enpe 511 final report

Tight Gas Optimization

Eric Hayhurst

Rahmah Alawami

Haneen Alhaddad

Mmakeng John Otsweleng

Supervised by:

Dr, Roberto Aguilera

12/08/2015

ENPE 511: Design for Oil

and Gas Engineers I

Acknowledgments We would like to thank Dr. Roberto Aguilera (University of Calgary) and Dr. Harvey Yarranton

(University of Calgary) for their advice and support during the completion of this project.

Executive Summary:

As the world advances and technology develops, the requirement for large amounts of clean,

natural gas is expected to skyrocket. To meet this demand, energy firms will have to look beyond

typical conventional reservoirs and towards other resources. Though this idea may at first seem

perplexing, there is actually another bountiful solution to the worlds increasing energy needs,

located deep below the subsurface. These are known as unconventional tight gas reservoirs.

Formations such as these are known to contain very large volumes of gas in place. Therefore,

optimizing and exploiting these tight gas reservoirs will be the key to success in the future.

This project focuses on two tight gas reservoirs of the Western Canada Sedimentary Basin.

Known as the Cadomin and Nikanassin, these formations are classified as a special type of

unconventional reservoir; a Continuous Accumulation. Often produced in a comingled manner,

they present low permeabilities, often less than 0.1mD, but high amounts of sweet gas. These

regions also present a wide array of natural fractures, predominantly in the lateral direction. In

this study, a single region, located in township 65, range 8, west of the 6th meridian, is analyzed.

This is located within the Western Canada Sedimentary Basin’s deep basin.

This report serves two major purposes. The first is to understand the geological aspects and

characteristics of these tight gas reservoirs. Analysis of the log data from 12 well locations

within these regions shows that the Cadomin and Nikanassin present porosity values of 4.94%

and 4.86% respectively. The permeabilities of these region are 1.3mD for the Cadomin, and

0.5mD for the Nikanassin. These are close to the expected 0.1mD value. Volumetric and material

balance methods were used to show that the volume of gas within the formations reaches a

combined amount of around 9.0x108 m3. These regions have therefore been proven to contain

massive gas reserves. However, the recovery factor in the area is low, due to the irregular

permeability and pressure distribution. New advances must be discovered to obtain the resource.

This leads to the second purpose of the report; to optimize the production rates of gas from

within the Cadomin and Nikanassin regions. A selection of 7 producing wells was used to

determine 4 different type wells within the region. Some of the well locations have reached a

boundary condition. Others are producing under linear or bilinear flow, due to the natural

fractures of the formations. In order to obtain any flow, these formation must be hydraulically

fractured. A total of three optimization methods were considered for this project. The first was to

drill three new infill wells a year, for a total of five years. Another possible, and more

economical optimization method for this project was to reperforate and fracture a single well,

which was still producing under bilinear conditions. If both of these methods proved to be

profitable, a combination method would be considered. From analysis of the Net Present Worth

of the project, it was determined that the reperforation and fracturing method was the only one of

the three suggestions to produce a profit. In specific, a four stage fracture job was seen to provide

the highest income, $1,011,087.60, of all optimization methods. This profit margin is higher than

the $733018.52 earned from the base case method. Therefore, the best method for optimization is

to reperforate and fracture any wells in the region under linear or bilinear flow. This method will

be more economic then the base case unless gas prices reduce to under 90% of the current value.

Table of Contents 1. Introduction ............................................................................................................................. 1

1.1: Reservoir Overview .......................................................................................................... 1

1.2: Continuous Accumulation ................................................................................................ 1

1.3: Reservoir Location ........................................................................................................... 2

1.4: Wells ................................................................................................................................. 2

1.5: Pool History ...................................................................................................................... 3

1.6: Producing Wells ............................................................................................................... 4

1.7: Enhanced recovery methods ............................................................................................. 4

1.8: Existing Facilities ............................................................................................................. 5

2. Reservoir and Fluid Characterization ...................................................................................... 6

2.1: Basin Description ............................................................................................................. 6

2.2: Cadomin Geology ............................................................................................................. 7

2.3: Nikanassin Geology.......................................................................................................... 7

2.4: Drive Mechanism ............................................................................................................. 9

2.5: Production and Pressure Analysis .................................................................................... 9

3. Log Interpretation .................................................................................................................... 9

3.1: Readings ........................................................................................................................... 9

3.2: Water Resistivity .............................................................................................................. 9

3.3: Cutoffs .............................................................................................................................. 9

3.4: Shale Volume ................................................................................................................. 10

3.5: Porosity ........................................................................................................................... 10

3.6: Water Saturation ............................................................................................................. 10

3.7: Log property averaging .................................................................................................. 13

3.8: Net Pay ........................................................................................................................... 14

3.9: Interpolated well results ................................................................................................. 14

4. Core Data............................................................................................................................... 15

4.1: Core Analysis: ................................................................................................................ 15

4.2: Core vs. Log porosity ..................................................................................................... 26

4.3: Permeability determination ............................................................................................ 27

4.4: Comparison of Permeability calculation methods .......................................................... 29

4.5: Permeability averaging ................................................................................................... 30

4.6: Capillary Pressure ........................................................................................................... 30

5. Reservoir Fluid Properties ..................................................................................................... 30

5.1: Pressure-Volume-Temperature (PVT) Data ................................................................... 30

5.2: Gas Properties Correlations ............................................................................................ 30

6. Mapping ................................................................................................................................ 31

6.1: Topography Maps ........................................................................................................... 31

6.2: Gross thickness Maps ..................................................................................................... 31

6.3: Net Pay Maps: ................................................................................................................ 32

6.4: Cross Sections ................................................................................................................ 32

6.5: Bubble Maps ................................................................................................................... 33

7. Reserve Estimates ................................................................................................................. 34

7.1: Volumetrics .................................................................................................................... 34

7.2: Material Balance ............................................................................................................. 34

8. Production Forecasting .......................................................................................................... 35

8.1: Production History.......................................................................................................... 35

8.2: Reservoir Flow Characterization .................................................................................... 36

8.3: Analytical Decline Analysis ........................................................................................... 43

8.4: Flowing Material Balance .............................................................................................. 52

9. Optimization analysis: ........................................................................................................... 53

9.1: Optimization Methods .................................................................................................... 53

10. Infill drilling – Project Components: .................................................................................. 54

10.1: Horizontal Drilling ....................................................................................................... 54

10.2: Fracturing ..................................................................................................................... 57

10.3 Dry Gas Facilities .......................................................................................................... 63

10.4: Stress Map .................................................................................................................... 63

10.5. Capital Expenses: Drilling Costs .................................................................................. 64

10.6. Capital Expenses: Completion Costs ............................................................................ 72

10.7. Capital Expenses: Other drilling and completion expenses ......................................... 76

10.8: Capital Expenses: Gas Facilities .................................................................................. 78

10.9: Total Capital Expenses ................................................................................................. 79

11. Reperforation and Fracturing – Project Components .......................................................... 80

11.1: Perforating .................................................................................................................... 80

11.2: Fracturing ..................................................................................................................... 80

11.3: Capital Expenses .......................................................................................................... 81

11.4: Total Capital Expenses ................................................................................................. 82

12. Economic Analysis .............................................................................................................. 83

12.1: Base Case Analysis....................................................................................................... 83

12.2: Infill Drilling Economic Analysis ................................................................................ 83

12.3: Re-Perforation and Fracturing Economic Analysis ...................................................... 84

12.4: Drilling, Re-Perforation and Fracturing Economic Analysis ....................................... 85

12.5: Economic conclusions .................................................................................................. 85

13. Sensitivity Analysis ............................................................................................................. 85

13.1: Infill drilling sensitivity ................................................................................................ 85

13.2: Abandonment Considerations ...................................................................................... 88

14. Conclusion ........................................................................................................................... 89

Bibliography .............................................................................................................................. 91

Appendix A: Nomenclature ...................................................................................................... 95

Appendix B: Maps and Diagrams ............................................................................................. 96

Appendix C: Well Information ................................................................................................. 99

Appendix D: Well Logs .......................................................................................................... 102

Appendix E: Cross Plots ......................................................................................................... 139

Appendix F: Log Interpretation............................................................................................... 145

Appendix G: Core Information ............................................................................................... 148

Appendix H: Capillary Pressure .............................................................................................. 163

Appendix I: Reservoir Fluid Properties .................................................................................. 165

Appendix J: Maps and Cross Sections .................................................................................... 169

Appendix K: Reserves Estimates ............................................................................................ 180

Appendix L: Production Forecasting ...................................................................................... 181

Flowing Material Balance ................................................................................................... 193

Appendix M: Economic Analysis ........................................................................................... 194

Appendix N: Sensitivity Analysis ........................................................................................... 211

Appendix O: Gantt Chart ........................................................................................................ 216

List of Figures

List of Figures

Figure 1: Diagram highlighting the differences between conventional reservoirs and Continuous

Accumulations (USGS, 2002)………………………………………………….…….….……….1

Figure 2: Map of the Western Canada Sedimentary Basin …………………………..…….……2

Figure 3: Existing Facilities and Pipelines Within Township 65-08W6………………………....5

Figure 4: Location of the Township within Alberta. Based on this location, township 065-08W6

is seen to be a member of the Alberta Foothills…………………………………….....................6

Figure 5: Modified Pickett Plot for all wells. They follow the first distinctive trend, with

m=2.2422, and a=0.5282………………………………………………………………….….…11

Figure 6: Modified Pickett Plot for all wells following the second distinctive trend, with

m=1.9455, and a=0.5282……………………………………………………………….……….12

Figure 7: Locations of the wells in each Pickett trend……………………………………….…12

Figure 8: Full core intervals for box 1 and 2 respectively. Core samples originate from well

00/12-32-065-08W6………………………………..…………………………………………..16

Figure 9: Grain size distribution in the first core box………………………………….………17

Figure 10: Analysis of a core piece for well 00/12-32-065-08W6. Potential fracture zones are

marked………………………………………………………………………………………....18

Figure 11: Core sections from well 00/11-09-068-

08W6………………………………………………………………….…….…………………19

Figure 12: Log data of the cored interval shows a gamma ray spike and increasing neutron

porosity…20

Figure 13: Core cross section and core face samples within the region of well 00/11-09-065-

08W6 show significant horizontal

fracturing……………………………………………………………………………….……..20

Figure 14: A water beading test was performed on a core section from well 00/11-09-065-

08W6……………………………………………………………………………………….…21

Figure 15: Different gamma ray responses in the cored interval determined the analyzed

regions…21

Figure 16: Core sections from well 00/11-09-068-

08W6…………………………………………………………………………………………22

Figure 17: A water beading test was performed on sections at the top of the core from well

00/10-29-065-

08W6……………………………………………………………………………...………….23

Figure 18: Analysis of a broken core section showed the presence of parallel

laminations……………………………………………………………………………...……23

Figure 19: Core sections from well 00/11-09-068-08W6. The twelfth (pictured left) and

thirteenth (pictured right) core boxes are

shown……………………………………………………………………...…………………24

Figure 20: A section of the core from box 13 of well 00/10-29-065-

08W6……………………………………………………………………………..…………..25

Figure 21: Pore throat aperture for all available cores in the township. This relationship uses

maximum horizontal permeability…………………………………………………….……..27

Figure 22: Pore throat aperture for all available cores in the township. This relationship uses 90⁰

horizontal permeability………………………………………………………………………27


vertical permeability…………………………………...……………………………………28

Figure 24: Plot of Material Balance equation of P/Z versus cumulative

production…………………………………………………………………………...………34

Figure 25: Well 12-32-065 has 3 distinct slopes indicating the change in flow type as time

increase……………………………………………………………………………….....…..36

Figure 1: Well 08-22-065 has a slope of -0.515 which is characteristic of formation linear flow

and a slope = -2.665 indicating that the boundary was reached at 70th month, September

2005………………………………………………………………………………….……..37

Figure 27: Well 14-11-065: has slopes -0.5 for linear flow until 18th month (April 2007) and

slope = -0.301 from 20th month (June 2007) until recent production. The recent flow behavior is

characteristic of bilinear

flow……………………..…………………………………………………………………38

Figure 2: Well 15-13-065: has slope = -0.5 until the 32nd month (August 2003) then BDF

flowed…………...…………………………….…………………………………………..38

Figure 29: Shows estimated natural fractured zones in well 14-11-

065…………………………………………………………………………………...……39

Figure 3: Well 09-34-065 shows a long period of formation damage until it reaches BDF at 28th

month ..…………………………………………………………… ………………………41

Figure 31: Well 07-21-065 shows transitional behavior from linear flow to

BDF………………..……………………………………………………………….……..42

Figure 4: Well 13-30-065 shows transitional flow behavior therefore the flow is approaching

BDF……………………………………………………………………………………….42

Figure 5: Determination of exponential decline equation constants for Well 14-11-

065………………………………………………………………………………..……….44

Figure 6: Illustration of production forecast and production history for well 14-11-

065…………………………………………………………………………………...….44

Figure 7: Determination of exponential decline equation constants for Well 12-32-

065……………………………………………………………...………………………..44

Figure 8: Illustration of production forecast and production history for well 12-32-

065………………………………………………………………...………………….….45

Figure 9: Illustration of pool production forecast and production history……....….….46

Figure 10: Crossplot shows the flow types for the pool………………...….……..….….46

Figure 11: The recoverable gas reserves in our pool by production history and extrapolated by

exponential decline method …………………………………………………………..…47

Figure 12: The recoverable gas reserves in our pool by exponential decline method..47

Figure 13: Illustration of type well 1 production forecast and production history……...49

Figure 14: Illustration of type well 2 production forecast and production history...……49

15: Illustration of type well 3 production forecast and production history……………...50

Figure 16: Illustration of type well 4 production forecast and production history………50

Figure 45: Shows the position of the type wells in our target zone. The dashed circles shows the

apparent magnitude of the radius drainage for the

wells……………………………………….…….…….…….…….……………..………51

Figure 46: Plot of Flowing Material Balance equation of wellhead pressure versus cumulative

production........................................................................................................ …..............52

Figure 47: Comparison between vertical and horizontal

wells……………………………….….…….…….…….…….…….…….………………54

Figure 48: The four main horizontal drilling configurations……………………………..56

Figure 49: Comparison of drilling and completion costs for vertical and horizontal wells

.… ….…….…….…….……….…….…….…….……….…….…….……….……….….57

Figure 50: Schematic of a hydraulic fracture. Note that the fracture opens up parallel to the

minimum stress………………………………………..…………………………………58

Figure 51: Results of the Multistage fracture test performed within the Western Canada

Sedimentary Basin……………………………………………………………………….59

Figure 52: Relationship between formation permeability and number of fracture stages for a tight

gas reservoir……………………………………………………………………………..60

Figure 53: Cumulative production of a reservoir over increasing fracture half

lengths……………………………………………………………………………….…..60

Figure 54: Comparison between fracture half length and cumulative production....…….61

Figure 55: Proppant concentration per unit of volume (in lbm/gal) for the stages.….…..62

Figure 56: Common dry gas facility diagram (Gas Battery Diagram)…………..….……63

Figure 57: Stress Map of the Western Canada Sedimentary basin………………………64

Figure 58: The learning curve associated with a horizontal drilling

job………………………………………………………………………………………72

.Figure 59: Tornado Chart for the one year infill drilling project. From this figure, it is clear that

the Capital and Variable field expenses have the larges effect on the Net Present Worth for the

project.. ……………………………………………………………………………...…87

Figure 60: Spider chart extrapolation showing the capital expense required for the project to

break even…………………………………………………………………….……..…88

Figure 61: Map showing the location of the designated

township………………………………………………………………………………..95

Figure 62: Regional Boundaries of the Deep Basin, located within the Western Canada

Sedimentary……………………………………………………………………………96

Figure 63: Map of township 65-08W6. The wells selected for analysis are marked in

red………………………………………………………………………..…………….97

Figure 64: Well cards for the 12 selected wells in the township………..……………..98

Figure 65: Wellbore Schematic 00/14-11-065-

08W6………………………………………………………………………………….100

Figure 66: Sample log from well 00/09-34-065-08W6. This well does not penetrate the entire

Nikanassin formation…………………………………………...…………………….102

Figure 67: Well Log for Well 00-07-21-65-08W6 obtained from

Accumap………………………………………………………………………..…….103

Figure 68: Porosity, Water Saturation and Permeability Logs that were built by analyzing the

logs for the Cadomin Formation. This figure shows the logs made for well 00-07-21-65-

08W6…………………………………………………………………...…………….104


logs for the Nikanassin Formation. This figure shows the logs made for well 00-07-21-65-

08W6………………………………………………………………………………...105

Figure 70: Well Log for Well 00-13-30-65-08W6 obtained from Accumap…….....106



08W6……………………………………………………………………………..…107


logs for the NIikanassin Formation. This figure shows the logs made for well 00-13-30-65-

08W6……………………………………………………………………………..…108


Accumap……………………………………………………………...……..………109



08W6……………………………………………………………………...……..….110



08W6……………………………………………………………………………….111


Accumap…………………………………………………………….……..………112



08W6……………………………………………………………………..…...……113



08W6………………………………………………………………………..…...…114


Accumap……………………………………………………………..…..…………115



08W6…………………………………………………………………..……..…….116



08W6………………………………………………………………...……..………117


Accumap……………………………………………………………..…………….118



08W6…………………………………………………………………..…………..119



08W6…………………………………………………………………..….……….120

Figure 85: Well Log for Well 00-03-07-65-08W6 obtained from Accumap. ….…121



08W6…………………………………………………………..…………………..122



08W6……………………………………………………………..…………..……123


Accumap………………………………………………………..………………….124



08W6………………………………………………………..………………….….125



08W6………………………………………………………………………..…….126


Accumap…………………………………………………..………………………127



08W6………………………………………………………………………….…..128

Figure 93: Porosity, Water Saturation and Permeability Logs that were Built by analyzing the


08W6…………………………………………………………………………..…129


Accumap……………………………………………………...…………………..130



08W6……………………………………………………………………………..131



08W6……………………………………………………………………..………132

Figure 97: Well Log for Well 00-05-06-65-08W6 obtained from Accumap

……………………………………………………………………………………133



08W6……………………………………………………………………….…….134



08W6……………………………………………………………………………..135


Accumap……………………………………………………………...………….136



08W6…………………………………………………………………………….137



08W6……………………………………………………………………………138

Figure 103: Modified Pickett Plot for well 00/07-21-065-08W6. Note that this well follows the first

distinctive trend, with m=2.2422, and

a=0.5141………………………………………………………………..……..139

Figure 104: Modified Pickett Plot for well 00/11-09-065-08W6. Note that this well follows the

second distinctive trend, with m=1.9685, and a=0.5423……………….……..139


first distinctive trend, with m=2.2341, and

a=0.5426………………………………………………………………………140



a=0.5493……………………………………………………………………....140


distinctive trend, with m=2.2478, and a=0.5141……………………………..141

Figure 108:Modified Pickett Plot for well 00/07-26-065-08W6. Note that this well follows the

first distinctive trend, with m=2.2499, and a=0.5070………..………………141


first distinctive trend, with m=2.2478, and a=0.5352……..…………………142


first distinctive trend, with m=2.2632, and a=0.5352……..…………………142



a=0.5211…………………………………………….………………………..143



a=0.5070…………………………………………….………………………..143


second distinctive trend, with m=1.9294, and

a=0.5141………………………………….…………………………………..144


second distinctive trend, with m=1.9289, and

a=0.5423…………………………………………….………………………..144

Figure 115: Log-Core correlation for the analyzed interval of well 00/12-32-065-

08W6………………………………………………………………………….148

Figure 116: Log-Core correlation for the analyzed interval of well 00/11-09-065-

08W6………………………………………………………………………….149

Figure 117: Log-Core correlation for the two analyzed intervals of well 00/10-29-065-

08W6…………………………………………………………………………….150

Figure 118: Relationship between the core and log porosity data for well 00/07-21-065-08W6,

before the depth correction was

performed……………………………………………………………………….151


after the core data was shifted upwards by a distance of 2.2m…………………151

Figure 120: Correlation between log and core porosity values at the same depth interval for well

00/07-21-065-08W6. This well

featured……………………………………………………………………..…..152


after the depth correction. Log porosity data has now been adjusted based on the previously

developed correlation for this

well…………………………………………………………………………….152


00/10-29-065-08W6. …………………………………………………….……153


00/11-09-065-08W6……………………………………………...……………153

Figure 124: Pore throat aperture for well 00/06-02-065-08/W6. Max Horizontal permeability is

measured against porosity………………………………………..……………154

Figure 125: Pore throat aperture for well 00/06-02-065-08/W6. 90o Horizontal permeability is

measured against porosity………………………………………………..……154


measured against porosity……………………………………………..………155


measured against porosity……………………………………………..………155


measured against porosity.

…………………………………………………………………………………156

Figure 129: Pore throat aperture for well 00/05-06-065-08/W6. Vertical permeability is measured

against porosity……………………………………………………..…………156


measured against porosity……………………..………………………………157


measured against porosity………………………………………..……………157


against porosity………………..………………………………………………..158


measured against

porosity…………………………………………………………………………158


measured against

porosity…………………………………………………………………………159


against porosity…………………………………………………………………159


measured against porosity………………………………………………………160


measured against porosity.………………………………………………………160

Figure 138: Cadomin Formation – Mercury-air 𝑃𝑐 Vs 𝑆𝑊. ……….….…………163

Figure 139: Nikanassin Formation – Mercury-air 𝑃𝑐 Vs 𝑆𝑊. ……………………163

Figure 140: Mercury-air 𝑃𝑐 Vs 𝑆𝑊 Using Average Properties……………………164

Figure 141: Gas Compressibility Factor and Formation Factor Averages for both Cadomin and

Nikanassin Formations. .…………………………………………………. ………167

Figure 142: Gas Density and Viscosity Averages for both Cadomin and Nikanassin

Formations………………………………………………………………………….167

Figure 143: Contour map presenting the tops of the Cadomin formation………….169

Figure 144: Contour map presenting the tops of the Nikanassin formation………..170

Figure 145: Contour map presenting the gross thickness of the Cadomin

formation……………………………………………………………..…………….171

Figure 146: Contour map presenting the gross thickness of the Nikanassin

formation…………………………………………………………………..………..172

Figure 147:Cadomin SgФhnet contour map. This is used in volumetric calculations for Original

Gas in Place…………………………………………………………………………173

Figure 148: Nikanassin SgФhnet contour map. This is used in volumetric calculations for Original

Gas in Place …………………………………………………………………………174

Figure 149: Map of the township showing the cross sectional cuts made through the formation. .

………………………………………………………………………………..………175

Figure 150: North-south cross section through the township………….……………..176

Figure 151: East-West Cross section through the township …………………………177

Figure 152: Diagonal Cross Section of the township. This cut follows a southwest-northeast

trend, parallel to the trust belt………………………………………………...………178

Figure 153: Cadomin Formation Bubble Map showing Cumulative Gas

Production………………………………………………………………………..…..179

Figure 154: Nikanassin Formation Bubble Map showing Cumulative Gas

Production…………………………………………………………………………....179

Figure 155: Shows apparent natural fractured zones in Well 07-21-

065……………………………………………………………………………………182

Figure 156: Shows apparent natural fractured zones in Well 09-34-065…………….183

Figure 157: Shows apparent natural fractured zones in Well 13-30-

065…………………………………………………………………………………….184

Figure 158: Shows cumulative gas production for individual wells……….…………185

Figure 159: Shows forecast cumulative gas production for individual wells………….185

Figure 160: Shows monthly gas production for individual wells…………….……….186

Figure 161: Pool cumulative production history compared to forecast cumulative gas

production………………………………………………………………………...……186

Figure 162: Pool monthly gas production then extrapolated by exponential decline method over

15 years…………………………………………………………………………………187

Figure 163: Type well 1 cumulative production history then extrapolated by exponential decline

method……………………………………………………………………………..……187


method…………………………………………………………………………..………187


method……………………………………………………………………..……………188


method…………………………………………………………………………..………188

Figure 167: Determination of exponential decline equation constants for the pool

…………………………………………………………………………………………..189

Figure 168: Determination of the exponential decline equation constants for well 07-21-

065……………………………………………………………………………..………..189


065……………………………………………………………………………..………..189


065…………………………………………………………………………..…………..190


065………………………………………………………………………..……………..190


065………………………………………………………………………..…………..190


065…………………………………………………………………..………………..191


065……………………………………………………………………..……………..191

Figure 175: Determination of the exponential decline equation constants for Type well

1……………………………………………………………………………..………..191


2………………………………………………………………………..……………..192


3……………………………………………………………………..………………..192


4…………………………………………………………………………..…………..192

Figure 179:Perforation data for wells within township 065-08W6 ……….…………194

Figure 180:Schematic of horizontal drilling techniques. The process shown in this diagram

corresponds to short radius drilling…………………………………………….……..195

Figure 181: Spider chart for the single year infill drilling project………….………..211

Figure 182: Tornado Chart for the two year infill drilling project……………..……212

Figure 183: Tornado Chart for the three year infill drilling project…………………213

Figure 184: Tornado Chart for the four year infill drilling project ……………..…..214

Figure 185: Tornado Chart for the five year infill drilling project………………..…215

Figure 186: Gantt chart showing the work done by each team member this

semester…………………………………………………………………………...…216

List of tables:

Table 1: Results of the Volumetrics OGIP calculations based on the thickness maps for

formations of interest………………………………………………………………….33

Table 2: Summarizes radius of drainage for individual wells. Well 14-11-065 have no significant

BDF within a period of 15

years…………………………………………………..……………………………….48

Table 3: Summarizes radius of drainage for type wells and the pool

……………………………………………………………………………………..….48

Table 4: Drilling costs for an infill well. Costs are analyzed on a vertical

basis……………………………………………………………………………..…….70

Table 5: Factor cost increase used to estimate horizontal well expenses from vertical well

data…..………………………………………………………………………….…….71

Table 6: Cost of Horizontal drill jobs, per well, over each year of the project..….…..72

Table 7: Completion costs for an infill drilled well in township 065-08W6…………76

Table 8: Total capital expense for the infill drilling project………..…………..……..80

Table 9: Total capital expenses for the reperforation and fracturing project, per stage

performed…….……………………………………………………………………......82

Table 10: Capital Cost and Operating Cost per 3 wells for the Infill Drilling

Analysis……….……………………………………………………………...………..84

Table 11: Capital and operating costs for the reperforation and fracturing project, per stage

performed for a single well ………………………………………………………...…85

Table 12: Allowable tolerance on each economic variable before the Base Case becomes the

more effective

method……………………………………………………………….…………..……85

Table 13: Sensitivity analysis on the parameters for a single year infill drilling

project……………………………………………………………………….….……..86

Table 14: Net Present Worth of each infill drilling project with Abandonment

considered……………………………………………………………………………..89

Table 15: Table 15: List and definition of symbols used in this

report…………………………………………………………………………………..95

Table 16: Production history within the township of

interest………………………………………………………………………….…….100

Table 17: Drillstem test results from available

wells……………………………………………………...…………………………..100

Table 18: Sample chart containing log readings and calculations for the Cadomin section of well

00/09-34-065-

08W6…………………………………………………………..…………………...102

Table 19: Average Porosity and Water Saturation within each well, for each

formation………………………………………………………………..………….147

Table 20: Gross Pay, net Pay and Net/Gross Ratio within each well, within the Cadomin.

…………………………………………………………………………..……………147

Table 21: Gross Pay, net Pay and Net/Gross Ratio within each well, within the Nikanassin…..

