to connect their homes to a water buffalo during drilling as an alternative to using their groundwater well. The catch is that, if their well does become contaminated, they would also waive their right to have Sunoco drill them a new replacement well.
“Egregious Violations”
In January 2018, the DEP again suspended ME2’s construction, this time indefinitely revoking their permits, due to even more IRs. DEP also cited Sunoco for “egregious and willful” permit violations —mainly executing HDDs at sites where they had no permission to do so. The DEP noted of their decision that, “a permit suspension is one of the most significant penalties DEP can levy.”
Nevertheless, Sunoco was again allowed to resume construction on February 8, 2018, after paying a $12.6 million fine. The DEP press release accompanying the decision assured the public that, “Sunoco has demonstrated that it has taken steps to ensure the company will conduct the remaining pipeline construction activities in accordance with the law and permit conditions, and will be allowed to resume.”
A few weeks later, Sunoco ran a full-page advertisement in the Harrisburg Patriot-News, shown above, lauding their safety record. Among other notables, the piece boasts, “State and federal regulators spent more than 100 inspection days during 2017 on the Mariner East project, more inspection days than on any other pipeline in Pennsylvania.” Critics have noted that the inordinate number of inspections are due to the comedy of errors associated with ME2’s construction.
Karst Formations & Sinkholes
Which brings us to the current ME2 debacle. Last week, the PA Public Utility Commission (PUC) ordered a temporary shutdown of Mariner East 1 (ME1), another natural gas liquids pipeline owned by Sunoco/ETP. ME1 was built in the 1930s and its right-of-way is being used for most of ME2’s route across the state. This latest construction setback comes in the wake of numerous sinkholes that emerged beginning in December along Lisa Drive in West Whitehead Township, a suburb of Philadelphia in Chester County.
The most recent of these sinkholes grew into a 20ft-deep, 15ft-wide chasm that exposed portions of ME1 and came within 10ft of a house. It is worth noting that, until only a few days ago, ME1 was an operational 8in pipeline with a potential impact radius (aka “blast zone”) of some 500ft. The PUC ordered that Sunoco must now run a line inspection on ME1 for a mile upstream and a mile downstream from the sinkhole sites along Lisa Drive, seen in the image below. Note the proximity of these sinkholes to Amtrak’s Keystone rail lines (connecting Pittsburgh to Philadelphia), under which ME2 also runs. The Federal Railway Administration only recently learned of the sink holes from a nearby resident.
The Lisa Drive sinkholes are being credited to Sunoco executing an HDD in an area known to have karst geological formations. Sunoco has been ordered by the PUC to conduct more geophysical testing and seismic analyses of the area because of this. Karst is often called the “Swiss cheese” of geology — notorious for caves, sinkholes, and underground rivers. As these geological formations change shape, pipelines can bend and settle over time, ultimately leading to potentially dangerous gas leakages or explosions. For instance, the 2015 Atex-1 pipeline explosion in Follansbee, WV, was ultimately determined by the Pipeline and Hazardous Materials Safety Administration (PHSA) as having been caused by ground settling. That explosion released some 24,000 barrels of ethane, burning more than five acres of surrounding land.
The US Geological Survey (USGS) maintains fairly detailed maps of rock formations for most states, including formations known to have karst. In PA, there are a number of “carbonate” rock families known for karst features and settlement issues: limestone and dolostone, and, to a lesser extent, shale. Meanwhile, the PA Department of Conservation and Natural Resources (DCNR) has maintained a record of karst “features” — sinkholes and surface depressions — documented since 1985. A great explanation of the different types of karst features can be found here.
Underestimating the Risks
What is concerning about the Lisa Drive sinkholes is that Sunoco had supposedly already conducted additional karst geological reviews of the area as part of the August DEP settlement, subsequently ranking a nearby HDD (#PA-CH-0219) as “low risk” for running into karst issues—despite knowing the HDD runs through a karst formation with sinkholes and surface depressions in the area. For the HDD that runs the length of Lisa Drive (#PA-CH-0256), the study rated its risk as “very low.” These two HDDs are shown below, along with the area of ME1 now under structural review.
