The majority of FracTracker’s posts are generally considered articles. These may include analysis around data, embedded maps, summaries of partner collaborations, highlights of a publication or project, guest posts, etc.

Wastewater Disposal Facility in Colorado
Kyle Ferrar, MPH

Groundwater Threats in Colorado

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

Introduction

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

Groundwater Threats

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

Waste Management

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

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

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

Figure 1. Interactive map of groundwater threats in Colorado


View Map Fullscreen | How Our Maps Work

Injection Wells

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

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

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

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

Why the concern?

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

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

The State of CO Injection Wells

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

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

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

Class II Injection Wells

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

Where is the waste going?

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

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

Centralized Exploration and Production Waste Management Facilities

Photo by COGCC

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

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

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

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

Linnoilypit

Figure 3. Linn energy oily wastewater disposal pit

Production and Injection Volumes

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

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

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

CO wastewater Volumes by year

Figure 4. Colorado wastewater volumes by year (barrels)

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

Figures 5-6

Figure 4. Colorado gas produced by year (MCF)
Figure 4. Colorado gas produced by year (MCF)
Figure 5. Colorado oil produced by year (barrels)
Figure 5. Colorado oil produced by year (barrels)

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

How Counties Compare

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

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

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

Aquifer Exemptions

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

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

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

Sources of Water

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

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

Fresh Water Use

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

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

Other Water Sources

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

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

Conclusions

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

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

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

Cover photo by COGCC

Energy-related story maps
Karen Edelstein

Energy-Related Story Maps for Grades 6-10

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Over the past half year, FracTracker staffer Karen Edelstein has been working with a New York State middle school teacher, Laurie Van Vleet, to develop a series of interdisciplinary, multimedia story maps addressing energy issues. The project is titled “Energy Decisions: Problem-Based Learning for Enhancing Student Motivation and Critical Thinking in Middle and High School Science.” It uses a combination of interactive maps generated by FracTracker, as well as websites, dynamic graphics, and video clips that challenge students to become both more informed about energy issues and climate change and more critical consumers of science media.

Edelstein and VanVleet have designed energy-related story maps on a range of topics. They are targeted at 6th through 8th grade general science, and also earth science students in the 8th and 10th grades. Story map modules include between 10 and 20 pages in the story map. Each module also includes additional student resources and worksheets for students that help direct their learning routes through the story maps. Topics range from a basic introduction to energy use, fossil fuels, renewable energy options, and climate change.

The modules are keyed to the New York State Intermediate Level Science Standards. VanVleet is partnering with Ithaca College-based Project Look Sharp in the development of materials that support media literacy and critical thinking in the classroom.

Explore each of the energy-related story maps using the links below:

Energy-related story maps

Screenshot from Energy Basics story map – Click to explore the live story map

This unique partnership between FracTracker, Project Look Sharp, and the Ithaca City School District received generous support from IPEI, the Ithaca Public Education Imitative. VanVleet will be piloting the materials this fall at Dewitt and Boynton Middle Schools in Ithaca, NY. After evaluating responses to the materials, they will be promoted throughout the district and beyond.

Zoning in SW PA map
Guest Author

Oil & Gas Zoning in Southwestern Pennsylvania

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Read more
Starved Rock State Park by Michelle McCray
Guest Author

How Frac Sand Mining is Altering an Economy Dependent on Starved Rock State Park, IL

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An Ottawa, IL resident’s letter to U.S. Silica regarding how the firm’s “frac” sand mines adjacent to Starved Rock State Park will alter the local economy.

Starved Rock State Park

As is so often the case, we find that those things we have taken most for granted are usually the things we miss most when they are gone. The list of what our nation has lost to industrial and commercial concerns couldn’t possibly be compiled in a single article. The short-sighted habits of economic progress have often led to long-term loss and ecologic disaster. That is why it took a man like Abraham Lincoln, a man of long-term vision and wisdom, to sign into existence our first national park, preserving for antiquity what surely would have been lost to our American penchant for development and overuse.

With that in mind, I have always found it amazing how the gears of our own local and state governments have continually chosen the economic path of least resistance and allowed the areas surrounding Starved Rock State Park to be ravaged and destroyed for what is, ultimately, minimal gain. I am no expert but I suspect it could be argued that a full 1/3 of LaSalle County’s economic engine is funded by the simple existence of Starved Rock State Park. Beyond the 2 million plus visitors to the park each year, it cannot be forgotten that nearly every municipality in LaSalle County has directly or indirectly benefited from the countless number of businesses that prosper from the magnetism of the park’s tranquil canyons.

Photos by Michelle McCray of McCray Photography.

Preservation Not Development

As the 4-year battle with Mississippi Sand over development of the Ernat property has proved, there are many rational souls who truly acknowledge the importance of maintaining a healthy and productive park environment. With the recent sale of the Ernat property to U.S. Silica, we are again confronted with the prospect of irrational development of the eastern boundaries of Starved Rock State Park.

Given the gravity of these decisions, I would like to share a letter recently sent on behalf of many of those who have fought so hard and so long for preservation of that same eastern boundary. This letter was sent to Brian Shinn, CEO of U.S. Silica Holdings, INC. (SLCA) in Frederick, Maryland nearly a month ago, and we have yet to receive a response. In sharing this information on FracTracker’s website, I hope this letter will contribute to further discussion among our local representatives over a far more long-term vision of what LaSalle County wishes to be and what qualities, both environmental and economic, that it wishes to maintain and protect:

Letter to US Silica

Dear Mr. Shinn,

I am writing this letter on behalf of dozens of LaSalle County, Illinois residents who have, for the past several years, been intimately involved in the active pursuit of rational use and conservation of our local natural environment. As I am sure you are aware, the debate over use of the Ernat property as a functional sand mining operation has been a long and hard-fought battle. Years of litigation by the Sierra Club and other local environmental groups helped stall it’s development by Mississippi Sand, and have now led to the sale of the Ernat acreage to U.S. Silica. As irrational as the previous proposals were, the sale putting that acreage under your control has not lessened our concerns over the damaging use of that property as it relates to historic Highway 71 and the entire Starved Rock State Park area.

