U.S. Department of the Interior

U.S. Geological Survey

Fact Sheet 2009–3032

May 2009

Water Resources and Natural Gas Production from 

the Marcellus Shale

Printed on recycled paper

By Daniel J. Soeder1 and William M. Kappel2

Introduction

The Marcellus Shale is a 

sedimentary rock formation 

deposited over 350 million years ago 

in a shallow inland sea located in 

the eastern United States where the 

present-day Appalachian Mountains 

now stand (de Witt and others, 1993). 

This shale contains significant 

quantities of natural gas. New developments in drilling technology, along 

with higher wellhead prices, have 

made the Marcellus Shale an important 

natural gas resource. 

The Marcellus Shale extends 

from southern New York across 

Pennsylvania, and into western 

Maryland, West Virginia, and eastern 

Ohio (fig. 1). The production of commercial quantities of gas from this 

shale requires large volumes of water 

to drill and hydraulically fracture the 

rock. This water must be recovered 

from the well and disposed of before 

the gas can flow. Concerns about the 

availability of water supplies needed 

for gas production, and questions 

about wastewater disposal have been 

raised by water-resource agencies 

and citizens throughout the Marcellus 

Shale gas development region. This 

Fact Sheet explains the basics of 

Marcellus Shale gas production, with 

the intent of helping the reader better 

understand the framework of the 

water-resource questions and concerns.

What is the Marcellus Shale?

The Marcellus Shale forms 

the bottom or basal part of a thick 

sequence of Devonian age, 

sedimentary rocks in the Appalachian 

Basin. This sediment was deposited 

by an ancient river delta, the remains 

of which now form the Catskill 

Mountains in New 

York (Schwietering, 

1979). The basin 

floor subsided under 

the weight of the 

sediment, resulting 

in a wedge-shaped 

deposit (fig. 2) that 

is thicker in the 

east and thins to the 

west. The eastern, 

thicker part of the 

sediment wedge 

is composed of 

sandstone, siltstone, 

and shale (Potter 

and others, 1980), 

whereas the thinner 

sediments to the 

west consist of finergrained, organicrich black shale, 

interbedded with 

organic-lean gray 

shale. The Marcellus 

Shale was deposited 

as an organic-rich 

mud across the 

Appalachian Basin 

before the influx of 

the majority of the 

younger Devonian 

sediments, and was 

buried beneath them. 

Why is the Marcellus Shale an 

Important Gas Resource? 

Organic matter deposited with 

the Marcellus Shale was compressed 

and heated deep within the Earth over 

geologic time, forming hydrocarbons, 

including natural gas. The gas occurs 

in fractures, in the pore spaces 

1

U.S. Geological Survey, MD-DE-DC Water 

Science Center, 5522 Research Park Drive, 

Baltimore, MD 21228

2U.S. Geological Survey, New York Water 

Science Center, 30 Brown Road, Ithaca, NY 14850

Figure 1. Distribution of the Marcellus Shale (modified from 

Milici and Swezey, 2006).
between individual mineral grains, and 

is chemically adsorbed onto organic 

matter within the shale (Soeder, 1988). 

To produce commercial amounts of 

natural gas from such fine-grained 

rock, higher permeability flowpaths 

must be intercepted or created in the 

formation. This is generally done using 

a technique called hydraulic fracturing 

or a “hydrofrac,” where water under 

high pressure forms fractures in the 

rock, which are propped open by sand 

or other materials to provide pathways 

for gas to move to the well. Petroleum 

engineers refer to this fracturing 

process as “stimulation.”

From the mid-1970s to early 

1980s, the U.S. Department of Energy 

(DOE) funded the Eastern Gas Shales 

Project (EGSP) to develop new technology in partnership with industry 

that would advance the commercial 

development of Devonian shale gas 

(Schrider and Wise, 1980). Goals of 

the project included assessing the size 

of the resource, estimating recoverable 

gas, and determining the most effective technology for gas extraction. The 

EGSP shale stimulation experiments 

tested a wide variety 

of hydrofracs and 

other techniques. 

Results were somewhat uneven, and 

DOE concluded 

that stimulation 

alone was generally insufficient to 

achieve commercial 

shale gas production 

(Horton, 1982). It 

was suggested that 

better success could 

be obtained by targeting specific formations in specific 

locations. The EGSP 

results did indicate 

that if the hydraulic 

fractures were able 

to intercept sets of existing, natural 

fractures within the shale (fig. 3), a 

network of flowpaths could be 

created.

