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

FracTracker Alliance

Ethane Cracker Discussion in Regional Air Pollution Report

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Pittsburgh Regional Environmental Threats Analysis (PRETA) Air: Hazardous Air Pollutants

Although now we are an independent non-profit, FracTracker.org actually started as a project of CHEC at the University of Pittsburgh Graduate School of Public Health. At that time, Matt, Kyle, and I worked with researchers such as Drew Michanowicz and Jim Fabisiak of Pitt, as well as Jill Kriesky now of the Southwest PA Environmental Health Project, on a data mapping and analysis project called PRETA. The Pittsburgh Regional Environmental Threats Analysis (PRETA) is intended to inform stakeholders about Southwest Pennsylvania’s major environmental health risks and provide ways to manage them. CHEC worked with key decision makers and other academics to identify, prioritize, and assess these risks. The top three risks identified were ozone, particulate matter (PM), and hazardous air pollutants (HAPs). Due to the extensive time that research like this takes, the final report about hazardous air pollutants was just recently released.

Relevant to our oil and gas readers, the HAPs report included a piece about the proposed ethane cracker slated to be built in Beaver County, PA. Below is an excerpt of PRETA HAPs that discusses how the air quality in our region may change as a result of the removal of the present zinc smelter on that site, in place of the new cracker facility.

 

Read Full Report (PDF)

Excerpt: The Proposed Monaca, PA Ethane Cracker

Future Trends: New Sources of HAPs in Western Pennsylvania?

All of the previous risk analyses and data discussed [earlier in the report] were drawn using historical data collected in previous years. There is considerable delay around emissions inventory collection, air monitoring data collection, atmospheric modeling, and the calculated risk estimates’ being made public. Hence, these analyses speak best toward past and present trends. They often are less useful in predicting future risks, especially when sources and technologies are constantly changing. For example, better pollution mitigation and retrofitting processes should curtail future emissions from present levels. In addition, changing the profile of various industries within a region also will alter atmospheric chemistry and subsequent risks in future scenarios.

In recent years, there has been an unprecedented expansion of unconventional natural gas development (UNGD) in Western Pennsylvania, Ohio, and West Virginia driven in part by the recent feasibility of hydraulic fracturing, which is part of a drilling procedure that allows for the tapping of the vast methane deposits contained in the Marcellus and Utica shales beneath Pennsylvania and surrounding states. Primarily, drillers are seeking to extract methane (CH4), the primary component of natural gas. However, a portion of the natural gas present in our area is considered “wet gas,” which includes heavier hydrocarbons like ethane, propane, and butane that are typically dissolved in a liquid phase or condensate. These compounds are separated from the methane to be marketed as such products as liquid propane or used as feedstock in numerous other chemical processes. Therefore, a high demand remains for wet gas deposits regardless of fluctuating natural gas (methane) market prices. Thus, a large-scale expansion in other industries (e.g., chemical manufacturing) is anticipated to follow UNGD; new industrial facilities are needed to support the refining of wet gas condensates. For example, an ethane cracker converts or “cracks” ethane, a by-product of natural gas, into ethylene so that it can be used in the production of plastics.

Located in Monaca, Pa. (Beaver County), about 12 miles east of the West Virginia border, is an aging zinc smelter owned by the Horsehead Corporation. The present Horsehead facility is currently the largest zinc refining site in the United States, producing metallic zinc and zinc oxide from recycled material and steelmaking waste. The plant opened in the 1920s to take advantage of the by-products of steel manufacturing and has expanded and modernized over time. It employed about 600 workers until recently, when the company announced its relocation to a new state-of-the-art facility in North Carolina in the near future. The scope of this metal-refining operation was such that it was a significant source of metals and criteria air pollutants.

Recently, Shell Chemical, U.S. subsidiary of Royal Dutch Shell PLC, announced plans to build an ethane cracker in the northeast to take advantage of UNGD. Lured by substantial tax benefits and other economic incentives, Shell chose the former zinc smelting site in Monaca as its proposed new location for such a facility and, in March 2012, received the approval from Pennsylvania officials to build this petrochemical complex. The cracker, according to industry representatives, will be a multibillion-dollar structure and provide thousands of jobs for Pennsylvanians 43, 44. However, many of these jobs depend on the influx of concurrent industries and technologies, which are projected to follow in the wake of sufficient petrochemical refining facilities like the ethane cracker. Thus, it is not likely to be the sole source of pollutants in the area once constructed. Though plant construction remains years away, regional air pollutant composition and chemistry are poised to change as well. Adding to the issue is the fact that the zinc smelter, ranked as one of the worst air polluters in the country in 2002 45, will be decommissioned and have its operations moved to North Carolina.

Here, we will attempt to compare the pollutant profiles of the old and new air pollution sources in order to deduce potential air pollutant changes to existing air quality in the region. Previous emission inventories are available for the Horsehead zinc smelter (EPA Toxic Release Inventory for 2008) 46. Although the proposed cracker facility’s engineering specifics are not available yet, using the records of a similar existing wet gas processing plant, we can approximate the proposed cracker’s yearly emissions. In this case, we have chosen the similarly sized Williams Olefins Cracker Facility currently operating in Geismar, La., whose emissions profiles for 2008 also were available 46. This plant, owned by Williams Partners, L.P., processes approximately 37,000 barrels of ethane and 3,000 barrels of propane per day and annually produces 1.35 billion pounds of ethylene.

Table 5 from PRETA HAPs report

In assessing the emission inventories at the two sites, we first sought to compare those pollutants that were common to both facilities. Table 5 (above) compares the annual release of criteria pollutants for which National Ambient Air Quality Standards (NAAQS) exist. These include ozone, sulfur dioxide, nitrogen oxides, particulate matter (PM10, PM2.5), lead, and carbon monoxide, for which health-based regulatory standards exist for their concentration in ambient air1. Not surprisingly, the zinc smelter released large amounts of lead into the air (five tons per year). The proposed ethane cracker, on the other hand, would release only trace amounts of lead into the air and about 0.1 percent of the sulfur dioxide, 3 percent of the carbon monoxide, and 50 percent of the nitrogen oxides of the zinc smelter. Overall, release of PM would be of a similar order of magnitude at the two sites. Thus, the representative cracker facility by itself emits less NAAQS criteria pollutants than the smelter facility.