The likely result of these inaccurate assessments led to two IRs at Lisa Drive, one in October and another in November 0f 2017. DEP’s writeup of these events note that the total volume of drilling muds spilled remains unknown because Sunoco didn’t report the incident. Then, only a month later, sinkholes emerged in the same locations. An image of the November HDD IR is shown below.
It is important to note two additional things of Sunoco’s karst study, an except of which is seen in their map of the West Whiteland area below. First, Lisa Drive is just on the edge of a karst limestone formation. USGS data suggest the location is actually mica schist, but the USGS data is also only a rough estimate of different formations. This underscores why pipeline companies must be required to conduct detailed geotechnical analysis of all HDD sites at the onset of their projects.
The other notable aspect of Sunoco’s study is that it does not fully represent all rock formations known to have karst features. In Sunoco’s map, we see orange shading for limestone, but this does not include dolostone that underlies the many surface depressions and sinkholes surrounding West Whiteland. FracTracker’s map includes these formations for greater accuracy.
Interestingly, as Anya Litvak of the Pittsburgh Post-Gazette observed in her reporting on the Lisa Drive incident, Sunoco’s updated karst assessment ranked the entire route of the ME2 pipeline through the state as “low to very low” risk for potential issues. Furthermore, Sunoco has tried to downplay the Lisa Drive incident, stating that “all areas have been secured,” and that additional incidents are unlikely to occur.
But the overall relationship between Mariner East 2’s IRs, HDD sites, and known karst features tells a very different story than Sunoco’s about the potential risks of ME2. In addition to the concerns about new sinkholes near Lisa Drive, FracTracker found the following in our analysis:
7 sinkholes and 386 surface depressions are within 1,500ft of a ME2 HDD site.
Of the 230 HDDs, 87 are located in carbonate rock areas (52 in limestone/dolostone, 35 in shale).
Of the 99 IRs, 39 have occurred in carbonate rock areas (23 in limestone/dolostone, 16 in shale).
In other words, nearly half of the IRs caused by ME2 HDDs were located in areas known to have karst formations. Worth noting is that an additional 15 occurred in sandstone formations, also known to cause settlement over time. The remaining IRs are split across nine other formation types.
Considering that the DEP’s current review of Sunoco’s ability to safely execute future HDDs are based on the same karst study that missed the Lisa Drive HDD and ranked nearby HDDs as a “low” risk, one can only assume that additional spills will occur. There are many more HDD sites yet to be drilled, and also not likely studied fully for potential karst risks. As illustrated by the continuing saga of spills, violations, and omissions, it is clear that Sunoco has not maintained a high standard of construction in building ME2 from the onset.
We thank Eric Friedman from the Middletown Coalition for Community Safety for supplying photos of the Lisa Drive site used in this article.
By Kirk Jalbert, FracTracker Alliance
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2018/03/ME2_sinkholes_header.jpg400900FracTracker Alliancehttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngFracTracker Alliance2018-03-12 21:06:462021-04-15 15:01:23Mariner East 2: More Spills & Sinkholes Too?
On February 15, 2018, officials evacuated residents after XTO Energy’s Schnegg gas well near Captina Creek exploded in the Powhatan Point area of Belmont County, Ohio. More than two weeks later, the well’s subsequent blowout has yet to be capped, and people want to know why. Here is what we know based on various reports, our Ohio oil and gas map, and our own fly-by on March 5th.
March 19th Update: This is footage of the Powhatan Point XTO Well Pad Explosion Footage from Ohio State Highway Patrol’s helicopter camera the day after the incident:
Powhatan Point XTO well pad explosion footage from Ohio State Highway Patrol
Cause of the Explosion
The well pad hosts three wells, one large Utica formation well, and two smaller ones. XTO’s representative stated that the large Utica well was being brought into production when the explosion occurred. The shut-off valves for the other two wells were immediately triggered, but the explosion caused a crane to fall on one of those wells. The representative claims that no gas escaped that well or the unaffected well.
Observers reported hearing a natural gas hiss and rumbling, as well as seeing smoke. The Powhatan Point Fire Chief reported that originally there was no fire, but that one later developed on the well pad. To make matters worse, reports later indicated that responders are/were dealing with emergency flooding on site, as well.
