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Sanitized Site Visit Report

Chesapeake Energy Corporation

Marcellus Shale Gas Operations

February 6, 2015
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TABLE OF CONTENTS

Page

1.0 INTRODUCTION ........................................................................................................ 1

2.0 BACKGROUND AND OBJECTIVES .............................................................................. 1

3.0 OVERVIEW OF SHALE GAS PRODUCTION ................................................................. 3

3.1 Unconventional and Conventional Resources............................................ 3

3.2 Chesapeake’s Oil and Natural Gas Activity ............................................... 4

3.3 Chesapeake’s Northern Marcellus Shale Development Strategy ............... 5

3.4 Well Pad Construction ................................................................................ 8

3.5 Drilling........................................................................................................ 8

3.6 Well Completion: Perforating and Hydraulic Fracturing ......................... 12

3.7 Production Phase....................................................................................... 15

4.0 CHESAPEAKE SITES VISITED .................................................................................. 16

4.1 Wysox Source Water Withdrawal Site ..................................................... 16

4.2 Freshwater Impoundment ......................................................................... 19

4.3 Well Construction and Drilling (Well: Gardner Nebra 1H) ..................... 20

4.4 Production (Wells: James Barrett 1H and 2H) ......................................... 24

4.5 Centralized Arnold Renew Treatment Facility......................................... 28

Appendix A – LIST OF PARTICIPANTS ON THE CHESAPEAKE SITE VISIT

Appendix B – INFORMATION PROVIDED BY CHESAPEAKE

Appendix C – MAP OF SITES VISITED

Appendix D – SUMMARY OF COSTS PROVIDED BY CHESAPEAKE

Appendix E – POWER POINT PRESENTATION OF ALL SITE VISIT PICTURES
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LIST OF FIGURES

Page

Figure 3-1. Top View of a Horizontal Well Pad..............................................................................6

Figure 3-2. Chesapeake Active Shale Gas Wells in Northern Pennsylvania...................................7

Figure 3-3. Side View of Cementing Process..................................................................................9

Figure 3-4. Top View of Well Casing ...........................................................................................10

Figure 3-5. Hydraulic Fracturing Process Flow Diagram..............................................................14

Figure 4-1. Wysox Source Water Withdrawal Site Flow Diagram ...............................................16

Figure 4-2. Remote Transmitter.....................................................................................................17

Figure 4-3. Main Source Water Pump Housing.............................................................................17

Figure 4-4. Freshwater Intake Storage Tanks................................................................................18

Figure 4-5. Tracking System at Truck Fill Station at Water Withdrawal Site ..............................19

Figure 4-6. Freshwater Impoundment............................................................................................20

Figure 4-7. Freshwater Loading Station ........................................................................................20

Figure 4-8. Chesapeake Drilling Site.............................................................................................21

Figure 4-9. Intermediate Casing Drill Bits ....................................................................................22

Figure 4-10. Drill Pipe for Curved Portion of Well.......................................................................22

Figure 4-11. Drilling Site Flow Diagram.......................................................................................24

Figure 4-12. Production Site Flow Diagram..................................................................................25

Figure 4-13. Wellheads of James Barrett 1H and 2H ....................................................................26

Figure 4-14. Solar-Powered Methanol Tank and Injector .............................................................26

Figure 4-15. Water/Gas Separators (Right) and GPUs (Left)........................................................26

Figure 4-16. Produced Water Storage Tanks.................................................................................27

Figure 4-17. Flow Diagram of Chesapeake’s Arnold Treatment Facility .....................................29

Figure 4-18. Top View of Chesapeake’s Centralized Arnold Treatment Facility.........................30

Figure C-1. Overview of Sites Visited in ArcGIS .......................................................................C-1
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LIST OF TABLES

Page

Table 2-1. Chesapeake's Shale Gas Wastewater Management Practices in Pennsylvania (January 

1, 2010 through June 30, 2012) ...............................................................................2

Table 2-2. Statewide Shale Gas Wastewater Management Practices in Pennsylvania (January 1, 

2010 through June 30, 2012) ...................................................................................2

Table 3-1. Number of Wells in the United States Over Time .........................................................4

Table 3-2. Chesapeake’s Active Shale Gas Wells in Pennsylvania by County through June 20127

Table 3-3. Well Casing Information ..............................................................................................10

Table 4-1. James Barrett 1H Production Data ...............................................................................27

Table 4-2. James Barrett 2H Production Data ...............................................................................28

Table A-1. List of Attendees....................................................................................................... A-1

Table D-1. Summary of Costs Provided by Chesapeake ............................................................ D-1
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1.0 INTRODUCTION

On May 9, 2012, the U.S. Environmental Protection Agency (EPA) met with Chesapeake 

Energy Corporation (Chesapeake) and visited five sites in the Marcellus Shale Play in northern 

Pennsylvania. Appendix C includes a map of each site in the order it was visited, starting with 

Chesapeake’s Towanda, Pennsylvania office. These sites included:

 Gardner Nebra well 1H (drilling);

 Freshwater impoundment;

 James Barrett wells 1H and 2H (production);

 Arnold Treatment Facility; and

 Source water withdrawal site.

Meeting participants are listed below. Contact information is included in Appendix A.

U.S. EPA Office of Water, Office of Science and Technology Engineering and Analysis 

Division

Brian Damico

Lisa Biddle

Jan Matuszko

Cuc Schroeder

Erik Helm

Richard Witt

Eastern Research Group, Inc (ERG) (EPA Contractor)

Meghan Camp

Brent Ruminski

Chesapeake Energy, Inc

Troy Jordan

Jennifer Hoffman

Jimmie Hammontree

Brian Grove

2.0 BACKGROUND AND OBJECTIVES

The Chesapeake Marcellus Shale site visit was the first in a series of site visits that the 

EPA plans for this industry. During the visits, the EPA plans to view a range of shale gas 

operations that demonstrate a variety of production and wastewater management options,

including reuse, underground injection, centralized waste treatment, and publicly owned 

treatment works. The EPA intends to conduct several site visits in the Marcellus Shale Play
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because shale gas activity is high and underground injection capacity is limited for flowback1

and produced waters.

The purpose of the site visit was to collect background information on the shale gas 

industry and observe wastewater management practices. To initiate site visits, the EPA reviewed

information about Marcellus shale gas producers and their wastewater management practices.

During this review, the EPA identified Chesapeake as the most active producer in the Marcellus 

in terms of number of wells and gas production. In addition, Chesapeake’s wastewater 

management practices differ from some other gas producers in the state. According to the 

Pennsylvania Department of Environmental Protection’s (PA DEP’s) oil and gas reporting data, 

Chesapeake managed 94 to 97 percent of its wastewater through reuse between 2010 and June 

2012 compared to 21 to 75 percent statewide (PA DEP, 2012). Table 2-1 and Table 2-2 provide

an overview of Chesapeake’s shale gas wastewater management practices and statewide shale 

gas wastewater management practices in Pennsylvania.

Table 2-1. Chesapeake's Shale Gas Wastewater Management Practices in 

Pennsylvania (January 1, 2010 through June 30, 2012)

Management Practice

2010 2011 2012 (through June)

Volume 

(bbls) a

Percentage 

(%)

Volume 

(bbls) a

Percentage 

(%)

Volume 

(bbls) a

Percentage 

(%)

Reuse 425,651 94 1,424,516 98 1,252,791 97

Underground Injection 0 0 15,518 1 18,860 1

Centralized Waste Treatment 

(CWT) 15,596 3 9,205 1 22,251 2

Other (unknown) 11,321 3 6,640 0 0 0

Landfill 0 0 95 <1 0 0

Total 452,568 100 1,455,974 100 1,293,902 100

a—Wastewater volumes include produced water, flowback water, and drilling fluids.

b—Chesapeake hauled wastewater to HydroRevery, a CWT in Blossburg, PA that utilizes chemical 

precipitation, and Eureka Resources, a CWT in Williamsport, PA that utilizes chemical precipitation 

and/or evaporation/condensation.