Table 6 from PRETA HAPs report

Similarly, Table 6 (above) examines similarly reported HAPs released from both of the facilities in question. A comparison of available emissions inventories of HAPs reveals a list of common pollutants, including acrolein, benzene, ethylbenzene, xylene, and volatile organic compounds (VOCs). Note the projected increase in release of acrolein and VOCs by the proposed ethane cracker. The latter are a rather broad class of organic chemicals that have high vapor pressure (low boiling point), allowing appreciable concentrations in the air as a gaseous phase 47, 48. Examples of VOCs include formaldehyde, d-limonene, toluene, acetone, ethanol (ethyl alcohol), 2-propanol (isopropyl alcohol), and hexanal, among others. They are common components of paints, paint strippers, and other solvents; wood preservatives; aerosol sprays; cleansers and disinfectants; moth repellents and air fresheners; stored fuels and automotive products; hobby supplies; and dry-cleaned clothing. They also possess a diverse range of health effects, including, but not limited to, eye and throat irritation, nausea, headaches, nosebleeds, and skin rashes at low doses, and kidney, liver, and central nervous system damage at high doses. Some are known or suspected carcinogens. These chemicals are more often known for their role in indoor air pollution and have been linked to allergies and asthma 49. Recall that acrolein is already the primary driver of noncancer respiratory risk in the PRETA area, and releases from the proposed cracker would theoretically add to that burden.

Table 7 from PRETA HAPs Report 2013

Table 7 shows a compiled list of HAPs that were released from the Geismar plant in 2008 but not from the zinc smelter, highlighting the potential change in the pollutant mixture. For comparison, the pollutants highlighted in yellow represent those that are several orders of magnitude greater than those emitted by the Clairton Coke Works in 2008. Note the rather large emissions of formaldehyde and acetaldehyde that were discussed above as the number one and number five existing cancer drivers in the area.

Other VOCs of note include ethylene glycol, ethylene oxide, methyl-tert-butyl ether and propionaldehyde. While all these pollutants may have toxic effects on their own, one of the primary concerns, especially in outdoor air, should be their ability to form secondary pollutants. For example, we have noted previously that both acetaldehyde and formaldehyde can be formed via photo-oxidation reactions of other hydrocarbons and VOCs. Thus, the direct emissions reported in the table are likely to be significant underestimations of the true burden of acetaldehyde and formaldehyde in the area near the cracker. It also should be mentioned that a complex nonlinear sensitivity exists among VOCs, NOX, and the production rate of ozone (O3). Most urban areas are considered NOX saturated or VOC sensitive and therefore have low VOC/NOX ratios. In these environments, ozone actually decreases with increasing NOX and increases with increasing VOCs—a potentially likely situation within the urban areas of Southwestern Pennsylvania.

In conclusion, it would appear that the replacement of the existing zinc smelter with the proposed ethane cracker has the potential to significantly transform the current pollutant mixture in the region. The elimination of lead and other heavy metal emissions would be replaced by increases in formaldehyde and acetaldehyde. In addition, it does not appear that the proposed ethane cracker alone would increase any of the NAAQS criteria air pollutants, with the possible exception of ozone. On the other hand, the rather large releases of several known cancer drivers, such as formaldehyde and acetaldehyde, from the proposed cracker could increase cancer risk in the immediate proximity. In addition, the large influx of VOCs and fugitive emissions from these operations warrants further predictive analysis, especially with regard to current pollution-mitigating strategies that may not be anticipating a transforming pollutant mix.

Introduction of the ethane cracker & its effect on regional air quality in SW PA

Authors and Credits

University of Pittsburgh Graduate School of Public Health
Center for Healthy Environments and Communities
Pittsburgh, PA | August 2013

Authors

Drew Michanowicz, MPH, CPH
Kyle Ferrar, MPH
Samantha Malone, MPH, CPH
Matt Kelso, BA
Jill Kriesky, PhD
James P. Fabisiak, PhD

Technical Support

Department of Communications Services
Marygrace Reder, BA
Alison Butler, BA

Full HAPs Report (PDF) | Ozone (PDF) | Particulate Matter (PDF)
For questions related to the full report, please contact CHEC.

References Mentioned in Excerpt

43. Detrow , S. (2012). What’s an ethane cracker? StateImpact – Pennsylvania. Accessed 12-18-12: http://stateimpact.npr.org/pennsylvania/tag/ethane-cracker.

44. Kelso, M. (2012). Jobs impact of cracker facility likely exaggerated. FracTracker Alliance. Accessed 12-18-12: www.fractracker.org/2012/06/jobs-impact-of-cracker-facility-likely-exaggerated.

45. SCORECARD: The Pollution Information Site. (2002). Environmental Release Report: Zinc Corp. of America Monaca Smelter. Accessed 12-18-12: http://scorecard.goodguide.com/envreleases/facility.tcl?tri_id=15061ZNCCR300FR#major_chemical_releases.

46. U.S. EPA. (2008). Technology Transfer Network, Clearinghouse for Inventories and Emissions Factors The National Emissions Inventory. The National Emissions Inventory. Accessed 1-25-13: www.epa.gov/ttn/chief/net/2008inventory.html.

47. U.S. EPA. (2012). An Introduction to Indoor Air Quality (IAQ). Volatile Organic Compounds. Accessed 12-18-12: www.epa.gov/iaq/voc.html.

48. U.S. EPA. (2012). Volatile Organic Compounds (VOCs). Accessed 12-18-12: www.epa.gov/iaq/voc2.html.

49. Nielsen, G.D., S.T. Larsen, O. Olsen, M. Lovik , L.K. Poulsen, C. Glue , and P. Wolkoff. (2007). Do indoor chemicals promote development of airway allergy? Indoor Air 17: pp. 236–255.

