DCN: SGE00288 

# Sanitized Site Visit Report Chesapeake Energy Corporation Marcellus Shale Gas Operations

February 6, 2015DCN: SGE00288 i TABLE OF CONTENTS

Page

1.0 I NTRODUCTION

................................ ................................ ................................ ........ 1

2.0 B ACKGROUND AND O BJECTIVES

................................ ................................ .............. 1

3.0 O VERVIEW OF S HALE G AS P RODUCTION

................................ ................................ . 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 C HESAPEAKE S ITES V ISITED

................................ ................................ .................. 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 PICTURESDCN: SGE00288 ii 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 Sit e 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 T anks

................................ ................................ ................. 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

- 1DCN: SGE00288 iii 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 Uni ted States Over Time

................................ ......................... 4

Table 3

- 2. Chesapeake’s Active Shale Gas Wells in Pennsylvania by County through June 2012 7

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

- 1DCN: SGE00288 1

1.0 I NTRODUCTION

On May 9

, 2012

, t he 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 offi ce

. These sites included:

 Gardner Nebra well 1H (drilling) ;

 F reshwater impoundment ;

 James Barrett well s 1H and 2H (production) ;

 Arnold Treatment Facility ; and

 Source water withdrawal site

.

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

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

Brian Damico
Lis a Biddle

Jan Matuszko
Cuc Schroeder
Erik Helm
Richard Witt

E astern R esearch G roup, Inc (ERG) (EPA Contractor)

Meghan Camp
Brent Ruminski

Chesapeake Energy, Inc

Troy Jordan
Jennifer Hoffman
Jimmie Hammontree
Brian Grove

2.0 B ACKGROUND AND O BJECTIVES

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

. Th e EPA intends to conduct several site visits in the Marcellus Shale PlayDCN: SGE00288 2

because shale gas activity is high and underground injection capacity is limited for flowback 1 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 practice s

. 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 d iffer from some other gas producers in the state

. According to the Pennsylvani a 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 1 00 1,455,974 1 00 1,293,902 1 00

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 D atabase.
bbls

— B arrels

.

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 w ater in order to stay consistent with literature and other EPA reports.DCN: SGE00288 3 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 O VERVIEW OF S HALE G AS P RODUCTION

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 a nd 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, prod uction, and centralized treatment)

, genera l 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.DCN: SGE00288 4

 Heavy an d 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 , take n 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 ga s 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, includ ing 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 hor izontal drilling and hydraulic fracturing was developed in the Barnet t Shale

P la y 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 ( F eet) Total Gas Oil

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 primar ily 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 eco nomically 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

.DCN: SGE00288 5

2009

. At the time of the site visit, Chesapeake was active in the Barnett, Bossier, Haynesville, Eagl e Ford (liqui d), Niobrara, Cleveland/Tonkawa, Granite Wash, Colony Wash, Mississippi
Lime , and Ma rcellus oil and natural gas plays

, with 161 drilling rigs . The c ompany 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

. C ompany geologists analyze the data and recommend well locations with the highest production potential

. I t is not always possible to drill in the exact location recommended by a g eologist due to several factors such as: topography, environmentally sensitive habitats, water availability, s tate restrictions for siting, or restriction on s urface access with land owners

. In these situations

, Chesapeake find s the closest possible drilli ng 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 use s horizontal drill ing and geo

steering 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 drilli ng 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 c apable 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 Barne tt, 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 , Chesape ake has obtain ed slightly large r well pad leases ( 5 to 6 acres) and has drill ed 10 to 12 horizon tal 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 confin es 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.DCN: SGE00288 6

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 c luster 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 fra cturing crew availability) and gas prices allow

.

Figure 3

- 1 shows a top view of a Chesapeake horizontal well pad in n orthern Pennsylvania (not dr awn to scale). As previously explained , Chesapeake does not drill all six wells at once. Typically, it drill s 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 potentiall y infill to 500

- foot spacing.