Obviously, sand mining operations have been a long-standing component of LaSalle County economics. Decades of mining under U.S. Silica supervision have not substantially reduced the quality of life for county residents or the natural environment as a whole. However, as can be specified by many local experts, the development and spoilage of the Ernat property will most certainly have longstanding and drastic impacts on both the ecology of Starved Rock State Park and the economic engine that it sustains. Starved Rock State Park attracts over 2 million visitors each year, with an estimated half million visitors using the Hwy. 71 entrance paralleling the Ernat farm as their main gateway into the park. The Ernat property’s river frontage has long been the tranquil eastern entry into the Illinois Canyon area, as well as an active nesting site for countless birds amidst bountiful wetlands and flat, open prairies. The Ernat property’s shared access to Horseshoe Creek has also made it essential to the entire Illinois Canyon ecosystem within the park. In short, any development of this property will most certainly have long-term negative impacts on both the economics and ecology of the Illinois River Basin.

In writing this letter, we are hoping that U.S. Silica, under your guidance, may consider the opportunity to preserve this indispensable parcel of land and examine ways in which U.S. Silica might make this land available as a gift or negotiated property to the state of Illinois. It would certainly be an important addition to the entire Starved Rock State Park area. I have included the signatures of many of our own local coalition. We hope you will consider the long-term impacts that this development would have to one of Illinois premier natural areas. Thank you.

Inspiring Action

I hope those who have signed this letter will be inspired to further action, and those who have not will reconsider their years of inaction. The natural heritage and local economies of our entire Illinois River Basin are depending on it.

Sincerely,

Paul Wheeler

Only when the last tree has died…
and the last river been poisoned…
and the last fish been caught…
will we realize we cannot eat money.

Sand Mining Photos

For additional photos from Illinois, explore our online photo album.

Unimin’s North Utica Frac Sand Mine Active Mine Block

Mr. Wheeler grew up in Oak Lawn, IL and now lives with his wife and daughter in the Ottawa, IL area and is a para-educator.

Feature image by Michelle McCray of McCray Photography.

The BP Whiting, IN Oil Refinery
Ted Auch, PhD

US Oil Refineries and Economic Justice

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How annual incomes in the shadow of oil refineries compare to state and regional prosperity

North American Oil Refinery Capacity (Barrels Per Day (BPD))

Figure 1. North American Oil Refinery Capacity

Typically, we analyze the potential economic impacts of oil refineries by simply quantifying potential and/or actual capacity on an annual or daily basis. Using this method, we find that the 126 refineries operating in the U.S. produce an average of 100,000-133,645 barrels per day (BPD) of oil – or 258 billion gallons per year.

In all of North America, there are 158 refineries. When you include the 21 and 27 billion gallons per year produced by our neighbors to the south and north, respectively, North American refineries account for 23-24% of the global refining capacity. That is, of course, if you believe the $113 dollar International Energy Agency’s 2016 “Medium-Term Oil Market Report” 4.03 billion gallon annual estimates (Table 1 and Figure 1).

Table 1. Oil Refinery Capacity in the United States and Canada (Barrels Per Day (BPD))

United States Canada Mexico Total
Refinery Count 126 17 6 158
Average Capacity 133,645 BPD 104,471 BPD 228,417 BPD 139,619 BPD
Low Foreland & Silver Eagle Refining in NV & WY, 2-3K BPD Prince George & Moose Jaw Refining in BC and SK, 12-15K BPD Pemex’s Ciudad Madero Refinery, 152K BPD —
High Exxon Mobil in TX & LA, 502-560K BPD Valero and Irving Oil Refining in QC & NS, 265-300K BPD Pemex’s Tula Refinery, 340K BPD —
Median 100,000 BPD 85,000 BPD 226,500 109,000
Total Capacity 16.8 MBPD 1.8 MBPD 1.4 MBPD 22.1 MBPD

Census Tract Income Disparities

However, we would propose that an alternative measure of a given oil refinery’s impact would be neighborhood prosperity in the census tract(s) where the refinery is located. We believe this figure serves as a proxy for economic justice. As such, we recently used the above refinery location and capacity data in combination with US Census Bureau Cartographic Boundaries (i.e., Census Tracts) and the Census’ American FactFinder clearinghouse to estimate neighborhood prosperity near refineries.

Methods

Our analysis involved merging oil refineries to their respective census tracts in ArcMAP 10.2, along with all census tracts that touch the actual census tract where the refineries are located, and calling that collection the oil refinery’s sphere of influence, for lack of a better term. We then assigned Mean Income in the Past 12 Months (In 2014 Inflation-Adjusted Dollars) values for each census tract to the aforementioned refinery tracts – as well as surrounding regional, city, and state tracts – to allow for a comparison of income disparities. We chose to analyze mean income instead of other variables such as educational attainment, unemployment, or poverty percentages because it largely encapsulates these economic indicators.

As the authors of the UN’s International Forum of Social Development paper Social Justice in an Open World wrote:

In today’s world, the enormous gap in the distribution of wealth, income and public benefits is growing ever wider, reflecting a general trend that is morally unfair, politically unwise and economically unsound… excessive income inequality restricts social mobility and leads to social segmentation and eventually social breakdown…In the modern context, those concerned with social justice see the general  increase  in  income  inequality  as  unjust,  deplorable  and  alarming.  It is argued that poverty reduction and overall improvements in the standard of living are attainable goals that would bring the world closer to social justice.

