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Texas Creek Oriskany Sandstone Reservoir

Characterization: Final Report

Submitted To: Paul Dudenas, East Resources, Inc.

Date Delivered: 4/27/10

Prepared By: Pure Energy Consultants, LLC.

Michael Cronin Zachary Fidurko Matt Minemier Naser Saleh

Reservoir Engr. Petrophysical Engr. Surface Engr. Production

Engr.


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Executive Summary

East Resources, Inc. commissioned Pure Energy Consultants, LLC four months ago to

perform a reservoir characterization of the recently acquired Texas Creek Oriskany Sandstone

Gas Reservoir in the Appalachian Basin. PEC interpreted the reservoirs structure as an upthrust

asymmetric anticlinal block with a fold axis trending ENE. The reservoir terminates North and

South by thrust faults, and is conservatively modeled as terminating in the West by a thrust fault

boundary. There is limited data defining the nature of the reservoir to the East, so PEC has

considered three structural representations; 1) a conservative 4-Way closure, 2) an intermediate

3-Way Closure, and 3) an open 3-Way Closure to provide a basis for volumetric calculations.

The Texas Creek Field is represented using a 78 x 30 grid block model of 339ft x 339ft

cells populated using MATLAB and Excel to linearly interpolate between control points from

well log analysis and linearly extrapolate to PEC defined boundary conditions consistent with

available field data and appropriate extensive reservoir properties from analog Appalachian

Basin fields (Leidy, Tioga). Well-averaged porosity is 7.40% and well-averaged thickness of the

Oriskany is 178ft. Using the most conservative isopach model, recovery factor of 60%,

boundary porosity of 8%, water saturation of 25%, formation volume factor of .00295cu ft/scf,

the recoverable gas in place is estimated to be 134Bcf.

The drilling development plans that were created, for a non-specific location, includes

vertical, direction and horizontal drilling recommendations. For each well type we examined:

drilling muds, bit types, casing selections, cements as well as production optimization. Also a

relative economic analysis was employed as market prices fluctuate with the economy.

In summary, the preliminary drilling evaluation by PEC indicates that due to the reservoir

characteristics vertical or directional wells would be the best. Economic development of the field

as a gas producer is possible, and the probability of the Texas Creek field being used as a natural

gas storage reservoir for Marcellus Shale gas will be high. However, PEC must stress that these

results are preliminary, but the methods employed are conservative to safeguard versus risk but

flexible enough to properly exploit favorable conditions.


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Table of Contents

Executive Summary...1

Introduction. 4

Reservoir Overview4

Reservoir Model..5

Results and Discussion.6-17

Summary and Conclusions18


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Introduction

The purpose of this report is to provide East Resources Inc. with drilling plans for

vertical, directional, and horizontal wells in the Texas Creek Field, with the ultimate goal of

commenting on the economic value of each well. Included in the PEC analysis is a full

description of models used and assumptions employed, along with commentary on uncertainty in

the available data and strategies to reduce development risks.

Reservoir Overview

The formation of exploratory and commercial interest in this reservoir characterization

study of the Texas Creek Field is the Lower Devonian Oriskany Sandstone. This sandstone was

deposited in the Appalachian Basin ~400Mya in a storm dominated marine shelf depositional

system and is heavily fractured and deformed as a result of subsequent tectonic deformation

events due to the Oriskanys location in the Appalachian Fold and Thrust Belt (Appalachian

Basin Province Ryder, RT).

The reservoir is interpreted as an upthrust anticlinal dome with a fold axis trending East-

North-East (Figure 1). The anticline is bound on the Northern and Southern edges by thrust

faults based on the stratigraphic omission in map pattern and the regional geology (Roen and

Walker, 1996). Limb dip is asymmetric, and the Northern limb dips more steeply than the

Southern, consistent with other structural observations for in the Appalachian Fold and Thrust

Belt.


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Figure 1. SSTVD structure map of East Texas Field, North upwards. Courtesy of East Resources.

Reservoir Extensive Properties and Analog Reservoirs

To properly model the reservoir for the purposes of gas in place calculations, extensive

reservoir properties such as recovery factor, water saturation, average porosity, permeability

anisotropy ratio, etc were needed. In the absence of this information directly from the providedTexas Creek Field data, it became necessary to find a field similar to Texas Creek for purposes

of providing insight into the above mentioned extensive reservoir properties. The two analog

fields used for the reservoir characterization were the Leidy Field and the Tioga Field and were

selected on the basis of structural (limb dip, structural grain, fault orientation), pore pressure

gradient, temperature, AOF, gas composition, thickness, and formation similarities to Texas

Creek field (Roen and Walker, 1996), (Figure 12).


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Figure 2. Map of two analog fields. Note NE and ENE structural trend of fields. After Boen and Walker, Atlas of

major Appalachian gas plays: West Virginia Geological and Economic Survey Publication V-25, Gas Research

Institute 1996.