………………………………………………………………………………………..148

Table 22: Important reservoir properties for the geostatistically interpolated

wells………………………………………………………………………….……....148

Table 23: Pay intervals for the geostatistically interpolated wells…………………...149

Table 24: Permeability averages for the geostatistically interpolated wells. ……..….149

Table 25: Comparison of Permeability data from the Core Data and the Morris and Biggs

equation. Data obtained from well 00/12-32-065-08W6..…………………………..161

Table 26: Average maximum horizontal permeability for each well, in each

formation…………………………………………………………………………….161

Table 27: Average 90o horizontal permeability for each well, in each

formation…………………………………………………………………………….162

Table 28: Average vertical permeability for each well, in each

formation……………………………………………………………………………162

Table 29: Empirical Values of A and B in Capillary

Pressure…………………………………………………………………..……....…164

Table 30: Well 00-11-09-065-08W6 Gas

Analysis……………………………………………..…………………..………..…165

Table 31: Calculated gas compressibility factors and gas formation factors for Cadomin and

Nikanassin formations along with the averages.

……………………………………………..……….…………………………….…166

Table 32: Calculated gas density and gas viscosity for Cadomin and Nikanassin formations along

with the averages. …………………………………………………..…..………..…167

Table 33: Results of the 2 methods used to calculate the OGIP…..………………..180

Table 34: P/Z and cumulative production values for the wells that produced from Cadomin and

Nikanassin Formations in our township…………………………………………….180

Table 35: Production history for wells producing from the Cadomin and

Nikanassin……………………………………………………………………………..181

Table 36 : Wellhead pressures and cumulative production values for the wells that produced

from Cadomin and Nikanassin Formations in our

township……………………………………………………………………………….193

Table 37: Gas Price Forecast by Deloitte. …………………………….……………...196

Table 38: Base Case Economic Evaluation. ………………………………..………...197

Table 39: Year 1 Economic Evaluation – 3 New Drills 2016. ………………………..198

Table 40: Year 2 Economic Evaluation – 3 New Drills 2017……………………..…..199



Table 43: Year 5 Economic Evaluation – 3 New Drills 202…………………………..202

Table 44: Year 2016 Economic Evaluation – Re-perforating and Fracturing. ………..203

Table 45: Year 2019 Economic Evaluation – Re-perforating and Fracturing. ………..204

Table 46: Year 2022 Economic Evaluation – Re-perforating and Fracturing………....205

Table 47: Year 2025 Economic Evaluation – Re-perforating and Fracturing……..…..206

Table 48: Year 2016- Economic Evaluation – 3 New Wells and Re-perforating and Fracturing of

1 well. …………………………………………………………………..……………..207

Table 49: Year 2019- Economic Evaluation – 12 New Wells drilled since 2016 and the second

re-perforating and Fracturing well. …………………………………………………..208

Table 50: Year 2022- Economic Evaluation – 15 new wells drilled since 2016 and the third re-

perforating and Fracturing well……………………………………………………..209

Table 51: Year 2025- Economic Evaluation – 15 new wells drilled since 2016 and the fourth re-

perforating and Fracturing well……………………………………………………..210

Table 52: Sensitivity analysis on the parameters for a two year infill drilling

project………………………………………………………………………..……..212

Table 53: Sensitivity analysis on the parameters for a three year infill drilling

project………………………………………………………………………………213

Table 54: Sensitivity analysis on the parameters for a four year infill drilling

project………………………………………………………………………..……..214

Table 55: Sensitivity analysis on the parameters for a five year infill drilling

project……………………………………………………………………………….215

1

1. Introduction 1.1: Reservoir Overview This project focuses on the understanding and optimization tight gas reservoirs. In order to be

defined as a tight formation, a reservoir must feature extremely low matrix permeabilities, often

less than 0.1mD. The overall tightness of this formation forms a capillary trap above the

reservoir fluids. This creates an extensive pool of fluids, which features irregular reservoir

properties. Formations with these properties are classified as Unconventional Reservoirs.

1.2: Continuous Accumulation The Unconventional Reservoir analyzed in this report is defined as Continuous Accumulation.

These differ greatly from the typical anticline systems. As stated by Schenk (2001), Continuous

Accumulations are “regionally extensive pools of gas or hydrocarbons”, which “feature no

obvious seal or trap”, and are devoid and independent of a water column. Though these

reservoirs contain massive volumes of gas in place, the recovery factor is abnormally low. This

is due to the low permeability of the matrix system, and the abnormally high or low pressure

distribution. A schematic of a Continuous Accumulation is provided below.

Figure 1: Diagram highlighting the differences between conventional reservoirs and Continuous

Accumulations. Organization of a Continuous Accumulation is also shown. These are very large

formations, with very low permeabilities and irregular pressure distributions. The water layer is

located updip of the gas, and provides a Capillary seal (USGS, 2002).

Because of the low permeability of these formations, the drainage radii of producing wells will

not overlap. Therefore, each well acts as if it is producing from a separate, independent reservoir

system. The limited drainage areas of each well do not overlap. This is known as incremental

production. Unconventional reservoirs may also present natural micro fractures, created by

compressional tectonic mechanisms such as folding and faulting. These fractures are complex,

but generally small in width. As a result, they present little change in porosity, but act as flow

2

conduits. As recommended by Aguilera (2011), these reservoirs must be examined with at least a

dual porosity and permeability models.

Continuous Accumulations do not feature well defined fluid contacts. Therefore, the trapping

mechanism is not hydrodynamic. Rather, gas is held in place by capillary forces. Because these

forces overcome buoyancy, there will be no water leg in the reservoir. Instead, the water column

will be held updip of the gas. (Vargas and Aguilera, 2012). This creates a strong capillary seal,

termed the “water block” (Masters, 1979) above the reservoir. Because fluids are not organized

in the formation by increasing density, there is little free water production from these reservoirs.

That is, all water within a Continuous Accumulation is at the irreducible saturation.

1.3: Reservoir Location The tight gas formations

being studied are known as

the Cadomin and Nikanassin.

Located within the Western

Canada Sedimentary Basin

(WCSB), these formations

contain large volumes of dry

gas. For economic purposes,

production from the Cadomin

and Nikanassin is comingled.

The Western Canada

Sedimentary Basin extends

for hundreds of kilometers.

Portions of this reservoir can

be found within four different

provinces, Alberta, British

Therefore, it would be impossible to study the entire Continuous Accumulation. Instead, a single

township, 65-08W6, has been selected for analysis. A more detailed map, showing the location

of this township within the WCSB, has been provided in Appendix B of this report.

1.4: Wells Of the 88 wells within our township, 12 have been selected for further analysis:

-00-07-21-65-08W6 -00-07-26-65-08W6 -00-14-11-65-08W6 -00-07-12-65-08W6

-00-13-30-65-08W6 -00-12-32-65-08W6 -00-09-34-65-08W6 -00-11-09-65-08W6

-00-08-22-65-08W6 -00-03-07-65-08W6 -00-05-06-65-08W6 -00-15-13-65-08W6

Figure 2: Map of the Western Canada Sedimentary Basin

Columbia, Saskatchewan and Manitoba. A portion of this

reservoir can also be found within the Northwest

Territories.

3

These wells are spread to give a wide coverage of our township. They were selected based on

availability of logs, core samples and drillstem tests. With these criteria satisfied, the wells

penetrating deepest into the Nikanassin were chosen.

1.5: Pool History

The township under study, 065-08W6, has been in production for many decades. The first well in

this area, 00/10-29-065-08W6, was drilled by Precision Drilling, for the Devon Canada

Corporation, in August of 1978. This well targeted reservoirs in the Gething and Falher for

production. Future projections for this well were aimed at the Fernie. Therefore, the well has

been drilled through the Cadomin and Nikanassin formations. Drilling has continued within this

region, with the most recent well completion occurring in January of 2013. This drilling job was

performed by Horizon Drilling, for Nuvista Energy Ltd. This well was used for a deeper pool

test, with production projections intended for the Taylor Flats. There has been no drilling activity

within this township since early 2013. This is likely due to the economic conditions of the oil and

gas market. Operations will likely continue once gas prices stabilize.

Many companies have a stake in the land within this township. Almost 90% of the drilled wells

are operated by Canadian Natural Resource Limited. This company entered the region with its

first drilled well in November of 2006. Since this time, Canadian Natural has completed six of its

own wells, using Jomax Drilling as the contracted scouting and rigging company. The most

recent well was put into production in October 2007.

Canadian Natural obtained most of its wells from the Devon Canada Corporation, after a sellout

within the time range of 2010-2012. These purchased wells were drilled by various companies,

such a Beaver Drilling, Stoneham Drilling, Nabors Drilling. Akita Drilling, and most commonly,

Precision Drilling. The first of these wells was completed in August of 1978. Devon Canada put

its last well into production in December of 2010, shortly before the sellout. Devon Canada still

operates one well within this region, 00/13-21-065-08W6. This well was drilled in December of

1998. It, however, has since been abandoned, likely before the sellout. In total, Canadian Natural

operates 76 wells in this township. Nuvista Energy is the second most common inhabitant of this

township, with six wells in total. These were purchased from Talisman Energy. The first well

was drilled for this company in January of 1979. The last well was put into operation in January

2013, by Horizon drilling. This well was under original ownership by Nuvista. Other companies

have also drilled wells within this region. They include Conoco Phillips, which owns two wells,

drilled at similar times by Precision Drilling, in 2003 and 2004. These were purchased from

Burlington Resources Canada. Novus Energy operates four wells in the township. The first was

drilled by Northwell operators in March of 2006. Northwell has since obtained licenses from G2

resources. The last well completed by G2 resources before the sellout was put into production by

Savana Drilling, in September 2006. Nuvista,

Conoco Phillips, and Novus also operate a few facilities in the region. However, over 90% of the

facilties, or 77 of the 88 present, are operated by Canadian Natural.

4

The majority of the wells drilled in this township are targeted at the Cadomin region. Of the 88

wells present, 48 either target the Cadomin on its own, or comingle it with other formations. 19

wells produce from the Caddott formation, while 21 are aimed at the Falher region. The Gething

is also fairly well produced, with 13 of the 88 wells in the township penetrating and producing

from the formation. A few wells also target the Dunvegan, Notikewin, and Wilrich formations.

These, however, are uncommon. Only three of the 88 wells in this township produce from the

Nikanassin. These are typically comingled with Cadomin production.

The datacards for our selected 12 wells in this region are provided in Appendix C. These provide

information on well lisencing, drilling, construction and workover dates, and producing

formations.

1.6: Producing Wells Of the 12 selected wells, 7 produce from Cadomin/Nikanassin formations; 6 wells in Cadomin

and 1 well in Nikanassin. Within the township of interest, well 00/08-22-065-08W6 was the first

to be operated, in November 1999, with a cumulative gas production of 38,479.6 E3 m3. Well

00/13-30-065-08W6 recorded the highest cumulative production of 74,579.9 E3 m3. It was

drilled in since 2003. Produced water to gas ratios in this wells approach zero. Therefore, the

Cadomin and Nikanassin are strict dry gas reservoirs. A table of monthly production for wells in

this pool is provided in Appendix C. Drillstem test data is also summarized in Appendix C.

1.7: Enhanced recovery methods Despite the large volume of fluid in place, the recovery factors in these reservoirs are very low.

This is a result of the high flow inhabitance to fluid migration, caused by the low horizontal and

vertical permeabilities and the abnormally high or low pressure distribution. Flow is marginally

improved by the presence of micro fractures, but not enough to be considered naturally

productive.

To improve reservoir productivity, secondary and tertiary methods of enhanced oil recovery

must be considered. Unconventional, tight formations feature high sandstone content and low

connectivity between wells. Because of this, an acid job or waterflood would be ineffective.

Even if the reservoir were well connected, the low permeabilities would prevent water bank

movement. In general, pressure maintenance methods do not apply to unconventional reservoirs,

since they are not buoyancy driven (Kleinberg, 2014). Therefore, the most optimal method of

reservoir stimulation is Hydraulic Fracturing. Cracks in the formation open up flow pathways for

the gas, and help resolve the low permeability rations. Hydraulic fracture jobs throughout

unconventional gas regions have proven to be very effective in improving recovery rates.

5

1.8: Existing Facilities In the selected township, there are 2 active compressors operated by Canadian Natural Resources

Limited and 20 inactive gas test batteries operated by Devon Canada Corporation, Anderson

Exploration Limited and Home Oil Company Limited. Only 4 of those inactive batteries are

located within the selected 12 wells and none of the compressors are. Figure 3 shows the

distribution of compressors, batteries and pipelines within the township.

Figure 3: Existing Facilities and Pipelines Within Township 65-08W6

6

2. Reservoir and Fluid Characterization 2.1: Basin Description The area of study within this report is known as

the Western Canada Sedimentary Basin. This

region is composed of four main sections; the

Rocky Mountains, the Rocky Mountain Foothills,

the Interior Plains of British Columbia and

Western Alberta, and the Interior Plains of

Southern Saskatchewan and Manitoba (Alberta

Geological Survey, 1989). Township 065-08W6 is

located within the Northern section of the

foothills, close in proximity to the Rocky

Mountains. This area is not directly interfered by

mountain relief. However, it is heavily influenced

by the Southeast-Northwest trending trust belt of

the Rocky Mountains (Solano, Zambrano and

Aguilera, 2011). This feature was formed due to

the tectonic actions of uplift and compression

during the Rocky Mountain formation. The

stratigraphy, faults and reservoir boundaries of

this region are all heavily controlled by the trust

belt direction.

Figure 4: Location of the Township within

Alberta. Based on this location, township

065-08W6 is seen to be a member of the

Alberta Foothills.

In specific, the township under study is a member of the Deep Basin section of the Western

Canada Sedimentary Basin. This area in located in the western section of the Western Canada

Sedimentary Basin, and forms “an extensive area of hydrocarbon saturated, abnormally

pressured, thermally mature clastic rocks, with minor associated carbonate sequences.” (Zaitlin,

Moslow, 2006). This area is characterized by low permeability gas reservoirs, with little to no

water production. The Deep Basin contains a large gas reservoir, which is assumed to exceed

over 400 tcf of fluid (Wright, 2010). Township 065-08W6 is found within the lower pressured

section of the deep basin. This area shows typical behavior of a continuous Accumulation, with

the gas in place being at a lower pressure then the up dip water. Note that a high pressure section

of the Deep basin can be found slightly southwestward of the township. This area does not

contain under pressured gas below the water. Rather, gas pressure can exceed that of the updip

fluid, but is held in place due to strong capillary forces (Masters, 1979). In this section of the

basin, a water leg can potentially be found. This, however, is highly uncommon. A map of the

Deep Basin, including the township location, can be found in Appendix B.

7

2.2: Cadomin Geology This reservoir consists of two main formations, the Cadomin and Nikanassin. The Cadomin

formation is the basal member of the Lower Cretaceous Blairmore group, a “thick wedge of non-

marine strata located within the Alberta Foothills” (Mellon, 1967). This formation was formed

over a long period of time by relatively smooth and flat lying processes. During the early times

of deposition, layers were formed by fragmented clasts and conglomerates from the Rocky

Mountain river runoff. This material was deposited at the end of the mountain canyon channels.

As a result, large Alluvial Fans were formed in the area. Water flow over these fans redistributed

sediment downslope. This caused large Alluvial plains to develop. Water runoff from these

plains joined up with a flowing braided stream, known as the Spirit River. Over time, all Alluvial

Plains sediments were captured by this river. Sediments were transported away from the

mountains and drainage areas, in a direction parallel to the thrust belt. In addition to the facies

from the Alluvial Plains, which were composed of thick Chert Conglomerates and poorly sorted

Quartzite pebbles, the Spirit River also transported its own unique sediments from nearby

drainage areas. These grains were typically small, well sorted pebbles of Chert and Quartz.

Though finer then the Alluvial Fan Conglomerates, the Spirit River facies are often found to

have the higher reservoir potential. In net, this geological layer is thought to have been formed

from the mixed depositional processes of two fluvial systems; a mountain fed Alluvial Fan and

the Spirit River trunk channel (McLean, 2004).

Typically, the Cadomin layer ranges between 20-40m thick. This formation is composed

primarily of upwards fining sandstone conglomerates. The bottom layer of this formation

contains sandy conglomerates, with an average diameter of 6 inches. These sandstones are

mainly composed of well-rounded white and pink Quartzite, and grey to black Chert or Argillite.

The formation grades upwards into pale grey, medium grained cherty sandstone. Upper layers

also contain abundant amounts of organic plant and animal remains (McLean, 2004). The

average size of the conglomerates within this region grains is 0.4-1.2 in, though diameters can

extend beyond 16 in.

Two sharp layer contacts are found within the Cadomin. The lower is composed of thin bedded

coaly shale and siltly sandstone, originally from the Nikanassin formation, and the upper with

grey, dark shale from the Luscar facies. Layers in this region are generally folded and poorly

exposed. Many sections of the Cadomin are interbedded with finer sands and shales, reducing the

permeability of the system (Mellon, 1967).

2.3: Nikanassin Geology Below the Cadomin formation, a tight member of the Upper Jurassic/Lower Cretaceous group,

known as the Nikanassin can be found. This layer is situated within the powerful Southwest-

Northeast trending trust belt of the Canadian Rockies (Solano, Zambrano and Aguilera, 2011).

This belt influences the folding and faulting of the region. The Nikanassin is known to present a

complicated stratigraphy. There has been plenty of tectonic action in the area, which has caused

large amounts of structural deformation. This has also resulted in the formation of a large thrust

8

fault below the Nikanassin. In general, this formation is tighter then the Cadomin. However, it

presents a larger volume of gas in place. In total, the Nikanassin ranges from 120-170m in gross

thickness. It is comprised of four main layers. From bottom to top, these are known as the

Monteith, Beattie Peaks, Monach and Bickford formations (Miles et al, 2009). Each of these

layers is influenced by a different depositional process, and therefore, contains different facies

type.

The lowest of these, the Monteith, presents a strongly heterogeneous distribution of Quartz

arenites, with minor amounts of argillaceous grains and very limited Chert. Small Silica

overgrowths are also common in this formation. The Monteith was formed by storm influenced

river deposition in a Prograding Deltaic system. Therefore, the grain size profile is strongly

upwards coarsening. The sedimentary material is thickest near the distribution channels. Prodelta

material in the layer is sharply overlain by Deltaic Mouthbar deposits. The strongly

heterogeneous nature of this layer is a result of the presence of strata that were once a part of the

Rocky Mountains (Miles et al, 2009).

The Beattie Peaks contains predominant amounts of Silt and Shale. Some of the Northwestern

portions of this layer also present thin sandstone sections. These, however, are highly

uncommon. Highly carbonaceous to coaly components can be found in the mid-southern

portions of the Beattie Peaks formation. Due to the shales, it presents limited reservoir potential.

Therefore, minimal research has been put into the identification of a depositional environment

for this area. Due to the high organic content within the Beattie Peaks, it is suggested that the

region could be a part of a deltaic or coastal environment (Miles et. al, 2009).

The Monach is generally the thickest layer of the Nikanassin. Typically, it covers a depth

interval of over 100m. This layer is contains high sandstone to shale ratios, making it the most

productive of the existing layers. The composition of the Monach is notably different from the

Monteith formation. Unlike the underlying layers, this region presents coarse grained, poorly

sorted, sub-angular chert grains and sandstone fragments. The layer is thickest near the foothills,

and thins northeastward. Facies in the area were deposited by extensive fluvial meandering

channels and braidplains. Therefore, the Monach is an upwards fining sequence (Miles et. al,

2009).

Due to erosional processes, the Bickford formation can only be found within the western British

Columbia region. Therefore, an unconformity exists between the majority of the Cadomin and

Nikanassin formations. The few present sections of the Bickford show that the region is

dominated by Shale and Siltstone. Overall, the composition of the Nikanassin formation reveals

a continuously changing geological environment. Lower layers were formed by subsea and

deltaic processes. These transitioned into coastal type environments, and eventually, continental

fluvial processes. Therefore, the Nikanassin was formed while the shoreline was regressing

outwards from the Alberta region.

9

2.4: Drive Mechanism Since the reservoirs contain large volumes of dry gas, the drive mechanism is a strong gas

expansion. No water is produced from the layers, and no fluids are injected to promote recovery.

2.5: Production and Pressure Analysis Transient flow tests for 2 wells producing in Cadomin indicate similar reservoir properties.

Pressure gradients of (1.28 – 2.0) kPa/m are indicative of gas as the reservoir fluid and skin of ---

-3.4 is evidence of natural fractures in Cadomin and Nikanassin formations. As a comparison,

well 00/01-28-065-08W6/02 producing in Gething formation shows completely different

reservoir properties. Figure 4 in Appendix C illustrates the differences. Test results have also

been provided in the appendix of this report.

For production tests, 2 offset wells were studied – Figures 5 and 6 summarize the flow rate and

pressure response.

3. Log Interpretation 3.1: Readings Log readings were taken at 1m increments for the Cadomin formation. Since the Nikanassin

presents a larger thickness, readings were taken at more variable increments, between 1-7 m,

based on property variation. Since properties could show variations within these reading

intervals, the averages of properties over the entire increment were taken.

3.2: Water Resistivity Unconventional reservoirs do not contain defined gas-water contacts, making it difficult to

directly obtain water resistivity. Information on water resistivity for township 65-08W6 at 25oC

was found, from the Canadian Well Logging Society Water Catalogue (2002), to be 0.344

ohm*m. This was corrected to the average temperature within the Cadomin and Nikanassin, 91oC,

using the equation:

𝑅𝑇2 = 𝑅𝑇2 (𝑇1 + 21.5

𝑇2 + 21.5)

The results gave an average water resistivity of 0.142 ohm*m within the Cadomin and

Nikanassin.

3.3: Cutoffs To define the difference between net pay and unproductive regions, shale and water saturation

cutoffs were developed. Based on the advice of Roberto Aguilera, this report defines the cutoffs

as Vsh =60% and Sw =55%. The shale cutoff is set within a higher range, since the Nikanassin is

10

known to feature prominent volumes of shale. The Cadomin will also contain reasonable shale

content within some regions, making this cutoff applicable to both formations. The assumed

water saturation cutoff will ensure reasonable gas production from each layer. Under current

economic conditions, it is risky to target pay regions with much less than 50% productivity of the

desired fluid. This is especially true for unconventional reservoirs, based on the effort required to

produce from an interval. The 55% water saturation cutoff does slightly undercut the desired gas

productivity from pay. However, this estimation allows for the occurrence of human based

logging and recording errors that result in water saturation overestimates. A lower cutoff may

accidentally mislabel productive pay as an uneconomic layer if human error is present.

Since porosities and permeabilities in tight reservoirs are low, no cutoffs were developed for

these properties. Furthermore, the matrix porosity and permeability do not strongly correlate with

gas production, as flow pathways are fracture dominated.

3.4: Shale Volume

High Shale volumes are expected within sections of the Cadomin, and large portions of the

Nikanassin formation. The volume of shale, Vsh, was obtained using Gamma Ray readings and

the Clavier equation:

𝑉𝑠ℎ𝑖 =(𝐺𝑅)𝑙𝑜𝑔−(𝐺𝑅)𝑐𝑙𝑒𝑎𝑛

(𝐺𝑅)𝑠ℎ𝑎𝑙𝑒−(𝐺𝑅)𝑐𝑙𝑒𝑎𝑛 𝑉𝑠ℎ = 1.7 − [3.38 − (𝑉𝑠ℎ𝑖 + 0.7)2]0.5 (Clavier

Equation)

The Clavier equation was selected for analysis since it presents a reasonable compromise

between older and tertiary rocks, and can be used for multiple lithology types (Crain, 2015)

3.5: Porosity Neutron and Density porosities were averaged using the following formula:

∅𝑒 = √∅𝐷

2 + ∅𝑁2

2

This formula is specific to gas saturated porous space. Effective porosity’s are then corrected

based on the shale content of the depth increment:

∅𝑒′ = ∅𝑒(1 − 𝑉𝑠ℎ)

3.6: Water Saturation The Cadomin and Nikanassin contain laminated shales. These layers exist between the sandstone

grains, and will not affect the porosity and permeability of the actual sand layers (Aguilera,

1990). Because of these laminated shales, the regular Archies equation cannot be used to find

water saturation. Instead, the Poupon equation for laminated shales must be applied:

11

𝑆𝑤2 =

𝑎(1 − 𝑉𝑙𝑎𝑚)𝑅𝑤

∅𝑒′𝑚 (

1

𝑅𝑡−

𝑉𝑙𝑎𝑚

𝑅𝑠ℎ)

This equation extends to reservoirs featuring various types of pore geometries. Therefore, it can

be applied to naturally or hydraulically fractured reservoirs, as long as they contain shale laminae

(Elkewidy et. al, 2013). Aguilera wrote the equation in logarithmic form (1990). This is known

as a Modified Pickett Plot

log (𝑅𝑡

𝐴𝑙𝑎𝑚) = −𝑚𝑙𝑜𝑔(∅𝑒

′) + log(𝑎𝑅𝑤) + log (𝑆𝑤)−2

𝐴𝑙𝑎𝑚 =(𝑅𝑠ℎ − 𝑅𝑡𝑉𝑙𝑎𝑚)(1 − 𝑉𝑙𝑎𝑚)

𝑅𝑠ℎ

Through pattern recognition, data from the selected wells can be classified to follow two

distinctive trends. These trends differ in the value of the cementation exponent, but present

highly similar values for “a” and water resistivity. The modified Pickett Plots for the two trends

within the Cadomin region can be found below, whereas the Pickett Plots for all the selected

wells can be found in Appendix E.

Figure 5: Modified Pickett Plot for all wells. These follow the first trend, with m=2.2422, and

a=0.5282

12

Figure 6: Modified Pickett Plot for all wells following the second distinctive trend, with

m=1.9455, and a=0.5282

Since the Cadomin and Nikanassin present lithology’s that are relatively laterally continuous, the

presence of two trends could hint towards the existence of two separately sourced gas pools

within the accumulation. The wells within a particular different trend groups, however, are not

located within similar regions. It is not possible to develop two gas pool regions from these well

locations without making major assumptions on reservoir boundaries. Therefore, it is more likely

that these trends are due to lithological differences rather than separate gas pools.

13

3.7: Log property averaging Porosity and water saturation have been arithmetically averaged for the Cadomin and Nikanassin

∅𝑒′𝑎𝑣𝑔

=(∑ ∅𝑒𝑖

′ℎ𝑖)𝑛𝑖=1

∑ ℎ𝑖𝑛𝑖=1

𝑆𝑤𝑖 =∑ 𝑆𝑤𝑗ℎ𝑗

𝑛𝑗=1

∑ ℎ𝑗𝑛𝑗=1

Tables listing the average porosity and saturation of each formation and for each well are

provided in Appendix F.

The obtained property averages for the Cadomin are Фe’=4.94% and Sw= 48.47%. The

Nikanassin presents averages of Фe’= 4.86% and Sw= 44.45%. These are very typical values for

a Continuous Accumulation. Both reservoirs present similar porosity and water saturation values.

Though this is not always the case for the Cadomin and Nikanassin, it does show the generally

strong relationship between the formations. This data also shows that the Nikanassin is a slightly

tighter formation, but has more gas in place. This is due to the larger pay thickness, and lower

water saturation within the Nikanassin region.

Figure 7: Locations of the wells in each Pickett trend.

There is no logical correlation between the well

locations and the trend group. Therefore, Pickett

differences are due to lithological factors.