As of today, the Utica well that initially exploded is still releasing raw gas.
Map of drilling operations in southeast Ohio, with the Feb 15, 2018 explosion on XTO Energy’s Schnegg gas well pad marked with a star. View dynamic map
Public Health and Safety
No injuries were reported after the incident. First responders from all over the country are said to have been called in, though the mitigation team is not allowed to work at night for safety reasons.
The evacuation zone is for any non-responders within a 1-mile radius of the site, which is located on Cat’s Run Road near State Route 148. Thirty (30) homes were originally evacuated within the 1-mile zone according to news reports, but recently residents within the outer half-mile of the zone were cleared to return – though some have elected to stay away until the issue is resolved completely. As of March 1, four homes within ½ mile of the well pad remain off limits.
The EPA conducted a number of site assessments right after the incident, including air and water monitoring. See here and here for their initial reports from February 17th and 20th, respectively. (Many thanks to the Ohio Environmental Council for sharing those documents.)
Much of the site’s damaged equipment has been removed. Access roads to the pad have been reinforced. A bridge was recently delivered to be installed over Cats Run Creek, so as to create an additional entrance and exit from the site, speaking to the challenges faced in drilling in rural areas. A portion of the crane that fell on the adjacent wellhead has been removed, and workers are continuing their efforts in removing the rest of the crane.
The above video by Earthworks is optical gas imaging that makes visible what is normally invisible pollution from XTO’s Powhatan Point well disaster. The video was taken on March 3, 2018, almost 3 weeks after the accident that started the uncontrolled release. Learn more about Earthworks’ video and what FLIR videos show.
An early estimate for the rate of raw gas being released from this well is 100 million cubic feet/day – more than the daily rate of the infamous Aliso Canyon natural gas leak in 2015/16. Unfortunately, little public information has been provided about why the well has yet to be capped or how much gas has been released to date.
Bird’s Eye View
On February 26, a two-mile Temporary Flight Restriction (TFR) was enacted around the incident’s location. The TFR was supposed to lapse during the afternoon of March 5, however, due to complications at the site the TFR was extended to the evening of March 8. On March 5, we did a flyover outside of the temporary flight restriction zone, where we managed to capture a photo of the ongoing release through a valley cut. Many thanks to LightHawk and pilot Dave Warner for the lift.
XTO Energy well site and ongoing emissions after the explosion over two weeks ago. Many are still waiting on answers as to why the well has yet to be capped. Photo by Ted Auch, FracTracker Alliance, March 5, 2018. Aerial support provided by LightHawk
Additional resources
Per the Wheeling Intelligencer – Any local residents who may have been impacted by this incident are encouraged to call XTO’s claims phone number at 855-351-6573 or visit XTO’s community response command center at the Powhatan Point Volunteer Fire Department, located at 104 Mellott St. or call the fire department at 740-312-5058.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2018/03/XTO-Incident-Feature.jpg400900FracTracker Alliancehttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngFracTracker Alliance2018-03-06 15:53:362021-04-15 15:01:25Waiting on Answers Weeks after a Well Explosion in Belmont County Ohio
Water is the key ingredient in the hydraulic fracturing process, and its usage – in total and per well – is increasing at an exponential rate. Below, FracTracker takes a look at water withdrawal and use for fracking across 23 Eastern Ohio counties between 2010 and 2016.
Mapping Hydraulic Fracturing Freshwater Supply and Demand in Ohio
Below is a map of annual and cumulative water withdrawal volumes by the hydraulic fracturing industry across Ohio between 2010 and 2016. It displays 312 unique sites, as well as water usage per lateral. The digital map, which can be expanded fullscreen for more features, includes data up until May 2017 for 1,480 Ohio laterals (vertical wells can host more than one lateral well).
The primary take-home message from this analysis and the resulting map is that we can only account for approximately 73% of the industry’s more than 13-billion-gallon freshwater demand by considering withdrawals alone. Another source or sources must be supplying water for these hydraulic fracturing operations.