Source: PA DEP’s Oil and Gas Reporting Database.

bbls—Barrels.

Table 2-2. Statewide Shale Gas Wastewater Management Practices in 

Pennsylvania (January 1, 2010 through June 30, 2012)

Management Practice

2010 2011 2012 (through June)

Volume 

(bbls) a

Percentage 

(%)

Volume 

(bbls) a

Percentage 

(%)

Volume 

(bbls) a

Percentage 

(%)

Reuse 3,608,599 21 11,139,323 55 7,954,321 75

Underground Injection 727,164 4 2,242,157 11 1,037,722 10

Centralized Waste Treatment 

(CWT) 10,760,972 62 6,311,394 31 1,511,531 14

 

1 Chesapeake refers to wastewater generated by the well during the flowback process (i.e., initial 30 to 90 days after 

fracturing) as initial produced water. However, this report refers to this wastewater as flowback water in order to 

stay consistent with literature and other EPA reports.
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Table 2-2. Statewide Shale Gas Wastewater Management Practices in 

Pennsylvania (January 1, 2010 through June 30, 2012)

Management Practice

2010 2011 2012 (through June)

Volume 

(bbls) a

Percentage 

(%)

Volume 

(bbls) a

Percentage 

(%)

Volume 

(bbls) a

Percentage 

(%)

Publicly Owned Treatment 

Works (POTW) 580,486 3 47,629 <1 0 0

Other (unknown) 1,480,481 9 50,221 0 0 0

Landfill 4,047 <1 28,184 <1 85,681 1

Road Spreading 783 0 0 0 0 0

Storage pending disposal or 

reuse 87,914 1 345,502 2 83,478 1

Total 17,250,445 100 20,164,411 100 10,672,734 100

a—Wastewater volumes include produced water, flowback water, and drilling fluids.

Source: PA DEP’s Oil and Gas Reporting Database.

bbls—Barrels.

During the site visit, the EPA collected general site information, including location, 

operator name, wastewater management practices, treatment methods, recordkeeping practices,

and economic information, such as descriptions of factors affecting decisions to develop a well, 

lease, or project.

Troy Jordan, a senior environmental specialist from Chesapeake, led the discussion of 

Chesapeake’s Marcellus operations and the site tour. The remainder of this report summarizes 

the site visit, including a general oil and gas industry discussion held with Chesapeake prior to 

going into the field (Section 3.0) and information provided by Chesapeake during the tour

(Section 4.0).

3.0 OVERVIEW OF SHALE GAS PRODUCTION

Prior to a tour of operations near Sayre, Pennsylvania, the EPA and Chesapeake 

discussed Chesapeake’s oil and gas operations at a regional office. Chesapeake provided a 

comprehensive overview of the oil and gas extraction process and its unconventional oil and gas 

operations, but the site tour focused on shale gas operations. Topics discussed include industry 

profile, process descriptions (i.e., freshwater withdrawal, water storage, well construction, 

production, and centralized treatment), general costs, and other information provided by 

Chesapeake.

3.1 Unconventional and Conventional Resources

Chesapeake defines unconventional resources as those found in formations that are 

resistant to economical flow without assistance from horizontal drilling, stimulation treatments, 

or special recovery processes.2 Currently, Chesapeake is mostly active in shale oil and shale gas 

plays. Chesapeake categorized unconventional resources into the following types:

 

2

Provided by Chesapeake on page 11 of Appendix B.
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 Heavy and very heavy oil (oil sands, tar sands, and very viscous oil);

 Oil shale;

 Shale oil;

 Shale gas;

 Tight gas; and

 Coalbed methane.

To illustrate how the oil and gas industry evolved in the United States, Chesapeake 

provided data shown in Table 3-1, taken from the National Petroleum Council (NPC).

3 However, 

NPC does not provide the underlying database or its origin. The data show that the total number 

of gas wells as a percentage of total wells increased from 17 percent in the period 1900 to 1924

to 43 percent in the period 2000 to 2011. As reported by NPC, there are more than 60,292 

horizontal wells drilled to date, including 30,006 horizontal gas wells and 30,286 horizontal oil 

wells. However, the NPC data did not include any information on how many of these horizontal 

wells are active or producing in unconventional formations. Chesapeake explained that the 

combination of horizontal drilling and hydraulic fracturing was developed in the Barnett Shale 

Play and that it became common in the 1990s. Chesapeake also estimates that horizontal wells 

will produce gas over a 30- to 50-year lifetime.

Table 3-1. Number of Wells in the United States Over Time

Year

Number of Wells Number of 

Horizontal Wells

Well Depth Range

Total Gas Oil (Feet)

1900 to 1924 154,587 26,242 83,779 NR 1–16,834

1925 to 1949 489,011 59,624 258,485 NR 1741–14,451

1950 to 1974 1,122,005 128,798 506,550 NR 199–22,840

1975 to 1999 1,123,615 297,677 522,032 NR 439–29,060

2000 to 2011 453,772 194,056 121,617 NR 347–34,158

1844 to 2011 3,600,000 NR NR 60,292 NR

Source: NPC, 2011.

NR—Not Reported.

Chesapeake provided a brief overview of current and emerging shale gas plays in the 

United States. The Barnett was the largest shale-gas-producing play until two years ago, when 

the Haynesville overtook it in volume of production. According to Chesapeake, other emerging 

plays include Marcellus, Utica, Mississippi, Niobrara, and Eagle Ford. Chesapeake expects that 

the Marcellus may eventually become the largest producer in the United States. The Marcellus is 

primarily a dry gas play (i.e., it produces primarily natural gas with minimal condensate and/or 

oil). However, Chesapeake indicated that the southwestern parts of the Marcellus may produce 

more liquids. Because natural gas prices fell after 2008 and have remained low since, liquid-rich 

plays are more economically attractive.

3.2 Chesapeake’s Oil and Natural Gas Activity

Chesapeake is the second-largest producer of gas in the United States after Exxon Mobil.

Exxon Mobil became the largest U.S. natural gas producer after acquiring XTO Energy Inc. in 

 

3 Available online at http://www.npc.org/NARD-ExecSummVol.pdf.
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2009. At the time of the site visit, Chesapeake was active in the Barnett, Bossier, Haynesville, 

Eagle Ford (liquid), Niobrara, Cleveland/Tonkawa, Granite Wash, Colony Wash, Mississippi 

Lime, and Marcellus oil and natural gas plays, with 161 drilling rigs. The company owns several 

subsidiaries, each with a focus on a particular part of the development process (e.g., Nomac is a 

Chesapeake-owned company that focuses on drilling). Chesapeake initially mobilized 25 drilling 

rigs along with six fracturing crews to the Marcellus. Since gas prices have remained low, 

Chesapeake moved 10 rigs and three fracturing crews from the Marcellus to other plays that have 

more potential to produce condensate or oil. Fifteen rigs and three fracturing crews, however, are 

still active in the dry gas producing northern Marcellus, and remains the most active driller in the 

Marcellus play. 

3.3 Chesapeake’s Northern Marcellus Shale Development Strategy

Chesapeake’s strategy for leasing properties in northern Marcellus relies heavily on

compiling a large proprietary database of core samples and 3D seismic data. Company geologists 

analyze the data and recommend well locations with the highest production potential. It is not 

always possible to drill in the exact location recommended by a geologist due to several factors 

such as: topography, environmentally sensitive habitats, water availability, state restrictions for 

siting, or restriction on surface access with land owners. In these situations, Chesapeake finds the 

closest possible drilling location that will address these factors and still allow for the effective 

production of minerals from the unit. The geologists give the final go-ahead before the mineral 

lease is finalized based on production potential. Chesapeake uses horizontal drilling and geosteering to drill into the target formation and remain in that part of the target formation with the 

highest production potential.