14

Note that some layers presented very high water saturations. Certain areas even contained 100%

water within the porous space. Yet, these formations only produce gas (and sometimes, very

small volumes of water). This peculiar occurrence is common within Continuous Accumulations.

Due to the strong capillary seal, the water within the formation is non-moveable. Therefore, it

cannot be produced, but water is present within the reservoir.

3.8: Net Pay The Cadomin formation presents a highly variable thickness. Within this township, the gross

thickness of the Cadomin ranges from 6 to 69m in thickness. The average pay interval of the

Cadomin is around 18-22m. Data from well 00/12-32-065-08W6 seems to indicate that the gross

thickness of the Cadomin increases towards the Northwest section of the township. The net pay

of the Cadomin also shows strong fluctuation. Pay intervals range from 3 to 48m, with an

average thickness between 9 and 11m. Ratios of the net to gross thickness show that between

100% and 33% of the Cadomin formation can be productive. The exact locations of the pay

within this township can be mapped out to show spatial variations. See section 6 of this report for

more information on the mapping results.

A table for the net pay, and the net to gross ratio for each well in the two formations can be

found in Appendix F.

Because most wells within this township do not fully penetrate the Nikanassin, the obtained pay

values are not accurate. Instead, this data shows the proportion of the upper Nikanassin, or

Monach region that can be considered productive. The net to gross ratios cannot be held constant

and extrapolated to the full region thickness, since the Beattie Peaks and Monteith present

different properties from the Monach. These ratios could, however, be applied within reasonable

accuracy, to the total thickness of the Monach alone. This would give a crude estimate of the

Monach pay thickness.

Based on information from 00/11-09-065-08W6, the only analyzed well that reaches the bottom

of the Nikanassin, the net pay should range somewhere around 45m. This amounts to 27% of the

total region thickness. More accurate results on the productive regions for the Nikanassin would

require additional information from wells that fully penetrate the formation.

3.9: Interpolated well results The township under analysis lacks appreciable data for the Nikanassin region. Of the 88 wells in

the township, only 9 penetrate through the entire Nikanassin formation. Of these, 6 are situated

in the southwest corner of the township. Because of this, only one of the 12 wells selected for log

interoperation actually reaches a depth below the Nikanassin.

In order to draw maps for the region, more data on the Nikanassin is required. Therefore, the data

for wells has been obtained using weighted averages and spatial interpolation. In this analysis,

the properties of the four closest wells were combined on a distance based average. The spatial

variations of properties within the township were also accounted for in this analysis. This is a

15

very simple and crude geostatistical analysis, applied based on the time constraints and lack of

actual data associated with this project. Note that these values were only used for mapping

purposes. They are not included in the overall porosity, water saturation or permeability

averages. The 8 wells selected for geostatistical interpolation are listed below

-00-12-36-65-08W6 -00-06-36-65-08W6 -00-10-29-65-08W6 -00-06-19-65-08W6

-00-15-18-65-08W6 -00-10-08-65-08W6 -00-03-08-65-08W6 -00-16-05-65-08W6

The properties obtained for these wells are tabulated in Appendix F.

4. Core Data 4.1: Core Analysis: The geological description of the Cadomin and Nikanassin provided earlier in this report gives a

general representation of the facies type, distribution, and the depositional process within the

region. For proper well analysis, is necessary to obtain more specific information, relevant to the

township. The best way to obtain detailed and accurate information on the formation is through a

physical core analysis. The cores within this township can be found at the ERCB Core Research

Center. In total, 9 boxes of core from three different wells were analyzed. Two of these cores

were taken from the Cadomin region, while the last was recovered from the lower Monach

section of the Nikanassin.

Core 1: 00/12-32-065-08W6 – 2 boxes

- Box 1 of 12: 2944.80m-2946.13m TVD

- Box 2 of 12: 2946.13m-2947.47m TVD

Core 2: 00/11-09-065-08W6 – 3 boxes

- Box 1 of 4: 3071.00m-3072.25m TVD

- Box 2 of 4: 3072.25m-3073.50m TVD

- Box 3 of 4: 3073.50m-3074.75m TV

Core 3: 00/10-29-065-08W6 – 4 boxes

- Box 1 of 16: 3077.00m-3078.13m TVD

- Box 2 of 16: 3078.13m-3079.25m TVD

- Box 12 of 16: 3089.38m-3090.50m TVD

- Box 13 of 16: 3090.50m-3091.63m TVD

16

The ERCB Core Lab provides two different box sizes, based on the diameter of the recovered

core. For a 2 or 3 inch diameter core, the box can fit up to 2.5 inches, or 0.762 m of core per

section. Each box is composed of two sections. Therefore, 5 inches, or 1.524 m of core can be

contained in each box. Both of the Cadomin cores are within this diameter range. The Nikanassin

core, however, is 4 inches in diameter. The box required for a 4 inch diameter core will fit up to

2 inches, or 0.6096 m of core in each section. This means that up to 1.2192m of core can be

found per box.

Because of the different coring lengths from each well, some boxes may not be completely filled

with core. It is assumed that the core is evenly distributed between each box. That is, every box

for a given well contains an equal amount of core. This may not be completely accurate.

However, the error of this approximation is minimal compared to log mis-calibrations, missing

core sections, and measurement depth errors. Therefore, this estimate will be applied in the

subsequent core analysis sections. Based on the core length for each well, it is assumed that each

box will contain:

Core 1: 00/12-32-065-08W6 – 1.325m of core

Core 2: 00/11-09-065-08W6 – 1.250m of core

Core 2: 00/10-29-065-08W6 – 1.125m of core

4.1.1: Core 1: 00/12-32-065-08W6

The two upper members of the twelve core boxes from well 00/12-32-065-08W6 were analyzed.

Samples were obtained from the Cadomin region. Each core box is assumed to contain 1.325m

17

of core material. Qualitative analysis of this core reveals features that are very representative of

the Cadomin.

The top of the core contains a narrow interval of small to medium sized pebbles. These grains are

reasonably sorted, and tightly packed. Deeper core depths, on the other hand, present a range of

poorly sorted conglomerates. These conglomerates are massive in size compared to the

preceding pebbles. Therefore, this sequence is upwards fining. This type of organization is

expected in a fluvial based system like the Cadomin. The transition between coarse and fine

grains is very short. This could be described as a discontinuous change in grain size. The gaps in

between the pebbles and conglomerates are filled with a dense cement. No obvious gaps are

Figure 8: Full core intervals for box 1

and 2 respectively. Core samples

originate from well 00/12-32-065-

08W6.

18

present within the cement phase. This supports the low porosity and permeability assumption

within the region.

Figure 9: Grain size distribution in the first core box. The first image shows the top of the core. Small to

medium sized pebbles are found in the region. The second image shows the core at a lower depth. The

grains in this section are coarse conglomerates.

The core presents fairly obvious cyclicity between coarser conglomerates and finer pebbles. As

this is an upwards fining sequence, the smaller pebbles of the cycle are always above the thicker

conglomerates. The average cycle length is approximately 1.5m. Because of the large cycle size,

only two sequences were observed within the two boxes analyzed. When comparing the two

major facies types in the core, it becomes obvious that the conglomerates occupy a much larger

portion of the depth then the pebbles. Within the two core boxes analyzed, approximately 80% of

the depth was occupied by conglomerates. Seeing as this is an upwards fining sequence, the

fraction of coarser conglomerates is expected to increase at lower depths. Therefore, the

Cadomin is concluded to be conglomerate dominated. This is an important fact, as the poor

sorting and cementation within the conglomerate regions will provide lower porosity values.

Analysis of a core body section shows a continuation of the conglomerate facies. Note that there

is noticeable fracturing along the top face of the core. This is not surprising, as the Cadomin

region is known to present a large array of natural fractures. The fractures seen on the core face

are vertical. These are less common then horizontal fractures, but can help promote flow. In

general, however, the horizontal fractures of the system controls the flow of the gas in place.

19

Figure 10: Analysis of a core piece for well 00/12-32-065-08W6. Potential fracture zones are marked.

4.1.2: Core 2: 00/11-09-065-08W6 The upper three core boxes of well 00/11-09-065-08W6 have been analyzed. Each core box

seems to contain 1.25m of material. This accounts for 75% of the core interval. Unlike well

00/12-32-065-08W6, this core presents a very large interval of fine grain sizes. This is situated

below a small section of coarse conglomerates, which is unusual for an upwards fining

formation. The transition between the fine and coarse grains is completely discontinuous.

Interestingly, the core sections within the region of the discontinuity cannot be matched up

without introducing obvious gaps. Therefore, it is strongly suspected that there is a missing

section of core within this interval that has not been labeled. This fact has been confirmed by

onsite geologists.

20

Figure 11: Core sections from well 00/11-09-068-08W6. The first (pictured left) and second (pictured

right) core boxes are shown. It is suspected that a large sand lens is present in this region. Fine grains

occupy over 95% of the interval. Thick conglomerates are only found in the top section of the first box.

Core box three shows a similar lithology to box two.

The unusual trend of fine grains within this core is suspected to be the result of a large sand lens.

This type of feature is rare, but can be found within certain parts of the Cadomin. The logs for

this well also show a unique behavior within the cored interval. Gamma ray readings increase

significantly within the region, which is typical of a fined grained region with increased shale

content. Neutron porosity values also show an increase, likely due to the increased water content

in the shaly sections. Therefore, it is likely that this sand lens contains a large amount of shale.

21

Note that the logs within the cored region are misaligned, and poorly printed. Because of this, it

is difficult to truly diagnose the cause of the fine grain region in this core. It is likely, however,

that the wellsite geologists cored this region in order to identify the cause of this unusual log

behavior. The rest of the formation at this well location presents typical log responses. The

geology in other sections is likely similar to that seen at well 00/12-32-065-08W6.

Figure 12: Log data of the cored interval shows a gamma ray spike and increasing neutron porosity.

The cross section of this core has also been analyzed.

Many natural fractures can be spotted within this rock

face. All fractures on the cross section are horizontal.

Note that the number of fractures on this section

greatly exceeds the amount seen on the core face from

well 00/12-32-065-08W6. Analysis of the core face at

well 00/11-09-06508W6 also shows the presence of

large lateral fractures. This proves that the majority of

natural fractures in the system are horizontal.

Therefore, the horizontal permeability of the formation

is a key parameter in flow estimation.

Figure 13: Core cross section and core face samples within the region of well 00/11-09-065-08W6 show

significant horizontal fracturing.

22

In order to determine the general porosity range within the core, a water beading test was performed. In

this experiment, a small amount of water is carefully placed on top of the core. The droplet is observed

over time. If the water is quickly absorbed into the core, then the region is within a high porosity range.

However, if the droplet beads on top of the core sample, then the region does not exhibit large porosities.

Upon observing this test, it was concluded that the droplet was not absorbed into the core. Therefore, this

region is within the lower porosity range. Such a result is expected within the tight Cadomin formation.

Figure 14: A water beading test was performed on a core section from well 00/11-09-065-08W6. Results

showed that the core has a low porosity

4.1.1: Core 1: 00/10-29-065-08W6

This core was taken from the Nikanassin formation. The

recovered depth ranges from 1952.50m to 1970.50m subsea.

Therefore, it is a member of the Monach region. Each box

contains approximately 1.125m of core, give or take a few

millimeters. In total, four boxes of core have been analyzed from

this well location. These cores sections are located within two

different depth intervals. The selection of the core regions was

based on careful log analysis. It was noticed that the top of the

core presented high gamma ray values, which is indicative of

shale. On the other hand, lower regions of the core interval

presented a significant gamma ray decline. This would point

towards the presence of a sandier region. Two samples from

each of these locations were selected.

Figure 15: Different gamma ray

responses in the cored interval

determined the analyzed regions.

23

The top two boxes of the core were used to identify features from the first region. These core

samples presented a predominant amount of continuous shale. No other obvious lithology types

could be identified. This correlates well with the high gamma ray values in this region. High

shale content is expected within the Nikanassin, even in sandier formations like the Monach. The

core has noticibly fallen apart in the top box. Therefore, the facies have a very structural integrity

in some regions.

Figure 16: Core sections from well 00/11-09-068-08W6. The first (pictured left) and second (pictured

right) core boxes are shown. This region seems to be very shaly. Also note that the top section of the first

core was not well preserved.

24

In order to confirm the presence of shale, a water bead test was performed on the core. It is

known that shales have a high capacity to absorb water. Therefore, a small droplet of water faced

on the core face should be absorbed very quickly. Results of the test do indeed show a quick

absorbance rate. This, along with the gamma ray readings, qualitative core appearance and low

strength of the facies, confirms that the region is highly shale dominated.

Figure 17: A water beading test was performed on sections at the top of the core from well 00/10-29-065-

08W6. The water droplet was absorbed very well, which indicates a high porosity facies, or shale. Based

on the appearance of the rock, this formation is likely composed of shale.

Broken sections of this core was also

investigated. It was noted that both the top

face and cross section of the core presented

parallel laminations. The core also showed

a small presence of both vertical and

horizontal natural fractures. As with the

cores within the Cadomin region, most of

these fractures are lateral. Therefore,

horizontal permeability largely controls

flow within the Nikanassin

Figure 18: Analysis of a broken core

section showed the presence of parallel

laminations. The fractured sections of this

core are circled. Both horizontal and

vertical fractures are present. Horizontal fractures seem to be more common.

25

Two boxes, 12 and 13, from the second identified region of the core were also analyzed. As

suspected from the lower gamma ray values, these core sections presented a higher sand content.

This assumption is based on a qualitative analysis of the core colour, which is noticeably lighter

then the shaly region found above. This core sample, however, is still darker than those found in

the Cadomin. Therefore, these cores still contain a reasonable percentage of shaly material.

Figure 19: Core sections from well 00/11-09-068-08W6. The twelfth (pictured left) and thirteenth

(pictured right) core boxes are shown. This region is sandier then the top of the Monach core, but still

presents high levels of shaly material. The upper sections of box 12 present distinct parallel laminations

and cross bedding. This is not present on the core in box thirteen.

26

Upper sections of this core seem to present parallel laminations and cross bedding on the face.

These laminations become less prominent at the lower depths. This could point to a transition

from higher shale levels to increased sand content. Certain sections of the core present natural

fractures. As with all of the other cores analyzed, the majority of these fractures are horizontal.

Figure 20: A section of the core from box 13 of well 00/10-29-065-08W6. This core does not contain

parallel laminations. Strong lateral fractures are seen throughout the section.

4.2: Core vs. Log porosity Core porosities obtained from the AccumapTM database have been depth corrected and compared

to the log porosities within the same interval. Depth corrections were performed on all cores

intervals so that the core and log porosities featured aligned trends. Log porosities were then

adjusted to match the more accurate core readings. These corrections are applied to all readings

within the formation for that well. When core data was not available, correlations were

developed based on data from nearby wells.

Three example Core vs. Log porosity plots have been provided in Appendix G. Of these, two

were taken from the Cadomin and one from the Nikanassin formation. The first plot shows a

typical core-log porosity correlation for the Cadomin region. Most of the wells within the region

followed a similar, but not identical trend to the case shown. Depth correction plots have also

been provided for this core. These graphs show:

27

-depth vs. uncorrected depth core porosities and unadjusted log porosities

- depth vs. corrected depth core porosities, and unadjusted log porosities

- depth vs. corrected depth core porosities, and the adjusted log porosities

The second crossplot shows a core-log porosity correlation for the Nikanassin region. Note that

this is the only core within the township that was sampled from the Nikanassin. The developed

relationship between the core and log porosities for this Nikanassin core is similar to those seen

within the Cadomin region at nearby wells. This could be due to the fact that the Cadomin and

Nikanassin are composed of similar sandstone types. Since there is a lack of core information

within the Nikanassin, it will be assumed that the similarity between the Cadomin and

Nikanassin core-log correlations can be applied to all regions within the township. Therefore, the

core-log porosity relationships developed for the Cadomin will be extended into the Nikanassin

region.

The last of these plots was derived from a well with older log data. Because this log featured a

significant amount of noise, distortion and track misalignment (due to a poor photocopying job),

the Core vs. Log porosity plot features a significantly different trend then those seen in other

wells, and has a large non-zero intercept. This plot has been provided to show the effect of

human based logging error on the obtained reservoir properties, and highlights the importance of

data normalization.

4.3: Permeability determination In total, 7 cores were examined for porosity permeability relationships. All provided information

on the maximum horizontal permeability. Four contained data on vertical and 90o horizontal

permeability. These data were plotted on a Porosity vs. Permeability cross plot in order to

determine the RP35 pore throat aperture. This is defined by Aguilera (2002) as the pore throat

radius at 35% mercury saturation, and can be calculated using the following equation:

𝑟𝑝35 = 2.665(𝑘

100∅𝑒′)

0.45

Pore aperture plots have been provided below, and in the Appendix G. Maximum horizontal, 90o

horizontal and vertical permeabilities have all been analyzed, when available. It is clear from

these plots that the porosity and permeability present too much scatter to be related. Instead,

permeability’s correlate closely with pore throat curves. This relationship is logical, as flow is

controlled by pore throats. Using the derived pore aperture crossplots, it can be found that the

Cadomin and Nikanassin are dominated by Mesopores and Macropores. Common pore throat

diameters fall within the range of 2-4 microns.

28

.


maximum horizontal permeability. Note that most pore throats within these reservoirs are either

Mesopores or Macropores

Figure 22: Pore throat aperture for all available cores in the township. This relationship uses 90⁰

horizontal permeability. Most pore throats are Mesopores or Macropores

29


vertical permeability. Most pore throats are Mesopores.

The maximum horizontal permeability values present more scatter then the 90o and vertical

variants. However, by looking at the general trends of the graphs and areas of high data

concentration, it becomes clear that the permeabilities in all directions are similar. Therefore, the

Cadomin presents a relatively isotropic permeability scheme. This is assumed to be true for the

Nikanassin as well, though no cores were tested from this region due to the lack of porosity and

permeability data available.

The data from these cross plots was used to determine the permeability at each well. When core

data was not available, correlations were developed based on nearby wells. If there were no wells

close to the point of interest, the following relationship was used (Morris and Biggs, 1967)

𝑘𝑚𝑎𝑥 = (250∅𝑒′3

𝑆𝑤⁄ )2

4.4: Comparison of Permeability calculation methods To show the validity of the Morris and Biggs equation, a sample test has been run for well 00/12-

32-065-08W6. In this test, the permeabilities were calculated from the equation for the Cadomin

region, and compared to the permeabilities obtained from the porosity-permeability fit equation

that was derived using core data. Note that well 00/12-32-065-08W6 was selected for this test

because it exhibits a well structured best fit line that closely models the porosity-permeability

relationship of the core. This well also has clean and understandable log data, so the property

readings are assumed to be accurate. The results of this test, which show that the Morris and

Biggs equation does provide a close fit for the data in clean sandstone areas. However, the

30

correlation massively under predicts areas with shale. This is due to the higher prediction of

water saturation within the region. Results are presented in Appendix G.

4.5: Permeability averaging The permeabilities in our reservoir were averaged for each well using arithmetic, harmonic and

geometric relationships:

𝐾𝑎𝑣𝑔 𝑎𝑟𝑖𝑡ℎ𝑚𝑒𝑡𝑖𝑐 =∑ 𝐾𝑖ℎ𝑖

∑ ℎ𝑖 𝐾𝑎𝑣𝑔 ℎ𝑎𝑟𝑚𝑜𝑛𝑖𝑐 =

∑ ℎ𝑖

∑(ℎ𝑖𝐾𝑖

) 𝐾𝑎𝑣𝑔 𝑔𝑒𝑜𝑚𝑒𝑡𝑟𝑖𝑐 = √∏ 𝐾𝑖

ℎ𝑖𝑛

Since the wells relied on porosity-permeability correlations, and permeability estimates from

small scale samples, the geometric averaging method was selected (Jensen, 1991). A chart of the

average permeability has been provided in Appendix G. Results show that the Cadomin has an

average maximum horizontal permeability of 1.3 mD. The Nikanassin proves again to be the

tighter formation with an average maximum horizontal permeability of 0.5 mD. Both values are

reasonable for tight reservoirs

4.6: Capillary Pressure Capillary pressures were found using the relationship by Kwon and Pickett (Aguilera, 2002):

𝑃𝑐 = 𝐴[𝑘

(100∅)]−𝐵

Where 𝑃𝑐 is the mercury-air capillary pressure, k is formation permeability, ∅ is porosity, A is a

function of 𝑆𝑤 and B is approximately 0.45. Capillary pressure is a fluid-rock property that

depends on the pore throat radius. Since tight gas reservoirs present low permeability, capillary

pressures will be high. Refer to Appendix H for the capillary pressure trends of each well.

5. Reservoir Fluid Properties 5.1: Pressure-Volume-Temperature (PVT) Data The Cadomin and Nikanassin formations are both dry gas reservoirs. Approximately 90% of the

gas content is methane. Table 20 in Appendix I shows a summary of well 00-11-09-65-08W6 gas

analysis, obtained from the AccumapTM database. All inspected wells have similar gas analyses.

5.2: Gas Properties Correlations The law of corresponding states (Baker et. al, 2015) along with the initial reservoir pressure and

run depth temperature, both obtained from AccumapTM, were used to calculate the gas

compressibility factor. In addition, Lee et al. correlation (Baker et. al, 2015) is used to calculate

the gas viscosity as it applies to ranges of pressures and temperatures that are applicable to the

inspected formations. Refer to Appendix I for fluid gas properties correlations and trends.

31

6. Mapping 6.1: Topography Maps The tops of both the Cadomin and Nikanassin formations for the entire township have been

mapped. This analysis is based on all 88 wells in the region. These maps show that the Cadomin

formation tops range from -1871.4m to -2041.3m below the subsurface. In general, the

shallowest depths of the Cadomin occur in the northeast portion of the township. This region is

at is deepest in the southwest sections. Therefore, the Cadomin shows a northeast to southwest

downwards dip in topography. Contour lines for the formation tops are parallel to the southeast-

northwest thrust fault belt of the Rocky Mountains. This makes sense, as formation dipping

would occur due to strong faulting within the area.

The Nikanassin presents a similar topographical map to the Cadomin. The formation top subsea

depths range from -1884.5m in the northeast corner of the township to -2055.3m in the

southwest. Therefore, the formation once again slopes downwards from the northeast to

southwest portion of the township. This is caused by faulting in the township, as all contour lines

are parallel to the thrust belt of the Rocky Mountains.

Topography maps are available in Appendix J of this report.

6.2: Gross thickness Maps The Cadomin shows a very complicated gross thickness pattern. As a general description, the

formation is at its thinnest in the far eastern and western sections of the township. The interval

thickness of the formation tends to increase towards the center of the township. A strange

anomaly occurs in the northern areas of this region, with total the thickness of the formation

increasing by over 40m to reach a total value of 71.6m. This is observed in well 00/12-32-065-

08W6. It is unknown if this occurrence is accurate, or if it is influenced by logging error.

Excluding this anomaly, the Cadomin thickness ranges from 5.0 to 33.0m

The Nikanassin gross thickness map shows a different trend to that seen in the Cadomin. The

depth interval of the formation seems to increase within the center of the township. The region

thins from the center, and re-thickens within the northeast and southwest portions of the region.

Once again, contour lines follow the southeast-northwest thrust fault belt. Due to the limited data

within the Nikanassin region, the gross thickness within most areas had to be extrapolated from

other available data. Historical data from abandoned wells showed high production values within

the center of the township. This was assumed to be because of a larger interval thickness in the

area. Therefore, the correlations within the Nikanassin region are not certain. Additional wells

would have to be drilled in the area in order to determine more information. Alternatively,

seismic tests could be performed. Based on the data recorded from actual wells, the Nikanassin

thickness ranges from 158.0m to 181.3m.

Thickness maps are available in Appendix J of this report.

32

6.3: Net Pay Maps: Net pay within both the Cadomin and Nikanassin formations has been calculated using gas

saturation, porosity and net thickness. This is known as a SgФhnet contour map. This type of

diagram is used because its values are easy to implement in the volumetric calculations.

Much like the gross thickness map, net pay for the Cadomin region is very complex. This makes

sense, since interval thickness will play a factor in the net pay calculations. In general, the

Cadomin presents the lowest net pay in the eastern regions of the township. Pay increases both

north and southward. The SgФhnet value reaches a maximum around the center of the township.

Values for the SgФhnet net pay range between 0.074964m and 0.79197m. Contour lines, though

complex in nature, do tend to follow a southeast-northwest trend, parallel to the thrust belt of the

Rocky Mountains.

The Nikanassin presents a simpler net pay map then the Cadomin. The patterns of this diagram

loosely follow the trends seen in the gross thickness map for this region. SgФhnet values reach a

maximum in a southeast-northwest trending diagonal line that passes near to the northeast corner

of the township. Pay then thins towards the northeast corner and southwestern regions. Another

maximum point occurs in the southwestern corner of the township. This is the exact location

where the majority of the Nikanassin penetrating wells within this township have been drilled.

The largest recorded SgФhnet pay value in the Nikanassin is 1.38455m, while the smallest is

0.7437m. Note that regions within the center of the map had to be assumed, since no data was

available for those areas. Once again, historical production data in the Nikanassin is used as a

basis for the pay approximations. Actual pay values for the region could show some variance

from the assumed values. In order to obtain the true SgФhnet pay, additional wells would have to

be drilled.

Net pay maps are available in Appendix J of this report.

6.4: Cross Sections Cross Sections were developed to highlight the lateral continuity of the Cadomin and Nikanassin.

In total, three cross sections were created

-Cross Section A: A north-south trending cut

-Cross Section B: An east west directed section

-Cross Section C: Lateral analysis in the direction parallel to

the southeast-northwest thrust fault

Each section cuts through three wells. Cross Sections were not lined up based on actual subsea

depth since this parameter varies significantly between wells. As seen in the topographical maps

of the Cadomin layer, the southwest portion of the Cadomin is over 200m deeper than the

northeast section. Therefore, a structural cross section would not be very useful in this situation.

of true depth the beginning of the layer. Instead, the top of the Cadomin region was selected as

33

the datum for each cross section. Therefore, these maps are stratigraphic. This datum was chosen

because it presents an obvious regional marker. More specifically, the top of the Cadomin region

always seems to contain a 2-5m shale streak. This was obviously deposited in a laterally

continuous matter before folding and faulting displaced sections of the Cadomin formation. By

lining up these points, it is easy to compare the depositional features of the rest of the formation

in the positions that they were likely in during formation. A diagram of the cuts is provided in

Appendix J. Each cross sectional diagram marks the locations of sandstone and shale dominated

regions. In addition, the approximate depths of the Monach, Beattie Peaks, and Monteith are

labeled and correlated. Note that some of the logs within these cross sections do not penetrate the

entire depth of the Nikanassin. Therefore, full analysis of these regions could not be complete.

These logs can be easily spotted, since they do not show correlations for the Beattie Peaks and

Monteith depths.

Each cross section shows similar patterns between sandstone and shale deposition. Sandstone

areas are highlighted in yellow, while shale zones are marked with black. The Cadomin is

evidently the sandier of the two formations. Typically, 3-4 shale streaks can be found in the

Cadomin. The exception to this rule is well 00/12-32-065-08W6, which presents a higher shale

content, and is almost double the thickness of the other Cadomin locations. It should be noted

that the Cadomin always seems to present a shale streak at the top and base. These, laminated

shale layers bound the formation, and likely act as no flow boundaries that prevent cross flow

between formations.