Hydraulic fracturing rig on the banks of the Ohio River in Marshall County, West Virginia, Winter 2018 (Flight provided by SouthWings)
When Leatra Harper at Freshwater Accountability Project and Thriving Earth Exchange and I brought up this issue with Ohio Division of Water Resources Water Inventory and Planning Program Manager, Michael Hallfrisch, the following correspondence took place on January 24, 2018:
Mr. Hallfrisch: “Where did the water usage per lateral data come from? Does the water usage include reused/recycled water? I know that many of the larger operators reuse a significant amount of their flow back because of the high cost of disposal in class II injection wells.”
FracTracker: “[We’]ve been looking at Class II disposal economics in several states and frankly the costs here in Ohio are quite cheap and many of the same players in Ohio operate in the other states [We]’ve looked at. Granted they usually own their own Class II wells in those other states (i.e., OK, or CO) but the fact that they are “vertically integrated” still doesn’t excuse the fact that the cost of disposing of waste in Ohio is dirt cheap. As for recycling that % was always a rounding error and last [we] checked the data it was going down by about 0.25-0.35% per year from an average of about 5.5-8.0%. [We respectfully] doubt the recycling % would fill this 25% gap in where water is coming from. This gap lends credence to what Lea and [FracTracker] hear time and again in counties like Belmont, Monroe, Noble etc with people telling us about frequent trenches being dug in 1st and 2nd order streams with operators topping off their demands in undocumented ways/means. Apologies for coming down hard on this thing but we’ve been looking/mapping this thing since 2012 and increasingly frustrated with the gap in our basic understanding of flows/stocks of freshwater and waste cycling within Ohio and coming into the state from PA and WV.”
The fracking industry in Ohio uses roughly 10-14 million gallons per well, up from 4-5 million gallon demands in 2010, which means that freshwater demand for this industry is increasing 15% per year (Figures 1 and 2). (This rate is more than double the volumes cited in a recent publication by the American Chemical Society, by the way.) If such exponential growth in hydraulic fracturing’s freshwater demand in Appalachia continues, by 2022 each well in Ohio and West Virginia will likely require[1*]at least 43 million gallons of freshwater (Table 1).
Table 1. Projected annual average freshwater demand per well (gallons) for the hydraulic fracturing industry in Ohio and West Virginia based on a 15% increase per year.
Year
Water Use Per Well (gallons)
Ohio
West Virginia
2019
19,370,077
19,717,522
2020
23,658,666
23,938,971
2021
28,896,760
29,064,215
2022
35,294,582
35,286,756
2023
43,108,900
42,841,519
Water quantity and associated watershed security issues are both acute and chronic concerns at the local level, where fracking’s freshwater demands equal 14% of residential demands across Ohio. These quantities actually exceed 85% of residential demand in several Ohio counties (e.g., Carroll and Harrison), as well as West Virginia (e.g., Doddridge, Marshall, and Wetzel). Interestingly the dramatic uptick in Ohio freshwater demand that began at the end of 2013 coincides with a 50% decline in the price of oil and gas (Figure 3). The implication here is that as the price of gas and oil drops and/or unproductive wells are drilled at an unacceptable rate, the industry uses more freshwater and sand to ensure acceptable financial returns on investments.
To date, the fracking industry has taken on average 90 million gallons of freshwater per county out of Ohio’s underlying watersheds, resulting in the production of 9.6 million gallons of brine waste that cannot be reintroduced into waterways. This massive waste stream is destined for one of Ohio’s Class II Injection wells, but the industry spends less than 1.25% of available capital on water demand(s) and waste disposal. All of this means that the current incentive (cost) to become more efficient is too low. Sellers of water to the industry like the Muskingum Watershed Conservancy District, which we’ve chronicled frequently in the past[2], have actually dropped their price for every 1,000 gallons of water – from roughly $9 to now just $4-6 – for the fracking industry in recent years.
Hydraulic fracturing’s demand is becoming an increasingly larger component of total water withdrawals in Ohio, as other industries, agriculture, and mining become more efficient. Oil and gas wells drilled at the perimeter of the Utica Shale are utilizing 1.25 to 2.5 times more water than those that are staged in the shale “Sweet Spots.” Furthermore, the rise in permitting of so called “Super Laterals” would render all of our water utilization projections null and void. Laterals are the horizontal wells that extend out underground from the vertical well. Most well pads are home to multiple laterals in the range of 4-7 laterals per pad across Ohio and West Virginia.