Read Full Report (PDF)

OH Shale Viewer
Ted Auch, PhD

OH National Response Center Data on Shale Gas Viewer

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By Ted Auch, PhD – Ohio Program Coordinator, FracTracker Alliance

Thanks to the Freedom of Information Act (FOIA), we as US citizens have real-time access to “all oil, chemical, radiological, biological, and etiological discharges into the environment anywhere in the United States and its territories” data via the National Response Center (NRC). The NRC is an:

initial report taking agency…[that] does not participate in the investigation or incident response. The NRC receives initial reporting information only and notifies Federal and State On-Scene Coordinators for response…Verification of data and incident response is the sole responsibility of Federal/State On-Scene Coordinators.[1]

We decided that NRC incident data would make for a useful layer in our Ohio Shale Gas Viewer. As of September 1, 2013 it is included and will be updated bi-monthly. Thanks go out to SkyTruth’s generous researchers Paul Woods and Craig Winters. We have converted an inventory of Ohio reports provided by SkyTruth into a GIS layer on our map, consisting of 1,191 events, including date and type, back to January 2012.


The layer is not visible until you zoom in twice from the default view on the map above. It appears as the silhouette of a person lying on the ground with Skull and crossbones next to it. View fullscreen>

Currently, the layer includes 28 hydraulic fracturing-related events, 61 “Big [Oil and Chemical] Spills,” and 1,102 additional events – most of which are concentrated in the urban centers of Cleveland, Toledo, Columbus, and Toledo OH.

From a Utica Shale corporation perspective, 21 of the 28 reports are attributed to Chesapeake Operating, Inc. (aka, Chesapeake Energy Corporation (CHK)) or 75% of the hydraulic fracturing (HF) events, while CHK only accounts for 48% of all HF drilled, drilling, or producing wells in OH. Anadarko, Devon, Halcon, and Rex are responsible for the remaining 7 reports. They collectively account for 2.7% of the state’s current inventory of unconventional drilled, drilling, or producing wells.

[1] To contact the NRC for legal purposes, email efoia@uscg.mil. The NRC makes this data available back to 1982, but we decided to focus on the period beginning with the first year of Utica permits here in Ohio to the present (i.e., 2010-2013).

Kyle Ferrar, MPH

Local Actions and Local Regulations in California

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By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

The potential for large scale oil development in the Monterey and other shale basins has raised concern in California communities over the use of hydraulic fracturing and other unconventional well stimulation techniques, such as acidizing.  The fact that DOGGR was not tracking the use of these techniques, much less regulating them, has led to a variety of actions being taken by local governments.  Several groups including county directors, city councils, and neighborhood and community councils have passed resolutions supporting state-wide bans on hydraulic fracturing and other controversial stimulation techniques.  As can be seen in the following map, several of them are located within the greater LA metropolitan area, which is currently considering a local moratorium.

This map shows the local civic groups in the LA metropolitan area that have passed resolutions supporting statewide bans/moratoriums on hydraulic fracturing and other controversial stimulation activities.

This map shows the local civic groups [green check marks] in the LA metropolitan area that have passed resolutions supporting statewide bans/moratoriums on hydraulic fracturing and other controversial stimulation activities. Click on the map to view larger image.

Two local jurisdictions, the South Coast Air Quality Management District and the County of Santa Barbara, have enacted their own measures to regulate oil and gas development.  Both require notification of drilling techniques, and Santa Barbara County requires operators to file for a unique permit when using hydraulic fracturing. Data from the county of Santa Barbara’s permitting program was not readily accessible – although it may well be that they have not issued any permits.  The South Coast Air Quality Management District is charged with managing the air quality for Orange County, the city of Los Angeles and the surrounding urban centers of Riverside and San Bernardino.  In the spring of 2013, the SCAQMD passed Southern California rule 1148.2.  The rule requires oil operators to submit specific reports of well activity documenting drilling, chemical use and the well stimulation techniques employed, directly to the SCAQMD.  Reportable methods include acidification, gravel packing, and hydraulic fracturing.  The rule was implemented June 2, 2013. The database of well-site data is readily accessible via the web.  Web users can obtain individual well summaries of drilling activity and chemical-use reports, or download the full data sets.  The site is user-friendly and the data is easily accessible. Unfortunately, the currently available data set is missing some of the most important information, specifically well API numbers – the unique identifier for all wells drilled in the United States.  This data gap makes it impossible to compare or cross-reference this data set with others.

AQMD Wellsites

FracTracker has mapped the well-sites reported on the SCAQMD in the new map on the California page titled California Local Actions, Monitoring and Regulations.  This map outlines the boundaries of SCAQMD and other sub-state regulatory agencies that have elected to manage the drilling activity.  Details on the programs are provided in the map layers.  The data published by the SCAQMD has been included in the map.  In the map above, if you compare the SCAQMD data layer to the Hydraulically Fractured dataset derived by combining DOGGR and FracFocus data, you can see that the two data sets do not look to include the same well sites.  Unfortunately, it cannot be known whether this is merely an issue of slightly dissimilar coordinates or legitimate data gaps; the SCAQMD data set lacks the API identifier for the majority of well sites reported.  Because the regulatory landscape tends to follow the political leadership that reflects the interests of the constituency, legislative districts have also been included as a viewable map layer.   Be active in your democracy.

Kyle Ferrar, MPH

Keeping Track of Hydraulic Fracturing in California

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By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

Environmental regulations in California are considered conservative by most state standards. To name a few practices, the state has developed an air quality review board that conducts independent toxicological assessments on a level competitive with the U.S. EPA, and the state instituted the U.S.’s first green house gas cap and trade program. But most recently the California Department of Conservation’s Division of Oil, Gas and Geothermal Resources (DOGGR) has been criticized in the media for its lack of monitoring of hydraulic fracturing activity. DOGGR has been responsive to criticism and preemptive of legislative action and has begun a full review of all well-sites in California to identify which wells have been hydraulically fractured and plan to monitor future hydraulic fracturing. Additionally they have maintained historical records of all wells drilled, plugged, and abandoned in the state in web-accessible databases, which include data for oil and gas, geothermal, and injection wells, as well as other types of support wells such as pressure maintenance, steam flood etc.. The data is also viewable in map format on the DOGGR’s online mapping system (DOMS).

To understand what is missing from the DOGGR dataset, it was compared to the dataset extracted from FracFocus.org by SkyTruth. The map “Hydraulic Fracturing in California” compares these two datasets, which can be viewed individually or together as one dataset with duplicates removed. It is interesting to note the SkyTruth dataset categorizes 237 wells as hydraulically fractured that DOGGR does not, and identifies three wells (API #’s 11112215, 23727206, and 10120788) not identified in the DOGGR database. For the some of these 237 wells, DOGGR identifies them as new, which means they were recently drilled and hydraulically fractured and DOGGR will be updating their database. Many are identified as active oil and gas wells., while the rest are identified as well types other than oil and gas. Also the SkyTruth dataset from FracFocus data contains additional information about each well-site, which DOGGR does not provide. This includes volumes of water used for hydraulic fracturing and the fracture date, both of which are vital pieces of monitoring information.

