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).
“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.”
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
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
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
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
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.
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
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.
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.
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.
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://stg.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
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.
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.
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
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|
Table 3. Idle Well Counts by County
|County||Count by County|
|9||San Luis Obispo||202|
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
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
- 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.
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
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
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
- Los Angeles
- Santa Barbara
- San Luis Obispo
- Plugged Well Count
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?
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.
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.
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.
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.
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.
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
Guest blog by Meryl Compton, policy associate with Frontier Group
Roughly half of the homes in America use gas for providing heat, hot water or powering appliances. If you use gas in your home, you know that leaks are bad – they waste money, they pollute the air, and, if exposed to a spark, they could spell disaster.
Our homes, however, are only the end point of a vast production and transportation system that brings gas through a network of pipelines all the way from the wellhead to our kitchens. There are opportunities for wasteful and often dangerous leaks all along the way – leaks that threaten the public’s health and safety and contribute to climate change.
How frequent are gas leaks?
Between January 2010 and November 2018, there were a reported 1,888 incidents that involved a serious injury, fatality or major financial loss related to gas leaks in the production, transmission and distribution system, according to data from the Pipeline and Hazardous Materials Safety Administration. These incidents caused 86 deaths, 487 injuries and over $1 billion in costs.
When gas lines leak, rupture, or are otherwise damaged, the gas released can explode, sometimes right in our own backyards. Roughly one in seven of the incidents referenced above – 260 in total – involved an explosion.
In September 2018, for example, a series of explosions in three Massachusetts communities caused one death, numerous injuries and the destruction of as many as 80 homes. And there are many more stories like it from communities across the U.S. From the 2010 pipeline rupture and explosion in San Bruno, California, that killed eight people and destroyed almost 40 homes to the 2014 disaster in New York City that destroyed two five-story buildings and killed eight people, these events serve as a powerful reminder of the danger posed by gas.
The financial and environmental costs
Gas leaks are also a sheer waste of resources. While some gas is released deliberately in the gas production process, large amounts are released unintentionally due to malfunctioning equipment, corrosion and natural causes like flooding. The U.S. Energy Information Administration estimates that 123,692 million cubic feet of gas were lost in 2017 alone, enough to power over 1 million homes for an entire year. That amount is likely an underestimate. On top of the major leaks reported to the government agency in charge of pipeline safety, many of our cities’ aging gas systems are riddled with smaller leaks, making it tricky to quantify just how much gas is lost from leaks in our nation’s gas system.
Leaks also threaten the stability of our climate because they release large amounts of methane, the main component of gas and a potent greenhouse gas. Gas is not the “cleaner” alternative to coal that the industry often makes it out to be. The amount of methane released during production and distribution is enough to reduce or even negate its greenhouse gas advantage over coal. The total estimated methane emissions from U.S. gas systems have roughly the same global warming impact over a 20-year period as all the carbon dioxide emissions from U.S. coal plants in 2015 – and methane emissions are likely higher than this amount, which is self-reported by the industry.
In most states, there is no strong incentive for gas companies to reduce the amount of leaked gas because they can still charge customers for it through “purchased gas adjustment clauses.” These costs to consumers are far from trivial. Between 2001 and 2011, Americans paid at least $20 billion for gas that never made it to their homes.
These and other dangers of gas leaks are described in a recent fact sheet by U.S. PIRG Education Fund and Frontier Group. At a time when climate change is focusing attention on our energy system, it is critical that communities understand the full range of problems with gas – including the ever-present risk of leaks in the extensive network of infrastructure that brings gas from the well to our homes.
We should not be using a fuel that endangers the public’s safety and threatens the stability of our climate. Luckily, we don’t have to. Switching to electric home heating and hot water systems and appliances powered by renewable energy would allow us to move toward eliminating carbon emissions from homes. Electric heat pumps are twice as efficient as gas systems in providing heat and hot water, making them a viable and commonsense replacement. Similarly, as the cost of wind and solar keep falling, they will continue to undercut gas prices in many regions.
It’s time to move beyond gas and create a cleaner, safer energy system.
By Meryl Compton, policy associate with Frontier Group, a non-profit think tank part of The Public Interest Network. She is based in Denver, Colorado.
Feature image at top of page shows San Bruno, California, following the 2010 pipeline explosion
Never has the saying “adding fuel to the fire” been so literal.