These laterals, which can reach up to 21,000 feet or almost 4 miles, demand as much as 87 million gallons of freshwater each.
Even accounting for the fact that the super laterals are 17-21,000 feet in length – vs. an average of 7,452 feet – such water demand would dwarf current demands and their associated pressures on watershed security and/or resilience; typically, Ohio’s hydraulically fractured laterals require 970-1,080 gallons of freshwater per lateral foot (GPLF), but super laterals would need an astounding 4,470 GLPF.
Conclusions and Next Steps
The map above illustrates the acute pressures being put upon watersheds and public water supplies in the name of “energy independence.” Yet, Ohio regulators and county officials aren’t putting any pressure on the high volume hydraulic fracturing (HVHF) industry to use less water and produce less waste. We can’t determine exactly how water demand will change in the future. The problem is not going away, however, especially as climate change results in more volatile year-to-year fluctuations in temperature and precipitation. This means that freshwater that was/is viewed as a surplus “commodity” will become more valuable and hopefully priced accordingly.
Furthermore, the Appalachian Ohio landscape is undergoing dramatic transformations at the hands of the coal and more recently the HVHF industry with strip-mines, cracking plants, cryogenic facilities, compressor stations, gas gathering lines – and more – becoming ubiquitous.
We are seeing significant acreage of deciduous forests, cropland, or pasture that once covered the region replaced with the types of impervious surfaces and/or “clean fill” soil that has come to dominate HVHF landscapes in other states like North Dakota, Texas, and Oklahoma.
This landscape change in concert with climate change will mean that the region will not be able to receive, processes, and store water as effectively as it has in the past.
It is too late to accurately and/or more holistically price the HVHF’s current and past water demand in Ohio, however, such holistic pricing would do wonders for how the industry uses freshwater in the future. After all, for an industry that believes so devotedly in the laws of supply and demand, one would think they could get on board with applying such laws to their #1 resource demand in Appalachia. The water the HVHF industry uses is permanently removed from the hydrological cycle. Now is the time to act to prevent long term impacts on Ohio’s freshwater quantity and quality.
Relevant Data
Ohio hydraulic fracturing lateral freshwater demand by individual well between 2010 and the end of 2016. Download
Ohio hydraulic fracturing lateral freshwater withdrawals by site between 2010 and the end of 2016. Download
Endnotes
*Certainty, with respect to this change in freshwater demand, is in the range of 86-90% assuming the exponential functions we fit to the Ohio and West Virginia data persist for the foreseeable future. Downing, Bob, 2014, “Ohio Drillers’ Growing Use of Fresh Water Concerns Environmental Activists”, March 19th, Akron, Ohio
Downing, Bob, 2014, “Group Reacts to Muskingum Watershed Leasing Deal with Antero”, April 22nd, Akron, Ohio
By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2018/02/Rig-River-Feature.jpg400900Ted Auch, PhDhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngTed Auch, PhD2018-02-28 11:12:392021-04-15 15:01:25Fracking’s Freshwater Supply and Demand in Eastern Ohio
The head of Murray Energy Corporation, Robert Murray, is very close to the highest office in the land. Such an association demands a close look at the landscape from which this corporation and its founder arouse.
Belmont County, Ohio’s most famous tycoon Robert Murray has established a close relationship with the Trump administration. This connection dates back to his $300,000 contribution to Trump’s inauguration. The intimacy of this relationship has been given new weight recently when it was revealed that a hug between Mr. Murray and the Department of Energy’s Secretary Rick Perry preceded a meeting where Mr. Murray presented the administration with a memo outlining a 16-point plan for removing some of the burdensome regulations put in place by Mr. Murray’s least favorite person former President Barack Obama.