Environmental regulatory agencies like to separate air pollution sources into point and non-point sources. Point sources are “single, identifiable” sources, whereas non-point are more ‘diffuse’ resulting in impacts spread out over a larger geographical area. We would equate oil refineries to point sources of socioeconomic and/or environmental injustice. The non-point analysis would be far more difficult to model given the difficulties associated with converting perceived quality of life disturbance(s) associated with infrastructure like compressor stations from the anecdotal to the empirical.

Results

Primarily, residents living in the shadow of 80% of our refineries earn nearly $16,000 less than those in the surrounding region – or, in the case of urban refineries, the surrounding Metropolitan Statistical Areas (MSAs). Only residents living in census tracts within the shadow of 25 of our 126 oil refineries earn around $10,000 more annually than those in the region.

On average, residents of census tracts that contain oil refineries earn 13-16% less than those in the greater region and/or MSAs (Figure 2). Similarly, in comparing oil refinery census tract incomes to state averages we see a slightly larger 17-21% disparity (Figure 3).

Mean Annual Income In US Refinery Census Tracts Minus Surrounding Census Tracts (2014 $)
Mean Annual Income In US Refinery Census Tracts Minus Surrounding Census Tracts (2014 $)
Mean Annual Income In US Refinery Census Tracts Minus State Average (2014 $)
Mean Annual Income In US Refinery Census Tracts Minus State Average (2014 $)

Digging Deeper

United States Oil Refinery Income Disparities (Note: Larger points indicate oil refinery census tracts that earn less than the surrounding region or city)

Figure 4. United States Oil Refinery Income Disparities (Note: Larger points indicate oil refinery census tracts that earn less than the surrounding region or city.)

Oil refinery income disparities seem to occur not just in one region, but across the U.S. (Figure 4).

The biggest regional/MSA disparities occur in northeastern Denver neighborhoods around the Suncor Refinery complex (103,000 BPD), where the refinery’s census tracts earn roughly $42,000 less than Greater Denver residents1. California, too, has some issues near its Los Angeles’ Valero and Tesoro Refineries and Chevron’s Bay Area Refinery, with a combined daily capacity of nearly 600 BPD. There, two California census associations in the shadow of those refineries earn roughly $38,000 less than Contra Costa and Los Angeles Counties, respectively. In the Lone Star state Marathon’s Texas City, Galveston County refinery resides among census tracts where annual incomes nearly $33,000 less than the Galveston-Houston metroplex. Linden, NJ and St. Paul, MN, residents near Conoco Phillips and Flint Hills Resources refineries aren’t fairing much better, with annual incomes that are roughly $35,000 and nearly $33,000 less than the surrounding regions, respectively.

Click on the images below to explore each of the top disparate areas near oil refineries in the U.S. in more detail. Lighter shades indicate census tracks with a lower mean annual income ($).

Philadelphia and Northern Delaware Area Refineries and Mean Annual Income Across the Region
Philadelphia and Northern Delaware Area Refineries and Mean Annual Income Across the Region
Houston Area Refineries and Mean Annual Income Across the Region
Houston Area Refineries and Mean Annual Income Across the Region
Bay Area Refineries and Mean Annual Income Across the Region
Bay Area Refineries and Mean Annual Income Across the Region
Northern New Jersey Area Conoco Phillips Refinery and Mean Annual Income Across the Region
Northern New Jersey Area Conoco Phillips Refinery and Mean Annual Income Across the Region
Denver Area Refineries and Mean Annual Income Across the Region
Denver Area Refineries and Mean Annual Income Across the Region
Twin Cities Refineries and Mean Annual Income Across the Region
Twin Cities Refineries and Mean Annual Income Across the Region

Conclusion

Clearly, certain communities throughout the United States have been essentially sacrificed in the name of Energy Independence and overly-course measures of economic productivity such as Gross Domestic Product (GDP). The presence and/or construction of mid- and downstream oil and gas infrastructure appears to accelerate an already insidious positive feedback loop in low-income neighborhoods throughout the United States. Only a few places like Southeast Chicago and Detroit, however, have even begun to discuss where these disadvantaged communities should live, let alone how to remediate the environmental costs.

Internally Displaced People

There exists a robust history of journalists and academics focusing on Internally Displaced People (IDP) throughout war-torn regions of Africa, the Middle East, and Southeast Asia – to name a few – and most of these 38 million people have “become displaced within their own country as a result of violence.” However, there is a growing body of literature and media coverage associated with current and potential IDP resulting from rising sea levels, drought, chronic wildfire, etc.

The issues associated with oil and gas infrastructure expansion and IDPs are only going to grow in the coming years as the Shale Revolution results in a greater need for pipelines, compressor stations, cracker facilities, etc. We would propose there is the potential for IDP resulting from the rapid, ubiquitous, and intense expansion of the Hydrocarbon Industrial Complex here in the United States.

N. American Hydrocarbon Industrial Complex Map


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Footnotes and Additional Reading

  1. The Suncor refinery was implicated in a significant leak of tar sands crude associated benzene into the South Platte River as recently as 2013. According to Suncor’s website this refinery “supplies about 35% of Colorado’s gasoline and diesel fuel demand and is a major supplier of jet fuel to the Denver International Airport. The refinery is also the largest supplier of paving-grade asphalt in Colorado.”
  2. New York Times story on the growing footprint of BP’s Whiting Refinery: Surrounded by Industry, a Historic Community Fights for Its Future
Download Map Data (zip)

By Ted Auch, PhD – Great Lakes Program Coordinator, FracTracker Alliance

Mariner East 2 Pipeline Route
FracTracker Alliance

Mariner East 2 and Watershed Risks

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Mariner East 2 (ME 2) is a $2.5 billion, 350 mile-long pipeline that, if built, would be one of the largest pipeline construction projects in Pennsylvania’s history—carving a fifty-foot wide path through 17 counties. A project of Sunoco Logistics, ME 2 would have the capacity to transport 275,000 barrels a day of propane, ethane, butane, and other hydrocarbons from the shale fields of Western Pennsylvania and neighboring states to an international export terminal in Marcus Hook, located on the Delaware River.