Figure 3

- 1 . Top View of a H orizontal Well Pad

Figure 3

- 2 shows all Chesapeake shale gas wells in northern Pennsylvania using the
EPA’s GeoPlatform map p ing 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.DCN: SGE00288 7

2012

. 5 Table 3

- 2 shows Chesapeake’s well counts by county for the entire state. The cluster of
wells illustrates Chesapeake’s developm ent 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 t hrough 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_E xternal_Data

.DCN: SGE00288 8 Table 3

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

County t hrough June 2012

County Number of Wells

Horizontal Vertical Total

All O ther C ounties 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 cons truction

, drilling, and fracturing of the initial well will commence before gas pipelines are available . As a result , pipeline construction must continually follow drilling location s to bring new production to the sales lines.

C onstruction 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 constru ction (e.g., Marcellus). Construction cost s include excavation, access roads, well pad containment, and permits.

Chesapeake constructs each northern Marcellus w ell pad to hold four to six horizontal
wells on approximately two and a half acres (300 by 400 f eet ). The construction process
includes:

1. Level ing the terrain to create a flat well pad. Extra s oil is piled on the high side of
site to ensure that native soils are preserved

. After the wells are installed and developed, s oil from the berm is used for sit e reclamation.

2. Install ing buffers such as deflection berms, silt socks, secondary earthen containments, and/or sedimentation traps around the entire well pad

.

3. Final level ing 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 hour s per day, seven days per week operation. Employees that remain onsite 24 hours per day include drill workers, directional drillers, a geologist, and workersDCN: SGE00288 9

responsible for producing the drilling mud. If on

- the

- spot decisions must be made, these personnel are always immediately available. The ons ite 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 th e 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

. A s 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 lateral s 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 become s 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 e ntire 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 ProcessDCN: SGE00288 10

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 depth s 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 forc e available at the surface to bring the cement to the surface. However, in order to keep the overall structural integrity of the well intact, d rilling fluid is added from the top of the well to the

cemen ted portions of the casing below

.

Table 3

- 3 . Well Casing Information

Casing String Name Final Depth Range
of Casing ( F eet) 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 a 4,400

– 7,800 b 5.5 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 CasingDCN: SGE00288 11

During drilling, operators pump drilling fluid 6 (air, mud (a mixture of water and an inert weighting materials such barite) , or synthetic

- based oi l ) 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 cuttin gs to the surface; maintaining wellbore integrity; and maintaining down hole pressure of the fluid greater than the pressure in any given formation. P ressure s can increase with depth and the likelihood of encountering them on the way to the target formatio n 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, whe re 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 z one. 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 th e 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 geologist s and other analyst s can evaluate the c onditions down hole at the bit

.

Water

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

 Gels (e.g., bentonite) to enhance c utting

- carrying properties

 Lime for pH control

 Polymers to prevent excessive seepage into the formation

 Salt to increase conductivity and allow the o perator 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 c utting

- carrying proper ties

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

As stated previously, d rillers 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. D rilling with fresh water creates fewer disturbances to the freshwater aquifer than air drilling

. Air drilling may cause turbidity or an effervescent effect
in the fresh water aquifer

. Air drill can also be loud at shallow depth which may disturb nearby
resi dents 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).DCN: SGE00288 12

above the target formation. T he 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 a t 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 ente rs 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 Co mpletion: 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

 Availab ility 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, t he operator lowers the explosive

- charged perforation guns down the well to the end of the horizontal lateral and detonates t he explosives i n a controlled man ne r . The explosion creates several holes that extend approximately 1 foot into the formation rock and are approximately 1/2 inch in diameter. The se holes (i.e., perforation s) 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 p ad is the injection of high pressure water and chemical additives ( i.e., no proppant) t o create the initial fractures into the formation. After the pad is pumped down hole , p roppant 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 di fferent 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. PadDCN: 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 u se 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 help s “ carry ” proppant into the formation fractures. However, because gel fractures tend to be more expensive due to additional
chemical s and horsepower requirements , operators generally avoid using gel fracturing if they can successfully and efficiently utilize a slick water frac ture

.