The Nikanassin presents a much higher shale content then the Cadomin. This is particularly true

within the Beattie Peaks layer. Almost the entire content of this section contains some level of

shale. Even the sandier formations of these formation, the Monach and Monteith, contain high

shale levels. This adversely affects the Nikanassin’s production potential, as layers with high

gamma content are not considered as pay. The provided cross sections also mark the

approximate tops of each sub layer within the Nikanassin. From this analysis, it is clear that the

Monach layer is the thickest. In general, this layer seems to occupy just under half of the total

Nikanassin interval. The Beattie peaks and Monteith are approximately the same thickness in the

northern regions of the township. Analysis of the cross sections shows, however, that the Beattie

Peaks layer thins in the southeast portions of the Nikanassin, parallel to the thrust belt.

6.5: Bubble Maps Bubble maps give an idea about the potential of a formation of interest. Bubble maps that show

the cumulative production from Cadomin and Nikanassin Formations inside township 65 can be

found in Appendix J. Looking at the Cadomin bubble map, we can see that the smallest bubble

represents a production of 100 m3 of dry gas, whereas the larger bubbles gives a cumulative

production of about 280 E6m3 of dry gas. This huge variation shows that we have a variable

permeability distribution inside the township. As for the Nikanassin bubble map, we can only

detect 8 bubbles on the map. This suggests that production from the Nikanassan formation is

limited and undeveloped. The production rage for the Nikanassin is betweem 1.3 E3m3 and 114

34

E6m3 of dry gas. Indeed, the numbers are a confirmation of the limited production from the

Nikanassan.

7. Reserve Estimates 7.1: Volumetrics Volumetrics were used to estimate the Original Gas in Place (OGIP). The Net thickness maps

coupled with the trapezoidal rule were applied to both Cadomin and Nikanassin Formations,

respectively, as shown by the following equations:

OGIP = Ah∅(1 − Sw)

Bg

V =h

2[Ao + 2A1 + 2A2 + . . . + 2An − 1 + An]

Thickness maps can be found in Appendix K. Volumertics results are shown in Table 1 below.

Because these values were derived primarily from visual inspection, they have a very low

accuracy. As can be seen, the estimate of OGIP for the Nikanassan formation is slightly higher

than that for the Cadomin, indicating it has higher potential. This can be attributed to the fact that

the thickness of the Nikanassan is about three times that of the Cadomin. Also, the Nikanassin

being a mainly tight and shaly formation, whereas the Cadomin is a conglomerate. Refer to

previous sections about geology of the area.

OGIP (E6m3)

Cadomin Thickness Map 408.381

Nikanassin Thickness Map 485.408

Total 893.789

Table 1: Results of the Volumetrics OGIP calculations based on the thickness maps for

formations of interest.

7.2: Material Balance Since the pool we are looking at is a dry gas pool, the material balance equation reduces to the

plot of P/Z versus cumulative production (Mattar & McNeil, 1998). Such a plot was made for all

the wells producing from both Cadomin and Nikanassin Formations in order to estimate the

OGIP. The plot was made considering production from Cadomin and Nikanassin formations as

commingled. The plot is shown in figure 23 below. In the plot we can see two clusters of data,

one towards the top and the other towards the bottom of the data points. Those two trend lines

give the range within which an acceptable OGIP estimate can be made. As shown on the figure,

the red line represents the highest estimate of 1.08 E9m3 of dry gas, while the yellow line

represents the lowest estimate of 870 E6m3. An average was taken through the green line which

gives an OGIP of 1.0 E9m3.

35

Figure 24: Plot of Material Balance equation of P/Z versus cumulative production.

Note that the material balance estimates are definitely higher than Volumetrics estimate. This is

as expected since material balance is based on real production history and shut in pressures,

whereas Volumertics takes into account the assumptions made about cut-offs and the errors

included in them. For this reason, we consider the material balance the more reliable of the two

methods. Refer to Appendix L to find P/Z and cumulative production tabulated values for the

wells used in this plot.

8. Production Forecasting 8.1: Production History

Within the township of study, 12 wells were selected as our pool and 7 of those wells produced

from Cadomin and Nikanassin formations. As of July 2015, the 7 wells producing from

formations have a total cumulative production of 255,911.4 E3m3. Water production is

extremely minimal with water to gas ratios (WGR) of about zero. Only 1 well is producing from

Nikanassin and the other 6 wells are producing from Cadomin formation. Details of the

producing wells are summarized in tables found in in Appendix L. Also refer to Appendix L for

production graphs for wells of interest.

36

8.2: Reservoir Flow Characterization

For the detailed study of flow behavior the production histories of the 7 wells are presented in

graphs below. Log-log crossplots of monthly gas production versus time (months) is used to

identify the flow behavior (Zambrano et. al, 2013). There are 3 flow types identified in our target

zone namely:

1. Formation linear flow – with a slope of -0.5 E3m3/month

2. Bilinear flow – slope of -0.25 E3m3/month

3. Boundary Dominated Flow (BDF) – characterized by a steep slope.

8.2.1: Formation linear flow Formation linear flow occurs only in high conductivity zones. This type of flow is characterized

by a slope of -0.5 E3m3/month. In our area of study, formation linear flow is the most dominant

flow type. The following wells are characterized by formation linear flow behavior.

1.00

10.00

100.00

1000.00

10000.00

1.00 10.00 100.00 1000.00

MO

NTH

LY G

AS

RA

TE (

E3 M

^3)

T (MONTHS)

Well 12-32-065-8W6

Jet perforation(acid squeeze, fractured) : 17shots/m @ (2945-2948) m and (2437.5-2440) m

Jet perforation(fractured) : 17 shots/m @ (2663.5-2668.5) m

Jet perforation(fractured) : 17 shots/m @ (2535-2538) m

Slope = -0.569

Slope = -0.525

Slope = -0.884

37

Figure 25: Well 12-32-065: has 3 distinct slopes indicating the change in flow type as

time increase. From beginning to the 7th month (October 2003), slope = -0.569; from the

7th month to 39th month (July 2006), slope = -0.525 and from 50th month (June 2007) to

the final month of production, slope = -0.884 indicating that the flow wave is

approaching the boundary. Perforation intervals as well as the time at which they were

perforated

Figure 26: Well 08-22-065 has a slope of -0.515 which is characteristic of formation

linear flow and a slope = -2.665 indicating that the boundary was reached at 70th month,

September 2005.

0.10

1.00

10.00

100.00

1000.00

10000.00

1.00 10.00 100.00 1000.00

MO

NTH

LY G

AS

PR

OD

UC

TIO

N (

E3M

3)

T (NUMBER OF MONTHS)

Well 08-22-065-8W6

Jet perforation(fractured) : 16 shots/m @ (3033-3038) m

Slope = -0.515

Slope = -2.665

38

Figure 27: Well 14-11-065: has slopes -0.5 for linear flow until 18th month (April 2007)

and slope = -0.301 from 20th month (June 2007) until recent production. The recent flow

behavior is characteristic of bilinear flow.

1.00

10.00

100.00

1000.00

1.00 10.00 100.00 1000.00

MO

NTH

LY G

AS

RA

TE (

E3 M

^3)

T (MONTHS)

Well 14-11-065-8W6

Jet perforation(fractured) : 17 shots/m @ (3003 - 3008) m

Slope1 = -0.5 (linear flow)

Slope2 = -0.301 (bilinear flow)

0.10

1.00

10.00

100.00

1000.00

10000.00

1.00 10.00 100.00 1000.00

MO

NTH

LY G

AS

RA

TE (

E3 M

^3)

T (MONTHS)

Well 15-13-065-8W6Jet perforation(fractured) : 20 shots/m @ (3009 - 3013) m

Slope = -0.5 (linear flow)Flowback due to hydraulic fracturing

Boundary Dominated Flow

39

Figure 28: Well 15-13-065: has slope = -0.5 until the 32nd month (August 2003) then

BDF flowed.

8.2.2: Bilinear flow This is flow behavior is a combination of fracture linear flow and formation linear flow. Bilinear

flow is only observed in well 14-11-065 with a slope = -0.301 E3m3/month from the 20th month,

June 2007 to July 2015. This is an indication that there may be some natural fractures in this

well. Natural fractures can be identified when there is log separation between shallow resistivity

and deep resistivity (Aguilera, 1994). Well logs were studied to identify depth intervals at which

these fractures may be present. There was log separation between shallow resistivity (20 inch

investigation) and deep resistivity (60 inch investigation). However, normalization was critical

so that well 14-11-065 data makes sense. The normalization procedure was as follows:

Deep resistivity (60 inch investigation): assigned to round dot line,

Medium resistivity (30 inch investigation): assigned to dash line,

Shallow resistivity (20 inch investigation): assigned to long dash line,

We suspected that the log scale was mislabeled and this correction was important since there is

indeed log separation, but deep resistivity values were lower than that of the shallow resistivity.

The figure below shows the fractured depth intervals.

Natural fractures:(3001-3008)m

(3010-3013)m

(3018-3021)m

(3037-3043)m

Well 14-11-065

40

Figure 29: Shows estimated natural fractured zones in well 14-11-065

Therefore depth intervals with natural fractures and respective formations are:

(3001-3008) m: Cadomin

(3010-3013) m: Cadomin

(3018-3021) m: Cadomin

(3037-3043) m: Nikanassin

Other wells indicate the presence of natural fractures, but from the crossplots of monthly gas

production versus time, there is no indication of bilinear flow in these wells. The fracture linear

flow is usually short term and therefore may have been masked by the formation linear flow,

may this is the reason why bilinear flow behavior wasn’t observed in these wells. The wells and

their estimated natural fractured depth intervals are as follows:

Well 07-21-065: fractured zones are (3087.5 – 3092.5) m and (3097.6 – 3099.8) m, both

in the Cadomin formation.

Well 09-34-065: fractured zone is (2842.5 – 2845.3) m in the Nikanassin formation.

Well 13-30-065: fractured zone is (3073.2 – 3082) m in the Nikanassin formation.

Figures for natural fractured zone identification are shown in Appendix L.

8.2.3: Boundary Dominated Flow (BDF) This type of flow behavior is observed when the production has reached the boundary. The flow

is no longer linear and therefore production forecast cannot the modelled by exponential decline

analysis method since it will yield inaccurate future projections. To overcome this problem of

production forecast, type wells were developed based on whether the wells have reached the

boundary or not. The following 4 wells have reached the boundary as per the crossplots:

Well 12-32-065: this well followed the linear flow behavior then reached the boundary.

The graph is shown above under formation linear flow section.

Well 08-22-065: also had formation linear flow then BDF followed.

Well 15-13-065: there was formation linear flow during the initial months and BDF

during recent production.

Well 09-34-065: this well has formation damage since the slope of the crossplot of

monthly gas production versus time (months) is zero. By comparing the crossplot to the

graph of dimensionless rate versus dimensionless time (Sageev et. al, 1985), a relatively

horizontal line is indicative of positive skin which is the formation damage. This well

shown the formation damaged kind of flow until the BDF started at the 28th month,

February 2008. The crossplot for this well is shown below:

41

Figure 30: Well 09-34-065 shows a long period of formation damage until it reaches BDF at 28th

month

Some wells haven’t quite reached the boundary but there are approaching the BDF.

Well 07-21-065: has a slope = -0.7565 E3m3/month indicating transitional flow behavior

from formation linear flow to BDF. After the 15th month, April 2004, the monthly gas

production increased to 411.50 E3m3/month from about 283 E3m3/month. This 1.45

multiplication factor was due fractured zone production as a result of jet perforation. This

increased production declined at rate similar to that of the pre-perforation production.

That is, the production was still in the defined transition flow behavior. At 79th month,

August 2009, the production decreased rapidly indicating close proximity to the

boundary. The crossplot is shown in the next page.

Well 13-30-065: this well is also in transitional flow behavior with a slope = -0.699

E3m3/month indicating that the production is approaching the BDF. The crossplot for

this is shown in the next page.

10.00

100.00

1000.00

1.00 10.00 100.00 1000.00

Well 09-34-065-8W6

*Jet perforation(fractured, acid squeeze) : 17shots/m @ (2850-2853) m and (2795-2799) m*Fractured @ (2795-2799) m*Packer @ (2841.5-2841.5) m

Slope = -1.0

42

Figure 31: Well 07-21-065 shows transitional behavior from linear flow to BDF

Figure 32: Well 13-30-065 shows transitional flow behavior therefore the flow is

approaching BDF

1.00

10.00

100.00

1000.00

1.00 10.00 100.00 1000.00

MO

NTH

LY G

AS

RA

TE (

E3 M

3)

T (MONTHS)

Well 07-21-065-8W6Jet perforation(fractured) : 17 shots/m @ (3018 -

Slope = -0.7565 (linear flow to BDF)

Jet perforation(fractured) : 20 shots/m @ (3087.5 -3092.5) m

0.10

1.00

10.00

100.00

1000.00

10000.00

1.00 10.00 100.00 1000.00

MO

NTH

LY G

AS

RA

TE (

E3 M

^3)

T (MONTHS)

Well 13-30-065-8W6Jet perforation(fractured) : 20 shots/m @ (3065 - 3070) m and (2787 -2792) m

Slope = -0.699 (linear flow to BDF)

43

8.3: Analytical Decline Analysis

8.3.1: Exponential decline method In Accumaps program, monthly production rate versus time was fitted into Classic Production

Graph to compare exponential, harmonic and hyperbolic curves for all the wells in our targeted

zone. Essentially all the wells followed exponential type of decline.

For the wells with formation linear flow and bilinear flow, exponential decline analysis was used

to model future gas production. Those wells are:

Well 14-11-065

Well 12-32-065

Since forecasts for other wells could not be determined by exponential decline of individual

wells due to the fact that they are governed by BDF, type wells were developed and their decline

rate was calcuted. By summing individual monthly gas production, the decline for the pool was

evaluated

The equation for the exponential decline is:𝑄 = 𝑄𝑖𝑒−𝑐𝑡 therefore;

𝐿𝑛(𝑄) = 𝐿𝑛(𝑄𝑖) − 𝑐𝑡

Where;

𝑄 = 𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝑔𝑎𝑠 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛

𝑄𝑖 = 𝐼𝑛𝑖𝑡𝑖𝑎𝑙 𝑚𝑜𝑛𝑡ℎ𝑙𝑦 𝑔𝑎𝑠 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛

𝑐 = 𝑑𝑒𝑐𝑙𝑖𝑛𝑒 𝑐𝑜𝑛𝑠𝑡𝑎𝑛𝑡 (1

𝑚𝑜𝑛𝑡ℎ)

𝑡 = 𝑡𝑖𝑚𝑒 (𝑛𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑚𝑜𝑛𝑡ℎ𝑠)

A plot of Ln (Q) versus t in a linear scale produce line with a slope = - c. The determined values

of c and 𝑄𝑖 are as follows:

Well 14-11-065: c = 0.004/month

𝑄𝑖 = 105.5305 E3m3/month

Well 12-32-065: c = 0.0187/month

𝑄𝑖 = 1,204.235 E3m3/month

The following plots shows how the constants of the exponential decline method were determined

and the production forecast which was determined over 15 years. Even after 15 years of

production, well 14-11-065 still have a formation linear flow since there is no indication of the

BDF as per production forecast. When there is BDF, the curve tends to be more horizontal as it

illustrated in production forecast for well 12-32-065 which has an evident BDF at 112th month.

The time at which BDF starts was estimated by drawing a tangent that extends from the

horizontal portion of the graphs.

44

Figure 33: Determination of exponential decline equation constants for Well 14-11-065

Figure 34: Illustration of production forecast and production history for well 14-11-065

Figure 35: Determination of exponential decline equation constants for Well 12-32-065

y = -0.004x + 4.65

0.00

1.00

2.00

3.00

4.00

5.00

6.00

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00

Ln (

Q)

t (months)

Well 14-11-65: Ln (Q) vs time

-50

0

50

100

150

200

250

300

0 50 100 150 200 250 300 350

Gas

Rat

e (E

3m

3)

Number of months from Nov 2005

Production Forecast: Well 14-11-065

ProductionForecastProductionHistory

y = -0.0187x + 7.56

-2

0

2

4

6

8

10

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00 160.00

Ln (

Q)

t (number of months)

Well 12-32-65: Ln (Q) vs. time

45

Figure 36: Illustration of production forecast and production history for well 12-32-065

8.3.2: Pool Forecast The pool behavior was evaluated by summing the individual monthly gas productions and

summing the cumulative gas production of individual wells. This a bulk kind of analysis because

all the wells are added together even though the geological aspects (existence of BDF or not)

says otherwise. As a result the time at which BDF begin tends to be longer, at 223rd month. The

crossplot in Figure 38 indicates 2 slopes: slope1 = -0.1019 (transition from formation damage to

bilinear flow) and slope2 = -0.49212 (formation linear flow). The exponential decline parameters

were determined to be:

c = 0.0079/month

𝑄𝑖 = 3,338.494 E3m3/month

As shown in the graph below, production forecast is little bit shifted upwards compared to the

pool history data. However, the cumulative gas production of the both data sets is in agreement.

More figures are in Appendix L for more information.

-500

0

500

1000

1500

2000

2500

0.00 50.00 100.00 150.00 200.00 250.00 300.00 350.00

Gas

Rat

e (E

3m

3)

Number of months from Apr 2004

Production Forecast: Well 12-32-65

ProductionForecast

ProductionHistoryBDF bedins at 112th month

46

Figure 37: Illustration of pool production forecast and production history

Figure 38: Crossplot shows the flow types for the pool

The following graphs the recoverable gas reserves in our pool of 7 wells. When studying the

production history with the future production extrapolated, the recoverable gas reserves are

425,000.00 E3m3. When using exponential decline from the time zero until the next 15 years,

the recoverable gas reserves are 420,000.00 E3m3. These 2 values are in agreement and that

means the exponential decline method works best for modelling future gas production.

0

500

1000

1500

2000

2500

3000

3500

4000

0 50 100 150 200 250 300 350

Gas

Rat

e (E

3m

3)


Pool Production ForecastPoolForecast

PoolHistory

BDF starts at 223nd month

100.00

1000.00

10000.00

1.00 10.00 100.00 1000.00

MO

NTH

LY G

AS

RA

TE (

E3M

3)

T(MONTHS)

Pool Analysis

Slope1 = -0.1019

Slope2 = -0.49212

47

Figure 39: The recoverable gas reserves in our pool by production history and extrapolated by

exponential decline method

Figure 40: The recoverable gas reserves in our pool by exponential decline method

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

3500.00

4000.00

100000.0 150000.0 200000.0 250000.0 300000.0 350000.0 400000.0 450000.0

∑𝑄

(E3

M3

)

∑CUMULATIVE PRODUCTION (E3M3)

Total Gas Rate vs Total Cumulative Gas Production

Recoverable Gas Reserves = 425,000.00 E3m3

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.0

3500.0

4000.0

0.0 50000.0 100000.0 150000.0 200000.0 250000.0 300000.0 350000.0 400000.0 450000.0

∑Q

(E3

M3

)

∑CUMULATIVE PRODUCTION (E3M3)

Production Forecast as per Exponential Decline

Recoverable Gas Reserves = 420,000.00 E3m3

48

8.3.3: Type wells It is essential to know when the boundary will be reached and at what distance. Using our target

zone’s fluid parameters; permeability, porosity, total compressibility (estimated using the ideal

gas behavior,𝐶𝑡 =1

𝑃𝑖 ) and time (hours) at which BDF begins. For the wells with transitional flow

behavior, production forecasts were used to estimate the time at which BDF begins. The radius

of drainage was calculated as,

𝑅𝐷 = √𝑘𝑡

948∅𝜇𝐶𝑡

Radius of drainage was calculated for individual wells, pool and the type wells. The results are

summarized in tables 2 and 3 below for comparison.

Wells Radius of drainage (m)

15-13-65 4313.372

07-21-65 4617.8

14-11-65 N/A

13-30-65 8907.414

12-32-65 10186.76

09-34-65 3708.127

08-22-65 3365.742

Table 2: Summarizes radius of drainage for individual wells. Well 14-11-065 have no significant

BDF within a period of 15 years

Type well Radius of drainage (m)

Type well 1 7241.421




Pool 9127.781

Table 3: Summarizes radius of drainage for type wells and the pool

Based on the flow behavior and the geology (radius of drainage), type wells were developed as

follows:

Type well 1: include wells 13-30-065 and 07-21-065. These wells are approaching BDF

and second largest radius of drainage (the radius at which the production wave hit the

boundary). BDF begins at around 158th month from November 2003 as shown in figure

41 below.

Type well 2: include wells 12-32-065 and 14-11-065. Type 2 wells are characterized by a

linear flow and they have the largest radius of drainage. Type well 2 have BDF beginning

at 175th month from November 2005 as shown in figure 42.

Type wells 3: have wells 08-22-065 and 15-13-065. These ones are characterized by

linear flow then BDF and they have the 3rd largest radius of drainage. This type well have

BDF starting at 47th month from January 2001.

49

Type well 4: is made up of well 09-34-065 only since it’s the only well with formation

damage and has the smallest radius of drainage. BDF begins at 52nd month from

November 2005.

The longer the time it takes for the BDF to begin, the longer it will take to produce the well at

formation linear flow. Radius drainage gives an estimate of how far the well is from the

boundary and this helps in determining where to drill new wells.

Figure 41: Illustration of type well 1 production forecast and production history


0

200

400

600

800

1000

1200

0.00 50.00 100.00 150.00 200.00 250.00 300.00 350.00

Gas

Rat

e (E

3m

3)


Production Forecast: Type well 1

ProductionForecast

Production History

BDF begins at 158th month

0

200

400

600

800

1000

1200

0 50 100 150 200 250 300 350

Gas

Rat

e (E

3m

3)

t (number of months from Nov 2005)

Type well 2: Production forecast

ProductionForecast

ProductionHistory

BDF begins at 175th month

50



0

200

400

600

800

1000

1200

1400

1600

1800

0 20 40 60 80 100 120 140 160 180 200

Gas

Rat

e (E

3m

3)

t ( number of months from Jan 2001)

Type well 3: Production forecast

Production History:Exponential decline

Production HistoryBDF bedins at 47nth month

0

50

100

150

200

250

300

350

400

450

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00

Gas

Rat

e (E

3m

3)


Type well 4: Production Forecast

Production History:Exponential decline

Production History

BDF begins at 52nth month

51

Figure 45: Shows the position of the type wells in our target zone. The dashed circles shows the

apparent magnitude of the radius drainage for the wells

Type well 1

Type well 4

Type well 3

Type well 2

Type well 2

52

8.4: Flowing Material Balance The flowing material balance desires to model “flowing” tubing and casing pressures versus

cumulative production volumes in order to estimate OGIP. This procedure can be applied early

in the life of the well and is different than the normal material balance plot which uses shut-in

reservoir pressures ((Mattar & McNeil, 1998). The idea is to draw a line through flowing tubing

pressure and then draw a line parallel to it that passes through initial P/Z value. For our wells that

produced from the Cadomin and Nikanassin Formations, reasonable flowing bottomhole

pressures were not available. For this reason, wellhead pressures were used to make the plot

shown below in figure 46. Tabulated values of well head pressures can be found in Appendix L.

Figure 46: Plot of Flowing Material Balance equation of wellhead pressure versus cumulative

production.

The red and yellow lines that were used in the material balance plot to show the highest and

lowest reserves estimate were also drawn on the flowing material balance plot. Notice that these

two lines are parallel to the fitted blue trendline that passes through the flowing wellhead data.

Thus, similar reserves estimates to the ones obtained through material balance are expected. The

blue line serves as the expected decline linear relationship.

53

9. Optimization analysis:

9.1: Optimization Methods In order to improve the productivity of the township, different alternative will be analyzed. In

total, 4 main methods will be proposed:

1.) Base Case: This is the simplest optimization method. In essence, this method

suggests that absolutely nothing new be done within the township. That is, production

is continued in the exact way that it has been previously. This will be the cheapest

method, but it results in the least income. However, due to current economic

conditions, it may be the most profitable. Since this method involves no new

investment, it is used as the base case. The performance of all other methods will be

compared to this option

2.) Infill Drilling: In this method, new wells will be drilled within the township. In order

to increase the probability of success for these wells, the drilling locations will be

marked between two currently existing production locations. This is known as infill

drilling. Because formation data is already available at original well locations, and the

existence of a gas pool in the area has been confirmed, it is highly likely that these

infill wells will be productive. In order to produce from the new locations, however,

the wells must be drilled, completed, perforated and fractured. In addition, new

roadways, facilities and pipelines must be installed at the well locations.

The location of these wells will be perpendicular to the maximum stress lines of the

Western Canadian Sedimentary Basin. This will maximize the efficiency of the

hydraulic fracture regime by allowing transverse fractures to grow from the wellbore

axis (Beard, 2011). The proposed infill drilling scheme for this project is as follows.

Three new wells will be drilled per year. This will continue for a maximum of five

years. The profit associated with infill drilling for a total of one, two, three, four and

five years will be calculated and compared to determine the best drilling scheme. The

overall earnings of the optimal infill method will be compared to the base case.

3.) Reperforation and Fracturing: This optimization method proposes the activation of

currently dormant layers of the formation. To do this, new sections of the wellbore

will be perforated, then fractured. Of the 12 selected wells for this township, seven

are producing. All of these producing wells have not been fully perforated or

hydraulically fractured. Six of the seven wells wells have already hit the boundary

condition. For these wells, a reporforation and fracture would not provide much

improvement to the production conditions. The incremental increase in production, if

any, would not be worth the extra cost.

The last well, 00/14-11-065-08W6, is still under billinear flow, and can be worked

over to improve production rates. This well is currently producing from the Cadomin

54

formation. Because, production data is only available for this region, new perforations

will also be within the Cadomin. As with infill drilling, a four stage fracture job will

be initiated. Each perforation interval will be 5m long.

This method is significantly cheaper than infill drilling, since there are no costs

associated with the installation of new facilities, pipelines or roadways. In addition,

no new drilling or casing/tubing costs will be encountered. This method, however,

will result in less production then infill drilling. The earnings of this method will be

compared to the base case.

4.) Combination: This method involves a mixture of infill drilling and

reperoration/fracturing of the existing well under non boundary conditions. Since this

methods deal with improvements on completely different wells (existing wells vs.

new infill wells), it will be the sum of options 2 and 3. Therefore, depending on the

success of the independent fracture and infill drilling projects, this could either be the

best or worst optimization method.

10. Infill drilling – Project Components:

10.1: Horizontal Drilling

10.1.1: Definition:

As a convention, most wells are drilled vertically. In

this configuration, the wellbore intersects through

multiple pay zones of the formation. However, there

are many disadvantages to the vertical well setup. In

particular, vertical wells only contact a small portion

of the actual pay zones that they intersect. This lowers

the overall productivity of the well.

Horizontal wells have been introduced to combat this

problem. These wells have many distinct advantages

over their vertical counterparts.

These include (Joshi, 1991):

-Horizontal wells have an increased contact area with the reservoir. This maximum

reservoir contact allows for the intersected pay zone to be drained more effectively.

Figure 47: Comparison between

vertical and horizontal wells.

55

-These wells take advantage of gravitational forces in the drainage process. Therefore,

fluids will flow at a fast rate into the wellbore. The increase in rate is a function of the

fluid weight

-Horizontal wells reduce the pressure drop in the formation. Therefore, fluid can be

recovered for longer periods of time before depletion and abandonment occurs.

-These wells can intersect fractures and drain them right into the wellbore. This allows

for very efficient recovery.

-These wells can improve the drainage area of a given well in low permeability regions.