ME 2 has sparked a range of responses from residents in Pennsylvania, however, including concerns about recent pipeline accidents, the ethics of taking land by eminent domain, and the unknown risks to sensitive ecosystems. Below we explore the watersheds that could be impacted by this proposed pipeline.

Watershed Impacts

While some components of Sunoco’s ME 2 proposal are approved, the project requires more permits from the Pennsylvania Department of Environmental Protection (DEP) before construction can begin. Among those are permits to build through and under stream and wetlands. Many of the waters threatened by ME 2 are designated by the Commonwealth as “exceptional value” (EV) or “high quality” (HQ) and are supposed to be given greater protections from harm. Water Obstruction and Encroachment Permits, also known as “Chapter 105” permits, are required for any building activities that would disrupt any body of water, including wetlands and streams. Sunoco applied for these so-called “Chapter 105” permits in the summer of 2015, but its applications were rejected as incomplete several times.

The below map shows the ME 2 route as of May 2016 relative to the watersheds and streams it will cross. Zoom into the map to see additional layers. Note that this is the most accurate representations of ME 2’s route we have seen to date. MWA provided the shapefiles for ME 2’s route to FracTracker Alliance and continues its investigations into potential watershed impacts.

Proposed ME 2 Route

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In total, ME 2’s path will include 1,227 stream crossings, 570 wetland crossings, and 11 pond crossings. Of the 1,227 stream crossings, 19 are EV and 318 are HQ, meaning that 337 crossings will disturb what DEP refers to as “special protection” waters. In addition, there are 129 exceptional value wetlands being crossed. These numbers were compiled by Mountain Watershed Association (MWA) from Sunoco’s permitting applications. MWA also identified 2 HQ streams in Washington County, and 3 HQ streams in Blair County, that are proposed to be crossed that are not acknowledged as being HQ in Sunoco’s permits.

Public Comment Period Open

People living along the proposed route are sometimes in the best position to see what the route looks like from the ground, where wetlands and streams are, and what kinds of wetlands and streams they are. The DEP is accepting public comments on Sunoco’s ME 2 Ch. 105 permit application through Wednesday, August 24. Each DEP regional office receives separate Ch. 105 applications depending on where the pipeline routes through different counties. Those wishing to comment on the project can do so through the DEP regional office websites: DEP Southwest Region, DEP South-central Region, DEP Southeast Region. For guidance on how to write comments on permits, see MWA’s Pipeline Project Information & Talking Points.

We wish to thank Mountain Watershed Association and the Clean Air Council for helping us compile data and analysis for this article.

Written by Kirk Jalbert, PhD, MFA – Manager of Community-Based Research & Engagement, FracTracker Alliance

Karen Edelstein

New York: A Sunshine State!

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Photovoltaic solar resources of the US (NREL)

Photovoltaic solar resources of the US (NREL)

It’s difficult to talk about the risks of oil and gas extraction without providing data on energy alternatives in the conversation. Let’s look at New York State, as an example. There, solar power is taking a leadership position in the renewable energy revolution in the United States. Although New York State receives far less sunshine than many states to the west and south, the trends are bright! Currently, New York State ranks seventh in the nation in installed solar capacity, with over 700 MW of power generated by the sun, enough to power 121,000 homes.

Despite common assumptions that solar power only makes sense where the sun shines 360 days a year, we’ve been seeing successful adoption of solar in Europe for years. For example, in Germany, where even the most southern part of the country is further north of the Adirondack Mountains in New York State, close to 7% of all the power used comes from combined residential and commercial scale photovoltaic sources–35.2 TWh in all. Munich, one of the sunniest places in all of Germany, has a lower average solar irradiation rate of 3.1 kWh/m2/day than most cities in New York State; compare it with locations in New York like Rochester (3.7 kWh/m2/day), New York City (4.0 kWh/m2/day), and Albany (3.8 kWh/m2/day). At present, Germany still leads New York State by more than double the electrical output from solar for equivalent areas.

cumulative_capacity

Cumulative Solar Capacity in New York

The cumulative capacity for completed photovoltaic systems in New York State has risen steeply in the past three years, with ground-mounted and roof-top residential capacity outpacing commercial capacity by a wide margin.

Nonetheless, commercial and industrial scale installations in New York account for over 100 MW of power capacity in the state.

Large-Scale Solar Installations Map

This map shows the location of those large-scale solar installations in the US (zoom out to see full extent of US), as of March 2016. Here is our interactive map:

View map full screen | How FracTracker maps work

In the past fifteen years, the increase in small to medium-sized solar installations in New York State has been significant, and growth is projected to continue.  The following animation, based on data from the New York State Energy Research and Development Authority (NYSERDA), shows that increase in capacity (by zip code) since 2000:

solar_animation_cumulative_2000-15

Solar Installations by Zip Code

NYSERDA also provides maps that show distributions of residential, governmental/NGO, and commercial solar energy projects (images shown below). For example, Suffolk County leads the way in the residential arena, with nearly 8200 photovoltaic (PV) systems on roofs and in yards, with an average size of 8.3 kW each.

Erie County has 128 PV systems run by governmental and not-for-profit groups, with an average size of about 27 kW each. Albany County has over 320 commercial installations, with an average size each of about 117 kW.

