Posts

Water Use in WV and PA

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

GasWellWaterWithdrawals 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 Because most water used in Marcellus operations is withdrawn from surface waters, withdrawals can result in dewatering and severe impacts on small streams and aquatic life.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)

WV Water Withdrawals

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

North American Pipeline Proposal Map

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):

  1. All known North American pipeline proposals
  2. Those pipelines that have yet to be documented by the EIA’s Natural Gas Pipeline Network mapping team
  3. EIA documented pipelines more accurately mapped to the county level (i.e., select northeastern pipelines)
  4. 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:

  1. 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)
  2. Duluth to The Dakotas, NYMarc Pipeline, Mariner East, Millenium Pipeline Company, WBI Energy’s Bakken,
  3. British Columbia – Enbridge, Spectra/BG, Coastal, Tanker Route
  4. Midwest – ATEX and Bluegrass, BlueGrass, BlueGrass Pipeline,
  5. TransCanada/New England – Portland, Financial Post,
  6. Alaska Pipelines Historically
  7. Rail projects and primary transport
  8. Keystone Tar Sands – Canada (website no longer active), United States, Texas-Oklahoma
  9. Gulf Coast – Florida
  10. MarkWest Houston, Liberty, Liberty, Houston and Majorsville,
  11. Texas Oklahoma – Granite Wash Extension,
  12. Ohio – Spectra Energy, Enterprise Products, Kinder Morgan, Buckeye-Kinder Morgan-El Paso, Chesapeake Energy and AEP
  13. 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.

 

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

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

California Regulations. The Venoco oil well in downtown Los Angeles.

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]

Ancient Seas, Modern Ownership Concerns

By Karen Edelstein, NY Program Coordinator, FracTracker Alliance

In the Finger Lakes Region of New York State, while the debate rages about underground storage of gas in abandoned salt solution mines near Seneca Lake, the story is quite different to the east at Cayuga Lake. Cayuga has a history of not just solution brine mining, but also extensive mining of solid rock salt. The map below shows the footprint of underground salt mining – room-and-pillar style 2300 feet below Cayuga Lake – by the multinational corporation, Cargill. Mineral rights beneath the lake are owned by New York State, but note that some of the mine also extends underneath privately owned land in the Town of Lansing.


Map of Lansing, NY Cargill Salt Mine. For a full-screen version of this map (including map legend), click here.

About this Map

The interactive map (above) shows the location and extent of the Cargill Salt mine in Lansing, NY. The boundaries of the mine were digitized from a map, Figure 2.3-2, entitled “Plan View of the Cayuga Mine Showing East and West Shoreline Benchmark Locations” from the Spectra Environmental Group, Latham, NY, circa 2004, and another planning document acquired. Here is one of the original maps, and a planning map showing expansion through 2003. An additional map from a Cargill mine expansion permit request, viewed at the DEC headquarters in Cortland, NY, shows additional requested development under residential areas in Lansing. This layer is shaded green.

Questions Abound

The dynamics around salt extraction, and other uses such as gas extraction, raise several questions.

Consider the stratigraphic column of rocks in New York State. The salt layer that is being mined by Cargill is the Salina Group, approximately 2300 feet below the surface. Salt is dug out mechanically, broken up by machinery and explosives to break up the solid layer. The Marcellus Shale (in Lansing) is above that salt layer–in the expanse of Middle Devonian Rocks, while the Utica Shale is below it–part of the Ordovician rock strata. In order to drill into the Marcellus Shale, one would not need to enter the salt layer, although the boundary of rock between the two strata might only be a few hundred feet thick. Reaching the Utica Shale would require piercing the salt layer. The Central New York region is crisscrossed by an abundance of vertical cracks and joints in the bedrock, some of which are thought to be hundreds to thousands of feet long, and may extend to “basement rock”, the ancient rock below the hundreds-of-millions year-old sedimentary layers such as the shale, sandstone, and salt.

Numerous plugged and abandoned salt wells from the days of solution mining–mid 1800s to mid 1900s– are located on and near Salt Point, the delta where Salmon Creek meets Cayuga Lake. As the map shows, the rock salt mining extent is near to, but not in contact with, these old brine wells. The underground shape of the solution wells is not entirely understood, and may be variable due to different rates of dissolution of halite during the extraction process. The rock salt is mined out as a solid, not a a saturated salt liquid that would have then gone through an evaporation process in a giant kiln. Were rock salt extraction to occur too close to the old solution wells and a wall breached, flooding in the current Cargill mine could result.