This reduces the number of wells required to develop the reservoir

-Horizontal wells are particularly advantageous in gas reservoirs. The recovery of fluid in

a gas region with a horizontal well is two to three times the amount that could be

recovered by a vertical well.

-Horizontal wells can operate under linear flow conditions, similar to a fracture.

These benefits make horizontal wells ideal for unconventional gas reservoirs. The increased

productivity and recovery is particularly appealing in the Cadomin and Nikanassin formations,

due to the lower production rates, irregular pressure distributions, and tight permeabilities.

10.1.2: Types

There are many types of horizontal wells. As outlined by Sada Joshi, the four main horizontal

well configurations are Ultrashort, short, medium and long. Of these, the most typical setup for a

horizontal well is medium. In this configuration, a 300-800ft hole, known as the turning radius,

is used at the kickoff point to convert from the vertical to horizontal direction. This large turning

radius allows for the use of conventional drilling tools during the project. The angle of decline of

the horizontal hole is 6o to 20o per every meter of length. These wells are 1000-2000ft in

horizontal length. This is ideal for a horizontal well, as evidence has shown that the first 2000ft

of the wellbore accounts for the majority of the production. Medium setups and can be

completed open or closed hole (Joshi, 1991).

56

Figure 48: The four main horizontal drilling configurations

The reservoir under study features two separate formations, the Cadomin and the Nikanassin.

Therefore, each infill well will kickoff at two separate locations. The horizontal section of the

well within the Nikanassin formation will intersect with one of the Monach or Monteith layers.

Beattie Peaks is not considered since it is unproductive. The layer within the Nikanassin at which

the Horizontal kickoff occurs will completely affect the depth of the well. It is common

convention to vertically drill out the entire depth of the formation regardless of the depth of the

horizontal portion. This allows the Geologist to log and core the full region. After this process is

complete, the depth below the kickoff point is plugged and abandoned.

10.1.3: Drawbacks

There are numerous benefits of horizontal drilling. Despite this, the process also has a few

distinct limitations. The largest disadvantage of these wells is that they only contact a single pay

zone. Therefore, one layer is drained per horizontal well. This prevents the well from reaching

the productivity potential of the entire reservoir. This issue however, can be resolved through the

use of vertical hydraulic fractures. These features will intersect through multiple pay zones,

draining the entire formation.

The other major disadvantage of horizontal drilling is the cost. As a crude estimation, horizontal

wells are two to three times more expensive to drill then a vertical well. However, the extra

productivity from the horizontal job should balance the extra cost over time. In addition,

horizontal wells feature a sharp drilling learning curve (Joshi, 1991). As the drillers gain

experience with the horizontal drilling methods, they will be able to create and complete the well

more effectively. Therefore, the costs of horizontal drilling should go down as more jobs have

been completed. That is, the second horizontal well will cost less the first, and the third will cost

less than the second. This reduction in cost may be minor between two well jobs. On a larger

scale, however, the savings are significant.

57

Figure 49: Comparison of drilling and completion costs for vertical and horizontal wells. This

example is a case study from Prudhoe Bay, Alaska (Joshi, 1991)

In the case of an unconventional formation such as the Cadomin or Nikanassin, the advantages of

horizontal drilling outweigh the drawbacks. Therefore, the prospective infill wells within this

region will all be drilled horizontally.

10.2: Fracturing

10.2.1: Natural Fracture Definition:

Fractures are defined as small cracks in the formation, created from the application of pressures

that exceed formation stresses. Two main classifications of fractures exist; natural and hydraulic

(Lee et al, 2005). The first case, natural fracturing, occurs within the formation due to

overburden pressures. Therefore, these exist without any sort of manmade prompting. The

Cadomin and Nikanassin both feature small natural fractures. These provide large flow conduits

for the gas in place. Without these fractures, in fact, neither formation would be able to produce

much fluid. This is due to the low matrix porosity and permeability within the productive

regions.

10.2.3: Natural Fracture Regimes

Two types of natural fracture regimes exist. These are known as the dual porosity and dual

permeability models (Lee et al, 2005). In the dual porosity model, both the matrix and fracture

provide storage space for the fluid. However, only the fractures allow for flow to the wellbore. In

other words, the matrix space is not in communication with the wellbore, and flow occurs from

the matrix, to the fracture, and into the wellbore. The dual permeability model, on the other hand,

58

sees both the matrix and fracture providing storage and flow pathways to the wellbore. As stated

by Aguilera, a triple porosity model can also be defined in tight gas reservoirs. This model

accounts for intergrunular, microfracture, and isolated moldic porosity (Aguilera, 2011).

10.2.4: Hydraulic Fracture Definition

Natural Fractures provide an increase in fluid flow from the formation. Oftentimes, however, the

productivity of a reservoir can be further increased through the implementation of manmade, or

hydraulic fractures. This is particularly necessary in unconventional reservoirs, which have large

volumes of gas resources, but low permeabilities and recovery factors under the current state

(Aguilera, 2014).

Hydrualic fractures are formed by the application of sufficient hydrualic forces to overcome the

natural stresses (Yew, Weng, 2015). This is often accomplished by injecting fluids into a

reservoir at locations of low stress. Small solid materials, known as proppants, are added to the

fluid as it is injected. The fluid is responsible for breaking the formation and expanding the

fracture. Once the fluid is removed from the system, the proppant is responsible for pushing the

sides of the fracture apart. Without proppant, the formation would close in on the fracture after

fluid leak off, invalidating the intent of the

job.

Fractures open up parallel to the direction of

minimum stress. Therefore, the width of the

fracture will be along the direction of the

minimum stress. The length of the fracture,

on the other hand, will be perpendicular to the

minimum stress, or parallel to the maximum

stress. For this reason, horizontal wells drilled

parallel to the maximum stress line will have

fractures branching outwards from the

wellbore in the transverse direction. This

prevents the overlapping of different fracture

regimes, improving recovery (Beard, 2011).

10.2.5: Hydraulic Fracture Regimes

Hydraulic fractures present five main types of flow regimes. The first, fracture linear flow,

occurs when all fluid storage and production occurs from the fractures. This mechanism will

only exist for a short period, before the matrix becomes involved in production. Once the

formation begins drawing fluid from the matrix, one of two new regimes can develop. The first,

known as bilinear flow, occurs in shorter, low conductivity fractures. Billinear flow is signified

by a quarter slope of the pressure and pressure derivative curves on a pressure vs. time diagnostic

plot. If the fracture is long and features high conductivity, Formation linear flow will begin. As

Figure 50: Schematics of a hydraulic fracture.

Note that the fracture opens up parallel to

minimum stress (Adapted from the University

of Minnesota, 2012)

59

discovered by Aguilera, this flow regime is signified by a half slope for the pressure and pressure

derivative curves on the diagnostic plot. After a period of time, Billinear or Formation linear

flow will become elliptical. This eventually leads into Pseudoradial flow, which mimics the

transient type conditions of the middle time region (Lee et al., 2005)

10.2.6: Proppant Type

When designing a hydraulic fracture, the proppant type to be used must be significantly

considered. The predominant proppant size used within shaly, gas filled wells is the 40/70 or

40/80 mesh (Beard, 2011). These proppants are medium to large in size, allowing for a wider

fracture opening. In larger fracture jobs for tight gas reservoirs, the 30-50 should also be

considered (Aguilera, 2011). Because the Cadomin and Nikasassin regions are shale bearing gas

formations, these three proppants will be considered for selection.

In a test performed within the Western Canada Sedimentary Basin, Aguilera found that the 40-70

proppant created a larger fracture size then the 30-50 mesh variant. Only 20% of this fracture

volume, however, was found to be effective at conducting fluids. The 30-50 mesh proppant

formed a smaller, but more permeable fracture, with over 60% conductance.

Therefore, the smaller 40-70 proppant showed poorer performance under the high stress

conditions of the Western Canada Sedimentary Basin. Therefore, to optimize the fracture

production within this region, a 30-50 mesh proppant should be selected.

10.2.7: Number of fracture stages

Hydraulic fracturing is performed in small sections, known as stages. These stages start at the

end of the wellbore and move towards the beginning (Gorman, 2011). As stated by Beard,

fracture stages are typically 250-500ft in length. Each stage should ideally be places 50-100

inches apart.

The number of fracture stages initiated in a formation can be highly variable. Multistage

fracturing is known to improve the productivity of the well, at the detriment of increased costs. A

Multistage fracturing test has been performed by Gonzalez, Aguilera et. al within the Western

Canada Sedimentary Basin. The area of study is in a similar location to that being studied in this

project. Results of this test are shown below:

Figure 51: Results of the Multistage fracture test performed within the Western Canada

Sedimentary Basin (Aguilera et al., 2014)

60

The effective conductivity of the fracture job decreases after the second fluid stage. Therefore,

subsequent Hydraulic fracture stages will require a larger half-length in order to achieve

reasonable productivity. Such a job would require a larger volume of proppant. When

determining the total number of fracture stages, however, the total permeability of the formation

must also be considered. Under the guidelines of Wei and Holditch, a fracture job in a tight gas

sand with permeabilities between 0.1-5 mD should feature 4 fluid stages, 1 predpad, 1 pad and 1

afterflush stage. Therefore, a total of 6 stages will be considered for this project. Of these, 4

stages involve fluid and proppant injection.

Figure 52: Relationship between formation permeability and number of fracture stages for a tight

gas reservoir (Wei, Holditch, 2009).

10.2.8: Fracture Size

The size of the fracture job is a key factor to consider. Larger fractures will result in increased

well performance. These jobs, however, will require additional proppant and fluid volumes.

Though the overall production of a larger fracture is higher, the incremental change in recovered

fluids per foot of additional length decreases with fracture length (Wei, Holditch, 2009). These

are all important factors to consider when determining the amount of proppant required for a

fracture stage. Therefore, a balance between incremental cumulative production and the extra

fracturing expense of each job must be found.

Figure 53: Cumulative production of a reservoir over increasing fracture half lengths. Note that

the incremental production decreases as the half length increase (Wei, Holditch, 2009).

61

In order to truly analyze the optimum fracture volume for this project, data within the township

of study would have to be analyzed. The overall profit of each different fracture job would be

calculated using the current gas price. Unfortunately, there is a lack of horizontal well production

data within this township. Without this information, it is not possible to determine optimum

performance firsthand.

Instead, the ideal proppant volume will be determined based on tests performed at similar

locations within the Western Canada Sedimentary Basin. In 2011, Aguilera and Leguizamon

performed a study on job size, using a 30-50 mesh proppant. From this test, it was determined

that the medium range, 45 tonne fracture job presented the largest increment in cumulative

production. The 55 ton and 65 tonne fracture jobs only showed slightly better production

potential. Essentially, the cumulative production from these larger jobs can be considered

equivalent to the 45 tonne fracture. The minor increment in fluid recovery is not worth the

additional costs. This is especially true under the current economic conditions. Low gas prices

will reduce the effect of additional production, making proppant cost the key factor in job

optimization.

Figure 54: Comparison between fracture half length and cumulative production. The largest

incremental increase in production seems to occur between the 35 and 45 tonne job. Cumulative

production is relatively unaffected by fracture size after this point. With these considerations in

mind, the 45 tonne fracture job seems to provide optimum results (Aguilera, Leguizamon, 2011)

62

10.2.9: Fluid Volume

To crack the formation open, a volume of fluid will be required. This fluid is pumped into the

system, fracturing the rock material perpendicular to the minimum stresses. As expressed by Wei

and Holditch, the volume of fluid per fracture stage is affected by the viscosity of the fracturing

fluid, and the number of stages present. In this case, a high viscosity fluid is defined above

200cP. The fracturing fluid used in this project will be water. Therefore, analysis will be focused

on the lower viscosity fluids. Results are shown in the table below:

Figure 55: Proppant concentration per unit of volume (in lbm/gal) for the stages (Wei, Holditch,

2009)

In the case of this project, a four fluid stage fracture job is used. Therefore, the stages will

require proppant concentrations of 1.5lbm/gal, 2lbm/gal, 2.5lbm/gal and 3lbm/gal. As

determined from the analysis by Aguilera and Leguizamon, 45 tonnes, or approximately 100,

000 lbm of proppant is required per fluid stage. From this, it can be found that 67,000gal,

50,000gal, 40,000gal, and 34,000gal will be required for stages 1, 2, 3 and 4 respectively.

Therefore, a total of 191,000 gallons of water will be required for fracturing in each formation.

Since both the Cadomin and Nikanassin will be fractured, 382,000 gallons of water is necessary

per well.

10.2.10: Fluid Pumping Rate

Three slurry flow rates were teted; 8m3/min, 9m3/min and 10m3/min (Aguilera, Leguizamon,

2011). It was found total performance of the fracture job was not largely affected by fluid

flowrates. Taking economic considerations into account, it was found that the best fluid pumping

rate is 9m3/min

10.2.11: Conclusion

For each fracture, 45 tonnes of 30-50 proppant will be used. Therefore, the total proppant weight

required per well is 360 tonnes. This will require 191,000gal of water. Water is pumped into the

system at a rate of 9m3/min

63

10.3 Dry Gas Facilities After dry gas is produced, it needs to be purified from any contaminants, separated from any

liquids and solids, and prepared to meet sales requirements. The main function of a facility is to

treat gas for sales or disposal and deliver it to the transportation system. A common gas facility

consists of a gas battery and a compressors as shown in figure 56. Most gas batteries contain

separators and dehydrators.

Figure 56: Common dry gas facility diagram (Gas Battery Diagram)

10.4: Stress Map The location of the infill drilled wells must now be determined. All developmental cases that

involve drilling new wells should be performed along southeast-northwest minimum stress

direction. This is parallel to the thrust belt of the Rocky Mountains. Therefore, the horizontal

wellbore will intersect the southwest-northeast oriented maximum stress lines. This is done so

that the largest overall permeability in the region can be utilized. Fractures should always be

placed so that their width is parallel to the minimum stresses. This will increase the size of the

64

flow opening. Because of this, permeability is always at its largest in SW-NE direction, due to

the maximum principal stress. Thus, if the wells are drilled along the minimum stress lines,

wider fractures will be able to develop outwards from the horizontal wellbore

Figure 57: Stress Map of the Western Canada Sedimentary basin shows that the minimum stress

direction is southeast-northwest trending, parallel to the thrust belt of the Rocky Mountains. All

wells will be drilled in this direction

10.5. Capital Expenses: Drilling Costs

10.5.1: Exploration

This project focuses on the drilling of infill wells. Based on data from nearby locations in the

township, it can be concluded with reasonable certainty that the newly drilled wells will contact

gas reserves. Therefore, it may not be necessary to conduct hydrocarbon exploration tests.

However, under the current economic climate, it is particularly risky to drill based on

hypothetical evidence from nearby wells and data correlations. The cost of drilling and

65

abandoning without production would be detrimental to a company. In order to increase the

probability of success from these infill wells, it is recommended that exploration tests be

performed if allowed in the company budget. This is an extra cost, but the sacrifice is worth

gaining insight on the reservoir potential. In other words, it is better to take a small loss on

exploration for the sake of knowledge, then to deal with the crippling consequences of drilling

and abandonment.

To confirm the presence of hydrocarbons, seismic tests will be performed at each new drilling

locations. These tests use blasts of sound from powerful air guns to penetrate the strata. These

sound waves navigate the subsurface, and are reflected or refracted by geological beds

(Lavernge, 1989). By observing the propagation and transmission of these waves, a geologist or

engineer can determine rock and fluid interfaces. This information, along with other seismic

data, can be used to determine the potential reserves of the formation.

The township under study in this paper is located within the foothills of Alberta. Based on

Sproule chart estimate (Sproule Associations, 1999), a seismic survey in this location would

have an average cost of:

$26,250 per km of depth (1999 CAD dollars)

The average depth of the formation, measured to the bottom of the Nikanassin region, is 2550m.

Therefore, the total exploration costs are equal to:

$66,937.50 (1999 CAD dollars) per well

$200,812.50 (1999 CAD dollars) for three wells.

This is a lesser cost compared to that expected for a full digging and rigging procedure in an

unsuccessful environment.

10.5.2: Rig rental

A rig is required to drill the new infill wells. One rig will be rented for all five wells. This rig

will be transported to different locations over the year. In order to save costs, the rig will be

rented, not bought. According the Sproule Associations, drill rigs are rented on a per day basis.

The daily cost of a rig rental is related the drilling depth. Based on the average 2550m formation

depth (note that the formation depth never exceeds 3000m), a triple drilling rig must be used.The

cost of a rig rental is:

$8,544 (1999 CAD dollars) per day.

In one day, a rig can drill through 250m of formation (Sproule Associations, 1999). This is an

average estimate for typical rock formations. The Cadomin and Nikanassin, however, are

composed of hard and tight material. The compact sandstone within the region will take a longer

amount of time to drill through. In addition, care must be observed when drilling through the

shale regions, in order to avoid hole collapse. Therefore, it is assumed that this drilling process

will take twice as long as a normal procedure. That is, the rig can drill through 125m of

formation per day.

66

The new wells within the region will not be vertical, but rather, horizontal. When dealing with

this kind of well configuration, is customary to first drill out the entire vertical depth of the

formation. This allows for openhole logging and coring within the entire region. In order to save

costs in the rental process, an average depth of 2500m will be assumed for the calculation. Based

on the formation depth, it is concluded that the rig can drill a vertical wellbore in 20 days. An

extra 5m drilling depth will be tagged on to each day in order to cover the entire 2550m

formation depth.

As this is a preliminary economic estimate, it is reasonable to assume the maximum drilling

depth for each formation. This assumption will result in maximum costs, which allows for proper

budgeting, and gives the lower bound for economic profit. In addition, it is recommended by

Joshi that the entirely of a formation be vertically drilled, regardless of the depth of the

horizontal kickoff point.

In order to take advantage of conventional drilling equipment, medium horizontal wells will be

drilled. In this type of configuration, the horizontal portion of the well length can be 1000-2000ft

(Joshi, 1991). Because this project is based on infill drilling, the new wells are all within

reasonable proximity to each other. In order to prevent excessive interference between wellbores,

a total horizontal well length of 500m will be drilled. This dimension was specifically chosen so

that it did not exceed 600m. Practical experience in the field has shown that wellbores are fairly

unproductive after the initial 600m length. Each horizontal well is planned to branch out in two

locations. Therefore, the total horizontal drilling length will be 1000m. This will take 8 days to

drill

Twelve extra days will be added to the drilling schedule. This will account for rig transportation

time, set up and takedown, maintenance issues, unworkable weather conditions, periods of

logging, coring and drillstem test analysis, and other unpredictable issues. In total, a 40 day

drilling program has been allocated to each well

$341,760 (1999 CAD dollars) per well.

The total rig rental cost will amount to:

$1,025,280 (1999 CAD dollars) for three wells

10.5.3: Drill bit

The cost of rig rental does not include purchasing a drill bit. For the coarse and compact

sandstones being analyzed in the Cadomin and Nikanassin region, a Button Bit is recommended

(Lloyd, 2014).

Due to the lack of information on drill bit pricing from actual manufacturing companies, an

estimate for the drill bit cost has been made from the Sproule chart. The cost of the bit is taken as

a function of drilling depth. The average formation depth for the Nikanassin of 2550m is used in

this estimate. Note that this expense is merely an approximation, since the Sproule chart does not

differentiate between different drill bit types. The total cost of a drill bit has been found to be:

$39,750 (1999 CAD dollars) for three wells

67

As with all equipment, the drill bit will wear out. However, due to the strength of the Button Bit,

it is fair to assume that it will last for all three drilling jobs. Since the lifetime of the bit ranges,

the cost per well becomes:

$13,250 (1999 CAD dollars) per well

10.5.4: Drilling Mud

Special muds are added to the wellbore during the drilling process in order to combat formation

overpressure and system blowout (Lloyd, 2014). Two main types of drilling muds exist; Water

based and Oil based. Previous drilling jobs in the selected township used an Invert drilling mud.

This type of drilling fluid contains a water-in-oil emulsion where water is the dispersed phase,

and crude or diesel oil is continuous (Barrett et al, 2005). This type of drilling fluid is commonly

used in environments like the Cadomin or Nikanassin, in order to prevent the swelling and

sloughing of shales (Lloyd, 2014).

The general cost of a drill mud is provided as a function of depth in the Sproule charts. The

assumed average depth of the formation under study is 2550m. Therefore, the cost of a drilling

mud, per well, is:

$56000 (1999 CAD dollars) per well

It is assumed that the drilling costs in the Sproule chart refer to the general, and more common,

water based muds. Oil based muds are known to be the more expensive of the drilling fluids. In

order to avoid under budgeting for this project, it will be assumed that Oil muds cost double of

the value listed in the Sproule Chart. Therefore, the total cost of an Invert mud for a single Infill

well is:



10.5.5: Surface costs

There are many costs that are associated with the drilling process, which must be covered before

drilling can officially begin. These include the acquisition of a drilling license, surveys,

landman’s fees, easements, capital damage, first year’s wellsite rentals, dirt work, engineering

and supervision (Sproule Associations, 1999). There is also a cost associated with transporting

the rented rig from the previous location to the new drilling location. This is known as the rig

move cost.

All of these expenses can be considered together as Surface costs. These costs are a function of

well depth. Based on the average formation depth of 2550m, the Surface costs can be estimated

to be:



68

10.5.6: Surface Casing

Surface casing is used in the wellbore to provide additional structural support, isolate weak

formations, hold the wellhead in place, and to establish integrity for further drilling processes

(Aadnøy, 2011). In this township, a 244.5mm surface casing is typically used. The surface casing

process, including cementing, is expensed as a function of casing depth. As recommended by

Aadnøy, the casing shoe in these infill wells will be run to a depth of 1000m below the

subsurface. Therefore, the total cost of the casing is equal to:



10.5.7: Logging

Log data should be taken at each new well location. This information can be used to obtain a

variety of reservoir and fluid properties, such as porosity, shale content and water saturation.

Since the measurement tool is run down the entire wellbore, logging costs will be a function of

the total formation depth. Based on the average depth of 2550m to the bottom of the Nikanassin

region, the well logging process will cost:



10.5.8: Coring

Cores should be taken within the region in order to determine rock properties. A good rock

sample will reveal information on the formation geology, depositional environment, facies type,

porosity, permeability and bulk density. Four core samples will be taken at each of our well

locations; one for the Cadomin, and one in each of the three Nikanassin regions (Monach,

Beattie Peaks and Monteith). The average core length from samples currently existing in the

township is 11.50m. This same length will be used as a basis for all newly drilled cores. In order

to allow for some core breakage or facies loss, which will happen in the shale dominated regions,

an extra 3.5m of core will be drilled. Therefore, the objective length of each core will be 15m.

Since four cores are taken per infill well location, the total core length will be 60m per well.

The tools for the coring process, including rig time, cost $5,000 upfront. An additional $75 is

expensed for every meter of core drilled (Sproule Associations, 1999). Therefore, the total cost

for the coring process is equal to:

$6,125 (1999 CAD dollars) per core



69

10.5.9: Drill Stem tests

A drillstem test is a temporary completion, using downhole tools, of the formation (Lee et. al,

2003). These tests are used to measure the pressure response in a well over time. These tests will

provide information on reservoir fluids, reservoir temperature, well productivity and pressure

distribution. The obtained pressure data can be used to estimate formation permeability, skin

factor, and static pressure conditions (Abdulsadek, 2015)

Four drillstem tests will be run in each new infill well. The first of these will be run within a

sandstone interval of the Cadomin region. The final three tests are run within the cleanest

intervals of each of the three Nikanassin regions; Monach, Beattie Peaks and Monteith.

The Cadomin and Nikassin are tight formations. In addition, the high shale content increases the

possibility of hole washout. This should be largely combatted through the use of oil based muds.

However the possibility of washout must still be considered. Because of the high shale content

and the low matrix permeability, straddle drillstem tests must be performed (Lee et. al, 2003).

The total cost for these tests, from the Sproule charts, will be:

$10,000 (1999 CAD dollars) per test



10.5.10: Other expenses

There are other minor expenses associated with the drilling process. For example, fuel must be

provided to the rig, and other operating equipment during the drilling time. Fuel costs amount to

$500/day (Sproule Associations, 1999). These fuel costs must be accounted for in all three

drilling locations. In addition, the costs of boilers and other heating equipment must be

considered during the winter months. According to the Sproule charts, these costs amount to

$1000/day. It will be assumed that one of the three infill wells will be drilled in the winter.

The operating crew will require a campsite and amenities during the drilling period. This is a

necessary cost, as the township under analysis is far from any local towns or accommodations.

The estimated campsite cost amounts to $1500 per day. The last major cost associated with this

project deals with unpredictable events, known as contingences. Because these are related to

future circumstances, the associated cost is difficult to estimate. As a rule of thumb, contigences

are worth 20% of the total project.

As estimated, each well will take 40 days to drill. Therefore, the additional costs amount to:

Fuel:



70

Boiler:


Campsites:



10.5.11: Total drilling costs:

The total drilling costs are shown in the chart below. These are converted to 2015 dollars using

the Chemical Engineering Plant Cost Indices (CEPCI), obtained from the Chemical Engineering

Magazine

CEPCI (1999) = 390.6 CEPCI (2014) = 575.7

CEPCI (2008) = 575.4 CEPCI (2015) = 558.3 (as of June 2015, preliminary estimate)

These cost indices account for economic variations in cost an expense between different

operating years. In essence, the conversion between two cost indices accounts for yearly inflation

and deflation effects.

Expensed

service/equipment

Cost in original year (1999 CAD $/well) Cost in 2015 (CAD $ /well)

Exploration 66,937.50 95,676.41

Rig rental 341,760.00 488,491.06

Drill bit 13,250.00 18,938.75

Drilling Mud 112,000.00 160,086.02

Surface preparation 250,000.00 357,334.87

Surface Casing 17,000.00 24,298.77

Logging 27,500.00 39,306.84

Coring 24,500.00 35,018.82

Drillstem Tests 40,000.00 57,173.58

Fuel 20,000.00 28,586.79

Boiler 40,000.00 57,173.58

Campsites 60,000.00 85,760.37

Sum 1,012,947.50 1,447,845.86

Contingences 202589.50 289569.172

Total 1,215,537.00 1,737,415.03

Table 4: Drilling costs for an infill well. Costs are analyzed on a vertical basis. This expense is

incremented up by a factor of three to account for additional horizontal drilling expenses.

The costs listed in this chart are for vertically drilled wells. These prices must be adjusted to

match the expenses associated with horizontal drilling. In general, a horizontally drilled well will

cost one and a half to two times more than a vertical well (Joshi, 1991). Due to the lack of data

available on horizontal well pricing, this approximation will be used for this project. The

71

increase in horizontal drilling prices is mainly due to the difficulty of the job, and driller

inexperience. Over time, however, the learning curve allows for greater drilling efficiency, and

decreased costs. As state by Roberto Aguilera, this learning curve is a lot steeper for horizontal

wells then vertical. In addition, the use of drilling optimization methods (Aguilera, 2012) allows

for a further reduction in horizontal drilling costs. On average, optimization will reduce the costs

of the well project by 3-9%, and the drilling time by 5-21%.

Based on this information, it is reasonable to assume that the horizontal drilling will become

cheaper after successive projects have been completed. The difference in expense between two

back to back drilling processes will not be significant. However, the savings between jobs

completed in separate years will be significant. This estimation allows the drilling crew a

significant period of time to learn better optimization methods.

The horizontal drilling jobs in the first year will be assumed to cost double of a vertical project.