New York State’s Future Solar Contribution

pricing

Price of Completed Solar Systems 2003-2016

The prices of solar panels is steeply declining, and is coupled with generous tax incentives. The good news, according to the Solar Energy Industries Association (SEIA), is that over the next five years, New York State’s solar capacity is expected to quadruple its current output, adding over 2900 MW of power. This change would elevate New York State from seventh to fourth place in output in the US.

By Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance

Bill Hughes giving tour to students in shale fields, WV
Guest Author

A Cross-Country Ride to Support Oil and Gas Tours in West Virginia

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Bill Hughes giving tours of gas fields in West Virginia. Photo by Joe Solomon. https://flic.kr/s/aHskkXZj3z

Bill Hughes giving a tour of gas fields in West Virginia. Photo by Joe Solomon.

As many of you know, educating the public is a FracTracker Alliance core value – a passion, in fact. In addition to our maps and resources, we help to provide hands-on education, as well. The extraordinary Bill Hughes is a FracTracker partner who has spent decades “in the trenches” in West Virginia documenting fracking, well pad construction, water withdrawals, pipeline construction, accidents, spills, leaks, and various practices of the oil and gas industry. He regularly leads tours for college students, reporters, and other interested parties, showing them first-hand what these sites look, smell, and sound like.

While most of us have heard of fracking, few of us have seen it in action or how it has changed communities. The tours that Bill provides allow students and the like to experience in person what this kind of extraction means for the environment and for the residents who live near it.

Biking to Support FracTracker and Bill Hughes

Dave Weyant at the start of his cross-country bike trip in support of WV tours

Dave Weyant at the start of his cross-country Pedal for the Planet bike trip

In the classic spirit of non-profit organizations, we work in partnership with others whenever possible. Right now, as you read this posting, another extraordinary Friend of FracTracker, Dave Weyant (a high school teacher in San Mateo, CA), is finishing his cross-country cycling tour – from Virginia to Oregon in 70 days.

Dave believes strongly in the power of teaching to reach the hearts of students and shape their thinking about complicated issues. As such, he has dedicated his journey to raising money for FracTracker. He set up a GoFundMe campaign in conjunction with his epic adventure, and he will donate whatever he raises toward Bill’s educational tours.

Help us celebrate Dave Weyant’s courage, vision, and generosity – and support Bill Hughes’s tireless efforts to open eyes, evoke awareness, and foster communication about fracking – by visiting Dave’s GoFundMe page and making a donation. Every gift of any size is most welcome and deeply appreciated.

100% of the funds raised from this campaign will go to support Bill’s oil and gas tours in West Virginia. FracTracker Alliance is a registered 501(c)3 organization. Your contribution is tax deductible.

Support Oil and Gas Tours in WV

And to those of you who have already donated, thank you very much for your support!

South Belridge field by Sarah Leen, National Geographic
Kyle Ferrar, MPH

Trends in California’s Oil and Gas Development

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By Kyle Ferrar, Western Program Coordinator

Over 38,000 oil and gas wells have likely been hydraulically fractured in California. The last permitted hydraulic fracturing operation in CA was approved in June 2015. Additionally, new aquifer exemption proposals will make it easier for operators to obtain hydraulic fracturing permits. One of the most interesting and troubling issues we found when analyzing the data on violations is that operators with the highest number of new well permits are also responsible for the majority of violations. In this article, we provide a look at these and other the trends of unconventional drilling in CA.

Updated CA Shale Viewer

First of all, the CA Shale Viewer has been updated! New data has been uploaded into the map about unconventional drilling in California, and new data resources have been used to identify shale gas activity (Fig. 1). Recent reports in CA have exposed what many researchers expected – hydraulic fracturing has been occurring in the state without any oversight or documentation for a long time.

In this presentation of the Updated CA Shale Viewer we showcase an analysis of these new data sources that better describe unconventional drilling in CA. We then look to new well permitting data to see what current spatial trends may mean for future oil and gas development. We also look at a sample of operator violations issued by the state regulatory agency to tell us a bit about who the bad actors may be.

Figure 1. CA Shale Viewer – Location of well stimulation & other unconventional oil & gas activity


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Current Fracking Activity

Fracking in California has been put on hold at the moment as a result of low oil prices combined with the new permitting requirements for groundwater monitoring. In 2015, the CA Council on Science and Technology (CCST) released a report on hydraulic fracturing, as required by State Bill 4, proposed by Senator Pavley. The legislation required the Division of Oil, Gas and Geothermal Resources to create regulations for hydraulic fracturing and other stimulation activities such as acidizing. The report highlighted the necessity of protecting California’s groundwater resources. As another requirement of SB4, the state water resources control board adopted Model Criteria for Groundwater Monitoring in areas of Oil and Gas Well Stimulation, which includes three main components:

  1. Area-specific required groundwater monitoring near stimulation wells by operators
  2. Requirements for designated contractor sampling and testing
  3. Regional scale groundwater monitoring to be implemented by the State Water Board

With these requirements in place to protect groundwater, using hydraulic fracturing and other “extreme” high energy input techniques to extract oil is not currently economical in California. Operators have not submitted a permit application for hydraulic fracturing in CA since June 2015.

This status may change in the near future, though, as DOGGR has proposed groundwater monitoring exemptions for 3 large aquifer systems in Kern and Arroyo Grande counties. Such a proposal would mean that operators would not have to monitor for groundwater contamination in these areas when using hydraulic fracturing or other stimulation technologies like acidizing.

Previous Fracking Activity

One outcome of the aforementioned CCST report on hydraulic fracturing was a review of stimulation activity that has occurred in CA but went undocumented. Researchers at Lawrence Berkeley National Laboratory (LBNL) screened thousands of oil and gas well logs and records to calculate the extent to which hydraulic fracturing was actually being used in California’s oil fields. LBNL derived “Well Stimulation Treatment” probabilities based on the number of well records that reported utilizing hydraulic fracturing.