This would obviously not be good.

(Nor, for that matter, would have been the prospect of storing spent nuclear fuel in the abandoned brine wells, something that was being considered in the mid-1970s. In a 3-volume study of the geology of the Salina Basin (spanning a d-state area), the conclusion made by the Stone and Webster Engineering Corporation1,  consultant to the US Department of Energy, was that no salt mining sites in the Finger Lakes region were appropriate  for nuclear fuel storage without further study of the area’s extensive, but under-studied, faulting patterns.)

What are the implications of other sorts of mineral extraction, in this part of the Finger Lakes Region?

Yours or Mine?

The extent of Cargill’s mining under residential portions of the Town of Lansing provokes several questions. For example, if Cargill has long-term access to these subsurface mineral rights, property owners do not control the land beneath their homes. This is not altogether uncommon in areas of mineral – or oil and gas – extraction. Can that land be leased for gas drilling?

It was revealing to look more closely at records of expired oil and gas leases in the area. During this process, we discovered that within the area that is “claimed” by Cargill for subsurface mineral extraction, numerous surface owners had also leased the gas rights beneath their property (see blue starburst markers on the map)2, even if the property deeds explicitly, for example,  indicated that the property owner “will not cause any damage to the said salt or mining operations [of the party of the second part] by permitting or consenting to any other drilling 1000 feet below the the surface of said premises, for oil, gas, water or any other substance or mineral..” (Tompkins County Clerk, Liber 463, p.284-5).  Here are links to page 2 and 3 of the deed, and the very comprehensive leasing clause of one of these oil and gas leases that permits a wide variety of gas-extraction related activity–both on the surface, and below ground.

Four of the ten leases were on property held by the Town of Lansing itself, and one other was on property owned by a local elected official. While all of these leases expired in 2012, and were never, in fact, drilled (due to the de facto moratorium on HVHF gas extraction in New York), the mash-up of these datasets raises important questions about our permitting structure. The implications of two separate entities claiming overlapping subsurface rights spotlights many questions regarding the oversight and regulation of potentially conflicting uses. Of particular concern are the risks posed by migration of gas through joints and fissures in the bedrock that are further weakened by hydraulic fracturing – and the potential for methane explosions3 in salt mines, whether or not a well shaft penetrates the salt gallery.

For more details on operations at Cargill’s Lansing mine, see this article from The Lansing Star, September 2012: Lansing Down Under: A Look at the Cargill Salt Mine.

References

  1. Regional Geology of the Salina Basin, Report of the Geologic Project Manager
    Volumes 1 and 2, Phase I, August 1977-January 1978, and Volume 3 Update, October 1979. Prepared by Stone and Webster Engineering Corporation for the Office of Nuclear Waste Isolation, Battelle Memorial Institute, Project Management Division, US Department of Energy.
  2. Map of Gas Leases in Tompkins County
  3. Cargill Incorporated Belle Isle Salt Mine Explosion (1979)

Letter of Inquiry from a Public Health Professional

By Mary Ellen Cassidy, Community Outreach Coordinator

I recently came across a letter by Dr. Alan Ducatman, MS, MD, Professor of Public Health and Medicine at WVU in Donald Strimbeck’s updates.  It stuck me by its sincerity, logical tone, and reasonableness.

Drilling Spill SampleDr. Ducatman’s letter begins by commenting on the gas industry’s response to a surface spill in Garfield County.  The industry’s response to this spill, an Energy In Depth Blog (12/20/13), includes the following statement, “We all know spills are bad and can cause problems, so what exactly did they expect to find?”

Dr. Ducatman’s letter looks past the rather snide tone of the response to commend the industry for its honest acknowledgement that spills do occur and bad things can and do happen.  Dr. Ducatman notes that, although the response “lacks consistency with past and present behavior in public forums,” he hopes to see it become a “consistent and reasonable position” in the future.

The letter then calls on industry to be more scientific and open in their communications regarding other issues such as quality assurance, worker safety, well casing failures, leaks, water testing impediments, public protection practices, and reporting, while reminding the industry of the human and economic costs of externalities and the “terrible weight” of these collateral impacts on communities.

It occurred to me, upon reading this letter that more of us need to ask questions of the industry and take action to protect and support our impacted communities. Not only do we need more professional researchers like Dr. Ducatman asking questions, we also need many more people on the ground _DSC4465documenting what is happening around them to hold the industry accountable.