Chesapeake described their long term drilling plans in the northern Marcellus and 

described differences in drilling strategies in the northern Marcellus and urban areas of the 

Barnett shale. However, Chesapeake notes that well pad designs will not only differ among shale 

plays but also within shale plays due to variations in regulatory structure, population density, 

land availability, climate, roads, and water availability. In the northern Marcellus, Chesapeake 

estimates that the total cost of well pad construction, drilling, and fracturing one well on average 

is in the range of [REDACTED]. In this area, Chesapeake’s long-term plan is to drill

approximately six horizontal wells per well pad, with each pad capable of draining 

approximately 2 square miles of formation. But to reduce the risk of a poor investment resulting 

from variability in market conditions, high cost for drilling and fracturing, and the potential for 

drilling into a low-producing formation, Chesapeake normally drills and fractures only two of the 

planned six wells when the well pad is first constructed. Chesapeake uses a different strategy in

the Barnett, where they are developing gas wells in urban areas, and where land is more difficult 

to obtain primarily because the Barnett is a more developed play that has been in active 

development for more than 20 years. In the urban areas of the Barnett, Chesapeake has obtained

slightly larger well pad leases (5 to 6 acres) and has drilled 10 to 12 horizontal wells on a single

pad. In these cases, all 10 to 12 wells may be drilled and fractured at one time to maximize the 

efficiency of the limited land availability in an urban setting and minimize the amount of time 

spent for construction and development in a congested area. While the pads with high number of 

wells per pad are necessary in the strict confines of an urban setting, Chesapeake’s average well 

pad for the Barnett play is approximately three acres in size and will have three to five wells per 

pad.
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Geologists have not yet identified the full extent of the producing areas of the Marcellus 

formation. For this reason, Chesapeake obtains new leases near existing successful leases,

forming a cluster of leases. To date, Chesapeake estimates it has constructed more than 50 

percent of the well pads planned for the northern Marcellus. On most of these well pads 

Chesapeake has installed only the first two of six planned wells.4 Chesapeake’s overall strategy 

is to continue to expand its cluster of leases in the northern Marcellus until the “edge” of the 

production zone is determined (i.e., trial and error with drilling new wells). Once the northern 

Marcellus formation is well defined, Chesapeake plans to go back to existing well pads to drill 

and fracture the remaining four wells, as logistics (e.g., drilling rig and fracturing crew 

availability) and gas prices allow.

Figure 3-1 shows a top view of a Chesapeake horizontal well pad in northern 

Pennsylvania (not drawn to scale). As previously explained, Chesapeake does not drill all six

wells at once. Typically, it drills the middle two wells first. When conditions are favorable, the 

drill rig will be brought back on site to drill the remaining four wells. At the surface, the well 

heads are spaced 15 feet apart; however, the wells are directed away from each other so that 

horizontal laterals of the wells are spaced 1,000 feet apart. If Chesapeake decided to drill more 

than six wells on a particular pad, they can potentially infill to 500-foot spacing.

Figure 3-1. Top View of a Horizontal Well Pad

Figure 3-2 shows all Chesapeake shale gas wells in northern Pennsylvania using the 

EPA’s GeoPlatform mapping tool and coordinates from PA DEP’s spud reports through June 

 

4

If 50 percent of total well pads are already constructed, each with only two of six wells, then less than 20 percent 

of the wells have been drilled depending on future well production and future market conditions.

Well pad

Wells

1,000 ’

4,000’

500 ’

Potential 

infill well

15 ’
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2012.

5

Table 3-2 shows Chesapeake’s well counts by county for the entire state. The cluster of 

wells illustrates Chesapeake’s development activity. Operating a cluster of wells results in

reduced trucking, less gas pipeline installation, and other infrastructure benefits. However, this is 

difficult for small companies to follow this pattern because of high upfront costs.

Source: EPA’s GeoPlatform mapping tool.

Figure 3-2. Chesapeake Active Shale Gas Wells in Northern Pennsylvania

Table 3-2. Chesapeake’s Active Shale Gas Wells in Pennsylvania by 

County through June 2012

County

Number of Wells

Horizontal Vertical Total

Bradford 451 13 464

Susquehanna 119 3 122

Sullivan 42 3 45

Wyoming 38 2 40

Beaver 13 5 18

Greene 17 0 17

Washington 16 0 16

 

5

PA DEP spud data includes wells through June 30, 2012. Available online at: 

http://www.depreportingservices.state.pa.us/ReportServer/Pages/ReportViewer.aspx?/Oil_Gas/Spud_External_Data.
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Table 3-2. Chesapeake’s Active Shale Gas Wells in Pennsylvania by 

County through June 2012

County

Number of Wells

Horizontal Vertical Total

All Other Counties 6 4 10

State Total 702 30 732

Source: PA DEP’s spud data through June 2012.

3.4 Well Pad Construction

Most lease agreements only address mineral rights and do not include surface use. After 

Chesapeake selects a location for a new well pad, they must obtain surface use agreements. Once 

Chesapeake obtains a surface use agreements, well pad construction can begin. In general, most 

of the well construction work is conducted by Chesapeake’s subsidiaries. However, the company 

typically uses local contractors to supply materials (e.g., gravel, fuel) to help complete 

excavation. Well pad construction, drilling, and fracturing of the initial well will commence 

before gas pipelines are available. As a result, pipeline construction must continually follow 

drilling locations to bring new production to the sales lines.

Construction of a well pad in the Marcellus can vary in costs between [REDACTED]. 

The lower cost represents the cost to develop a well pad on flat terrain with very few influencing 

factors (e.g., well pads in rural western and arid regions). The higher cost represents the cost to 

develop a well pad on hilly terrain, with high levels of precipitation, climate extremes with frost, 

varying environmental conditions such as wetlands, and inferior roads as influencing cost factors 

for pad construction (e.g., Marcellus). Construction costs include excavation, access roads, well 

pad containment, and permits.

Chesapeake constructs each northern Marcellus well pad to hold four to six horizontal 

wells on approximately two and a half acres (300 by 400 feet). The construction process 

includes:

1. Leveling the terrain to create a flat well pad. Extra soil is piled on the high side of 

site to ensure that native soils are preserved. After the wells are installed and 

developed, soil from the berm is used for site reclamation.

2. Installing buffers such as deflection berms, silt socks, secondary earthen 

containments, and/or sedimentation traps around the entire well pad. 

3. Final leveling of well pad with gravel and geotextile.

4. Hydro mulching (slurry of seed and mulch) of all soil berms and barriers. 

However, this process is weather dependent.

3.5 Drilling

Drilling is a 24 hours per day, seven days per week operation. Employees that remain 

onsite 24 hours per day include drill workers, directional drillers, a geologist, and workers 
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responsible for producing the drilling mud. If on-the-spot decisions must be made, these 

personnel are always immediately available. The onsite workers work 12-hour shifts for 14 days 

followed by 14 days off. During the drilling and fracturing process, Chesapeake provides

temporary office and housing units on site for these workers.

Constructing and drilling one well in the rough terrain of the northern Marcellus requires 

24 days on average. Mobilizing large trucks and drilling equipment to the well pad in rough 

terrain takes more time than on flat terrain. When Chesapeake first drilled in this area, drilling 

took as long as 80 days per well. As the company learned more about the Marcellus formation,

the topography, the limits of the surrounding infrastructure such as local roads, and continued 

efforts to build a corporate structure to manage assets such as water and waste management, it

became more efficient at drilling. Chesapeake now drills the average well in this region 7,000

feet deep, with horizontal laterals approximately 4,000 feet long in approximately 24 days. The 

cost for Chesapeake to drill a single horizontal well is [REDACTED]. 