Cost reductions from optimization will follow the 3-9% range proposed by Aguilera. In the

second year, the maximum reduction of 9% will occur. The fifth and final drilling year will see

the minimum reduction of 3% occur. Successive years in between will each see the cost

reduction factor decrease by 2%. This represents a fair learning curve range over time. As the

drilling crew becomes more experienced, they will reach a maximum optimization potential. At

this point, no new improvements can be made to the drilling job, and the costs will stabilize.

Year % change in cost from

previous year

Cost reduction factor

1 N/A 2

2 9 1.82

3 7 1.69

4 5 1.61

5 3 1.56

Table 5: Factor cost increase used to estimate horizontal well expenses from vertical well data.

The cost indices decreases every year, due to the learning curve, as well as other implemented

horizontal drilling optimization methods.

So, in the final year, the horizontal job will cost 1.56 times the amount of a vertical project.

These factors are used to determine the horizontal drilling costs, which can be found in the table

below:

Year Cost (2015 CAD $)

1 3,474,830.06

2 3,162,095.35

3 2,940,748.68

4 2,793,711.25

5 2,709,899.91

Table 6: Cost of Horizontal drill jobs, per well, over each year of the project. Costs decrease due

to the learning curve and other optimization methods.

72

Figure 58: The learning curve associated with a horizontal drilling job. Note that the incremental

decrease in cost becomes less as the years increase.

As expected, the effects of the learning curve decrease over time. The drillers cannot keep

learning more efficient tactics and drilling methods infinitely. Once the crew has mastered the

tactic of horizontal drilling, the prices will stabilize

10.6. Capital Expenses: Completion Costs

10.6.1: Production Casing and Cementing

Once the hole has been drilled, it is usually cemented and cased. The production casing is

installed for two main purposes; to act as a backup pipeline for the production tubing, and to

support the lower depths of the formation from collapse (Byrom, 2015). Based on these

purposes, the production casing must be able to support the weight of the fluids, while resisting

the pressures of the surrounding formation.

Production casings is not necessary in all wells. In particular, many horizontal wells are

produced without production casing, or openhole, without immediate consequences (Joshi,

1991). The exact need for production casing could be evaluated after the exact locations have

been scouted, or even during the drilling process. In this preliminary economic estimate, the

costs of production casing will be accounted for. It is always best plan for all expenses, so that

the project does not go over budget.

3,474,830.06

3,162,095.35

2,940,748.68

2,793,711.252,709,899.91

2,500,000.00

2,700,000.00

2,900,000.00

3,100,000.00

3,300,000.00

3,500,000.00

3,700,000.00

3,900,000.00

0 1 2 3 4 5 6

Dri

llin

g co

st (

$)

Year

Horizontal drilling - Learning curve

73

According to the Sproule Associations, the cost of production casing, including the cement job,

is a function of formation depth. Based on the 2550m average depth of the Nikanassin base, the

costs of production casing and cementing amount to:



Once the production casing is in place, the packers are set to specific zones. This isolates the

formation of interest for a hydraulic fracturing job

10.6.2: Rig time during completion

The drilling rig must always be present on site during the completion process. Therefore, extra

rig rental days must be accounted for in an economic evaluation. For a completion job at depths

greater than 2000m in depth, it is recommended that the rig be kept onsite for three extra days.

This accounts for the time required to case, perforate and fracture the formation.

For the formation depth being analyzed in this project, rig rental will cost $8,544 per day.

Therefore, the total rental costs amount to:



10.6.3: Perforating

Production casing acts as a strong boundary between the wellbore and the formation. So, if the

hole is cased, there is no way for fluid to enter the production tubing. To fix this problem, the

production tubing is perforated with a powerful shot from a specifically designed gun. On

average, 13 shots are fired into the casing per meter of formation (Sproule Associations, 1999).

This gives the fluid access to the wellbore.

A perforation job costs $3,000 to set up. This accounts for the first 3m worth of shots. Every

additional meter will cost $500. In this project, wells will be producing in both the Cadomin and

Nikanassin regions. In order to save costs, neither region will be fully perforated.

In the paper, Fracture Design in Horizontal Shale Wells – Data Gathering to Implementation,

Beard recommends 4-6 perforations per fracture stage. This matches the information obtained

from the existing wells in the township of interest. In specific, township data shows an average

perforation length of 5m for each Cadomin stage, and 4m for Nikanassin stages. The infill wells

drilled for this project will feature 8 fluid stages in total; 4 for the Cadomin formation, and 4 for

the section of the Nikanassin that is being produced.

Therefore, 20m of perforation shots are required per each Cadomin section, while 16m are

required in the Nikanassin. This results in 36 total perforation shots per well. The total cost of

perforations for each well is therefore:


74


10.6.4: Acidizing

The Cadomin and Nikanassin are predominantly composed of Sandstones, not Carbonates.

Therefore, an Acidizing job would be pointless. No cost allowance will be given to this sort of

treatment.

10.6.5: Fracturing

Fracturing costs can be divided into three main factors; proppant, fluid and pumping. In total,

eight fluid fracturing stages are performed per well. The first four will be caused within the

Cadomin region, while the last 4 will be formed in either the Monach or Monteith formation of

the Nikanassin region.

In total, 360 tonnes of 30-50 mesh proppant will be required per well. In order to obtain

maximum efficiency from the fracture job, a ceramic proppant will be used. According to Ted

Smalley of “buyproppant.com”, the average price of a proppant is $300-$800 (2014 USA

dollars) per tonne. Since the 30-50 mesh proppant is within the larger and more expensive range

of proppant types, a price per tonne of $800 will be assumed. Therefore, in net, the proppant will

be purchased for:

$288,000 (2014 USA dollars) per well

According to the Bank of Canada, the current exchange rate between American and Canadian

dollars is

$1.00 CAD = $0.7485 USA

Therefore, the cost of proppant in Canadian dollars is $1070.00. Therefore, the expense per well

caused by proppant acquisition is:



The proppant must be injected into the reservoir with a fluid. This fluid is responsible for

applying sufficient hydraulic pressure to crack the formation open. The cheapest, and safest fluid

to use in this situation is water. According to the 2009 Water Pricing Report by Steven Renzetti,

ground water is free to extract within Alberta. Therefore, the water for this project will be

obtained from a nearby ground well. Or, if available, recycled water from a previous fracturing

job will be used. This minimizes the transportation costs.

Lastly, a pump must be purchased to force the fracturing fluids and proppants into the wellbore.

The cost of a simple pump is dependent on the depth of the producing interval. For a formation

between 2000-3500m, the cost of a pump is (Sproule Industries, 1999)

$70,000 (1999 CAD dollars)

75

Two pumps will be purchased for fracturing purposes at each well. The first will feed fluids to

the Cadomin, while the second is directed to the Nikanassin formation. Therefore, the total pump

cost per well is:

140,000 (1999 CAD dollars) per well

520,000 (1999 CAD dollars) for three wells

Note that pumps also have an electricity requirement. This must be accounted for in the yearly

operating costs.

10.6.6: Wellhead and production tubing

In order to produce from the region, fluid must be directed to some sort of piping. This tubing

string will connect to the surface, at the wellhead, where it is directed to pipelines, separators,

and treatment facilities. The production tubing must be able to withstand the pressures exerted by

the fluids. It must also promote the flow of fluids to the surface by providing open transport

pathways.

As outlined by Sproule Associations, the production tubing and wellhead are considered

together, as a function of depth. For drilling jobs deeper then 2200m, the total cost of this

equipment is:



10.6.7: Miscellaneous costs

Other minor costs associated with completion must be accounted for. These expenses include

transportation of wellsite materials and equipment, supplies and accommodations, such as

campsites, for the crew during the completion process, and well/equipment maintenance. For a

2550m deep drill job, these costs amount to:



10.6.8: Contingences

As with any good completion project, contingences are taken into considering. As with the

drilling process, it is best to budget an extra 20% of the total project cost towards the

unpredictable factors. This money may not be used. But it is best to consider it anyways, so that

the project does not go over budget.

10.6.9: Total completion costs

Total completion costs are shown below. These are converted to 2015 dollars using the CEPCI

values, obtained from the Chemical Engineering Magazine

76

CEPCI (1999) = 390.6 CEPCI (2014) = 575.7

CEPCI (2008) = 575.4 CEPCI (2015) = 558.3 (as of June 2015, preliminary estimate)

This conversion between accounts for yearly inflation and deflation effects.

Expensed service/equipment Cost in original year (CAD $ per well) Cost in 2015 (CAD $ per well)

Casing and Cementing 108,000.00 (1999) 154,368.66

Rig Time 26,632.00 (1999) 38,066.17

Perforation 19,500.00 (1999) 27,872.12

Acidizing 0.00 (2015) 0.00

Proppant 385,200 (2014) = 261,350 (1999) 373,557.69

Fracturing fluid 0.00 (2015) 0.00

Pump 140,000 (1999) 200,107.53

Wellhead and Tubing 20,000 (1999) 28,586.79

Miscellaneous 55,000 (1999) 78,613.67

Sum 630,481.87 (1999) 901,172.63

Contingences 126,096.37 (1999) 180,234.53

Total 756,578.24 (1999) 1,081,407.15

Table 7: Completion costs for an infill drilled well in township 065-08W6

The total completion cost per well is $1,081,407.15 (2015 CAD)

10.7. Capital Expenses: Other drilling and completion expenses

10.7.1: Land costs

The lease to the land in the township has already been obtained during previous drilling

operations. Therefore, there are no costs associated with the acquisition of land in this project.

10.7.2: Drilling permit

Before drilling can begin, a permit must be obtained from the Alberta Energy Regulators board.

The cost of a drilling permit varies between the townships of Alberta. As an initial preliminary

estimate, the cost of a drilling permit will be assumed to be in the range of $750,000 (2015 CAD

dollars)

10.7.3: Road costs

The drilling crew and surface operators must be able to easily access the planned location for any

new wells. Therefore, roadways must be paved to each individual wellsite. These roadways

should be widened, in order to provide access to all heavy equipment and machinery. According

to the Alberta Government body on municipal affairs, an unpaved gravel roadway of 10m width

will cost:

$560,000 per km length (2008 CAD dollars)

77

On average, the new wellsite locations are 2.5 kilometers away from preexisting roadways.

Therefore, for 5 new infill drilled wells, the road costs amount to:

$1,400,000 (2008 CAD dollars) per well



10.7.4: Rig Move

The drilling rig must be transported between two locations. To do this, a trucking company must

be hired, and brought to the wellsite location. Actual transportation quotes can be obtained from

a trucking company once the project is set to begin. As a preliminary cost estimation, $15,000

will be allotted per well to the total rig takedown, transportation and setup process.



10.7.5: Abandonment

All wells must be abandoned at some point within the lifetime of the project. Abandonment can

occur for two major reasons. Either the formation was proven to be unproductive after the well

was drilled, or the pressure in the formation dropped below the abandonment value for the

location. Typical abandonment pressures are valued at 100psia per 1000 feet of depth (Craft,

Hawkins, 1991).

This project relies on infill drilling, and all drilling locations were pre tested with seismic

methods. Therefore, the probability of drilling success is very high. The first cause of

abandonment is insignificant, so no failed drilling jobs will be considered in this estimate. The

costs associated with depleted well abandonment, however, still must be accounted for.

According to Sproule Associations, a well drilled within the Alberta Foothills will cost $420 to

abandon per meter of drilled formation. The average depth at the base of the Nikanassin, 2550m,

will be used in the calculation. The horizontal drilling distance of 1000m must also be

considered. Therefore, in total, 3500m of formation must be abandoned. This results in a cost of:




Note that abandonment does not occur until the end of the project.

78

10.8: Capital Expenses: Gas Facilities

10.8.1: Pump

The first component of a gas facility is a pump to draw gas to the battery. Since this project is

based on an average depth of 2550 m, a pump for a maximum depth of 3500 m is selected.

According to Sproule Association, the cost of a 3500 m pump is as follow:



$428,801.84 (2015 CAD dollars) per 3 wells

10.8.2: Battery

One battery is required for each well to collect the gas then separate and purify it from any

impurities before it is being further processed or distributed. A one-well battery with 4’ treater is

selected for this project. The cost of the selected battery is, as provided by Sproule Association,

as follow:




10.8.3: Gas Treating Facility

After gas is purified in the battery, it is send to a gas treating facility to regenerates the desiccant

medium by dehydrators and increase the flowing pressure by compressors (Gas Battery

Diagram). Since the cumulative production of tight gas reservoirs is generally low, a dehydrator

with a small capacity, 2000-4000 MCF/day is selected. According to Sproule Association,

dehydrators cost as follows:




Installation cost must be also be considered when calculating the expenses of a gas treating

facility. It is reported by Sproule Association that the installation cost is 1.5 times the equipment

cost, which will give us a value of:


As mentioned previously, tight gas reservoirs has a low production rate; therefore, it requires a

gas compressor with low power. A 50-150 hp compressors was chosen in this project and it was

assumed that the compressors used would require 150 hp to work. Prices ar reported by Sproule

Association:

79



$2,220,443.15 (2015 CAD dollars) per 3 wells

Other equipment that need to be considered are Orifice meter run and line heaters with their

installation costs. As reported by a document made by Sproule Association:

Orifice Meter Run Equipment: $25,728.112 (2015 CAD dollars) per 3 well

Orifice Meter Run Installation: $64,320.28 (2015 CAD dollars) per 3 well

Line Heaters Equipment: $150,080.65 (2015 CAD dollars) per 3 well

Line Heaters Installation: $300,161.29 (2015 CAD dollars) per 3 well

10.8.4: Gathering Pipelines

Gathering pipelines are required to connect between different facility equipment and join with

the existing main pipeline in the township. A 4 inch pipeline is selected in this project and an

average of 2.5 km is considered in the township. According to Sproule Association, the cost of a

2.5 km pipeline will be:

$101,060 (1999 CAD dollars)

$144,449 (2015 CAD dollars)

10.9: Total Capital Expenses The total capital expenses are given in the chart below, in 2015 Canadian dollars. These are

shown on a per year basis. Note that 3 wells are drilled per year. The yearly expense of the infill

drilling can therefore be found as three times the individual well cost.

Also note that the learning curve changes the yearly cost of horizontal drilling. Therefore, the

total capital expense will vary between years. This must be accounted for in the economic cost

estimation:

80

Capital Expense Cost per year ($ 2015 CAD)

Year 1 Year 2 Year 3 Year 4 Year 5

Expensed at

project start

Drilling permit 750,000.00 750,000.00 750,000.00 750,000.00 750,000.00

Drilling 10,424,490.18 9,799,020.78 9,225,673.80 8,652,326.85 8,131,102.35

Completion 3,244,221.45 3,244,221.45 3,244,221.45 3,244,221.45 3,244,221.45

Roadways 4,075,182.00 4,075,182.00 4,075,182.00 4,075,182.00 4,075,182.00

Rig Move 45,000.00 45,000.00 45,000.00 45,000.00 45,000.00

Compressors 2,220,443.15 2,220,444.15 2,220,445.15 2,220,446.15 2,220,447.15

Batteries 321,601.38 321,602.38 321,603.38 321,604.38 321,605.38

Well on Pump 428,801.84 428,801.84 428,801.84 428,801.84 428,801.84

Treatment facility 1,183,493.09 1,183,493.09 1,183,493.09 1,183,493.09 1,183,493.09

TOTAL 22,837,682.14 22,212,214.74 21,638,869.76 21,065,524.81 20,544,302.31

Expensed at

project end

Abandonment 6,303,387.00 6,303,387.00 6,303,387.00 6,303,387.00 6,303,387.00

Table 7: Total capital expense for the infill drilling project

11. Reperforation and Fracturing – Project

Components 11.1: Perforating The objective in reperforating is to increase the productivity of current wells, without incurring

major expenses. Well 00/14-11-065-08W6 will be reperforated four times within the Cadomin

region. If this perforation is successful in creating additional profit, other intervals may be

considered for analysis in the future, potentially within the Nikanassin region.

11.2: Fracturing Of the 12 wells analyzed within the region, only one producing well, 00/14-11-065-08W6, has

not hit the boundary condition. It is only economically feasible to fracture from this well,

especially under the current recession conditions. This well currently produces from the

Cadomin. In order to avoid excessive workover and redrilling costs into the Nikanassin, all

reperforation and fracturing jobs will be located within the Cadomin. Drilling jobs for this well

into the Nikanassin formation may be considered once economic conditions improve. Even at

that point, however, it is likely more feasible to drill and entirely new well that accesses the

Nikanassin in a nearby location.

This job will follow the same methodology as that used in the infill drilling process. Therefore,

the 30-50 proppant and fracturing water will be identical to those determined previously. Once

again, four fracture stages are performed on this well. Each fracture stage is within

81

A set of four fracture stages will be considered for this well. These, however, will not be

performed simultaneously. Rather, one fracture stage will be performed per year. For each stage,

45 tonnes of proppant will be required. The amount of water used in each stage varies. Listed in

order from the first to last stage, 67,000gal, 50,000gal, 40,000gal, and 34,000gal will be needed

for the fracturing job. All producing wells are currently equipped with pumping devices for the

proppant and fracturing fluid. These pumps may, however, need to be upgraded in order to

handle additional fluid volumes. If more fracturing stages are considered in the future, extra

pumps should be added to the wellsite location.

11.3: Capital Expenses

11.3.1: Reperforation

Previous wells within the Cadomin region show an average perforation interval of four meters.

The new perforations will follow this sizing guideline. A 3m perforation setup will cost $3000.

The additional meter of shots will cost an extra $500 (Sproule Associations, 1999). Therefore,

the total perforation cost amounts to:

$3,500 (1999 CAD dollars) for one perforation set

$5002.68 (2015 CAD dollars) for one perforation set

11.3.2: Fracturing

In order to fracture the perforated interval of the Cadomin, 180 tonnes of 30-50 ceramic proppant

will be required. One tonne of this proppant will cost $800.00 (Smalley, 2014). Therefore, the

cost of proppants per stage for the refracturing job amounts to:

$36,000 (2014 USA dollar)

The current exchange rate between CAD and USA dollars is (Bank of Canada, 2015):

$1.00 CAD = $0.7485 USA

Therefore, the proppant cost becomes:

$48,096.19 (2014 CAD dollar) per stage

$46,642.53 (2015 CAD dollar) per stage

Within Alberta, ground water is free of charge to oil and gas companies (Renzetti, 2009). In

order to save on transportation costs, water from a nearby ground well or recycled water from a

previous fracture job will be used

The pumps within the region must also be upgraded to handle additional fluid volumes. An

estimated expense of $10,000 (2015 CAD dollars) per fracture stage will be allowed for this

process. Therefore, the total pumping cost within this region is:

$20,000 (2015 CAD dollar) per fracture stage

82

11.3.3: Facilities

Since the reperforation and fracturing jobs are performed at pre-existing well locations, no new

facilities need to be installed. Since the production rates of wells have increased, however, the

current batteries, pumps and compressors may need to be upgraded. A total of $30,000 per

fracture stage will be allowed for facilities additions and general maintenance:

$30, 000 (2015 CAD dollars) for one well

Contingences:

An amount equivalent to 20% of the fixed capital income is set aside for contingences. This

money is only used if unexpected problems arise in the perforation or fracturing process.

11.4: Total Capital Expenses The total capital expenses associated with this project are given below. Note that these upgrades

are only performed once within the lifetime of the well. Since three wells are reperforated and

fractured, the total capital expense is three times that for a single well:

Capital Expense Cost per year ($ 2015 CAD)

Perforation 5002.68

Proppant 46,642.53

Pump upgrade 10,000.00

General Facilities upgrade 30,000.00

Sum: 91,645.21

Contingences 18,329.04

Total: 109,974.25

Table 9: Total capital expenses for the reperforation and fracturing project, per stage performed.

83

12. Economic Analysis The proposed optimization methods must all be checked on an economic basis. That is, the

overall profit of the method will be determined. This economic analysis factors in the costs of

each different method. Ultimately, the selected option will be the one that gives the best

economic performance.

In specific, the economic indicator used to analyze the different optimization methods will be the

Net Present Value (NPV). This method takes the time value of money, and annual variations in

revenue and cost. The NPV is defined as:

𝑁𝑃𝑉 = ∑(𝑁𝐶𝐹)

(1 + 𝑖)𝑗

𝑛

𝑖=1

The NPV will be calculated on a 15 year basis. That is, from the year 2015 until 2030. Profits

and expenses are discounted using the current Capitalization Rate. This rate provides an accurate

ratio of the Net income of a project to its property value. No reliable data on the current

capitalization rates for 2015 could be found for this project. Therefore, a value of 12% will be

assumed. This will give a minimum bound for the project worth. The minimum bound will show

the lowest profits that can be achieved by the project. This is important to analyze, since it

confirms whether the project is safe to consider under the worst possible conditions. If the NPV

is positive under the minimum bound, then it is clear that the project will make profit under all

cases, and is safe to consider. For a preliminary economic estimation, this information is

sufficient.

For this report, we assumed for simplicity that the royalty rate and tax rate in Alberta are both

20%. Gas price forecast is obtained from Deloitte consulting company. A table summarizing gas

price forecast along with the economic evaluation tables can be found in Appendix M.

12.1: Base Case Analysis Base case analysis evaluates the township with the current operation and production conditions.

It is assumed that no changes occur on the conditions for the coming 15 years. Production rates

were forecasted using decline analysis and gas prices were resourced from a Deloitte resource

evaluation report. A detailed economic evaluation can be found in Appendix M

12.2: Infill Drilling Economic Analysis

12.2.1: Capital Cost

As discussed previously, 3 horizontal wells will be drilled each year for a maximum of 5 years

starting 2016. The capital cost for this development plan was calculated previously based on an

evaluation by Sproule Association. Table 10 shows a summary of the capital cost considered for

this analysis per year.

84

12.2.2: Fixed Operating Cost

In this project, fixed operating cost is independent of the production rate and assumed to be the

cost of supervision and overhead. Based on the Sproule’s evaluation, fixed operating cost per

was estimated to be $3,600/well.

12.2.3: Variable Operating Cost

Variable operating cost are normally depended on the production rate under normal conditions.

Due to the limited resources available, it was estimated that the variable operating cost is

$35.97/E3m3. However, when a new well is drilled, a percentage of the capital investment

should be considered when calculating the variable operating cost. Based on Sproule’s

evaluation, operating cost for field gas pipeline is 3% of the capital investment, Gas processing

plant is 10% of the capital investment, and Gas compressors is 8% of the capital investment.

Year 1 Year 2 Year 3 Year 4 Year 5

Capital

Cost

$22,837,682.14 $22,212,214.74 $21,638,869.76 $21,065,524.81 $20,544,302.31

Fixed

Operating

Cost

$10,800.00 $10,800.00 $10,800.00 $10,800.00 $10,800.00

Variable

Operating

Cost

$4,795,913.25 $4,664,565.09 $4,544,162.65 $4,423,760.21 $4,314,303.48

Table 10: Capital Cost and Operating Cost per 3 wells for the Infill Drilling Analysis

12.3: Re-Perforation and Fracturing Economic Analysis

12.3.1: Capital Cost

The capital cost for this development plan was calculated previously using Sproule’s evaluation.

Only one well will be re-perforated then fractured every three years starting from 2016. Table

summarize the capital expensed of this plan.

12.3.2: Fixed Operating Cost

Same assumption was made for this plan that the fixed operating cost is assumed to be the cost of

supervision and overhead which is estimated to be $3,600/well.

12.3.3: Variable Operating Cost

Variable operating cost are normally depended on the production rate under normal conditions.

Due to the limited resources available, it was estimated that the variable operating cost is

$35.97/E3m3.

85

Capital Cost $109,974.25

Fixed Operating Cost $3,600/year

Variable Operating Cost $35.97/E3m3

Table 11: capital and operating costs for the reperforation and fracturing project, per stage

performed for a single well.

12.4: Drilling, Re-Perforation and Fracturing Economic Analysis In this plan, 3 horizontal wells will be drilled per year along with re-perforating and fracturing

well 00/14-11-065-08W6. The capital and operating cost for the previous two development plans

were added and used for the evaluation. Appendix M shows a detailed economic analysis for this

plan.

12.5: Economic conclusions Based on the economic analysis done for each optimization method, it was found that a four

stage reperforation and fracture job produced $1011087.60 in income. This method showed the

highest profits, beating the base case value of $733018.52 by around $275,000. This method will

continue to be effective until certain restrictions are met. To test this, the gas price, production

rate and capital expense were separately varied until the Net Present Worth of the fracture

project equaled that of the base case. A table of the results is given below:

Economic Variable Allowable tolerance

Capital Expense 2.0980 Gas Price 0.8659 Production Rates 0.8044

Table 12: Allowable tolerance on each economic variable before the Base Case becomes the

more effective method

Therefore, the reperforation and fracturing method will be profitable unless the capital expenses

raise to 209.80% of the current value, gas prices reduce to 86.59% or production rates lower to

80.44% of the current value. At this point, the base case will be the most economic method.

13. Sensitivity Analysis 13.1: Infill drilling sensitivity Sensitivity analysis was performed on the economic factors for the infill drilling method. This

test is meant to see which parameters had the largest effect on the net present worth of the

project. With this information, the method can be altered to better fit the current economic

climate. The following parameters were tested:

-Capital expenses, from drilling and facilities

86

-Variable field expenses, such as pipelines, processing plants and compressors

-Gas Price, which changes yearly.

-Yearly Production, a factor that varies between the four type wells

-Variable operating costs, based on the yearly gas production

-Royalties, which are governmentally controlled but may change over time

-Taxes, also controlled by the government, but subject to variance over time

-Fixed operating cost, which includes supervision and overhead costs

Each of these parameters is subject to a 20% change in both the positive and negative direction.

This shows the changes over a reasonable variance of economic parameters. The effects of these

increases and decreases on the Net Present Worth are documented for each of the five cases of

the infill drilling method:

-Drill three wells over 1 year

-Drill six wells over 2 years

-Drill nine wells over 3 years

-Drill twelve wells over 4 years

-Drill fifteen wells over 5 years

The sensitivity results for the single year drilling method can be found below. The data

associated with the other four sensitivity methods can be found in Appendix N

Year 1

NPV High, +20% ($) NPV Low, -20% ($)

Standard NPV ($)

Fixed Opex -23353045.46 -23266520.3 -23309782.88

Taxes -23377936.39 -23241629.38 -23309782.88

Royalties -23429724.3 -23189841.47 -23309782.88

Variable Opex -23473671.93 -23145893.84 -23309782.88

Production -22993906.28 -23625659.49 -23309782.88

Gas Price -22911093.8 -23708471.97 -23309782.88

Var field expenses -24166195.96 -22453369.8 -23309782.88

Capex -27387940.41 -19231625.36 -23309782.88 Table 12: Sensitivity analysis on the parameters for a single year infill drilling project.

These results can be shown in a tornado chart. This type of analysis will help diagnose the extent

at which each parameter effects the Net Present Worth of the infill drilling method.

87

Figure 59: Tornado Chart for the one year infill drilling project. From this figure, it is clear that

the Capital and Variable field expenses have the largest effect on the Net Present Worth for the

project.

Interestingly, the Capital and Variable field expenses have a larger effect on the Net Present

Worth of the infill drilling project then the gas prices or production rates. This is likely due to the

fact that this project studies only 7 producing wells in the township. If more of the nearby gas

wells were analyzed, then a change in the gas price or production rate would have a larger

overall effect on the Net Present Worth.

