Ted Auch, PhD

The Underlying Politics and Unconventional Well Fundamentals of an Appalachian Storage Hub

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FracTracker is closely mapping and following the petrochemical build-out in Appalachia, as the oil and gas industry invests in petrochemical manufacturing. Much of the national attention on the build-out revolves around the Appalachian Storage Hub (ASH), a venture spearheaded by Appalachian Development Group.

The ASH involves a network of infrastructure to store and transport natural gas liquids and finds support across the political spectrum. Elected officials are collaborating with the private sector and foreign investors to further development of the ASH, citing benefits such as national security, increased revenue, job creation, and energy independence.

Left out of the discussion are the increased environmental and public health burdens the ASH would place on the region, and the fact that natural gas liquids are the feedstock of products such as plastic and resins, not energy.

The “Shale Revolution”

the allegheny plateau

The Allegheny Plateau. Wikipedia

The “Shale Revolution” brought on by high-volume hydraulic fracturing (fracking) in this region encompasses thousands of wells drilled into the Marcellus and Utica-Point Pleasant shale plays across much of the Allegheny Plateau. This area spans from north of Scranton-Wilkes Barre, Pennsylvania, just outside the Catskills Mountains to the East in Susquehanna County, Pennsylvania, and down to the West Virginia counties of Logan, Boone, and Lincoln.  The westernmost extent of the fracking experiment in the Marcellus and Utica shale plays is in Noble and Guernsey Counties in Ohio.

Along the way, producing wells have exhibited steeper and steeper declines during the first five years of production, leading the industry to develop what they refer to as “super laterals.” These laterals (the horizontal portion of a well) exceed 3 miles in length and require in excess of 15 million gallons of freshwater and 15,000 tons of silica sand (aka, “proppant”)[1].

The resource-intense super laterals are one way the industry is dealing with growing pressure from investors, lenders, the media, state governments, and the public to reduce supply costs and turn a profit, while also maintaining production. (Note: unfortunately these sources of pressures are listed from most to least concerning to industry itself!)

Another way the fracking industry is hoping to make a profit is by investing in the region’s natural gas liquids (NGLs), such as ethane, propane, and butane, to support the petrochemical industry.

The Appalachian Storage Hub

Continued oil and gas development are part of a nascent effort to establish a mega-infrastructure petrochemical complex,  the Appalachian Storage Hub (ASH). For those that aren’t familiar with the ASH it could be framed as the fracking industry’s last best attempt to lock in their necessity across Appalachia and nationwide. The ASH was defined in the West Virginia Executive as a way to revitalize the Mountain State and would consist of the following:

“a proposed underground storage facility that would be used to store and transport natural gas liquids (NGLs) extracted from the Marcellus, Utica and Rogersville shales across Kentucky, Ohio, Pennsylvania and West Virginia. Construction of this hub would not only lead to revenue and job creation in the natural gas industry but would also further enable manufacturing companies to come to the Mountain State, as the petrochemicals produced by shale are necessary materials in most manufacturing supply chains…[with] the raw materials available in the region’s Marcellus Shale alone…estimated to be worth more than $2 trillion, and an estimated 20 percent of this shale is composed largely of ethane, propane and butane NGLs that can be utilized by the petrochemical industry in the manufacturing of consumer goods.”

This is yet another example of fracking rhetoric that appeals to American’s sense of patriotism and need for cheaper consumer goods (in this case, plastics), given that they are seeing little to no growth in wages.

While a specific location for underground storage has not been announced, the infrastructure associated with the ASH (such as pipelines, compressor stations, and processing stations) would stretch from outside Pittsburgh down to Catlettsburg, Kentucky, with the latter currently the home of a sizeable Marathon Oil refinery. The ASH “would act like an interstate highway, with on-ramps and off-ramps feeding manufacturing hubs along its length and drawing from the available ethane storage fields. The piping would sit above-ground and follow the Ohio and Kanawha river valley.”

The politics of the ASH – from Columbus and Charleston to Washington DC

Elected officials across the quad-state region are supporting this effort invoking, not surprisingly, its importance for national security and energy independence.

State-level support

West Virginia Senator Joe Manchin (D) went so far as to introduce “Senate Bill 1064 – Appalachian Energy for National Security Act.”  This bill would require Secretary of Energy Rick Perry and his staff to “to conduct a study on the national security implications of building ethane and other natural-gas-liquids-related petrochemical infrastructure in the United States, and for other purposes.”

Interestingly, the West Virginia Senator told the West Virginia Roundtable Inc’s membership meeting that the study would not examine the “national security implications” but rather the “additional security benefits” of an Appalachian Storage Hub and cited the following to pave the way for the national security study he is proposing: “the shale resource endowment of the Appalachian Basin is so bountiful that, if the Appalachian Basin were an independent country, the Appalachian Basin would be the third largest producer of natural gas in the world.”

Senator Manchin is not the only politician of either party to unabashedly holler from the Appalachian Mountaintops the benefits of the ASH. Former Ohio Governor, and 2016 POTUS primary participant, John Kasich (R) has been a fervent supporter of such a regional planning scheme. He is particularly outspoken in favor of the joint proposal by Thailand-based PTT Global Chemical and Daelim to build an ethane cracker in Dilles Bottom, Ohio, across the Ohio River from Moundsville, West Virginia. The ethane cracker would convert the region’s fracked ethane into ethylene to make polyethylene plastic. This proposed project could be connected to the underground storage component of the ASH.

The Democratic Pennsylvania Governor Tom Wolf has consistently advocated for the project, going so far as to sign “an unprecedented agreement at the Tri-State Shale Summit, promising collaboration between the states in securing crackers for the region and, by extension, support of the storage hub.”

Dilles Bottom, OH ethane cracker site. Photo by Ted Auch, aerial assistance provided by LightHawk.

Not to be outdone in the ASH cheerleading department, West Virginia Governor Jim Justice (R), who can’t seem to find any common ground with Democrats in general nor Senator Manchin specifically, is collaborating with quad-state governors on the benefits of the ASH. All the while, these players ignore or dismiss the environmental, social, and economic costs of such an “all in” bet on petrochemicals and plastics.

Even the region’s land-grant universities have gotten in on the act, with West Virginia University’s Appalachian Oil and Natural Gas Research Consortium and Energy Institute leading the way. WVU’s Energy Institute Director Brian Anderson pointed out that, “Appalachia is poised for a renaissance of the petrochemical industry due to the availability of natural gas liquids. A critical path for this rebirth is through the development of infrastructure to support the industry. The Appalachian Storage Hub study is a first step for realizing that necessary infrastructure.”

National-level support

The Trump administration, with the assistance of Senator Manchin’s “Senate Bill 1337 – Capitalizing on American Storage Potential Act”, has managed to stretch the definition of the Department of Energy’s Title XVII loan guarantee to earmark $1.9 billion for the Appalachian Development Group, LLC (ADG) to develop the ASH, even though any project that receives such a loan must:

  1. utilize a new or significantly improved technology;
  2. avoid, reduce or sequester greenhouse gases;
  3. be located in the United States; and,
  4. have a reasonable prospect of repayment.

This type of Public-Private Investment Program  is central planning at its finest, in spite of the likelihood that the prospects of the ASH meeting the second and fourth conditions above are dubious at best (even if the project utilizes carbon capture and storage technologies).

Public-Private Investment Programs have a dubious past. In her book “Water Wars,” Vandana Shiva discusses the role of these programs globally and the involvement of institutions like the World Bank and International Monetary Fund:

“public-private partnerships”…implies public participation, democracy, and accountability.  But it disguises the fact that the public-private partnership arrangements usually entail public funds being available for the privatization of public goods…[and] have mushroomed under the guise of attracting private capital and curbing public-sector employment.”

In response to the Department of Energy’s Title XVII largesse, Congresswoman Pramila Jayapal and Ilhan Omar introduced Amendment 105 in Rule II on HR 2740. According to Food and Water Watch, this amendment would restrict “the types of projects the Department of Energy could financially back. It would block the funding for ALL projects that wouldn’t mitigate climate change.”

On Wednesday, June 19th Congress voted 233-200 along party lines to pass the amendment, preventing funds from the Energy Policy Act of 2005  to be provided to any “project that does not avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse gases”.

International interest

The only condition of Department of Energy’s Title XVII loan program ASH is guaranteed to meet is the third (be located in the United States), but as we’ve already mentioned, the level of foreign money involved complicates the domestic facade.

Foreign involvement in the ASH lends credence to Senator Manchin’s and others’ concerns about where profits from the ASH will go, and who will be reaping the benefits of cheap natural gas. The fact that the ASH is being heavily backed by foreign money is the reason Senator Manchin raised an issue with the outsized role of state actors like Saudi Arabia and China as well as likely state-backed private investments like PTT Global Chemical’s. The Senator even cited how a potential $83.7 billion investment in West Virginia from China’s state-owned energy company, China Energy, would compromise “domestic manufacturing and national security opportunities.”

