Articles

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.

Pipeline Incidents Updated and Analyzed

April 14, 2014/by Matt Kelso, BA

Pipeline spill in Mayflower, AR on March 29, 2013. Photo by US EPA via Wikipedia.

The debate over the Keystone XL pipeline expansion project has grabbed a lot of headlines, but it is just one of several proposed major pipeline projects in the United States. As much of the discussion revolves around potential impacts of the pipeline system, a review of known incidents is relevant to the discussion.

A year ago, the FracTracker Alliance calculated that there was an average of 1.6 pipeline incidents per day in the United Sates. That figure remains accurate, with 2,452 recorded incidents between January 1, 2010 and March 3, 2014, a span of 1,522 days.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) classifies the incidents into three categories:

Gas transmission and gathering: Gathering lines take natural gas from the wells to midstream infrastructure. Transmission lines transport natural gas from the regions in which it is produced to other locations, often thousands of miles away. Since 2010, there have been 486 incidents on these types of lines, resulting in 10 fatalities, 71 injuries, and $620 million in property damage.
Oil and hazardous liquid: This includes all materials overseen by PHMSA other than natural gas, predominantly crude and refined petroleum products. Liquified natural gas is included in this category. There were 1,511 incidents during the reporting period for these pipelines, causing 6 deaths and 15 injuries, and $1.8 billion in property damage.
Gas distribution: These pipelines are used by utilities to get natural gas to consumers. In just over 40 months, there were 455 incidents, resulting in 42 people getting killed, 183 reported injuries, and $86 million in property damage.

Curiously, while incidents on distribution lines accounted for 72 percent of fatalities and 67 percent of all injuries, the property damage in these cases were only responsible for just over 3 percent of $2.5 billion in total property damage from pipeline spills since 2010. A reasonable hypothesis accounting for the deaths and injuries is that distribution lines are much more common in densely populated areas than are the other types of pipelines; an incident that might be fatal in an urban area might go unnoticed for days in more remote locations, for example. However, as the built environment is also much more densely located in urban areas, it does seem surprising that reported property damage isn’t closer to being in line with physical impacts on humans.

How accurate are the data?

In the wake of the events of September 11, 2001, governmental agency data suddenly became much more opaque. In terms of pipelines, public access to the pipeline data that had been mapped to that point was removed. It was later restored, with limitations. As it stands now, most pipeline data in the United States, including the link to the pipeline proposal map above, are intentionally generalized to the point where pipelines might not even be rendered in the appropriate township, let alone street.

There are some exceptions, though. If you would like to know where pipelines are in US waters in the Gulf of Mexcio, for example, the Bureau of Ocean Energy Management makes that data not only accessible to view, but available for download on data.gov, a site dedicated to data transparency. While the PHMSA will not do the same with terrestrial pipelines, the do release location data along with their incident data.

Pipeline incidents from 1/1/2010 through 3/3/2014. To access details, legend, and other map controls, please click the expanding arrows icon in the top-right corner of the map.

This fatal pipeline incident was in Allentown, PA, but was given coordinates in Greenland.

Unfortunately, we see evidence that the data are not well vetted, at least in terms of location. One of the most serious incidents in the timeframe, an explosion in Allentown, Pennsylvania that killed five people and injured three more, was given coordinates that render in the middle of Greenland. Another incident leading to fatalities was given location data that put it in Manatoba, well outside of the reach of the US agency that publishes the data. Still another incident appears to be in the Pacific Ocean, 1,300 miles west-southwest of Mexico. There are many more examples as well, but the majority of incidents seem to be reasonably well located.

Fuzzy data: are national security concerns justified?

Anyone who watches the news on a regular basis knows that there are people out there who mean others harm. However, a closer look at the incident data shows that pipelines are not a common means of accomplishing such an end.

Causes of pipeline incidents from 1/1/10 to 3/3/14, with counts.

For each category showing causation, there are numerous subcategories. While we don’t need to look into all of those here, it is worth pointing out that there is a subcategory of, “other outside force damage” that is designated as, “intentional damage.” Of the 2,452 total incidents, nine incidents fall into this subcategory. These subcategories are further broken down, and while there is an option to express that the incident is a result of terrorism, none have been designated that way in this dataset . Five of the nine incidents are listed as acts of vandalism, however. To be thorough, and because it provides a fascinating insight into work in the field, let’s take a look at the narrative description for each incident that are labeled as intentional in origin:

Approximately 2 bbls of crude oil were released when an unknown person(s) removed the threaded pressure warning device on the scraper trap’s closure door. As a result of the absence of the 1/2 inch pressure warning device crude oil was able to flow from the open port upon start up of the pipeline and pressurization of the scraper trap. Once this was discovered the 1/2 inch pressure warning device was properly put back into the scaper trap.
Aboveground piping intentionally shot by unknown party. Installed stoppall on line at 176+73 (7 146′) upstream of damaged aboveground piping. Cut and capped pipeline.
Friday october 18th at approximately 6:00 p.m. we were notified of a gas line break at Kayenta Mobile Home Park. The Navajo Police responded to an emergency call about vandals in one of the parks alley ways kicking at meters. Upon arrival they found the broke meter riser at the mobile home park and expediently used the emergency shutdown system to remedy the situation. This immediately cut service to 118 customers in the park. [Names removed] responded to the call. we arrived on site at approximately 9:30 p.m. We located the damage and fixed the system at approximately 1:30 a.m. i called the Amerigas emergency call center and informed them that we would be restarting the system the following morning and to tell our customers they would need to be home in order to restore service. We then started the procedure of shutting every valve off to all customers before restarting the system. We started the system back up at 9:30a.m. 10/19/2013. Once the system was up to full pressure and all systems were normal we began putting customers back into service. The completion of re-establishing service to all customers on the system was completed on 10/23/2013.
A service tech was called at 1:15 am Sunday morning to respond to the Marlboro Fire Department at an apparent explosion and house fire. The tech arrived and called for additional resources. He then began to check for migrating gas in the surrounding buildings along the service to the house and in the street. no gas readings were detected. The distribution and service on call personnel arrived and began calling in additional company resources to assist in the response effort and controlling the incident. A distribution crew was called in to shut off and cut the service. Additional service techs were called in to assist in checking the surrounding buildings and in the streets at catch basins and manholes around the entire block. Gas supply personnel were called in and dispatched to take odorant samples in the houses directly across from 15 Grant Ct. that had active gas service. Gas survey crews were called in to survey Grant St. and the two parallel streets McEnelly St. and Washington Ct. along with the portion of Washington st. in between these streets. The meter and meter bar assembly were taken by the investigators as evidence. The service was pressure tested to the riser which was witnessed by a representative of the DPI. The service was cut off at the main. After the investigators completed gathering evidence at the scene they gave permission to begin cleaning up the site. There was a tenant home at the time of the explosion who was conscious and walking around when the fire department arrived. He was taken to the hospital and reports are that he sustained 2nd and 3rd degree burns on portions of his body.
On Friday, September 7, 2012 PSE&G responded to a gas emergency call involving a gas ignition. The initial call came in from the Orange Fire Department at 17:09 as a house fire at 272 Reock Ave Orange; the fire chief stated gas was not involved and the fire was caused by squatters. Subsequent investigation of the incident revealed that the fire was caused when one of the squatters lit a match which ignited leaking gas originating from gas piping removed from the head of an inside meter set. The gas meter inlet valve and associated piping were all removed by an unknown person on an unknown date prior to the fire. An appliance service tech responded and shut the gas off at the curb at 17:40 on September 7 2012. A street crew was dispatched and the gas service to 272 reock ave was cut at the curb at 19:00. Two people (names unknown) squatters were injured one by the fire one was injured jumping out a window to escape the fire. The home in question was vacated by the owner and the injured parties were trespassing on the property at the time of the incident. PSE&G has been unable to confirm any information on the status of their injuries due to patient confidentiality laws.
The homeowner tampered with company piping by removing 3/4″ steel end cap with a 3/4″ steel nipple on the tee was removed which caused the gas leak in the basement and resulted in a flash fire. The most likely source of ignition was the water heater. The homeowner died in the incident.
A structure fire involved an unoccupied hardware store and a small commercial 12-meter manifold. There were no meters on the manifold and no customers lost service. The heat from the structure fire melted a regulator on the manifold which in turn released gas and contributed to the fire. The cause is officially undetermined; however according to the fire department the cause appears to be arson with the fire starting in the back of the building and not from PG&E facilities. PG&E was notified of this incident by the fire department at 1802 hours. The gas service representative arrived on scene at 1830 hours. The fire department stopped the flow of gas by closing the service valve and the fire was extinguished at approximately 1900 hours. this incident was determined to be reportable due to damages to the building exceeding $50,000. There were no fatalities and no injuries as a result of this incident. Local news media was on-site but no major media was present.
A house explosion and fire occurred at approximately 0208 hours on 2/7/10. The fire department called at PG&E at 0213 hours. PG&E personnel arrived at 0245 hours. The fire department had shut off the service valve and removed the meter before PG&E arrived. The house was unoccupied at the time of the explosion. The gas service account was active and the gas service was on (contrary to initial report). The cause of the explosion is undetermined at the time of this report but the fire department has indicated the cause appears to be arson. After the explosion, PG&E performed a leak survey of the service the services on both sides of this address and the gas main in the front of all three of these addresses. No indication of gas was found. PG&E also performed bar hole tests over the service at 3944 17th Avenue and found no indication of gas. The gas service was cut off at the main and will be re-connected when the customer is ready for service.
On Monday, January 25, 2010 at approximately 2:30pm a single-family home at 2022 west 63rd Street Cleveland OH (Cuyahoga County) was involved in an explosion/fire. The gas service line was shut-off at approximately 4:30pm. A leak survey of the main lines and service lines on W. 83rd between Madison and Lorain revealed no indications of gas near the structure. A service leak at 2131 West 83rd Street was detected during the leak survey. This service line was replaced upon discovery. On Tuesday, January 26th, 2010 the service line at 2022 W. 83rd was air tested at operating pressure with no pressure loss. An odor test was conducted at 2028 West 83rd Street. The results of this odor test revealed odor levels well within dot compliance levels. Our investigation revealed an odor complaint at this residence on January 18th. Dominion personnel responded to the call and met with the Cleveland Fire Department. Dominion found the meter disconnected and the meter shut-off valve in the half open position. The shut-off valve was closed by the Dominion technician and secured with a locking device. The technician placed a 3/4 inch plug in the open end of the valve. The technician also attempted to close the curb-slop valve but could not. The service line was then bar hole tested utilizing a combustible gas indicator from the street to the structure. As a result, no leakage was discovered. A second attempt to close the curb box valve on January 19th ended when blockage was discovered in the valve box. The valve box was in the process of being scheduled for excevatlon and shut off by a construction crew at the time of the incident. An investigation of the incident site determined the cause to be arson as approximately 6 inches of service line and the meter shut-off valve (with locking device still intact) detached from the service line were recovered inside the structure.

While several of these narratives do make it seem as if the incidents in question were deliberate, these seem to have been caused by people on the ground, not by some GIS-powered remote effort. Seven of the nine incidents were on distribution lines, which tend to occur in populated areas, where contact with gas infrastructure is in fact commonplace, and six out of those seven incidents occurred inside houses or other structures.

On the other hand, there is a real danger in not knowing where pipelines are located. 237 accidents were due to excavation activities, and 86 others were caused by boats, cars, or other vehicles unrelated to excavation activity. Better knowledge of the location of these pipelines could reduce these numbers significantly.

Water Use in WV and PA

April 4, 2014/by FracTracker Alliance

Water Resource Reporting and Water Footprint from Marcellus Shale Development in West Virginia and Pennsylvania

Report and summary by Meghan Betcher and Evan Hansen, Downstream Strategies; and Dustin Mulvaney, San Jose State University

The use of hydraulic fracturing for natural gas extraction has greatly increased in recent years in the Marcellus Shale. Since the beginning of this shale gas boom, water resources have been a key concern; however, many questions have yet to be answered with a comprehensive analysis. Some of these questions include:

What are sources of water?
How much water is used?
What happens to this water following injection into wells?

With so many unanswered questions, we took on the task of using publically available data to perform a life cycle analysis of water used for hydraulic fracturing in West Virginia and Pennsylvania.

Summary of Findings

Some of our interesting findings are summarized below:

In West Virginia, approximately 5 million gallons of fluid are injected per fractured well, and in Pennsylvania approximately 4.3 million gallons of fluid are injected per fractured well.
Surface water taken directly from rivers and streams makes up over 80% of the water used in hydraulic fracturing in West Virginia, which is by far the largest source of water for operators. Because most water used in Marcellus operations is withdrawn from surface waters, withdrawals can result in dewatering and severe impacts on small streams and aquatic life.
Most of the water pumped underground—92% in West Virginia and 94% in Pennsylvania—remains there, lost from the hydrologic cycle.
Reused flowback fluid accounts for approximately 8% of water used in West Virginia wells.
Approximately one-third of waste generated in Pennsylvania is reused at other wells.
As Marcellus development has expanded, waste generation has increased. In Pennsylvania, operators reported a total of 613 million gallons of waste, which is approximately a 70% increase in waste generated between 2010 and 2011.
Currently, the three-state region—West Virginia, Pennsylvania, and Ohio—is tightly connected in terms of waste disposal. Almost one-half of flowback fluid recovered in West Virginia is transported out of state. Between 2010 and 2012, 22% of recovered flowback fluid from West Virginia was sent to Pennsylvania, primarily to be reused in other Marcellus operations, and 21% was sent to Ohio, primarily for disposal via underground injection control (UIC) wells. From 2009 through 2011, approximately 5% of total Pennsylvania Marcellus waste was sent to UIC wells in Ohio.
The blue water footprint for hydraulic fracturing represents the volume of water required to produce a given unit of energy—in this case one thousand cubic feet of gas. To produce one thousand cubic feet of gas, West Virginia wells require 1-3 million gallons of water and Pennsylvania wells required 3-4 million gallons of water.

Table 1. Reported water withdrawals for Marcellus wells in West Virginia (million gallons, % of total withdrawals, 2010-2012)

Source: WVDEP (2013a). Note: Surface water includes lakes, ponds, streams, and rivers. The dataset does not specify whether purchased water originates from surface or groundwater. As of August 14, 2013, the Frac Water Reporting Database did not contain any well sites with a withdrawal “begin date” later than October 17, 2012. Given that operators have one year to report to this database, the 2012 data are likely very incomplete.

