The Environmental Benefits and
Challenges of Tight Oil and Gas
Development
Hannah Wiseman
Assistant Professor, Florida State University College of
Law
hwiseman@law.fsu.edu
2013 Energy Conference, October 29, 2013
The development of oil and natural gas
resources from shales and tight sandstones—
“tight” formations—has transformed domestic
fossil fuel production, causing the United States
to become a leading producer.
What are the environmental benefits and
challenges of this transformation, and what
opportunities for improvement remain?
http://marcellus.psu.edu/resources/PDFs/marcellusshalereport09.pdf.pdf
Road map of presentation
• National perspective on benefits and costs:
simultaneous displacement of coal and
renewables/energy efficiency.
• Wellhead perspective: smaller surface
footprint due to horizontal drilling, but tens of
thousands of new wells and associated
impacts.
• The regulatory landscape, with a focus on the
states, and improvements needed.
National benefits: displacement of
coal in electricity generation
Lower U.S. CO2 emissions
Methane leakage: the latest science
• “Magic number” for climate is 3.2% leakage or
lower (Environmental Defense Fund estimate).
• Allen et al. (2013): methane leakage during
flowback is low—0.42% of gross gas production.
– Measured actual leakage from 489 hydraulically
fractured wells (27 flowbacks). Although controlled
for potential bias, might have measured best
practices.
• Alvarez et al. (2012): converting fleets to CNG
“increases radiative forcing for 80 yr. before any
net climate benefits are achieved.”
National costs: displacement of other
innovative efforts, renewable technologies
Henry Jacoby et al. (MIT), The Influence of Shale
Gas on U.S. Energy and Environmental Policy
(2012):
• “The gas ‘revolution’ has important implications
for the direction and intensity of national efforts
to develop and deploy low-emission
technologies, like CCS [carbon capture and
storage or sequestration] for coal and gas.” It will
slow and in some cases stop these efforts.
• Cheaper gas “serves to reduce the rate of market
penetration of renewable generation.”
Energy Information Administration: Estimated levelized cost of new
generation resources, 2018, in 2011 dollars per megawatt hour,
excluding tax credits
Plant type
Levelized
capital cost
Fixed O&M
Variable
O&M
(including
fuel)
Transmission Total system
investment
levelized cost
Conventional 65.7
coal
4.1
29.2
1.2
100.1
Conventional 15.8
combinedcycle gas
1.7
48.4
1.2
67.1
Advanced
nuclear
83.4
11.6
12.3
1.1
108.4
Wind
onshore
70.3
13.1
0.0
3.2
86.6
Geothermal
76.2
12.0
0.0
1.4
89.6
Solar PV
130.4
9.9
0.0
4.0
144.3
Solar thermal 214.2
41.4
0.0
5.9
261.5
Hydro
4.1
6.1
2.0
90.3
78.1
Wellhead perspective: environmental
risks
Potential risks in this presentation identified
from the following materials:
– Violations of state environmental and oil and gas
laws at wellheads.
– Other incidents collected and reported by state or
regional agencies and courts.
– Peer-reviewed papers.
http://www.dec.ny.gov/docs/materials_minerals_pdf/rdsgeisch6b0911.pdf
Most important risks (it appears)
• Cumulative impacts
– Traditional risks (long known in oil and gas industry),
magnified due to number of wells: landscape
impacts, habitat fragmentation, air emissions, other
risks
• Spills and leaks from pits and tanks:
contamination of soil, surface water, groundwater
• Bird deaths in pits (but low
as compared to deaths caused
by house cats and automobiles)
https://www.fws.gov/phdec2012.html
• Impacts on streams when water withdrawn
simultaneously within one region
• Inadequate casing and plugging of wells
• A lack of good options for disposal: large
quantities of liquids; solids that settle out of
brine and flowback
• Road damage and other local challenges
http://gallery.usgs.gov/photos/03_08_2013_v0Qd72Gts4_03_
08_2013_7
Other risks: not as prevalent (perhaps),
but single incidents can have large impacts
Leaking underground injection control (UIC)
disposal wells
Induced seismicity from UIC wells
http://water.epa.gov/type/groundwater/uic/class2/
Cumulative impacts
• The EPA estimates that 11,400 new wells are
fractured or refractured annually in the United
States.
• In New York State, 56,508 horizontal gas wells
and 6,723 vertical gas wells could be drilled
and fractured in thirty years (NY Dept. of
Envtl. Conservation).
• Approximately 28,000 wells will have been
drilled in Texas’s Barnett Shale by 2030.
(Currently at 16,000 wells.)
City of Fort
Worth,
Texas:
1,856
producing
wells
http://fortworthtexas.gov/gaswells/defau
lt.aspx?id=50608
Cumulative air emissions
Air impacts
http://www.ndoil.org/image/cache/NDPCAnnual092111_2.pdf
Colorado
Gabrielle Petron et al., Hydrocarbon Emissions
Characterization in the Colorado Front Range: A
Pilot Study, J. Geophysical Research (2012)
Analysis of daily air samples “since 2007 shows
highly correlated alkane enhancements caused by
a regionally distributed mix of sources in the
Denver-Julesburg Basin.” Attributed to “a mix of
venting emissions (leaks) of raw natural gas and
flashing emissions from condensate storage tanks.”
Spills
Pennsylvania Marcellus: Two fuel tank trucks
collided at the pad entrance. . . . The fuel tank was
damaged and leaked approximately 15 gallons of
diesel fuel” onto road. Contaminated material
excavated. Permit 115-20293.
Self-reported 20-gallon diesel spill from delivery
truck. Permit 115-20298.
New Mexico tight sands: “A fuel pump split, allowing
1,000 gallons of diesel to be released. 100 gallons
recovered.” API 30-039-30557.
Louisiana Haynesville: “Oil based mud
discharged in vicinity of well and allowed to
migrate to natural drainage.” Permit 239818.
Pennsylvania Marcellus: “1,500 gallon spill of
drilling mud . . . observed on the surface of the
ground outside of the containment area.” Permit
131-20047.
New Mexico tight sands: “During fracking a
valve was left open due to human error causing a
release of 245 gallons of frac water, all
recovered.” API 30-045-34625.
Pennsylvania Marcellus: “Blowout, frac fluid
release” in Tioga County. Permit 117-20373.
Surface pits and tanks
Louisiana Haynesville: Frac tanks used for temporary
storage of produced saltwater. Gauging error caused
overflow, and water flowed into ditch and swampy
area. Permit 238585.
Texas Barnett shale: Driveway, pasture, pond polluted
with low chloride drilling fluids diluted with rain water.
Permit 630921.
Colorado tight sands: “Excessive oil accumulation at
tank battery. Berm not sufficient at tank battery.
Excessive oil on ground at wellhead, oil is migrating
down grade (from wellhead) toward upper pit.
Wildlife accessing both pits.” API 05-103 -08459.
U.S. v. Brigham Oil and Gas (D.N.D.
2012)—Bakken Shale reserve pits
“On May 6, 2011, Special Agent Grosz and [Fish
and Wildlife] Service Contaminants Specialist . . .
.inspected the . . . site. Grosz inspected the pit
and noted it was not netted or flagged at the
time of inspection. He noticed an oil sheen “on
the fluid of the reserve pit.” During the
inspection, . . . Grosz observed and collected
“two dead and oiled mallards.” Dead pintails
and ring-tailed ducks also found.
http://dwrcdc.nr.utah.gov/rsgis2/search/Display.asp?FlNm=anasacut
Simultaneous water withdrawals
Susquehanna River Basin Commission, July 16, 2012,
64 Water Withdrawals for Natural Gas Drilling and
Other Uses Suspended to Protect Streams
“Under SRBC’s passby flow restrictions, when
streams drop to predetermined protected low flow
levels, operators who are required to meet the
agency’s passby requirement must stop taking
water.” Most states and regions do not have this
type of regulation.
http://www.srbc.net/newsroom/NewsReleasePrintFriendly.aspx?NewsReleaseID=90
Inadequate casing and plugging of
wells
Pennsylvania Marcellus: “Methane migrated to
surface through cement in 9 5/8” annulus.” Permit
033-26848.
(Post-drilling – well shut in): “Cellar is filled with
water. . . .Well head is leaking from somewhere
below the surface of the water. Gas is bubbling
up through the water all around the wellhead.”
Permit 033-26828.
“March 30, 2011 order: “Catalyst Energy’s
unpermitted discharge of iron, manganese,
dissolved methane, dissolved ethane, and
combustible free gas from its drilling activities
into groundwater violates . . . the Clean
Streams Law . . . [and] constitutes unlawful
conduct and a public nuisance.”
Mar. 10, 2009 letter from DEP, Bradford, PA: Lab
analysis of spring water “indicated levels of
Chlorides, Total Dissolved Solids, Calcium,
Sodium and Specific Conductivity that were in
excess of EPA’s drinking water standards.
Elevated levels of these parameters are
indicative of a dilute brine solution and suggest
an infiltration of frac water into the shallow
ground water that supplies your spring.”
Disposal challenges
Lara A. Haluszczak et al., Geochemical Evaluation
of Flowback Brine from Marcellus Gas Wells in
Pennsylvania, APPL. GEOCHEM. at 6 (2012) noted
levels of radium in flowback water “13-1300
times that maximum contamination level for
drinking water standards.”
Difficult to treat at a wastewater treatment
plant.
Underground injection control wells
Oklahoma Geological Survey (2011)
“Cases of clear anthropogenically-triggered seismicity
from fluid injection are well documented with
correlations between the number of earthquakes in an
area and injection.”
See also Katie M. Keranen et al., Potentially Induced
Earthquakes in Oklahoma, USA: Links Between
Wastewater Injection and the 2011 Mw 5.7 Earthquake
Sequence, GEOLOGY (2013).
Midland, Texas: an improperly constructed
injection well—maintained by a company now
in bankruptcy—leaked into the city’s drinking
water aquifer, creating a “‘plume’ of chloride
infested water that is (and has been for some
time) migrating through the Aquifer” and
progressively polluting more fresh water.
Approximately 6.2 billion gallons had been
contaminated by 2010.
Road damage and other local
challenges
National Park Service estimates average well requires
320 to 1,365 truck trips, depending on whether water is
trucked in or piped in.
http://marcellus.psu.edu/resources/PDFs/m
arcellusshalereport09.pdf.pdf
http://www.willistondevelo
pment.com/usrimages/Willi
ston_Impact_Statement.pdf
The regulatory landscape
REGIONAL
LOCAL
States determine
nature and
extent of local
jurisdiction.
STATE
States have
independent
authority over
many development
activities.
PUBLIC-PRIVATE
States work with
nonprofits and
industry groups to
write guidelines,
review regulations.
States, with
federal approval,
participate in
compacts.
FEDERAL
States
implement
certain federal
environmental
regulations.
State regulations
• For cumulative impacts, not much regulation,
although Colorado leads in controlling air
emissions, and Maryland has proposed a
comprehensive gas drilling plan.
• Spills; leaks from pits and tanks: well and well
site setbacks, minimum pit liner thickness,
minimum “freeboard” in pits. Pits must be
dewatered and filled in.
Well setback requirements
Pennsylvania Act 13, effective Apr. 16, 2012 – under review
Regulatory provision
Before Apr. 16, 2012
As of Apr. 16, 2012
Distance between gas well
and water well
200 ft.
58 Pa. C.S. § 601.205
500 ft.
58 Pa. C.S. § 3215
Distance between well site or 100 ft.
well and stream
58 Pa. C.S. § 601.205
300 ft.
58 Pa. C.S. § 3215
Distance between well pad
and public water supply
1,000 ft.
58 Pa. C.S. § 3215
no regulation identified
Rebuttable presumption that 1,000 ft. for contamination
oil and gas operations caused within 6 months of
water contamination
operations
58 Pa. C.S. § 601.208
2,500 ft. for contamination
within 1 year of operations
58 Pa. C.S. § 3218
West Virginia Natural Gas Horizontal Well Control Act, HB 401,
effective December 14, 2011
Regulatory provision
Before December 14, 2011
As of December 14, 2011
Distance between gas well
and water well
200 ft.
W. Va. Code § 22-6-21
250 ft.
W.Va. Code § 22-6A-12
Distance between well pad
or well and stream
no regulation identified
100 ft.
W. Va. Code § 22-6A-12
Distance between well pad
or well and trout stream
no regulation identified
300 ft.
W. Va. Code § 22-6A-12
Distance between well pad
and public water supply
no regulation identified
1,000 ft.
W. Va. Code § 22-6A-12
Rebuttable presumption that w/in 1,000 ft. of site
oil and gas operations caused
water contamination
W. Va. Code § 22-6-35
w/in 1,500 ft. of site
W. Va. Code § 22-6A-18
• Few direct regulations to protect against bird
deaths, although some states require netting
or pit covers.
• Stream impacts from cumulative water
withdrawals: states like West Virginia and
Pennsylvania require operators to show that
water withdrawal will not harm aquatic life.
Federal listing of diamond darter as endangered
will likely affect water use in Marcellus.
http://conservationfisheries.org/index.php/species/currentspecies/crystallaria-cincotta-diamond-darter/
Casing and well plugging: few states have updated
well bonding requirements, but many mandate
pressure tests of wells prior to fracturing. Some
have increased required casing depths, and some
limit the installation of used casing.
Most states provide minimum times for which
cement must set before being disturbed, and many
specify the type of cement that must be used.
http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx
#maps
Casing requirements example – Ohio SB 165,
effective June 30, 2010
Before June 30, 2010
As of June 30, 2010
“[G]ood and sufficient wrought iron
or steel casing so as to exclude all
surface, fresh, or salt water from
any part of such well.”
“[S]ufficient steel or conductor casing” that
protects unconsolidated sediments and water.
Method of placing casing approved
by Chief of Division of Mineral
Resources Management.
Materials must “comply with industry standards
for the type and depth of the well and the
anticipated fluid pressures that are associated with
the well.”
Sour gas and gas bearing zones must be isolated.
In lieu of casing, Chief could accept
“adequate mudding methods.”
Oh. St. § 1509.17
Well shall not be perforated in zones of water
protection.
Well owner shall notify mineral resources inspector
each time the owner or representative notifies
someone to perform casing.
Oh. St. 1509. § 17
Tracking water quality
Baseline testing: not uniform, but states
increasingly require it: incentivized to 1,500 feet
in West Virginia, 2,500 feet in Pennsylvania;
required to 1,500 feet in Ohio. See also
Colorado and Michigan.
State approaches to disposal
• Limit the available methods of disposal.
– Ohio S.B. 165 (codified at Ohio Rev. Code §
1509.226(10)): “flowback from the stimulation of a
well, and other fluids used to treat a well shall not be
spread on a road.”
• Require treatment prior to disposal.
– By 2014, Clean Water Act Treatment Standards for
Wastewater from Shale Gas Extraction
– 25 Pa. Code § 95.10: operators must reduce total
dissolved solids to a certain concentration prior to
disposal.
• Modify existing wastewater treatment permits.
Recycling of flowback and produced
water
• Very common in the Marcellus Shale region because of 25 Pa.
Code § 95.10: wastewater source reduction strategy must
“identify procedures” the operator will follow to maximize
recycling and reuse.
• Not much treatment of water necessary prior to reuse.
• Less common in other shales.
http://www.ohiodnr.com/Port
als/11/pdf/wastewater-factsheet.pdf
Changing governance to address
community impacts
• Pennsylvania Act 13 (2012): impact fee that is
redistributed for environmental remediation,
conservation, roads and bridges, low-income
housing.
– Pennsylvania Supreme Court still attempting to determine
constitutionality of Act 2013 after a Commonwealth court struck down
the Act.
• Road use agreements and other community
benefits agreements.
• Zoning to limit areas in which well development
may occur (where not preempted); cap decibel
levels; require sound barriers and fences.
Gina Banai, Rice Energy
Also note the importance of private
standards
• Lenders and lessors increasingly require
environmental protections within contracts and
leases, such as lining of the entire well pad, no
drilling in areas with too much surface water.
• Companies increasingly voluntarily disclose
chemicals added to fracturing water on FracFocus,
but we still do not know the composition of much
of the flowback water, which contains naturally
occurring substances.
• API standards, standards from Center for
Sustainable Shale Development impact certain
operators’ behavior.
State regulation: the enforcement
challenge
CO
2012
MI
2012
NM
2012
OH
2012
PA
2010
TX
2012
Number of field
inspectors
36
27
12
40
76
153
Approximate
number of active
oil and gas wells
(conventional and
unconventional)
49,062
(approx.
87 in
field)
15,742
56,366
55,083
92,326
See Regulatory Risks in Tight Oil and Gas Development. Hannah
Wiseman. Natural Gas & Electricity 29/5, ©2000, Wiley Periodicals,
Inc., a Wiley company, for sources.
279,856
Actual inspections and enforcement
State and
year
Approximate Number of
number of
inspectors
active oil
and gas
wells
Inspections
conducted
Violations
noted
Enforcement
actions
taken
Pennsylvania 92,326
2012
76
26,913
3,378
949
Texas 2009
87
128,000
80,000
550
280,000
http://www.portal.state.pa.us/portal/server.pt/community/oil_and_gas_compliance_report/20
299; http://www.sunset.state.tx.us/82ndreports/rct/rct_fr.pdf
Regulatory improvements needed
Comprehensive analysis of variability among
state regulations should be a top priority.
• In some cases, geology, climate, and other
factors may justify differences.
• In other cases, there might be one, accepted
practice for adequately protecting against risk,
yet this practice is not consistently required.
States should consider regulations with “total
harm thresholds” – those that address
cumulative impacts.
– Susquehanna River Basin Commission regulations
require water withdrawals to cease if streams drop
below a protected low flow level.
Bond amounts should be updated
• Indiana: $2,500 per oil and gas well, plus
annual fee, Ind. Code 14-37-6-1
• Ohio: $5,000 per well, Ind. Code 14-37-6-1
• Arlington, Texas $50,000 per well, City of
Arlington, Tex. Ordinance No. 07-074 §
6.01(B)(1)(c)
More insurance requirements
possibly needed
• Ohio Substitute Senate Bill No. 315 requires
liability insurance “of not less than five million
dollars bodily injury coverage and property
damage coverage,” and a “reasonable level of
coverage available for an environmental
endorsement.” Codified at Ohio Rev. Code §
1509.07.
• Few states require environmental liability
insurance. But see Maryland S.B. 854 (approved
May 16, 2013).
Better enforcement needed
• States likely need to raise well permitting fees
to fund more inspection staff.
• Through training, states should alert industry
to new rules to enhance compliance.
• States should establish enforcement priorities.
(Pennsylvania—incidents that “result in an
actual release of gas or pollutants and
endanger human life or public health and
safety”).
Example of industry training
Governments should reassess who
has what authority and why
• States are not in all cases the best entities to
regulate oil and gas development.
• Municipalities still need some control if high
drilling and fracturing rates are to continue—
minimal zoning and nuisance-prevention
authority needed.
• Federal government should, at minimum,
more closely investigate inconsistencies
among state regulations and consider filling
gaps if states do not.
Substantive gaps to prioritize
• Pit and tank management, including pits that
hold flowback for reuse, and secondary
containment requirements
• Wastewater reuse and disposal
• Baseline and post-drill water testing
• Casing requirements, including well pressure
tests--must ensure that casing can withstand
pressure of fracturing, and not all states do
• Water withdrawal regulations
• Community impacts
Summary of points
• Upstream oil and gas, like many other
industries, poses a number of risks. We can
limit many of these risks; others are more
difficult to address.
• Governments are rapidly updating certain
regulations, but gaps remain.
• Enforcement should be the first gap filled:
states should raise fees so that they can hire
more staff, set and implement priorities.
Consider electronic monitoring at sites?
Thank you. I welcome questions and comments:
hwiseman@law.fsu.edu.