Oil & Gas waste tank operated by SWEPI and Enervest at the Hayes pad, Otsego County, Michigan May 21st, 2016

The North Dakota Shale Viewer Reimagined: Mapping the Water and Waste Impact

June 18, 2020/by Ted Auch, PhD

We updated the FracTracker North Dakota Shale Viewer with current data and additional details on the astronomical levels of water used and waste produced throughout the process of fracking for oil and gas in North Dakota.

As folks who visit the FracTracker website may know, the fracking industry is predicated on cheap sources of water and waste disposal. The water they use to bust open shale seams becomes part of the waste stream that they refer to by the benign term “brine,” equating it to nothing more than the salt water we swim in when we hit the beaches.

Some oil and gas operators like SWEPI and Enervest in Michigan, however, have taken to calling their waste “SLOP” (Figure 1), which from my standpoint is actually refreshingly honest.

Fracking Energy Return on Investment 2012 – 2020

Since we created our North Dakota Shale Viewer on October 5^th, 2012, much has changed across the fracking landscape, while other songs have remained the same. Both of these truths exist with respect to fracking’s impact on water and the industry’s inability to get its collective head around the billions of barrels of oftentimes radioactive waste it produces by its very nature. From the outset, fracking was on dubious footing when it came to the water and waste associated with its operations, and we have seen a nearly universal and exponential increase in water demand and waste production on a per well basis since fracking became the highly divisive topic it remains to this day.

Figure 1. Oil & Gas waste tank operated by SWEPI and Enervest at the Hayes pad, Otsego County, Michigan May 21st, 2016 (44.892933, -84.786530). Photo by Ted Auch, FracTracker Alliance.

Environmental economists like to look at energy sources from a more holistic standpoint vis a vis engineers, traditional economists, and the divide-and-conquer rhetoric from Bismarck to the White House. They do this by placing all manner of energy sources along a spectrum of Energy Return On Energy Invested (EROEI).

Since the dawn of the fracking revolution, shale gas from horizontal wells has been near the bottom of the league tables with respect to EROEI which means it “…has decreased from more than 1000:1 in 1919 to 5:1 in the 2010s, and for production from about 25:1 in the 1970s to approximately 10:1 in 2007” for US oil and gas according to Hall et al. (2014). This is what John Erik Meyer has come the “EROI Mountain” whereby we’ve already “burned through the richest resources.”

It stands to reason that if natural gas from fracking were a real “bridge fuel” in the transition away from coal, it would at least approach or exceed the EROEI of the latter, but at 46:1 coal is still four times more efficient than natural gas. However, it must be said that coal’s days are numbered as well. Witness the recent bankruptcy of coal giant Murray Energy, and the only reason its EROEI has increased or remained steady is because the mining industry has transitioned to almost exclusively mountaintop removal and/or strip mining and the associated efficiencies resulting from mechanization/automation.

The North Dakota Shale Viewer

We enhanced our North Dakota Shale Viewer nearly eight years since it debuted. This exercise included the addition of several data layers that speak to the above issues and how they have changed since we first launched the North Dakota Shale Viewer.

View map fullscreen

It is worth noting that oil production in total across North Dakota has not even doubled since 2012, and gas production has only managed to increase 3.5-fold. However, the numbers look even worse when you look at these totals on a per well basis, which as I have mentioned seems to me to be the only way reasonable people should be looking at production. Using this lens, we see that production of oil in North Dakota on a per well basis oil is 1% less than it was in 2012 and gas production has not even doubled per well. This is a stunning contrast to the upticks in water and waste we have documented and are now including in our North Dakota Shale Viewer.

Water Demand Rises for Fracking

We’ve incorporated individual horizontal well freshwater demand for nearly 12,000 wells up to and including Q1-2020. The numbers are jaw dropping when you consider that at the time we debuted this map North Dakota, unconventional wells were using roughly 2.1 million gallons per well compared to an average of 8.3 million gallons per well so far this year. This per well increase is something we have been documenting for years now in states like Pennsylvania, Ohio, and West Virginia.

Learn More

For more analysis around water used for fracking, see “The Human Right to Water and Unconventional Energy,” a paper co-authored by Dr. Ted Auch with partners in the UK.

This is concerning for multiple reasons, the first being that if fracking ever were to rebound to its halcyon days of the early teens, it would mean some of our country’s most prized and fragile watersheds would be pushed to an irreversible hydrological tipping point. Hoekstra et al. (2012) have come to call this the “blue water” precautionary principle whereby “depletion beyond 20% of a river’s natural flow increases risks to ecological health and ecosystem services.”

Another concern is that while permitting in North Dakota has slowed like it has nationwide, the aforementioned quarterly water usage totals per well are now 5.25 times what they were in October 2012 and the total water used by the industry in North Dakota now amounts to 60.43 billion gallons– that we know of — which is nearly 50 times what the industry had used when we created our North Dakota Shale Viewer (Figure 2).[1]

With respect to the points made earlier about the value of EROEI, this increase in water demand has not been reflected in the productivity of North Dakota’s oil and gas wells, which means the EROEI continues to fall at rate that should make the industry blush. Furthermore, this trend should prompt regulators and elected officials in Bismarck and elsewhere to begin to ask if the long-term and permanent environmental and/or hydrological risk is worth the short-term rewards vis à vis the “blue water” precautionary principle, in this case of the Missouri River, outlined by Hoekstra et al. (2012). It is my opinion that it most assuredly is not and never was worth the risk!

The most stunning aspect of the above divergence in production and water demand is that on a per well basis, water only costs the industry roughly 0.46-0.76% of total well pad costs. This narrow range is a function of the water pricing schemes shared with me by the North Dakota Western Area Water Supply Authority (WAWSA). This speaks to an average price of water between $3.68 and $4.07 per 1,000 gallons for “industrial” use (aka, fracking industry) by way of eight depots and “several hundred miles of transmission and distribution lines” spread across the state’s four northwest counties of Mountrail, Divide, Williams, and McKenzie.

Figure 2. Average Freshwater Demand Per Well and Cumulative Freshwater Demand by North Dakota fracking industry from 2011 to Q1-2020.

$Average Freshwater Demand Per Well and Cumulative Freshwater Demand by North Dakota fracking industry from 2011 to Q1-2020$

Increasing Fracking Waste Production

On the fracking waste front, the monthly trend is quite volatile relative to what we’ve documented in states like Oklahoma, Kansas, and Ohio. Nonetheless, the amount of waste produced is increasing per well and in total. How you quantify this increase is quite sensitive to the models you fit to the data. The exponential and polynomial (Plotted in Figure 3) fits yield 4.76 to 9.81 million barrel per month increases, while linear and power functions yield the opposite resulting in 1.82 to 10.91 million-barrel declines per month. If we assume the real answer is somewhere in between we see that fracking waste is increasingly slightly at a rate of 1.51% per year or 460,194 barrels per month.

Figure 3. Average Per Well and Monthly Total Fracking Waste Disposal across 675 North Dakota Class II Salt Water Disposal (SWD) wells from 2010 to Q1-2020.

North Dakota has concerning legislation related to oil and gas waste disposal. Senate Bill 2344 claims that landowners do not actually own the “subsurface pore space” beneath their property. The bill was passed into law by Legislature last Spring but there are numerous lawsuits working against it. We will have further analysis of this bill published on FracTracker.org soon.

Earthworks ND Frack Waste Report

FracTracker collaborated with Earthworks to create an interactive map that allows North Dakota residents to determine if oil and gas waste is disposed of or has spilled near them in addition to a list of recommendations for state and local policymakers, including the closing of the state’s harmful oil and gas hazardous waste loophole. Read the report for detailed information about oil and gas waste in North Dakota.

North Dakota Frack Waste Report

Read the Report

The Value of Our Water

This data is critical to understanding the environmental and/or hydrological impact(s) of fracking, whether it is Central Appalachia’s Ohio River Valley, or in this case North Dakota’s Missouri River Basin. We will continue to periodically update this data.

Without supply-side price signaling or adequate regulation, it appears that the industry is uninterested and insufficiently incentivized to develop efficiencies in water use. It is my opinion that the only way the industry will be incentivized to do so is if states put a more prohibitive and environmentally responsible price on water and waste. In the absence of outright bans on fracking, we must demand the industry is held accountable for pushing watersheds to the brink of their capacity, and in the process, compromising the water needs of so many communities, flora, and fauna.

Data Links

Water Usage for nearly 12,000 fracked laterals in North Dakota up to and including April, 2020. We also include API number and operator in GIS, KML, and Spreadsheet formats. (https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2020/05/ND_FracFocus_April_2020_With_KML_Excel.zip)
Monthly volumes (2010 to 2020) and demographics for surrounding area for the 675 Class II Salt Water Disposal (SWD) Fracking Waste Injection Wells in North Dakota. We also include API number and operator in GIS, KML, and Spreadsheet formats. (https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2020/05/ND_ClassII_Well_MonthlyWaste_2010_Q2_2020_Demographics_WithKML_Excel.zip)
North Dakota Gas Plants (https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2020/06/GasPlants_WithExcel_KML.zip)

[1] Here in Ohio where I have been looking most closely at water supply and demand across the fracking landscape it is clear that we aren’t accounting for some 10-12% of water demand when we compare documented water withdrawals in the numerator with water usage in the denominator.

By Ted Auch, PhD, Great Lakes Program Coordinator

Falcon Pipeline Construction Releases over 250,000 Gallons of Drilling Fluid in Pennsylvania and Ohio

June 16, 2020/by Erica Jackson

Part of the Falcon Public Environmental Impact Assessment – a FracTracker series on the impacts of Falcon Ethane Pipeline System

Challenges have plagued Shell’s construction of the Falcon Pipeline System through Pennsylvania, Ohio, and West Virginia, according to documents from the Pennsylvania Department of Environmental Protection (DEP) and the Ohio Environmental Protection Agency (EPA).