2 Water Resources and Natural Gas Production from the Marcellus Shale

Figure 2. West to east line of section A-A’ of Middle and Upper Devonian rocks in the Appalachian Basin. The Marcellus Shale is the 

lowest unit in the sequence (modified from Potter and others, 1980).

Figure 3. Marcellus Shale drill core from West Virginia, 3.5 

inches in diameter, containing a calcite-filled vertical natural 

fracture. Photograph by Daniel Soeder, USGS.
In the mid-1980s, the Institute of 

Gas Technology (IGT) in Chicago performed some laboratory analyses on 

EGSP shale samples (Soeder, 1988). 

Published IGT lab measurements 

found that a “gas-in-place” value for 

the Marcellus Shale at pressures representative of production depths may 

be as high as 26.5 standard cubic feet 

of gas per cubic foot of rock (Soeder, 

1988). This greatly exceeded earlier 

gas-in-place estimates for Devonian 

shale by the National Petroleum 

Council (1980), which ranged from 

0.1 to 0.6 standard cubic feet of gas 

per cubic foot of rock. Although IGT 

analyzed only one sample of Marcellus 

Shale, the large volumes of gas now 

being produced from this formation 

substantiate the early discovery of 

significant gas reserves. 

In 2008, two professors 

at Pennsylvania State University and 

the State University of New York 

(SUNY) Fredonia estimated that about 

50 TCF (trillion cubic feet) of recoverable natural gas could be extracted 

from the Marcellus Shale (Engelder 

and Lash, 2008). In November 2008, 

on the basis of production information 

from Chesapeake Energy Corporation, 

the estimate of recoverable gas from 

the Marcellus Shale was raised to 

more than 363 TCF (Esch, 2008). 

The United States uses about 23 TCF 

of natural gas per year (U.S. Energy 

Information Administration, 2009), 

so the Marcellus gas resource may be 

large enough to supply the needs of the 

entire Nation for roughly 15 years at 

the current rates of consumption.

Why is the Marcellus Shale 

Being Developed Now?

Low prices for natural gas, and 

ineffective production technology did 

little to spark interest in Devonian 

shale gas in the 1990s, despite the 

publication of the IGT Marcellus 

gas-in-place estimates. Two factors 

working together have promoted the 

current high levels of interest in the 

Marcellus Shale. First, wellhead prices 

for gas have risen from values of less 

than $2.00 per MCF (thousand cubic 

feet) in the 1980s (fig. 4) to a peak 

of $10.82 per MCF in the summer 

of 2008 (U.S. Energy Information 

Administration, 

2009). Although 

prices had declined 

to $5.15 per MCF in 

January 2009 due to 

the economic downturn, they are still 

substantially higher 

than a decade earlier. 

The second 

factor that spurred 

interest in the 

development of the 

Marcellus Shale is a 

new application of 

an existing drilling 

technology known 

as directional drilling, which involves 

steering a downhole 

drill bit in a direction 

other than vertical. 

An initially vertical 

drillhole is slowly 

turned 90 degrees to penetrate long 

horizontal distances, sometimes over 

a mile, through the Marcellus Shale 

bedrock. Hydraulic fractures are then 

created into the rock at intervals from 

the horizontal section of the borehole, 

allowing a substantial number of 

high-permeability pathways to contact 

a large volume of rock (fig. 5). 

According to Range Resources (2008), 

one of the first major horizontal drillers of Marcellus Shale, these wells 

typically produce gas at a rate of about 

4 MMCF (million cubic feet) per day. 

Over its lifetime, each horizontal well 

on an 80-acre surface spacing can be 

expected to produce a total of about 

2.5 BCF (billion cubic feet) of gas at 

an estimated production cost of $1.00 

per MCF (Chernoff, 2008).

What are the Water-Resource 

Concerns About Developing 

Natural Gas Wells in the 

Marcellus Shale?

Substantial amounts of water are 

required for the drilling and stimulation of a Marcellus Shale gas well. 

Fluids recovered from the well, including the liquids used for the hydrofrac, 

and any produced formation brines, 

must be treated and disposed of properly. Three important water-resource 

3 Water Resources and Natural Gas Production from the Marcellus Shale

Figure 4. Wellhead price of natural gas since the mid-1970s to January 2009. [Source 

U.S. Energy Information Administration, 2009.]