Table 3-3 and Figure 3-4 provide an overview of drilling and casing information 

including depth, casing name, casing diameter and the fluid type used to drill each phase. 

Chesapeake constructs each well with as many as seven or eight layers of casing and cement. 

Casing diameter becomes smaller with depth. Each new casing string starts at the surface of the 

well and extends deeper than the previous casing. At depths less than 3,500 feet, cement is 

installed along the entire length of the casing to the surface as a barrier between each new casing. 

In general, the driller installs a well following the steps below:

1. Drill section of well (i.e., to one of the depth categories in Table 3-3) and then 

retract drill bit and pipe. The drill pipe connects the drill bit to surface equipment 

and carries the drilling fluid.

2. Install threaded steel casing into well.

3. If depth is less than 3,500 feet, the operator lowers a cement pump through the 

steel casing until it reaches the bottom of the well. The operator then pumps the 

cement down hole forcing the cement out of the bottom of the casing and back up 

the outside of the casing known as the annular space until the cement reaches the 

surface. Figure 3-3 provides a side view of this step.

Source: Provided by Chesapeake after site visit.

Figure 3-3. Side View of Cementing Process
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4. Allow at least eight hours for cement to cure.

5. Drill new section of well through the cement at the bottom of the well and repeat 

steps 1 through 4. At depths greater than 3,500 feet, the operator may utilize a 

combination of drilling fluids and cement to fill the annular space rather than 

cement alone. The reason the process is changed at this depth is because the 

weight of cement becomes greater than the force available at the surface to bring 

the cement to the surface. However, in order to keep the overall structural 

integrity of the well intact, drilling fluid is added from the top of the well to the 

cemented portions of the casing below.

Table 3-3. Well Casing Information

Casing String Name

Final Depth Range 

of Casing

(Feet) a

Casing Outer 

Diameter (inches) Grout Drilling Fluid Type

Conductor 40–80 16–20 Cement Air or fresh water.

Surface 700–1,400 9.625–13.375 Cement Air.

Intermediate 1,800–2,800 9.625 Cement Air or mud.

Production a4,400–7,800b5.5 Cement to ≤ 

3,500 feet Mud or SOBM fluid.

a—Fracturing is performed through the production casing.

b—Production casing is installed in the entire length of the well including horizontal lateral.

Source: Provided by Chesapeake after site visit.

Figure 3-4. Top View of Well Casing
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During drilling, operators pump drilling fluid6(air, mud (a mixture of water and an inert 

weighting materials such barite), or synthetic-based oil) down the drill pipe and out through 

holes on the drill bit. Drilling fluids have several critical functions such as cooling the drill bit; 

transporting drill cuttings to the surface; maintaining wellbore integrity; and maintaining down 

hole pressure of the fluid greater than the pressure in any given formation. Pressures can increase

with depth and the likelihood of encountering them on the way to the target formation is higher 

as the well becomes deeper.7 At shallow depths, where formation pressure is typically low and 

there is more certainty of not finding gaseous pockets, drillers use compressed air drilling, 

because it’s more cost effective. At greater depths, where greater stressors are being applied to 

the well bore, drillers use muds or synthetic oil based mud (SOBM), SOBM is a drilling fluid 

that utilizes non petroleum based oil, similar to vegetable oil, to drill the horizontal section 

through the production zone. The oil protects the formation from swelling and provides better 

weight control as the drill bit proceeds through the production formation. In addition to these 

functions, drilling fluids provide a critical communications link from the drill bit to the operator 

at the surface. The electrolytic properties of the drill fluid allow electrical signals to be sent from 

the drill bit through the drilling fluid to the surface, where geologists and other analysts can 

evaluate the conditions down hole at the bit.

Water-based fluids (i.e., muds) may contain the following additives:

 Gels (e.g., bentonite) to enhance cutting-carrying properties

 Lime for pH control

 Polymers to prevent excessive seepage into the formation 

 Salt to increase conductivity and allow the operator to analyze downhole 

conditions via electric currents

 Barite, as needed, to add weight to the fluid

Synthetic-oil-based fluids may contain the following additives:

 Emulsifiers to keep water and fluid together

 Gels to enhance cutting-carrying properties

 Barite, as needed, to add weight to the fluid

As stated previously, drillers prefer to air drill at shallow depths as long as possible 

because there is less work to do on the surface and cost are lower. Air drilling does not require 

mud or synthetic-based fluid recycling operations. Air drilling requires a series of large air 

compressors that pressurize air to 3,600 psi.

Chesapeake uses fresh water for drilling the first stages of the well, specifically when 

setting the conductor and surface casing. Drilling with fresh water creates fewer disturbances to 

the freshwater aquifer than air drilling. Air drilling may cause turbidity or an effervescent effect 

in the freshwater aquifer. Air drill can also be loud at shallow depth which may disturb nearby 

residents and is normally reserved for use after the surface casing is set in place.

Once the surface casing is set, drilling operations begin using air as a drilling fluid to 

complete the vertical portion of the well. The well is drilled to approximately 800 to 1,000 feet 

 

6 The average northern Marcellus horizontal well requires 100,000 gallons of water for drilling.

7 The target formation in the northern Marcellus contains gas at 3,000 pounds per square inch (psi).
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above the target formation. The operator will then change to what is known as a bent motor to 

begin the horizontal leg of the well. The bent motor is a slightly bent (about 1°) tool attached to

the drill bit at the end of the drill string. This tool is designed for directional drilling and allows 

for the well bore to change from a vertical position to a horizontal position over a length of 

approximately 800 to 1,000 feet of vertical depth. As the well bore enters the target formation, 

the operator can orient the motor and bit from the surface to perform geosteering. Geosteering 

consist of an interaction of pushing or turning the drill string with the bent motor and utilizing 

drilling fluids through the motor to drive the bit. These interactions allow the operator to move

the well bore in any direction to stay centered accurately in the most productive zone regardless 

of changes in elevation of that targeted zone as the lateral leg of the well is extended.

3.6 Well Completion: Perforating and Hydraulic Fracturing

Chesapeake clarified that well-completion activities include perforating, hydraulic 

fracturing, and the flowback recovery process. The cost for Chesapeake to fracture a single 

horizontal well with 10 to 12 stages is [REDACTED]. The total cost depends on:

 Number of stages;

 Depth of formation;

 Cost of fuel; and

 Availability of water infrastructure.

Perforating is the process of using special explosives to connect the inside of the 

production casing to the gas shale formation. First, the operator lowers the explosive-charged 

perforation guns down the well to the end of the horizontal lateral and detonates the explosives in 

a controlled manner. The explosion creates several holes that extend approximately 1 foot into 

the formation rock and are approximately 1/2 inch in diameter. These holes (i.e., perforations)

create a starting point for the hydraulic fractures. After the first stage is perforated, the operator 

retracts the perforating guns from the well.