“Critical” infrastructure

With all of the discussion and legislation focused on energy and national security, many don’t realize the output of the ASH would be the production of petroleum-based products: mainly plastic, but also fertilizers, paints, resins, and other chemical products.

Not coincidentally, Republican Ohio State Representatives George Lang and Don Jones just introduced House Bill 242, and attempt to support the plastic industry by “prohibit[ing] the imposition of a tax or fee on [auxiliary or plastic] containers, and to apply existing anti-littering law to those containers.”

There will most certainly be a battle in the courts between the state and urban counties like Cuyahoga County, Ohio, who’s council just voted to ban plastic bags countywide on May 28.

Bills like this and the not unrelated “critical infrastructure” bills being shopped around by the American Legislative Exchange Council will amplify the rural vs urban and local vs state oversight divisions running rampant throughout the United States.  The reason for this is that yet another natural resource boom/bust will be foisted on Central Appalachia to fuel urban growth and, in this instance, the growth and prosperity of foreign states like China.

Instead of working night and day to advocate for Appalachia and Americans more broadly, we have legislation in statehouses around the country that would make it harder to demonstrate or voice concerns about proposals associated with the ASH and similar regional planning projects stretching down into the Gulf of Mexico.

Producing wells mapped

Impacts from the ASH and associated ethane cracker proposals will include but are not limited to: an increase in the permitting of natural gas wells, an increase in associated gas gathering pipelines across the Allegheny Plateau, and an exponential increase in the production of plastics, all of which are harmful to the region’s environment and the planet.

The production of the region’s fracked wells will determine the long-term viability of the ASH. From our reading of things, the permitting trend we see in Ohio will have to hit another exponential inflection point to “feed the beast” as it were. Figure 1 shows an overall decline in the number of wells drilled monthly in Ohio.

Figure 2, below it, shows the relationship between the number of wells that are permitted verse those that are actually drilled.

Figures 1. Monthly (in blue) and cumulative (in orange) unconventional oil and gas wells drilled in Ohio, January, 2013 to November, 2018

 

 Figure 2. Permitted Vs Drilled Wells in Ohio, January, 2013 to November, 2018

That supply-demand on steroids interaction will likely result in an increased reliance on “super laterals” by the high-volume hydraulic fracturing industry. These laterals require 5-8 times more water, chemicals, and proppant than unconventional laterals did between 2010 and 2012.

Given this, we felt it critical to map not just the environmental impacts of this model of fracking but also the nuts and bolts of production over time. The map below shows the supply-demand links between the fracking industry and the ASH, not as discrete pieces or groupings of infrastructure, but rather a continuum of up and downstream patterns.

The current iteration of the map shows production values for oil, natural gas, and natural gas liquids, how production for any given well changes over time, and production declines in newer wells relative to those that were fracked at the outset of the region’s “Shale Revolution.” Working with volunteer Gary Allison, we have compiled and mapped monthly (Pennsylvania and West Virginia) and quarterly (Ohio)[2] natural gas, condensate, and natural gas liquids from 2002 to 2018.

This map includes 15,682 producing wells in Pennsylvania, 3,689 in West Virginia, and 2,064 in Ohio. We’ve also included and will be updating petrochemical projects associated with the ASH, either existing or proposed, across the quad-states including the proposed ethane cracker in Dilles Bottom, Ohio and the ethane cracker under construction in Beaver County, Pennsylvania, along with two rumored projects in West Virginia.


View Map Full Screen

Conclusion

We will continue to update this map on a quarterly basis, will be adding Kentucky data in the coming months, and will be sure to update rumored/proposed petrochemical infrastructure as they cross our radar. However, we can’t be everywhere at once so if anyone reading this hears of legitimate rumors or conversations taking place at the county or township level that cite tapping into the ASH’s infrastructural network, please be sure to contact us directly at info@fractracker.org.

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance with invaluable data compilation assistance from Gary Allison

Feature Photo: Ethane cracker plant under construction in Beaver County, PA. Photo by Ted Auch, aerial assistance provided by LightHawk.

[1] For a detailed analysis of the HVHF’s increasing resource demand and how lateral length has increased in the last decade the reader is referred to our analysis titled “A Disturbing Tale of Diminishing Returns in Ohio” Figures 12 and 13.

[2] Note: For those Bluegrass State residents or interested parties, Kentucky data is on its way!

Kyle Ferrar, MPH

Permitting New Oil and Gas Wells Under the Newsom Administration

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California regulators halt well permitting after Consumer Watchdog and FracTracker reveal a surge in well permits under California Governor Newsom

October 24th, 2019 update: 

There have been several exciting updates since FracTracker Alliance and Consumer Watchdog released a report on fracking and regulatory corruption under Governor Newsom’s administration, detailed in the article below.

On July 11th, 2019, immediately following the report’s release, Governor Newsom fired Ken Harris, head of California’s Division of Oil, Gas, and Geothermal Resources (DOGGR).

Newsom’s chief of staff Ann O’Leary stated:
“The Governor has long held concerns about fracking and its impacts on Californians and our environment, and knows that ultimately California and our global partners will need to transition away from oil and gas extraction. In the weeks ahead, our office will work with you to find new leadership of (the division) that share this point of view and can run the division accordingly.”
FracTracker Alliance supports the governor’s decision and hopes that new leadership acts in the best interests of Californians while moving the state towards 100% renewable energy.

Two months later in September, it was announced that no new fracking permits had been approved in California since the report was issued. We’re thrilled to see this immediate cessation. Yet, while new fracking activity has halted, other forms of oil and gas development continue to threaten Californian’s health and natural resources.

FracTracker Alliance’s review of public records found that DOGGR issued approximately 1,200 permits for steam injection and other “enhanced recovery” techniques through September 2nd, a 60% increase from the 749 permits issued in the same period last year. Sources within DOGGR revealed that at least 40 illegal oil spills from wells were ongoing in Kern and Santa Barbara Counties.

A final development came on October 12th, when Governor Newsom signed a bill to prevent oil and gas development on state lands. As state lands often neighbor federal lands, this bill will play a role in protecting federal land from pipelines, wells, and other polluting infrastructure. Newsom also changed the name of DOGGR to the “Geologic Energy Management Division,” and modified its mission to include protecting public health and environmental quality.

We remain hopeful that Newsom will take a bold stance in leading California away from fossil fuels.

Original July 11th, 2019 FracTracker article:

FracTracker Alliance and Consumer Watchdog have uncovered new data showing an increase in oil and gas permitting by California regulators in 2019 compared to 2018, calling into question Governor Gavin Newsom’s climate commitment. Even more concerning, this investigation found that state regulators are heavily invested in the oil companies they regulate.

FracTracker Alliance’s new report with Consumer Watchdog compares oil and gas permitting policies of the current Governor Gavin Newsom’s administration with that of former Governor Jerry Brown’s administration.

The former lieutenant governor to Brown, Governor Newsom has set out to make a name for himself. As part of stepping out of Brown’s shadow, Newsom has expressed support for a Just Transition away from fossil fuels. Governor Newsom’s 2020 budget plan includes environmental justice measures and an unprecedented investment to plan for this transition that includes investments in job training.

Yet five months into Governor Newsom’s first term, regulators are on track to allow companies to drill and “frack” more new oil and gas wells than Brown allowed in 2018. The question now is: will Governor Newsom actually take the next step that Brown could not, and prioritize the reduction of oil extraction in California?

In addition, the Consumer Watchdog report reveals that eight California regulators with the Division of Oil, Gas, and Geothermal Resources (DOGGR) are heavily invested in the oil companies they regulate. FracTracker and Consumer Watchdog are calling for the the removal of DOGGR officials with conflicts of interest, and an immediate freeze on new well approval. Read the letter to Governor Newsom here.

Governor Brown’s Legacy

Around the world, Brown is recognized as a climate warrior. His support of solar energy technology and criticisms of the nuclear and fossil fuel industry was ultimately unique in the late 1970’s.

In 1980, during his second term as Governor and short presidential campaign, he decried that fellow democrat and incumbent President Jimmy Carter had made a “Faustian bargain” with the oil industry. Since then, he has continued to push for state controls on greenhouse gas emissions. To end his political career, Brown hosted an epic climate summit in San Francisco, California, which brought together climate leaders, politicians, and scientists from around the world.

While Brown championed the reduction of greenhouse gas emissions, his policies in California were contradictory. While front-line communities called for setbacks from schools, playgrounds, hospitals and other sensitive receptors, Brown ignored these requests. Instead he sought to spur oil production in the state. Brown even used state funds to explore his private properties for oil and mineral resources that could be exploited for personal profit.

Brown’s terms in the Governor’s office show trends of increasing oil and gas production. The chart in Figure 1 shows that during his first term (1979-1983), California oil extraction grew towards a peak in production. Then in 2011 at the start of Brown’s second term (2011-2019), crude oil production again inflected and continued to increase through 2015, ending a 25-year period of relatively consistent reduction.