California wildfires have been growing at unheard of rates over the last five years, causing record breaking destruction and loss of life. Now that we’ve had a little rain and perhaps a reprieve from this nightmare wildfire season, it is important to consider the factors influencing the risk and severity of fires across the state.
Oil and gas extraction and consumption are major contributors to climate change, the underlying factor in the recent frequent and intense wildfires. A lesser-known fact, however, is that many wildfires have actually burned in oil fields in California – a dangerous circumstance that also accelerates greenhouse gas emissions. Our analysis shows where this situation has occurred, as well as the oil fields most likely to be burned in the future.
First, we looked at where wildfires are currently burning across the state, shown below in Map 1. This map is from CAL FIRE and is continuously updated.
Map 1. The CAL FIRE 2018 Statewide Incidents Map
CAL FIRE map showing the locations and perimeters of California wildfires
California’s recent fire seasons
The two largest wildfires in California recorded history occurred last year. The Mendocino Complex Fire burned almost a half million acres (1,857 square kilometers) in Mendocino National Forest. The Thomas Fire in the southern California counties of Ventura and Santa Barbara burned nearly 282,000 acres (1,140 square kilometers). A brutal 2017 fire season, however is now overshadowed by the ravages of 2018’s fires.
With the effects of climate change increasing the severity of California’s multi-year drought, each fire season seems to get worse. The Woolsey Fire in Southern California caused a record amount of property damage in the hills of Santa Monica and Ventura County. The Camp Fire in the historical mining town of Paradise resulted in a death toll that, as of early December, has more than tripled any other wildfire. And many people are still missing.
The Thomas Fire
A most precarious situation erupts when a wildfire spreads to an oil field. Besides having a surplus of their super flammable namesake liquid, oil fields are also storage sites for various other hazardous and volatile chemicals. The Thomas Fire was such a scenario.
The Thomas fire burned through the steep foothills of the coastal Los Padres mountains into the oil fields. When in the oil fields, the oil pumped to the surface for production and the stores of flammable chemicals provided explosive fuel to the wildfire. While firefighters were able to get the majority of the fire “contained,” the oil fields were too dangerous to access. According to the community, oil fires remained burning for weeks before they were able to be extinguished.
The Ventura office of the Division of Oil Gas and Geothermal Resources (DOGGR) reported that the Thomas Fire burned through the Taylor Ranch oil fields and a half dozen other oil fields including the Ventura, San Miguelito, Rincon, Ojai, Timbe Canyon, Newhall-Portrero, Honor Rancho and Wayside Canyon. DOGGR Ventura officials said Newhall-Potrero was “half burned over.” Thomas also burned within a 1/3 mile of the Sespe oil field. Schools and other institutions closed down throughout the Los Angeles Basin, but DOGGR said there was no impact on oil and gas operations that far south. The fire spurred an evacuation of the Las Flores Canyon Exxon oil storage facility but thankfully was contained before reaching the facility.
Wildfire threat for oil fields
Map 2. California Wildfires in Oil Fields
The Thomas Fire was not the first time or the last time an oil field burned in a California wildfire. Map 2 above shows state wildfires from the last 20 years overlaid with maps of California oil fields, oil wells, and high threat wildfire zones. The map shows just the oil fields and oil and gas wells in California that have been burned by a wildfire.
We found that 160 of California’s 517 oil fields (31%) have been burned by encroaching wildfires, affecting more than 10,000 oil and gas well heads.
An ominous finding: the state’s highest threat zones for wildfires are located close to and within oil and gas fields.
The map shows that wildfire risk is greatest in Southern California in Ventura and Los Angeles counties due to the arid environment and high population density. Over half the oil fields that have burned in California are in this small region.
Who is at fault?
Reports show that climate change has become the greatest factor in creating the types of conditions conducive to uncontrollable wildfires in California. Climate scientists explain that climate change has altered the natural path of the Pacific jet stream, the high-altitude winds that bring precipitation from the South Pacific to North America.
In a recent study, researchers from the University of Idaho and Columbia University found that the impact of global warming is growing exponentially. Their analysis shows that since 2000, human-caused climate change prompted 75% more aridity — causing peak fire season to expand every year by an average of nine days. The Fourth National Climate Assessment details the relationship between climate change and wildfire prevalence, and comes to the same conclusion: impacts are increasing.