As expected, we found that the volumes of water used to fracture Marcellus Shale gas wells are substantial, and the quantities of waste generated are significant. While a considerable amount of flowback fluid is now being reused and recycled, the data suggest that it displaces only a small percentage of freshwater withdrawals. West Virginia and Pennsylvania are generally water-rich states, but these findings indicate that extensive hydraulic fracturing operations could have significant impacts on water resources in more arid areas of the country.

While West Virginia and Pennsylvania have recently taken steps to improve data collection and reporting related to gas development, critical gaps persist that prevent researchers, policymakers, and the public from attaining a detailed picture of trends. Given this, it can be assumed that much more water is being withdrawn and more waste is being generated than is reported to state regulatory agencies.

Data Gaps Identified

We encountered numerous data gaps and challenges during our analysis:

All data are self-reported by well operators, and quality assurance and quality control measures by the regulatory agencies are not always thorough.
In West Virginia, operators are only required to report flowback fluid waste volumes. In Pennsylvania, operators are required to report all waste fluid that returns to the surface. Therefore in Pennsylvania, flowback fluid comprises only 38% of the total waste which means that in West Virginia, approximately 62% of their waste is not reported, leaving its fate a mystery.
The Pennsylvania waste disposal database indicates waste volumes that were reused, but it is not possible to determine exactly the origin of this reused fluid.
In West Virginia, withdrawal volumes are reported by well site rather than by the individual well, which makes tracking water from withdrawal location, to well, to waste disposal site very difficult.
Much of the data reported is not publically available in a format that allows researchers to search and compare results across the database. Many operators report injection volumes to FracFocus; however, searching in FracFocus is cumbersome – as it only allows a user to view records for one well at a time in PDF format. Completion reports, required by the Pennsylvania Department of Environmental Protection (PADEP), contain information on water withdrawals but are only available in hard copy at PADEP offices.

In short, the true scale of water impacts can still only be estimated. There needs to be considerable improvements in industry reporting, data collection and sharing, and regulatory enforcement to ensure the data are accurate. The challenge of appropriately handling a growing volume of waste to avoid environmental harm will continue to loom large unless such steps are taken.

Report Resources

Complete Report | Webinar

This report was written on behalf of Earthworks and was funded by a Network Innovation Grant from the Robert & Patricia Switzer Foundation.

This FracTracker article is part of the Water Use Series

Finding PA Department of Environmental Protection Data

March 28, 2014/by FracTracker Alliance

Data transparency is a major issue in the oil and gas world. Some states in the U.S. do not make the location or other details associated with wells easy to find. If one is looking for Pennsylvania data, however, the basic datasets are quite accessible. The PA Department of Environmental Protection (DEP) maintains several datasets on unconventional drilling activity in the Commonwealth and provides this information online and free of charge to the public. The following databases are ones that we commonly use to update our maps and perform data analyses:

1. Wells Drilled (Spudded)

2. Permitted Wells

3. O&G Violations

Search Criteria

Below are tips for how to search the PA DEP’s records and download datasets if you would like:

Dates

Date ranges must be entered in these databases in order to narrow down the search. We suggest starting with 1/1/2000 through current if you would like to see all unconventional activity to date.

County, Municipality, Region, and Operator

This criteria can be further refined by selecting particular counties, regions, etc.

Unconventional Only

For all datasets, “Unconventional Only – Yes” should be selected if you are only interested in the wells that have been drilled into unconventional shale formations and hydraulically fractured, or “fracked.”

“Unconventional” definitions according to PA Code, Chapter 78:

Unconventional well — A bore hole drilled or being drilled for the purpose of or to be used for the production of natural gas from an unconventional formation.

Unconventional formation — A geological shale formation existing below the base of the Elk Sandstone or its geologic equivalent stratigraphic interval where natural gas generally cannot be produced at economic flow rates or in economic volumes except by vertical or horizontal well bores stimulated by hydraulic fracture treatments or by using multilateral well bores or other techniques to expose more of the formation to the well bore.

Download

Once search criteria have been defined, click View Report to see the most up to date information compiled below. From there, the file can be downloaded in different formats, such as a PDF or Excel file.

Visit this page to see all of the oil and gas reports that the PA DEP issues.

H 2 O Where Did It Go?

March 19, 2014/by FracTracker Alliance

By Mary Ellen Cassidy, Community Outreach Coordinator, FracTracker Alliance

A Water Use Series

Many of us do our best to stay current with the latest research related to water impacts from unconventional drilling activities, especially those related to hydraulic fracturing. However, after attending presentations and reading recent publications, I realized that I knew too little about questions like:

How much water is used by hydraulic fracturing activities, in general?
How much of that can eventually be used for drinking water again?
How much is removed from the hydrologic cycle permanently?

To help answer these kinds of questions, FracTracker will be running a series of articles that look at the issue of drilling-related water consumption, the potential community impacts, and recommendations to protect community water resources.

Ceres Report

We have posted several articles on water use and scarcity in the past here, here, here and here. This article in the series will share information primarily from Monika Freyman’s recent Ceres report, Hydraulic Fracturing & Water Stress: Water Demand by the Numbers, February 2014. If you hunger for maps, graphs and stats, you will feast on this report. The study looks at oil and gas wells that were hydraulically fractured between January 2011 and May 2013 based on records from FracFocus.

Class 2 UI Wells

Water scarcity from unconventional drilling is a serious concern. According to Ceres analysis, horizontal gas production is far more water intensive than vertical drilling. Also, the liquids that return to the surface from unconventional drilling are often disposed of through deep well injection, which takes the water out of the water cycle permanently. By contrast, water uses are also high for other industries, such as agriculture and electrical generation. However, most of the water used in agriculture and for cooling in power plants eventually returns to the hydrological cycle. It makes its way back into local rivers and water sources.

In the timeframe of this study, Ceres reports that:

97 billion gallons of water were used, nearly half of it in Texas, followed by Pennsylvania, Oklahoma, Arkansas, Colorado and North Dakota, equivalent to the annual water need of 55 cities with populations of ~ 5000 each.
Over 30 counties used at least one billion gallons of water.
Nearly half of the wells hydraulically fractured since 2011 were in regions with high or extremely high water stress, and over 55% were in areas experiencing drought.
Over 36% of the 39,294 hydraulically fractured wells in the study overlay regions experiencing groundwater depletion.
The largest volume of hydraulic fracturing water, 25 billion gallons, was handled by service provider, Halliburton.

Water withdrawals required for hydraulic fracturing activities have several worrisome impacts. For high stress and drought-impacted regions, these withdrawals now compete with demands for drinking water supplies, as well as other industrial and agricultural needs in many communities. Often this demand falls upon already depleted and fragile aquifers and groundwater. Groundwater withdrawals can cause land subsidence and also reduce surface water supplies. (USGS considers ground and surface waters essentially a single source due to their interconnections). In some areas, rain and snowfall can recharge groundwater supplies in decades, but in other areas this could take centuries or longer. In other areas, aquifers are confined and considered nonrenewable. (We will look at these and additional impact in more detail in our next installments.)

Challenges of documenting water consumption and scarcity

Tracking water volumes and locations turns out to be a particularly difficult process. A combination of factors confuse the numbers, like conflicting data sets or no data, state records with varying criteria, definitions and categorization for waste, unclear or no records for water volumes used in refracturing wells or for well and pipeline maintenance.