Figure 3

- 5 provides a simple flow diagram of the fracturing process at the well pad. First, the operator trucks or pip es 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 flowback 1 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. F resh 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 t o 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 Marcellu s ) 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, e ach horizontal well in the Marcellus requires about 4.7 to 7.2 million gallons of water.
After f racturing 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 frac turing tanks, separators, and a small work over rig or wire li ne to remove the plugs from each frac turing 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 injecte d into the well and produced fluids from the target formation flow back to the surface and are captured in fracturing
tanks . At first, the flowback 1 water will consist of nearly 100 percent water and proppant, with
little to no gas. G as will eventually begin to flow and increases over time while water flow
decreases. P roduction infrastructure (e.g., gas pipeline, gas production units

, and separators )
must be inst alled before the operator releases the gas for sale. I f 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

.DCN: SGE00288 15

During flowback operations, a typical n orthern Marcellus well will produce approximately 10 to 15 percent of the hydraulic fracturing fluid volume inject ed. Chesapeake
operators normally truck all flowback 1 water directly to another fracturing site and mix it with fresh water for fracturing the next well

. Depen ding 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 determinati on 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 flowback 1 water

. A s the amount of solids (proppants) in the flowback 1

water subsides to a minimum level, the well can enter the pr oduction 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 pipe line

. Otherwise, t he 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

. R easons for removing water content from the gas stream
includ e :

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

 Reduce potential of free water formation in d ownstream 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 volatil e 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 9 0 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 h eating 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 flowback 1 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

s urface 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 C HESAPEAKE S ITES V ISI TED

This s ection 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 t he order of the well development process

.

 Wysox Source Water Withdrawal s ite ;

 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 S ource Water Withdrawal Site

.

Figure 4

- 1 . Wysox Source Water Withdrawal Site Flow DiagramDCN: SGE00288 17

At the Wysox site, t he intake is located approximately 10 feet under water and is connected to a pump housed in a sma ll 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 maxi mum flow rate is 1,000 gallon s per minute. The flow meter is located between the main pump and storage tanks.
It meters the volume of water withdrawn from the r iver

, and its transmitter signals to the main pump when storage tank level s are low ; thus

, the m ain 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 HousingDCN: 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 tank s 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 . Fresh w ater 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 truc k 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 S RBC
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 tempe ratures 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 i mpoundment and un loading station that
the EPA visited during the site tour. The un loading 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 mil 11 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 open s 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 . Fresh w ater Impoundment

Figure 4

- 7 . Fresh w ater 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 G ardner
Nebra 1H. Figure 4

- 8 shows the overall pad setup. The entire p ad 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, a ll 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. U sing a vacuum

, Chesapeake collects all water that is accumulated

on t he 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 drill ing rigs. Each type of rig hasDCN: SGE00288 21

advantages and disadvantages

. The operation control room on the rig monitors the well and drill depth s

. 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 b roken 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 hole s 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 dri lling 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 . D rill 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, stabili zing 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 inclu des 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
th e targeted production zone, they may also change over to a SOBM in order to protect the formation from swelling and provide better weight contro l.DCN: SGE00288 23

Chesapeake operates a closed

- loop system during drilling that is designed to minimize
the amounts of freshwat er and chemicals needed during these operations and eliminates the use of open pit flow return impoundments. Figure 4

- 11 presents a flow diagram of th is 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. Dri lling 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 retur ns to the surface with cuttings where t he mixture of cuttings and mud first enters a mu d/gas separator. The mud and cuttings mixture typically does not contain any gas unless the drill passes through a gas

- producing formation on i ts 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 cen trifuge to

remov e 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 moni toring 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 Treat ment 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 41.674025 o , Longitude W