Records show that at least 70 spills have occurred since construction began in early 2019, releasing over a quarter million gallons of drilling fluid. Yet the true number and volume of spills is uncertain due to inaccuracies in reporting by Shell and discrepancies in regulation by state agencies.

See Map of Spills

A drilling fluid spill from Falcon Pipeline construction near Moffett Mill Road in Beaver County, PA. Source: Pennsylvania DEP

Releases of drilling fluid during Falcon’s construction include inadvertent returns and losses of circulation – two technical words used to describe spills of drilling fluid that occur during pipeline construction.

Drilling fluid, which consists of water, bentonite clay, and chemical additives, is used when workers drill a borehole horizontally underground to pull a pipeline underneath a water body, road, or other sensitive location. This type of installation is called a HDD (horizontal directional drill), and is pictured in Figure 1.

Figure 1. An HDD operation – Thousands of gallons of drilling fluid are used in this process, creating the potential for spills. Click to expand. Source: Enbridge Pipeline

Here’s a breakdown of what these types of spills are and how often they’ve occurred during Falcon pipeline construction, as of March, 2020:

Loss of circulation
- Definition: A loss of circulation occurs when there is a decrease in the volume of drilling fluid returning to the entry or exit point of a borehole. A loss can occur when drilling fluid is blocked and therefore prevented from leaving a borehole, or when fluid is lost underground.
- Cause: Losses of circulation occur frequently during HDD construction and can be caused by misdirected drilling, underground voids, equipment blockages or failures, overburdened soils, and weathered bedrock.
- Construction of the Falcon has caused at least 49 losses of circulation releasing at least 245,530 gallons of drilling fluid. Incidents include:
  - 15 losses in Ohio – totaling 73,414 gallons
  - 34 losses in Pennsylvania – totaling 172,116 gallons
Inadvertent return
- Definition: An inadvertent return occurs when drilling fluid used in pipeline installation is accidentally released and migrates to Earth’s surface. Oftentimes, a loss of circulation becomes an inadvertent return when underground formations create pathways for fluid to surface. Additionally, Shell’s records indicate that if a loss of circulation is large enough, (releasing over 50% percent of drilling fluids over 24-hours, 25% of fluids over 48-hours, or a daily max not to exceed 50,000 gallons) it qualifies as an inadvertent return even if fluid doesn’t surface.
- Cause: Inadvertent returns are also frequent during HDD construction and are caused by many of the same factors as losses of circulation.
- Construction of the Falcon has caused at least 20 inadvertent returns, releasing at least 5,581 gallons of drilling fluid. These incidents include:
  - 18 inadvertent returns in Pennsylvania – totaling 5,546 gallons
    - 2,639 gallons into water resources (streams and wetlands)
  - 2 inadvertent returns Ohio – totaling 35 gallons
    - 35 gallons into water resources (streams and wetlands)

However, according to the Ohio EPA, Shell is not required to submit reports for losses of circulation that are less than the definition of an inadvertent return, so many losses may not be captured in the list above. Additionally, documents reveal inconsistent volumes of drilling mud reported and discrepancies in the way releases are regulated by the Pennsylvania DEP and the Ohio EPA.

Very few of these incidents were published online for the public to see; FracTracker obtained information on them through a public records request. The map below shows the location of all known drilling fluid releases from that request, along with features relevant to the pipeline’s construction. Click here to view full screen, and add features to the map by checking the box next to them in the legend. For definitions and additional details, click on the information icon.

View map full screen

Jefferson County, Ohio

Our investigation into these incidents began early this year when we received an anonymous tip about a release of drilling fluids in the range of millions of gallons at the SCIO-06 HDD over Wolf Run Road in Jefferson County, Ohio. The source stated that the release could be contaminating drinking water for residents and livestock.

Working with Clean Air Council, Fair Shake Environmental Legal Services, and DeSmog Blog, we quickly discovered that this spill was just the beginning of the Falcon’s construction issues.

Documents from the Ohio EPA confirm that there were at least eight losses of circulation at this location between August 2019 and January 2020, including losses of unknown volume. The SCIO-06 HDD location is of particular concern because it crosses beneath two streams (Wolf Run and a stream connected to Wolf Run) and a wetland, is near groundwater wells, and runs over an inactive coal mine (Figure 2).

Figure 2. Losses of circulation that occurred at the SCIO-06 horizontal directional drill (HDD) site along the Falcon Pipeline in Jefferson County Ohio. Data Sources: OH EPA, AECOM

According to Shell’s survey, the coal mine (shown in Figure 2 in blue) is 290 feet below the HDD crossing. A hazardous scenario could arise if an HDD site interacts with mine voids, releasing drilling fluid into the void and creating a new mine void discharge.

A similar situation occurred in 2018, when EQT Corp. was fined $294,000 after the pipeline it was installing under a road in Forward Township, Pennsylvania hit an old mine, releasing four million gallons of mine drainage into the Monongahela River.

The Ohio EPA’s Division of Drinking and Ground Waters looked into the issues around this site and reported, “GIS analysis of the pipeline location in Jefferson Co. does not appear to risk any vulnerable ground water resources in the area, except local private water supply wells. However, the incident location is above a known abandoned (pre-1977) coal mine complex, mapped by ODNR.”

If you believe your environment may be impacted by pipeline construction, you may contact Fair Shake Environmental Legal Services for assistance, and as always you can reach out to FracTracker Alliance with questions and concerns.

While we cannot confirm if there was a spill in the range of millions of gallons as the source claimed, the reported losses of circulation at the SCIO-06 site total over 60,000 gallons of drilling fluid. Additionally, on December 10th, 2019, the Ohio EPA asked AECOM (the engineering company contracted by Shell for this project) to estimate what the total fluid loss would be if workers were to continue drilling to complete the SCIO-06 crossing. AECOM reported that, in a “very conservative scenario based on the current level of fluid loss…Overall mud loss to the formation could exceed 3,000,000 gallons.”

Despite this possibility of a 3 million+ gallon spill, Shell resumed construction in January, 2020. The company experienced another loss of circulation of 4,583 gallons, reportedly caused by a change in formation. However, in correspondence with a resident, Shell stated that the volume lost was 3,200 gallons.

Whatever the amount, this January loss of circulation appears to have convinced Shell that an HDD crossing at this location was too difficult to complete, and in February 2020, Shell decided to change the type of crossing at the SCIO-06 site to a guided bore underneath Wolf Run Rd and open cut trench through the stream crossings (Figure 3).

Figure 3. The SCIO-06 HDD site, which may be changed from an HDD crossing to an open cut trench and conventional bore to cross Wolf Run Rd, Wolf Run stream (darker blue), an intermittent stream (light blue) and a wetland (teal). Click to expand.

An investigation by DeSmog Blog revealed that Shell applied for the route change under Nationwide Permit 12, a permit required for water crossings. While the Army Corps of Engineers authorized the route change on March 17th, one month later, a Montana federal court overseeing a case on the Keystone XL pipeline determined that the Nationwide Permit 12 did not meet standards set by federal environmental laws – a decision which may nullify the Falcon’s permit status. At this time, the ramifications of this decision on the Falcon remain unclear.

Inconsistencies in Reporting

In looking through Shell’s loss of circulation reports, we noted several discrepancies about the volume of drilling fluid released for different spills, including those that occurred at the SCIO-06 site. As one example, the Ohio EPA stated an email about the SCIO-06 HDD, “The reported loss of fluid from August 1, 2019 to August 14, 2019 in the memo does not appear to agree with the 21,950 gallons of fluid loss reported to me during my site visit on August 14, 2019 or the fluid loss reported in the conference call on August 13, 2019.”

In addition to errors on Shell’s end, our review of documents revealed significant confusion around the regulation of drilling fluid spills. In an email from September 26, 2019, months after construction began, Shell raised the following questions with the Ohio EPA:

when a loss of circulation becomes an inadvertent return – the Ohio EPA clarifies: “For purposes of HDD activities in Ohio, an inadvertent return is defined as the unintended return of any fluid to the surface, as well as losses of fluids to underground formations which exceed 50-percent over a 24-hour period and/or 25-percent loss of fluids or annular pressure sustained over a 48-hour period;”
when the clock starts for the aforementioned time periods – the Ohio EPA says the time starts when “the drill commences drilling;”
whether Shell needs to submit loss of circulation reports for losses that are less than the aforementioned definition of an inadvertent return – the Ohio EPA responds, “No. This is not required in the permit.”

How are these spills measured?

A possible explanation for why Shell reported inconsistent volumes of spills is because they were not using the proper technology to measure them.

Shell’s “Inadvertent Returns from HDD: Assessment, Preparedness, Prevention and Response Plan” states that drilling rigs must be equipped with “instruments which can measure and record in real time, the following information: borehole annular pressure during the pilot hole operation; drilling fluid discharge rate; the spatial position of the drilling bit or reamer bit; and the drill string axial and torsional loads.”

In other words, Shell should be using monitoring equipment to measure and report volumes of drilling fluid released.

Despite that requirement, Shell was initially monitoring releases manually by measuring the remaining fluid levels in tanks. After inspectors with the Pennsylvania DEP realized this in October, 2019, the Department issued a Notice of Violation to Shell, asking the company to immediately cease all Pennsylvania HDD operations and implement recording instruments. The violation also cited Shell for not filing weekly inadvertent return reports and not reporting where recovered drilling fluids were disposed.

In Ohio, there is no record of a similar request from the Ohio EPA. The anonymous source that originally informed us of issues at the SCIO-6 HDD stated that local officials and regulatory agencies in Ohio were likely not informed of the full volumes of the industrial waste releases based on actual meter readings, but rather estimates that minimize the perceived impact.