We are therefore interested in looking at existing data to understand if moving forward, Governor Newsom will continue Brown’s legacy of support for California oil production. We start by looking at the first half of 2019, the beginning of Governor Newsom’s term, to see if his administration will also allow the oil and gas industry to increase extraction in California.

Figure 1. Chart of California’s historic oil production, from the EIA

Analysis

The FracTracker Alliance has collaborated with the non-profit Consumer Watchdog to review records of oil and gas well permits issued in 2018 and thus far into 2019.

Records of approved permits were obtained from the CA Department of Conservation’s Division of Oil Gas and Geothermal Resources (DOGGR). Weekly summaries of approved permits for the 52 weeks of 2018 and the first 22 weeks of 2019 (January 1st-June 3rd) were compiled, cleaned, and analyzed. Notices of well stimulations were also included in this analysis. The data is mapped here in the Consumer Watchdog report, as well as in more detail below in the map in Figure 2.

Figure 2. Map of California’s Permits, 2018 and 2019


View map fullscreen | How FracTracker maps work

Findings

At FracTracker, we are known for more than simply mapping, so we have, of course, extracted all the information that we can from this data. The dataset of DOGGR permits included details on the type of permit as well as when, where, and who the permits were granted. With this information we were able to answer several questions.

Of particular note and worthy of prefacing the data analysis was the observation of the very low numbers of permits granted in the LA Basin and Southern California, as compared to the Central Valley and Central Coast of California.

First, what are the types of permits issued?

Regulators require operators to apply for permits for a number of activities at well sites. This dataset includes permits to drill wells, including re-drilling existing wells, permits to rework existing wells, and permits to “sidetrack”. Well stimulations using techniques such as hydraulic fracturing and acid fracturing also require permits, as outline in CA State Bill 4.

How many permits have regulators issued?

In 2018, DOGGR approved 4,368 permits, including 2,124 permits to drill wells. In 2019, DOGGR approved 2,366 permits from January 1 – June 3, including 1,212 permits to drill wells. At that rate, DOGGR will approve 5,607 total permits by the end of 2019, including 2,872 wells.

That is an increase of 28.3% for total permits and an increase of 35.3% for drilling oil and gas wells.

DOGGR also issued 222 permits for well stimulations in 2018. So far in 2019, DOGGR has issued 191 permits for well stimulations, an increase of 103.2%.

Who is applying for permits?

As shown in Table 1 below, the operators Chevron U.S.A. Inc., Aera Energy LLC ( a joint conglomerate of Shell Oil Company and ExxonMobil), and Berry Petroleum Company, LLC dominate the drilling permit counts for both 2018 and 2019.

Aera has obtained the most drilling permits thus far into 2019, while Chevron obtained the most permits in 2018, almost 100 more than Aera. In 2019, Chevron was issued almost 3 times the amount of rework permits as Aera, and both have outpaced Berry Petroleum.

Table 1. Permit Counts by Operator

Where are the permits being issued?

Data presented in Table 2 indicate which fields are being targeted for drilling and rework permits. While the 2019 data represents less than half the year, the number of drilling permits is almost equal to the total drilling permit count for 2018.

Majority players in the Midway-Sunset field are Berry Petroleum and Chevron. South Belridge is dominated by Aera Energy and Berry Petroleum. The Cymric field is mostly Chevron and Aera Energy; McKittrick is mostly Area Energy and Berry Petroleum. The Kern River field, which has by far the most reworks (most likely due to its massive size and age) is entirely Chevron.

Table 2. Permit Counts by Field

Conclusions

Be sure to also read the Consumer Watchdog report on FracTracker’s permit data!

The details of this analysis show that DOGGR has allowed for a modest increase in permits for oil and gas wells in 2019. The increase in well stimulations in 2019 is estimated to be larger, at 103.2%.

There was the consideration that this could be a seasonal phenomenon since we extrapolated from data encompassing just less than the first half of the year. But upon reviewing data for several other years, that does not seem to be the case. The general trend was instead increasing numbers of permits as each year progresses, with smaller permit counts through the first half of the year.

Oil prices do not provide much explanation either. The chart in Figure 3 shows that crude prices were higher in 2018 than they have been for the vast majority of 2019. The increase in permits could be the result of oil and gas operators like Chevron and Aera anticipating a stricter regulatory climate under Governor Newsom. Operators may be securing  as many permits as possible, while DOGGR is still liberally issuing them. This could be a consequence of the Governor’s recognition of the need for California to begin a managed decline of fossil fuel production and end oil drilling in California.

Could this be an early industry death rattle?

Figure 3. Crude prices in 2018 and 2019

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

Urban Drilling in Los Angeles
Kyle Ferrar, MPH

Impact of a 2,500′ Oil and Gas Well Setback in California

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Why does California need setbacks?

A new bill proposed by California State Assembly Member Al Muratsuchi (D), AB345, seeks to establish a minimum setback distance of 2,500′ between oil and gas wells and sensitive sites including occupied dwellings, schools, healthcare facilities, and playgrounds. A setback distance for oil and gas development is necessary from a public health standpoint, as the literature unequivocally shows that oil and gas wells and the associated infrastructure pose a significant risk to the communities that live near them.

FracTracker Alliance conducted a spatial analysis to understand the impact a 2,500’ well setback would have on oil and gas expansion in California. In a previous report, The Sky’s Limit California (Oil Change Internal, 2018), Fractracker data showed that 8,493 active or newly permitted oil and gas wells were located within a 2,500’ buffer of sensitive sites. At the time it was estimated that 850,000 Californians lived within the setback distance of at least one of these oil and gas wells.

This does not bode well for Californians, as a recently published FracTracker literature review found that health impacts resulting from living near oil and gas development include cancer, infant mortality, depression, pneumonia, asthma, skin-related hospitalizations, and other general health symptoms. Studies also showed that health impacts increased with the density of oil and gas development, suggesting that health impacts are dose dependent. Living closer to more oil and gas sites means you are exposed to more health-threatening contamination.

An established setback is therefore necessary to alleviate some of these health burdens carried by the most vulnerable Environmental Justice (EJ) communities. Health assessments by the Los Angeles County Department of Health and studies on ambient air quality near oil fields by Occidental College Researchers support the assumption that 2,500′ is the necessary distance to help alleviate the harsh conditions of degraded air quality. Living at a distance beyond 2,500′ from an oil and gas site does not mean you are not impacted by air and water contamination. Rather the concentrations of contaminants will be less harmful. In fact studies showed that health impacts increased with proximity to oil and gas, with associated impacts potentially experienced by communities living at distances up to 9.3 miles (Currie et al. 2017) and 10 miles (Whitworth et al. 2017).

Assembly Bill 345

This analysis assesses the potential impact of State Assembly member Al Muratsuchi’s Assembly Bill 345 on California’s oil and gas extraction and production. Specifically, AB345 establishes a minimum 2,500’ setback requirement for future oil and gas development. It does not however directly address existing oil and gas permits.

The bill includes the following stipulations and definitions:

  • All new oil and gas development, that is not on federal land, are required to be located at least 2,500′ from residences, schools, childcare facilities, playgrounds, hospitals, or health clinics.
  • In this case the redrilling of a previously plugged and abandoned oil or gas well or other rework operation is to be considered new oil and gas development.
  • “Oil and gas development” means exploration for and drilling production and processing of oil, gas or other gaseous and liquid hydrocarbons; the flowlines; and the treatment of waste associated with that exploration, drilling, production, and processing.
  • “Oil and gas development” also includes hydraulic fracturing and other stimulation activities.
  • “Rework operations” means operations performed in the well bore of an oil or gas well after the well is completed and equipped for production, done for the purpose of securing, restoring, or improving hydrocarbon production in the subsurface interval that is the open to production in the well bore.
  • The bill does not include routine repairs or well maintenance work.

Map

Figure 1. Map of Wells within a 2,500′ Setback Distance from Sensitive Receptor Sites. The map below shows the oil and gas wells and permits that fall within the 2,500′ setback distance from sensitive receptor sites.  Summaries of these well counts and discussions of these well types are included below as well.

Map of Wells within a 2,500′ Setback Distance from Sensitive Receptor Sites

View map fullscreen | How FracTracker maps work

 

Environmental Justice

The California Environmental Justice Alliance (CEJA) has just released their 2018 Environmental Justice Agency Assessment, which used FracTracker’s data and mapping to assess environmental equity in the state regulation of oil permitting and drilling. The report issued the Division of Oil, Gas, and Geothermal Resources (DOGGR) a failing grade of ‘F’. According to the report, “DOGGR is aware that the proposed locations of many drilling activities are in or near EJ communities, but approves permits irrespective of known health and safety risks associated with neighborhood drilling.”