FracTracker Alliance aims to empower and equip volunteers to track and document unconventional gas and oil activities. Options for engagement include:

  • Trail Logbook – addressing trail-based observations about physical and experiential conflicts related to oil and gas development
  • The US Map of Suspected Well Water Impacts – aggregating cases of home drinking water problems that may be associated with oil and gas exploration
  • The new FracTracker mobile app (for iPhones) – making it easy  to take photos and record information on various oil and gas impacts in your neighborhood or afar. We are currently in the pilot testing phase of this app, which can also be used to contribute data to the other two programs described above.

These programs depend on crowdsourced information from you and others to grow a national database on the extensive footprint of the industry.  Check out our website and projects to see where you fit.

In addition, we always welcome your ideas on how our mapping and other services can help your community’s efforts to protect its health and natural resources.

Contact me to learn more about how you can become a part of the FracTracker team, and a special thank you to Dr. Alan Ducatman for his letter reenergizing this important conversation.

If you are one of those people ready to work together in a concerted effort towards a more positive energy future, FracTracker needs you.


Mary Ellen Cassidy, Community Outreach Coordinator
Cassidy@FracTracker.org
304-312-2063

Hydrocarbon Industrial Complex Map In Detail

Below is a brand new map from our team that contains multiple data layers that speak to the myriad players and facilities involved in the North American hydrocarbon network – from upstream processing facilities to transporters and export terminals. This map helps us to demonstrate the complexity of the hydrocarbon industry, because we often assume that hydraulic fracturing or related extractive techniques are local issues. However, there is actually a tremendous – and growing – interconnectivity between production, transport, processing, usage, storage, and export.


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

Data Descriptions

EIA Sources: Peak Shavers, Underground Natural Gas Storage, Compressor Station, Natural Gas HUBs, and Pipeline Data

Peak Shavers are:

…used for storing surplus natural gas that is to be used to meet the requirements of peak consumption later during winter or summer. Each peak-shaving facility has a regasification unit attached but may or may not have a liquefaction unit…[they] depend upon tank trucks to bring LNG from other nearby sources to them. Of the approximate 113 active LNG facilities in the United States, 57 are peak-shaving facilities. The other LNG facilities include marine terminals, storage facilities, and operations involved in niche markets such as LNG vehicular fuel. Learn more

The data included in this map include 109 Peak Shavers vs. the aforementioned 57.

  • Regional distribution: 7 Central US, 12 Midwest, 53 Northwest, 24 Southeast, 5 Southwest, 8 Western
  • 106 of which are active and 3 under construction

The Underground Natural Gas Storage Facilities (UNGSF) layer is an EIA-defined collection of 413 facilities1, a definition that includes “pipelines, local distribution companies, producers, and pipeline shippers with an inventory management tool, seasonal supply backup, and access to natural gas needed to avoid imbalances between receipts and deliveries on a pipeline network.” (For a more detailed description of UNGSF, see the EIA’s description)

Compressor Stations are designed to ensure:

…that the natural gas flowing through any one pipeline remains pressurized, compression of this natural gas is required periodically along the pipe…usually placed at 40 to 100 mile intervals along the pipeline. The natural gas enters the compressor station, where it is compressed by either a turbine, motor, or engine…[they] gain their energy by using up a small proportion of the natural gas that they compress.

For a more detailed discussion of the importance and design of compressor stations, refer to NaturalGas.org’s The Transportation of Natural Gas.

  • This layer includes: 1,756 compressor stations with the following regional distribution: 207 Canadian, 344 Central US, 14 Gulf Coast, 169 Midwest, 249 Northeast, 191 Southeast, 450 Southwest, and 132 Western stations
  • The mean and total horsepower across 1,417 of these facilities is 10,411 and 18,282,484, respectively, with average and total throughput of 660 and 1,159 Billion Cubic Feet (BCF)2.

Natural Gas HUBs are broken down by operator type with 26 “Market Center”, 31 “Market Hub”, 3 “Production Hub”, and 3 “Storage Hub” facilities included.

  • Regional distribution: 9 in Canada, 7 across the Central US, 4 in the Midwest, 8 in the Northeast, 4 in the Southeast, 24 in the Southwest, and 7 in the Western US.
  • All facilities were activated between 1994 and 1998
  • Status: 5 Canceled, 13 Inactive, 36 Operational, and 9 Proposed HUBs

Pipeline segments are parsed by type: a) 69 sections totaling 1,627 miles described as “Gathering” at an average diameter of 17 inches, b) 18,905 segments totaling 127,049 miles as “Interstate” with an average diameter of 15 inches, and  c) 15,152 “Intrastate” segments totaling 66,939 miles and an average diameter of 2.8 inches.