Along with these impediments, “chain of custody” also presents its own obstacles for attempts at water bookkeeping. Unconventional drilling operations, from water sourcing to disposal, are often shared by many companies on many levels. There are the operators making exploration and production decisions who are ultimately liable for environmental impacts of production. There are the service providers, like Halliburton mentioned above, who oversee field operations and supply chains. (Currently, service providers are not required to report to FracFocus.) Then, these providers subcontract to specialists such as sand mining operations. For a full cradle-to-grave assessment of water consumption, you would face a tangle of custody try tracking water consumption through that.

To further complicate the tracking of this industry’s water, FracFocus itself has several limitations. It was launched in April 2011 as a voluntary chemical disclosure registry for companies developing unconventional oil and gas wells. Two years later, eleven states direct or allow well operators and service companies to report their chemical use to this online registry. Although it is primarily intended for chemical disclosure, many studies, like several of those cited in this article, use its database to also track water volumes, simply because it is one of the few centralized sources of drilling water information. A 2013 Harvard Law School study found serious limitations with FracFocus, citing incomplete and inaccurate disclosures, along with a truly cumbersome search format. The study states, “the registry does not allow searching across forms – readers are limited to opening one PDF at a time. This prevents site managers, states, and the public from catching many mistakes or failures to report. More broadly, the limited search function sharply limits the utility of having a centralized data cache.”

To further complicate water accounting, state regulations on water withdrawal permits vary widely. The 2011 study by Resources for the Future uses data from the Energy Information Agency to map permit categories. Out of 30 states surveyed, 25 required some form of permit, but only half of these require permits for all withdrawals. Regulations also differ in states based on whether the withdrawal is from surface or groundwater. (Groundwater is generally less regulated and thus at increased risk of depletion or contamination.) Some states like Kentucky exempt the oil and gas industry from requiring withdrawal permits for both surface and groundwater sources.

Can we treat and recycle oil and gas wastewater to provide potable water?

Will recycling unconventional drilling wastewater be the solution to fresh water withdrawal impacts? Currently, it is not the goal of the industry to recycle the wastewater to potable standards, but rather to treat it for future hydraulic fracturing purposes. If the fluid immediately flowing back from the fractured well (flowback) or rising back to the surface over time (produced water) meets a certain quantity and quality criteria, it can be recycled and reused in future operations. Recycled wastewater can also be used for certain industrial and agricultural purposes if treated properly and authorized by regulators. However, if the wastewater is too contaminated (with salts, metals, radioactive materials, etc.), the amount of energy required to treat it, even for future fracturing purposes, can be too costly both in finances and in additional resources consumed.

It is difficult to find any peer reviewed case studies on using recycled wastewater for public drinking purposes, but perhaps an effective technology that is not cost prohibitive for impacted communities is in the works. In an article in the Dallas Business Journal, Brent Halldorson, a Roanoke-based Water Management Company COO, was asked if the treated wastewater was safe to drink. He answered, “We don’t recommend drinking it. Pure distilled water is actually, if you drink it, it’s not good for you because it will actually absorb minerals out of your body.”

Can we use sources other than freshwater?

How about using municipal wastewater for hydraulic fracturing? The challenge here is that once the wastewater is used for hydraulic fracturing purposes, we’re back to square one. While return estimates vary widely, some of the injected fluids stay within the formation. The remaining water that returns to the surface then needs expensive treatment and most likely will be disposed in underground injection wells, thus taken out of the water cycle for community needs, whereas municipal wastewater would normally be treated and returned to rivers and streams.

Could brackish groundwater be the answer? The United States Geological Survey defines brackish groundwater as water that “has a greater dissolved-solids content than occurs in freshwater, but not as much as seawater (35,000 milligrams per liter*).” In some areas, this may be highly preferable to fresh water withdrawals. However, in high stress water regions, these brackish water reserves are now more likely to be used for drinking water after treatment. The National Research Council predicts these brackish sources could supplement or replace uses of freshwater. Also, remember the interconnectedness of ground to surface water, this is also true in some regions for aquifers. Therefore, pumping a brackish aquifer can put freshwater aquifers at risk in some geologies.

Contaminated coal mine water – maybe that’s the ticket? Why not treat and use water from coal mines? A study out of Duke University demonstrated in a lab setting that coal mine water may be useful in removing salts like barium and radioactive radium from wastewater produced by hydraulic fracturing. However, there are still a couple of impediments to its use. Mine water quality and constituents vary and may be too contaminated and acidic, rendering it still too expensive to treat for fracturing needs. Also, liability issues may bring financial risks to anyone handling the mine water. In Pennsylvania, it’s called the “perpetual treatment liability” and it’s been imposed multiple times by DEP under the Clean Streams Law. Drillers worry that this law sets them up somewhere down the road, so that courts could hold them liable for cleaning up a particular stream contaminated by acid mine water that they did not pollute.

More to come on hydraulic fracturing and water scarcity

Although this article touches upon some of the issues presented by unconventional drilling’s demands on water sources, most water impacts are understood and experienced most intensely on the local and regional level. The next installments will look at water use and loss in specific states, regions and watersheds and shine a light on areas already experiencing significant water demands from hydraulic fracturing. In addition, we will look at some of the recommendations and solutions focused on protecting our precious water resources.

Class II Oil and Gas Wastewater Injection and Seismic Hazards in CA

March 15, 2014/by Kyle Ferrar, MPH

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

In collaboration with the environmental advocacy groups Earthworks, Center for Biological Diversity, and Clean Water Action, The FracTracker Alliance has completed a proximity analysis of the locations of California’s Class II oil and gas wastewater injection wells to “recently” active fault zones in California. The results of the analysis can be found in the On Shaky Ground report, available for download at www.ShakyGround.org.¹

Production of oil and natural gas results in a large and growing waste stream. Using current projections for oil development, the report projects a potential 9 trillion gallons of wastewater over the lifetime of the Monterey shale. In California the majority of wastewater is injected deep underground for disposal in wells deemed Class II wastewater injection. The connection between seismic activity and underground injections of fluid has been well established, but with the current surge of shale resource development the occurrence of earthquakes in typically seismically inactive regions has increased, including a recent event in Ohio covered by the LA Times. While both hydraulic fracturing and wastewater injection wells have been linked to the induction of seismic activity, the impacts of underground injection wells used for disposal are better documented and linked to larger magnitude earthquakes.

Therefore, while hydraulic fracturing of oil and gas wells has also been documented to induce seismic activity, the focus of this report is underground injection of waste fluids.

Active CA Faults

A spatial overview of the wastewater injection activity in California and recently active faults can be viewed in Figure 1, below.

Figure 1. California’s Faults and Wastewater Injection Wells. With this and all maps on this page, click on the arrows in the upper right hand corner of the map to view it fullscreen and to see the legend and more details.

The focus of the On Shaky Ground report outlines the relationship between does a thorough job reviewing the literature that shows how the underground injection of fluids induces seismic activity. The proximity analysis of wastewater injection wells, conducted by The FracTracker Alliance, provides insight into the spatial distribution of the injection wells. In addition, the report M7.8 earthquake along the San Andreas fault could cause 1,800 fatalities and nearly $213 billion in economic damages.² To complement the report and provide further information on the potential impacts of earthquakes in California, FracTracker created the maps in Figure 2 and Figure 3.