The California State Legislature is currently reviewing California Senate Bill 4 (CA SB 4) written by Sen. Fran Pavley (D-Agoura Hills), which would put in place a regulatory structure for permitting and monitoring hydraulic fracturing and other activity.  A caveat for acidification is also included that would require companies to obtain a specific permit from the state before acidizing a well.  The bill has received criticism from both industry and environmentalists.  While it does not call for a moratorium or regulate what chemicals are used, it is the first legislation that requires a full disclosure of all hydraulic fracturing fluid additives, including those considered proprietary.  This is the last of at least seven bills on the issue, the majority of which have been turned down by lawmakers. The most conservative bills (Assemblywoman Mitchell; D-Culver City) proposed moratoriums on hydraulic fracturing in the state. Earlier this year lawmakers approved a bill (Sen. Pavley; D-Agoura Hills) that would direct the state to complete and independent scientific risk assessment of hydraulic fracturing. The bill directs permitters to deny permits if the study is not finished by January 1, 2015, and also requires public notice before drilling as well as disclosure of chemicals (besides those considered proprietary). In May, a bill (Sen. Wold; D-Davis) was passed requiring drillers to file a $100,000 indemnity bond for each well, with an optional blanket indemnity bond of $5 million for operators with over 20 wells. Another bill (Jackson; D-Santa Barbara) that would require monitoring of both transportation and disposal of wastewater was tabled until next year.

Although hydraulic fracturing has been conducted in California for over a decade, it was not monitored or regulated, and the majority of Californians were not aware of it. Industry groups have portrayed the lack of attention as a testament to its environmental neutrality, but Californians living smack dab in the middle of the drilling tend to tell a different story. The issue is now receiving attention because hydraulic fracturing is such a hotbed topic of contention, along with the potential future of the billions of barrels of oil in the Monterey Shale. The unconventional extraction technology necessary to recover the oil from these deep shale formations is state of the art, which means it is not tried and true. The methods include a combination of high tech approaches, such as horizontal drilling, high volume hydraulic fracturing, and acidification to name a few. Realize: if this technology existed for the last 60 years, the Monterey Shale would already have been developed long ago, along with the rest of the U.S. deep shale formations.

Waste produced by Chesapeake Appalachia and the industry leader in each category from unconventional wells in PA between January and June 2013
Matt Kelso, BA

PA Releases Unconventional Production and Waste Data

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The Pennsylvania Department of Environmental Protection (DEP) releases unconventional oil and gas production and waste data twice a year.  It is important to note that both datasets are self-reported from the industry, and there are usually a few operators who miss the reporting deadline.  For that reason, FracTracker usually waits a week or so to capture the results of the fashionably late.  However, after looking at the data, it is likely that there are still operators that have not yet reported.

Production

Production is perhaps the most important metric of the oil and gas industry.  After all, if there were no production, there would be no point in drilling in the first place.  Royalty payments for property owners are based on production values from the wells.  More than that though, it can be an indication of hot spots, and to some degree, which operators are better at getting the product out of the ground than the rest of the field.

Location

Unconventional formations–especially the Marcellus Shale and Utica Shale–underlie about two-thirds of Pennsylvania.  However, that does not mean that if an operator drilling a hole in Clarion County can expect the same result as well in Sullivan County, for example.  Production is unevenly distributed throughout the state:

Unconventional gas production in Pennsylvania from January to June 2013. All production values are in thousands of cubic feet (Mcf). Counties with above average production per well are highlighted in orange.

Unconventional gas production in Pennsylvania from January to June 2013. All production values are in thousands of cubic feet (Mcf). Counties with above average production per well are highlighted in orange.

With 1.4 trillion cubic feet of gas production in half a year from unconventional wells, Pennsylvania has become a major leader in production.  For a quick comparison to other regions of the country, see the Energy Information Administration, (although the EIA has apparently not felt inspired to update their data in a while).

It should be noted that there is also oil and condensate production from unconventional wells in Pennsylvania, although that really amounts to a drop in the barrel, so to speak.  Unlike the Bakken, where gas is seen as a byproduct that is routinely flared because there is no infrastructure ready to accept it, the Marcellus and Utica in Pennsylvania are really all about the gas.  Some of the gas from the western part of the state is considered wet, with heavier hydrocarbons like ethane and propane mixed with the methane, but in terms of this report, there is no distinction between wet gas and dry gas, or pure methane.  Eight out of 17 wells producing oil and 430 out of 505 wells producing condensate are located in Washington County.

Operators

The reason that production values are more telling for geographies than for operators is that most operators in Pennsylvania are limited to select portions of the state, where their leasing strategies were focused.  Therefore, certain companies occupy the regions that yield higher production, while others are left trying to extract from less productive areas.  So looking at production by operator does not necessarily reflect their skill at extraction, but it does does give a general impression of how much one of their wells is likely to produce, which could be useful for people trying to negotiate leases, among other considerations.

Unconventional gas production by operator in Pennsylvania from January to June 2013. All production values are in thousands of cubic feet (Mcf). Operators with above average production are highlighted in orange.

Unconventional gas production by operator in Pennsylvania from January to June 2013. All production values are in thousands of cubic feet (Mcf). Operators with above average production are highlighted in orange.

Note that eight operators on the list have no data.  Presumably, there are the operators that have not yet reported their data to the DEP, although it is possible that some of them could be defunct.  Obviously, any missing data here would also be missing from the county totals.  Alpha Shale is the clear leader in terms of production per well, with about 1.2 million Mcf per well.  Citrus, Rice, and Chief occupy the next teir, with each exceeding an average of 700,000 Mcf.  All four are relatively minor operators, however, with fewer than 100 wells reporting production.  In terms of total production, Chesapeake blows the competition out of the water, with roughly the same production as the next two producers (Cabot and Range) combined.