On the cause of wildfires, the report explains:
Compound extremes can include simultaneous heat and drought such as during the 2011–2017 California drought, when 2014, 2015, and 2016 were also the warmest years on record for the state; conditions conducive to the very large wildfires, that have already increased in frequency across the western United States and Alaska since the 1980s.
Both 2017 and 2018 have continued the trend of warmest years on record, and so California’s drought has only gotten worse. The report goes on to discuss the threat climate change poses to the degradation of utilities’ infrastructure. Stress from climate change-induced heat and drought will require more resources dedicated to maintaining utility infrastructure.
The role of public utilities
The timing of this report could not be more ironic considering the role that utilities have played in starting wildfires in California. Incidents such as transformer explosions and the degradation of power line infrastructure have been implicated as the causes of multiple recent wildfires, including the Thomas Fire and the most recent Woolsey and Camp wildfires – three of the most devastating wildfires in state history. As public traded corporations, these utilities have investors that profit from their contribution to climate change which, in turn, has created the current conditions that allow these massive wildfires to spread. On the other hand, utilities in California may be the least reliant on fossil fuels. Southern California Edison allows customers to pay a surcharge for 100% renewable service, and Pacific Gas and Electric sources just 20% of their electricity from natural gas.
As a result of the fire cases, each of which might be attributed to negligence, stock prices for the two utilities plummeted but eventually rebounded after the California Public Utilities Commission (CPUC) assured investors that the utilities would be “bailed out” in the case of a possible financial failure to the reproach of the general public. The CPUC assured that the state could bail out utilities if they were forced to finance recovery for the fires they may have caused.
CPUC President, Michael Picker, stated:
The CPUC is one of the government agencies tasked with ensuring that investor-owned utilities operate a safe and reliable grid… An essential component of providing safe electrical service is the financial wherewithal to carry out safety measures.
Along with regulation and oversight, part of the agency’s work involves ensuring utilities are financially solvent enough to carry out safety measures.
January 1, 2019 will mark the seventh year of drought in California. Each fall brings anxiety and dread for state residents, particularly those that live in the driest, most arid forests and chaparral zones. Data show that the wildfires continue to increase in terms of intensity and frequency as the state goes deeper into drought induced by climate change.
While California firefighters have been incredibly resourceful, over 70% of California forest land is managed by the federal government whose 2019 USDA Forest Service budget reduces overall funding for the National Forest System by more than $170 million. Moving forward, more resources must be invested in supporting the health of forests to prevent fires with an ecological approach, rather than the current strategy which has focused predominantly on the unsustainable practice of fuel reduction and the risky tactics of “fire borrowing”. And of course, the most important piece of the puzzle will be addressing climate change.
By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance
Feature image by Marcus Yam, LA Times
Offshore drilling in the United States federal waters has caused the most environmentally destructive disasters in North America. Yet, new policy is pushing for the expansion of offshore drilling, particularly off the coast of California.
Offshore Drilling History
In 1969, Union Oil’s offshore rig Platform A had a blowout that leaked 100,000 barrels into the Santa Barbara Channel, one of the most biologically diverse marine environments in the world. The spill lasted ten days and killed an estimated 3,500 sea birds, as well as an untold number of marine mammals. Unbelievably, the Santa Barbara spill is only the third largest spill in U.S. waters. It follows the 1989 Exxon Valdez and the 2010 Deepwater Horizon spills. These incidents keep getting bigger.
More offshore drilling means a higher risk of catastrophe, additional contamination of air and water locally, and more greenhouse gas emissions globally.
Federal Moratorium on California Offshore Leases
Up until the beginning of 2018, further oil and gas development using offshore oil rig platforms seemed quite unlikely. After the 1969 oil spill from Platform A and the subsequent ban on further leasing in state waters, the risk of another devastating oil spill was too large for even the federal government to consider new leases. The fact that the moratorium lasted through 16 years of Bush presidencies is truly a victory. Across the aisle, expanding offshore operations has been opposed. In Florida, even Republican Governor Rick Scott teamed up with environmental groups to fight the Department of Interior’s recent sales of offshore leases.
Trump’s New Gas Leasing Program
Now, the U.S. Bureau of Ocean Energy Management (BOEM) is preparing a new 2019-2024 national Outer Continental Shelf (OCS) oil and gas leasing program to replace the existing 2017-2022 program. This is an unusual practice, and part of Trump’s America-First Offshore Energy Strategy. The Trump administration opened up most of the US coastal waters for new oil and gas drilling with a recent draft proposal offering 47 new offshore block lease sales to take place between 2019 and 2024.