While we cannot confirm this claim, we know a few things for sure: 1) there are conflicting reports about the volume of drilling fluids spilled in Ohio, 2) according to Shell’s engineers, there is the potential for a 3 million+ gallon spill at the SCIO-06 site, and 3) there are instances of Shell not following its permits with regard to measuring and reporting fluid losses.

The inconsistent ways that fluid losses (particularly those that occur underground) are defined, reported, and measured leave too many opportunities for Shell to impact sensitive ecosystems and drinking water sources without being held accountable.

What are the impacts of drilling fluid spills?

Drilling fluid is primarily composed of water and bentonite clay (sodium montmorillonite), which is nontoxic. If a fluid loss occurs, workers often use additives to try and create a seal to prevent drilling fluid from escaping into underground voids. According to Shell’s “Inadvertent Returns From HDD” plan, it only uses additives that meet food standards, are not petroleum based, and are consistent with materials used in drinking water operations.

However, large inadvertent returns into waterways cause heavy sedimentation and can have harmful effects on aquatic life. They can also ruin drinking water sources. Inadvertent returns caused by HDD construction along the Mariner East 2 pipeline have contaminated many water wells.

Losses of circulation can impact drinking water too. This past April in Texas, construction of the Permian Highway Pipeline caused a loss that left residents with muddy well water. A 3 million gallon loss of circulation along the Mariner East route led to 208,000 gallons of drilling mud entering a lake, and a $2 million fine for Sunoco, the pipeline’s operator.

Our Falcon Public EIA Project found 240 groundwater wells within 1/4 mile of the pipeline and 24 within 1,000 ft of an HDD site. The pipeline also crosses near surface water reservoirs. Drilling mud spills could put these drinking water sources at risk.

But when it comes to understanding the true impact of the more than 245,000+ gallons of drilling fluid lost beneath Pennsylvania and Ohio, there are a lot of remaining questions. The Falcon route crosses over roughly 20 miles of under-mined land (including 5.6 miles of active coal mines) and 25 miles of porous karst limestone formations (learn more about karst). Add in to the mix the thousands of abandoned, conventional, and fracked wells in the region – and you start to get a picture of how holey the land is. Where or how drilling fluid interacts with these voids underground is largely unknown.

Other Drilling Fluid Losses

In addition to the SCIO-04 HDD, there are other drilling fluid losses that occurred in sensitive locations.

In Robinson Township, Pennsylvania, over a dozen losses of circulation (many of which occurred over the span of several days) released a reported 90,067 gallons of drilling fluid into the ground at the HOU-04 HDD. This HDD is above inactive surface and underground mines.

The Falcon passes through and near surface drinking water sources. In Beaver County, Pennsylvania, the pipeline crosses the headwaters of the Ambridge Reservoir and the water line that carries out its water for residents in Beaver County townships (Ambridge, Baden, Economy, Harmony, and New Sewickley) and Allegheny County townships (Leet, Leetsdale, Bell Acres, and Edgeworth). The group Citizens to Protect the Ambridge Reservoir, which formed in 2012 to protect the reservoir from unconventional oil and gas infrastructure, led efforts to stop Falcon Construction, and the Ambridge Water Authority itself called the path of the pipeline “not acceptable.” In response to public pressure, Shell did agree to build a back up line to the West View Water Authority in case issues arose from the Falcon’s construction.

Unfortunately, a 50-gallon inadvertent return was reported at the HDD that crosses the waterline (Figure 4), and a 160 gallon inadvertent return occurred in Raccoon Municipal Park within the watershed and near its protected headwaters (Figure 5). Both of these releases are reported to have occurred within the pipeline’s construction area and not into waterways.

Figure 4) HOU-10 HDD location on the Falcon Pipeline, where 50 gallons were released on the drill pad on 7/9/2019

Figure 5) SCIO-05 HDD location on the Falcon Pipeline, where 160 gallons were released on 6/10/19, within the pipeline’s LOD (limit of disturbance)

Farther west, the pipeline crosses through the watershed of the Tappan Reservoir, which provides water for residents in Scio, Ohio and the Ohio River, which serves over 5 million people.

A 35- gallon inadvertent return occurred at a conventional bore within the Tappan Lake Protection Area, impacting a wetland and stream. We are not aware of any spills impacting the Ohio River.

Pipelines in a Pandemic

This investigation makes it clear that weak laws and enforcement around drilling fluid spills allows pipeline construction to harm sensitive ecosystems and put drinking water sources at risk. Furthermore, regulations don’t require state agencies or Shell to notify communities when many of these drilling mud spills occur.

Despite the issues Shell experienced during construction, work on the Falcon continued over the past months during state shelter-in-place orders, while many businesses were forced to close.

The problem continues where the 97-mile pipeline ends – at the Shell ethane cracker. In March, workers raised concerns about the unsanitary conditions of the site, and stated that crowded workspaces made social distancing impossible. While Shell did halt construction temporarily, state officials gave the company the OK to continue work – even without the waiver many businesses had to obtain.

The state’s decision was based on the fact it considered the ethane cracker to “support electrical power generation, transmission and distribution.” The ethane cracker – which is still months and likely years away from operation – does not currently produce electrical power and will only provide power generation to support plastic manufacturing.

This claim continues a long pattern of the industry attempting to trick the public into believing that we must continue expanding oil and gas operations to meet our country’s energy needs. In reality, Shell and other oil and gas companies are attempting to line their own pockets by turning the country’s massive oversupply of fracked gas into plastic. And just as Shell and state governments have put the health of residents and workers on the line by continuing construction during a global pandemic, they are sacrificing the health of communities on the frontlines of the plastic industry and climate change by pushing forward the build-out of the petrochemical industry during a global climate crisis.

This election year, while public officials are pushing forward major action to respond to the economic collapse, let’s push for policies and candidates that align with the people’s needs, not Big Oil’s.

By Erica Jackson, Community Outreach & Communications Specialist, FracTracker Alliance

Fracking Water Use in Pennsylvania Increases Dramatically

May 29, 2020/by Matt Kelso, BA

Unconventional wells in Pennsylvania were always resource-intensive, but the maps below show how the amount of water used per well has grown significantly in recent years. In 2013, these wells used an average of 5.8 million gallons per well. By 2019, that figure had increased 145%, consuming more than 14.3 million gallons per well. This is a glimpse into the unsustainable resource demands of this industry and the decreasing energy returned on investment.

As fracking proponents will eagerly remind you, hydraulic fracturing was invented decades ago – back in 1947 – so the practice has been in use for quite a while. What really separates modern unconventional shale gas wells from the supposedly traditional, conventional wells is more a matter of scale than anything else. While conventional wells are typically fracked with tens of thousands of gallons of fluid, their unconventional counterparts are far thirstier, consuming millions of gallons per well.

And of course, more inputs translate into more outputs — not necessarily in the form of gas, but in the form of toxic, radioactive waste. This creates a slew of problems ranging from health impacts, to increased transportation, to disposal.

View map fullscreen | How FracTracker maps work

However, this increase in consumption has continued to grow on a per-well basis, so that wells drilled in recent years aren’t really in the same category as wells drilled a decade ago at the beginning of Pennsylvania’s unconventional boom.

In Pennsylvania, unconventional wells are primarily drilled into two deep shale layers, the Devonian-aged Marcellus Shale, which is about 390 million years old, and the Utica Shale from the Late Ordovician period, which was deposited about 60 million years before the Marcellus. These formations have been known about for decades, but did not yield enough gas justify the expense of drilling until the 21^st century, when horizontal drilling allowed for a much greater surface area of exposure to the shale formations. However, stimulating this increased distance also requires significantly more fracking fluid – a mixture of water, sand, and chemicals – which increased the consumptive use of water by several orders of magnitude. And in the end, all of this extra work that is required to extract the gas from the ground has made the industry unprofitable, as high production numbers have outpaced demand.

FracFocus Data

As residents in shale fields around the country started to see impacts to their drinking water, they began to demand to know more about what was injected into the ground around them. The industry’s response was FracFocus, a national registry to address the water component of this question, if not the issue of fracking chemicals. In the early days, visitors to the site could only access data one well at a time, so systematic analyses by third parties were precluded. Additionally, record keeping was sloppy, with widespread data entry issues, incorrect locations, duplicate entries, and so forth.

Many of these issues were addressed with the rollout of FracFocus 2.0 in May of 2013. This fixed many of the data entry issues, such as the six different spellings of “Susquehanna” that were used, and enabled downloads of the entire data set. For that reason, when we wanted to look at changes over time, our analysis started in 2013, where only minimal obvious corrections were required at the county level.

Unconventional wells in Pennsylvania were always resource-intensive, but this GIF shows that the amount of water used per well has grown significantly in recent years. In 2013, these wells used an average of 5.8 million gallons per well. By 2019, that figure had increased 145%, consuming more than 14.3 million gallons per well. This is a glimpse into the unsustainable resource demands of this industry and the decreasing energy returned on investment.

However, statewide data is available since 2008, and as long as we keep in mind the data quality issues from the earlier years, the results are even more stark.

Year	FracFocus Reports	Total Water (gal)	Average Water per Well (gal)	Maximum Water (gal)
2008	2	4,117,827	4,117,827	4,117,827
2009	19	37,415,216	4,157,246	6,176,104
2010	57	123,747,550	4,267,157	7,595,793
2011	1,174	786,513,944	4,345,381	12,146,478
2012	1,375	2,721,696,367	4,676,454	14,247,085
2013	1,272	7,431,752,338	5,842,573	19,422,270
2014	1,277	10,359,150,398	8,112,099	26,927,838
2015	904	8,216,787,382	9,089,367	32,049,750
2016	589	5,933,622,817	10,074,063	32,701,940
2017	710	8,547,034,675	12,038,077	38,681,496
2018	805	10,901,333,749	13,542,030	36,812,580
2019	686	9,811,475,207	14,302,442	39,329,556
2020	76	986,425,600	12,979,284	29,177,980
Grand Total	8,946	65,861,073,069	9,248,852	39,329,556

Figure 1: While the total number of frack jobs reported to FracFocus has declined over the years, the amount of water per well has increased substantially.