The perforations in the first stage are immediately fractured with what is known as the 

pad. The pad is the injection of high pressure water and chemical additives (i.e., no proppant) to 

create the initial fractures into the formation. After the pad is pumped down hole, proppant is 

introduced into the fracturing fluid to keep the fractures open. After the first stage is full with 

water and proppant, the operator lowers a plug into the well bore to isolate the portion of the well 

that was just hydraulically fractured completing the first stage, followed by the perforating gun

to begin the second stage. This allows the operator to plug the first stage to maintain pressure, 

separate the different stages, and immediately perforate the second stage. The ongoing 

perforating and fracturing process is outlined below:

First stage

1. Perforating

2. Pad

3. Proppant 

4. Plugging

Second Stage

1. Perforating

2. Pad
DCN: SGE00288 13

3. Proppant 

4. Plugging

Last Stage (10 to 12 stages on each horizontal lateral)

1. Perforating

2. Pad

3. Proppant 

4. Final Plug

Chesapeake reported that their northern Marcellus wells use slick water fracturing fluid, 

which is a mixture of water, chemical additives, and proppant. In other formations, it is difficult 

to pump the proppant into the formation using slick water techniques. When this occurs, the 

operator may add gel to the mixture. Gel fracturing is similar to slick water except that a thick 

gaur is added to the fracturing fluid to increase viscosity, which helps “carry” proppant into the 

formation fractures. However, because gel fractures tend to be more expensive due to additional 

chemicals and horsepower requirements, operators generally avoid using gel fracturing if they 

can successfully and efficiently utilize a slick water fracture.

Figure 3-5 provides a simple flow diagram of the fracturing process at the well pad. First, 

the operator trucks or pipes fresh water from the nearest freshwater impoundment or State 

approved surface water body withdrawal site to the freshwater tanks located on the well pad.

8

When flowback1 water from a recent nearby well completion is available for reuse it is trucked to 

the well pad and stored in reuse tanks. Chemicals and proppant are stored in nearby tanks on the 

well pad. Fresh water, reuse water, chemicals, and proppant are piped to a blender unit where 

they are mixed to specific ratios. The operator controls the ratio from a control vehicle located on 

the well pad. After blending, the water, chemicals, and sand are piped to the pump trucks. The 

pump trucks pump the hydraulic fracturing fluid to a pressure greater than the formation pressure 

(typically greater than 3,000 psi for the northern Marcellus) and inject it into the well.

 

8 Chesapeake has constructed 60 freshwater impoundments to support its northern Marcellus operations.
DCN: SGE00288 14

Figure 3-5. Hydraulic Fracturing Process Flow Diagram

Fracturing each stage will require 470,000 to 600,000 gallons of water, so with 10 to 12 

stages, each horizontal well in the Marcellus requires about 4.7 to 7.2 million gallons of water. 

After fracturing the last stage, the operator may shut the well in (i.e., seal the well off and leave 

the plugs in place) and begin to remove all of the fracturing equipment from the well pad.

Depending on the number of stages and wells to be fractured on a given well pad, the hydraulic 

fracturing process can be completed in three to five days on average. Once the fracturing crew 

has left, the flowback crew will bring in a small number of fracturing tanks, separators, and a 

small work over rig or wire line to remove the plugs from each fracturing stage. When the well 

pad is ready, the operator removes the stage plugs and releases the pressure at the wellhead to 

commence the flowback process.

During the flowback process, hydraulic fracturing fluids injected into the well and 

produced fluids from the target formation flow back to the surface and are captured in fracturing

tanks. At first, the flowback1 water will consist of nearly 100 percent water and proppant, with 

little to no gas. Gas will eventually begin to flow and increases over time while water flow 

decreases. Production infrastructure (e.g., gas pipeline, gas production units, and separators) 

must be installed before the operator releases the gas for sale. If this infrastructure is delayed, the 

operator may “shut-in” the well (i.e., not release the pressure at the wellhead). Shut-in is possible 

for weeks or even months if necessary while production equipment is installed on the pad and 

pipeline are brought to the well.

Pump 

Trucks

Truck or 

temporary 

pipe

Reuse 

tanks

Blender

Proppant 

storage 

trucks

Fresh water impoundment

Reuse 

tanks

Chemicals

Fresh 

water 

tanks

Fresh 

water 

tanks

Fresh 

water 

tanks

Well

High pressure 

water, chemicals, 

proppant

Water, chemicals, 

proppant

Well pad

Control 

vehicle
DCN: SGE00288 15

During flowback operations, a typical northern Marcellus well will produce 

approximately 10 to 15 percent of the hydraulic fracturing fluid volume injected. Chesapeake 

operators normally truck all flowback1 water directly to another fracturing site and mix it with 

fresh water for fracturing the next well. Depending on the quantity of available reuse water, 

Chesapeake will typically use a 10 to 15 percent blend ratio of reuse water to fresh water. In 

regions where flowback recovery is higher than 10 to 15 percent of the injected volume, blending 

ratio determination is more critical. Higher blending ratios (e.g., 40 percent) are possible if reuse 

water from multiple wells is available. Chesapeake plans to increase this number to 50 percent in 

the future.

3.7 Production Phase

During the flowback process, the well can begin the production phase if the pipeline and 

mobile separation units are available at the time the well is in its initial flowback stages, this is 

commonly referred to as reduced emissions completions or “green completions”. However, when 

this is not an option during the initial flowback process the gas is flared and workers monitor the 

amount of proppant in the flowback1 water. As the amount of solids (proppants) in the flowback1

water subsides to a minimum level, the well can enter the production phase of operations.

During production, Chesapeake uses a gas/water separator to remove the gas from the

produced water at the surface. If the well is operating before pipeline infrastructure has been 

installed, the separated gas can be flared or the well can be shut in while waiting on the pipeline. 

Otherwise, the gas flows directly to another set of separators or heater treaters, which remove 

water vapor by means of simple phase separation or in the case of a heater treater by adding 

indirect heat to the separation vessel which helps further promote the drying of the gas before the 

gas is fed to the collection pipeline. Reasons for removing water content from the gas stream

include:

 Prevent line plugging from hydrate formation by removing water 9;

 Reduce potential of free water formation in downstream pipelines, which would 

reduce pipeline capacity;

 Minimize corrosion in the pipeline; and

 Meet minimum pipeline quality standards for gas heating content and quality for

the market 10.

The gas will go through dehydration and compression processes downstream of the well 

pad, so compression at the well pad is not always required. Regions that produce more liquids 

(e.g., condensate, oil) may require additional vapor-collection equipment on the well pad during 

production to prevent emissions of volatile organic compounds (VOCs). If liquids are expected, 

the separator must be capable of separating water, condensates or oils, and gas.

Produced water from the separators flows to aboveground storage tanks. Typically, the 

production phase will start within 90 days of the fracturing job. In the northern Marcellus, a well 

in production will generate less than 10 barrels of water per day. This produced water contains 

 

9 Hydrates form when the temperature and pressure of a water and hydrocarbon mixture decrease to a certain point. 

Hydrates are solid crystals that can cause plugging in pipes.

10 Water has a lower heating content of gas. Because gas is sold on the market on a million BTU basis per volume, 

drying the gas increases the value of on the market.
DCN: SGE00288 16

higher concentrations of total dissolved solids (TDS) than those produced during flowback1

operations. Chesapeake hauls the majority of produced water in the northern Marcellus to their 

centralized treatment location (see section 4.5).

The costs for Chesapeake to operate a single horizontal well during production include:

 Capital costs for storage tanks, separators, heater treaters, and other miscellaneous 

surface equipment;

 Wastewater management costs to haul wastewater from the site when the storage

tanks reach capacity; and

 Daily operational costs for sending technicians to the well site for visual 

inspection of equipment.

4.0 CHESAPEAKE SITES VISITED

This section describes the sites that the EPA visited during the May 9 tour. Appendix C 

provides a map of the specific sites visited in the order that the tour progressed, starting with 

Chesapeake’s regional office. The list below includes the sites visited in the order of the well 

development process.

 Wysox Source Water Withdrawal site;

 Freshwater impoundment;

 Gardner Nebra well 1H (drilling);

 James Barrett wells 1H and 2H (production); and

 Arnold Treatment Facility.

4.1 Wysox Source Water Withdrawal Site

Chesapeake currently operates eight source water withdrawal sites in northern 

Pennsylvania. EPA visited one of the eight source water withdrawal sites called the Wysox 

Source Water Withdrawal Site, which withdraws water from the Susquehanna River. Figure 4-1

shows the flow of water from the Susquehanna River to the freshwater storage tanks, truck fill 

stations, and freshwater impoundments at the Wysox Source Water Withdrawal Site.