FracTracker’s analysis of low income communities in Kern County shows the following:

  • There are 16,690 active oil and gas production wells located in census blocks with median household incomes of less than 80% of Kern’s area median income (AMI).
  • Therefore about 25% (16,690 out of 67,327 total) of Kern’s oil and gas wells are located within low-income communities.
  • Of these 16,690 wells, 5,364 of them are located within the 2,500′ setback distance from sensitive receptor sites such as schools and hospitals (32%) vs 13.1% for the rest of the state.

For more information on the breakdown of Kern County wells, see our informational table, here.

DOGGR wells

Using freshly published Division of Oil, Gas, and Geothermal Resources (DOGGR) data (6/3/19), we find that there are 9,835 active wells that fall within the 2,500’ setback distance, representing 13.1% of the total 74,775 active wells in the state.

There are 6,558 idle wells that fall within the 2,500’ setback distance, of nearly 30,000 total idle wells in the state. Putting these idle wells back online would be blocked if the wells require reworks to restart or ramp up production. For the most part operators do not intend for most idle wells to come back online. Rather operators are just avoiding the costs of plugging and properly abandoning the wells. To learn more about this issue, see our recent coverage of idle wells here.

Of the 3,783 permitted wells not yet in production, or “new wells,” 298 (7.8%) are located within the 2,500’ buffer zone.

Getting a count of plugged wells within the setback distance is more difficult because there is not a complete dataset, but there are over 30,000 wells in areas with active production that would be blocked from being redrilled. In total there are 122,209 plugged wells listed in the DOGGR database.

Permits

We also looked at permit applications that were approved in 2018, including permits for drilling new wells, well reworks, deepening wells and well sidetracks. This may be the most insightful of all the analyses.

Within the 2018 permit data, we find that 4,369 permits were approved. Of those 518 permits (about 12%) were granted within the proposed 2,500’ setback. Of the permits 25% were for new drilling, 73% were for reworks, and 2% were for deepening existing wells. By county, 42% were in Kern, 24% were in Los Angeles, 14% in Ventura, 6% in Santa Barbara, 3% in Fresno, and 2% or less in Glenn, Monterey, Sutter, San Joaquin, Colusa, Solano, Orange and Tehama, in descending order.

SCAQMD Notices

In LA, Rule 1148.2 requires operators to notify the South Coast Air Quality Management District (SCAQMD) of activities at well sites, including stimulations and reworks. These data points are reiterative of the “permits” discussed above, but the dataset is specific to the SCAQMD and includes additional activities. Of the 1,361 reports made to the air district since the beginning of 2018 through April 1, 2019; 634 (47%) were for wells that would be impacted by the setback distance; 412 incidences were for something other than “well maintenance” of which 348 were for gravel packing, 4 for matrix acidizing, and 65 were for well drilling. We are not sure where gravel packing falls, in reference to AB345.

A major consideration is that this rule may force many active wells into an idle status. If the onus of plugging wells falls on the state, these additional idle wells could be a major liability for the public. Fortunately AB1328 recently defined new idle well rules. The rules entice operators to plug and abandon idle wells. If rule 1328 is effective at reducing the stock of idle wells, these two bills could complement each other. (For more information on idle wells, read FracTracker’s recent analysis, here: https://www.fractracker.org/2019/04/idle-wells-are-a-major-risk/)

State Bill 4 Well Stimulation Reporting

We also analyzed data reported to DOGGR under the well stimulation requirements of CA State Bill 4 (SB4), the 2013 bill that 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. Since 2016 operators have been required to secure special permits to stimulate wells, which includes hydraulic fracturing and several other techniques. To learn more about this state regulation read FracTracker’s coverage of SB4. From January 1, 2016 to April 1, 2019, there have been 576 well stimulation treatment permits granted under the SB4 regulations. Only 1 hydraulic fracturing event, permitted in Goleta, would have been impacted by a 2,500’ setback in 2018.

Support for AB345

After being approved by the CA Assembly Natural Resources Committee in a 7-6 vote, the bill did not make it up for a vote in the Senate Appropriations Committee during the 2019 legislative session.  The bill was described by the committee as “promising policies that need more time for discussion.” AB345 is now a two-year bill in the state Senate and will be reconsidered by the committee in January of 2020. The Chairperson of the Appropriations Committee, Lorena Gonzalez, indicated her general support for the policy and committed to working with the author to find a way to move the bill forward at the end of the session.

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance 

Feature image by David McNew, Getty Images

Matt Kelso, BA

Production and Location Trends in PA: A Moving Target

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The FracTracker Alliance tends to look mostly at the impacts of drilling, from violations affecting surface and ground water to forest fragmentation to neighbors breathing diesel exhaust near disposal wells.  We also try to give residents tools to help predict where future activity will occur, but as this article details, such predictive tools can do little more than trail moving targets. To that end, we have taken a look into areas where gas production is high for unconventional wells in the state, which are likely sites of future development.

The Pennsylvania Department of Environmental Protection’s (DEP) Production Report is self-reported by the various operators active in the state. Unconventional wells generate a large quantity of natural gas, measured in thousands of cubic feet (Mcf), as well as limited amounts of oil and condensate, both of which are measured in 42 gallon barrels. In this analysis, we are only considering the gas production.

Click here for full screen map. 

In the map above, you can click on any well to learn more about the production values, along with a variety of other information including the well’s formation and age.  The age was calculated by counting days from the spud date to the end of the report cycle, March 31, 2019.

 

Top Average Gas Production by County – April 2018 to March 2019

CountyProducing Wells Avg. Production (Mcf) Production Rank Avg. Age of Producing WellsAge Rank
Wyoming 2511,269,15615 Yr / 10 Mo / 4 Days12
Sullivan1281,087,86825 Yr / 2 Mo/ 24 Days8
Allegheny1171,075,01834 yr/ 2 Mo / 7 Days2
Susquehanna1,4291,066,73445 Yr / 6 Mo / 22 Days10
Greene1,131796,75555 yr / 10 Mo / 28 Days13
Figure 1 – This table shows the top five counties in Pennsylvania for per-well unconventional gas production. The final column shows the county ranking for the average age of wells, from youngest to oldest

We can also see this data summarized by county, where average production and age values are available on a county by county basis (see Figure 1). Hydrocarbon wells are known to decrease production steeply over time, a phenomenon known as the decline curve, so it is not surprising to see a relatively young inventory of wells represented in the list of top five counties with per-well gas production. Age is not the only factor in production values, however, as certain geographies simply contain more accessible gas resources than others.

 

Figure 2 – 12 month gas production and age of well. Production is usually much higher during the earliest phases of the well’s production life.  This does not include wells that have been plugged or taken out of production.  Click on image for full-sized view.

In Figure 2, we look at the production of all unconventional wells in the state, expecting to see the highest production in younger wells. This mostly appears to be the case, but as mentioned above, there are also hot and cold spots with respect to production. A notable variable in this consideration is producing formation.

Since 93% (8,730 out of 9,404) of unconventional wells reporting gas production are in the Marcellus Shale Formation, the traditional hot spots in the northeastern and southwestern portions of the state heavily skew the overall totals in terms of both production and number of wells.  Other formations of note include the Onodaga Limestone (137 wells, 1.5% of total), Burket Member (117 wells, 1.2%), Genesee Formation (104 wells, 1.1%), and the Utica Shale (99 wells, 1.1%) (Figure 3).

Figure 3 – Unconventional gas production over 12 months, showing formation. Click on image for full-sized view.

Drillers have been exploring some of these formations for decades. In fact, the oldest producing well that is currently classified as unconventional was 13,435 days old as of March 31, which works out to 36 years, 9 months, and 12 days.

However, this is fairly rare – only 384 (4%) of the 9,404 producing wells were more than 10 years old. 5,981 wells (64%) are between 5 and 10 years old, with the remaining 3,039 wells (32%) younger than 5 years old.

This does not take into account wells of any age that have been plugged or otherwise taken out of production.

Age of Pennsylvania’s active wells

< 5 years old
5-10 years old
> 10 years old

 

Utica Shale

The Utica Shale is worth a special mention here for a couple of reasons.  First, we must acknowledge its prominence in neighboring Ohio, which has 2,160 permitted Utica wells to go with just 40 permitted Marcellus wells, the prevalence of the two plays seems to invert just as one passes over the state line. And yet, the most productive Utica wells are near the border with New York, not Ohio.

In fact, each of the top 11 producing Utica wells during the 12 month period were located in Tioga County.  It’s worth noting that these are all between one and two years old, which would have given the wells time to be drilled, fracked, and brought into production, while still being in the prime of their production life. Compared to the Marcellus, sample size quickly becomes an issue when analyzing the Utica in Pennsylvania (Figure 4).

Figure 4 – Producing Utica wells in Pennsylvania. Note that the cluster of heavily producing wells in Tioga and Potter Counties near the New York border are mostly young wells where higher production would be expected.  Click on image for full sized view.