Probabilities were then derived for each pool, which is a geographically isolated formation within an oil field. Using these probabilities, FracTracker calculated a conservative estimate for the number of stimulated wells in the state at over 38,000. There are 228,010 unique Well ID’s listed in the DOGGR database. This puts the proportion of hydraulically fractured wells in California at 16.7% of the total 228,090 wells known.

New Wells

Whereas many other states break down their oil and gas data to show in what phase of development a well may be, CA identifies all wells between the permitted and producing/injecting phase as “new.” In Figure 2 below you can see the wells identified in 2016 as “new.” The DOGGR dataset shows there are currently 6,561 new wells in California as of July 2016. Counts of new well permits were calculated for individual operators and are listed below in Table 1.

Table 1. Top 10 operators according to new well permit counts in California, along with the number of new well permits currently active, the percent those permits represent of total new well permits in the state, and the percentage of violations the operator is responsible in the DOGGR dataset provided to FracTracker Alliance.

Order Operator Permit Count Permit % Violations %
1 Aera Energy LLC 2012 30.67% 22.34%
2 Chevron U.S.A. Inc. 968 14.75% 20.35%
3 California Resources Production Corporation 768 11.70% 5.89%
4 Linn Operating, Inc. 574 8.75% 12.04%
5 E & B Natural Resources Management Corporation 572 8.71% 1%
6 California Resources Elk Hills, LLC 374 5.70% 5.52%
7 Seneca Resources Corporation 185 2.82% 2.83%
8 Freeport-McMoRan Oil & Gas LLC 164 2.50% 15.22%
9 Vaquero Energy, Inc. 154 2.35% 0.22%
10 Macpherson Oil Company 116 1.77% 2.09%

There are 68 fields in CA that have added new wells in the new DOGGR dataset published in July 2016. The top 10 fields are listed in Table 2 below.

Table 2. Top 10 Oil Fields by Permit (New Well) Count

Order Oil Field Well Count
1 Belridge, South 1518
2 Midway-Sunset 903
3 Poso Creek 553
4 Lost Hills 488
5 Cymric 336
6 Kern River 294
7 Elk Hills 276
8 Kern Front 233
9 McKittrick 186
10 Belridge, North 174

In Figure 2 below, the counts of new wells in fields are shown in shades of yellow/red. The fields with the highest number of new wells are located in the Central Valley. The top 10 operators’ wells are also identified. The majority of new well permits are located in the South Belridge oil field, and the majority of those wells are operated by Aera Energy. As can be seen in the map, most new wells are located in fields in Kern county, but Santa Barbara and Fresno, and even Salinas counties have fields with 40 or more new well permits.

Figure 2. New Well Permitting Map of Unconventional Drilling in California


View map fullscreen | How FracTracker maps work

Violations

Who collects violations data?

In most states with heavy oil and gas drilling, data on violations is collected by the state regulatory agency, aggregated in datasets and spreadsheets, and made available to the public. FracTracker has done analyses with such data in the past.

In Pennsylvania for instance, a 2011 look at the data showed us that as the number of inspectors on the ground in the Marcellus Shale fields increases, the number of violations/well actually decrease. This was important information that challenged the cynical hypothesis: that more inspectors mean additional eyes on the ground to identify more violations during inspections. In reality, more inspectors actually mean that operators are held to higher standards, and further best management practices (BMPs) are employed. This trend at least seemed to be the case in Pennsylvania. As a regulatory agency, such knowledge is incredibly important, and even validates increased spending and budgets for more personnel.

In California, the issue of publishing violations data is again met with a similar response from the Division of Oil Gas and Geothermal Resources (DOGGR), specifically the “Oh, is that my job?” question.

How is it shared?

At FracTracker, we spent time working with regulatory officials at DOGGR to get some data on violations. We were informed that at some point in the future, the data may be aggregated and available digitally. Until then, however, a request for the data would have to be made to each of the six district offices individually and would take approximately a year to pull together scanned copies of violations notices in PDF format. Unfortunately, we at FracTracker do not have the capacity to process such files. Instead we asked for anything DOGGR had digitally available, and we were provided with a sample subset of 2,825 violations dating mostly from 2013 and 2014 and only in District 2, the Los Angeles Basin.

What does CA violations data look like?

Looking at the sample of data in Table 2, we see that the majority of violations are caused by the operators that also have the most new well permits. Aera Energy, in particular, is responsible for over 1/5 of all violations in our sample set. Limiting factors and sampling bias of the sample set of violations may impact this analysis, though, as all violations are limited to Los Angeles County.  Operators that mostly operate in the Central Valley will be under represented in the violations count. When more violations data becomes available we will be sure to expand this analysis.

Bans and Regulations on Unconventional Drilling in California

Although every state regulatory agency lambasts that they have the most comprehensive and conservative set of oil and gas extraction regulations, California regulators may actually be right. That is, save for New York which has banned hydraulic fracturing outright.

Regardless of the policy decisions made at the state-level, multiple local municipalities in CA have attempted to or succeeded in passing local bans. Six counties have passed outright bans on unconventional drilling in California, as can be seen in the FracTracker Local Actions map below (Fig. 3). Most recently the county of Alameda, home to the cities of Berkeley and Oakland, has passed a ban. The county of Monterey is also considering a ban on all oil and gas extraction, which has been approved as a local ballot initiative for November 2016.

Figure 3. Local Actions, Bans and Regulations Map


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As the price of oil rebounds closer to $100/barrel, there will be more interest by operators to increase unconventional drilling in California. The addition of new aquifer exemptions will make it all the more appealing. These local movements are therefore incredibly important to ensure that “extreme” extraction methods like fracking don’t expand in the future.