Waste

Along with all of the profitable gas being produced in Pennsylvania comes all of the various waste products that are created in the process.  Before jumping into the numbers, I’d like to point out that it is likely that operators who have not reported production also have not reported their contribution to the waste.  In its current form, the waste report has 12,604 lines of data from 4,991 different unconventional wells.    Here is a summary of the waste produced by type from unconventional formations in Pennsylvania:

Waste reported from unconventional wells in Pennsylvania from January to June 2013. Note that one barrel equals 42 US gallons.

Waste reported from unconventional wells in Pennsylvania from January to June 2013. Note that one barrel equals 42 US gallons.

Some interesting things are revealed when sorting the waste type data by operator, although the resulting table is a little unweildy, even for me.  But here are a few highlights:

  • Anadarko reported 99.5 percent of basic sediment production  
  • Southwestern Energy produced more than twice as much drill cuttings (128,000 tons) as the next highest operator (Cabot:  50,000 tons)
  • Range Resources led the pack with 172,000 barrels of drilling fluid, with Chevron Appalachia (168,000 barrels) close behind
  • PA Gen Energy had the most flowback fracturing sand reported, with over 8,600 tons, despite having fewer than 100 producing wells.
  • Chevron Appalachia produced the most fracing fluid waste (934,000 barrels), with Range Resources coming in at number two (773,000 barrels).  This is what Pennsylvania calls the flowback fluid; this is not the straight chemical additives that used in the hydraulic fracturing process, but those additives are included in this fluid
  • The most produced fluid, or formation brine, came from Range Resources wells (1.6 million barrels), followed by Chesapeake (1.4 million barrels)
  • 82 percent of the servicing fluid reported was from Cabot (1,741 barrels)
  • 100 percent of the spent lubricant was reported by SWEPI (19 barrels)

Amazingly, despite their overwhelming lead in gas production in the state, Chesapeake Appalachia did not have the most of any of the eight different waste types, and in some cases, were not even close:

Waste produced by Chesapeake Appalachia and the industry leader in each category from unconventional wells in PA between January and June 2013

Waste produced by Chesapeake Appalachia and the industry leader in each category from unconventional wells in PA between January and June 2013

The Pennsylvania waste data is also notable for including the disposal method of the waste:

Disposal method for unconventional waste from PA between January and June 2013

Disposal method for unconventional waste from PA between January and June 2013

And for those who can handle one last table, Pennsylvania also tells us where the waste is disposed:

Destination of unconventional oil and gas waste in PA between January and June 2013, by state

Destination of unconventional oil and gas waste in PA between January and June 2013, by state

 

 

Kyle Ferrar, MPH

FracTracker Alliance’s *NEW* California Shale Viewer

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By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

The FracTracker Alliance has just recently opened a new office based out of Berkeley, California. As a first step in addressing the unique issues of oil and gas extraction in the Golden State, FracTracker has queried the data that is published by the state’s regulatory agencies, and has translated those datasets into various maps that highlight specific issues. As a first step in this process, FracTracker transcribed the well-site data that is publicly available from the California Department of Conservation’s (DOC) Division of Oil, Gas and Geothermal Resources (DOGGR).

This first phase of analysis is presented in FracMapper on the California page, here. FracTracker has translated the entire DOGGR database into a map layer that can be viewed on the California Shale Viewer map, here. The California Shale Viewer will be continuously updated to map the expanding oil and gas development as it occurs. Featured map layers on the California Shale Viewer focus on hydraulic fracturing in the state of California. The hydraulic fracturing well-site data comes from two sources. First, the layer “CA Hydraulically Fractured Wells Identified by DOGGR” portrays the maps identified by regulatory agency as having been hydraulically fractured. The DOGGR is aware that their dataset is not complete in terms of identifying all wells that have been hydraulically fractured. The second source of data is from our friends at SkyTruth, and provided in the layer “CA Hydraulically Fractured Wells Identified by SkyTruth”. Using a crowd-source platform, SkyTruth has generated a dataset based on the information reported to FracFocus.org. FracFocus.org refuses to provide aggregated datasets of their well-site data. These hydraulically fractured well-sites can be viewed as a individual datasets in the California Shale Viewer, or as a combined layer in the map “California Hydraulically Fractured and Conventional Oil and Gas Wells” map, where you are also able to view the dataset of wells FracFocus identifies as hydraulically fractured, but DOGGR does not.

More information concerning the many different types of wells drilled in California and the status of these wells (whether they are planned, active, idle or plugged) can be found in the “Well Type” map and “Well Status” map, also available on the FracTracker California page.

Koontz Class II Injection Well, Trumbull County, Ohio, (41.22806065, -80.87669281) with 260,278 barrels (10,020,704 gallons) of fracking waste having been processed between Q3-2010 and Q3-2012 (Note: Q1-2016 volumes have yet to be reported!).
Ted Auch, PhD

OH Class II Injection Wells – 2012 Year-in-Review

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By Ted Auch, PhD – OH Program Coordinator

Ohio is currently home to 242 of what Ohio Department of Natural Resources (ODNR) calls “Active” Class II Injection wells capable of accepting hydraulic fracturing waste1. This is not an accurate reflection of the state’s entire Class II Injection well inventory, which includes 129 Enhanced Oil Recovery (EOR), 82 Annular Disposal (AD), 221 Salt Water Disposal (SWD), 1,987 Temporarily Abandoned Annular Disposal (TAAD), and 57 Salt Mining (SM) wells. These have all been chronicled in our Shale Gas Waste Disposal Network Map (see below).