Figure 5. Combination of directional drilling and hydraulic 

fracturing technology used for gas production from the 

Marcellus Shale in the Appalachian Basin (modified from 

http://geology.com/articles/marcellus-shale.shtml).
concerns related to Marcellus Shale 

gas production are: 

• supplying water for well construction without impacting local water 

resources,

• avoiding degradation of small 

watersheds and streams as substantial amounts of heavy equipment and supplies are moved 

around on rural roads, and 

• determining the proper methods 

for the safe disposal of the large 

quantities of potentially contaminated fluids recovered from the 

wells.

These concerns are discussed in 

more detail in the following sections.

Water Supply 

Drilling requires large amounts 

of water to create a circulating mud 

that cools the bit and carries the rock 

cuttings out of the borehole. After 

drilling, the shale formation is then 

stimulated by hydraulic fracturing, 

which may require up to 3 million 

gallons of water per treatment (Harper, 

2008). Many regional and local water 

management agencies are concerned 

about where such large volumes of 

water will be obtained, and what the 

possible consequences might be for 

local water supplies. Under drought 

conditions, or in locations with already 

stressed water supplies, obtaining the 

millions of gallons needed for a shale 

gas well could be problematic. Drillers 

could face substantial transportation 

costs if the water has to be trucked in 

from great distances.

Similar shale gas operations in the 

Barnett Shale of Texas have obtained 

hydrofrac water largely from groundwater sources (Byrd, 2007). Watersupply concerns over the Barnett Shale 

drilling have been brought up in the 

past (see, for example, Francis, 2007). 

Texas State and County agencies now 

closely monitor volumes of water used 

during drilling, and a consortium of 

Barnett Shale drilling companies have 

developed best management practices 

for water conservation, with the goal 

of keeping the pace of drilling and 

production activities within the bounds 

of sustainable water use. Similar steps 

have been discussed in Marcellus 

Shale gas production areas, but not yet 

fully implemented. 

Transporting Fluids and Supplies 

Large hydrofrac treatments often 

involve moving large amounts of 

equipment, vehicles, and supplies into 

remote areas (fig. 6). Transporting 

all of this to drill sites over rural 

Appalachian Mountain roads could 

potentially cause erosion, and threaten 

local small watersheds with sediment. 

Drill pad and pipeline construction 

also have the potential to cause similar 

problems. Of equal concern is the 

possibility for spills or leaks into water 

bodies as the fluids and chemical 

additives are transported and handled. 

Little is known about how a Marcellus 

Shale drilling “boom” might adversely 

affect the land, streams, and available 

water supplies in the Appalachian 

Basin. Even under current Marcellus 

gas production levels, complaints of 

rural road damage and traffic disruption from drilling equipment have been 

received, indicating that this could be 

a significant problem if carried out 

across thousands of active drill sites.

Wastewater Disposal 

For gas to flow out of the shale, 

nearly all of the water injected into the 

well during the hydrofrac treatment 

must be recovered and disposed of. In 

addition to the problem of dealing with 

large bulk volumes of liquid waste, 

contaminants in the water may complicate wastewater treatment. Whereas 

the percentage of chemical additives in 

a typical hydrofrac fluid is commonly 

less than 0.5 percent by volume, the 

quantity of fluid used in these hydrofracs is so large that the additives in a 

three million gallon hydrofrac job, for 

example, would result in about 15,000 

gallons of chemicals in the waste. 

Hydrofrac fluids are often treated 

with proprietary chemicals to increase 

the viscosity to a gel-like consistency 

that enables the transport of a 

proppant, usually sand, into the fracture to keep it open after the pressure 

is released (fig. 7). The viscosity of 

these fluids then breaks down quickly 

after completion of the hydrofrac, so 

4 Water Resources and Natural Gas Production from the Marcellus Shale

Figure 6. A hydraulic fracturing stimulation in 2007 on a Marcellus Shale gas well showing 

the amount of equipment involved.
5 Water Resources and Natural Gas Production from the Marcellus Shale

they can be easily removed from the 

ground. The chemical formulations 

required to achieve this are highly 

researched and closely guarded, and 

finding out exactly what is in these 

fluids may present a challenge. The 

data publicly available on Marcellus 

Shale hydrofrac treatments indicate 

that a slickwater frac works best on 

this formation (Harper, 2008). These 

types of hydrofracs employ linear gels 

and friction reducers in the water, and 

utilize only small amounts of proppant, 

relying instead on fracture surface 

roughness to hold it open (Rushing 

and Sullivan, 2007). The potential 

problems for local wastewater treatment facilities caused by proprietary 

chemical additives in hydrofrac fluid 

are unclear.