Note that all infill drilling options have a similar tornado chart. The effects of each parameter,

therefore, are not greatly affected by the number of wells drilled. Based on the negative profits

shown from this method, however, it is clear that more infill wells are being drilled per year then

the economic factors can handle. To check this assumption, a spider diagram of the parameters

showing major sensitivity variation in the first infill drilling scheme has been created. This can

be found in Appendix N. The chart has been extrapolated to show the percent decrease in capital

cost required to make the project break even. Results to this analysis are shown below:

88

Figure 60: Spider chart extrapolation showing the capital expense required for the project to

break even.

As seen above, a 110% decrease in the capital expense is required to bring the Net Present Worth

to zero. This is equivalent to drilling no wells whatsoever. Therefore, it is not advisable under the

current conditions to introduce any new infill wells for the region. Once prices stabilize, this

optimization method may be taken into further consideration. Note that no attempt was made to

correlate the gas price to the breakeven point of this project. Because the line a so shallow, an

extrapolation would not produce any useful results. The sensitivity requirement for the prices in

order to break even would be unreasonable.

13.2: Abandonment Considerations In the preceding economic analysis, the abandonment costs at the end of the well lifetime were

not considered. This costs, however, are significant, and must be factored into the budget.

Fortunately, abandonment does not occur until the end of the project lifetime. Therefore, the

manager of the project will not have to raise to produce the full abandonment costs at the time of

drill spudding. Inflation will increase the worth of the abandonment investment, so that it is

worth the proper amount by the project end.

The date of abandonment is unknown. The abandonment pressure for this project is known to be

100psi/1000ft of subsurface. However, because the wells within this region lack pressure data,

89

these values become difficult to accurately determine. For the purpose of a preliminary economic

estimate, the abandonment costs will be assumed to occur at the end of the 15 year project

timeframe. Based on this assumption, the total Net Present Worth of each different infill drilling

method, with abandonment considered, can be found. These are given in the table below:

Column1 NPV With Abandonment ($)

NPV Normal ($)

Year 1 -26,764,598.60 -23,309,782.88

Year 2 -50,754,054.16 -438,44,422.73

Year 3 -72,200,781.52 -61,836,334.37

Year 4 -90,904,670.45 -770,85,407.59

Year 5 -107,854,058.6 -90,579,980.00

Table 13: Net Present Worth of each infill drilling project with Abandonment considered

Since production rates from the infill drilled wells are still reasonably high by the end of the

project, abandonment may not actually be considered within the timeframe of this project.

Therefore, this factor is not considered as a part of the main economic analysis. Rather, it is

simply a sensitivity consideration. The change in Net Present Worth based on abandonment at

the earliest potential date will reveal the worst case basis of profits (or in this case, loses) for

each infill drilling method.

14. Conclusion The Cadomin and Nikanassin were identified to be members of a Continuous Accumulation,

located within the lower pressured region of the Western Canada Sedimentary Basins deep basin.

The 12 selected wells within the township, 065-08W6, provided great insight into reservoir

characterization. From analysis, it was determined that these reservoirs present large volumes of

gas in place, exceeding 9.0x108 m3. However, due to the low porosities of permeabilities, in the

range of 4.94%, 4.86%, 1.3mD and 0.5mD for the Cadomin and Nikanassin respectively, the

reservoir possesses a low recovery factor. Therefore, the region needs to be properly analyzed

and optimized in order to access the gas in place.

From an economic perspective, the producing wells were categorized into four different types.

This allowed for an estimation on the future production of old and new wells. Based on this

information, two optimization methods were developed; infill drilling and reperforating and

fracturing current wells. If both methods were productive, a combination of the two ideas would

be selected. Based on the Net Present Worth of all optimization methods, it was determined that

reperforation and fracturing would produce the highest profits. This method continues to be

90

effective unless gas prices drop below 90%, or production rates decline to 85% of the current

value.

Tight gas reservoirs are the gateway to the future in hydrocarbon production. As demand

increases and conventional reservoirs become depleted, energy firms will turn to these

formations for their massive potential. Therefore the importance of understanding and optimizing

unconventional reservoirs cannot be understated. These accumulations have near unlimited

potential. As oil and gas engineers, it is our job to discover new technology and optimization

methods so that we can successfully obtain it.

91

Bibliography Aadnøy, B.S, (2011). Modern Well Design, Second edition. Boca Raton, FL. CRC Press

Abdulsadek, K. (2015) ENPE 509 Fall 2015 course notes – Drillstem testing and Analysis.

Calgary, AB: University of Calgary.

Aguilera, R., Aguilera, M.S. (2002). The Integration of Capillary Pressures and Pickett Plots for

Determination of Flow Units and Reservoir Containers. Calgary, AB: Society of Petroleum

Engineers.

Aguilera, R. (1990). Extensions of Pickett Plots for the Analysis of Shaly Formations by Well

Logs. Calgary, AB: Servipetrol Ltd.

Aguilera, R. (2014). Flow Units: From Conventional to Tight-Gas to Shale-Gas to Tight-Oil to

Shale-Oil Reservoirs. Calgary, AB: SPE Reservoir Evaluation & Engineering

Aguilera, R. (1994, Vol 33, No. 9). Formation Evaluation of Coalbed Methane Formations.

Servipetrol Ltd.

Aguilera, R. (2002). Incorporating capillary pressure, pore throat aperture radii, height above

free-water table, and Winland r35 values on Pickett plots. AAPG Bulletin, 86(4), 605-624.

Aguilera, R., Harding, T. (2007). State-of-the-Art of Tight Gas Sands Characterization and

Production Technology. Calgary, AB: Petroleum Society of Canada.

Aguilera, R. Gonzalez, L., Nasreldin, G., Rivero, J., Welsh, P. (2014). 3D Modelling of

Multistage Hydraulic Fractures and Two-Way-Coupling Geomechanic/Fluid Flow Simulation of

a Horizontal Well in the Nikanassin Tight Gas Formation, Western Canada Sedimentary Basin.

Calgary, AB: SPE Reservoir Evaluation and Engineering

Aguilera, R., Leguizamon, J. (2011). Hydraulic Fracturing of Naturally Fractured Tight Gas

Reservoirs. Calgary, AB: Society of Petroleum Engineers.

Alberta Geological Survey. (2012). Geological Atlas of the Western Canada Sedimentary Basin.

Calgary, AB: Alberta Energy Regulator

Baker, R.O., Yarranton, H.W., Jenson, J.L. (2015). Practical Reservoir Engineering and

Characterization. Waltham, MA: Elsevier.

Barrett, B., Bouse, E., Carr, B., Dewolfe, B., Growcock, F., Harvey, T., Haston, J., Kargl, M.,

Lee, T.H., Line, B., Mehta, H., Merrill,J., Morgan, M.C., Morgenthaler, M., Peard, N.S., Piper,

W., Rehm, B., Richards, M., Robinson, L., Steen, W., Stefanov, M. (2005). Drilling Fluids

Processing Handbook. Houston, TX: Gulf Professional Publishing, Elsevier.

Bank of Canada (2015). Daily Currency Convertor. Retrieved from

http://www.bankofcanada.ca/rates/exchange/daily-converter/

Beard, T. (2011). EPA Hydrolic Fracturing Workshop: Fracture design in Horizontal Shale

Wells – Data gathering and Implementation. Oklahoma City, OK: Chesapeake Energy

92

Beres, G. (2015), Q3 2015 Cap Rates and Investment Insights: Calgary, AB. Toronto, ON:

CBRE group

Bhattacharya, J., Walker, R.G. (1991). Allostratigraphic subdivision of the Upper Cretaceous

Dunvegan, Shaftesbury, and Kaskapau Formations in the subsurface of northwestern Alberta.

Calgary, AB: Bulletin of Canadian Petroleum Geology.

Byrom, T.G. (2015). Casing and Liners for Drilling and Completion: Design and Application.

Kidlington, MA: Gulf Professional Publishing, Elsevier.

Center for Hydraulic Fracturing of Rock. (2012). Mechanics of Hydraulic Fractures.

Minneapolis, MN: University of Minnesota.

Contreras, O., Hareland, G., Aguilera, R. (2011). An Innovative Approach for Pore Pressure

Prediction and Drilling Optimization in Abnormally Subpressured Basins. Calgary, AB:

Canadian Society for Unconventional Gas.

Craft, E.C., Hawkins, M. (1991). Applied Petroleum Reservoir Engineering. Englewood Cliffs,

NJ: Prentice Hall inc.

Crain, E.R. (1986). The Log analysis Handbook. Tulsa OK: Pennwell Corporation

Elkewidy, T. I. and Elkewidy, H. T. (2013). Characterization of Naturally Fractured Hydraulic

Units with Shaly Content. Cartagena, Colombia: AAPG Search and Discovery Article

Freddy, J., Vargas, R., Aguilera, R. (2012). Updip Water Blockage in the Nikanassin Basin

Centered Gas Accumulation, Western Canada Sedimentary Basin. Calgary, AB: Society of

Petroleum Engineers.

Jensen, J. L. Use of the Geometric Average for Effective Permeability Estimation. In

Mathematical Geology, Vol. 23, No. 6. Houston, TX, International Society for Mathematical

Geology

Gorman, C. (2011). Exploring the Hydraulic Fracturing Process. Houston, TX. Cadotog Oil and

Gas.

Holditch, S.A., Tschirhart, N.R. (2005). Optimal Stimulation Treatments in Tight Gas Sands. .

College Station, TX: Society of Petroleum Engineers

Holditch, S.A., Wei, Y.N. (2009). Computing Estimated Values of Optimal Fracture Half Length

in the Tight Gas Sand Advisor Program. College Station, TX: Society of Petroleum Engineers

Joshi, S.D. (1991). Horizontal Well Technology. Tulsa, OK: Pennwell Publishing Company

Kleinberg, R. (2014). Technology on the Horizon and Over the Horizon. Houston, TX.

Schlumberger.

Lavarnge, M. (1989). Seismic Methods. Paris, France: Ѐditions Technip, Institut Français du

pétrole publications.

93

Lee, J., Rollins, J.B., Spiivey, J.P. (2003). Pressure Transient Testing. Calgary, AB: Society of

Petroleum Engineers

Lloyd, M. (2014) ENPE 507 Course Notes Winter 2014 – Drilling analysis section. Calgary AB,

University of Calgary

Mattar, L., & McNeil, R. (1998). The" flowing" gas material balance. Journal of Canadian

Petroleum Technology, 37(02).

McLean, J.R. (2004). The Cadomin Formation; stratigraphy, sedimentology, and tectonic

implications. Alexandria, VA: American Geological Institute.

Mellon, G.B. (1967). Stratigraphy and Petrology of the Lower Cretaceous Blairmore and

Mannville Groups, Alberta Foothills and Plains. Edmonton, AB: Research Council of Alberta.

Miles, B.D., Hubbard, S.M., Raines, K.M., Kukulski, R.B., Fisher, R.M., Zonneveld, J.P. (2009).

A Stratigraphic Framework for the Jurassic–Cretaceous Nikanassin Group, Northwestern

Alberta, Canada. Calgary, AB: AAPG Search and Discovery.

Morrison Hershfield Ltd. (2008). Guidelines on Valuations of tangible capital assets for PSAB

3150. Edmonton, AB. Alberta Municipal Affairs.

Moslow, T.F., Zaitlin, B.A. (2006). A review and Deep Basin Gas Reservoirs in the Western

Canada Sedimentary Basin. Calgary, AB: Suncor Energy.

Naik, G.C. (unknown publication date). Tight Gas Reservoirs – An Unconventional Natural

Energy Source for the Future. Pinedale Online publication. Retrieved from

http://www.pinedaleonline.com/socioeconomic/pdfs/tight_gas.pdf.

Olson, J.E., Laubach, S.E., Lander, R.H. (2009). Natural fracture characterization in tight gas

sandstones: Integrating mechanics and diagenesis. Austin, TX: The American Association of

Petroleum Geologists.

Renzetti, S. (2009). Economic and/or Market-Based Instruments to Allocate Water and Promote

Conservation: Water Pricing. Edmonton, AB: Alberta Water Council

Sageev, A., Ramey Jr. S.A and Prat Da G. (1985). Decline Curve Analysis for Double-Porosity

Systems. INTEVEP S.A and Stanford University.

Schenk, C.J. (2001). Geologic Definition of Conventional and Continuous Accumulations in

Select U.S. Basins – The 2001 Approach. Denver, CO: U.S. Geological Survey.

Solano, N., Zambrano, L., Aguilera, R. (2011). Cumulative-Gas-Production distribution on the

Nikanassin Tight gas Formation, Alberta and British Columbia, Canada. Calgary, AB: Society of

Petroleum Engineers.

Smalley, T. (2014). Ceramic Proppant Price Per Ton. Retrieved from

http://www.buyproppant.com/ceramic-proppant-price-per-ton/

94

Sproule Associations Ltd. (1999). Evaluation of Canadian Oil and Gas properties: Section 4 –

Capital and Operating Cost estimates. Calgary, AB: Sproule association – Worldwide Petroleum

Consultants.

Vigrass, L. (2006). Western Canada Sedimentary Basin. Regina, SK: Canadian Plains Research

Center, University of Regina. Retrieved from

http://esask.uregina.ca/entry/western_canada_sedimentary_basin.html

Weng, X. Yew, C.H. (2015). Mecahnics of Hydraulic Fracturing. Waltham, MA: Gulf

Professional Publishing, Elsevier

Wright, C. (2010). Deep Basin Gas Study. Calgary, AB: Canadian Search and Discovery

USGS Uinta-Piceance Assessment Team. (2002). Executive Summary—Assessment of

Undiscovered Oil and Gas Resources of the Uinta-Piceance Province of Utah and Colorado,

2002. Denver, CO: U.S. Geological Survey.

Zambrano Liliana, Pedersen Per K. and Rorbeto Aguilera. (November 2013, 6-7). Geologic

Controls of Gas Production from Tight-Gas Sandstones of the Late Jurassic Monteith Formation,

Deep Basin, Alberta, Canada. Schulich School of Engineering, University of Calgary

95

Appendix A: Nomenclature

Table 14: List and definition of symbols used in this report

Symbol Description Units ∅ Porosity

∅𝐍 Neutron Porosity

∅𝐃 Density Porosity

∅𝐞 Effective Porosity

∅𝐞′ Effective Shale Corrected Porosity

∅𝐞′𝐚𝐯𝐠

Average Shale Corrected Porosity

𝐑𝐰 Water Resistivity Ohm*m

𝐑𝐰 𝐦𝐜 Water Resistivty at 25oC Ohm*m

𝐑𝐭 Total Resistivity Ohm*m

𝐑𝐬𝐡 Shale Resistivity Ohm*m

𝐀𝐥𝐚𝐦 Laminated Shale Coefficient

𝐓𝐦𝐜 Measured conditions temperature (25oC) oC

𝐓𝐅 Average Formation Temperature oC

m Cementation Exponent

a Archie rock property constant

𝐕𝐬𝐡𝐢 Uncorrected Shale Volume fraction

𝐕𝐬𝐡 Corrected Shale Volume fraction

𝐆𝐑𝐥𝐨𝐠 Formation Gamma Ray Reading API

𝐆𝐑𝐜𝐥𝐞𝐚𝐧 Clean Sand Gamma Ray Reading API

𝐆𝐑𝐬𝐡 Shale Gamma Ray Reading API

𝐕𝐬𝐡 Shale Volume

𝐓 Absolute Temperature K

𝐒𝐰 Water Saturation

𝐒𝐰 𝐚𝐯𝐠 Average Water Saturation

𝐒𝐠 Gas Saturation

𝐎𝐆𝐈𝐏 Original Gas in Place

𝐡 Interval Thickness m

𝐡𝐧𝐞𝐭 Net Pay Thickness m

𝐍/𝐆 Net to Gross Pay Ratio

𝐁𝐠 Formation Gas Volume Factor Sm3/m3

k Permeability mD

𝐤𝐦𝐚𝐱 Maximum Horizontal Permeability mD

𝐤𝟗𝟎 90o Horizontal Permeability mD

𝐤𝐯𝐞𝐫𝐭 Vertical Permeability mD

rp35 Pore throat aperture at 35% Mercury Saturation nm

𝛍 Gas Viscosity Pa.s

𝛒 Gas Density kg/m3

z Gas Compressibility Factor

q Gas production flowrate STB/D

Q Cumulative Gas production STB

P Pressure Psi

Pc Capillary Pressure Psi

NPV Net Present Value $

NCF Net Cash Flow $/year

i Discount/capitalization rate Fraction/annum

96

Appendix B: Maps and Diagrams

Figure 61: Map

showing the

location of the

designated

township. Note

that the

Continuous

Accumulation is

divided into 6

areas, parallel to

the trust belt of

the Rocky

Mountains

(Aguilera et. al,

2011)

97

Figure 62:

Regional

Boundaries of

the Deep Basin,

located within

the Western

Canada

Sedimentary

Basin. The

location of

township 065-

08W6 is shown

to be within the

Lower Pressured

Deep Basin

98

Figure 63: Map of township 65-08W6. The wells selected for analysis are marked in red.

99

Appendix C: Well Information

Figure 64: Well cards for the 12 selected wells in the township.

100

Well Formation Start of

Production

Initail

Production

Production

as of Jul

2015

Cumulative

Gas

Production

(x107m3)

Cumulative

Water

Production

(m3)

00/07-21-065-08W6/0 Cadomin Feb-03 181.7 91.8 2.5 860.5

00/08-22-065-08W6/0 Cadomin Nov-99 439 108.7 3.8 721.8

00/09-34-065-08W6/0 Nikanassin Nov-05 129.7 95.7 2.1 293

00/12-32-065-08W6/0 Cadomin Apr-03 1989.3 246.8 6.0 5014.4

00/13-30-065-08W6/0 Cadomin Nov-03 727.5 313.9 7.5 8053.3

00/14-11-065-08W6/0 Cadomin Dec-05 32.7 73.8 0.99 228.4

00/15-13-065-08W6/0 Cadomin Jan-01 252.3 113.6 4.4 864.4

Table 15: Production history within the township of interest

Well Pressure at Run

Depth (kPa)

Reservoir

Temp.

(°C)

Calculated

Skin

Flow

capacity

(mD-m)

Pressure

Gradient

(kPa/m)

00/13-30-065-08W6/0 22159 97 -3.4 3.7 2

00/01-28-065-08W6/0 23081 100.9 N/A N/A 1.28

00/01-28-065-08W6/2 18701 96.9 N/A N/A 9.37

Table 16: Drillstem test results from available wells.

101

Figure 65: Wellbore Schematic

00/14-11-065-08W6. This is

the only well of the 12 being

analyzed that has not hit the reservoir boundary

102

Appendix D: Well Logs

Figure 66: Sample log from well

00/09-34-065-08W6. This well does not

Penetrate the entire Nikanassin formation.

Table 17: Sample chart containing log

readings and calculations for the

Cadomin section of well 00/09-34-

065-08W6. Red denotes an

unproductive layers.

103

Figure 67: Well

Log for Well 00-

07-21-65-08W6

obtained from

Accumap.

104


logs for the Cadomin Formation. This figure shows the logs made for well 00-07-21-65-08W6

105


logs for the Nikanassin Formation. This figure shows the logs made for well 00-07-21-65-08W6.

106

.

Figure 70: Well

Log for Well

00-13-30-65-

08W6 obtained

from Accumap.

107

Figure 71: Porosity, Water Saturation and Permeability Logs that were built by analyzing the logs for the

Cadomin Formation. This figure shows the logs made for well 00-13-30-65-08W6.

108


NIikanassin Formation. This figure shows the logs made for well 00-13-30-65-08W6.

109

Figure 73: Well

Log for Well 00-

08-22-65-08W6

obtained from

Accumap.

110



111


Nikanassin Formation. This figure shows the logs made for well 00-08-22-65-08W6.

112

Figure 76: Well

Log for Well 00-

07-12-65-08W6

obtained from

Accumap.

113



114


Nikanassin Formation. This figure shows the logs made for well 00-07-12-65-08W6.

115

Figure 79: Well

Log for Well 00-

07-26-65-08W6

obtained from

Accumap.

116



117


Nikanassiin Formation. This figure shows the logs made for well 00-07-26-65-08W6.

118

Figure 82: Well

Log for Well 00-

12-32-65-08W6

obtained from

Accumap.

119


Cadomin Formation. This figure shows the logs made for well 00-12-32-65-08W6

120


Nikanassin Formation. This figure shows the logs made for well 00-12-32-65-08W6

121

Figure 85: Well

Log for Well 00-

03-07-65-08W6

obtained from

Accumap.

122



123



124

Figure 88: Well

Log for Well 00-

11-09-65-08W6

obtained from

Accumap.

125



126



127

Figure 91: Well

Log for Well 00-

14-11-65-08W6

obtained from

Accumap.

128



129

Figure 93: Porosity, Water Saturation and Permeability Logs that were Built by analyzing the logs for the


130

Figure 94: Well

Log for Well 00-

09-34-65-08W6

obtained from

Accumap.

131



132



133

Figure 97: Well

Log for Well 00-

05-06-65-08W6

obtained from

Accumap.

134



135



136

Figure 100: Well

Log for Well 00-

15-13-65-08W6

obtained from

Accumap.

137



138



139

Appendix E: Cross Plots

Figure 103: Modified

Pickett Plot for well

00/07-21-065-08W6.

Note that this well

follows the first

distinctive trend, with

m=2.2422, and

a=0.5141

Figure 104: Modified Pickett Plot for well 00/11-09-065-08W6. Note that this well follows the second

distinctive trend, with m=1.9685, and a=0.5423

140





141

Figure 107:

Modified Pickett

Plot for well

00/07-12-065-

08W6. Note that

this well follows

the first distinctive

trend, with

m=2.2478, and

a=0.5141

Figure 108:Modified Pickett Plot for well 00/07-26-065-08W6. Note that this well follows the first


142





143





144





145

Appendix F: Log Interpretation

Cadomin Nikanassin

Porosity (%) Water Saturation

(%)

Porosity

(%)

Water Saturation

(%)

00-05-06-065-08W6 4.0 55.6 4.2 37.1

00-15-13-065-08W6 6.9 26.2 3.1 48.2

00-09-34-065-08W6 5.0 56.7 3.9 55.1

00-14-11-065-08W6 4.1 46.6 3.8 50.3

00-11-09-065-08W6 3.8 54.6 2.6 49.7

00-03-07-065-08W6 6.9 31.7 4.5 36.1

00-12-32-065-08W6 5.8 36.6 8.7 31.3

00-07-26-065-08W6 4.4 57.3 5.0 64.4

00-07-12-065-08W6 4.3 56.6 6.4 49.9

00-08-22-065-08W6 4.5 58.7 6.7 30.8

00-13-30-065-08W6 5.0 62.6 4.9 46.4

00-07-21-065-08W6 4.7 38.4 4.6 34.2

Average: 4.94 48.47 4.86 44.45 Table 18: Average Porosity and Water Saturation within each well, for each formation.

Cadomin

Well ID Gross Pay (m) Net Pay (m) N/G Ratio SgФhnet

00-05-06-065-08W6 6 6 1.0 0.31

00-15-13-065-08W6 13 7 0.54 0.13

00-09-34-065-08W6 21 12 0.57 0.26

00-14-11-065-08W6 25 14 0.56 0.31

00-11-09-065-08W6 27 16 0.59 0.27

00-03-07-065-08W6 12 11 0.92 0.51

00-12-32-065-08W6 69 48 0.70 0.62

00-07-26-065-08W6 19 8 0.42 0.15

00-07-12-065-08W6 6 13 0.46 0.11

00-08-22-065-08W6 8 4 0.50 0.08

00-13-30-065-08W6 9 3 0.33 0.05

00-07-21-065-08W6 21 19 0.91 0.55

Table 19: Gross Pay, net Pay and Net/Gross Ratio within each well, within the Cadomin. All wells

penetrate through the entire Cadomin, and are therefore representative of the formation.

146

Nikanassin

Well ID Penetrated Gross Pay

(m)

Penetrated Net Pay

(m)

N/G Ratio SgФhnet

00-05-06-065-08W6 37 15 0.41 0.24

00-15-13-065-08W6 31 24 0.77 0.60

00-09-34-065-08W6 17 34 0.50 0.30

00-14-11-065-08W6 13 3 0.23 0.06

00-11-09-065-08W6 168 45 0.27 0.43

00-03-07-065-08W6 34 21 0.62 0.60

00-12-32-065-08W6 9 8 0.89 0.48

00-07-26-065-08W6 17 7 0.41 0.13

00-07-12-065-08W6 30 16 0.53 0.52

00-08-22-065-08W6 38 22 0.58 1.02

00-13-30-065-08W6 17 13 0.77 0.34

00-07-21-065-08W6 28 13 0.46 0.40

Table 20: Gross Pay, net Pay and Net/Gross Ratio within each well, within the Nikanassin. Note

that 00/11-09-065-08W6 is the only well to penetrate the Nikanassin fully. For the rest of the

wells, the Gross pay, Net pay and N/G ratio are not representative of the entire formation.

Cadomin Nikanassin

Porosity (%) Water Saturation (%) Porosity

(%)

Water Saturation

(%)

00-12-36-065-08W6 4.7 57.0 4.5 60.0

00-06-36-065-08W6 4.6 57.1 4.5 62.1

00-10-29-065-08W6 5.2 32.2 4.1 57.4

00-06-19-065-08W6 4.3 50.0 4.8 48.3

00-15-18-065-08W6 4.4 47.5 3.5 42.9

00-10-08-065-08W6 5.5 41.5 3.6 41.9

00-03-08-065-08W6 5.3 43.2 3.5 42.9

00-16-05-065-08W6 4.5 55.4 3.3 40.3

Table 21: Important reservoir properties for the geostatistically interpolated wells.

147

Cadomin Nikanassin

Gross Pay

(m)

Net

Pay

(m)

N/G

Ratio

SgФhnet Gross Pay

(m)

Net Pay

(m)

N/G

Ratio

SgФhnet

00-12-36-065-08W6 12 6 0.50 0.12 166 45 0.27 0.82

00-06-36-065-08W6 18 9 0.50 0.16 158 41 0.26 0.74

00-10-29-065-08W6 23 20 0.87 0.71 146 48 0.33 0.83

00-06-19-065-08W6 28 18 0.64 0.38 170 56 0.33 1.38

00-15-18-065-08W6 21 16 0.76 0.36 175 51 0.29 1.03

00-10-08-065-08W6 26 20 0.77 0.66 181 55 0.30 1.16

00-03-08-065-08W6 35 26 0.74 0.79 174 51 0.29 1.04

00-16-05-065-08W6 24 15 0.63 0.30 176 59 0.34 1.15

Table 22: Pay intervals for the geostatistically interpolated wells.

Cadomin

Nikanassi

n

Arithmatic Harmoni

c

Geometric Arithmati

c

Harmonic Geometri

c

00-12-36-065-08W6 3.67 1.11 2.30 4.58 0.0018 0.18 00-06-36-065-08W6 2.56 0.81 1.43 5.62 0.0034 0.20

00-10-29-065-08W6 3.92 1.17 2.83 10.71 0.020 0.56

00-06-19-065-08W6 103.51 1.95 3.61 27.39 0.024 0.47

00-15-18-065-08W6 1.20 0.87 0.99 28.68 0.015 0.59 00-10-08-065-08W6 15.26 0.15 1.52 2.18 0.033 0.72 00-03-08-065-08W6 6.10 0.21 2.26 3.22 0.023 0.45 00-16-05-065-08W6 5.95 0.43 0.84 3.55 0.017 0.30

Table 23: Permeability averages for the geostatistically interpolated wells.