Feature Photo: South Belridge field by Sarah Leen, National Geographic

Air emissions from drilling rig
FracTracker Alliance

A Review of Oil and Gas Emissions Data in Pennsylvania

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By Wendy Fan, 2016 Intern, FracTracker Alliance

From 2011-2013, the PA Department of Environmental Protection (DEP) required air emission data to be conducted and reported by oil and gas drillers in Pennsylvania. We have tried to look at this data in aggregate to give you a sense of the types and quantities of different pollutants. Corresponding to their degree of oil and gas drilling activity, Washington, Susquehanna, Bradford, Greene, and Lycoming counties are the highest emitters of overall pollutants between the specified years. Despite the department’s attempt to increase transparency, the data submitted by the operators severely underestimates the actual amount of pollutants released, especially with regard to methane emissions. Furthermore, gaps such as inconsistent monitoring systems, missing data, and a lack of a verification process of the self-reported data weaken the integrity and reliability of the submitted data. This article explores the data submitted and its implications in further detail.

Why Emissions Are Reported

The U.S. Energy Information Administration (EIA) estimates that U.S. natural gas production will increase from 23 trillion cubic feet in 2011 to over 33 trillion cubic feet in 2040. Pennsylvania, in particular, is one of the states with the highest amount of drilling activity at present. This statistic can be attributed to resource-rich geologic formations such as the Marcellus Shale, which extends throughout much of Appalachia. While New York has banned drilling using high-volume hydraulic fracturing (fracking), Pennsylvania continues to expand its operations with 9,775 active unconventional wells as of June 10, 2016.

Between 2000-2016, drillers in Pennsylvania incurred 5,773 violations and $47.2 million in fines. The PA DEP, which oversees drilling permits and citations, has undergone criticism for their lack of action with complaints related to oil and gas drilling, as well as poor communication to the public*. In order to increase transparency and to monitor air emissions from wells, the DEP now requires unconventional natural gas operators to submit air emission data each year. The data submitted by operators are intended to be publicly accessible and downloadable by county, emission, or well operator.

* Interestingly, PA scored the highest when we rated states on a variety of data transparency metrics in a study published in 2015.

Importance of Data Collected

PA’s continual growth in oil and gas drilling activity is concerning for the environment and public health. Pollutants such as methane, carbon dioxide (CO2), and nitrous oxides (NOx) are all major contributors to climate change, and these are among the more common emissions found near oil and gas activities. Long-term exposure to benzene, also commonly associated with drilling sites, can result in harmful effects on the bone marrow and the decrease in red blood cells. Vomiting, convulsions, dizziness, and even death can occur within minutes to several hours with high levels of benzene.

With such risks, it is crucial for residents to understand how many wells are within their vicinity, and the levels of these pollutants emitted.

Air Monitoring Data Findings & Gaps

Although the DEP collects emission data on other important pollutants such as sulfur oxides (SOx), particulate matter (PM10 and PM2.5), and toluene, this article focuses only on a few select pollutants that have shown the highest emission levels from natural gas activity. The following graphs illustrate emissions of methane, carbon dioxide (CO2), carbon monoxide (CO), nitrogen oxides (NOx), benzene, and volatile organic compounds (VOCs) for the top 10 counties with the highest amounts of natural gas activity. PA wells drilled data (often called SPUD data) will also be referenced throughout the article. Data source: PA SPUD Data.

CMC

PA DEP’s Calculation Methods Codes for Emissions

Well operators self-report an estimate of total emissions in tons per year through either an online or paper reporting system. They must also indicate the method they used to generate this estimate with the Calculation Methods Codes for Emissions (table shown right).

For more information on how the data is prepared and what are the reporting requirements, refer to PA DEP’s Instruction for Completing the Annual Emissions Statement Reporting Forms. 

Total Amount of Unconventional Wells 2000-2016

AmountofWells

Figure 1

Overall, Washington, Susquehanna, Bradford, Greene, and Lycoming counties were the main emitters of all selected pollutants (methane, CO2, CO, NOx, VOCs, and benzene) throughout Pennsylvania based on tons per year (Fig 1). This trend may be correlated to the amount of natural gas activity that exists within each state as shown in the graph above. The top three Pennsylvania counties with the highest amount of oil and gas activity since 2000 are Washington, Susquehanna, and Bradford with 1,347; 1,187; and 1,091 unconventional active wells, respectively.

Methane Emissions

PA_Methane

Figure 2

In 2012, Susquehanna, Bradford, and Lycoming counties reported the highest amount of methane released with levels at 36,607, 23,350, and 14,648 tons, respectively (Fig 2). In 2013, Bradford, Lycoming, and Greene counties reported the highest amount of methane released with levels at 17,805, 17,265, and 15,296 tons, respectively.

Although the overall trend of methane emission declines from 2012 to 2013, there is an unusual drop in Susquehanna County’s methane emissions from 2012 to 2013. Susquehanna’s levels went from 36,607 tons to 12,269 tons in that timeframe. However, the DEP SPUD data recorded an increase of 190 active wells to 214 active wells from 2012 to 2013 in that same county. Though the well operators did not provide details for this shift, possible reasons may be because of improved methods of preventing methane leaks over the year, well equipment may be less robust as it once was, operators may have had less of a reason to monitor for leaky wells, or operators themselves could have changed.

Lackawanna and Luzerne counties reported zero tons of methane released during the year of 2012 (not shown on graph). There are two possible reasons for this: both counties did not have any unconventional wells recorded in the 2012 SPUD data, which may explain why the two counties reported zero tons for methane emissions, or the levels submitted are a significant underestimation of the actual methane level in the counties. (While there were no new wells, there are existing wells in production in those counties.)