View Map Fullscreen >

Data Demographics

Ohio Class II Injection Well Volumes and Depth

Figure 1. Ohio’s Current “Active” and “Other” Class II Injection Well inventory, total depth, and depth interval model

The state’s “Active” stock of Class II wells averages 4,434 ± 2,032 feet in total depth with a range of 871 to 13,727 feet and 793,734 linear feet (Figure 1). The two deepest wells are CNX Gas Company’s 10,490 foot well in Warren Township and David R Hill’s 13,727 foot well in Pease Township, both of which are in Belmont County. The state’s 22 ≥7,000 foot wells are spread throughout the state’s eastern quarter2, however, in Washington (5), Summit (1), Stark (2), Portage (1), Mahoning (3), Guernsey (2), Coshocton (1), Carroll (2), Belmont (2), and Ashtabula (3). Meanwhile the state’s shallow Class IIs are predominantly in Tuscarawas (4) and Morgan (3) Counties (Figure 1)3. The state’s deepest Class II interval is home to very few “Active” wells and likewise is devoid of related – but not currently fracking-related injection wells – Class IIs. The state’s primary Class II counties are Morgan, Perry, and Hocking, with 610 of the state’s 1,988 Temporarily Abandoned Annular Disposal (TAAD) Class IIs at a depth of 2,870-4,000 feet. These “Other” Class IIs are the very wells many Ohioans are worried will be called into service for the disposal of fracking waste as unconventional drilling expands in OH, WV, PA, and potentially NY. Additionally, there are early signs of interest in horizontal drilling in Indiana, Kentucky, Illinois, and Michigan. With this growing interest comes concomitant concerns about disposal in those states, with specific foci on Michigan’s Class IIs in its most sensitive aquifers and natural areas and Illinois’ relatively strict drilling regulations.

Class II Geology

Utilizing data generously provided to us by ODNR’s UIC Section analyst Jennifer Gingras, we were able to take a closer look at OH’s current fracking waste story (Figure 2). Most of the “Active” wells lie within primary shale and secondary siltstone geologies, with secondary formations of importance being sandstones and black shales (Figure 3). Silstone, shale, and black shale are the primary geologies (>50% of the formation) underlying 202 of the state’s “Active” Class IIs; whereas the secondary geology (<50% of the formation) of nearly all (228) “Active” wells is either shale or siltstone.

Ohio Class II and Underlying Primary Geology Ohio Class II and Underlying Secondary Geology Ohio Class II Geology Pie Chart
Figure 2. Ohio’s 146 Active Class II Injection Wells that accepted hydraulic fracturing related brine wastes and their associated primary (Left Plate) and secondary (Right Plate) geologies. Figure 3. The primary and secondary geologies of Ohio’s 179 Active Class II Injection Wells as of December 2012

Class II Volumes 2010-2013

From a volume-injected perspective, 1.480 and 1.813 million barrels of waste fluids were received in and out of district, respectively, with averages of 3,096 and 3,793 barrels per well for a total of 3.29 million barrels year-to-date. The highest volumes received were in the Myers Well in Edinburg Township, Portage County well (received 71,116 “In Sector” barrels) and from “Out of Sector” in the Long Run Disposal Well (SWIW #*) in Newport Township, Washington County (received 208,845 barrels) (Figure 4). These two wells injected the most total drilling waste, followed by Ohio Oil Gathering Corp’s Newport Township, Washington County well and Warren Drilling Corp’s (SWIW #6) Jackson Township, Noble County well (Figure 1).

Ohio "In Sector" Class II and Underlying Primary Geology Ohio "Out Of Sector" Class II and Underlying Primary Geology
Figure 4. Ohio’s Active Class II Injection Wells that accepted hydraulic fracturing related
brine wastes from “In Sector” (Left Plate, 145 Wells) and “Out of Sector (Right Plate, 58 Wells) based locations.

Between 2010 and 2013-Q2, OH’s Class II Injection wells have received 35.058 million barrels, 46.6% from “In Sector” and 53.4% from “Out Of Sector”, with per well averages of 68.4 and 78.3K, respectively. The highest volume quarters to date were Q3 and Q4 of 2012, which boasted a total volume of 7.79 million barrels (59% “In Sector” Vs 41% “Out Of Sector”).

OH’s Fab Four Class II Counties

County No. “Active” Class II Injection Wells Yearly Processed Waste (barrels) Per-Well Average (barrels)
Morrow 13 440,040 33,849
Stark 17 745,601 43,859
Ashtabula 14 846,986 60,499
Portage 13 1,608,139 123,702

 

Combined, 34 of these 57 wells received 27% of the state’s total fracking brine waste.

Our “Shale Gas Waste Disposal Network Map” has been updated to include Q3 2010 to Q2 2913 Class II disposal rates and revenue on a quarterly basis.

Ohio Class II Processing Trajectory

Figure 5. Ohio’s quarterly fluctuations in Class II Injection well waste injected between 2010-Q3 and 2013-Q2 in sector, out of sector, and total

The Ohio Class II Crystal Ball

Using a simple statistical technique called linear regression we can do a decent job of projecting future trends in Ohio’s Class II volume story (Figure 5). Using this technique we see that the average amount of waste injected by the state’s Class II wells increases by 147,202 barrels or 4.64 million gallons per quarter. Most of this trajectory is due to “Out Of Sector” fracking waste, explaining 45% of the 67% quarter-to-quarter change attributed to the simple relationship between fiscal quarter and barrels received.

The amount of Class II Injection well waste received here in Ohio will likely double by the first half of 2015 at 68.379-71.711 million gallons and tripled by Q2-Q3 of 2018 (105.031-108.363 million barrels).

References

[1] Two of these wells are missing Latitude-Longitudes according to a search of the Ohio Department of Natural Resources (ODNR) Risk Based Data Management System (RBDMS) database. Additionally, fifty-one of these “Active” wells had yet to receive fracturing waste at the end of 2013-Q1.

[2] Much of the state’s western half is underlain by Karst topography which is susceptible to subsurface erosion due to the fragility of the limestone geology.

[3] Neighboring West Virginia is home to sixty-two Class II Injection Wells, Pennsylvania 805 “Active” Class IIs, Virginia 8 “Active” Class IIs, and Kentucky 82 Class IIs (US Class II Injection Well soon to arrive on FracTracker).

FracTracker Alliance

FracTracker Touring a Bit of Europe

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Basel_Berlin_DornbirnBy Samantha Malone, MPH, CPH – Manager of Science and Communications, FracTracker Alliance

I stare into my computer during an early morning Skype call with my hosts in Germany. As my cat stubbornly tries to join the conversation, we intently discuss international energy policies, travel plans, and audience demographics. This awkward setup is all in preparation for my upcoming whirlwind tour of Europe. On August 20 and 21, JF&C and Agora Energiewende will host roundtables with participants from their organizations, oil and gas companies, European advisory groups, Green Parliament, and me – just to name a few. This trip is in conjunction with the ISEE conference, where later in the week I will be talking about FracTracker on a panel with other experts regarding shale gas and oil extraction issues.