Among the few consistent themes from this most inconsistent of presidents has been a fondness for coal and steel, where brawny men do essential work and are threatened not by shifting economics, but by greenies and weenies who want to shut them down. Mr Trump and Mr Murray both want environmental rules rolled back—Mr Murray because it would be good for his bottom line, and Mr Trump because a second consistent aim of his presidency is to reverse anything done by Barack Obama. It is doubtful whether policy shifts alone could revive coal mining, but the attempt to do so says much about how vested interests operate in this administration… Mr Trump played a hard-nosed businessman on TV, but Mr Murray is the real thing. – The Economist, 2018
Not only has Mr. Murray succeeded in capturing the hearts and minds of the Trump administration, he has demanded that his $300,000 contribution get his longtime Oklahoman lawyer, and former aide to the senate’s chief climate skeptic James M. Inhofe of Oklahoma, the #2 spot behind Scott Pruitt at the EPA. Mr. Murray is so powerful that he managed to get Perry & Co. to fire the photographer that took the photo of the tender moment between Messrs. Perry and Murray.
Awkwardness aside, these situations could reasonably lead one to conclude that Perry and Pruitt are competing for Murray’s favor in the event they choose to run for higher office and need a patron with deep pockets. Mr. Murray would be in a real pickle if they both chose to run for the highest office in the land, with two fawning candidates potentially offering to one-up the other in terms of incentives and/or regulatory carve outs for Mr. Murray’s beloved King Coal.
Once the heart of Ohio Coal Country, Belmont Co. is now a major player on the hydraulic fracturing landscape, as well.
Given the growing influence of Mr. Murray and the coal industry writ large we thought it was time to do a deep dive into how Mr. Murray’s Appalachian Ohio home county of Belmont and surrounding counties have been altered by coal mining. We were also interested in how the coal industry has come to interact with the hydraulic fracturing industry, which has drilled 542 Utica wells in Belmont County alone since March 2012. These wells amount to 20% of all fracked wells in Ohio as of January 2018. The rate at which Utica wells are being permitted in Belmont County is actually increasing by about 1.5 to 2 permits per month or 5.5 to 7.8 times the statewide average (Figure 1).
Belmont County also happens to be the “all-time leader in coal production in Ohio” having produced 825 million tons since 1816 (ODNR, 2005). All of this means that the Ohio county that produces the most coal is also now The Buckeye State’s most actively drilled county.
Figure 1. Monthly and cumulative hydraulically fractured wells in Belmont County, Ohio between Q1-2012 and Q1-2018
However, the days of coal’s dominance – and easily mineable coal – in Ohio appear to be coming to an end.
Per mine, Ohio’s mines produce about 30% of the national average and 43% of the state averages (Figure 2). Ohio’s mines only produce about 10% of what the mega Western mines produce on a per-mine basis, and much less than states like New Mexico and Texas, as well.
Even with automation, the barriers to a return of coal in Appalachia are formidable given that most of the easily recoverable coal has already been mined. Additionally, the landscape is more formidable and not as conducive to the large strip-mine and dragline operations of the Powder River Basin, which produce roughly 8.5 million tons of coal per mine, compared to an average of 330,000 tons per mine in Appalachia. (Figure 2).
The below map depicts parcels owned by coal mining companies in the Ohio counties of Belmont, Noble, Guernsey, and Muskingum, as well as previously mined and/or potential parcels based on owner and proximity to existing mines.
We also incorporated production data (2001 to 2016) for 116 surface and strip coal mines in these and surrounding counties, natural gas pipelines, hydraulically fractured laterals, and Class II Salt Water Disposal (SWD) injection wells as of January 2018.
There are few areas in the United States where underground coal mining and fracking are taking place simultaneously and on top of each other. What could possibly go wrong when injecting massive amounts of fracking waste at high pressures into the geology below, while simultaneously pumping billions of gallons of water into hydraulically fractured laterals and mining coal at similar depths?
In the coming months and years we will be monitoring Belmont County, Ohio as an unfortunate case-study in determining the answer to such a unique question.
At the present time:
Murray Energy, its subsidiaries, and other coal companies own approximately 15% of Belmont County.
Coal companies and their associated real-estate firms and subsidiaries have mined or own approximately 5,615 square miles across the Noble, Belmont, Guernsey, and Muskingum counties.