Select states statistics:

  1. 7,450 segments were located in Texas with a total length of 44,600 miles,
  2. 1,313 segments were located in California with a total length of 6,370 miles,
  3. 2,738 segments in Louisiana with a  total length of 15,330,
  4. New York and New Jersey are home to a combined 2,315 pipeline segments with a total length of 4,015 miles,
  5. 859 segments and 5,935 miles in Ohio,
  6. Great Lakes bordering states contain 6,841 pipeline segments totaling 33,457 miles,
  7. Pacific Northwest states including Washington, Oregon, Idaho, and Montana contain 1,765 segments totaling 6,121 miles,
  8. Gulf Coast states sans Texas contain 3,886 pipeline segments totaling 25,775 miles.

The above datasets were compiled by Ted Auch and Daniel Berghoff of the FracTracker Alliance or sourced from the US Energy Information Administration via their Natural Gas data portal and their analysts Tu Tran and Robert King.

US River and Coastal Export/Import Ports

US inland (i.e., Mississippi River) and coastal ports are the singular ways in which all manner of hydrocarbons are transported to downstream processing facilities and subsequently used domestically or exported. The data contained herein include 12 Mississippi, 7 Ohio and Tennessee River, and 11 Columbia river ports along with 16 Great Lakes/St. Lawrence river ports (Table 1).

Table 1. Number of inland and coastal US and territories ports as of December 2013.

State

Number of Ports

State

Number of Ports

AK

40

MO

2

AL

7

MS

3

AR

2

NC

2

CA

9

NJ

2

CT

3

NY

6

DE, VA, MD, & DC

6

OH

2

FL

17

OK

2

GA

2

OR

13

HI

7

PA

2

IA

1

PR

1

ID

1

RI

1

IL

4

SC

1

KY

2

TN

4

LA

13

TX

11

MA

3

VI

1

ME

2

WA

6

MI

6

WI

4

MN

4

WV

2

US Coal Plants & Emissions

We were pointed to this data by Source Watch’s “Coal Swarm” project’s Director Ted Nace and researcher Joshua Frank. Learn more. The layer includes coal used, emissions of carbon dioxide (CO2), sulfur dioxide (SO2), methane (CH4), oxides of nitrogen (NOX), and mercury (Hg). Also included are the number of deaths across a variety of categories and emergency room visits attributed to each coal plant, along with estimates of the valuation of each of these. The raw data are available from the the US EPA’s Emissions & Generation Resource Integrated Database (eGRID) comprehensive data portal with the “Version 1.0” ZIP file containing: “spreadsheet files, state import-export files, Technical Support Document, file structure document, Summary Tables, GHG output emission rates, the EUEC2010 paper, and graphical representations of eGRID subregion and NERC region maps. Data in this file encompasses years 2009, 2007, 2005 and 2004.” The data were most recently updated on May 10, 2012 in order to include 2009 data.

Transload Facilities Directory

Directory Description:

Rail-to-truck transload facilities where cargo is transferred between tank trucks and water or rail transportation…These bulk material handling companies also provide information such as products handled, services and equipment available, and methods for dry bulk product transfer…These intermodal locations are owned or operated by trucking companies, railroads, or independent bulk terminal operators. Unless the prohibition is stated, these businesses have indicated they allow outside carriers to load products at their facilities. Learn more

Services Key:

  • Products handled: a. Acids, b. Chemicals (liquid), c. Chemicals (dry), d. Asphalt, e. Foods (liquid), f. Foods (dry), g. Plastics (dry), h. Petroleum products
  • Services/equipment available: a. Air compressor, b. Scale, c. Blending meters, d. Sampling service, e. Hot water heating, f. Steam heating, g. Tank trailer cleaning, h. Liquid storage tanks, i. Liquid pumps
  • Dry bulk product transfer by: a. Vacuum trailer, b. Auger, c. Blower, d. Gravity (trestle), e. Portable vacuum/air conveyor, f. Bulk conveyor

Intermodal Tank Containers

Those facilities “that have actual storage depot operations. The operators specialize in both the handling and storage of ISO containers.” Learn more

Intermodal tanks are:

… intermodal container[s] for the transport of liquids, gases and powders as bulk cargo…built to the [International Organization for Standardization] Standard, making it suitable for different modes of transportation. Both hazardous and non-hazardous products can be transported in tank containers. A tank container is a vessel of stainless steel surrounded by an insulation and protective layer of usually Polyurethane and aluminum. The vessel is in the middle of a steel frame. The frame is made according to ISO standards and is 19.8556 feet (6.05 meters) long, 7.874 feet (2.40 meters) wide and 7.874 feet (2.40 meters) or 8.374 feet (2.55 meters) high. The contents of the tank ranges from 27,000 to 40,000 liters (5,900 to 8,800 imp gal; 7,100 to 11,000 U.S. gal). There are both smaller and larger tank containers, which usually have a size different from the ISO standard sizes. The trade organization @TCO estimates that at the end of 2012 the global fleet of tank containers is between 340,000 and 380,000. (Wikipedia definition)

Services Key: a. Storage, b. Cleaning, c. Container shuttle service, d. Container drayage, e. Steam/electric heat, f. Rail siding, g. Repair/refurbishing, h. American Bureau of Shipping (ABS) certification, i. American Society of Mechanical Engineers (ASME) certification, j. ISO 9000 certification, k. 2.5- and 5-year ABS testing, l. Reefer tank repairs, m. Parts supply

Abbreviations: SC=straddle carrier, TLSL=top-lifting side-loader, D/D=drop-deck

MarkWest Facilities

Facility locational data gathered from the company’s operations website.

Cargo Tank Repair Directory

“Bulk Transporter’s Cargo Tank Trailer Repair Directory…the most comprehensive listing of repair facilities that service tank trucks and tank trailers. Additionally, many of these facilities offer custom fabrication. Most listings include services offered, but tank truck operators are encouraged to contact the facilities directly for more information…The first six items listed on the “Services Key” are the DOT tests and inspections required by federal law. Companies listing “R” or “U” stamps were asked to provide Bulk Transporter with a record of their accreditation. The federal CT registration number also was requested for the tank repair shops in the directory.” Learn more

Repair Services Key:

1. External visual inspection, 2. Internal visual inspection, 3. Lining inspection, 4. Leakage test, 5. Pressure retesting, 6. Thickness testing, 7. MC330/331 retesting, 8. Vapor recovery testing, 9. Bottom-loading conversion, 10. Major barrel repair, 11. Tank passivation, 12. Sandblasting/painting, 13. Tank changeouts, 14. Tank degassing, 15. Tank cleaning (for repair only), 16. Custom fabrication, 17. Purchase wrecked trailers, 18. Pick-up & delivery, 19. Lining repair, 20. ASME “U” stamp, 21. National Board “R” stamp

Soon To Be Added Data:

Tank Cleaning Directory

The Commercial Tank Cleaning Directory…information…was supplied by the operators of commercial and carrier-owned tank wash facilities that provide cargo tank interior cleaning. Directory listings may include product limitations such as “food grade only” or “no hazmat.” Learn more


Footnotes

[1] 407 active and 6 inactive facilities; Region –

  1. 259 “Consuming East” primarily within depleted reservoirs providing supplemental backup and/or peak period supply,
  2. 49 “Consuming West” primarily for domestic US and Alberta gas to flow at constant rates, and
  3. 105 “Producing” facilities which are primarily responsible for hydrocarbon basin export connectivity, transmission, and distribution and allow for the storage of currently redundant natural gas supply; Field Type Affiliation – 43 aquifers, 331 depleted fields, and 39 salt domes. Learn more

[2] These total horsepower and throughput figures are up from 13.4 million and 743 BCF in 1996.

Texas Drought Conditions and Water Availability

By Thomas DiPaolo, GIS Intern, FracTracker Alliance –

For the last three years, Texas has been experiencing a drought so severe that it has gained media attention around the world; the recurring theme from each media report is that the water use of the oil and natural gas industry is sucking up so much water from the ground that towns like Barnhart are seeing their taps run dry.


To view the fullscreen version of this map, including details about each layer, click here.

Surface Water

Water data for Texas, owned and operated by the Texas Water Development Board (TWDB), defines “reservoir storage” as the total volume of water contained within a reservoir, while “conservation storage” is specifically the volume of water that can be accessed and moved out of the reservoir. For example, the Twin Buttes Reservoir currently has 2,095 acre-feet of water in its reservoir storage, but because it cannot be removed from the reservoir, in terms of conservation storage it is considered “empty.” Twin Buttes is not the only reservoir in this position; Electra Lake, Meredith Lake, and White River Lake are also empty, and Electra Lake has no water at all in its reservoir storage. The average conservation storage of reservoirs statewide is 168,704.64 acre-feet. Ninety-two reservoirs (including the aforementioned) have less than that amount, while six reservoirs have conservation storages in excess of 1 million acre-feet. For reference, a TWDB report from last year found that in 2011 statewide fracking operations used a combined total of 81,500 acre-feet of water, over 26.5 billion gallons. That is almost enough to consume the conservation storage of the ten smallest reservoirs in the state.

The other measure for comparing water quantity is “fullness percentage,” a ratio between a reservoir’s current conservation storage and the maximum volume of water it can hold without flooding, or maximum conservation storage. Any reservoir with no conservation storage, therefore, has a fullness of 0%, while overflowing reservoirs are only 100% full. This means that, in contrast to the four reservoirs with 0% fullness, four other reservoirs have complete fullness. Monticello Reservoir, Mountain Creek Lake, and Squaw Creek Reservoir are all in excess of their conservation storages, but Houston Lake is flooding by the greatest amount, with reservoir storage of 139,409 acre-feet and conservation storage of 128,054 acre-feet. The average reservoir is  56.01% full as of this writing, but 44 of 115 reservoirs have a lower proportion of fullness. The problem here isn’t that every reservoir is under threat: it’s that those reservoirs which are threatened are running on empty.

Water Restrictions

Fig1The Texas Commission on Environmental Quality, the state’s oil and gas regulatory agency, publishes a list of drought-affected public water systems and their restrictions, classifying them by “stage” and “priority” (Figure 1). Stage refers to the expected duration of the existing water supply, while priority reflects the degree to which residents’ water usage is being restricted. This means water systems with no immediate threat of their supplies expiring may be applying extreme restrictions to sustain that supply. Water systems in the highest stage of “Emergency” have at most 45 days before their water supplies are exhausted; a priority of “Severe” means the water system has forbidden all outdoor water usage and may limit individual residents’ usage if they believe it’s necessary. At the time of this writing, 442 water systems have instituted voluntary restrictions on water usage, but 44 systems have a Severe priority, and five of those are in a stage of Emergency.

Of those systems, only the White River Municipal Water District appears in the map above within the data layer of public water systems offered by the TCEQ, and it lies within 20 miles of eight different fracking wells1. According to FracFocus.org, these eight wells consumed a combined volume of almost 600,000 gallons of water, or 1.8 acre-feet, when they were first fractured. While that amount may sound low, FracFocus shows 1,557 fracking wells within the state of Texas, and White River is located about 100 miles from the major oil fields of west Texas, where individual wells commonly consumed millions of gallons of water. For eight wells combined, 600,000 gallons is at the bottom of the scale.

FracFocus also notes that these figures do not take into account the amount of fresh water used in drilling. As freshwater becomes scarcer, hydraulic fracturing operations are turning to brackish water, which contains salt or other minerals, and water recycled from previous gas wells: the TWDB estimated that 17,000 of the 81,500 acre-feet of water used in 2011 was either brackish or recycled, and water recycling specifically is on the rise ever since the Texas legislature removed the need to seek permits before recycling water on leased land. FTS International reports that some of its Texas wells have completely switched over to recycled water.

It remains to be seen how soon efforts like this will bring relief to towns like Barnhart.


Footnotes

1. The eight wells in question are Bryant B-1045, etal #4576; Bryant B-1045, etal #4578; Flores, etal #182; Rankin #etal 161; Rankin, etal #172; Wheeler-1046, #4666; Wheeler-1046, #4678; and Williams, etal #4570. Reports on all of them can be found on FracFocus by searching for Crosby County, Texas.

Offshore oil and gas development in CA - Photo by Linda Krop Environmental Defense Center

Hydraulic Fracturing Offshore Wells on the California Coast

By Kyle Ferrar, CA Program Coordinator, FracTracker Alliance

Dirty Water by EDCOn October 16th, the Environmental Defense Center released a report focused on the use of hydraulic fracturing by offshore oil drilling platforms off the coast of California.1 The full report can be found on the EDC’s website. I was asked to assist in creating the report’s GIS maps, the results of which are described partially in the article below and are shown on the right.  An interactive map of this data, overlaid with additional data layers including oil spills and offshore wells is below.

Regulation of Offshore Drilling

California has 24 offshore oil rigs, with only one of them located, and therefore regulated, in state waters. In the map below, the regulated platform is labeled as “Holly.” The rest of the platforms, including platform “A” which was responsible for the Santa Barbara oil spill of 1969, are located in federal waters beyond the “outer continental shelf” (OCS) boundary, shown in the map with a dashed line.

Santa Barbara Channel_10.7.13

International, federal, and state laws are interrelated legal regimes that impact development of offshore oil, gas and other mineral resources in the US. Governance is bifurcated between state and federal law. States have authority in the “three-geographical-mile” area extending from their coasts. Federal regulatory regime governs minerals located under federal waters that extend out past state boundaries at least 200nautical miles from shore.  This is known as the “exclusive economic zone,” for which coastal nations have the sovereign right to explore, exploit, conserve, and manage marine resources. The basis for most federal regulations is the Outer Continental Shelf Lands Act (OCSLA), which provides the system for offshore oil and gas exploration, leasing, and ultimate development. Regulations range from health, safety, resource conservation and environmental standards to requirements for production-based royalties and in some cases royalty relief and other development incentives. The moratoria on offshore leasing on many areas of the outer continental shelf were lifted in 2008 by President Bush and the 110th congress. Prior to that, several areas were made available for leasing in 2006 including the Aleutians and the Gulf. Recent changes to authorities regulating offshore development resulted after the Mineral Management Service was implicated in numerous scandals, including uncollected royalties estimated to amount to $160 million in 2006 alone.2 Offshore resource extraction is now regulated by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement, both agencies of the Department of the Interior.

Investigating Hydraulic Fracturing

Point Conception Offshore Rigs_10.7.13

A recent freedom of information act request filed by the Environmental Defense Center (the group was formed in response to the 1969 Santa Barbara oil spill) identified 15 offshore drilling operations that used hydraulic fracturing. (Update: recent information from the FOIA shows 203 frac’ing operations from 6 different rig platforms!)4.  This number is most likely a vast underestimation, as the Bureau of Safety and Environmental Enforcement (BSEE) estimates 12% of offshore operations in the Gulf use hydraulic fracturing. These “frac” operations were conducted without notifying the necessary regulatory agencies. The majority of this activity was conducted from the platforms Gilda and Gail, both labeled in the maps. While these offshore energy resources may be oil-rich, the fossil fuel resources pale in comparison to the biodiversity and ecological productivity of the Santa Barbara Channel and the California Channel Islands. The geography of the Channel Islands was formed by the cold-water swells of Northern California meeting with the warm-water swells of Southern California. This convergence resulted in a plethora of ecological microcosms in addition to the critical and sensitive habitats of endangered and threatened species shown in the maps.

Recently, the Department of the Interior approved four more hydraulic fracturing operations at these offshore platforms. Take note of the many ecological preserves and areas of protected/sensitive habitat in the midst of the many offshore wells and platforms. The map layer showing historic oil spills deserves special attention, with focus on the spills at platforms Gail and Gilda. Seeing this, it is alarming that the proposals were not required to conduct environmental impact assessments, and were instead granted “categorical exemptions” from the environmental analyses and public transparency actions strictly required by the National Environmental Policy Act. These actions (or lack thereof) in such an ecologically complex environment, especially considering it is the historical site of the US’s third largest oil spill, raises serious questions of compliance with other federal laws including the Clean Water Act, Endangered Species Act, Marine Mammal Protection Act, and Coastal Zone Management Act.3

Policy Recommendations

Additionally, the EDC report makes several policy recommendations:

  • Place a moratorium on offshore hydraulic fracturing, or “fracking,” and other forms of well stimulation unless and until such technologies are proven safe through a public and transparent comprehensive scientific review
  • Prohibit the use of categorical exclusions to authorize offshore fracking and other forms of well stimulation
  • Formally evaluate offshore fracking and other forms of well stimulation through a Programmatic Environmental Impact Statement
  • Initiate consistency reviews with the California Coastal Commission for all exploration plans, development plans, drilling or modification proposals involving fracking
  • Ensure that all fracking proposals comply with the Endangered Species Act and Marine Mammal Protection Act
  • Review and revise the Clean Water Act permit governing offshore oil platforms to directly address chemicals in frac flowback and other wastewater, either establishing effluent limitations for those chemicals or denying discharge altogether

References

  1. Environmental Defense Center. 2013. Dirty Water: Fracking offshore California. Retrieved 10/16/13.
  2. Daniel Whitten. September 16, 2010. Oil, Gas Royalty-In-Kind Program to End, Salazar Says. Bloomberg. Retrieved 10/15/2013.
  3. Environmental Defense Center. October 16, 2013. EDC Provides Fracking Details. Retrieved 10/16/13.
  4. ALICIA CHANG and JASON DEAREN. October 19, 2013. California Offshore Fracking More Widespread than Anyone Believed. Huffington Post. Retrieved 10/22/13.

European Drilling Perspectives

By Samantha Malone, MPH, CPH – Manager of Science and Communications

In August I spent a little over two weeks in Europe, the first of which was for work in Berlin, Germany and Basel, Switzerland. Now that I have had some time to process my travels and am back on a proper sleep schedule, I thought I’d provide a little wrap up of my impressions of Europe and the issue of unconventional drilling.

Berlin, Germany

Berlin, Germany

Berlin, Germany

In Berlin, I was hosted by two innovative organizations: JF&C and Agora Energiewende. JF&C is a consulting company that advises on international markets and sustainable growth. The roundtable held by JF&C was intended to bring together a diverse group of decision-makers in Germany to discuss potential challenges of heavy drilling in Europe — and they did not disappoint. Participants included representatives from the:

The diverse backgrounds of the group led to a heated yet balanced debate on the topic of whether unconventional gas extraction should occur in Germany, as well as the rest of Europe. I was quite impressed by the transparent and matter-of-fact perspectives held by attendees, which as you can see above included governmental, NGO, and industry reps.

My next presentation in Berlin was coordinated by Agora Energiewende. Energiewende refers to Germany’s dedication to transitioning from non-renewable to more sustainable fuels. You can read more about the movement here. This forum was set up in a more traditional format – a talk by me followed by a series of questions from the audience. Many of the attendees at this event were extremely well informed about the field of unconventional drilling, climate change, and economics, so the questions were challenging in many respects. Attendees ranged from renewable energy developers to US Embassy personnel. As a reflection of such diversity, we discussed a variety of topics at this session, including US production trends and ways to manage and prepare databases in the event that heavy drilling commences in Germany and other parts of Europe.

Interestingly, one of the major opponents of this form of gas extraction in Germany, I learned, has been the beer brewers. (They were not able to be at the table that day, sadly enough.) German breweries that adhere to a 4-ingredient purity law referred to as Reinheitsgebot are very concerned and also very politically active. You can read more about beer vs. fracking here, just scroll down that page a bit.

Over decadent cappuccinos the next morning, I met with Green Parliament representatives who wanted to hear firsthand about FracTracker’s experience of drilling in the U.S. Overall, my Berlin tour showed me that many individuals seemed skeptical that unconventional drilling could safely fulfill their energy needs, while also possessing a hearty intellectual craving to learn as much about it as they could.

Basel, Switzerland

Basel, Switzerland

Basel, Switzerland

The second part of the week was dedicated to attending and presenting at the International Society for Environmental Epidemiology conference in Basel, Switzerland. I participated in a panel that discussed the potential environmental and public health impacts of unconventional gas and oil drilling, as well as methods for prevention and remediation. The audience was concerned about a lack of regulatory and data transparency and the likelihood that such operations could contaminate ground/drinking water supplies. Based on the number of oil and gas wells impacted by the recent Colorado flooding tragedy, I cannot blame them. Most of these attendees were from academia or non-profits, although not entirely; check out coverage from this Polish radio station. (As mentioned in a previous post, Poland is one of the countries in Europe that has the potential for heavy drilling.)

The amount of knowledge I gained – and shared – from this one week alone is more than could have been possible in a year through phone calls and email exchanges. I am incredibly thankful for our funders’ and FracTracker’s support of this endeavor. Being able to discuss complex issues such as unconventional drilling with stakeholders in person is an invaluable key for dynamic knowledge sharing on an international level.

Links to My Presentations (PDFs):  JF&C  |  Agora  |  ISEE

A few non-work pictures from the second week of my trip…

Dornbirn, Austria

Dornbirn, Austria

Lake Lugano, Switzerland

Lake Lugano, Switzerland

The Alps, Switzerland

The Alps, Switzerland

Milan, Italy

Milan, Italy

Local Actions and Local Regulations in California

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.