Second, portions of the Utica are known for their wet gas content, meaning that the gas has significant quantities of natural gas liquids (NGLs) including ethane, propane, and butane, which are gaseous at ambient temperatures but typically condensed into liquid form by oil and gas companies.  These are used for specialized fuels and petrochemical feedstocks, and are therefore more valuable than the methane in natural gas.

The production report does not capture the amount of NGLs in the gas, but a map from the Energy Information Administration shows the entire play, noting that the composition is dryer on the eastern portions of the play. In fact, a wet gas composition along the Ohio border might help to explain continued interest in what are otherwise well below average gas production results for Pennsylvania.

A Moving Target

It is difficult to predict where the industry will focus its attention in the coming months and years, but taking a look at production and formation data can give us a few clues.  Obviously, operators who found a particularly productive pocket of hydrocarbons are likely to keep drilling more holes in the ground in those areas until production is no longer profitable. Therefore, impacts to water, air, and nearby residents can be expected to continue in heavily drilled areas largely because the production level makes it attractive for drillers.

On the other hand, we should not assume that areas that are currently not productive are off the table for future consideration, either. Different formations are productive in different geographies, so a sweet spot for the Marcellus might be a dud in the Utica, or vice versa.

Finally, when comparing production, we must always take the age of the well into consideration, as all oil and gas wells can be expected to start off with a short period of very high production, followed by years of ever-diminishing returns throughout the expected 10 to 11 year lifecycle of the well. Because of this, what seems like a hotspot now may look below average in a similar analysis in three to four years, particularly in formations with relatively light drilling activity. This means that the top list of production by well could change over time, so be sure to check back in with FracTracker to see how events unfold.

By Matt Kelso, Manager of Data and Technology, FracTracker Alliance

 

https://www.kvpr.org/post/dormant-risky-new-state-law-aims-prevent-problems-idle-oil-and-gas-wells
Kyle Ferrar, MPH

Idle Wells are a Major Risk

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Designating a well as “idle” is a temporary solution for operators, but comes at a great economic and environmental cost to Californians 

Idle wells are oil and gas wells which are not in use for production, injection, or other purposes, but also have not been permanently sealed. During a well’s productive phase, it is pumping and producing oil and/or natural gas which profit its operators, such as Exxon, Shell, or California Resources Corporation. When the formations of underground oil pools have been drained, production of oil and gas decreases. Certain techniques such as hydraulic fracturing may be used to stimulate additional production, but at some point operators decide a well is no longer economically sound to produce oil or gas. Operators are supposed to retire the wells by filling the well-bores with cement to permanently seal the well, a process called “plugging.”

A second, impermanent option is for operators to forego plugging the well to a later date and designate the well as idle. Instead of plugging a well, operators cap the well. Capping a well is much cheaper than plugging a well and wells can be capped and left “idle” for indefinite amounts of time.

Well plugging

Unplugged wells can leak explosive gases into neighborhoods and leach toxic fluids into drinking waters. Plugging a well helps protect groundwater and air quality, and prevents greenhouse gasses from escaping and expediting climate change. Therefore it’s important that idle wells are plugged.

While plugging a well does not entirely eliminate all risk of groundwater contamination or leaking greenhouse gases, (read more on FracTracker’s coverage of plugged wells) it does reduce these risks. The longer wells are left idle, the higher the risk of well casing failure. Over half of California’s idle wells have been idle for more than 10 years, and about 4,700 have been idle for over 25 years. A report by the U.S. EPA noted that California does not provide the necessary regulatory oversite of idle wells to protect California’s underground sources of drinking water.

Wells are left idle for two main reasons: either the cost of plugging is prohibitive, or there may be potential for future extraction when oil and gas prices will fetch a higher profit margin.  While idle wells are touted by industry as assets, they are in fact liabilities. Idle wells are often dumped to smaller or questionable operators.

Orphaned wells

Wells that have passed their production phase can also be “orphaned.” In some cases, it is possible that the owner and operator may be dead! Or, as often happens, the smaller operators go out of business with no money left over to plug their wells or resume pumping. When idle wells are orphaned from their operators, the state becomes responsible for the proper plugging and abandonment.

The cost to plug a well can be prohibitively high for small operators. If the operators (who profited from the well) don’t plug it, the costs are externalized to states, and therefore, the public. For example, the state of California plugged two wells in the Echo Park neighborhood of Los Angeles at a cost of over $1 million. The costs are much higher in urban areas than, say, the farmland and oilfields of the Central Valley.

Since 1977, California has permanently sealed about 1,400 orphan wells at a cost of $29.5 million, according to reports by the Division of Oil, Gas, and Geothermal Resources (DOGGR). That’s an average cost of about $21,000 per well, not accounting for inflation. From 2002-2018, DOGGR plugged about 600 wells at a cost of $18.6 million; an average cost of about $31,000.

Where are they?

Map of California’s Idle Wells


View map fullscreen | How FracTracker maps work

The map above shows the locations of idle wells in California.  There are 29,515 wells listed as idle and 122,467 plugged or buried wells as of the most recent DOGGR data, downloaded 3/20/19. There are a total of 245,116 oil and gas wells in the state, including active, idle, new (permitted) or plugged.

Of the over 29,000 wells are listed as idle, only 3,088 (10.4%) reported production in 2018. Operators recovered 338,201 barrels of oil and 178,871 cubic feet of gas from them in 2018. Operators injected 1,550,436,085 gallons of water/steam into idle injection wells in 2018, and 137,908,884 cubic feet of gas.

The tables below (Tables 1-3) provide the rankings for idle well counts by operator, oil field, and county (respectively).  Chevron, Aera, Shell, and California Resources Corporation have the most idle wells. The majority of the Chevron idle wells are located in the Midway Sunset Field. Well over half of all idle wells are located in Kern County.

Table 1. Idle Well Counts by Operator
Operator Name Idle Well Count
1 Chevron U.S.A. Inc. 6,292
2 Aera Energy LLC 5,811
3 California Resources Production Corporation 3,708
4 California Resources Elk Hills, LLC 2,016
5 Berry Petroleum Company, LLC 1,129
6 E & B Natural Resources Management Corporation 991
7 Sentinel Peak Resources California LLC 842
8 HVI Cat Canyon, Inc. 534
9 Seneca Resources Company, LLC 349
10 Crimson Resource Management Corp. 333

 

Table 2. Idle Well Counts by Oil Field
Oil Field Count by Field
1 Midway-Sunset 5,333
2 Unspecified 2,385
3 Kern River 2,217
4 Belridge, South 2,075
5 Coalinga 1,729
6 Elk Hills 958
7 Buena Vista 887
8 Lost Hills 731
9 Cymric 721
10 Cat Canyon 661

 

Table 3. Idle Well Counts by County
County Count by County
1 Kern 17,276
2 Los Angeles 3,217
3 Fresno 2,296
4 Ventura 2,022
5 Santa Barbara 1,336
6 Orange 752
7 Monterey 399
8 Kings 212
9 San Luis Obispo 202
10 Sutter 191

 

Risks

According to the Western States Petroleum Association (WSPA) the count of idle wells in California has increased from just over 20,000 idle wells in 2015 to nearly 30,000 wells in 2018! That’s an increase of nearly 50% in just 3 years!

Nobody knows how many orphaned wells are actually out there, beneath homes, in forests, or in the fields of farmers. The U.S. EPA estimates that there are more than 1 million of them across the country, most of them undocumented. In California, DOGGR officially reports that there are 885 orphaned wells in the state.

A U.S. EPA report on idle wells published in 2011 warned that existing monitoring requirements of idle wells in California was “not consistent with adequate protection” of underground sources of drinking water. Idle wells may have leaks and damage that go unnoticed for years, according to an assessment by the state Department of Conservation (DOC). The California Council on Science and Technology is actively researching this and many other issues associated with idle and orphaned wells. The published report will include policy recommendations considering the determined risks. The report will determine the following:

  • State liability for the plugging and abandoning of deserted and orphaned wells and decommissioning facilities attendant to such wells
  • Assessment of costs associated with plugging and abandoning deserted and orphaned wells and decommissioning facilities attendant to such wells
  • Exploration of mechanisms to ameliorate plugging, abandoning, and decommissioning burdens on the state, including examples from other regions and questions for policy makers to consider based on state policies

Current regulation

As of 2018, new CA legislation is in effect to incentivize operators to properly plug and abandon their stocks of idle wells. In California, idle wells are defined as wells that have not had a 6-month continuous period of production over a 2-year period (previously a 5-year period). The new regulations require operators to pay idle well fees.  The fees also contribute towards the plugging and proper abandonment of California’s existing stock of orphaned wells. The new fees are meant to act as bonds to cover the cost of plugging wells, but the fees are far too low:

  • $150 for each well that has been idle for 3 years or longer, but less than 8 years
  • $300 for each well that has been idle for 8 years or longer, but less than 15 years
  • $750 for each well that has been idle for 15 years or longer, but less than 20 years
  • $1,500 for each well that has been idle for 20 years or longer

Operators are also allowed to forego idle well fees if they institute long-term idle well management and elimination plans. These management plans require operators to plug a certain number of idle wells each year.