Figure 4-1. Wysox Source Water Withdrawal Site Flow Diagram

Pump 

housing and 

pump

Susquehanna 

River

Freshwater 

storage tanks

Meter and 

transmitter

Fill stations

Pump

Impoundments 

or wells

Trucking
DCN: SGE00288 17

At the Wysox site, the intake is located approximately 10 feet under water and is 

connected to a pump housed in a small shed just onshore. The water is routed through a flow 

meter equipped with a remote transmitter and pumped to the storage tanks. Figure 4-2 and Figure 

4-3 show the remote transmitter and main pump housing. The main pump‘s maximum flow rate 

is 1,000 gallons per minute. The flow meter is located between the main pump and storage tanks. 

It meters the volume of water withdrawn from the river, and its transmitter signals to the main 

pump when storage tank levels are low; thus, the main pump runs intermittently as needed.

Chesapeake’s permit from the Susquehanna River Basin Commission (SRBC) allows a 

maximum of 0.999 million gallons per day to be withdrawn at this location. When the remote 

transmitter recognizes that the 0.999-million-gallon limit is reached, it automatically shuts down 

the main pump until midnight. According to Chesapeake, this site reaches its maximum 

withdrawal capacity and must be shut down five of seven days a week on average.

Figure 4-2. Remote Transmitter

Figure 4-3. Main Source Water Pump Housing
DCN: SGE00288 18

Figure 4-4 shows the five storage tanks at the freshwater intake site. In the winter, these 

tanks are taken out of service to prevent freezing. During winter, fresh water is pumped from the 

river withdrawal into trucks at the fill stations, bypassing the tanks. Each of the five tanks has a 

capacity of 400 barrels (16,800 gallons) and is 20 feet tall. When the water level drops to 15 feet, 

the remote transmitter turns the main pump on until the tank level reaches 97-percent capacity.

Figure 4-4. Freshwater Intake Storage Tanks

When trucks arrive onsite for fresh water, they connect to fill stations located next to the 

storage tanks. Figure 4-5 shows a close-up of the automated screen at the fill station. To activate 

the fill station, the trucker must enter the truck ID and the freshwater destination. The truck ID 

indicates the truck capacity. Entering the freshwater destination allows Chesapeake to track 

water from intake to impoundment or well pad. These standard operating procedures ensure that 

Chesapeake maintains accurate tracking of all water withdrawals in accordance with the SRBC 

and the PADEP. In the summer, the fill stations load trucks to 97-percent capacity. In the winter, 

the fill station loads trucks to only 90-percent capacity to provide an extra safety margin when 

cold temperatures can reduce the capacity of the truck’s tank when ice forms inside the wall of 

the tank from an earlier load of water.
DCN: SGE00288 19

Figure 4-5. Tracking System at Truck Fill Station at Water Withdrawal Site

4.2 Freshwater Impoundment

Figure 4-6 and Figure 4-7 show the freshwater impoundment and unloading station that 

the EPA visited during the site tour. The unloading stations are connected to the impoundment 

via underground pipelines and are used only for unloading freshwater into the impoundment. 

This impoundment is lined with 60 mil11 liner, holds 9.3 million gallons, and provides enough 

fresh water to hydraulically fracture between one and two well pads.

Chesapeake uses a network of large impoundments to store fresh water for drilling and 

fracturing processes. Currently, Chesapeake has [REDACTED] impoundments in northern 

Pennsylvania, ranging in size from 7 million to 15.5 million gallons. Combined, the 

impoundments store enough water to sustain Chesapeake’s operations for five to six months if all 

source water withdrawals were to stop. Each freshwater impoundment is lined with 60 mil 

HDPE liner.

To minimize trucking costs, Chesapeake uses temporary high density polyethylene 

(HDPE) piping as much as possible to transport fresh water from the impoundment to the well 

pad. However, temporary piping is difficult to use in hilly terrain because it requires a series of 

booster pumps to increase pressure. Most temporary piping is only rated for 100 pounds per 

square inch, limiting the size of the booster pumps between hills thus limiting the altitude of the 

hill temporary piping can be installed on. When Chesapeake runs temporary piping from the 

impoundment to a well pad, it opens the gate shown in Figure 4-6. Chesapeake stated they once 

ran water from this impoundment to a well approximately 7 miles away using a steel pipeline 

that would later be used to transport gas. However, using gas pipeline to move freshwater is not 

common.

 

11 One mil is equal to 0.001 inches. 
DCN: SGE00288 20

Figure 4-6. Freshwater Impoundment

Figure 4-7. Freshwater Loading Station

4.3 Well Construction and Drilling (Well: Gardner Nebra 1H)

At the time of the site visit, Chesapeake was drilling a horizontal well called Gardner 

Nebra 1H. Figure 4-8 shows the overall pad setup. The entire pad is surrounded by a 3-foot 

berm. Outside of the berm are mounds of topsoil that were displaced during the site excavation. 

When well construction is complete, Chesapeake will use the top soil stored in these mounds for 

site remediation. Within the pad, all equipment and tanks are in secondary containment. The site 

is set up to prevent run-on and run-off. The only accumulations of water on the pad are direct

rain and snow precipitation. Using a vacuum, Chesapeake collects all water that is accumulated 

on the well pad surface and reuses the collected water for drilling.

Chesapeake explained that it is using a diesel-powered drilling rig at the Gardner Nebra 

1H because the well is located in an area that does not have access to electric power. Chesapeake 

has the option for electric, diesel, or natural gas powered drilling rigs. Each type of rig has 
DCN: SGE00288 21

advantages and disadvantages. The operation control room on the rig monitors the well and drill 

depths. This control room transmits all monitored data directly to Chesapeake’s control center, 

located in Oklahoma City. This also allows operations to be monitored remotely via iPhone and 

in real time.

Figure 4-8. Chesapeake Drilling Site

At the time of the EPA’s visit to Gardner Nebra 1H, Chesapeake had completed the 

intermediate casing portion of the well. The drilling team was in the process of removing 90-foot 

sections of piping from the well to retrieve a broken drill bit. Chesapeake explained that this 

operation can be time consuming because the drill bit can only be removed at a rate of 1,000 feet 

per hour. Figure 4-9 shows two intermediate casing drill bits that Chesapeake had on site the day 

of the visit. The drill bit on the right is made out of diamond and glass. The diamond drill bit is 

used to drill the lateral (horizontal) portion of the well through the Marcellus shale. The red 

arrows in the figure point to holes in the bits through which the drilling fluid is injected into the 

well bore to cool the bit and carry cuttings to the surface.
DCN: SGE00288 22

Figure 4-9. Intermediate Casing Drill Bits

Figure 4-10 shows the drilling pipes. The pipes shown in this picture have a slight bend 

and are used for drilling the curved portion of the well. The curved portion of the well is drilled 

at a 14-degree/100-ft bend, and it can take 800 to 1,000 feet to complete the turn from vertical to 

horizontal.

Figure 4-10. Drill Pipe for Curved Portion of Well

At the time of the site visit, Chesapeake had completed the air-drilling portion of the 

well. Chesapeake explained that they will use fresh water to drill through the drinking water zone 

to limit their impact while setting the surface casing that isolates the well bore from the drinking 

water aquifer. Once the surface casing is set, Chesapeake uses compressed air as a drilling fluid, 

the compressed air acts similar to other drilling fluids by cooling the bit, stabilizing the well 

bore, and moving cuttings up to the surface. Drilling on air is highly efficient while drilling the 

vertical portion of the well.