The 116 mines in this map have mined an average of 3.22 million tons of coal since 2001 and more than 373 million tons in total. Mr. Murray’s mines account for 50% of this amount, producing nearly 15 times more coal per mine than the other 112 mines.
Collectively, these mines have contributed 1.09 billion tons of CO2 and CH4+N2O in CO2 equivalents to atmospheric climate change, or 68 million tons per year (MTPY). This volume is equivalent to the annual emissions of nearly 60 million Americans or 19% of the population.
Murray’s mines alone have contributed enough greenhouse gases (CO2+CH4+N2O) to account for the emissions of 9.2% of the US population since 2001. Each Murray mine is belching out 8.41 million tons of greenhouse gases per year or roughly equivalent to the emissions of 463,489 Americans.
Relevant data for this map can be found at the end of this article.
Broader Implications
Robert Murray’s influence and mining impacts extend well beyond Appalachian Ohio.
Mr. Murray’s is the primary owner of 157 mines and associated facilities1 across eleven states – and five of the six major Lower 48 coal provinces – from Utah and North Dakota to Alabama, Georgia, and Florida (Figure 3). Mr. Murray likes to highlight his sage purchases of prime medium and high volatility bituminous coal real-estate over the years on his company’s website. However, nowhere in his corporate overview does he mention his most notorious mine: the abandoned and sealed underground Crandal Canyon Mine, Emery County, Utah. It was at this mine on August 6, 2007 that a collapse trapped six miners and resulted in their deaths, along with the deaths of three rescue workers. Mr. Murray told the BBC that he had had an emotional breakdown and hadn’t deserted anyone living in a little trailer adjacent to the mine’s entrance every day following the collapse. Furthermore, Mr. Murray blames such events on subsidiaries like Grenwal Resources Inc., which happens to be the owner of record for the Crandal Canyon Mine and is one of thirty-three unique subsidiaries owned by Mr. Murray (data download).
Figure 3. US Coal Mines by type and Mines Owned by Robert Murray highlighted in turquoise
Table 1. Robert Murray coal mine ownership by mine status
Status
Number of Mines
Abandoned
68
Abandoned and Sealed
62
Active
12
Non-Producing
10
Temporarily Idled
5
Total
157
The Politics of Energy
Robert Murray and his fellow fossil fuel energy brethren’s bet on Trump paid off, with Trump winning 99% of the vote in congressional districts where coal mines exist (Figure 4). Such a performance bested the previous GOP candidates of McCain and Romney even though they had achieved an impressive 96% of the vote. Interestingly, Trump did nearly as well in congressional districts dominated by wind farms and ethanol refineries where more than 87% of the electorate was white.
Figure 4. Presidential election results for GOP candidates in voting districts where various forms of energy are produced and/or processed, 2016, 2012, and 2008
Trump & Co. promised these districts that his administration would breathe life into the fossil fuel industry. True, Trump, Pruitt, Perry, and Interior Secretary Ryan Zinke are greasing the skids for the industry’s revival. In terms of annual production, however, it is far from certain that such moves will translate into the types of boost in employment promised by Trump during the 2016 campaign. Even if production does return, executives like Murray admit that the advent of efficiencies and extraction technologies means that the industry is mining more coal per miner than ever before:
“Trump has consistently pledged to restore mining jobs, but many of those jobs were lost to technology rather than regulation and to competition from natural gas and renewables, which makes it unlikely that he can do much to significantly grow the number of jobs in the industry,” said Murray. “I suggested that he temper his expectations. Those are my exact words,” said Murray. “He can’t bring them back.” – The Guardian, March 27, 2017
Conclusions and Next Steps
It remains to be seen how the coal mining and fracking industry’s battle for supremacy will play out from a socioeconomic, health, environmental, and regulatory perspective. While many people understand that coal jobs aren’t coming back, we shouldn’t doubt the will of the Trump administration and friends like Robert Murray to make sure that profits can still be extracted from Appalachia.