In February 2019, State Assembly member Chris Holden introduced an idle oil well emissions reporting bill. Assembly bill 1328 requires operators to monitor idle and abandoned wells for leaks. Operators are also required to report hydrocarbon emission leaks discovered during the well plugging process. The collected results will then be reported publicly by the CA Department of Conservation. According to Holden, “Assembly Bill 1328 will help solve a critical knowledge gap associated with aging oil and gas infrastructure in California.”

While the majority of idle wells are located in Kern County, many are also located in California’s South Coast region. Due to the long history and high density of wells in the Los Angeles, the city has additional regulations. City rules indicate that oil wells left idle for over one year must be shut down or reactivated within a month after the city fire chief tells them to do so.

Who is responsible?

All of California’s wells, from Kern County to three miles offshore, on private and public lands, are managed by DOGGR, a division of the state’s Department of Conservation. Responsibilities include establishing and enforcing the requirements and procedures for permitting wells, managing drilling and production, and at the end of a well’s lifecycle, plugging and “abandoning” it.

To help ensure operator liability for the entire lifetime of a well, bonds or well fees are required in most states. In 2018, California updated the bonding requirements for newly permitted oil and gas wells. These fees are in addition to the aforementioned idle well fees. Operators have the option of paying a blanket bond or a bond amount per well. In 2018, these fees raised $4.3 million.

Individual well fees:

  • Wells less than 10,000 feet deep: $10,000
  • Wells more than 10,000 feet deep: $25,000

Blanket fees:

  • Less than 50 wells: $200,000
  • 50 to 500 wells: $400,000
  • 500 to 10,000 wells: $2,000,000
  • Over 10,000 wells: $3,000,000

With an average cost of at least $31,000 to plug a well, California’s new bonding requirements are still insufficient. Neither the updated individual nor blanket fees provide even half the cost required to plug a typical well.

Conclusions

Strategies for the managed decline of the fossil fuel industry are necessary to make the proposal a reality. Requiring the industry operators to shut down, plug and properly abandon wells is a step in the right direction, but California’s new bonding and idle well fees are far too low to cover the cost of orphan wells or to encourage the plugging of idle wells. Additionally, it must be stated that even properly abandoned wells have a legacy of causing groundwater contamination and leaking greenhouse gases such as methane and other toxic VOCs into the atmosphere.

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

Cover photo: Kerry Klein, Valley Public Radio

DOGGR
Kyle Ferrar, MPH

Literally Millions of Failing, Abandoned Wells

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By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

In California’s Central Valley and along the South Coast, there are many communities littered with abandoned oil and gas wells, buried underground.

Many have had homes, buildings, or public parks built over top of them. Some of them were never plugged, and many of those that were plugged have since failed and are leaking oil, natural gas, and toxic formation waters (water from the geologic layer being tapped for oil and gas). Yet this issue has been largely ignored. Oil and gas wells continue to be permitted without consideration for failing and failed plugged wells. When leaking wells are found, often nothing is done to fix the issue.

As a result, greenhouse gases escape into the atmosphere and present an explosion risk for homes built over top of them. Groundwater, including sources of drinking water, is known to be impacted by abandoned wells in California, yet resources are not being used to track groundwater contamination.

Abandoned wells: plugged and orphaned

The term “abandoned” typically refers to wells that have been taken out of production. At the end of their lifetime, wells may be properly abandoned by operators such as Chevron and Shell or they may be orphaned.

When operators properly abandon wells, they plug them with cement to prevent oil, natural gas, and salty, toxic formation brine from escaping the geological formation that was tapped for production. Properly plugging a well helps prevent groundwater contamination and further air quality degradation from the well. The well-site at the surface may also be regraded to an ecological environment similar to its original state.

Wells that are improperly abandoned are either plugged incorrectly or are “orphaned” by their operators. When wells are orphaned, the financial liability for plugging the well and the environmental cleanup falls on the state, and therefore, the taxpayers.

You don’t see them?

In California’s Central Valley and South Coast abandoned wells are everywhere. Below churches, schools, homes, they even under the sidewalks in downtown Los Angeles!

FracTracker Alliance and Earthworks recently spent time in Los Angeles with an infrared camera that shows methane and volatile organic compound (VOC) emissions. We visited several active neighborhood drilling sites and filmed plumes of toxic and carcinogenic VOCs floating over the walls of well-pads and into the surrounding neighborhoods. We also visited sites where abandoned, plugged wells had failed.

In the video below, we are standing on Wilshire Blvd in LA’s Miracle Mile District. An undocumented abandoned well under the sidewalk leaks toxic and carcinogenic VOCs through the cracks in the pavement as mothers push their children in walkers through the plume. This is just one case of many that the state is not able to address.

California regulatory data shows that there are 122,466 plugged wells in the state, as shown below in the map below. Determining how many of them are orphaned or improperly plugged is difficult, but we can come up with an estimate based on the wells’ ages.

While there are no available data on the dates that wells were plugged, there are data on “spud dates,” the date when operators begin drilling into the ground. Of the 18,000 wells listing spud dates, about 70% were drilled prior to 1980. Wells drilled before 1980 have a higher risk of well casing failures and are more likely to be sources of groundwater contamination.

Additionally, wells plugged prior to 1953 are not considered effective, even by industry standards. Prior to 1950, wells either were orphaned or plugged and abandoned with very little cement. Plugging was focused on protecting the oil reservoirs from rain infiltration rather than to “confine oil, gas and water in the strata in which they are found and prevent them from escaping into other strata.” Of the wells with drilling dates in the regulatory data, 30% are listed as having been drilled prior to the use of cement in well plugging.

With a total of over 245,000 wells in the state database, and considering the lack of monitoring prior to 1950, it’s reasonable to assume there are over 80,000 improperly plugged and unplugged wells in California.

Map of California’s Plugged Wells

View map fullscreen | How FracTracker maps work

The regions with the highest counts of plugged wells are the Central Valley and the South Coast. The top 10 county ranks are listed below in Table 1. Kern County has more than half of the total plugged wells in the entire state.

Table 1. Ranks of Counties by Plugged Well Counts
  • Rank
  • 1
  • 2
  • 3
  • 4
  • 5
  • 6
  • 7
  • 8
  • 9
  • 10
  • County
  • Kern
  • Los Angeles
  • Orange
  • Fresno
  • Ventura
  • Santa Barbara
  • Monterey
  • San Luis Obispo
  • Solano
  • Yolo
  • Plugged Well Count
  • 65,733
  • 17,139
  • 7,259
  • 6,970
  • 4,302
  • 4,192
  • 2,266
  • 1,463
  • 1,456
  • 1,383

The issue is not unique to California. Nationally, an estimated 2.56 million oil and gas wells have been drilled and 1.93 million wells had been abandoned by 1975. Using interpolated data, the EPA estimates that as of 2016 there were 3.12 million abandoned wells in the U.S. and 69% of them were left unplugged.

In 2017, FracTracker Alliance organized an exercise to track down the locations of Pennsylvania’s abandoned wells that are not included in the PA Department of Environmental Protection’s digital records. Using paper maps and the FracTracker Mobile App, volunteers explored Pennsylvania woodlands in search of these hidden greenhouse gas emitters.

What are the risks?

Emissions

Studies by Kang et al. 2014, Kang et al 2016, Boothroyd et al 2016, and Townsend-Small et al. 2016 have all measured methane emissions from abandoned wells. Both properly plugged and improperly abandoned wells have been shown to leak methane and other VOCs to the atmosphere as well as into the surrounding groundwater, soil, and surface waters. Leaks were shown to begin just 10 years after operators plugged the wells.

Well density

The high density of aging and improperly plugged wells is a major risk factor for the current and future development of California’s oil and gas fields. When fields with old wells are reworked using new technology, such as hydraulic fracturing, CO2 flooding, or solvent flooding (including acidizing, water flooding, or steam flooding), the injection of additional fluid and gas increases pressure in a reservoir. Poorly plugged or aging wells often lack the integrity to avoid a blowout (the uncontrolled release of oil and/or gas from a well). There is a consistent risk that formation fluids will be forced to migrate up the plugged wellbores and bypass the existing plugs.

Groundwater

In a 2014 report, the U.S. Geological Service warned the California State Water Resources Control Board that the integrity of abandoned wells is a serious threat to groundwater sources, stating, “Even a small percentage of compromised well bores could correspond to a large number of transport pathways.”

The California Council on Science and Technology (CCST) has also suggested the need for additional research on existing aquifer contamination. In 2014, they called for widespread testing of groundwater near oil and gas fields, which has still not occurred.