Along with the introduced 

chemicals, hydrofrac water is in close 

contact with the rock during the course 

of the stimulation treatment, and when 

recovered may contain a variety of 

formation materials, including brines, 

heavy metals, radionuclides, and 

organics that can make wastewater 

treatment difficult and expensive. The 

formation brines often contain relatively high concentrations of sodium, 

chloride, bromide, and other inorganic 

constituents, such as arsenic, barium, 

other heavy metals, and radionuclides 

that significantly exceed drinkingwater standards (Harper, 2008). 

The current disposal practice 

for Marcellus Shale liquids in 

Pennsylvania requires processing them 

through wastewater treatment plants, 

but the effectiveness of standard 

wastewater treatments on these fluids 

is not well understood. In particular, 

salts and other dissolved solids in 

brines are not usually removed successfully by wastewater treatment, 

and reports of high salinity in some 

Appalachian rivers have been linked to 

the disposal of Marcellus Shale brines 

(Water and Wastes Digest, 2008). 

Another disposal option involves 

re-injecting the hydrofrac fluids 

back into the ground at a shallower 

depth. This is a common practice in 

the Barnett Shale production area 

of Texas, and has been utilized for 

some Marcellus wells drilled in West 

Virginia (Kasey, 2008). Concerns 

in Appalachian States about the 

possible contamination of drinkingwater supply aquifers has limited the 

practice of re-injecting Marcellus 

fluids, however. Another option might 

be to inject the waste fluid into deeper 

formations below the Marcellus Shale 

that are not used as aquifers, such as 

Figure 7. Example of a gel used in hydrofracturing to carry proppant into a fracture. 

Photograph by Daniel Soeder, USGS.

the Oriskany or Potsdam Sandstones. 

A third disposal process used in Texas 

places the wastewater into an open 

tank to evaporate. The solids that 

remain behind are then disposed of as 

dry waste. Although this may be an 

effective technique in the deserts of the 

American Southwest, its usefulness in 

the humid climate of the Appalachians 

is questionable. A systematic study of 

the options for Marcellus Shale waste 

fluid treatment, disposal, or recycling 

could help to determine the best available procedures.

Summary

Natural gas is an abundant, 

domestic energy resource that burns 

cleanly, and emits the lowest amount 

of carbon dioxide per calorie of any 

fossil fuel. The Marcellus Shale 

and other natural gas resources in 

the United States are important 

components of a national energy 

program that seeks both greater energy 

independence and greener sources of 

energy. Marcellus gas development 

has begun in the northern Appalachian 

Basin, with significant lease holdings 

throughout Pennsylvania, West 

Virginia, southern New York, western 

Maryland, and eastern Ohio. Because 

of questions related to water supply 

and wastewater disposal, however, 

many state agencies have been 

cautious about granting permits, and 

some states have placed moratoriums 

on drilling until these issues are 

resolved. At the same time, gas 

companies, drillers, and landowners 

are eager to move forward and develop 

the resource. 

While the technology of drilling 

directional boreholes, and the use of 

sophisticated hydraulic fracturing 

processes to extract gas resources 

from tight rock have improved over 

the past few decades, the knowledge 

of how this extraction might affect 

water resources has not kept pace. 

Agencies that manage and protect 

water resources could benefit from a 

better understanding of the impacts 

that drilling and stimulating Marcellus 

Shale wells might have on water 

supplies, and a clearer idea of the 

options for wastewater disposal. 
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seekingalpha.com/article/68716-

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Prepared by USGS West Trenton 

Publishing Service Center.

Edited by Valerie M. Gaine.

Graphics and design by Timothy W. Auer.

For additional information, contact:

Director, MD-DE-DC Water Science Center

U.S. Geological Survey

5522 Research Park Drive

Baltimore, MD 21228

or visit our Web site at: 

http://md.water.usgs.gov

Fact Sheet 2009–3032