1) Atlas of major Appalachian gas plays: West Virginia Geological and Economic Survey Publication V-25, Gas

Research Institute 1996, Edited by John B. Roen and Brian J. Walker"

2) Water saturation values after Paul Dudenas, East Resources, personal communication, 2010.

Results and Discussion

Determination of Pore Pressure and Fracture Pressure

Accurate determination of expected pore pressure and fracture pressure profiles with

depth is crucial in the safe and efficient development of wells. Understanding the pore pressure

and fracture pressure gradients permits selection of appropriate mud weights to avoid kicks or

formation fracture in addition to the optimum number of casing runs.


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For the purposes of this analysis, data from well logs and drilling reports for the Graham

#2 well were taken to be representative of a hypothetical well designed to be drilled in the Texas

Creek Field. While this method is limited in its absolute predictive capabilities, it is useful as an

observational and planning tool.

Fracture pressure is a function of pore pressure, overburden pressure, and the poisson

ratio of rocks. There are numerous methods to calculate fracture pressure, but only the following

techniques were considered (EQ 1 -3).

Fmin = 1/3 * (1 + (2P/D)) (1) Hubbert and Willis Min

Fmax= * (1 + P/D) (2) Hubbert and Willis Max

F = (( SP)/D) * ( / (1- )) + P/D (3) Ben Eatons Method

Where:

P = Pore Pressure (psi) S = Overburden Stress (psi)

D = Depth (ft) = Poissons Ratio [ -]

Values from the Bulk Density and Sonic Logs were sampled every 250ft and used to

record overburden gradient (psi/ft), pore pressure gradient (psi/ft), and calculate poissons ratio.

Poissons ratio is calculated through EQ 4, which relates poissons ratio to the compressional and

shear wave slownesses, TC and TS (Appendix).

= [ 0.5*(TS/ TC)2

-1) /[(TS/ TC)2

-1) (4) Dewan Essentials of modern

open hole logging

When Sonic log coverage was not available, a typical poissons ratio of 0.25-0.3 was

used based on log lithology. Pore pressure gradient was assumed to equal 0.47 psi/ft by East

Resources. Since this assumption is unrealistic given pore pressure gradients exceeding 0.6psi/ft

in the Oriskany, a synthetic pore pressure curve was created by converting mud weights used in


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drilling to equivalent pressures and equivalent mud weights (EMW). Plots of the pore pressure

and fracture pressure vs depth are included in both psi and EMW space (Figures 1 and 2).

Figure 1. Pore pressure and fracture pressure profiles for Graham #2 well. Dotted portion of

pore pressure curve indicated pore pressure values taken from drilling fluid EMWs. Note the

increase in mud weight (pore pressure) in anticipation of the Marcellus and Oriskany

Formations.

0

1000

2000

3000

4000

5000

6000

7000

8000

0 1000 2000 3000 4000 5000 6000 7000 8000

Depth

(TVD)

Pressure (psia)Pore Pressure and Fracture Pressure

Pore Pressure

Ben Eaton Fracture

Hubbert & Willis Min

Hubbert & Willis Max

Field Mud Pressure


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Figure 2. Pore pressure and fracture pressure profiles for Graham #2 well plotted as equivalent

mud weight (EMW) vs depth (ft KB). Dotted portion of pore pressure curve indicated pore

pressure values taken from drilling fluid EMWs. Note the increase in mud weight (pore

pressure) in anticipation of the Marcellus and Oriskany Formations.

It is observed that the Ben Eaton method predicts a fracture pressure estimate that is

intermediate with respect to the Hubbert and Willis predictions (EQ 1 and EQ 2). For the

purposes of this study, the Ben Eaton Method is used in the determination of casing runs and

drilling fluid schedule.

We started by modeling a vertical well with a true vertical depth of 7500 feet. We did this

by examining the well data provided. Majority of data was taken from Graham II and used as a

0

1000

2000

3000

4000

5000

6000

7000

8000

0 5 10 15 20 25

Depth

(TVD)

Equivalent Mud Weight (PPG)

Pore Pressure and Fracture Pressure EMW

Pore Pressure

Ben Eaton

Fracture

Hubbert &

Willis Min

Hubbert &Willis Max

Field Mud

Pressure


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base for the entire drilling plan. We understand that there is error in this assumption due to

anticlines and other reservoir characteristics that are not analogous with the Graham II this will

be taken into consideration throughout the drilling process.