Shaking Assessments

Figure 2 presents shaking amplification and shaking hazards assessments. The dataset is generated from seismic evaluations. When there is an earthquake, the ground will amplify the seismic activity in certain ways. The amount of amplification is typically dependent on distance to the earthquake event and the material that comprises the Earth’s crust. Softer materials, such as areas of San Francisco built on landfills, will typically shake more than areas comprised of bedrock at the surface. The type of shaking, whether it is low frequency or high frequency will also present varying hazards for different types of structures. Low frequency shaking is more hazardous to larger buildings and infrastructure, whereas high frequency events can be more damaging to smaller structure such as single family houses. Various assessments have been conducted throughout the state, the majority by the California Geological Survey and the United States Geological Survey.

Figure 2. California Earthquake Shaking Amplification and Class II Injection Wells

Landslide Hazards

Below, Figure 3. Southern California Landslide and Hazard Zones expands upon the map included in the On Shaky Ground report; during an earthquake liquefaction of soil and landslides represent some of the greatest hazards. Liquefaction refers to the solid earth becoming “liquid-like”, whereas water-saturated, unconsolidated sediments are transformed into a substance that acts like a liquid, often in an earthquake. By undermining the foundations of infrastructure and buildings, liquefaction can cause serious damage. The highest hazard areas shown by the liquefaction hazard maps are concentrated in regions of man-made landfill, especially fill that was placed many decades ago in areas that were once submerged bay floor. Such areas along the Bay margins are found in San Francisco, Oakland and Alameda Island, as well as other places around San Francisco Bay. Other potentially hazardous areas include those along some of the larger streams, which produce the loose young soils that are particularly susceptible to liquefaction. Liquefaction risks have been estimated by USGS and CGS specifically for the East Bay, multiple fault-slip scenarios for Santa Clara and for all the Bay Area in separate assessments. There are not regional liquefaction risk estimate maps available outside of the bay area, although the CGS has identified regions of liquefaction and landslide hazards zones for the metropolitan areas surrounding the Bay Area and Los Angeles. These maps outline the areas where liquefaction and landslides have occurred in the past and can be expected given a standard set of conservative assumptions, therefore there exist certain zoning codes and building requirements for infrastructure.

Figure 3. California Liquefaction/Landslide Hazards and Class II Injection Wells

Press Contacts

For more information about this report, please reach out to one of the following media contacts:

Alan Septoff
Earthworks
(202) 887-1872 x105
aseptoff@earthworksaction.org

Patrick Sullivan
Center for Biological Diversity
(415) 632-5316
psullivan@biologicaldiversity.org

Andrew Grinberg
Clean Water Action
(415) 369-9172
agrinberg@cleanwater.org

References

Arbelaez, J., Wolf, S., Grinberg, A. 2014. On Shaky Ground. Earthworks, Center for Biological Diversity, Clean Water Action. Available at ShakyGround.org
Jones, L.M. et al. 2008. The Shakeout Scenario. USGS Open File Report 2008-1150. U.S. Department of the Interior, U.S. Geological Survey.

North American Pipeline Proposal Map

March 14, 2014/by Ted Auch, PhD

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

With all the focus on the existing TransCanada Keystone XL pipeline – as well as the primary expansion proposal recently rejected by Lancaster County, NB Judge Stephanie Stacy and more recently the Canadian National Energy Board’s approval of Enbridge’s Line 9 pipeline – we thought it would be good to generate a map that displays related proposals in the US and Canada.

North American Proposed Pipelines and Current Pipelines

To view the fullscreen version of this map along with a legend and more details, click on the arrows in the upper right hand corner of the map.

The map was last updated in October 2014.

Pipeline Incidents

The frequency and intensity of proposals and/or expansions of existing pipelines has increased in recent years to accompany the expansion of the shale gas boom in the Great Plains, Midwest, and the Athabasca Tar Sands in Alberta. This expansion of existing pipeline infrastructure and increased transport volume pressures has resulted in significant leakages in places like Marshall, MI along the Kalamazoo River and Mayflower, AR. Additionally, the demand for pipelines is rapidly outstripping supply – as can be seen from recent political pressure and headline-grabbing rail explosions in Lac-Mégantic, QC, Casselton, ND, Demopolis, AL, and Philadelphia.¹ According to rail transport consultant Anthony Hatch, “Quebec shocked the industry…the consequences of any accident are rising.” This sentiment is ubiquitous in the US and north of the border, especially in Quebec where the sites, sounds, and casualties of Lac-Mégantic will not soon be forgotten.

Improving Safety Through Transparency

It is imperative that we begin to make pipeline data available to all manner of parties ex ante for planning purposes. The only source of pipeline data historically has been the EIA’s Pipeline Network. However, the last significant update to this data was 7/28/2011 – meaning much of the recent activity has been undocumented and/or mapped in any meaningful way. The EIA (and others) claims national security is a primary reason for the lack of data updates, but it could be argued that citizens’ right-to-know with respect to pending proposals outweighs such concerns – at least at the county or community level. There is no doubt that pipelines are magnets for attention, stretching from the nefarious to the curious. Our interest lies in filling a crucial and much requested data gap.

Metadata

Pipelines in the map above range from the larger Keystone and Bluegrass across PA, OH, and KY to smaller ones like the Rex Energy Seneca Extension in Southeast Ohio or the Addison Natural Gas Project in Vermont. In total the pipeline proposals presented herein are equivalent to 46% of EIA’s 34,133 pipeline segment inventory (Table 1).

Table 1. Pipeline segments (#), min/max length, total length, and mean length (miles).

Section	#	Min	Max	Mean	Sum
Bakken	34	18	560	140	4,774
MW East-West	68	5	1,056	300	20,398
Midwest to OK/TX	13	13	1,346	307	3,997
Great Lakes	5	32	1,515	707	3,535
TransCanada	3	612	2,626	1,341	4,021
Liquids Ventures	2	433	590	512	1,023
Alliance et al	3	439	584	527	1,580
Rocky Express	2	247	2,124	1,186	2,371
Overland Pass	6	66	1,685	639	3,839
TX Eastern	15	53	1,755	397	5,958
Keystone Laterals	4	32	917	505	2,020
Gulf Stream	2	541	621	581	1,162
Arbuckle ECHO	25	27	668	217	5,427
Sterling	9	42	793	313	2,817
West TX Gateway	13	1	759	142	1,852
SXL in PA and NY	15	48	461	191	2,864
New England	70	2	855	65	4,581
Spectra BC	9	11	699	302	2,714
Alliance et al	4	69	4,358	2,186	4,358
MarkWest	63	2	113	19	1,196
Mackenzie	46	3	2,551	190	8,745
Total	411	128	1,268	512	89,232^†

^† This is equivalent to 46% of the current hydrocarbon pipeline inventory in the US across the EIA’s inventory of 34,133 pipeline segments with a total length of 195,990 miles

The map depicts all of the following (Note: Updated quarterly or when notified of proposals by concerned citizens):

All known North American pipeline proposals
Those pipelines that have yet to be documented by the EIA’s Natural Gas Pipeline Network mapping team
EIA documented pipelines more accurately mapped to the county level (i.e., select northeastern pipelines)
The current Keystone XL pipeline and the Keystone XL expansion proposal rectified to the county level in Nebraska, South Dakota, Oklahoma, and Texas

We generated this map by importing JPEGs into ArcMAP 10.2, we then “Fit To Display”. Once this was accomplished we anchored the image (i.e., georeferenced) in place using a minimum of 10 control points (Note: All Root Mean Square (RMS) error reports are available upon request) and as many as 30-40. When JPEGs were overly distorted we then converted or sought out Portable Network Graphic (PNG) imagery to facilitate more accurate anchoring of imagery.