In terms of the total number of unconventional wells drilled, the boom years in Pennsylvania were around 2010 to 2014, with more than 1,000 wells drilled each of those years, a total that has not been achieved again since. It is important to note that in this FracFocus data, we are not counting the wells, per se, but the reported instances of well stimulation through hydraulic fracturing, commonly called frack jobs. In the earliest portion of the date range, submitting data to FracFocus was voluntary, and therefore the total activity from 2008 through 2010 is vastly undercounted, but we have included what data was available.

It should be noted that the average consumption for frack jobs started in 2020 are down from the 2019 totals, however, the sample size is considerably smaller. This smaller sample due, in part, to reduced drilling activity due to oversupply of gas in the Northeast, but also due to the fact that the year is still in progress. This analysis is based on data downloaded from FracFocus in April 2020.

Changes Over Time

As we examine changes in the average water consumption over time from Figure 1, we can see that operators in Pennsylvania averaged between 4-5 million gallons of water per well from 2008 to 2012. The numbers take off from there, tripling to more than 14 million gallons for 2019, the last full year available. At the same time, drilling operators began experimenting with truly monstrous quantities of water. In 2008, the only well with water data available used just over 4.1 million gallons. By 2019, there was a well that used 39.3 million gallons of water, almost a tenfold increase.

From late 2008 through early 2020, the industry recorded the use of 65.8 billion gallons of water in unconventional wells. Since we know that many wells during the early boom years did not report to FracFocus, the actual usage must be substantially higher. For the years with the most reliable and complete data – 2013 to 2019 – total water consumption ranged from 5.9 to 10.9 billion gallons per year. For context, the average Pennsylvanian uses about 100 gallons per day, or 36,500 gallons per year.

That means that the 10.9 billion gallons that were pumped into fracked wells in 2018 equals the total usage of 298,667 residents for an entire year. Alternatively, that water could have filled 16,517 Olympic-sized swimming pools. It is equivalent to 33,455 acre-feet, meaning it could fill an acre-sized column of water that stretches more than six miles high.

Surely, there must be a better way to make use of our precious resources than to turn millions upon millions of gallons of water into toxic waste.

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

The Hidden Inefficiencies and Environmental Costs of Fracking in Ohio

January 13, 2020/by Ted Auch, PhD

Ohio continues to increase fracked gas production, facilitated by access to freshwater and lax radioactive waste disposal requirements.

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Map: Ohio Quarterly Utica Oil and Gas Production along with Quarterly Wastewater Disposal

Well Volumes

A little under a year ago, FracTracker released a map and associated analysis, “A Disturbing Tale of Diminishing Returns in Ohio,” with respect to Utica oil and gas production, highlighting the increasing volume of waste injected in wastewater disposal wells, and trends in lateral length in fracked wells from 2010 to 2018. In this article, I’ll provide an update on Ohio’s Utica oil and gas production in 2018 and 2019, the demands on freshwater, and waste disposal. After looking at the data, I recommend that we holistically price our water resources and the ways in which we dispose of the industry’s radioactive waste in order to minimize negative externalities.

Recently, I’ve been inspired by the works of Colin Woodward[1] and Marvin Harris, who outline the struggle between liberty and the common good. They relate this to the role that commodities and increasing resource intensity play in maintaining or enhancing living standards. This quote from Harris’s “Cannibals and Kings” struck me as the 122 words that most effectively illustrate the impacts of the fracking boom that started more than a decade ago in Central Appalachia:

“Regardless of its immediate cause, intensification is always counterproductive. In the absence of technological change, it leads inevitably to the depletion of the environment and the lowering of the efficiency of production since the increased effort sooner or later must be applied to more remote, less reliable, and less bountiful animals, plants, soils, minerals, and sources of energy. Declining efficiency in turn leads to low living standards – precisely the opposite of the desired result. But this process does not simply end with everybody getting less food, shelter, and other necessities in return for more work. As living standards decline, successful cultures invent new and more efficient means of production which sooner or later again lead to the depletion of the natural environment.” From Chapter 1, page 5 of Marvin Harris’ “Cannibals and Kings: The Origins of Cultures, 1977

In reflecting on Harris’s quote as it pertains to fracking, I thought it was high time I updated several of our most critical data sets. The maps and data I present here speak to intensification and the fact that the industry is increasingly leaning on cheap water withdrawals, landscape impacts, and waste disposal methods to avoid addressing their increasingly gluttonous ways. To this point, the relationship between intensification and resource utilization is not just the purview of activists, academics, and journalists anymore; industry collaborators like IHS Markit admitting as much in their latest analysis pointing to the fact that oil and gas operators “will have to drill substantially more wells just to maintain current production levels and even more to grow production”. Insert Red Queen Hypothesis analogy here!

Oil and Gas Production in Ohio

The four updated data sets presented here are: 1) oil, gas, and wastewater production, 2) surface and groundwater withdrawal rates for the fracking industry, 3) freshwater usage by individual Ohio fracked wells, and 3) wastewater disposal well (also referred to as Class II injection wells) rates.

Below are the most important developments from these data updates as it pertains to intensification and what we can expect to see in the future, with or without the ethane cracker plants being trumpeted throughout Appalachia.

From a production standpoint, total oil production has increased by 30%, while natural gas production has increased by 50% year over year between the last time we updated this data and Q2-2019 (Table 1).

According to the data we’ve compiled, the rate of growth for wastewater production has exceeded oil and is nearly equal to natural gas at 48% from 2017 to 2018. On average the 2,398 fracked wells we have compiled data for are producing 27% more wastewater per well now than they did at the end of 2017.

	————–2017————–			————–2019————–
	Oil (million barrels)	Gas (million Mcf)	Brine (million barrels)	Oil (million barrels)	Gas (million Mcf)	Brine (million barrels)
Max	0.51	12.92	0.23	0.62	17.57	0.32
Total	83.14	5,768.47	76.01	108.15	8,679.12	112.28
Mean	0.40	2.79	0.37	0.45	3.62	0.47

Table 1. Summary statistics for 2,398 fracked wells in Ohio from a production perspective from 2017 to Q2 2019.

$Total fracked gas produced per quarter and average fracked gas produced per well in Ohio from 2013 to Q2-2019.$

Figure 1. Total fracked gas produced per quarter and average fracked gas produced per well in Ohio from 2013 to Q2-2019.

The increasing amount of resources and number of wells necessary to achieve marginal increases in oil and gas production is a critical factor to considered when assessing industry viability and other long-term implications. As an example, in Ohio’s Utica Shale, we see that total production is increasing, but as IHS Markit admits, this is only possibly by increasing the total number of producing wells at a faster rate. As is evidenced in Figure 1, somewhere around the Winter of 2017-2018, the production rate per well began to flatline and since then it has begun to decrease.

Water demands for oil and gas production in Ohio

Since last we updated the industry’s water withdrawal rates, the Ohio Department of Natural Resources (ODNR) has begun to report groundwater rates in addition to surface water. The former now account for nine sites in seven counties, but amount to a fraction of reported withdrawals to date (around 00.01% per year in 2017 and 2018). The more disturbing developments with respect to intensification are:

1) Since we last updated this data, 59 new withdrawal sites have come online. There are currently 569 sites in total in ODNR’s database. This amounts to a nearly 12% increase in the total number of sites since 2017. With this additional inventory, the average withdrawal rate across all sites has increased by 13% (Table 2).

2) Since 2010, the demand for freshwater to be used in fracking has increased by 15.6% or 693 million gallons per year (Figure 2).

3) We expect to see an inflection point when water production will increase to accommodate the petrochemical buildout with cracker plants in Dilles Bottom, OH; Beaver County, PA; and elsewhere. In 2018 alone, the oil and gas industry pulled 4.69 billion gallons of water from the Ohio River Valley. Since 2010, the industry has permanently removed 22.96 billion gallons of freshwater from the Ohio River Valley. It would take the entire population of Ohio five years to use the 2018 rate in their homes.[2]

As we and others have mentioned in the past, this trend is largely due to the bargain basement price at which we sell water to the oil and gas sector throughout Appalachia.[3] To increase their nominal production returns, companies construct longer laterals with orders of magnitude more water, sand, and chemicals. At this rate, the fracking industry’s freshwater demand will have doubled to around 8.8-.9.5 billion gallons per year by around 2023. Figure 3 demonstrates that average fracked lateral length continues to increase to the tune of +15.7-21.2% (+1,564-2,107 feet) per quarter per lateral. This trend alone is more than 2.5 times the rate of growth in oil production and roughly 24% greater than the rate of growth in natural gas production (See Table 1).

4. The verdict is even more concerning than it was a couple years ago with respect to water demand increasing by 30% per quarter per well or an average of 4.73 million gallons (Figure 4). The last time we did this analysis >1.5 years ago demand was rising by 25% per quarter or 3.84 million gallons. At that point I wouldn’t have guessed that this exponential rate of water demand would have increased but that is exactly what has happened. Very immediate conversations must start taking place in Columbus and at the region’s primary distributor of freshwater, The Muskingum Watershed Conservancy District (MWCD), as to why this is happening and how to push back against the unsustainable trend.

	2017	2018
Sites	510	569
Maximum (billion gallons)	1.059	1.661
Sum (billion gallons)	18.267	22.957
Mean (billion gallons)	0.358	0.404

Table 2. Summary of fracking water demands throughout Ohio in 2017 when we last updated this data as well as how those rates changed in 2018.

$Hydraulic fracturing freshwater demand in total across 560+ sites in Ohio from 2010 to 2018 (Million Gallons Per Year).$

Figure 2. Hydraulic fracturing freshwater demand in total across 560+ sites in Ohio from 2010 to 2018 (million gallons per year).