Hydraulic Fracturing in Europe

One of the many reasons for this trip is because Europe is where the United States was several years ago with regard to the status of drilling, but their circumstances are vastly different. Where the U.S. moved quickly (in most cases) to utilize hydraulic fracturing to extract natural gas and oil, many countries in Europe are only now starting to explore this as an energy option. Some countries, such as France, outright banned the process. Whereas Poland, for many reasons, has embraced the relatively new technology. Just in terms of space, however, Europe is not an ideal location to drill. If you believe Google, in 2011 Europe hosted ~739 million people in an area of 10.82 million km2 – vs. the US in 2012 with ~314 million people in an area of 9.83 million km2. There are several other special considerations that would need to be made in order for Europeans to allow drilling operations like those that involve hydraulic fracturing in their backyards. One such technological advancement, I learned recently, is the option for wells to be completely enclosed (which helps to shield neighbors from potential air, smell, and noise pollution). Whether that refers to an enclosure during drilling or after, remains to be seen. Regardless, I am excited to share my shale gas experiences with others in Europe, but I am even more eager to learn how our experiences differ… The other reason for this trip is for vacation. Can’t fault that!

Schedule

  • Aug 19-23 (All Day): ISEE Conference. Basel, Switzerland
  • Aug 20 (12:00–15:30): JF&C Roundtable. Berlin, Germany
  • Aug 20 (16:00–18:00): Agora Energiewende Roundtable. Berlin, Germany
  • Aug 21 (Morning Meetings): Various groups. Berlin, Germany
  • Aug 22 (14:00-15:30): Conference Panel, S-3-30: Environmental & Occupational Health Risks from Fracking & Natural Gas Extraction. Congress Center, Basel, Switzerland.

When I return from Europe, I plan to write a follow up blog piece (with pictures of my own instead of stock ones). Stay tuned!

North Dakota Bakken Gas Flares
Guest Author

Gas Flaring and Venting: Data Availability and New Methods for Oversight

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By Samir Lakhani, GIS Intern, FracTracker Alliance

In the hazy world of gas flaring and venting, finding worthwhile data often leads one to a dead end. Although the Energy Information Administration (EIA) holds the authority to require active oil/gas companies to disclose this data, they choose not to. EIA will not proceed with such actions because, “…assessing the volume of natural gas vented and flared would add significant reporting burdens to natural gas producers causing them substantial investments.” Additionally, the EIA is not confident that oil/gas producing companies have the capability to accurately estimate their own emissions from venting or flaring activities.

Piece-Meal

Some states do voluntarily submit their estimates, but only 8 of the nation’s 32 oil and gas producing states submit their data. This makes attempts for national estimates incomplete and inaccurate. State officials have repeatedly complained that the EIA has provided them with insufficient guidelines as to how the data should be submitted, and in what format. It appears the only way that concerned parties are able to monitor this practice is with satellite imagery from the sky, to literally watch flaring as it occurs.

Bird’s Eye View

The Bakken Shale Formation has received a considerable amount of attention. We’ve all seen the nighttime satellite images of North Dakota, where a normally quiet portion of the state light up like a bustling city. It is to be understood that not all the lights in this region are gas flares. Much of it is emergency lighting and temporary housing associated with drilling companies.

There are a few obvious issues with satellite surveillance. Firstly, it is difficult to monitor venting emissions from a bird’s eye perspective. Venting is the process by which unsought gas is purposely wafted from drill sites into the atmosphere. Venting is a much more environmentally costly decision compared to the ignited alternative, as pure natural gas is twenty times more potent than CO2 as a greenhouse gas. To monitor venting behavior, from up high, Infrared sensors must be used. Unfortunately, these emissions do not transmit well through the atmosphere. Proper detection must be made much closer to earth’s surface, perhaps from an airplane or on the ground. Secondly, flaring is almost impossible to detect during the day using satellites. One could equate it to attempting to see a flashlight’s beam when the sun is out. Lastly, when the time comes to churn out an estimate on how much gas is really being wasted—the statistics vary wildly.

Using SkyTruth’s satellite image, and GIS data retrieved from North Dakota’s Department of Mineral Resources, it is now possible to pinpoint North Dakota’s most active gas flaring sites. Using this, more accurate estimates are now within reach. North Dakota gas drillers may flare their “associated” gas for up to one year. However, Officials at Mineral Management Service claim that it is not difficult to get an extension, due to economic hardship. There are always instances of gas/oil operators flaring or venting without authorization. In 2003, Shell paid a 49 million dollar settlement over an unnoticed gas flaring and venting operation that lasted several years. The beauty of satellite imagery and GIS detail is the observer’s ability to pinpoint flaring operations and by referencing the leases, evaluate whether or not such practices were authorized.

This map shows flaring activity in the Bakken Formation from January 1 through June 30, 2013. Please click the “Fullscreen” icon in the upper right hand corner to access the full set of map controls.

Regulation and Control

If flaring and venting are costly to the environment and result in a loss of company product (methane), you may ask why these practices are still conducted. Flaring and venting practices are cheaper than building the infrastructure necessary to harness this energy, unfortunately. To effectively collect this resource, a serious piping network is needed. It is as if a solar farm has been built in the desert, but there is no grid to take this power to homes. To lay down piping is an expensive endeavor, and it requires continuous repairs and on-site monitors. Even when North Dakota burns over 30% of their usable product, there is little initiative to invest in long term savings. A second method, called “green completions”, is becoming a more popular choice for oil and gas companies. A green completion is a portable refinery and condensate tank aimed to recover more than half of excess methane produced from drilling. Green completions are the best management practice of today, and the EPA wishes to implement green completion technology nationwide by 2015.

The best way to estimate gas flare and venting emissions is through submissions from gas/oil companies and to analyze the data using GIS applications. Concerned organizations and citizens should not have to rely on satellite services to watch over the towering infernos. There is new research coming out each day on adverse health effects from living in close proximity to a gas flare and vent. It releases a corrosive mixture of chemicals, and returns to the earth as acid rain. Please refer to this publication for a thorough assessment of possible health effects.