We will be updating this map periodically, and it should be noted that all layers are a priori aggregations of regional pipelines across the 4 categories above.

Imagery sources:

Northeast – Long Island Sound, Montreal to Portland, Westchester, Spectra Energy Northeast, Maritime Northeast-Algonquin-Texas Eastern, Delaware River Watershed, Northeastern accuracy of existing EIA data, New England Kinder Morgan, Spectra Energy-Tennessee Gas Pipeline Company (TGP)-Portland Natural Gas Transmission System (PNGTS)
Duluth to The Dakotas, NYMarc Pipeline, Mariner East, Millenium Pipeline Company, WBI Energy’s Bakken,
British Columbia – Enbridge, Spectra/BG, Coastal, Tanker Route
Midwest – ATEX and Bluegrass, BlueGrass, BlueGrass Pipeline,
TransCanada/New England – Portland, Financial Post,
Alaska Pipelines Historically
Rail projects and primary transport
Keystone Tar Sands – Canada (website no longer active), United States, Texas-Oklahoma
Gulf Coast – Florida
MarkWest Houston, Liberty, Liberty, Houston and Majorsville,
Texas Oklahoma – Granite Wash Extension,
Ohio – Spectra Energy, Enterprise Products, Kinder Morgan, Buckeye-Kinder Morgan-El Paso, Chesapeake Energy and AEP
The Rockies Express Pipeline (REX)

Reference

1. Krauss, C, & Mouawad, J. (2014, January 25). Accidents Surge as Oil Industry Takes the Train, The New York Times.

PA Production and Waste Data Updated

March 13, 2014/by Matt Kelso, BA

Every six months, the Pennsylvania Department of Environmental Protection (PADEP) publishes production and waste data for all unconventional wells drilled in the Commonwealth. These data are self-reported by the industry to PADEP, and in the past, there have been numerous issues with the data not being reported in a timely fashion. Therefore, the early versions of these two datasets are often incomplete. For that reason, I now like to wait a few weeks before analyzing and mapping this data, so as to avoid false conclusions. That time has now come.

This map contains production and waste totals from unconventional wells in Pennsylvania from July to December, 2013. Based on data downloaded March 6, 2014. Also included are facilities that received the waste produced by these wells. To access the legend and other map controls, please click the expanding arrows icon at the top-right corner of the map.

Production

Top 20 unconventional gas producers in PA, from July to December 2013. The highest values in each column are highlighted in red.

Table 1: Top 20 unconventional gas producers in PA, from July to December 2013. Highest values in each column are highlighted in red.

Production values can be summarized in many ways. In this post, we will summarize the data, first by operator, then by county. For operators, we will take a look at all operators on the production report, and see which operator has the highest total production, as well as production per well (Table 1).

It is important to note that not all of the wells on the report are actually in production, and not all of the ones that are produce for the entire cycle. However, there is some dramatic variance in the production that one might expect from an unconventional well in Pennsylvania that correlates strongly with which operator drilled the well in question. For example, the average Cabot well produces ten times the gas that the average Atlas well does. Even among the top two producers, the average Chesapeake well produces 2.75 times as much as the average Range Resources well.

The location of the well is the primary factor in regards to production values. 74 percent of Atlas’ wells are in Greene and Fayette counties, in southwestern Pennsylvania, while 99 percent of Cabot’s wells are in Susquehanna County. Similarly, 79 percent of Range Resources’ wells are in the its southwestern PA stronghold of Washington County, while 62 percent of Chesapeake’s wells are in Bradford county, in the northeast.

Pennsylvania unconventional gas production by county, from July to December 2013.

Table 2: PA unconventional gas production by county, from July to December 2013

Altogether, there are unconventional wells drilled in 38 Pennsylvania counties, 33 of which have wells that are producing (see Table 2). And yet, fully 1 trillion cubic feet (Tcf) of t he 1.7 Tcf produced by unconventional wells during the six month period in Pennsylvania came from the three northeastern counties of Susquehanna, Bradford, and Lycoming.

While production in Greene County does not compare to production in Susquehanna, this disparity still does not account for the really poor production of Atlas wells, as that operator averages less than one fourth of the typical well in the county. Nor can we blame the problem on inactive wells, as 84 of their 85 wells in Greene County are listed as being in production. There is an explanation, however. All of these Atlas wells were drilled from 2006 through early 2010, so none of them are in the peak of their production life cycles.

There is a different story in Allegheny County, which has a surprising high per well yield for a county in the southwestern part of the state. Here, all of the wells on the report were drilled between 2008 and 2013, and are therefore in the most productive part of the well’s life cycle. Only the most recent of these wells is listed as not being in production.

Per well production during the last half of 2013 for unconventional wells in Pennsylvania by year drilled.

Table 3: Per well production during last half of 2013 for PA unconventional wells by spud year

Generally speaking, the further back a well was originally drilled, the less gas it will produce (see Table 3). At first glance, it might be surprising to note that the wells drilled in 2012 produced more gas than those drilled in 2013, however, as the data period is for the last half of 2013, there were a number of wells drilled that year that were not in production for the entire data cycle.

In addition to gas, there were 1,649,699 barrels of condensate and 182,636 barrels of oil produced by unconventional wells in Pennsylvania during the six month period. The vast majority of both of these resources were extracted from Washington County, in the southwestern part of the state. 540 wells reported condensate production, while 12 wells reported oil.

Waste

There are eight types of waste detailed in the Pennsylvania data, including:

Basic Sediment (Barrels) – Impurities that accompany the desired product
Drill Cuttings (Tons) – Broken bits of rock produced during the drilling process
Flowback Fracturing Sand (Tons) – Sand used as proppants during hydraulic fracturing that return to the surface
Fracing Fluid Waste (Barrels) – Fluid pumped into the well for hydraulic fracturing that returns to the surface. This includes chemicals that were added to the well.
Produced Fluid (Barrels) – Naturally occurring brines encountered during drilling that contain various contaminants, which are often toxic or radioactive
Servicing Fluid (Barrels) – Various other fluids used in the drilling process
Spent Lubricant (Barrels) – Oils used in engines as lubricants

Method of disposing of waste generated from unconventional wells in Pennsylvania from July to December 2013.

Table 4: Method of disposing of waste generated from unconventional wells in PA from July to December 2013

Solid and liquid waste disposal for the top 20 producers of unconventional liquid waste in Pennsylvania during the last half of 2013.

Table 5: Solid & liquid waste disposal for top 20 producers of PA unconventional liquid waste during last half of 2013

This table shows solid and liquid waste totals for the ten counties that produced the most liquid waste over the six month period.

Table 6: Solid & liquid waste totals for the 10 counties that produced the most liquid waste over the 6 month period

There are numerous methods for disposing of drilling waste in Pennsylvania (see Table 4). Some of the categories include recycling for future use, others are merely designated as stored temporarily, and others are disposed or treated at a designated facility. One of the bright points of the state’s waste data is that it includes the destination of that waste on a per well basis, which has allowed us to add receiving facilities to the map at the top of the page.

As eight data columns per table is a bit unwieldy, we have aggregated the types by whether they are solid (reported in tons) or liquid (reported in 42 gallon barrels). Because solid waste is produced as a result of the drilling and fracturing phases, it isn’t surprising that the old Atlas wells produced no new solid waste (see Table 5). Chevron Appalachia is more surprising, however, as the company spudded 46 wells in 2013, 12 of which were started during the last half of the year. However, Chevron’s liquid waste totals were significant, so it is possible that some of their solid waste was reported, but miscategorized.