Once Chesapeake begins to turn the well bore horizontally they will begin using a 

synthetic-based mud that includes water, lime, barite, calcium chloride, and other materials to 

create the correct conditions to provide lubrication and cooling to the bit, add weight to 

strengthen the bore hole and move cuttings effectively to the surface. As Chesapeake enters into 

the targeted production zone, they may also change over to a SOBM in order to protect the 

formation from swelling and provide better weight control.
DCN: SGE00288 23

Chesapeake operates a closed-loop system during drilling that is designed to minimize 

the amounts of freshwater and chemicals needed during these operations and eliminates the use 

of open pit flow return impoundments. Figure 4-11 presents a flow diagram of this closed-loop 

system and shows the following steps:

1. Drilling mud is prepared in large metal containers known as the mud tanks that 

are continually circulated and monitored for the proper consistency and physical 

properties for the drilling operations. Drilling mud is taken from the tanks and 

transferred down the drill pipe to the drill bit and enters the well bore.

2. Drilling mud that was injected down the drill pipe returns to the surface with 

cuttings where the mixture of cuttings and mud first enters a mud/gas separator. 

The mud and cuttings mixture typically does not contain any gas unless the drill 

passes through a gas-producing formation on its way to the target formation.

3. The mud/gas separator allows any accumulated gases to escape through the 

surface of the fluid. This gas is routed to a secondary separator and flare located at 

the corner of the well pad.

4. The de-gassed mud and cuttings are piped to a shaker table, which removes the 

large drill cuttings from the fluid. Then the mud is sent through a centrifuge to 

remove the remaining drill cuttings.

5. The drill cuttings from the shaker table and the centrifuge are captured in lined 

metal containers and are transferred to lined roll off containers to be shipped off 

site for disposal at a local landfill.

6. The fluids from the shaker table and centrifuge are returned to the mud tanks 

where the process began.
DCN: SGE00288 24

Figure 4-11. Drilling Site Flow Diagram

An onsite geologist examines the cuttings and logs the formations that have been drilled.

The cuttings in the lined storage bins are dried with lime prior to disposal at a landfill. The 

cuttings are sampled and reported to the local landfill to insure the cuttings meet their 

specifications for acceptance. Radiation monitoring is standard for RCRA Subtitle D landfills so 

each shipment of drill cuttings must pass through monitors and meet radiation criteria before 

disposal in the landfill. Once drilling is complete, the drilling fluids are sent to Chesapeake’s 

Arnold Treatment Facility, where it is treated via filter press (see section 4.5).

4.4 Production (Wells: James Barrett 1H and 2H)

Chesapeake operates two wells in Bradford County called James Barrett 1H and 2H. The 

wells are located at Latitude N 41.674025o, Longitude W -76.378011o. Both wells have been 

producing for approximately two years. According to PA DEP, drilling commenced on well 1H 

on July 11, 2009, and 2H on August, 13 2009. Production began in February 2010. Chesapeake 

estimates that these two wells produce enough gas to power 50,000 American homes (see Table 

4-1 and Table 4-2 for well-specific gas and water production data). Chesapeake also estimated 

that horizontal wells in the northern Marcellus could produce for 30 to 50 years. Because these 

wells are relatively new, it is unknown exactly how long they will produce gas; however these 

wells have already produced at much higher level than they were expected to based on traditional 

shale gas production models.
DCN: SGE00288 25

Figure 4-12 provides a flow diagram of the production site. The mixture of produced 

water and gas is routed underground from both wells to the water/gas separators. The separator is 

where the water gas emulsion from the well is transferred from a high pressure pipe to a low 

pressure vessel. This pressure change along with gravity will allow the water and solids to 

physically separate from the gas vapors. Suspended solids (e.g., sediment, sand) remain in the 

produced water. The produced water flows from the bottom of the separators directly to the 

storage tanks. The gas exits the top of separators and flows directly to a gas production unit 

(GPU), where any remaining water entrained in the gas is removed before the gas goes to the 

sales line. The GPU seen on site has a firebox fueled by natural gas from the well. The firebox 

heats a bath that contains the lines from the separator. The increased heat further drives the 

water/gas separation. The water again falls out in the large chamber of the GPU and is sent to the 

produced water tanks, while the gas is piped through the sales meter to the Tennessee Interstate 

pipeline. The produced water storage tanks and the water/gas separators are contained in 

secondary containment structures visible in Figure 4-16

Figure 4-12. Production Site Flow Diagram

Figure 4-13 shows the two James Barrett wellheads. Because security can be an issue for 

isolated sites, Chesapeake encloses all wells and other equipment (e.g., separators, storage tanks) 

inside a barbed-wired fence in the northern Marcellus. Figure 4-15 shows two two-phase water 

gas separators to the right and two GPUs to the left. Figure 4-14 shows a methanol tank near the 

two wellheads. Periodically, a solar-powered pump injects methanol into the produced gas and 

water stream at the wellhead. When the gas exits the well through the choke, it expands 

decreasing pressure and temperature. This rapid change in pressure and temperature can create

hydrates that form crystalline structures that can obstruct pipes and possibly cause damage to the 

pipeline. Methanol injection lowers the hydrate-formation temperature to prevent hydrate from 

forming and plugging the lines. Methanol also prevents freezing and corrosion inside the pipes 

by absorbing water and dissolving hydrates through its solvent properties if they begin to form in 

the pipe.
DCN: SGE00288 26

Figure 4-13. Wellheads of James Barrett 1H and 2H

Figure 4-14. Solar-Powered Methanol Tank and Injector

Figure 4-15. Water/Gas Separators (Right) and GPUs (Left)
DCN: SGE00288 27

Figure 4-16 shows the two produced water storage tanks. Each produced water tank has a 400-

barrel (16,800 gallon) capacity. According to Chesapeake, each northern Marcellus well produces on 

the order of three to six barrels of produced water per day. Under these conditions, a water truck must 

empty the tanks every two to four months. Before entering the storage tanks, the produced water flows 

through a solar-powered flow meter. This allows Chesapeake to remotely monitor the volume of 

produced water in each tank. However, a Chesapeake employee still visits the site daily to ensure all 

equipment is properly working. 

Figure 4-16. Produced Water Storage Tanks

Table 4-1and Table 4-2 provide production data for James Barrett wells 1H and 2H,

downloaded from PA DEP. Wells 1H and 2H have produced 3.3 and 5.1 billion cubic feet 

(BCF), respectively, since the beginning of production in early 2010 through 2011. The 

Chesapeake tour guides suggested that these wells are above average in terms of gas production 

compared to what the company expected in the area. Chesapeake’s long-term plan is to expand 

this well pad from two to six wells. Chesapeake explained that while the four new wells are 

drilled and fractured, the two existing wells may be shut in.

Table 4-1. James Barrett 1H Production Data

Time

Production 

Days

Gas

Production 

(Mcf)

Gas

Production 

(Mcf/day)

Gas 

Production 

Decline (%)

Wastewater 

(bbl)

Wastewater 

(bbl/day)

2010 (1st half) 140 1,303,306 9,309 --

4,103 12.8

2010 (2nd half) 181 1,065,722 5,888 37

2011 (1st half) 181 559,311 3,090 47 1,012 5.6

2011 (2nd half) 184 349,239 1,898 39 352 1.9

Totals 686 3,277,578 4,778 a80 b5,468 8.0 a

Source: PA DEP’s Oil and Gas Reporting database.

a—Two-year average production rate.

b—Decline over first 686 days of production.