$Average lateral length for all of Ohio’s permitted hydraulically fractured laterals from from Q3-2010 to Q4-2019, along with average rates of growth from a linear and exponential standpoint (Feet).$

Figure 3. Average lateral length for all of Ohio’s permitted hydraulically fractured laterals from from Q3-2010 to Q4-2019, along with average rates of growth from a linear and exponential standpoint (feet).

Figure 4. Average Freshwater Demand Per Unconventional Well in Ohio from Q3-2011 to Q3-2019 (million gallons).

Waste Disposal

When it comes to fracking wastewater disposal, the picture is equally disturbing. Average disposal rates across Ohio’s 220+ wastewater disposal wells increased by 12.1% between Q3-2018 and Q3-2019 (Table 3). Interestingly, this change nearly identically mirrors the change in water withdrawals during the same period. What goes down– freshwater – eventually comes back up.

Across all of Ohio’s wastewater disposal wells, total volumes increased by nearly 22% between 2018 and the second half of 2019. However, the more disturbing trend is the increasing focus on the top 20 most active wastewater disposal wells, which saw an annual increase of 17-18%. These wells account for nearly 50% of all waste and the concern here is that many of the pending wastewater disposal well permits are located on these sites, within close proximity, and/or are proposed by the same operators that operate the top 20.

When we plot cumulative and average disposal rates per well, we see a continued exponential increase. If we look back at the last time, we conducted this analysis, the only positive we see in the data is that at that time, average rates of disposal per well were set to double by the Fall of 2020. However, that trend has tapered off slightly — rates are now set to double by 2022.

Each wastewater disposal well is seeing demand for its services increase by 2.42 to 2.94 million gallons of wastewater per quarter (Figure 5). Put another way, Ohio’s wastewater disposal wells are rapidly approaching their capacity, if they haven’t already. Hence why the oil and gas industry has been frantically submitting proposals for additional waste disposal wells. If these wells materialize, it means that Ohio will continue to be relied on as the primary waste receptacle for the fracking industry throughout Appalachia.

Variable	——————-All Wells——————-			——————-Top 20——————-
Variable	To Q3-2018	To Q3-2019	% Change	To Q3-2018	To Q3-2019	% Change
Number of Wells	223	243	+9.0	——-	——-	——-
Max (MMbbl)	1.12	1.20	+7.1	——-	——-	——-
Sum (MMbbl)	203.19	247.05	+21.6	101.43	119.31	+17.6
Average (MMbbl)	0.91	1.02	+12.1	5.07	5.97	+17.8

Table 3. Summary Statistics for Ohio’s Wastewater Disposal Wells (millions of barrels (MMbbl)).

$Average Fracking Waste Disposal across all of Ohio’s Class II Injection Wells and the cumulative amount of fracking waste disposed of in these wells from Q3-2010 to Q2-2019 (Million Barrels).$

Figure 5. Average Fracking Waste Disposal across all of Ohio’s Wastewater Disposal Wells and the cumulative amount of fracking waste disposed of in these wells from Q3-2010 to Q2-2019 (million barrels).

Using the Pennsylvania natural gas data merged with the Ohio wastewater data, we were able to put a finer point on how much wastewater would be produced with a 100,000 barrel ethane cracker like the one PTT Global Chemical has proposed for Dilles Bottom, Ohio. The following are our best estimate calculations assuming 1 barrel of condensate is 20-40% ethane. These calculations required that we take some liberties with the merge of the ratio of gas to wastewater in Ohio with the ratio of gas to condensate in Pennsylvania:

For 2,064 producing Ohio fracked wells, the ratio of gas to wastewater is 64.76 thousand cubic feet (Mcf) of gas produced per barrel of wastewater.
Assuming 40% ethane, the ratio of gas to condensate in Washington County, PA wells for the first half of 2019 was 320.08 Mcf of gas per barrel of ethane condensate. For 100,000 barrels of ethane needed per cracker per day, that would result in 494,285 barrels (20.76 million gallons) of brine per day.
Assuming 20% ethane, the ratio of gas to condensate in Washington County, PA wells for the first half of 2019 was 640.15 Mcf per barrel of ethane condensate = For 100,000 barrels of ethane needed per cracker per day that would result in 988,571 barrels/41.52 million gallons of wastewater per day.

But wait, here is the real stunner:

The 40% assumption result is 3.81 times the daily rates of wastewater taken in by our current inventory of wastewater disposal wells and 5.37 times the daily rates of brine taken in by the top 20 wells (Note: the top 20 wastewater disposal wells account for 71% of all wastewater waste taken in by all of the state’s disposal wells).
The 20% assumption result is 7.62 times the daily rates of wastewater taken in by our current inventory of wastewater disposal wells and 10.74 times the daily rates of wastewater taken in by the top 20 wells.

Therefore, we estimate the fracked wells supplying the proposed PTTGC ethane cracker will generate between 20.76 million and 41.52 million gallons of wastewater per day. That is 3.8 to 7.6 times the amount of wastewater currently received by Ohio’s wastewater disposal wells.

What does this means in terms of truck traffic? We can assume that at least 80% of the trucks that transport wastewater are the short/baby bottle trucks which haul 110 barrels per trip. This means that our wastewater estimates would require between 4,493 and 8,987 truck trips per day, respectively. The pressures this amount of traffic will put on Appalachian roads and communities will be hard to measure and given the current state of state and federal politics and/or oversight it will be even harder to measure the impact inevitable spills and accidents will have on the region’s waterways.

Conclusion

There is no reason to believe these trends will not persist and become more intractable as the industry increasingly leans on cheap waste disposal and water as a crutch. The fracking industry will continue to present shareholders with the illusion of a robust business model, even in the face of rapid resource depletion and precipitous production declines on a per well basis.

I am going to go out on a limb and guess that unless we more holistically price our water resources and the ways in which we dispose of the industry’s radioactive waste, there will be no other supply-side signal that we could send that would cause the oil and gas industry to change its ways. Until we reach that point, we will continue to compile data sets like the ones described above and included in the map below, because as Supreme Court Justice Louis Brandeis once said, “Sunlight is the best disinfectant!”

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

[1] Colin Woodward’s “American Character: A history of the epic struggle between individual liberty and the common good” is a must read on the topic of resource utilization and expropriation.

[2] https://pubs.er.usgs.gov/publication/cir1441

[3] In Ohio the major purveyor of water for the fracking industry is the Muskingum Watershed Conservancy District (MCWD) and as we’ve pointed out in the past they sell water for roughly $4.50 to $6.50 per thousand gallons. Meanwhile across The Ohio River the average price of water for fracking industry in West Virginia in the nine primary counties where fracking occurs is roughly $8.38 per thousand gallons.

Data Downloads

Quarterly oil, gas, brine, and days in production for 2,390+ Unconventional Utica/Point Pleasant Wells in Ohio from 2010 to Q2-2019

https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2019/12/Production_To_Q2_2019_WithExcel.zip

Ohio Hydraulic Fracturing Freshwater and Groundwater Withdrawals from 2010 to 2018

https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2019/12/OH_WaterWithdrawals_2010_2018_WithExcel.zip

Lateral length (Feet) for 3,200+ Fracked Utica/Point Pleasant Wells in Ohio up to and including wells permitted in December, 2019

https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2020/01/OH_Utica_December_2019_StatePlane_Laterals.zip

Freshwater Use for 2,700+ Unconventional Wells in Ohio from Q3-2011 to Q3-2019

https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2019/12/OH_FracFocus_December_2019_WithExcel.zip

Quarterly Volume Disposal (Barrels) for 220+ Ohio Class II Salt Water Disposal Wells from 2010 to Q4-2019

https://www.fractracker.org/a5ej20sjfwe/wp-content/uploads/2019/12/OH_ClassII_Loc_Vols_10_Q4_2019_WithExcel.zi

Fracking in Pennsylvania: Not Worth It

January 7, 2020/by Matt Kelso, BA

Despite the ever-increasing heaps of violations and drilling waste, Pennsylvania’s fracked wells continue to produce an excess supply of gas, driving prices down. To cut their losses, the oil and gas industry is turning towards increased exports and petrochemical production. Continuing to expand fracking in Pennsylvania will only increase risks to the public and to the climate, all for what may amount to another boom and bust cycle that is largely unprofitable to investors.

Let’s take a look at gas production, waste, newly drilled wells, and violations in Pennsylvania in the past year to understand just how precarious the fracking industry is.

Production

Fracked hydrocarbon production continues to rise in Pennsylvania, resulting in an increase in waste production, violations, greenhouse gas emissions, and public health concerns. There are three types of hydrocarbons produced from wells in Pennsylvania: gas, condensate, and oil. Gas is composed mostly of methane, the most basic of the hydrocarbons, but in some parts of Pennsylvania, there can be significant quantities of ethane, propane, and other so-called “natural gas liquids” (NGLs) mixed in. Each of these NGLs are actually gaseous at atmospheric conditions, but operators try to separate these with a combination of pressure and low temperatures, converting them to a liquid phase. Some of these NGLs can be separated on-site, and this is typically referred to as condensate. Fracked wells in Pennsylvania also produce a relatively tiny amount of oil.

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For those of you wondering why we are looking at the November, 2018 through October, 2019 time frame, this is simply a reflection of the available data. In this 12-month period, 9,858 fracked Pennsylvania wells, classified as “unconventional,” reported producing 6.68 trillion cubic feet of gas (Tcf), 4.89 million barrels of condensate, and just over 70,000 barrels of oil.

By means of comparison, Pennsylvania consumed about 1.46 Tcf of gas across all sectors in 2018, of which just 253 billion cubic feet (Bcf) was used in the homes of Pennsylvania’s 12.8 million residents. In fact, the amount of gas produced in Pennsylvania exceeds residential consumption in the entire United States by almost 1.7 Tcf. However, less than 17% of all gas consumed in Pennsylvania is for residential use, with nearly 28% being used for industrial purposes (including petrochemical development), and more than 35% used to generate electricity.