As with production, location matters when it comes to the generation of waste from these wells. But while the largest gas producing counties were led by three counties in the northeast, liquid waste production is most prolific in the southwest (see Table 6).

Table 7: PA unconventional operators with the most wells that produced gas, oil, and/or condensate, but no amount of waste.

Finally, we will take a look at the 359 wells that are indicated as in production, yet were not represented on the waste report as of March 6th. These remarkable wells are run by 38 different operators, but some companies are luckier with the waste-free wells than their rivals. As there was a six-way tie for 10th place among these operators, as sorted by the number or wells that produce gas, condensate, or oil but not waste, we can take a look at the top 15 operators in this category (see Table 7). Of note, gas quantity only includes production from these wells. Column on the right shows total number of wells that are indicated as producing, for that same operator, regardless of waste production.

114 of Southwestern Energy’s 172 producing wells were not represented on the waste report as of March 6th, representing just under two thirds of the total. In terms of the number of waste-free wells, Atlas was second, with 55. As for the highest percentage, Dominon, Hunt, and Texas Keystone all managed to avoid producing any waste at all for each of their seven respective producing wells, according to this self-reported data.

What Does Los Angeles Mean for Local Bans and Moratoria in California?

March 4, 2014/by Kyle Ferrar, MPH

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

California Regulations.

As confusing as you may think the regulatory structure is in your state (if you are not fortunate enough to be a Californian), just know that California’s regulatory structure is more complicated. Nothing in California’s recent history has clarified this point like the current debate over “fracking” regulations (hydraulic fracturing, as well as acidizing and other stimulation techniques). Since the passage of California State Bill 4 (SB-4), there have been significant concerns for self-rule and self-determination for individual communities. Further complicating the issue are the fracking activities being conducted from the offshore oil rig platforms located in federal waters. In addition to federal regulation, the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources is the premier regulatory authority for oil and gas drilling and production in the state. The State Water Resources Control Board and the Regional Water Quality Control Board hold jurisdiction over the states surface and groundwater resources, while the California Air Districts regulate air quality along with the California Air Resources Board. It is no surprise that a report published by the Wheeler Institute from the University of California, Berkeley found that this regulatory structure where several state and federal agencies share responsibility is not conducive to ensuring hydraulic fracturing is conducted safely.[1]

A Ban in Los Angeles, CA

The most recent local regulatory activity comes from the Los Angeles City Council. On Friday February 28, 2014, the City Council voted on and passed a resolution to draft language for a citywide ban of all stimulation techniques. The resolution calls for city zoning code to be amended in order to prohibit hydraulic fracturing activities in L.A. until the practices are proven to be safe. A final vote will then be cast to approve the final language. If it passes, Los Angeles will be the largest city in the United States to ban hydraulic fracturing. The FracTracker “Local Actions and Regulations Map” has been updated to include the Los Angeles resolution/ordinance, as well as the resolution supporting a statewide ban by the San Francisco Board of Supervisors, the moratorium in Santa Cruz County, and a resolution by the University of California, Berkeley Student Government. See all California’s local actions and regulations in the figure below. Click on the green checked boxes for a description of each action.

Click on the arrows in the upper right hand corner of the map for the legend and to view the map fullscreen.

State Bill 4 Preemption

Since the passage of California’s new regulatory bill SB-4, there has been a lot of confusion and debate whether the new state regulations preempt local jurisdictions from passing their own laws and regulations, and specifically moratoriums and bans. The county of Santa Cruz has a moratorium on fracking, but it was passed prior to the enactment of SB-4. Additionally Santa Cruz County is not a hotbed of drilling activity like Los Angeles or Kern. The team of lawyers representing the county of Ventura, where wells are actively being stimulated, came to a very different conclusion than the Los Angeles City Council. After reviewing SB-4, Ventura County came to the conclusion that lower jurisdictions were blocked from enacting local moratoriums. Draft minutes from the December 17, 2013 meeting quote, “The legal analysis provided by County Counsel indicates that the County is largely preempted from actively regulating well stimulation treatment activities at both new and existing wells. However, the County is required under CEQA to assess and address the potential environmental impacts from such activities requiring a discretionary County approval of new well sites.”[2]

On the other hand, independent analyses of the language in California SB-4 show that the legal-ese does not contain any provision that supersedes related local regulations. Rather, the bill preserves the right of local governments to impose additional environmental regulations.[3] The regulations do not expressively comment on the ability of local regulations to pass a moratorium or permanent ban. Additionally, DOGGR has supported a court decision that the SB-4 language expressly prohibits the state regulatory agency from enforcing the California Environmental Quality Act (according to the Division of Oil, Gas and Geothermal Resources).[4] As for local measures, a recent article by Edgcomb and Wilke (2013) provides multiple examples of precedence in California and other states for local environmental bans and regulations in conjunction with less restrictive state law.[3] Of course, any attempt to pass a ban on fossil fuel extraction or development activities where resource development is actively occurring will most likely be met with litigation and a lawsuit from industry groups such as the Western States Petroleum Association. Industry representatives charge that the ordinance is an unconstitutional “taking” of previously leased mineral rights by private property owners.[5,6] Pay close attention to this fight in Los Angeles, as there will be repercussions relevant to all local governments in the state of California, particularly those considering bans or moratoriums.

[1] Kiparsky, Michael and Hein, Jayni Foley. 2013. Regulation of Hydraulic Fracturing in California, a Wastewater and Water Quality Perspective. Wheeler Institute for Water Law and Policy. Center for Law Energy and the Environment, University of California Berkeley School of Law.

[2] Ventura County Board of Supervisors. December 17, 2013. Meeting Minutes and Video. Accessed March 2, 2014. [http://www.ventura.org/bos-archives/agendas-documents-and-broadcasts]

[2] Edgcomb, John D Esq. and Wilke, Mary E Esq. January 10, 2014. Can Local Governments Ban Fracking After New California Fracking Legislation? Accessed March 3, 2014. [http://californiafrackinglaw.com/can-local-governments-ban-fracking-after-new-california-fracking-legislation/]

[3] Hein, Jayni Foley. November 18, 2013. State Releases New Fracking Regulations amid SB 4 Criticism, Controversy. Accessed February 27, 2014. [http://blogs.berkeley.edu/2013/11/18/state-releases-new-fracking-regulations-amid-sb-4-criticism-controversy/]

[4] Fine, Howard. February 28, 2014. L.A. Council Orders Fracking Moratorium Ordinance. Los Angeles Business Journal. [http://labusinessjournal.com/news/2014/feb/28/l-council-orders-fracking-moratorium-ordinance/]

[5] Collier, Robert. March 3, 2014. L.A. fracking moratorium – the difficult road ahead. Climate Speak. Accessed March 4, 2014. [http://www.climatespeak.com/2014/03/la-fracking-moratorium.html]

[6] Higgins, Bill. Schwartz, Andrew. Kautz, Barbara. 2006. Regulatory Takings and Land Use Regulation: A Primer for Public Agency Staff. Institute for Local Government. Available at [http://www.ca-ilg.org/sites/main/files/file-attachments/resources__Takings_1.pdf]

Over 1.1 Million Active Oil and Gas Wells in the US

March 4, 2014/by Matt Kelso, BA

Please Note

Click here to view an update on this topic

Many people ask us how many wells have been hydraulically fractured in the United States. It is an excellent question, but not one that is easily answered; most states don’t release data on well stimulation activities. Also, since the data are released by state regulatory agencies, it is necessary to obtain data from each state that has oil and gas data to even begin the conversation. We’ve finally had a chance to complete that task, and have been able to aggregate the following totals:

Oil and gas summary data of drilled wells in the United States.