Mcf—Million cubic feet.

bbls—Barrels.
DCN: SGE00288 28

Table 4-2. James Barrett 2H Production Data

Time

Production 

Days

Gas 

Production 

(Mcf)

Gas 

Production 

(Mcf/day)

Gas 

Production 

Decline (%)

Wastewater 

(bbl)

Wastewater 

(bbl/day)

2010 (1st half) 135 1,327,798 9,836 --

2,335 7.4

2010 (2nd half) 181 1,462,346 8,079 18

2011 (1st half) 180 1,306,599 7,259 10 790 4.4

2011 (2nd half) 183 1,028,712 5,621 23 843 4.6

Totals 679 5,125,455 7,549 a43b3,968 5.8 a

Source: PA DEP’s Oil and Gas Reporting database.

a—Two-year average production rate.

b—Decline over first 679 days of production.

Mcfs—Million cubic feet.

bbl—Barrels.

4.5 Centralized Arnold Renew Treatment Facility

Chesapeake operates a zero discharge centralized wastewater treatment facility (Arnold 

Treatment Facility), which is a part of Chesapeake’s Aqua Renew Program.12 Chesapeake started 

this program in an effort to maximize wastewater recycling in its overall northern Marcellus 

operations. The Arnold Treatment Facility uses basic filtration methods to remove total 

suspended solids (TSS) from drilling muds and produced water trucked from the well pad. 

Produced water in the northern Marcellus contains much higher levels of TDS and TSS than 

initial flowback1 water and is treated before reuse. According to PA DEP, this facility operates

under permit number WMGR123NC004.

Chesapeake does not typically treat flowback1 water at the Arnold Treatment Facility. 

According to Chesapeake, the wells in the northern Marcellus only return about 10 to 15 percent 

of the water injected during fracturing over the first 90 days after fracturing. The flowback1

water, in contrast to produced water from production, typically contains relatively low TDS and 

TSS concentrations. Chesapeake reuses most of its flowback1 waters without any treatment and 

is blended with fresh water prior to reuse. The flowback/freshwater ratio used by Chesapeake 

ranges from 15:85 to 40:60. 

Conditions for reuse are not as favorable for Chesapeake operators in other shale gas 

plays. As flowback1 water volume (as a percentage of total fracturing fluid volume) increases, 

reuse becomes more difficult because blending ratios also increase. For example, the 

Mississippian,

13 an unconventional oil play in which Chesapeake is active, is one of the highest 

water-producing formations in the country. Wells in this area produce four to six barrels of water 

for every one barrel of oil, and over 1,000 gallons per day after the initial flowback period. These 

areas generate much higher volumes of wastewater compared to the northern Marcellus. In 

addition, underground injection capacity is abundant in northern Oklahoma and Kansas, making 

treatment less attractive.

 

12 More information is available online at http://www.chk.com/Environment/Water/Pages/Aqua-Renew.aspx. 

13 The Mississippian formation is a low-permeability limestone formation in Oklahoma that requires horizontal 

drilling and hydraulic fracturing. This formation is a tight oil formation similar to shale oil (American Gas Reporter, 

(2011). Available online at http://superioroilandgas.com/mississippi-limestone-emerging-as-top-flight-horizontalliquids-play/. 
DCN: SGE00288 29

Figure 4-17 shows the flow diagram of the Arnold Treatment Facility. As previously 

mentioned, this facility is designed to treat two types of waste streams: produced water and 

drilling mud. All wastewater is trucked to the site and unloaded into fracturing tanks for storage. 

Produced water and drilling mud are stored separately.

Drilling mud is pumped into a filter press to separate the drill cuttings from the drilling 

mud. The solids removed from the press are transported to lined solid waste containers using a 

pug mill. Lime is added to further dry the solid waste before it is transported to a landfill for 

disposal. Prior to leaving the site, a third-party consultant scans each tank with a Geiger counter 

to inspect for radioactivity. Chesapeake did not mention any cases where radioactivity levels of 

cuttings forced the waste to a hazardous landfill. The treated mud (i.e., water-based fluid 

described in Section 3.5) is piped directly to mud treatment tanks. Chesapeake mentioned that 

chemistry testing and addition is performed on the fluid as necessary but could not provide any 

details on the chemical additives. 

Produced water is emptied from the truck directly into brine tanks (orange tanks in Figure 

4-18). From these tanks, the produced water passes through two disk filters. The first and second 

filters remove TSS down to 100 microns and 20 microns, respectively. The filtered water is 

piped directly into reuse tanks (green tanks in Figure 4-18). From the green reuse tanks, water is 

trucked to the next job.

Figure 4-17. Flow Diagram of Chesapeake’s Arnold Treatment Facility

Figure 4-18 provides a satellite image of Chesapeake’s Arnold Treatment Facility

generated by Google Earth©on October 6, 2011.

Produced 

water trucked 

from wells

Filter 

press

Reuse tanks

Reuse tanks

Reuse tanks

100 micron 

filter

20 micron 

filter

Mud 

treatment

Treated mud

Cuttings 

waste to 

landfill Solid Mud

waste

Secondary containment

Produced 

water tank

Water for reuse 

trucked to 

fracturing job

Mud trucked 

from wells Mud Storage

Drilling Mud and Cuttings

Lime

Treated mud for 

reuse trucked to 

drilling site
DCN: SGE00288 30

Source: Generated by Google Earth © using base map information from PA Department of Conservation and 

Natural Resources and coordinates from PA DEP’s Oil and Gas Reporting database.

Figure 4-18. Top View of Chesapeake’s Centralized Arnold Treatment Facility
DCN: SGE00288

APPENDIX A

LIST OF PARTICIPANTS ON THE CHESAPEAKE SITE VISIT
DCN: SGE00288 A-1

The following table is a list of participants that attended the Chesapeake site visit:

Table A-1. List of Attendees

First Name Organization Phone Number Email

Jan Matuszko U.S. EPA, Branch Chief (202) 566-1035 Matuszko.Jan@epa.gov

Brian D’Amico U.S. EPA, SGE Lead (202) 566-1069 Damico.Brian@epa.gov

Lisa Biddle U.S. EPA, SGE Engineer (202) 566-0350 Biddle.Lisa@epa.gov

Cuc Schroeder U.S. EPA, SGE Statistician (202) 566-2397 Schroeder.Cuc@epa.gov

Erik Helm U.S. EPA, SGE Economist (202) 566-1049 Helm.Erik@epa.gov

Richard Witt U.S. EPA, OGC (202) 564-5496 Witt.Richard@epa.gov

Jennifer Hoffman Chesapeake Energy Corp., 

Manager – Regulatory 

Affairs

(405) 935-6818 Jennifer.Hoffman@chk.com

Troy Jordan Chesapeake Energy Corp., 

Senior Environmental 

Specialist

(405) 935-4503 Troy.Jordan@chk.com

Brian Grove Chesapeake Energy Corp (570) 265-6525 Brian.Grove@chk.com

Jimmie Hammontree Chesapeake Energy Corp., 

Manager – Regulatory 

Affairs

(405) 935-6818 Jimmie.Hammontree@chk.com

Meghan Camp ERG, Senior Chemical 

Engineer

(703) 633-1684 Meghan.Camp@erg.com

Brent Ruminski ERG, Energy Engineer (703) 633-1701 Brent.Ruminski@erg.com 
DCN: SGE00288

APPENDIX B

INFORMATION PROVIDED BY CHESAPEAKE
DCN: SGE00288

APPENDIX C

MAP OF SITES VISITED
DCN: SGE00288 C-1

Source: Generated by ArcGIS using base map information from Bing Maps ©.

Figure C-1. Overview of Sites Visited in ArcGIS
DCN: SGE00288

APPENDIX D

SUMMARY OF COSTS PROVIDED BY CHESAPEAKE
DCN: SGE00288 D-1

Table D-1. Summary of Costs Provided by Chesapeake

[REDACTED]
DCN: SGE00288

APPENDIX E

POWER POINT PRESENTATION OF ALL SITE VISIT PICTURES

[REDACTED]