Fracked Gas Production and Consumption in Pennsylvania from 2013 through 2018

Figure 1. Fracked gas production compared to all fracked gas consumption and residential gas consumption in Pennsylvania from 2013 through 2018. Data from ref. Energy Information Administration.

While gas production has expansive hotspots in the northeastern and southwestern portions of the state, the liquid production comes from a much more limited geography. Eighty percent of all condensate production came from Washington County, while 87% of all fracked oil came from wells in Mercer County.

Because the definition of condensate has been somewhat controversial in the past (while the oil export ban was still in effect), I asked the Department of Environmental Protection (DEP) for the definition, and was told that if hydrocarbons come out of the well as a liquid, they should be reported as oil. If they are gaseous but condense to a liquid at standard temperature and pressure (60 degrees Fahrenheit and pressure 14.7 PSIA) on-site, then it is to be reported as condensate. Any NGLs that remain gaseous but are removed from the gas supply further downstream are reported as gas in this report. For this reason, it is not really possible to use the production report to find specific amounts of NGLs produced in the state, but it certainly exceeds condensate production by an appreciable margin.

The one-year volume withdrawal of gas from unconventional wells in Pennsylvania is equal to the volume of 3.2 Mount Everests

The volume of gas withdrawn from fracked wells in Pennsylvania in just one year is equal to the volume of 3.2 Mount Everests!

Waste

Hydrocarbons aren’t the only thing that come out of the ground when operators drill and frack wells in Pennsylvania. Drillers also report a staggering amount of waste products, including more than 65 million barrels (2.7 billion gallons) of liquid waste and 1.2 million tons of solid waste in the 12-month period.

Waste facilities have significant issues such as inducing earthquakes, toxic leachate, and radioactive sediments in streambeds.

Waste Type	Liquid Waste (Barrels)	Solid Waste (Tons)
Basic Sediment	63
Brine Co-Product	247
Drill Cuttings		1,094,208
Drilling Fluid Waste	1,439,338	11,378
Filter Socks		143
Other Oil & Gas Wastes	2,236,750	6,387
Produced Fluid	61,376,465	41,165
Servicing Fluid	17,196	3,250
Soil Contaminated by Oil & Gas Related Spills		25,505
Spent Lubricant Waste	1,104
Synthetic Liner Materials		21,051
Unused Fracturing Fluid Waste	7,077	1,593
Waste Water Treatment Sludge		35,151
Grand Total	65,078,240	1,239,831

Figure 2. Oil and gas waste generated by fracked wells as reported by drillers from November 1, 2018 through October 31, 2019. Data from ref: PA DEP.

Some of the waste is probably best described as sludge, and several of the categories allow for reporting in barrels or tons. Almost all of the waste was in the well bore at one time or another, although there are some site-related materials that need to be disposed of, including filter socks which separate liquid and solid waste, soils contaminated by spills, spent lubricant, liners, and unused frack fluid waste.

Where does all of this waste go? We worked with Earthworks earlier this year to take a deep dive into the data, focusing on these facilities that receive waste from Pennsylvania’s oil and gas wells. While the majority of the waste is dealt with in-state, a significant quantity crosses state lines to landfills and injection wells in neighboring states, and sometimes as far away as Idaho.

Please see the report, Pennsylvania Oil & Gas Waste for more details.

Read the Report

Drilled Wells

Oil and gas operators have started the drilling process for 616 fracking wells in 2019, which appear on the Pennsylvania DEP spud report. This is less than one third of the 2011 peak of 1,956 fracked wells, and 2019 is the fifth consecutive year with fewer than 1,000 wells drilled. This has the effect of making industry projections relying on 1,500 or more drilled wells per year seem rather dubious.

Fracked Unconventional Wells Drilled per Year in Pennsylvania from 2005 through 2019

Figure 3. Unconventional (fracked) wells drilled from 2005 through December 23, 2019, showing totals by regional office. Data from ref: PA DEP.

Oil and gas wells in Pennsylvania fall under the jurisdiction of three different regional offices. By looking at Figure 2, it becomes apparent that the North Central Regional Office (blue line) was a huge driver of the 2009 to 2014 drilling boom, before falling back to a similar drilling rate of the Southwest Regional Office.

The slowdown in drilling for gas in recent years is related to the lack of demand for the product. In turn, this drives prices down, a phenomenon that industry refers to as a “price glut.” The situation it is forcing major players in the regions such as Range Resources to reduce their holdings in Appalachia, and some, such as Chevron, are pulling out entirely.

Violations

Disturbingly, 2019 was the fifth straight year that the number of violations issued by DEP will exceed the total number of wells drilled.

$Unconventional fracked wells drilled and violations issued from 2005 through 2019$

Figure 4. Unconventional (fracked) drilled wells and issued violations from 2005 through December 2019. Data from ref: DEP.

Violations related to unconventional drilling are a bit unwieldy to summarize. The 13,833 incidents reported in Pennsylvania fall into 359 different categories, representing the specific regulations in which the drilling operator fell short of expectations. The industry likes to dismiss many of these as being administrative matters, and indeed, the DEP does categorize the violations as either “Administrative” or “Environmental, Health & Safety”. However, 9,998 (72%) of the violations through December 3, 2019, are in the latter category, and even some of the ones that are categorized as administrative seem like they ought to be in environmental, health, and safety. For example, let’s look at the 15 most frequent infractions:

Violation Code	Incidents	Category
SWMA301 – Failure to properly store, transport, process or dispose of a residual waste.	767	Environmental Health & Safety
CSL 402(b) – POTENTIAL POLLUTION – Conducting an activity regulated by a permit issued pursuant to Section 402 of The Clean Streams Law to prevent the potential of pollution to waters of the Commonwealth without a permit or contrary to a permit issued under that authority by the Department.	613	Environmental Health & Safety
102.4 – Failure to minimize accelerated erosion, implement E&S plan, maintain E&S controls. Failure to stabilize site until total site restoration under OGA Sec 206(c)(d)	595	Environmental Health & Safety
SWMA 301 – MANAGEMENT OF RESIDUAL WASTE – Person operated a residual waste processing or disposal facility without obtaining a permit for such facility from DEP. Person stored, transported, processed, or disposed of residual waste inconsistent with or unauthorized by the rules and regulations of DEP.	540	Environmental Health & Safety
601.101 – O&G Act 223-General. Used only when a specific O&G Act code cannot be used	469	Administrative
402CSL – Failure to adopt pollution prevention measures required or prescribed by DEP by handling materials that create a danger of pollution.	362	Environmental Health & Safety
78.54* – Failure to properly control or dispose of industrial or residual waste to prevent pollution of the waters of the Commonwealth.	339	Environmental Health & Safety
401 CSL – Discharge of pollutional material to waters of Commonwealth.	299	Environmental Health & Safety
102.4(b)1 – EROSION AND SEDIMENT CONTROL REQUIREMENTS – Person conducting earth disturbance activity failed to implement and maintain E & S BMPs to minimize the potential for accelerated erosion and sedimentation.	285	Environmental Health & Safety
102.5(m)4 – PERMIT REQUIREMENTS – GENERAL PERMITS – Person failed to comply with the terms and conditions of the E & S Control General Permit.	283	Environmental Health & Safety
78.56(1) – Pit and tanks not constructed with sufficient capacity to contain pollutional substances.	256	Administrative
78a53 – EROSION AND SEDIMENT CONTROL AND STORMWATER MANAGEMENT – Person proposing or conducting earth disturbance activities associated with oil and gas operations failed to comply with 25 Pa. Code § 102.	247	Environmental Health & Safety
102.11(a)1 – GENERAL REQUIREMENTS – BMP AND DESIGN STANDARDS – Person failed to design, implement and maintain E & S BMPs to minimize the potential for accelerated erosion and sedimentation to protect, maintain, reclaim and restore water quality and existing and designated uses.	235	Environmental Health & Safety
CSL 401 – PROHIBITION AGAINST OTHER POLLUTIONS – Discharged substance of any kind or character resulting in pollution of Waters of the Commonwealth.	235	Environmental Health & Safety
OGA3216(C) – WELL SITE RESTORATIONS – PITS, DRILLING SUPPLIES AND EQUIPMENT – Failure to fill all pits used to contain produced fluids or industrial wastes and remove unnecessary drilling supplies/equipment not needed for production within 9 months from completion of drilling of well.	206	Environmental Health & Safety

Figure 5. Top 15 most frequently cited violations for unconventional drilling operations in Pennsylvania through December 3, 2019. Data from ref: DEP.

Of the 15 most common categories, only two are considered administrative violations. One of these is a general code, where we don’t know what happened to warrant the infraction without reading the written narrative that accompanies the data, and is therefore impossible to categorize. The only other administrative violation in the top 15 categories reads, “78.56(1) – Pit and tanks not constructed with sufficient capacity to contain pollutional substances,” which certainly sounds like it would have some real-world implications beyond administrative concerns.

Check out our Pennsylvania Shale Viewer map to see if there are violations at wells near you.

Bloated With Gas, Fraught With Trouble

To address the excess supply of gas, companies have tried to export the gas and liquids to other markets through pipelines. Those efforts have been fraught with trouble as well. Residents are reluctant to put up with an endless barrage of new pipelines, yielding their land and putting their safety at risk for an industry that can’t seem to move the product safely. The Revolution pipeline explosion hasn’t helped that perception, nor have all of the sinkholes and hundreds of leaky “inadvertent returns” along the path of the Mariner East pipeline system. In a sense, the industry’s best case scenario is to call these failures incompetence, because otherwise they would be forced to admit that the 2.5 million miles of hydrocarbon pipelines in the United States are inherently risky, prone to failure any time and any place.