- 76.378011 o . 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 2 009. 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. B ecause 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 wate r/gas separators. The sepa rator 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 entr ained in the gas is removed before the gas goes to the
sales line. The GPU seen on site has a firebox fuel ed 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 separator s 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 t he wellhead . When the gas exits the well through the choke, it expands decreasing pressure and t emperature

. This rapid change in pressure and temperature can create
h ydrates 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 solv ent properties if they begin to form in the pipe

.DCN: SGE00288 26 Figure 4

- 13 . Well h eads of James Barrett 1H and 2H

Figure 4

- 14 . Solar

- Powered Methanol Tank and Injector

Figure 4

- 15 . Water/Gas Separators ( R ight) and GPUs ( L eft)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

emp ty 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 stil l visits the site daily to ensure all equipment is properly working.

Figure 4

- 16 . Produced Water Storage Tanks

Table 4

- 1 and Table 4

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

, downloaded fro m 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

com pared 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 (1 st half) 140 1,303,306 9,309

-- 4,103 12.8 2010 (2 nd half) 181 1,065,722 5,888 37

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

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

Totals 686 3,277,578 4,778 a 80 b 5,468 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

. b bl s

— B arrels.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 (1 st half) 135 1,327,798 9,836

-- 2,335 7.4 2010 (2 nd half) 181 1,462,346 8,079 18

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

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

Totals 679 5,125,455 7,549 a 43 b 3,968 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.
Mcf s

— Million cubic feet

. b bl

— B arrels.

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 r ecycling 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.

P roduced water in the northern Marcellus contains much higher levels of TDS and TSS than
initial flowback 1 water and is treated before reuse. According to PA DE P, this facility operat es under permit number WMGR123NC004.

Chesapeake does not typically treat flowback 1 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 flowback 1

water , in contrast to produced water from production , typically contains relatively low TDS and
TSS concentrations. Chesapeake reuse s most of its flowback 1 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 flowback 1 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 unconvention al 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 perio d. 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 form ation is a tight oil formation similar to shale oil (American Gas Reporter, (2011). Available online at http://superioroilandgas.com/mississipp i

- limestone

- emerging

- as

- top

- flight

- horizontal

liquids

- 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 dril ling mud are stored sepa rately.

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 wa ste to a hazardous landfill. The treated mud (i.e., water

- based fluid
described in S ection 3.5 ) i s 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.

P roduced 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 direc tly into reuse tanks (green tanks in Figure 4

- 18 )

. F rom 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.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 FacilityDCN: SGE00288 APPENDIX A
LIST OF PARTICIPANTS ON THE CHESAPEAKE SITE VISITDCN: 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. J an@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 Schro e der. Cuc @epa.gov

Erik Helm U.S. EPA, SGE Economist (202) 566

- 1049 Helm. E rik@epa.gov

Richard Witt U.S. EPA, OGC (202) 564

- 5496 Witt. R ichard@epa.gov

Jennifer Hoffman Chesapeake Energy Corp.,

Manager

– Regulatory
Affairs (405) 935

- 6818 Jennifer. H offman@chk.com

Troy Jordan Chesapeake Energy Corp.,

Senior Environmental Specialist (405) 935

- 4503 Troy. J ordan@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. H ammontree@chk.com

Meghan Camp ERG , Senior Chemical

Engineer (703) 633

- 1684 Meghan. C amp@erg.com

Brent Ruminski ERG , Energy Engineer (703) 633

- 1701 Brent. R uminski@erg.comDCN: SGE00288 APPENDIX B
INFORMATION PROVIDED BY CHESAPEAKEDCN: SGE00288 APPENDIX C
MAP OF SITES VISITEDDCN: SGE00288 C

- 1

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

Figure C

- 1. Overview of Sites Visited in ArcGISDCN: SGE00288 APPENDIX D
SUMMARY OF COSTS PROVIDED BY CHESAPEAKEDCN: 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]