Where might these new leases occur?
The offshore federal waters that are open for oil and gas leases are shown in dark blue in the map below (Figure 1). Zoom out to see the extent.
Figure 1. Map of Offshore Oil and Gas Extraction
California’s Offshore Oil
Southern California has a legacy of oil extraction, particularly Los Angeles. It’s not just the federal government that is keen on continuing this legacy. While the state has not permitted the leasing of new blocks in offshore waters, Governor Brown’s policies have been very friendly to the oil and gas industry. According to Oil Change International’s Sky’s the Limit report: “Under the Brown administration, the state has permitted the drilling of more than 20,000 new wells,” including 5,000 offshore wells in state waters. About 2,000 of these offshore wells have been drilled since 2012.
This map developed in collaboration with Consumer Watch Dog juxtaposes the offshore wells drilled in CA state waters with those drilled in federal waters.
Southern California is the main target for future offshore leasing. The Monterey Shale formation, which underlies the city of Los Angeles and expands north offshore to the Ventura Coast, is thought to contain the largest conventional oil plays left IN THE WORLD! The map above shows the locations of state and federal offshore oil and gas wells and the rigs that service them. It also shows historical wells off the coast of Northern California.
Northern California, both onshore and offshore, sits on top of major reserves of natural gas, which may also be developed given the political climate. With an increase in the price of natural gas, operators will be developing these gas fields. Some operators, such as Chevron, have already drilled natural gas wells in northern California, but have left the wells “shut in” (capped) until production becomes more profitable.
For a more comprehensive coverage on environmental impacts of offshore operations, including those to sensitive species, check out the Environmental Defense Center’s Dirty Water Report and read our additional coverage of California’s existing offshore drilling, and offshore fracking.
Air Pollution from Oil Rigs
FracTracker, in collaboration with Earthworks, recently teamed up with the Center for Biological Diversity and Greenpeace International to get up close to offshore oil rigs. As a certified Optical Gas Imaging Thermographer, Kyle Ferrar (Western Program Coordinator for FracTracker Alliance and California Community Empowerment Project Organizer for Earthworks), took footage of the offshore oil rigs.
Using infrared technology, we were able to visualize and record emissions and leaks of volatile hydrocarbons and other greenhouse gases coming from these offshore sites. We documented many cases of intense flaring from the rigs, including several cases where the poorly burning flare allowed hydrocarbons to be leaked to the atmosphere prior to complete combustion of CO2.
Below you can view a compilation of the footage we were able to capture from small pontoon boats.
FracTracker has looked at offshore oil and gas drilling from many different angles. We have looked to the past, and found the most egregious environmental damages in U.S. history. We have analyzed the data and shown where, when, and how much offshore drilling is happening in California. We have demonstrated that much of the drilling and many of the proposed leases are in protected and sensitive habitats. We have looked at policy and found that both Governor Brown and President Trump are aligned to promote more oil and gas development. We have even looked at the rigs in person in multiple spectrums of light and found that these operations continuously leak and emit greenhouse gases and other air toxins.
No matter which way you look at offshore oil and gas drilling, it is clearly one of the most threatening methods of oil and gas extraction in use today.
By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance
WASHINGTON, DC – As oil and gas representatives descend on Pittsburgh this week for the annual Shale Insight conference, four advocates working to protect their communities from the harms of oil and gas development have been selected to receive the 2018 Community Sentinel Award for Environmental Stewardship, coordinated by FracTracker Alliance:
- Ellen Gerhart – Pennsylvania
- Natasha Léger – Colorado
- Rebecca Roter – Pennsylvania, now Georgia
- Youth award: Nalleli Cobo – California
This year’s recipients have founded grassroots organizations to protect communities from nearby drilling, paired traditional advocacy with scientific savvy, protested pipelines on land taken by eminent domain, and organized to stop urban drilling despite persistent health problems related to the drilling activity.
“The impacts of the oil and gas industry are visible across the United States, but hope abounds in the volunteers working in their communities and cherished places to document, report, and confront fossil fuel harms,” remarked Brook Lenker, Executive Director of FracTracker Alliance. “We are proud to honor Ellen, Natasha, Rebecca, and Nalleli this year, whose noble actions exemplify the transformative power of caring, committed, and engaged people.”