Leaks

In addition to the contamination of underground sources of drinking water, abandoned well failures can even create a pathway for methane and fluids to escape to Earth’s surface. In many cases, such as in Pennsylvania, Texas, and California, where drilling began prior to the turn of the 20th century, many wells have been left unplugged. Of the abandoned wells that were plugged, the plugging process was much less adequate than it is today.

If plugged wells are allowed to leak, surface expressions can form. These leaks can travel to the Earth’s crust where oil, gas, and formation waters saturate the topsoil. A construction supervisor for Chevron named David Taylor was killed by such an event in the Midway-Sunset oil field near Bakersfield, CA. According to the LA Times, Chevron had been trying to control the pressure at the well-site. The company had stopped injections near the well, but neighboring operators continued high-pressure injections into the pool. As a result, migration pathways along old wells allowed formation fluids to saturate the Earth just under the well-site. Tragically, Taylor fell into a 10-foot diameter crater of 190° fluid and hydrogen sulfide.

California regulations

Following David Taylor’s death in 2011, California regulators vowed to make urgent reforms to the management of underground injection, and new rules finally went into effect on April 1, 2018. These regulations require more consistent monitoring of pressure and set maximum pressure standards. While this will help with the management of enhanced oil recovery operations, such as steam and water flooding and wastewater disposal, the issue of abandoned wells is not being addressed.

New requirements incentivizing operators to plug and abandon idle wells will help to reduce the number of orphan wells left to the state, but nothing has been done or is proposed to manage the risk of existing orphaned wells.

Conclusion

Why would the state of California allow new oil and gas drilling when the industry refuses to address the existing messes? Why are these messes the responsibility of private landholders and the state when operators declare bankruptcy?

New bonding rules in some states have incentivized larger operators to plug their own wells, but old low-producing or idle wells are often sold off to smaller operators or shell (not Shell) companies prior to plugging. This practice has been the main source of orphaned wells. And regardless of whether wells are plugged or not, research shows that even plugged wells release fugitive emissions that increase with the age of the plug.

If the fossil fuel industry were to plug the existing 1.666 million currently active wells, there would be nearly 5 million plugged wells that require regular inspections, maintenance, and for the majority, re-plugging, to prevent the flow of greenhouse gases. This is already unattainable, and drilling more wells adds to this climate disaster.

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

Matt Kelso, BA

Pennsylvania Drilling Trends in 2018

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With the new year underway, it’s an opportune moment to reflect on the state of unconventional oil and gas extraction in Pennsylvania and examine a few of the drilling trends. A logical place to start is looking at the new wells drilled in 2018.

As always, but perhaps even more so than in previous years, unconventional drilling in Pennsylvania is a tale of two shale plays, with hotspots in the southwestern and northeastern corners of the state. The northeastern hotspot seems to be extending westward, including 25 new wells in Jones Township in Elk County (an area shown in dark red near the “St Marys” label on the map). In the southwestern hotspot, the industry continues to encircle Allegheny County, closing in on the City of Pittsburgh like a constrictor.

Screen shot showing spud report for Indiana Township, Allegheny County from 1/1/2017 through 1/4/2019. We suspect these spud dates of 11/29/17 and 11/30/17 are incorrect.

Screen shot showing spud report for Indiana Township, Allegheny County from 1/1/2017 through 1/4/2019. We suspect these spud dates of 11/29/17 and 11/30/17 are incorrect.

Data error? As Pittsburgh-area residents reflect on the past year, some of them must be wondering why a new well pad in Indiana Township, just northeast of the city isn’t shown on the map above. The answer is that the data the Department of Environmental Protection (DEP) has for these wells indicate they were drilled November 29-3o, 2017, although we believe this to be incorrect. FracTracker obtained the data from the Spud Report on January 2, 2019, which indicates seven wells spudded in that two day span on the “Miller Jr. 10602” well pad. This activity drew considerable opposition from families in the Fox Chapel School district in May of 2018, and was therefore widely reported on by the media. An article published on WESA indicates an expected drill date of July 2018, for example.

It turns out the new year is also a good time to remember that our understanding of the oil and gas industry around us is shaped, molded, and limited by the availability and quality of the data. We brought the Indiana Township data error to the attention of DEP, which only confirmed that the operator (Range Resources) entered the spud dates into the DEP’s online system. Perhaps these well were drilled in November of 2018 not 2017? There is even a possibility these wells have yet to be drilled.

Here are a few more dissections of the data, such as it is:

Graph of unconventional (fracking) wells drilled in PA, YTD - Drilling trends

Figure 1: Unconventional wells drilled in PA by year: 2005 to 2018

Wells Drilled Over Time

Barring more widespread data issues, the status of a handful of wells in Indiana Township does not have much of an impact on the overall trend of drilling in the state. There were 779 wells on the report, representing just under 40% of the total from the peak year of 2011, when industry drilled 1,958 wells. The year 2019 was the fourth year in a row where the industry failed to drill 1,000 wells, averaging 719 per year over that span. In contrast, the five years between 2010 and 2014 saw an average of 1,497 wells per year, more than twice the more recent average. As mentioned in our Hazy Future report, projections based on very aggressive drilling patterns are already proving to be out of phase with reality, although petrochemical commodity markets might change drastically in the coming decades.

How long before wells are plugged?

We also like to periodically check to see how long these wells stay in service. In Pennsylvania, there are two relevant well statuses worth following: plugged and regulatory inactive. While there are a number of conditions that characterize regulatory inactive wells, they are essentially drilled wells that are not currently in production, but may have “future utility.” Therefore, the wells are not required to be permanently plugged at this time.

Unconventional wells drilled since 2005 in PA - Drilling trends

Figure 2: This chart shows the percentage of unconventional wells drilled since 2005 with a plugged or regulatory inactive status as of December 31, 2018.

In order to understand some of the finer points, it’s best to use Figure 1 (above) in conjunction with Figure 2. We can see that most of the wells drilled in the initial years of the Marcellus boom have already been plugged, although Figure 1 shows us that the sample size is fairly low for these years. In 2005, for example, 7 of the 9 (78%) unconventional wells drilled in the state that year are already plugged. The following year, 24 of the 37 (65%) wells drilled are now plugged, and an additional 4 (11%) wells have a regulatory inactive status as of the end of 2018. The following year, the combined plugged and inactive wells account for just over 50% of the 113 wells drilled that year, and this trend continues along a fairly predictable curve. An exception is the noticeable bump around the most active drilling years of 2010 and 2011, where there are slightly more wells with a plugged or inactive status than might be expected. It is interesting to note that even the most recent wells are not immune to being plugged, including 8 plugged wells and 4 inactive wells drilled in 2018 that were not able to get past their very first year in production.

Overall, of the 11,675 drilled wells accounted for on this graphic, 851 (7%) are plugged already, with an additional 572 (5%) of wells with an inactive status.  Unconventional wells that are 11 years old have a roughly 50% chance of being plugged or inactive, and we would therefore expect to see the number of these wells skyrocket in the coming years before leveling off, roughly mirroring the drilling boom and subsequent slowdown of Marcellus Shale extraction in Pennsylvania.

Conclusions

Many factors contribute to fluctuations in drilling trends for the Marcellus Shale and other unconventional wells in Pennsylvania. Very cold winters result in high consumption by residential and commercial users. New gas-fired power plants can increase the demand for additional drilling. Recessions and economic conditions are known to reduce the demand for energy as well, and drillers’ heavy debt burdens can slow down operations appreciably. Additionally, other fossil fuel and renewable energy sources compete with one another, altering the market conditions even further. And finally, every oil and gas play eventually reaches a point where the expected results from new wells are not worth the money required to get the hydrocarbons to the surface, and unconventional wells are much more expensive to develop than more traditional operations.

Because of all of these variables, month to month or even year to year fluctuations are not necessarily that telling.  On the other hand, a four-year period where drilling is roughly half of previous extraction is significant, and can’t be easily dismissed as a blip in the data.

By Matt Kelso, Manager of Data and Technology, FracTracker Alliance

Leaking tank in Arvin
Kyle Ferrar, MPH

Arvin, CA Setback Ordinance Passes Unanimously!

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The small city of Arvin, CA has succeeded in taking a brave step forward to protect the public health of its community.

On July 17, 2018 the Arvin City Council voted 3-0 (two members were absent) in support of a setback ordinance. This is the first California oil and gas ordinance that has an actual effect, as it is the first in a region where drilling and fracking are actively occurring. The Arvin, CA setback ordinance prevents wells from being drilled in residential or commercially-zoned spaces. Also, setback distances of 300 feet for new development and 600 feet for new drilling operations have been established for sensitive sites, such as parks, hospitals, and schools.

(To see where other local actions have been taken in California, check out our coverage of local actions and map, which was recently updated.)