In addition to increasing the transportation and export of natural gas to new markets, private companies and elected officials are collaborating to attract foreign investors to fund a massive petrochemical expansion in the Ohio River Valley. The planned petrochemical plants intend to capitalize on the cheap feedstock of natural gas.

Pennsylvania’s high content of NGLs is a selling point by the industry, because they have an added value when compared to gas. While all of these hydrocarbons can burn and produce energy in a similar manner, operators are required to remove most of them to get the energy content of the gas into an acceptable range for gas transmission lines. Because of this, enormous facilities have to be built to separate these NGLs, while even larger facilities are constructed to consume it all. Shell’s Pennsylvania Petrochemicals Complex ethane cracker being built in Beaver County, PA is scheduled to make 1.6 million metric tons of polyethylene per year, mostly for plastics.

This comes at a time when communities around the country and the world are enacting new regulations to rein in plastic pollution, which our descendants are going to finding on the beach for thousands of years, even if everyone on the planet were to stop using single-use plastics today. Of course, none of these bans or taxes are currently permitted in Pennsylvania, but adding 1.6 million metric tons per year to our current supply is unnecessary, and indeed, it is only the beginning for the region. A similar facility, known as the PTT Global Chemical cracker appears to be moving forward in Eastern Ohio, and ExxonMobil appears to be thinking about building one in the region as well. Industry analysts think the region produces enough NGLs to support five of these ethane crackers.

Despite all of these problems, the oil and gas industry still plans to fill the Ohio River Valley with new petrochemical plants, gas processing plants, and storage facilities in the hopes that someday, somebody may want what they’ve taken from the ground.

Here’s hoping that 2020 is a safer and healthier year than 2019 was. But there is no need to leave it up to chance. Together, we have the power to change things, if we all demand that our voices are heard. As a start, consider contacting your elected officials to let them know that renewing Pennsylvania’s blocking of municipal bans and taxes on plastic bags is unacceptable.

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

Photo by Ted Auch, FracTracker Alliance

Fracking Threatens Ohio’s Captina Creek Watershed

December 20, 2019/by Ted Auch, PhD

FracTracker’s Great Lakes Program Coordinator Ted Auch explores the risks and damages brought on by fracking in Ohio’s Captina Creek Watershed

Scroll down or click here to view the story map full screen

View the Story Map Full Screen

The Captina Creek Watershed straddles the counties of Belmont and Monroe in Southeastern Ohio and feeds into the Ohio River. It is the highest quality watershed in all of Ohio and a great examples of what the Ohio River Valley’s tributaries once looked, smelled, and sounded like. Sadly, today it is caught in the cross-hairs of the oil and gas industry by way of drilling, massive amounts of water demands, pipeline construction, and fracking waste production, transport, and disposal. The images and footage presented in the story map below are testament to the risks and damage inherent to fracking in the Captina Creek watershed and to this industry at large. Data included herein includes gas gathering and interstate transmission pipelines like the Rover, NEXUS, and Utopia (Figure 1), along with Class II wastewater injection wells, compressor stations, unconventional laterals, and freshwater withdrawal sites and volumes.

The image at the top of the page captures my motivation for taking a deeper dive into this watershed. Having spent 13+ years living in Vermont and hiking throughout The Green and Adirondack Mountains, I fell in love with the two most prominent tree species in this photo: Yellow Birch (Betula alleghaniensis) and Northern Hemlock (Tsuga candadensis). This feeling of being at home was reason enough to be thankful for Captina Creek in my eyes. Seeing this region under pressure from the oil and gas industry really hit me in my botanical soul. We remain positive with regards to the area’s future, but protective action against fracking in the Captina Creek Watershed is needed immediately!

Fracking in the Captina Creek Watershed: A Story Map

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Want Not, Waste Not? Fossil Fuel Extraction’s Waste Disposal Challenges

October 3, 2019/by Karen Edelstein

Pennsylvania’s fracking industry is producing record amounts of toxic waste — where does it all go?

Drilling for methane and other fossil fuels is an energy-intensive process with many associated environmental costs. In addition to the gas that is produced through high volume hydraulic fracturing (“unconventional drilling,” or “fracking”), the process generates a great deal of waste at the drill site. These waste products may include several dozen tons of drill cutting at every well that is directionally drilled, in addition to liner materials, contaminated soil, fracking fluid, and other substances that must be removed from the site.

In 2018, Pennsylvania’s oil and gas industry (including both unconventional and conventional wells) produced over 2.9 billion gallons (nearly 69 million barrels) of liquid waste, and 1,442,465 tons of solid waste. In this article, we take a look at where this waste (and its toxic components) end up and how waste values have changed in recent years. We also explore how New York State, despite its reputation for being anti-fracking, isn’t exempt from the toxic legacy of this industry.

Waste that comes back to haunt us

According to a study by Physicians, Scientists and Engineers, over 80% of all waste from oil and gas drilling stays within the state of Pennsylvania. But once drilling wastes are sent to landfills, is that the end of them? Absolutely not!

Drilling waste also gets into the environment through secondary means. According to a recent report by investigative journalists at Public Herald, on average, 800,000 tons of fracking waste from Pennsylvania is sent to Pennsylvania landfills. When this waste is sent to landfills, radioactivity and other chemicals can percolate through the landfill, and are collected as leachate, which is then shipped to treatment plants.

Public Herald documented how fourteen sewage treatment plants in Pennsylvania have been permitted by Pennsylvania’s Department of Environmental Protection (PA DEP) to process and discharge radioactive wastes into more than a dozen Pennsylvania waterways.

Public Herald’s article includes an in-depth analysis of the issue. Their work is supported by a map of the discharge sites, created by FracTracker.

Trends over time

Pennsylvania Department of Environmental Protection maintains a rich database of oil and gas waste and production records associated with their Oil and Gas Reporting Website. The changes in waste disposal from Pennsylvania’s unconventional drilling reveal a number of interesting stories.

Let’s look first at overall unconventional drilling waste.

According to data from the federal Energy Information Administration, gas production in Pennsylvania began a steep increase around 2010, with the implementation of high volume hydraulic fracturing in the Marcellus Shale (see Figure 1). The long lateral drilling techniques allowed industry to exploit exponentially more of the tight shale via single well than was ever before possible with conventional, vertical drilling.

Figure 1. Data summary from FracTracker.org, based on EIA data.

The more recently an individual well is drilled, the more robust the production. We see an overall increase in gas production over time in Pennsylvania over the past decade. Paradoxically, the actual number of new wells drilled each year in the past 4-5 years are less than half of the number drilled in 2011 (see Figure 2).

Figure 2: Data summary from FracTracker.org, based on PA DEP data

Why is this? The longer laterals —some approaching 3 miles or more—associated with new wells allow for more gas to be extracted per site.

With this uptick in gas production values from the Marcellus and Utica Formations come more waste products, including copious amounts drilling waste, “produced water,” and other byproducts of intensive industrial operations across PA’s Northern Tier and southwestern counties.

Comparing apples and oranges?

When we look at the available gas production data compared with data on waste products from the extraction process, some trends emerge. First of all, it’s readily apparent that waste production does not track directly with gas production in a way one would expect.

Recall that dry gas production has increased annually since 2006 (see Figure 1). However, the reported waste quantities from industry have not followed that same trend.

In the following charts, we’ve split out waste from unconventional drilling by solid waste in tons (Figure 3) and liquid waste, in barrels (Figure 4).

Figure 3: Annual tonnage of solid waste from the unconventional oil and gas industry, organized by the state it is disposed in. Data source: PA DEP, processed by FracTracker Alliance

Figure 4: Annual volume of liquid waste from the unconventional oil and gas development, organized by state it is disposed in. One barrel is equivalent to 42 gallons. Data source: PA DEP, processed by FracTracker Alliance

Note the striking difference in disposal information for solid waste, compared with liquid waste, coming from Pennsylvania.

“Disposal Location Unknown”

Until just the last year, often more than 50% of the known liquid waste generated in PA was disposed of at unknown locations. The PA DEP waste report lists waste quantity and method for these unknown sites, depending on the year: “Reuse without processing at a permitted facility,” “Reuse for hydraulic fracturing,” “Reuse for diagnostic purposes,” “Reuse for drilling or recovery,” “Reuse for enhanced recovery,” and exclusively in more recent years (2014-2016), “Reuse other than road-spreading.”

In 2011, of the 20.5 million barrels of liquid waste generated from unconventional drilling, about 56% was allegedly reused on other drilling sites. However, over 9 million barrels—or 44% of all liquid waste—were not identified with a final destination or disposal method. Identified liquid waste disposal locations included “Centralized treatment plant for recycle,” which received about a third of the non-solid waste products.

In 2012, the quantity of the unaccounted-for fracking fluid waste dropped to about 40%. By 2013, the percentage of unaccounted waste coming from fracking fluid dropped to just over 21%, with nearly 75% coming from produced fluid, which is briny, but containing fewer “proprietary”—typically undisclosed—chemicals.

By 2017, accounting had tightened up further. PA DEP data show that 99% of all waste delivered to undisclosed locations was produced fluid shipped to locations outside of Pennsylvania. By 2018, all waste disposal was fully accounted for, according to DEP’s records.

In looking more closely at the data, we see that:

Prior to 2018, well drillers did not consistently report the locations at which produced water was disposed of or reused. Between 2012 and 2016, a greater volume of unconventional liquid waste went unaccounted for than was listed for disposal in all other locations, combined.
In Ohio, injection wells, where liquid waste is injected into underground porous rock formations, accounted for the majority of the increase in waste accepted there: 2.9 million barrels in 2017, and 5.7 million barrels in 2018 (a jump of 97%).
West Virginia’s acceptance of liquid waste increased significantly in 2018 over 2017 levels, a jump of over a million barrels, up from only 55,000. This was almost entirely due to unreported reuse at well pads.
In 2018, reporting, in general, appears to be more thorough than it was in previous years. For example, in 2017, nearly 692,000 barrels of waste were reused at well pads outside PA, but those locations were not disclosed. Almost 7000 more barrels were also disposed of at unknown locations. In 2018, there were no such ambiguities.