The next step in our modeling process was designing our casing strings. Based on the

pore pressure and fracture gradient curves analysis we knew how many casing strings were

required. Our data indicated that only two strings were needed. The first string, which is

designed to protect natural underground aquifers from potential contamination, was cemented in

at 1250 feet. This allowed us to use a 12-1/4 inch air hammer bit to drill to this depth. Using air

as our drilling fluid increases the rate of penetration while reducing cost. The casing that we

chose was P-110, which has a weight of 43.5 pounds per foot, over J-55. Examining Table 1 you

can see the comparisons between P-110 and J-55 for varying diameter sizes. P-110 provides

higher burst, collapse, and tensile strength. To calculate these strengths we used the following

three formulas.

Casing Weight Diameter Burst (psi) Collapse (psi) Tensile (lb/ft)

36 # 9-5/8" 3520 2020 3636428

23 # 7" 5280 3270 3636428

10.5 # 4-1/2" 6081 4010 3636428

43.5 # 9-5/8" 8700 4419 83040126 # 7" 9955 5900 830401

13.5 # 4-1/2" 16275 10670 830401

J-55

P110

= 0.875(2

)

= (

)

=

4(

2 2)

Equation 1- Burst Pressure

Equation 2- Collapse Pressure

Equation 3- Tensile Force

Table 1


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After deciding on the type of casing to run as well as size of wellbore we next examined

how much cement is required using Equation 4. We used class A because it is the cheapest and

most commonly used in the Appalachian basin. Due to our low reservoir temperature class A can

withstand the Oriskany.2 2

09.4

For the vertical well surface casing we calculated that 334 sacks of cement would be required.

Equation 4 gives results in barrels; which was then converted to cubic feet. In order to calculate

how many sacks were required we calculated a yield factor of 1.17. Of course more cement

would be needed due to some lost in circulation among other factors. The production string,

which is the 7 inch P-110, 26 pounds per foot, would run from surface to TD. We calculated that

559 sacks of class A cement would be required. We also examined some additives that could be

potentially added to our cement depending on the environment and what is required.

The basic additives we chose to examine:

Bentonite- is a clay for building drilling fluid viscosity, lowering cement density andlowering slurry costs.

Cement Retarders- tend to reduce setting time of cement slurries.o Examples: Organic acid with calcium lignosulfonate, Calcium-sodium

lignosulfonate, decahyrate.

Filtration Control- Serves a similar function as mud filtrate controls.o Examples: Latex, bentonite with a dispersant, CMHEC.

The next string of casing that was run for the vertical well went to 7500 feet. The characteristics

of this string are: P-110 with 7 inch diameter, with a weight of 26 pounds per foot. This part of

the well could most likely be drilled with an air rig as our pressure curves indicate. The air

hammer bit we used was based off the drilling reports for the Graham II.

Equation 4


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We next created a model for a directional well. We were given a target that we had to

reach for this well. We assumed we were drilling from the corner of a 40 acre plot and had to

reach the middle by the time we reached our true vertical depth. The target was 933 feet from the

corner which is where our well was located. This well has a lot more flexibility in the design as

our kick off point would depend on where the well was drilled along with what formation the bit

is in at the time.

Like the vertical well we ran two strings of casing. One went to our KOP while the other string

goes to TD. Because the vertical and direction wells are very similar we were able to use similar

characteristics for both wells. Our directional well was based on a build hold and drop well. We

designed our KOP to be at 1300 feet; which is where our first string, which is designed to

protect natural underground aquifers from potential contamination, was cemented in at 1300 feet.

This allowed us to use a 12-1/4 inch air hammer bit to drill to this depth. Using air as our drilling

fluid increases the rate of penetration while reducing cost. The casing that we chose was P-110,

which has a weight of 43.5 pounds per foot, over J-55.

The following section describes the selection of well geometries (dog leg severities, arc

lengths, horizontal departure, etc). For the purposes of brevity, SPE Textbook Series Vol 2:

Applied Drilling Engineering was consulted for the geometric relationships and equations of

drilling trajectories.

Figure 3- Graham II Drilling Report


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For the purposes of this exercise, the following constraint (Figure 1) was used in the

design of the directional well (Wang, JY. 2010 Personal Communications). The well must be

drilled from the NW corner to the center of a 40 acre block with the target TD of 7500.

Figure 4. 40 acre plot, with target at center and TD = 7500.

For simplicity, a symmetric build and hold drop S directional well was chosen with

radius 450, maximum inclination angle = 20 degrees, and dog leg severity of 12.7deg/100. A

cross sectional view of the well trajectory looking NE is provided (Figure 5).

1320f

t

660

660

TD = 7500

KB


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Figure 5. Looking NE at build and hold drop S symmetric directional well. Key values noted.

Similar to the vertical well we decided to use class A cement. For the same reasons stated

above and with the possibility to add the same additives. For the cementing of the 9-5/8 sting

370 sacks would be required. The production string, which is also 7 inch P-110 with a weight of

26 pounds per foot, would run from surface to total depth. The annular capacity will require 350

sacks of Class A cement. These values were calculated using equation 4 similar to calculations

with vertical model.