Will the fracking industry and coal barons agree to get along, or will they wage a war on multiple fronts to marginalize the other side? Will this be another natural resource conflagration? If so, how will the people – and species like the “near-threatened” Hellbender Salamander (Cryptobranchus alleganiensis) or the region’s recovering Bald Eagle (Haliaeetus leucocephalus) population that live in the disputed Appalachian communities respond? How will their already stressed day-to-day existence be affected? To this point, the fossil fuel industry has managed to blame everyone but itself for the tepid to non-existent job growth in their sectors.
The Appalachian landscape has been deeply scarred and fragmented by coal mining, and now it is experiencing a new colonizing force in the form of the hydraulic fracturing industry. When Appalachia realizes that automation, globalization, and natural gas, are the key drivers to the downfall of coal, will they bring fire, brimstone, and pitchforks to the doorstep of Murray Energy of the fracking companies? Or is Appalachia’s future merely that of an extraction colony?
FracTracker Alliance has been mapping the impacts of unconventional oil and gas (O&G) drilling activity in Pennsylvania since 2010, and the Pennsylvania Shale Viewer is our most complete map to show the impacts of the industry.
While it can rightly be said that the development of the Marcellus Shale and other unconventional formations have affected half the state since 2005, this analysis takes a look at high impact areas, as well as a closer look at areas that have been avoided so far.
By Matt Kelso, Manager of Data and Technology, FracTracker Alliance
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2018/01/HighImpactAreas-PA-Feature.jpg400900Matt Kelso, BAhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngMatt Kelso, BA2018-02-05 11:47:352021-04-15 15:01:28High Impact Areas and Donut Holes – A Look at Unconventional O&G Activity in PA
The City of Arvin, with a population of about 20,000, is located in Kern County, California just 15 miles southeast of Bakersfield. Nicknamed ‘The Garden in the Sun,’ Arvin is moving forward with establishing new regulations that would limit oil and gas development within the city limits.
Setback Map
The new ordinance proposes setback distances for sensitive sites including hospitals and schools, as well as residentially and commercially zoned parcels. The proposal establishes a 300-foot buffer for new development and 600’ for new operations.
In the map below, FracTracker Alliance has mapped out the zoning districts in Arvin and mapped the reach of the buffers around those districts. The areas where oil and gas well permits will be blocked by the ordinance are shown in green, labeled “Buffered Protected Zones.” The “Unprotected Zones” will still allow oil and gas permits for new development.
There are currently 13 producing oil and gas wells within the city limits of Arvin, 11 of them are located in the protected zones. Those within the protected zones are operated by Sun Mountain Oil and Gas and Petro Capital Resources. They were all drilled prior to 1980, and are shown in the map below.
Information on the public hearings and proposals can be found in the Arvin city website, where the city posts public notices. As of January 24, 2018, these are the current documents related to the proposed ordinance that you will find on the webpage:
In December of 2016, Committee for a Better Arvin, Committee for a Better Shafter, and Greenfield Walking Group, represented by Center for Race, Poverty and the Environment, sued Kern County. The lawsuit was filed in coordination with EarthJustice, Sierra Club, Natural Resources Defense Council, and the Center for Biological Diversity.
The Importance of Local Rule
Self-determination by local rule is fundamental of United States democracy, but is often derailed by corporate industry interests by the way of state pre-emption. There is a general understanding that local governments are able to institute policies that protect the interests of their constituents, as long as they do not conflict with the laws of the state or federal government. Typically, local municipalities are able to pass laws that are more constrictive than regional, state, and the federal government.
Unfortunately, when it comes to environmental health regulations, states commonly institute policies that preserve the rights of extractive industries to access mineral resources. In such cases, the state law “pre-empts” the ability of local municipalities to regulate. Local laws can be considered the mandate of the people, rather than the influence of outside interest on representatives. Therefore, when it comes to land use and issues of environmental health, local self-determination must be preserved so that communities are empowered in their decision making to best protect the health of their citizens.
https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2018/01/Arvin_bakersfield_re.jpg400900Kyle Ferrar, MPHhttps://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2021/04/2021-FracTracker-logo-horizontal.pngKyle Ferrar, MPH2018-01-30 11:59:072021-04-15 15:01:28Arvin, CA – a City in the Most Drilled County in the Country – files for a Setback Ordinance