Considering that methane is the primary component of natural gas activity, the non-existent level of methane reported seem highly implausible even with inactive wells on site. Typically, an old or inactive gas well can either be abandoned, orphaned, or plugged. By definition, abandoned wells have been inactive for more than a year, and orphaned wells were abandoned prior to 1985. (Because of this distinction, however, no unconventional wells can be considered “orphaned.”) To plug a well, cement plugs are used to cover up wellbores in order to cease all flow of gas. The act of physically plugging up the wells paints an illusion that it is no longer functioning and has ceased all emissions.

Because of this flawed impression, systematic monitoring of air emissions is often not conducted and the wells are often ignored. Several studies have shown even abandoned and plugged wells are still spewing out small and at times large quantities of methane and CO2. One study published in 2014 in particular measured 19 abandoned wells throughout Pennsylvania, and concluded that abandoned wells were significant contributors to methane emissions – contributing 4-7% of total anthropogenic (man-made) methane emissions in PA.

View methane emissions map full screen: 2012-2013

Carbon Dioxide Emissions

PA_CO2

Figure 3

In 2012, Bradford County reported 682,302 tons of CO2 emitted; Washington County reported 680,979 tons; and Susquehanna reported 560,881 tons (Fig. 3). In 2013, Washington continued to lead with 730,674 tons, Bradford at 721,274 tons, and Lycoming with 537,585 tons of CO2 emitted.

What’s intriguing is according to SPUD data, Armstrong, Westmoreland, and Fayette also had considerable natural gas activity between the two years as shown on the map. Yet, their levels of CO2 emission are significantly lower compared to Lycoming or Susquehanna Counties. Greene County, in particular, had lower levels of CO2 reported. Yet, they had 106 active wells in 2012 and 117 in 2013. What is even more unusual is that Bradford County had 9 more wells than Greene County in 2013, yet, Greene County still had significantly higher CO2 levels reported.

Reasons for this difference may be that Greene County lacked the staff or resources to accurately monitor for CO2, the county may have forgotten to record emissions from compressor stations or other fugitive emission sources, or the method of monitoring may have differed between counties. Whatever the reason is, it is evident that the levels reported by Greene County may not actually be an accurate depiction of the true level of CO2 emitted.

View CO2 emissions map full screen: 2012-2013

Carbon Monoxide Emissions

Spudded wells in PA with reported CO emissions by county 2011-13

Spudded wells in PA with reported CO emissions by county 2011-13

PA_CO

Figure 4

According to the PA SPUD data, the number of new wells drilled in Bradford County dropped from 389 in 2011 to 163 in 2012 to 108 to 2013. The diminishing number of newly drilled wells in this particular county may explain the noticeable outlier in CO emission as seen on the graph (Fig 4).

View CO emissions map full screen: 2011-2013

NOx and VOCs

PA_VOCs
PA_VOCs
PA_NOx
PA_NOx

Compressor stations are also known to emit VOC, NOx, and various greenhouse gases; they run 24/7 and serve multiple wells. Compressor stations are necessary to move the natural gas along the pipelines, and thus, may still be required to function even after some wells have ceased operation. Furthermore, there can be multiple compressor stations in a region because they are installed at intervals of about 40 to 100 miles. This suggests that in addition to drilled wells, compressor stations provide additional avenues for NOx or VOC to leak into the air.

View NOx and VOC emissions maps full screen: VOC 2011-2013 | NOx 2011-2013

Benzene Emissions

Spudded wells in PA with reported benzene emissions by county 2011-13

Spudded wells in PA with reported benzene emissions by county 2011-13

Chart of PA benzene emissions data county to county

Figure 7

The levels of benzene emitted varied the most when compared to the other pollutants presented previously. Generally, the high levels of methane, CO2, and NOx emitted correlate with the high amount of natural gas activity recorded for each county’s number of drilled unconventional wells. However, it is interesting that both Westmoreland and Fayette counties had fewer active wells than Bradford County, yet, still reported higher levels of benzene (Fig 1, Fig 7).

An explanation for this may be the different monitoring techniques, the equipment used on each site which may vary by contractor or well access, or that there are other external sources of benzene captured in the monitoring process.

View benzene emissions map full screen: 2011-2013

Questions Remain

Although the collection and monitoring of air emission from wells is a step in the right direction, the data itself reveals several gaps that render the information questionable.

  • The DEP did not require operators to report methane, carbon dioxide, and nitrous oxide in 2011. Considering that all three components are potent greenhouse gases and that methane is the primary component in natural gas production, the data could have been more reliable and robust if the amount of the highest pollutants were provided from the start.
  • Systematic air monitoring around abandoned, orphaned, and plugged wells should still be conducted and data reported because of their significant impact to air quality. The DEP estimates there are approximately 200,000 wells that have been abandoned and unaccounted for. This figure includes older, abandoned wells that had outdated methods of plugging, such as wood plugs, wood well casings, or no plug at all. Without a consistent monitoring system for fugitive air emissions, the public’s true risk of the exposure to air pollutants will remain ambiguous.
  • All emissions submitted to the DEP are self-reported data from the operators. The DEP lacks a proper verification process to confirm whether the submitted data from operators are accurate.
  • The finalized data for 2014 has yet to be released despite the DEP’s April 2016 deadline. The DEP inadvertently posted the reports in March 2016, but quickly removed them without any notification or explanation as to why this information was removed. When we inquired about the release date, a DEP representative stated the data should be uploaded within the next couple of weeks. We will provide updates to this post when that data is posted but the DEP.

Overall, PA DEP’s valiant attempt to collect air data from operators and to increase transparency is constrained by the inconsistency and inaccuracy of the dataset. The gaps in the data strongly suggest that the department’s collection process and/or the industry’s reporting protocol still require major improvements in order to better monitor and communicate this information to the public.

August 23, 2016 Update

The 2014 air emissions data are now available on PA DEP’s website.