A closer look at Pennsylvania’s fracking waste shipped to New York State

Despite a reputation for being resistant to the fracking industry, for most of this decade, the state of New York has been accepting considerable amounts of fracking waste from Pennsylvania. The greatest percentage shipped to New York State is in the form of drilling waste solids that go to a variety of landfills throughout Central and Western New York.

Looking closely at the bar charts above, it’s easy to notice that the biggest recipients of Pennsylvania’s unconventional liquid drilling waste are Pennsylvania itself, Ohio, as well as a significant quantity of unaccounted-for barrels between 2011 and 2016 (“Disposal location unknown”). The data for disposal of solid waste in New York tells a different story, however. In this case, Pennsylvania, Ohio, and New York State all play a role. We’ll take a look specifically at the story of New York, and illustrate the data in the interactive map that follows.

In this map, source locations in Pennsylvania are symbolized with the same color marker as the facility in New York that received the waste from the originating well pad. In the “Full Screen” view, use the “Layers” drop down menu to turn on and off data from separate years.

View map full screen | How FracTracker maps work

Solid waste transported to New York State

From the early days of unconventional drilling in Pennsylvania, New York State’s landfills provided convenient disposal sites due to their proximity to the unconventional drilling occurring in Pennsylvania’s Northern tier of counties. Pennsylvania and Ohio took the majority of solid wastes from unconventional drilling waste from Pennsylvania. New York State, particularly between 2011-2015, was impacted far more heavily than all other states, combined (Figure 5, below).

Figure 5: Known disposal locations (excluding PA and OH) of Pennsylvania’s solid waste. Data source: PA DEP, processed by FracTracker Alliance

Here’s the breakdown of locations in New York to where waste was sent. Solid waste disposal into New York’s landfills also dropped by half, following the state’s ban on unconventional drilling in 2014. Most of the waste after 2012 went to the Chemung County Landfill in Lowman, New York, 10 miles southeast of Elmira.

Figure 6: Solid waste from unconventional drilling, sent to facilities in NYS. Data source: PA DEP, processed by FracTracker Alliance

Is waste immobilized once it’s landfilled?

The fate of New York State’s landfill leachate that originates from unconventional drilling waste is a core concern, since landfill waste is not inert. If drilling waste contains radioactivity, fracking chemicals, and heavy metals that percolate through the landfill, and the resulting leachate is sent to municipal wastewater treatment plants, will traditional water treatment methods remove those wastes? If not, what will be the impact on public and environmental health in the water body that receives the “treated” wastewater? In Pennsylvania, for example, a case is currently under investigation relating to pollution discharges into the Monongahela River near Pittsburgh. “That water was contaminated with diesel fuels, it’s alleged, carcinogens and other pollutants,” said Rich Bower, Fayette County District Attorney.

Currently, a controversial expansion of the Hakes Landfill in Painted Post, New York is in the news. Sierra Club and others were concerned about oversight of radium and radon in the landfill’s leachate and air emissions, presumably stemming from years of receiving drill cuttings. The leachate from the landfill is sent to the Bath Wastewater Treatment plant, which is not equipped to remove radioactivity. “Treated” wastewater from the plant is then discharged into the Cohocton River, a tributary of the Chesapeake Bay. In April 2019, these environmental groups filed a law suit against Hakes C&D Landfill and the Town of Campbell, New York, in an effort to block the expansion.

Similar levels of radioactivity in leachate have also been noted in leachate produced at the Chemung County Landfill, according to Gary McCaslin, President of People for a Healthy Environment, Inc.

In recent years, much of the solid unconventional waste arriving in New York State has gone to the Chemung County Landfill (see Figure 6, above). Over the course of several years, this site requested permission to expand significantly from 180,000 tons per year to 417,000 tons per year. However, by 2016, the expansion was deemed unnecessary, and according, the plans were put on hold, in part “…because of a decline in the amount of waste being generated due to a slower economy and more recycling than when the expansion was first planned years ago.” The data in Figure 5 above also parallel this story, with unconventional drilling waste disposed in New York State dropping from over 200,000 tons in 2011 to just over 20,000 tons in 2018.

Liquid waste transported to New York State

The story about liquid unconventional drilling waste exported from Pennsylvania to states other than Ohio is not completely clear (see Figure 7, below). Note that the data indicate more than a 2000% increase in waste liquids going from Pennsylvania to West Virginia after 2017. While it has not been officially documented, FracTracker has been anecdotally informed that a great deal of waste was already going to West Virginia, but that the record-keeping prior to 2018 was simply not strongly enforced.

Figure 7: Known disposal locations (excluding Pennsylvania and Ohio) of Pennsylvania’s liquid waste. Data source: PA DEP, processed by FracTracker Alliance

Beginning in the very early years of the Pennsylvania unconventional fracking boom, a variety of landfills in New York State have also accepted liquid wastes originating in Pennsylvania, including produced water and flowback fluids (see Figure 8, below).

Figure 8: Liquid waste from unconventional drilling, sent to facilities in New York State. Data source: PA DEP, processed by FracTracker Alliance

In addition, while this information doesn’t even appear in the PA DEP records (which are publicly available back to 2010), numerous wastewater treatment plants did accept some quantity, despite being fully unequipped to process the highly saline waste before it was discharged back into the environment.

One such facility was the wastewater treatment plant in Cayuga Heights, Tompkins County, which accepted more than 3 million gallons in 2008. Another was the wastewater treatment plant in Auburn, Cayuga County, where the practice of accepting drilling wastewater was initially banned in July 2011, but the decision was reversed in March 2012 to accept vertical drilling waste, despite strong public dissent. Another wastewater treatment plant in Watertown, Jefferson County, accepted 35,000 gallons in 2009.

Fortunately, most New York State wastewater treatment plant operators were wise enough to not even consider adding a brew of unknown and/or proprietary chemicals to their wastewater treatment stream. Numerous municipalities and several counties banned fracking waste, and once the ban on fracking in New York State was instituted in 2014, nearly all importation of liquid unconventional drilling waste into the state ceased.

Nevertheless, conventional, or vertical well drilling also generates briny produced water, which the New York State Department of Environmental Conservation (DEC) permits communities in New York to accept for ice and dust control on largely rural roads. These so-called “beneficial use determinations” (BUDs) of liquid drilling waste have changed significantly over the past several years. During the height of the Marcellus drilling in around 2011, all sorts of liquid waste was permitted into New York State (see FracTracker’s map of affected areas) and was spread on roads. As a result, the chemicals—many of them proprietary, of unknown constituents, or radioactive—were indirectly discharged into surface waters via roadspreading.

Overall, in the years after the ban in 2014 on high volume hydraulic fracturing was implemented, restrictions on Marcellus waste coming into New York have strengthened. Very little liquid waste entered New York’s landfills after 2013, and what did come in was sent to a holding facility owned by Environmental Services of Vermont. This facility is located outside Syracuse, New York.

New York State says “no” to this toxic legacy

Fortunately, not long after these issues of fracking fluid disposal at wastewater treatment facilities in New York State came to light, the practice was terminated on a local level. The 2014 ban on fracking in New York State officially prevented the disposal of Marcellus fluids in municipal wastewater treatment facilities and required extra permits if it were to be road-spread.

In New York State, the State Senate—after 8 years of deadlock—in early May 2019, passed key legislation that would close a loophole that had previously allowed dangerous oil and gas waste to bypass hazardous waste regulation. Read the press release from Senator Rachel May’s office here. However, despite strong support from both the Senate, and the Assembly, as well as many key environmental groups, the Legislature adjourned for the 2019 session without bringing the law to a final vote. Said Elizabeth Moran, of the New York Public Interest Research Group (NYPIRG), “I want to believe it was primarily a question of timing… Sadly, a dangerous practice is now going to continue for at least another year.”

See Earthworks’ recent three part in-depth reporting on national, New York, and Pennsylvania oil and gas waste, with mapping support by FracTracker Alliance.

All part of the big picture

As long as hydrocarbon extraction continues, the issues of waste disposal—in addition to carbon increases in the atmosphere from combustion and leakage—will result in impacts on human and environmental health. Communities downstream and downwind will bear the brunt of landfill expansions, water contamination, and air pollution. Impacts of climate chaos will be felt globally, with the greatest impacts at low latitudes and in the Arctic.

Transitioning to net-zero carbon emissions cannot be a gradual endeavor. Science has shown that in order to stay under the 1.5 °C warming targets, it must happen now, and it requires the governmental buy-in to the Paris Climate Agreement by every economic power in the world.

No exceptions. Life on our planet requires it.

We have, at most, 12 years to make a difference for generations to come.

By Karen Edelstein, Eastern Program Coordinator, FracTracker Alliance

Ohio’s Secret Fracking Chemicals

September 12, 2019/by Shannon Smith

Wildness Lost – Pine Creek

August 7, 2019/by Shannon Smith

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

Idle Wells are a Major Risk

April 3, 2019/by Kyle Ferrar, MPH

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

Fracking Energy Return on Investment 2012 – 2020

The North Dakota Shale Viewer

Water Demand Rises for Fracking

Increasing Fracking Waste Production

The Value of Our Water

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Map: Ohio Quarterly Utica Oil and Gas Production along with Quarterly Wastewater Disposal

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Fracking in the Captina Creek Watershed: A Story Map

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Waste that comes back to haunt us

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“Disposal Location Unknown”

A closer look at Pennsylvania’s fracking waste shipped to New York State

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Is waste immobilized once it’s landfilled?

Liquid waste transported to New York State

New York State says “no” to this toxic legacy

All part of the big picture

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