This issue is not limited to US borders only; flaring has wreaked havoc in South America, Russia, Africa, and the Middle-East. During the extraction of oil, gas may return to the surface. In many of these areas where oil drilling is prevalent, there are no well-developed gas markets and pipeline infrastructure, which makes venting and flaring a more attractive way to dispose of an unintentionally extracted resource. If the US were to make substantial changes to the way we monitor, regulate, and reduce gas flaring/venting, and accessibility to data, we would set the standard on an international level. Such policy changes include: carbon taxation, streamlining the leasing process (Many oil/gas officials despise the leasing applications for pipelines), installing flaring/venting meters and controls, and tax incentives (to flare and green complete, rather than vent).

All of these changes would tremendously reduce and regulate gas flaring in the US, but without accurate and comprehensive data these proposed policies are meaningless. Data is, and forever will be, the diving board on which policy and change is founded.

Special thanks to Paul Woods and Yolandita Franklin of Skytruth, for using VIIRS and IR technologies to compile the data for the above map.

Karen Edelstein

Registered Water Withdrawals in New York State

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By Karen Edelstein, NY Program Coordinator, FracTracker Alliance

As of April 1, 2013, new regulations 6 NYCRR Parts 601 and 621 in New York State have been in effect that require users of large quantities of water to apply for withdrawal permits. The largest users of water—those with withdrawals of more than 100 million gallons per day—are the first group required to apply. The permit system then adds users on a yearly basis, targeting systems with decreasingly need. In 2014, the target group is users of 10-100 million gallons/day; in 2015, it is 2-10 million gallons/day, and so on. The full schedule is in Table 1, below. There are no fees associated with this permitting process.

In order to assess the geographic impacts of these varying uses, attorney Rachel Treichler submitted a Freedom of Information Law (FOIL) request to the New York State Department of Environmental Conservation. FracTracker Alliance assisted her in this effort by visualizing the data. Treichler believes that the new regulations make it virtually impossible for DEC to balance competing needs between large and small users.

In this interactive map, larger dots signify larger withdrawal. Click on each dot in the map to get more information.

Yellow: 0.0001-0.5 million gal/day
Light green: 0.5001-2 million gal/day
Dark green: 2.001-10 million gal/day
Medium blue: 10.001-100 million gal/day
Dark blue: >100 million gal/day

Until the adoption of these permitting requirements, water withdrawals in New York were governed by riparian rights determined by case law. Riparian rights are correlative–they fluctuate depending on the needs of other users and the amount of water available. Although the new regulations affirm that riparian rights will not be affected by the granting of permits, there is concern that users granted permits for stated amounts of water usage may be reluctant to adjust to the needs of other users in times of water scarcity. In New York State, both the Susquehanna River Basin Commission (SRBC) and the Delaware River Basin Commission (DRBC) have strong regulatory authority over withdrawals, and the new New York regulations provide that withdrawals subject to permitting by these commissions are exempt from the permitting requirements of the regulations. Comparable commissions with authority to regulate water withdrawals do not exist in the Great Lakes watershed, which includes the Finger Lakes Region, or in the other watersheds in the state, and in these watersheds, the permitting requirements of the regulations are the only generally-applicable water permitting requirements.

Currently, New York State has an abundance of water—there is certainly enough to go around to meet domestic and commercial uses. However, with climate change, continued population growth, and the potential for an uptick in hydrofracking throughout the Marcellus and Utica Shale region, the possibility for New York State being asked to sell or export our water increases considerably.

Under the current system, even by 2017, withdrawal permits will not be required for daily use under 100,000 gallons. While cumbersome, it would not be difficult for a typical hydrofracked site to sidestep any withdrawal permitting process if the water were removed over the course of several days by several different private haulers, particularly if the water were hauled any distance. It is conceivable that the gas drilling industry could readily exploit this loophole in the regulations.

Table 1. Dates by which Application for Initial Permit Must Be Completed

June 1, 2013 Systems that withdraw or are designed to withdraw a volume of 100 million gallons per day (mgd) or more
Feb. 15, 2014 Systems that withdraw or are designed to withdraw a volume equal to or greater than 10 mgd but less than 100 mgd
Feb. 15, 2015 Systems that withdraw or are designed to withdraw a volume equal to or greater than 2 mgd but less than 10 mgd
Feb. 15, 2016 Systems that withdraw or are designed to withdraw a volume equal to or greater than 0.5 mgd but less than 2 mgd
Feb. 15, 2017 Systems that withdraw or are designed to withdraw a volume equal to or greater than 0.1 but less than 0.5 mgd

 

Table 2. Water Users with Maximum Usage over 100 MGD

Facility Name Town/City County Average Units Max. Units
St. Lawrence/ FDR Power Project Massena St.Lawrence 79278.00 MGD 108686.00 MGD
Niagara Power Project Lewiston Niagara 47463.00 MGD 62164.00 MGD
Indian Point 2&3 LLCs Cortlandt Westchester 2024.00 MGD 2489.00 MGD
New York City DEP Neversink Sullivan 1078.00 MGD 1418.00 MGD
James A. Fitzpatrick Nuclear Power Plant Scriba Oswego 543.00 MGD 596.00 MGD
Ravenswood Generating Station Queens Queens 512.90 MGD 1390.00 MGD
Arthur Kill Generating Station Richmond Richmond 480.00 MGD 712.80 MGD
Astoria Generating Station Queens Queens 455.60 MGD 723.70 MGD
RE Ginna Nuclear Power Plant Ontario Wayne 427.00 MGD 511.00 MGD
Nine Mile Point Nuclear Station Scriba Oswego 401.10 MGD 457.10 MGD
Roseton Generating Station Newburgh Orange 340.54 MGD 794.40 MGD
Dunkirk Generating Station Dunkirk Chautauqua 304.00 MGD
Danskammer Generating Newburgh Orange 278.80 MGD 455.04 MGD
East River Generating Station New York New York 264.10 MGD 371.80 MGD
AES Somerset Somerset Niagara 239.00 MGD 274.00 MGD
AES Cayuga Lansing Tompkins 214.12 MGD 243.36 MGD
Huntley Generating Station Tonawanda Erie 200.00 MGD 406.00 MGD
Oswego Harbor Power Oswego Oswego 167.70 MGD 364.21 MGD
Genon Bowline Haverstraw Rockland 74.94 MGD 989.29 MGD
Monroe County Water Authority-Shoremont Greece Monroe 55.40 MGD 109.00 MGD

 

 Special thanks to Rachel Treichler for her insights and extensive background knowledge on this topic.