These four steadfast advocates were nominated by peers and selected by a committee of community defense leaders: Raina Rippel of Southwest Pennsylvania Environmental Health Project (Pennsylvania); Dan Shaffer of Allegheny-Blue Ridge Alliance and Dominion Pipeline Monitoring Coalition (Virginia); Dan Xie of Student PIRG (Florida); Jill Hunkler- Native American activist (Ohio); and Elena Sorokina of Crude Accountability (Washington, DC).
The award recipients will each receive $1,000 for their efforts and be recognized at an evening reception at the Renaissance Pittsburgh Hotel in Pittsburgh, Pennsylvania on Monday, November 26, 2018. The reception will also recognize heroes of the movement who recently passed away. Purchase tickets ($40).
This year’s major Community Sentinel sponsors include 11th Hour Project, The Heinz Endowments, and Foundation for Pennsylvania Watersheds. Award partners (to date) include Allegheny-Blue Ridge Alliance, Breathe Project, Center for Coalfield Justice, Crude Accountability, Earthworks, Food & Water Watch, Halt the Harm Network, Ohio Valley Environmental Coalition, Pipeline and Property Rights Center, Save the Hills Alliance, Sierra Club, Southwest Pennsylvania Environmental Health Project, and Viable Industries. View current sponsors and partners.
To learn more about the fourth annual Community Sentinel Award for Environmental Stewardship and to purchase tickets to the reception on November 26th, please visit: fractracker.org/sentinel-award.
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About FracTracker Alliance
FracTracker Alliance is a national non-profit with regional offices in California, New York, Ohio, Pennsylvania, Washington DC. The organization’s mission is to study, map, and communicate the risks of oil and gas development to protect our planet and support the renewable energy transformation. Learn more at fractracker.org.
For Release on October 24, 2018
Job Title: Data and GIS Intern
Internship Period: January 2019 – June 2019, 6 months
Application Deadline – Extended: November 16, 2018
Compensation: $11/hour, 15 hours per week
Locations: Oakland, CA and Pittsburgh, PA
FracTracker internships are dedicated to current college and graduate students, as well as recent grads. Each of our available 6-month internships runs from January through June 2019. Paid, temporary interns work 15 hours per week and are compensated $11/hour. This position is not eligible for health benefits, but travel expenses may be reimbursed. Please note this position is at will and subject to available funding.
This upcoming spring we are in need of interns in two of FracTracker’s offices, although some remote work is permissible if arranged in advance with their supervisor. Please select which of the two offices you are interested in working out of when applying online:
- California: 1440 Broadway, Ste. 205, Oakland, CA 94612
- Pennsylvania: 112 Sherman St, Pittsburgh, PA 15209
Interns will utilize GIS technologies to perform geo-spatial data collection, processing, and analysis. Tasks are typically associated with routine technical work in GIS, involving heavy amounts of database entry and management, generation of maps, and various types of research under the supervision of FracTracker staff.
The responsibilities of paid GIS interns revolve around the daily work of the other FracTracker staff, as well as time-sensitive projects. Responsibilities will vary, but may include:
- Data mining, cleaning, management, and GIS mapping
- Limited spatial analyses using GIS software
- Translation of data into information and stories for the blog
- Administrative support when needed
- Field research
- Participation in software development, integration, and system testing when needed
Working knowledge of: Geographic information systems (GIS) and Microsoft Office products (especially Word and Excel).
Ability to: Assist with researching spatial data availability from internal and external sources; collect, assimilate, analyze, and interpret data and draw sound conclusions; prepare oral and written reports.
Enrollment in or recent graduation from an accredited college or university is required. Majors can include geography, computer science, environmental science, public health, planning or a related field.
To apply for one of our spring 2019 internships, please submit the following materials by Friday, November 16, 2018 (deadline extended) through our online application form: cover letter, resume, and 3 references. Applications are not accepted via email, but you may address questions to Sam Rubright at email@example.com.
[Applications are no longer being accepted]
Deadline to apply: November 16, 2018
After November 16th, applicants will be contacted regardless of whether or not an interview is sought by us. Interviews will be conducted over the next two weeks, and a decision made by December 7th.
About FracTracker Alliance
FracTracker Alliance studies, maps, and communicates the risks of oil and gas development to protect our planet and support the renewable energy transformation. Learn more about FracTracker Alliance at www.fractracker.org.