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The final well design that we created was of a horizontal well. Up until our KOP the

design is very similar to that of vertical. This design required three strings of casing, the surface

casing, intermediate casing, and production casing. We designed our KOP to be at 6680 feet. Our

first string would go to the depth of 1250 feet in order to protect natural underground aquifers

from potential contamination; it was cemented in at 1250 feet. This allowed us to use a 12-1/4

inch air hammer bit to drill to this depth. Using air as our drilling fluid increases the rate of

penetration while reducing cost. The casing that we chose was P-110, which has a weight of 43.5

pounds per foot, over J-55.

Our intermediate string is 7 inch P-110 with a weight of 26 pounds per foot, and set at a

depth of 6000 feet. This is right at our KOP and just above the Marcellus. This was done so that

we could switch the drilling fluid to mud to avoid kicks, also it allows us to kick off in the Tully

Limestone. This helps us maintain wellbore integrity while minimizing fluid loss. This string

would require 137 sacks of Class A cement. Our production string is 4-1/2 inch P-110 with a

weight of 13.5 pounds per foot, and set at a depth of 10966 feet. This string will run horizontally

through the Oriskany. This string would run from surface to total depth and would require 937

sacks of Class A cement. For our production sting we realize that liners could also be a

possibility and that this zone would require perforations.

The horizontal well was designed to reach a TD of 7500. In the absence of production data and

rigorous reservoir simulation, a lateral length of 3000 was arbitrarily selected. Future workmay

certainly may refine this length. The dog leg severity of 7deg/100 is consistent with those

observed already in Texas Creek (Shepard #1). Kick off point was chosen to kick off in

competent Tully Limestone. A cross section of the well trajectory is included (Figure 6).


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Figure 6. Directional well trajectory.

For our vertical, directional and horizontal wells we chose to use fresh water mud. Table

2 shows mud capacities for vertical, directional, and horizontal. We realize that more mud would

be required to have on location in case of loss circulation and to maintain proper well control.

We chose fresh water mud due to it being less expensive than other oil based muds, and it is the

most commonly used type of much in the Appalachian basin due to low reservoir temperatures.

There are a variety of additives that could potentially use with our drilling mud depending on

drilling environment. The most common type of additive is lost circulation control which

prevents fluid loss and the build up of mud cakes on the borehole walls and example of this is

Nut Shell.


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During our bit selection process, we looked over the formation of the area from the

Appalachian Basin Province. The primary reservoir is the Oriskany sandstone, which is a quartz-

rich, calcite and silica-cemented, fine to coarse-grained sandstone sequence. Also, we calculated

the ROP of all DelCiotto #1, DelCiotto #2 and Graham #2 from the daily report that was locatedunder the Field data folder. After doing so, it was decided that the best bit to use was the PDC bit

because of the information retrieved. Also, we believed that it would be the most effective in

terms of economics and time. Though it can drill through harder formations, the PDC bit is most

affective against weak formation which in our case gives us the advantage because the formation

was found to be medium to medium hard. A PDC bit has a much better resistant than both a steel

and tungsten carbine bit which is why it can be used to drill in three or more wells. It is proven to

be the most economical alternative in many drilling scenarios and we believe it will be an asset

towards drilling here.

Vertical

Depth (ft) Capacity (bbls)

TVD (7500) 526

DirectionalDepth (ft) Capacity (bbls)

KOP (1300) 116.98

TD (7660) 552.1

Horizontal

Depth (ft) Capacity (bbls)

KOP (6680) 446

Landing Pt (7966) 493

TD (10966) 602

Table 2

=

Equation 5


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Summary and Conclusions

Pure Energy Consultants, LLC has developed three drilling designs based on the

characteristics of the Texas Creek field. The drilling designs were created for a vertical,

direction, and horizontal well within the field. The main focus areas were pore and fracture

pressure gradients, casing design, bit selection, cements and drilling fluid. Based on our research

we believe that either vertical or directional well should be drilled if infill drilling is to take

place. This is due to high expenses with horizontal with minimal extra recovery. Economic

evaluation of each well was extremely hard to do due to a large fluctuation in pricing depending

on economy and company. We used an air rig to drill till KOP largely due to economic factors

and the high rate of penetration that an air hammer provides. After KOP we would switch to

freshwater based mud. Our casing strings go down from 9-5/8 surface casing to 7 intermediate

casing and the horizontal casing is 4-1/2. We used P-110 casing for all of the strings to reduce

cost and improve wellbore stability. We used Class A cement for all of our cementing jobs as it

reduces cost and can withstand the temperatures. We understand that there are a variety of

additives for drilling fluid and cement however they are largely added depending on drilling

environment. The basic additives we would add are bentonite, fluid lose, retarders.

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