More details and maps of the setback ordinance and its development can be found in the initial FracTracker coverage of the proposal, below:

Arvin, CA – a City in the Most Drilled County in the Country – files for a Setback Ordinance

The measure was supported by Arvin Mayor Jose Gurrola. He described the front-lines experience of Arvin citizens:

The road to the update has been difficult for this community. Eight Arvin families were evacuated after a toxic gas leak from an underground oilfield production pipeline located near their homes in 2014. Some have now been re-occupied by concerned residents with no other options; other homes still stand empty. Meanwhile, a short distance away an older pump jack labors day and night next to homes pumping oil mixed with water to a nearby tank. Despite multiple complaints to state agencies of odors and noise by the residents, they are told by the agencies that there is nothing that can be done under the current regulations. The pump jack continues to creak along as children walk nearby on their way to school, covering their faces as the smell occasionally drifts their direction. – Jose Gurrola, Mayor of the City of Arvin

Fugitive Emissions Monitoring

In anticipation of the city council’s vote, FracTracker collaborated with Earthworks and the grassroots organization Central California Environmental Justice Network to visit the urban well sites within the city limits. Using Infrared FLIR technology, the sites were assessed for fugitive emissions and leaks. Visualizing emissions of volatile organic compounds (VOCs) at these sites provides a glimpse to what the community living near these wells are continually exposed. The infrared cameras used in these videos are calibrated to the wavelengths of the infrared spectrum where VOC hydrocarbons of interest are visible.

The map below shows the locations that were visited, as indicated by the three stars. Videos of each site are shown below the map.

Map 1. Arvin Setback Ordinance and FLIR Videos

View map fullscreen | How FracTracker maps work

FLIR Videos and Findings

Sun Mountain Simpson-1 Lease

In this FLIR video of Sun Mountain Simpson-1, fugitive emissions are obvious. The emissions are coming from the PV vent at the top of the produced water tank. These emissions are a mixture of a variety of volatile organic compounds, such as BTEX compounds and methane. This well site is located between homes, a small apartment complex, and a playground. While on the ground operating the FLIR camera I felt light headed, dizzy, and developed a headache. The emissions were reported to the San Joaquin Valley Air District (SJVAD), who sampled and found VOC concentrations at dangerous levels. The well operator was notified but refused to respond. Unfortunately, because this particular well produces under 50 barrels of oil/day, the site is exempt from any health related emissions regulations.

Sun Mountain Jewett 1-23 Lease

This well site is located near a number of single family homes and next two a park. The well site is also on the future location of the Arvin Community College. The FLIR video below is particularly interesting because it shows fugitive emissions from four different locations. The leaks include one at the well head that is potentially underground, one on separator equipment, and leaks from each of the tank PV hatches. When regulators were notified, they visited the site and fixed two of the leaks immediately. Fugitive emissions from the PV hatches were not addressed because this site is also exempt from regulations.

ABA Energy Corporation Richards Facility Tank Farm

The Richards Facility Tank Farm is a well site located outside the city limits on farmland. The facility is regulated as a point source of air pollution, therefore enforcement action can require the operator to fix leaks even from PV hatches on tanks. This FLIR video shows leaks from PV hatches, and a major leak from a broken regulator valve. A complaint was submitted to the SJVAD, and the operator was required to replace the broken regulator valve.

By Kyle Ferrar, Western Program Coordinator

Feature Image: Leaking tank at the Simpson 1 well site, Photo by Kyle Ferrar | FracTracker Alliance, 2018.

PA Well Pad Violations map
Matt Kelso, BA

Well Pad Violations in Pennsylvania

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Emerging Trends

We are always learning new things at FracTracker. While we have been analyzing and mapping oil and gas (O&G) violations issued by the Department of Environmental Protection (DEP) in Pennsylvania since 2010, we have apparently been under-representing the total amount of issues associated with unconventional drilling in the state.

The reason for the missing violations is that there are inconsistencies with how well pads are classified in the compliance report. Many of these well pads – full of unconventional permits and drilled wells – are indeed categorized as “unconventional” in the DEP compliance data. Others, equally full of unconventional permits and wells, simply leave that field blank.

Therefore, any analysis for unconventional violations is likely to miss some of the incidents that are attributed to the well pad itself, as opposed to any of the wells that are found upon that well pad.

Midas Well Pad unearths issue

While we have heard about missing violation data in the past, I discovered the nature of the issue while researching the Midas Well Pad in Plum Borough, Allegheny County on the DEP resource site eFACTS, noting the presence of multiple violations at the nascent well site. However, when attempting to download the relevant data on the compliance report, the results were missing. I had entered search parameters that made sense to me, limiting results to violations in the proper county and municipality, and including an inspection date range that was broader than what was showing up on eFACTS. I had also limited results to unconventional wells, because while this is Plum’s first unconventional well pad, the back roads are dotted with dozens – if not hundreds – of conventional O&G sites.

The Midas Well Pad, as seem from Coxcomb Hill Rd. in Plum, PA

After that attempt failed, I downloaded the entire state’s worth of data, whether conventional or not, and I was able to find the 31 violations associated with the well pad.

I contacted DEP about this, wondering whether there was some data irregularity that prevented my search in Plum from finding all of the incidents that occurred there. The reply was somewhat helpful, noting that there was no county, municipality, or unconventional value associated with that well pad in the compliance report, explaining why the search result came up negative.

It is worth noting that the separate well pad report does indeed have values for all of these fields for the Midas Well Pad, so there is a lack of consistency on this issue. Even more importantly, it is worth remembering that any compliance report search that limits results using county, municipality, or unconventional variables are likely to result in incomplete results.

The violations at the Midas Well Pad are focused around erosion and sedimentation issues, wetland impacts, failure to follow approved methodology, and failure to fix some of the problems on subsequent site inspections. The compliance report includes a narrative inspection comment, giving the public a glimpse through the inspector’s eyes. Here is one of several such comments at the site:

Follow up inspection related to wetland impact reported on 2/23/18 and 2/24/18. At the time of inspection, the Operator was actively conducting earth disturbance activity associated with the construction of well pad channel 6. The Department gave verbal permission on 2/27/2018 to deviate from the construction sequence and continue with the construction of PCSM wet pond 1. At the time of inspection wet pond 1 was partially constructed. The outlet structure and emergency spillway associated with wet pond 1. At the time of inspection wet pond 1 was holding water, however the slopes were not temporary stabilized. The Operator indicated that additional work was planned for the wet pond and would be temporary stabilized. The Operator indicated a previously unidentified seep located upgradient and outside of the LOD is contributing additional water to wet pond 1. The Department recommended the Operator identify wet weather springs upgradient from wet pond 1. Additionally, the Department recommends the Operator monitor all additional flow and submit a permit modification outlines changes made to the construction sequence and identifies the location of all toe drains to be constructed on site. The Department and Operator agreed to reschedule an onsite meeting to discuss the remediation of the wetland. Th Department recommends the Operator monitor the vegetative growth in the wetland. The Department recommends that the Operator add additional temporary mulch to the disturbed area and continue to perform routine maintenance to the temporary BMPs.

How pervasive is this problem?

The DEP well pad report contains data on 12,600 wells, situated on 3,715 wells pads. On the compliance side, there are 2,689 violations at 390 different sites that contain the words “Well Pad.” 739 of these violations do not have associated Well API Numbers, and are therefore not shown in our Pennsylvania Shale Viewer map. The number of sites with violations per operator is shown below in Figure 1 (click to expand).

Figure 1: Number of well pads appearing on compliance report by operator, through 5/15/2018. Click on the image to see the full-sized version.

There are four things to note about about Figure 1. 

First, this table is not the number of violations on well pads, but merely the count of well pads with violations appearing on the compliance report.

Second, this does not contain any data on wells on those pads that were issued violations – only instances where the well pads themselves were cited are shown.

PA Well Pad Violations: 

View map fullscreen

This map shows oil and gas (O&G) violations in Pennsylvania that are assessed to well pads, as opposed to individual wells. To access the map’s legend and other details, click the double-arrow icon at the top-left corner of the map.

The third thing to note about Figure 1 is that there are instances where the same pad falls into more than one category. Hilcorp Energy, for example, has 10 wells in the unconventional category, 11 wells that are not defined, but only 13 total wells, indicating significant overlap between the categories.

And fourth, there are 31 instances where the phrase “well pad” occurs in the compliance report where the unique Site ID# does not appear on the well pad report. In some cases, the name of the facility indicates that it might be for another facility that is related to the well pad, such as “Southwest System – Well Pad 36 to Bluestone Pipeline.” For other entries, such as “Yarasavage Well Pad”, it remains unclear why the Site ID# does not yield a matching entry from the well pad report.

By Matt Kelso, Manager of Data and Technology, FracTracker Alliance

 

Waiting on Answers - XTO incident image two weeks later
FracTracker Alliance

Waiting on Answers Weeks after a Well Explosion in Belmont County Ohio

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Mar 7 Update: The well has finally been capped.

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.

Site of the Feb 15th explosion on the XTO pad

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.

Photo of the XTO Energy well site and its current emissions after the explosion two weeks ago. Many are still waiting on answers as to why the well has yet to be capped.

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.

Sources: