Frequently
Asked Questions About Shale Gas and Hydraulic Fracturing in Massachusetts
last updated 12/11/2012
Useful resources about shale gas and hydraulic fracturing
The Massachusetts Geological Survey provides these links as a convenience to Massachusetts residents; these listings should not be taken as endorsements.
1.
Has there been
any interest in exploring for shale gas in Massachusetts?
To our knowledge, no companies have
expressed any interest in exploring for or developing shale gas in Massachusetts.
In addition, to our knowledge
no well driller has requested certification (310 CMR 46.00) from the
Massachusetts Department of Environmental Protection (MADEP) to drill any well
within Massachusetts other than water, monitoring, and geothermal wells. All well drillers are required to be
certified by regulation with MADEP before they are allowed to drill any wells
in Massachusetts.
2.
Is hydraulic
fracturing for shale gas coming to Massachusetts?
Probably not. Based on a survey of all available scientific
data, the geologic conditions in the Connecticut Valley in western
Massachusetts are not optimum for shale gas development. Black shale units in the Hartford Basin are
generally too thin, laterally discontinuous, and are cut by too many pre-existing
natural fractures and extinct faults. This makes extraction of hydrocarbons economically
not feasible with today’s technology at current market prices (see below).
However, more data need to be collected to completely rule out that possibility.
In addition, oil and gas wells used for
conventional or enhanced hydrocarbon recovery are defined as Class 2 wells
under the Massachusetts Underground Injection Control Regulations (310 CMR
27.00). Class 2 wells are currently
prohibited in the Commonwealth.
3.
Weren’t
shale gas deposits recently found in Massachusetts by the U.S. Geological
Survey (USGS)?
No. This is a common misconception of
USGS Fact Sheet 2012-3075. There is sufficient information in previously
published geologic literature to demonstrate that hydrocarbons were generated
in the Hartford basin roughly 200 million years ago (Pratt et al., 1988). However, as stated above, due to geologic
limitations there is no prospect of extraction of hydrocarbon from the Hartford
basin in the foreseeable future.
The USGS Fact Sheet refers to the
Hartford basin as a “composite total petroleum system” (TPS) with a potential
to produce gas from the black shale deposits, which are referred to by the USGS
in their report as “continuous gas accumulations”. TPS is just a term that
means the essential elements (ie., source rock for
hydrocarbon production, reservoir rocks to store hydrocarbons, and seal rock to
trap the migrating hydrocarbon) are potentially present and processes (ie., to generate hydrocarbons through burial, to migrate
hydrocarbon into reservoir rocks and to accumulate hydrocarbon in traps or as
residual hydrocarbon in the black shales) may have
occurred. It does NOT mean that oil and gas has been discovered and is ready for
production. The USGS did NOT quantitatively assess the
Hartford basin because of a lack of data. The USGS report assessed potential shale
gas volumes for 5 of the 14 Mesozoic extensional basins (see below) in the
eastern United States. The Hartford
Basin, which underlies the Connecticut Valley, was NOT one of the basins
assessed in this report.
The Hartford basin has no physical connection
or geologic relationship with the Marcellus or Utica shales
found in New York or Pennsylvania.
The USGS report can be downloaded at: http://pubs.usgs.gov/fs/2012/3075/fs2012-3075.pdf
4.
What is shale
gas?
Shale gas is natural gas formed and trapped
within shale formations. The gas is
trapped by adsorption onto insoluble organic matter in the shale and within
tiny pore spaces or micro-fractures within the shale. The gas is a mixture consisting
primarily of methane and minor amounts of ethane, propane, butane, carbon
dioxide, nitrogen and hydrogen sulfide, among others. Shale gas was first extracted as a
resource in Fredonia, NY in 1821.
5.
Shale gas is
sometimes referred to as unconventional gas or as occurring in continuous gas
accumulations. How is shale gas
different from conventional oil and gas?
Organic-rich shales
are the primary source rocks for oil and gas. When buried to great depths, the organic
material is converted by heat and pressure to hydrocarbons. Over geologic time some of the oil and
gas can migrate out of the source rocks through pores and fractures into
overlying and more porous sandstones and carbonate rocks, referred to as
reservoir rocks. The oil and gas
will migrate through the reservoir rocks until it hits a cap rock of impervious
material that impedes upward and lateral migration to the land surface. The trapped oil and gas is then
extracted by production wells. These accumulations generally consist of formation
waters (mineral-rich waters known as brines) at the base, which are overlain
successively by oil and natural gas. This is referred to as conventional oil
and gas.
In most cases, however, some of the
gaseous hydrocarbons are too tightly bound to organic material in the shale and
cannot escape. In other cases, the
shale and surrounding rocks are too impermeable to allow gas to migrate out of
the source rock into adjacent rock formations. In yet others, hydrocarbon gases are
produced by microorganisms living in the rocks. These all are known as unconventional or
continuous gas accumulations. In
many unconventional gas resource deposits, hydraulic fracturing is used as a
cost-effective means to make more of the potential reservoirs accessible for
natural gas production.
6.
What is shale?
Shale is a
sedimentary rock that is made predominantly of very fine-grained clay particles
deposited in very thin layers.
These rocks were originally deposited as mud in low energy depositional
environments, such as tidal flats, swamps, lakes, and deep-ocean basins where
the clay particles dropped out of suspension from the water column. Deep burial
of this mud results in a layered rock called shale, which actually describes
the very fine grained and laminated nature of the sediment, not its rock
composition. The composition of shales varies widely,
and only some are rich in organic materials that can generate natural gas.
7.
How does shale
gas form?
During deposition of the muds that form
shales, organic matter is also deposited,
particularly in swamps and lakes.
The amount of organic matter in a rock is measured by a parameter called
Total Organic Carbon (TOC). Shale gas is produced from organic-rich shales, also known as black shale. These are shales
with greater than 1% TOC. Plant and
algal remains and the animal forms that consume them are buried with the
sediment. As the sediment load
increases due to continued burial, heat and pressure converts some of this
organic material into hydrocarbons (compounds made of hydrogen and carbon). Conversion
of this initial organic material (called kerogen)
into petroleum causes an increase in rock pressure, which expels the oil and
gas from the shales into adjacent strata. Continued pressure from burial may allow
much of the natural gas to migrate from the organic shales
into overlying reservoir rocks. The
natural gas that remains tightly bound in the shale is the unconventional shale
gas.
8.
Do we have
organic rich black shales in Massachusetts?
Yes. There are numerous (perhaps 15 to 20) examples
of Lower Jurassic black shales in the Connecticut
Valley but these occur as very thin beds (Fig. 1;
Pratt et al., 1988). Bed
thicknesses average from 3 to 6 feet to just a few inches (Kruge
et al., 1989). Some beds may be up
to 25 feet thick in Connecticut but are laterally discontinuous and do not
cover large areas. These beds are
typically separated by an average of 30 or more feet of water laid (fluvial)
red sandstones and siltstones (Hubert et al., 1992).
Total cumulative thickness of the black
shales in the Connecticut valley of Massachusetts is estimated
to be between 100 and 130 feet (Pratt and Burruss,
1988) and no more than 160 feet (Hubert, person. communication, 2012). The shale beds occur within a 5000-6000 foot
thick (~1.1 miles) stack of fluvial and lacustrine sandstones, mudstones,
conglomerates, and flood basalt (Fig. 2).
The average organic content of the
black shales is about 2% by weight (Pratt et al.,
1988) but can be as high as 3 to 7.6%.
Samples of rock from the Connecticut valley show that oil and gas has
migrated out of some of these black shales in the geologic
past as evidenced by bitumen in fluid inclusions, mineralized veins, coated
fractures and stained sand grains in adjacent rocks (Pratt and Burruss, 1988).
9.
So is there
any conventional oil and gas found in the Connecticut valley in economic
quantities?
Most of the published evidence
indicates that with today’s prices and technology there is likely no
economically viable conventional or unconventional oil and gas in the
Connecticut valley (Pratt and Burruss, 1988; Hubert
et al., 2001).
The rocks are
either thermally overmature,
meaning they have been heated beyond the oil and gas thermal generation window (Fig. 3), or there is no trapping geometry of strata which
could have contained migrating hydrocarbons after they were produced. Accordingly, most of the economically
viable oil and gas probably volatilized and seeped to the surface long ago, roughly
170 million years ago (Hubert et al., 1992). All that is left behind in present day
rocks is the residual trail. The
area where the thermal regime may be most favorable for oil in Massachusetts is
in the northeast part of the Hartford basin south and east of the Holyoke Range
(Fig. 3).
10.
Have any companies expressed interest in evaluating
conventional oil or gas potential in the Connecticut valley in the past?
Yes. Texaco did some exploratory
geophysical work in the 1970s. They
did not return to the Connecticut Valley and no exploration drilling was
carried out. In the late 1980s
Texaco funded some work to examine the burial, diagenesis
and hydrothermal history of the Connecticut Valley (Taylor, 1991; Hubert et
al., 1992, 2001). No further
exploration was conducted.
11.
Do any of the
black shales in the Hartford basin contain shale gas?
Probably, however, several factors suggest
that extraction is most likely not practical or economically feasible with
current technology at present day gas prices. The black shale units are thin, of
variably thickness and laterally discontinuous. In most cases, the individual beds that
would be targeted are only 3 to 6 feet thick. Although they may be capable of storing
substantial amounts of hydrocarbon, the petroleum can diffuse out into adjacent
rocks relatively quickly due to the thin nature of the beds; it is a leaky
source rock at best. In addition, the Connecticut valley shales
have locally been heated by lava flows and hydrothermal fluids (Hubert et al.,
2001; Hubert et al., 1992; Pratt et al., 1988) leading to locally overly mature
deposits and limiting the areal extent of any potential extractable resource
(Pratt et al., 1988).
Thick (100 to 300+ feet) and laterally
extensive (several 10’s to 100’s of miles) sequences of black shale like the
Marcellus, Utica and Barnett Shales DO NOT EXIST in the Connecticut
valley.
In the USGS assessment, associated
tight sandstones were considered to be part of the continuous gas accumulations
evaluated. Under certain conditions, such as those that occur within the
Silurian sandstones of Ohio, tight sandstones associated with shale source
rocks may contain large unconventional (continuous) accumulations of natural
gas. The geological environments of the accumulations in Ohio, which extend
over many square miles, are considerably different than those that occur within
the Hartford basin.
However, more data are needed to fully
understand the geology and hydrocarbon potential of the basin. These additional data include exploratory
boreholes and rock cores to determine the actual thickness and continuity of
the target shale beds, seismic reflection surveys, geochemical analyses, tests
to determine the amount of gas in storage within the shale and the degree of
fracturing of the host rocks.
Recent geologic mapping in Connecticut shows that the rock units in some
parts of the Connecticut Valley are highly fractured and faulted with minor
offsets (M. Thomas, email communication, 12/3/12). Accordingly, drilling targets would be
difficult to site because of the structural discontinuities in the rock (such
as naturally occurring fractures and extinct faults) potentially limiting the
sustainability of any production.
12.
What is the
Hartford Basin?
The Connecticut valley originated as a
rift basin where the Earth’s crust began to pull apart during the opening of
the modern Atlantic Ocean in the Triassic and Jurassic periods (ie., geologic periods of time) about 220 million years
ago. The rifting was part of the
breakup of the supercontinent Pangea. Rifting creates a topographic lowland,
or basin, into which sediments from the surrounding highlands are deposited (Fig. 4).
These sediments can accumulate to great thicknesses depending on how fast
the basin subsides. It is estimated
that the depth of the Connecticut Valley rift basin is 13,000 to 16,000 feet. Locally drainage was impeded to allow a
variety of shallow lakes to form as the basin subsided.
13.
Where is the
Hartford Basin?
The rift basin extends from the Vermont
border almost to the Connecticut shoreline generally parallel with the
Connecticut River. The basin can be
divided into two parts using an east west imaginary line through the town of
Amherst as the dividing line. North
of Amherst (north of the Holyoke Range) the basin is referred to as the
Deerfield basin, south of Amherst (including the Holyoke Range) it is called
the Hartford basin. In
Massachusetts, the Hartford basin is approximately 15 miles wide and 19 miles
long whereas the Deerfield basin averages 3 miles wide by 15 miles long (Figs. 5 and Fig. 6).
14.
Where are the
organic rich black shales within the Hartford and
Deerfield Basins?
The table below lists the rock
formations that are found in the Hartford and Deerfield basins and their
respective thicknesses. An asterisk
next to the formation name means the rock formation contains black shale beds
within the unit. These thicknesses
are for the entire formation and are NOT
the thicknesses of the black shales within that
formation.
Hartford Basin
(oldest unit on bottom to youngest on top) |
Approx. Thickness (ft) |
Deerfield Basin
(oldest unit on bottom to youngest on top) |
Approx. Thickness (ft) |
Portland Formation* |
8000 |
Mount Toby Conglomerate/ |
1000 |
Hampden Basalt |
300 |
Turners Falls Formation* |
6560 |
East Berlin Formation* |
550 |
Deerfield Basalt |
330 |
Holyoke Basalt |
300 |
Fall River Beds* |
30 |
Shuttle Meadow Formation* |
450 |
Sugarloaf Arkose |
5600 |
Talcott Basalt |
300 |
|
|
New Haven Arkose |
6000 |
|
|
The black shales
formed in temporary non-saline, somewhat anoxic lakes with very poor
circulation allowing the accumulation of organic matter with the sediment (Fig. 7). The
lakes formed during rapid extension and subsidence of the basin in the lower
Jurassic period. The organic
material was derived from a mixture of algae, woody plant debris and some soil
organic matter (Spiker et al., 1988).
15.
Is there any evidence
that shale gas can be produced from any of the black shales
in the Hartford and Deerfield Basins?
No oil or gas wells have been drilled
to test any of the strata within the Hartford and Deerfield Basins. Therefore, there is no direct evidence
that oil or gas can or cannot be produced here. However, outcrop samples have been
examined, which may illuminate the petroleum potential of the black shales within the basins. Some samples from the Portland Formation
in the Hartford basin indicate that the rocks locally are thermally immature
meaning subsurface temperatures did not rise high enough and the thermal
maturation needed for effective petroleum generation was not achieved (Pratt et
al., 1988). The black shales in the Shuttle Meadow
and East Berlin Formations did fall in places within peak conditions for
petroleum generation (Pratt et al., 1988; Hubert et al., 1992) and are located
in the southeast portion of the Hartford basin underlying Massachusetts (Holyoke,
Springfield and Longmeadow) south and east of the Holyoke Range (Fig. 3) .
However these units are thin, laterally discontinuous and
fractured. Samples from the black shales in the Deerfield Basin north of the Holyoke Range
have experienced several episodes of hydrothermal alteration (Hubert et al.,
1992; 2001) and thus are thermally overmature and probably
not a commercial source for shale gas.
16.
What is
hydraulic fracturing?
Hydraulic fracturing, also known as fracking, involves a borehole or well that has been drilled
into the subsurface to reach a targeted formation, and then the pumping of a
fracturing fluid into that formation at a calculated, predetermined rate and
pressure in order to crack the rock and create artificial fractures in the
target formation. Hydraulic
fracturing well completions typically use water or water-based fluids as the
fracture fluids, mixed with a small amount of various additives (see below). Sand is also added to the mixture as a proppant (meaning to prop open), which is needed to prop
open the fractures once the fracturing process has stopped.
17.
What is
different about shales and why are they hydraulically
fractured?
All low porosity and permeability
potential reservoir rocks require hydraulic fracture stimulations. The permeability of a typical shale
(ability of fluids to move freely through the material) is very low (often
termed ultra low), which means that hydrocarbons are effectively trapped within
the shale and unable to flow under normal circumstances, and usually only
migrate out of the shale as it is compacted over geologic time. In order to increase the permeability of
the shale so that the tightly bound hydrocarbons can be released and extracted by
a production well, the formation is artificially stimulated by hydraulic fracturing. Hydraulic fracturing expands the width
of narrow, naturally-existing fractures in the rock and creates new ones. Overall this increases the permeability
of the shale in the vicinity of a gas well. Only then can the residual gas in the shale
be accessible for extraction.
18.
How is shale
gas accessed?
Shale gas is accessed by drilling a
production well into the black shale formation from the ground surface. The drilling pad consists of a drill rig
with a derrick, chemical storage tanks, sand and hydraulic fracturing fluid
storage tanks, pumps, and monitoring van, settling ponds and wastewater
retention ponds, among other things.
Each drilling pad may have from 2 to 15 wellheads each targeting the
same shale unit. Pads might be 5 to
7 acres in size during drilling but are reduced in size once drilling is
completed and production begins (King, 2012). http://www.kgs.ku.edu/PRS/Fracturing/Frac_Paper_SPE_152596.pdf
The
process begins by drilling a vertical hole and running jointed casing into the
hole. The depth of the initial vertical
hole depends on how deep it is to the deepest fresh water aquifer. Cement is
then pumped down the casing which then flows up the annulus (space between the
casing and the surrounding rock) sealing and separating the well bore from the
surrounding environment. This
casing is set several hundred feet below the deepest freshwater aquifer and is
pressure tested and logged to determine the integrity of the cement bond. The
integrity of the cement job is the key to preventing methane and water from
lower shale formations under high pressure from moving up the annulus to the
surface where it can contaminate shallow aquifers or reach the surface (King,
2012). For more information about
cementing wells see Nelson (1990).
After
the first casing is set and tested, a smaller drill bit is inserted into the
well bore and the hole advanced to the target shale. There may be multiple strings of casing
nested inside one another, each casing string being successively smaller in
diameter. Once the vertical hole
reaches the target depth the well may be turned in a direction parallel with
the producing shale bed. This may
be horizontal or slightly inclined depending on the attitude of the bed. The
length of the horizontal section of the well may vary from 1000 to 6000 feet in
length, sometimes longer. The time
needed to complete the entire drilling operation is usually 1 month to several
months depending on the number of wells (King, 2012).
Once
the horizontal portion of the well is drilled, cased and sealed specialized
equipment is used to isolate a portion of the borehole and perforate the casing
creating a connection between the shale formation and the pipe. The hydraulic fracturing fluid containing
water and sand is then pumped into the isolated section of the perforated
casing and shot into the shale formation creating hundreds of minute cracks
that can sometimes propagate a couple of hundred of feet away from the
borehole. The sand then fills the
cracks; holding them open and allowing the gas to flow freely into the pipe and
to the surface. Hydraulic
fracturing is conducted in stages and each stage may last from 20 minutes to up
to 4 hours (King, 2012).
An
overview of the drilling and fracking process can be
found at:
http://news.nationalgeographic.com/news/2010/10/101022-breaking-fuel-from-the-rock/
19.
What is in the hydraulic fracturing fluid?
The hydraulic fracturing fluid is 90%
water, 9.5% sand (silica sand) and 0.5% additives. The additives include: 1) acids to help dissolve minerals and
initiate pre-fracture of the rock; 2) sodium chloride (table salt) to allow
delayed breakdown of gel polymer chains; 3) polyacrylamide (friction reducer) to
minimize friction between the fluid and the pipe; 4) ethylene glycol (scale
inhibitors) to prevent mineral deposits in the pipe; 5) borate salts for
maintaining fluid viscosity as the temperature increases with depth; 6) sodium
and potassium carbonate for pH control; 7) Glutaraldehyde
(biocide disinfectant) to control bacteria in the water; 8) Guar Gum (gel
polymers) to thicken the fluid so the sand can stay suspended; 9) citric acid (iron
control) to prevent the precipitation of metal oxides; and, 10) isopropanol (surfactant)
to increase the viscosity of the fracking fluid. Variations of these 10 components
include 29 different chemicals in 652 different products and can include such
substances as xylene, benzene, and toluene, among others. The proportion of these additives and
the specific products used by drillers varies depending on the depth, type of
formation and other geologic factors. For more details on the quantities and
types of additives see (King, 2012, p.8; Whittemore,
2011)
http://www.kgs.ku.edu/PRS/Fracturing/Frac_Paper_SPE_152596.pdf
20.
Are any of
these additives dangerous?
Yes. A report listing the chemicals used in
hydraulic fracturing was prepared by the House of Representatives, Committee on
Energy and Commerce, Minority staff in April 2011. It is available at: http://democrats.energycommerce.house.gov/sites/default/files/documents/Hydraulic%20Fracturing%20Report%204.18.11.pdf
The report lists 29 chemicals in 652
different products that are: 1) known or possible human carcinogens; 2)
regulated under the Safe Drinking Water Act for their risks to human health;
or, 3) listed as hazardous air pollutants under the Clean Air Act.
21.
Is reporting required
for chemicals used as additives to the hydraulic fracturing fluid?
No. However, the range of chemicals
used is well known. What is
uncertain are the specifics about which products are used and in what
proportion at a given drill pad. Several
states are now requiring companies to disclose what chemicals they are using. States that have developed or are developing
disclosure laws include Arkansas, Colorado, Idaho, Montana, New Mexico, North
Dakota, Pennsylvania, Texas, West Virginia, and Wyoming (http://fracfocus.org/chemical-use/chemicals-public-disclosure). Further, the Ground Water Protection
Council and Interstate Oil and Gas Compact Commission have developed a registry
and database where industry can voluntarily submit to the database information
about their shale gas wells, including the chemicals used for fracking. The database has 33,277 wells registered as of December
6, 2012. The site is available to
the public at: http://fracfocus.org/
22.
How much water
is used during a typical hydraulic fracturing operation?
Water is needed during the drilling
operation to cool the bit and mix with drilling mud, which holds the hole open
while drilling, and it is also used as the primary component of the hydraulic
fracturing fluid. The actual quantity
of water used depends on the well depth, formation and pressure needed in the fracking process.
The amount of water needed to drill a well can be as little as 420,000
gallons up to 1 million gallons.
The hydraulic fracturing process may use as little as 42,000 gallons to
as much as 2.49 million gallons of water, sometimes more. Commonly 2-8 million gallons of water
are used for each Marcellus horizontal well. At one time, this was a one-time use of
the water. Now, however, companies
are recycling and reusing their fracture fluid through several wells. King (2012, p.40) provides some typical
water usage figures for drilling and hydraulic fracturing operations in some of
the major shale gas plays in the U.S. http://www.kgs.ku.edu/PRS/Fracturing/Frac_Paper_SPE_152596.pdf
Assuming a total of 3.49 million
gallons for drilling and hydraulic fracturing a single well, that is equivalent
to:
·
1.2 days of water usage for the Town of Amherst, MA
·
Covering the entire town of Amherst, MA (27 square miles)
with 0.2 mm of rain (0.00725 inches).
23.
Is there a
fluid byproduct produced from the drilling and fracking
operation?
Yes. After the fracking
process is completed some of the hydraulic fracturing fluid is absorbed or lost
to the formation and some of it returns up the well bore to the surface (called
flowback) because the subsurface is overpressured during hydraulic fracturing. This
overpressure forces some of the fluids up the borehole. Flowback of hydraulic
fracturing fluids during the first two to three weeks after hydraulic
fracturing ceases may produce 125 to 250 gallons per minute, for a few hours,
dropping to 29 gallons per minute within 24 hours and then quickly decreasing
during the next 2 to 3 weeks (King, 2012).
For more information on hydraulic fracturing fluid see:
http://www.kgs.ku.edu/Publications/PIC/pic32.html
http://www.kgs.ku.edu/Hydro/Publications/2012/Fracturing/index.html
http://www.kgs.ku.edu/PRS/Fracturing/Frac_Paper_SPE_152596.pdf
http://www.pacinst.org/reports/fracking/full_report.pdf
24.
What is the
history of hydraulic fracturing?
“Horizontal wells and hydraulic
fracturing are not new tools for the oil and gas industry. The first fracturing experiment was in
1947 and the process was accepted commercially by 1950. The first horizontal well was in the
1930s and horizontal wells were common by the late 1970s” (King, 2012, p.2). It is estimated by the Society of
Petroleum Engineers that over 1 million hydraulically fractured wells have been
completed in the U.S. and over 2.5 million world-wide (King, 2012, p.2). Over 550 papers have been published on
the subject of shale fracturing and another 3000 on horizontal well technology
and cover nearly 30 plus years of development in shale technology (King, 2012,
p.2).
25.
Are there environmental
risks associated with hydraulic fracturing?
Yes. Any major drilling or industrial
operation has risks. Potential
contamination of fresh groundwater, water consumption, earthquakes triggered by
injecting fluids, venting or flaring of methane and disposal of fluids are
common environmental concerns associated with hydraulic fracturing, drilling and
production operations. For more
information on the risks and safeguards see:
http://www.kgs.ku.edu/Hydro/Publications/2012/Fracturing/index.html
http://www.kgs.ku.edu/PRS/Fracturing/Frac_Paper_SPE_152596.pdf
http://www.pacinst.org/reports/fracking/full_report.pdf
http://www.kgs.ku.edu/PRS/Fracturing/Hydraulic_Fracturing_brochure_1_FINAL.pdf
http://www.shalegas.energy.gov/resources/111811_final_report.pdf
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and Olsen, P.E. 1988. Source of
kerogen in black shales
from the Hartford and Newark basins, eastern United States, in Froelich, A.J. and Robinson, G.R., eds., Studies of the
Early Mesozoic Basins of the Eastern United States. U.S. Geological Survey
Bulletin 1776, pp.63-68.
Taylor, J.M.
1991. Diagenesis of sandstones in the early Mesozoic Deerfield basin,
Massachusetts. M.S. Thesis: Department of Geosciences, University of
Massachusetts, Amherst, 225p.
Walsh, M.P.
2008. Petrology
and provenance of the Triassic Sugarloaf arkose,
Deerfield basin, Massachusetts. M.S. Thesis: Department of Geosciences,
University of Massachusetts, Amherst, 261p.
Whittemore, D.O. 2011. Water quality and hydraulic fracturing. Kansas Geological
Survey Note, November 3, 2011 (http://www.kgs.ku.edu/Hydro/Publications/2012/Fracturing/index.html)
Other
useful links about shale gas and hydraulic fracturing
·
General information describing the geology and hydrocarbon
potential of the Mesozoic rift basins along the eastern seaboard of the U.S.
http://pubs.usgs.gov/bul/1776/report.pdf
·
Evolution, sandstone diagenesis and hydrocarbon history of the Triassic-Jurassic Hartford rift basin in Connecticut and Massachusetts
Hubert et al., 1992 (awaiting copyright permission)
·
Burial and hydrothermal diagenesis of the sandstones in the early Mesozoic Deerfield rift basin, Massachusetts
·
Public information circular on hydraulic fracturing prepared
by the Kansas Geological Survey
http://www.kgs.ku.edu/Publications/PIC/pic32.html
·
Water quality and hydraulic fracturing
http://www.kgs.ku.edu/Hydro/Publications/2012/Fracturing/index.html
·
Hydraulic Fracturing 101 – a recent comprehensive
summary with many references
http://www.kgs.ku.edu/PRS/Fracturing/Frac_Paper_SPE_152596.pdf
·
Report on hydraulic fracturing and water resources from the
Pacific Institute
http://www.pacinst.org/reports/fracking/full_report.pdf
·
Hydraulic fracturing in proximity to water wells –
what homeowners should know
http://www.kgs.ku.edu/PRS/Fracturing/Hydraulic_Fracturing_brochure_1_FINAL.pdf
·
Association of American State Geologists position paper on
Hydraulic Fracturing
http://www.kgs.ku.edu/PRS/Fracturing/AASG_Hydraulic_Fracturing_statement.pdf
·
National Ground Water Association position paper on
Hydraulic Fracturing
http://www.kgs.ku.edu/PRS/Fracturing/rpt_hydraulic-fracturing-position-paper_NGWA.pdf
·
FracFocus, a database
of oil and gas wells with full disclosures
·
Department of Energy paper on improving safety and
environmental performance of hydraulic fracturing
http://www.shalegas.energy.gov/resources/111811_final_report.pdf
·
From the National Academy of Sciences – induced
seismicity from hydraulic fracturing
·
Duke University study on migration of deep brines to shallow
levels indicating that pathways capable of bringing deep brines to shallow
aquifers do exist and can be defined by geochemical signature (Note: the
connections described in this paper are not related to any drilling activities)
http://sites.nicholas.duke.edu/avnervengosh/files/2011/08/PNAS-2012-Warner-1121181109.pdf