While data on hydraulically fractured wells is rarely made available, the slant of the wells are often made accessible. The well types are as follows:

Directional: Directional wells are those where the top and the bottom of the holes do not line up vertically. In some cases, the deviation is fairly slight. These are also known as deviated or slant wells.
Horizontal: Horizontal wells are directional wells, where the well bore makes something of an “L” shape. States may have their own definition for horizontal wells. In Alaska, these wells are defined as those deviating at least 80° from vertical. Currently, operators are able to drill horizontally for several miles.
Directional or Horizontal: These wells are known to be directional, but whether they are classified as horizontal or not could not be determined from the available data. In many cases, the directionality was determined by the presence of directional sidetrack codes in the well’s API number.
Vertical: Wells in which the top hole and bottom hole locations are in alignment. States may have differing tolerances for what constitutes a vertical well, as opposed to directional.
Hydraulically Fractured: As each state releases data differently, it wasn’t always possible to get consistent data. These wells are known to be hydraulically fractured, but the slant of the well is unknown.
Not Fractured: These wells have not been hydraulically fractured, and the slant of the well is unknown.
Unknown: Nothing is known about the slant, stimulation, or target formation of the well in question.
Unknown (Shale Formation): Nothing is known about the slant or stimulation of the wells in question; however, it is known that the target formation is a major shale play. Therefore, it is probable that the well has been hydraulically fractured, with a strong possibility of being drilled horizontally.

Wells that have been hydraulically fractured might appear in any of the eight categories, with the obvious exception of “Not Fractured.” Categories that are very likely to be fractured include, “Horizontal”, “Hydraulically Fractured”, and “Unknown (Shale Formation),” the total of which is about 32,000 wells. However, that number doesn’t include any wells from Texas or Colorado, where we know thousands wells have been drilled into major shale formations, but the data had to be placed into categories that were more vague.

Oil and gas wells in the United States, as of February 2014. Location data were not available for Maryland (n=104), North Carolina (n=2), and Texas (n=303,909). To access the legend and other map tools, click the expanding arrows icon in the top-right corner.

The standard that we attempted to reach for all of the well totals was for wells that have been drilled but have not yet been plugged, which is a broad spectrum of the well’s life-cycle. In some cases, decisions had to be made in terms of which wells to include, due to imperfect metadata.

No location data were available for Maryland, North Carolina, or Texas. The first two have very few wells, and officials in Maryland said that they expect to have the data available within about a month. Texas location data is available for purchase, however such data cannot be redistributed, so it was not included on the map.

It should not be assumed that all of the wells that are shown in the map above the shale plays and shale basin layers are actually drilled into shale. In many cases, however, shale is considered a source rock, where hydrocarbons are developed, before the oil and gas products migrate upward into shallower, more conventional formations.

The raw data oil and gas data is available for download on our site in shapefile format.

Western States: Please Abandon the PLSS!

February 24, 2014/by Matt Kelso, BA

By Matt Kelso, Manager of Data and Technology

Increasingly, the FracTracker Alliance is asked about oil and gas extraction on a national scale. To that end, we are in the process of developing a national dataset of oil and gas wells. Since the data is curated at the state level, it is a challenge to get consistent data formatting from state to state. However, most states at least have the decency to release their location data in decimal degree (DD), that familiar format of latitude and longitude values where users of the data don’t need to calculate the location using three different columns of degrees, minutes, and seconds (DMS).

For example, a DMS point of 45°12’16.4″N, 95°55’12.5″W could be written more tidily in DD as 45.204556, -96.920139. Two numbers, one discrete place on the globe (a random point in rural South Dakota, as it turns out).

Here is how that same location is properly designated using the Public Land Survey System: “NW 14 T120N R51W Fifth Principal”

Fig. 1 Public Land Survey System. Source: National Atlas

In English, that is the northwest quarter of Section 14, Township 120 North, Range 51 West Fifth Principal. If we wanted to, the quarter section could itself be split into four quarters, and each of those units could be split again, resulting in, for example the SE quarter of the NE quarter of the NW quarter of section 14, Township 120 North, Range 51 West Fifth Principal (See Fig. 1).

To the uninitiated, the PLSS is a needlessly complex system of describing locations in the American West that was devised by Thomas Jefferson to grid out the wild American frontier. As such, it is not altogether surprising that it became the legal definition of place in many western states.

What is surprising is that the system is still in use, at least to the exclusion of other systems. Many states release oil and gas data with multiple geographic systems, including the PLSS, State Plane, UTM, and decimal degrees. This is an acceptable approach, as it caters to cartographers using technology ranging from the eighteenth through twenty-first centuries.

Accuracy Issues

My issue with the PLSS isn’t just that it is annoying. PLSS data are readily available, after all. Differing formats of the various data attributes can be worked out. However, there is inherently an accuracy issue with a system that uses a predefined area to define a point location. If you wanted to use it to describe an area such as a well pad, it is entirely possible that a typical drilling site might straddle four different sections, let alone quarter-quarter-quarter (QQQ) sections. For that matter, well pads could easily span multiple township and range designations, as well.

Fig. 2 PLSS sections in New Mexico

Statewide shapefiles that are as detailed as sections are quite large, and are the most detailed data that most data sources offer. This means that the best we can usually do with well data published in PLSS is draw the well at the centroid, or geographical center-point of the section, which in theory is one square mile. Given that the hypotenuse of a square mile block is 1.44 miles, the distance from the centroid to any of the corners is 0.72 miles, or about 3,800 feet, which is the potential error for mapping using PLSS section centroids. While that lack of accuracy is unsatisfying for the FracTracker Alliance, the whole system is a potential nightmare for first responders, in an industry where serious things can go wrong.

In some states, the entire land areas were never even gridded out. New Mexico, for example, has Native American reservations and extensive lands grants that were issued when the region was under Spanish and Mexican control (Fig. 2).

On top of all of that, those square mile sections are not always square. These sections are based on field surveys that were mostly conducted in the 19th century. Walking straight lines in rough terrain isn’t actually all that easy, and in many cases, areas with ferrous deposits in the soil can interfere with the functionality of a magnetic compass. If we take a closer look at the New Mexico sections map (Fig. 3 below), we can see that error is significant.

Moving Forward

Fig. 3 Areas in green show PLSS Sections in North-Central New Mexico. Areas in white were not gridded out as a part of the survey.

Luckily, we live in an age where technology makes Thomas Jefferson’s valiant attempt at a coordinate system obsolete. Decimal degree is a format that is well understood by GPS devices, Google Maps, sophisticated GIS software, and for the most part, the general public. For mapping purposes, decimal degree is so easy to use and so widely established that other systems, especially the PLSS, come across as needlessly opaque.

This situation is not even analogous with the United States’ famous reluctance to embrace the metric system. It takes some adjustment for people to start thinking in terms of kilograms and meters instead of pounds and feet. PLSS isn’t remotely intuitive as a coordinate system, even among those who use it all the time. It’s time to abandon this as a way of conveying location. I’d like to think that Thomas Jefferson, as a forward-thinking individual, would agree.