148

Appendix G: Core Information

Figure 115: Log-Core

correlation for the analyzed

interval of well 00/12-32-065-

08W6.

149


correlation for the analyzed

interval of well 00/11-09-

065-08W6.

150


correlation for the two

analyzed intervals of

well 00/10-29-065-

08W6

151

Figure 118: Relationship between the core and

log porosity data for well 00/07-21-065-

08W6, before the depth correction was

performed.

Figure 119: Relationship between the core

and log porosity data for well 00/07-21-065-

08W6, after the core data was shifted

upwards by a distance of 2.2m.

152

Figure 120: Correlation

between log and core

porosity values at the

same depth interval for

well 00/07-21-065-

08W6. This well

featured.

Figure 121: Relationship between the core and log

porosity data for well 00/07-21-065-08W6, after the

depth correction. Log porosity data has now been

adjusted based on the previously developed

correlation for this well.

153

Figure 122: Correlation between log and core porosity values at the same depth interval for well 00/10-

29-065-08W6. This is the only core within the township that samples the Nikanassin region.

Figure 123: Correlation between log and core porosity values at the same depth interval for well 00/11-

09-065-08W6. This well featured a significantly different relationship between core and log porosity.

This is assumed to be due to misalignment of the data tracks, measurement noise, and the age of the log.

154

Figure 124: Pore throat aperture for well 00/06-02-065-08/W6. Max Horizontal permeability is measured

against porosity. Note that most pore throats in this well are between Mesopores and Megapores.

Figure 125: Pore throat aperture for well 00/06-02-065-08/W6. 90o Horizontal permeability is measured


155


against porosity. Note that most pore throats in this well are between Mesopores and Marcopores.



156


against porosity. Note that most pore throats in this well are between Mesopores and Marcopores.

Figure 129: Pore throat aperture for well 00/05-06-065-08/W6. Vertical permeability is measured against

porosity. Note that most pore throats in this well are between Mesopores and Marcopores.

157





158


porosity. Note that most pore throats in this well are between Mesopores and Megapores.



159




porosity. Note that most pore throats in this well are between Mesopores and Megapores.

160


against porosity. Note that most pore throats in this well are between Micropores and Megapores.


against porosity. Note that most pore throats in this well are between Micropores and Megapores.

161

Blue = Clean Sandstome (Vsh<0.60) Red = Shale Zone (Vsh>0.60)

Table 24: Comparison of Permeability data from the Core Data and the Morris and Biggs equation. Data

obtained from well 00/12-32-065-08W6

Cadomin Nikanassin

Arithmatic Harmonic Geometric Arithmatic Harmonic Geometric

00-05-06-065-08W6 13.19 9.27 10.78 7.66 0.0014 0.17

00-15-13-065-08W6 21.37 4.32 9.01 3.43 0.011 0.14

00-09-34-065-08W6 6.36 2.20 4.43 1.85 0.00041 0.08

00-14-11-065-08W6 5.51 0.012 0.17 14.24 0.0078 0.13

00-11-09-065-08W6 0.22 0.02 0.05 0.11 0.020 0.54

00-03-07-065-08W6 610.15 0.4 4.47 6.32 0.027 0.37

00-12-32-065-08W6 3644.94 0.95 17.54 43.98 1.01 5.67

00-07-26-065-08W6 0.99 0.02 0.16 7.30 0.0033 0.28

00-07-12-065-08W6 5.15 0.017 0.15 12.51 0.15 1.54

00-08-22-065-08W6 1.46 0.07 0.21 137.42 0.53 3.61

00-13-30-065-08W6 11.11 5.67 7.89 71.55 0.041 0.33

00-07-21-065-08W6 2.18 1.71 1.93 71.58 0.0091 0.63

Average 360.22 0.046 1.29 31.50 0.0031 0.46 Table 25: Average maximum horizontal permeability for each well, in each formation.

Depth (m) K max from core data K max from equation

2873 1.778777571 0.914030035

2876 8142.909961 7557.234316

2879 75484.0623 53493.58035

2882 5.885426373 5.871867725

2885 9.315564589 10.26577893

2888 0.853368959 0.767355497

2891 0.61316249 0.016386117

2894 33.74781495 30.39510497

2897 3.650597649 2.406684588

2900 2.717572759 2.120367412

2903 0.313029792 0.000750335

2906 6.139186966 6.192780689

2909 2.497919461 2.323759052

2912 0.138696049 9.40712E-07

2915 0.131680652 4.53893E-07

2918 5.719579623 1.759626107

2921 14415986817 6261858.377

2924 21.81998632 7.692027627

2927 68.65858584 65.95262417

2930 12.03075069 15.89629917

2933 0.553432976 0.012531475

2936 7.658606186 8.233174729

2939 11.73253395 15.51618815

162

Cadomin

Arithmatic Harmonic Geometric

00-05-06-065-08W6 9.69 9.21 9.39 00-15-13-065-08W6

00-09-34-065-08W6 5.27 2.09 3.35 00-14-11-065-08W6

00-11-09-065-08W6

00-03-07-065-08W6 0.79 0.76 0.77 00-12-32-065-08W6 231.97 0.4 9.23 00-07-26-065-08W6

00-07-12-065-08W6

00-08-22-065-08W6

00-13-30-065-08W6 6.72 4.73 5.62 00-07-21-065-08W6

Average 50.88 1.08 4.16 Table 26: Average 90o horizontal permeability for each well, in each formation. Only wells with relevant

core data could be analyzed. Because of this, values are not necessarily representative of the region. All

core data is derived from a Cadomin Region.

Cadomin

Arithmatic Harmonic Geometric

00-05-06-065-08W6 4.45 3.6 1.94 00-15-13-065-08W6

00-09-34-065-08W6 2.74 1.27 2.07 00-14-11-065-08W6

00-11-09-065-08W6

00-03-07-065-08W6 0.45 0.39 0.41 00-12-32-065-08W6 33.93 0.60 3.25 00-07-26-065-08W6

00-07-12-065-08W6

00-08-22-065-08W6

00-13-30-065-08W6 2.56 1.83 2.16 00-07-21-065-08W6

Average 8.83 0.86 1.63 Table 27: Average vertical permeability for each well, in each formation. Only wells with relevant core

data could be analyzed. Because of this, values are not necessarily representative of the region. All core

data is derived from a Cadomin Region.

163

Appendix H: Capillary Pressure

Figure 138: Cadomin Formation – Mercury-air 𝑃𝑐 Vs 𝑆𝑊.

Figure 139: Nikanassin Formation – Mercury-air 𝑃𝑐 Vs 𝑆𝑊.

0

100

200

300

400

500

600

700

800

900

1000

0 10 20 30 40 50 60 70 80 90 100

Mer

cury

-Air

Cap

illar

y P

ress

ure

(P

si)

Water Saturation (%)

00-05-06-065-08W6

00-15-13-065-08W6

00-09-34-065-08W6

00-14-11-065-08W6

00-11-09-065-08W6

00-03-07-065-08W6

00-12-32-065-08W6

00-07-26-065-08W6

00-07-12-065-08W6

00-08-22-065-08W6

00-13-30-065-08W6

00-07-21-065-08W6

0

100

200

300

400

500

600

700

800

0 10 20 30 40 50 60 70 80 90 100

Mer

cury

-Air

Cap

illar

y P

ress

ure

(P

si)


00-05-06-065-08W6

00-15-13-065-08W6

00-09-34-065-08W6

00-14-11-065-08W6

00-11-09-065-08W6

00-03-07-065-08W6

00-12-32-065-08W6

00-07-26-065-08W6

00-07-12-065-08W6

00-08-22-065-08W6

00-13-30-065-08W6

00-07-21-065-08W6

164

Figure 140: Mercury-air 𝑃𝑐 Vs 𝑆𝑊 Using Average Properties.

Table 28: Empirical Values of A and B in Capillary Pressure (Aguilera, 2002).

0

50

100

150

200

250

300

350

400

450

0 10 20 30 40 50 60 70 80 90 100

Mer

cury

-Air

Cap

illar

y P

ress

ure

(P

si)


Cadomin

Nikanassin

165

Appendix I: Reservoir Fluid Properties

Table 29: Well 00-11-09-065-08W6 Gas Analysis.

Law of Corresponding States

The gas formation factor can be calculated as follows:

𝐵𝑔 = 5.037 ∗𝑧𝑇

𝑃

Where the gas compressibility factor is given by,

𝑧 = 𝐴 + (1 − 𝐴) exp(−𝐵) + 𝐶𝑃𝑟𝐷

The coefficients are given by,

𝐴 = 1.39(𝑇𝑟 − 0.92)0.5 − 0.36𝑇𝑟 − 0.101

𝐵 = (0.62 − 0.23𝑇𝑟)𝑃𝑟 + (0.066

𝑇𝑟 − 0.68− 0.037) 𝑃𝑟

2 + 0.32𝑃𝑟

6

109(𝑇𝑟−1)

𝐶 = 0.132 − 0.32log (𝑇𝑟)

𝐷 = 10(0.3106−0.49𝑇𝑟+0.1824𝑇𝑟2)

𝑇𝑟 =𝑇

𝑇𝑐, 𝑎𝑛𝑑 𝑃𝑟 =

𝑃

𝑃𝑐

in which the unit of 𝑇 𝑎𝑛𝑑 𝑇𝑐 is °𝑅 and the unit of 𝑃 𝑎𝑛𝑑 𝑃𝑐 is Psia.

Cadomin Nikanassin

Pc (Psia) 679.30 678.14

Tc (°R) 351.53 372.78

H2 0.0000 0.0000

He 0.0000 0.0000

N2 0.0125 0.0359

CO2 0.0211 0.0245

H2S 0.0000 0.0000

C1 0.9443 0.8192

C2 0.0162 0.0974

C3 0.0036 0.0179

IC4 0.0009 0.0017

NC4 0.0008 0.0013

IC5 0.0003 0.0007

NC5 0.0002 0.0003

C6 0.0001 0.0006

C7 0.0000 0.0005

C5 0.0000 0.0000

166

P (psia) Cadomin Nikanassin Average Cadomin Nikanassin Average

z z z 𝑩𝒈 𝑩𝒈 𝑩𝒈

100 0.9937 0.9933 0.9935 33.568 33.353 33.461

500 0.9708 0.9683 0.9696 6.559 6.503 6.531

1000 0.9441 0.9389 0.9416 3.189 3.153 3.171

1500 0.9220 0.9146 0.9183 2.076 2.047 2.062

2000 0.9067 0.8980 0.9024 1.531 1.508 1.520

2500 0.8997 0.8908 0.8952 1.216 1.196 1.206

3000 0.9015 0.8933 0.8974 1.015 1.000 1.007

3500 0.9119 0.9052 0.9085 0.880 0.868 0.874

4000 0.9300 0.9252 0.9276 0.785 0.777 0.781

4500 0.9547 0.9520 0.9533 0.717 0.710 0.713

5000 0.9847 0.9840 0.9842 0.665 0.661 0.663

5500 1.0187 1.0199 1.0192 0.626 0.623 0.624

6000 1.0557 1.0586 1.0571 0.594 0.592 0.593

6500 1.0949 1.0992 1.0969 0.569 0.568 0.568

7000 1.1355 1.1410 1.1382 0.548 0.547 0.548

7500 1.1772 1.1837 1.1804 0.530 0.530 0.530

8000 1.2195 1.2270 1.2231 0.515 0.515 0.515

Table 30: Calculated gas compressibility factors and gas formation factors for Cadomin and Nikanassin

formations along with the averages.

Lee et al. correlation The gas viscosity is given by

𝜇𝑔 = 10−4𝐾 exp(𝑋𝜌𝑔(2.4−0.2𝑋))

Where,

𝐾 =(9.4 + 0.02𝑀)𝑇1.5

209 + 19𝑀 + 𝑇

𝑋 = 3.5 +986

𝑇+ 0.01𝑀

𝜌𝑔 = 0.0014935𝑃𝑀

𝑧𝑇

in which the unit of 𝑇 is °𝑅 ,the unit of 𝑃 is Psia, and M is the molar mass of the gas.

167

P (psia) Cadomin Nikanassin Average Cadomin Nikanassin Average

𝝆𝒈 𝝆𝒈 𝝆𝒈 𝝁𝒈 𝝁𝒈 𝝁𝒈

100 0.00359 0.00362 0.00361 0.01429 0.01421 0.01425

500 0.01840 0.01856 0.01848 0.01456 0.01448 0.01452

1000 0.03783 0.03827 0.03805 0.01509 0.01503 0.01506

1500 0.05811 0.05894 0.05852 0.01580 0.01575 0.01578

2000 0.07880 0.08004 0.07941 0.01667 0.01665 0.01666

2500 0.09926 0.10086 0.10005 0.01767 0.01768 0.01767

3000 0.11887 0.12068 0.11977 0.01877 0.01880 0.01878

3500 0.13710 0.13896 0.13803 0.01992 0.01997 0.01994

4000 0.15363 0.15537 0.15451 0.02108 0.02113 0.02111

4500 0.16836 0.16988 0.16913 0.02222 0.02226 0.02224

5000 0.18138 0.18261 0.18201 0.02330 0.02333 0.02332

5500 0.19285 0.19380 0.19334 0.02433 0.02434 0.02434

6000 0.20300 0.20369 0.20337 0.02530 0.02529 0.02530

6500 0.21206 0.21252 0.21230 0.02621 0.02619 0.02620

7000 0.22020 0.22047 0.22035 0.02708 0.02703 0.02706

7500 0.22758 0.22769 0.22765 0.02789 0.02783 0.02786

8000 0.23433 0.23432 0.23434 0.02867 0.02859 0.02863

Table 31: Calculated gas density and gas viscosity for Cadomin and Nikanassin formations along with the

averages.

Figure 141: Gas Compressibility Factor and Formation Factor Averages for both Cadomin and

Nikanassin Formations.

y = -2E-24x6 + 1E-19x5 - 2E-15x4 + 9E-12x3 - 1E-08x2 - 6E-05x + 0.999

0.8

0.85

0.9

0.95

1

1.05

1.1

1.15

1.2

1.25

0 2000 4000 6000 8000 10000

Gas

Co

mp

ress

ibili

ty F

acto

r, z

Pressure (Psia)

y = 1913.8x-0.932

0

1

2

3

4

5

6

7

0 2000 4000 6000 8000 10000

Gas

Fo

rmat

ion

Fac

tor

, Bg

(bb

l/M

SCF)

Pressure (Psia)

168

Figure 142: Gas Density and Viscosity Averages for both Cadomin and Nikanassin Formations.

y = -4E-21x5 + 2E-16x4 - 2E-12x3 + 7E-09x2 + 3E-05x + 0.0006

0

0.05

0.1

0.15

0.2

0.25

0 5000 10000

Gas

Den

sity

(g/

cc)

Pressure (psia)

y = -3E-14x3 + 4E-10x2 + 7E-07x + 0.0141

0

0.005

0.01

0.015

0.02

0.025

0.03

0.035

0 5000 10000

Gas

Vis

cosi

ty (

cp)

Pressure (Psia)

169

Appendix J: Maps and Cross Sections

Figure 143: Contour map presenting the tops of the Cadomin formation.

170

Figure 144: Contour map presenting the tops of the Nikanassin formation

171

Figure 145: Contour map presenting the gross thickness of the Cadomin formation.

172

Figure 146: Contour map presenting the gross thickness of the Nikanassin formation.

173

Figure 147:Cadomin SgФhnet contour map. This is used in volumetric calculations for Original Gas in Place.

174

Figure 148: Nikanassin SgФhnet contour map. This is used in volumetric calculations for Original Gas in Place. Some of

the wells that penetrated the Nikanassin were not analyzed as a part of the 16 well set. This is because most are

grouped together in the southwest region. Therefore, quick log analysis was performed on these wells in order to

obtain the SgФhnet values. Those wells without logs were subject to correlations based on nearby well data, in order to

find SgФhnet

175

Figure 149: Map of the township showing the cross sectional cuts made through the formation.

Note that Cross Section C is parallel the thrust belt of the Rocky Mountains.

176

Figure 150: North-south

cross section through the

township

177

Figure 151: East-West

Cross section through

the township

178

Figure 38: Cadomin Formation Bubble Map showing Cumulative Gas Prodution.

Figure 152: Diagonal

Cross Section of the

township. This cut

follows a southwest-

northeast trend, parallel

to the trust belt

179

Figure 153: Cadomin Formation Bubble Map showing Cumulative Gas Production.

Figure 154: Nikanassin Formation Bubble Map showing Cumulative Gas Production.

180

Appendix K: Reserves Estimates

OGIP (E6m3)

Volumetrics 894

Material Balance Plot Average 1,000

Table 32: Results of the 2 methods used to calculate the OGIP.

Well p/z Q (x103m3)

00/07-31-065-08W6/0 24231.4 2.55,540.00

00/14-33-065-08W6/0 20,346.4 14,417.90

00/06-34-065-08W6/0 22,215.2 121,348.70

00/02-35-065-08W6/0 23,237.7 13,929.70

00/15-25-065-08W6/0 17,586.4 11,284.30

00/06-27-065-08W6/0 24,356.1 50,113.60

00/10-19-065-08W6/0 21,896.8 164,530.70

00/08-23-065-08W6/0 23,512.3 31,100.00

00/10-24-065-08W6/0 17460.4 105,861.70

00/04-18-065-08W6/0 21,261.9 12,715.60

00/03-10-065-08W6/0 23,149.4 31,507.60

00/15-13-065-08W6/0 18,442.6 44,112.60

00/12-32-065-08W6/0 23,765.8 60,586.30

00/13-30-065-08W6/0 23,844.0 74,579.90

00/08-22-065-08W6/0 23,268.8 38,479.60

00/14-11-065-08W6/0 18,414.5 9,871.50

00/09-34-065-08W6/0 22,650.4 21,466.80

00/06-19-065-08W6/0 33,116.7 30,595.30

Table 33: P/Z and cumulative production values for the wells that produced from Cadomin and

Nikanassin Formations in our township.

181

Appendix L: Production Forecasting

Well Formation Start of

Production

Initial Gas

Rate(E3m3/month)

Production as

of July 2015

(E3m3/month)

Cumulative

Gas

Production

(E3m3)

00/15-13-065-08W6/0 Cadomin Jan 2001 252.3 113.6 44,112.60

00/09-34-065-08W6/0 Nikanassin Nov 2005 129.7 95.7 21,466.80

00/12-32-065-08W6/0 Cadomin Apr 2003 1,989.30 246.8 60,586.30

00/13-30-065-08W6/0 Cadomin Nov 2003 727.5 313.9 74,579.90

00/07-21-065-08W6/0 Cadomin Feb 2003 181.7 91.8 25,600.00

00/08-22-065-08W6/0 Cadomin Nov 1999 439 108.7 38,479.60

00/14-11-065-08W6/0 Cadomin Nov 2005 32.7 73.8 9,871.50

Table 34: Production history for wells producing from the Cadomin and Nikanassin.

182

Jet Perforation:(3087.5-3092.5)m

Natural fracture:(3097.6-3099.8)m

Well 07-21-065

Figure 155: Shows apparent

natural fractured zones in Well

07-21-065

183

Natural fracture:(2842.5-2845.3)m

Well 09-34-065



09-34-065

184

Natural fracture:(3073.2-3082)m

Well 13-30-065



13-30-065

185

Figure 158: Shows cumulative gas production for individual wells

Figure 159: Shows forecast cumulative gas production for individual wells

-500.00

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

0.00 10000.00 20000.00 30000.00 40000.00 50000.00 60000.00 70000.00 80000.00

Mo

nth

ly g

as (

E3 m

3)

Cummulative Production (E3 m3)

Rate vs Cummulative production

Well 07-21-65

Well 08-22-065

Well 09_34_065

Well 12_32_065

Well 13_30_065

Well 14-11-065

Well 15-13-065

0.00

200.00

400.00

600.00

800.00

1000.00

1200.00

1400.00

1600.00

1800.00

0.00 10000.00 20000.00 30000.00 40000.00 50000.00 60000.00 70000.00 80000.00 90000.00

Gas

Rat

e (E

3m

3)

Cummulative Production (E3m3)

Production Forecast: Rate vs. Cummulative Production

Well 07-21-65

Well 15-13-65

Well 14-11-65

Well 13-30-65

Well 12-32-65

Well 09-34-65

Well 08-22-65

186

Figure 160: Shows monthly gas production for individual wells

Figure 161: Pool cumulative production history compared to forecast cumulative gas production

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00 160.00 180.00 200.00

Gas

Rat

e (E

3m

3)

Number of months

Monthly Gas Rate vs. Number of months

Well-15-13-065

Well-07-21-65

Well-13-30-65

Well-12-32-65

Well-09-34-65

Well-08-22-65

Well-14-11-65

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

3500.00

4000.00

100000.0 150000.0 200000.0 250000.0 300000.0 350000.0 400000.0

∑𝑄

∑(𝐶𝑢𝑚𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑃𝑟𝑜𝑑.)

Pool History and Forecast

Monthly gas production vs cumulative production

Forecast Monthly gas production vs cumulativeproduction

187

Figure 162: Pool monthly gas production then extrapolated by exponential decline method over

15 years


method


method

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

3500.00

4000.00

0 50 100 150 200 250 300 350

Tota

l Gas

Rat

e (E

3m

3)

t ( number of months from Nov 2005)

Total Gas Rate vs. time

0

200

400

600

800

1000

1200

0 10000 20000 30000 40000 50000 60000

Mo

nth

ly G

as P

rod

uct

ion

(E

3m

3)

Cumulative Gas Production (E3m3)

Type well 1 Cumulative Production

Production History

Extrapolated by Exponentialdecline

0

200

400

600

800

1000

1200

0 5000 10000 15000 20000 25000 30000 35000 40000 45000

Mo

nth

ly G

as P

rod

uct

ion

(E3

m3

)


Type well 2: Cumulative Production

From Production History

Extrapolated by Exponential decline method

188


method


method

0

200

400

600

800

1000

1200

1400

1600

1800

0 5000 10000 15000 20000 25000 30000 35000 40000Mo

nth

ly G

as P

rod

uct

ion

(E3

m3

)


Type well 3: Cumulative Gas Production


Extrapolated by Exponentialdecline method

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

400.00

450.00

0.00 5000.00 10000.00 15000.00 20000.00 25000.00 30000.00Mo

nth

ly G

as P

rod

uct

ion

(E3

m3

)


Type well 4: Cumulative Gas Production


Extrapolated by Exponentialdecline method

189

Figure 167: Determination of exponential decline equation constants for the pool

Figure 168: Determination of the exponential decline equation constants for well 07-21-065


y = -0.0079x + 7.7695

0

1

2

3

4

5

6

7

8

9

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00

Ln (

Q)


Ln (Cummulative Gas Rate) vs. time

y = -0.0168x + 6

-1.00

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00 160.00

Ln (

Q)

t (months)


y = -0.037x + 7.6

-1

0

1

2

3

4

5

6

7

8

9

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00 160.00 180.00 200.00

Ln (

Q)

t (months)


190




y = -0.004x + 4.65

0.00

1.00

2.00

3.00

4.00

5.00

6.00

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00

Ln (

Q)

t (months)


-4

-2

0

2

4

6

8

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00 160.00

Ln (

Q)

t (months)


y = -0.0131x + 7.4

y = -0.0187x + 7.56

-2

0

2

4

6

8

10

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00 160.00

Ln (

Q)

t (months)


191



Figure 175: Determination of the exponential decline equation constants for Type well 1

y = -0.0137x + 5.8866

0

1

2

3

4

5

6

7

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00

Ln (

Q)

t (months)


y = -0.0281x + 7.0333

-4

-2

0

2

4

6

8

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00 160.00 180.00 200.00

Ln (

Q)

t (months)


y = -0.0145x + 6.8868

0

2

4

6

8

0 20 40 60 80 100 120 140 160

Ln (

Q)


Type well 1: Ln (Q) vs. time

192




y = -0.0111x + 6.1667

0

1

2

3

4

5

6

7

8

0 20 40 60 80 100 120 140

Ln (

Q)



y = -0.0253x + 6.5685

0

1

2

3

4

5

6

7

8

0 20 40 60 80 100 120 140 160 180 200

Ln (

Q)



y = -0.0137x + 5.8866

0

1

2

3

4

5

6

7

0 20 40 60 80 100 120 140

Ln (

Q)


Type well 4:Ln (Q) vs. time

193

Flowing Material Balance

Well P(wh) (Kpaa) Q (E3m3)

00/07-31-065-08W6/0 6,280 2,555.40

00/12-32-065-08W6/0 6,912 60,586.30

00/14-33-065-08W6/0 19,730 14,417.90

00/09-34-065-08W6/0 14,700 21,466.80

00/06-34-065-08W6/0 15,073 121,348.70

00/02-35-065-08W6/0 16,731 13,929.70

00/15-25-065-08W6/0 12,230 11,284.30

00/06-27-065-08W6/0 17,537 50,113.60

00/13-30-065-08W6/0 12,890 74,579.90

00/10-19-065-08W6/0 15,788 164,530.70

00/08-22-065-08W6/0 17,486 38,479.60

00/08-23-065-08W6/0 17,220 31,100.00

00/10-24-065-08W6/0 12,159 105,861.70

00/15-13-065-08W6/0 13,693 44,112.60

00/04-18-065-08W6/0 12,000 12,715.60

00/03-10-065-08W6/0 13,824 31,507.60

00/14-11-065-08W6/0 13,500 9,871.50

Table 36 : Wellhead pressures and cumulative production values for the wells that produced

from Cadomin and Nikanassin Formations in our township.

.

194

Appendix M: Economic Analysis

Figure 179:Perforation data for wells within township 065-08W6

195

Figure 180:Schematic of horizontal drilling techniques. The process shown in this diagram

corresponds to short radius drilling (Joshi, 1991).

196

Table 37: Gas Price Forecast by Deloitte.

197

Base Case Analysis

Table 38: Base Case Economic Evaluation.

Year Type 1

(E3m3)

Type 2

(E3m3)

Type 4

(E3m3)

Type 3

(E3m3)

Total Cum.

Production

(E3m3)

Alberta

Reference

Average Price -

Current

(C$/E3m3)

Gross

RevenueCapex

Fixed

Opex

Variable

OpexRoyalty Revenue Tax

Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 1269.933 1548.839 903.9506 140.5554 3863.278 92.84 $358,666.73 $0.00 $25,200.00 $138,962.11 $71,733.35 $122,771.27 $24,554.25 $98,217.02 $98,217.02 $98,217.02

2016 1067.12 1355.683 766.914 113.9044 3303.6214 111.195 $367,346.18 $0.00 $25,200.00 $118,831.26 $73,469.24 $149,845.68 $29,969.14 $119,876.55 $119,876.55 $107,032.63

2017 896.6979 1186.616 650.6519 76.58503 2810.55083 125.315 $352,204.18 $0.00 $25,200.00 $101,095.51 $70,440.84 $155,467.83 $31,093.57 $124,374.26 $124,374.26 $99,150.40

2018 753.4925 1038.633 552.0147 56.5317 2400.6719 134.14 $322,026.13 $0.00 $25,200.00 $86,352.17 $64,405.23 $146,068.73 $29,213.75 $116,854.99 $116,854.99 $83,175.07

2019 633.1574 909.1051 468.3307 41.72922 2052.32242 146.495 $300,654.97 $0.00 $25,200.00 $73,822.04 $60,130.99 $141,501.94 $28,300.39 $113,201.55 $113,201.55 $71,941.63

2020 532.0402 795.7306 397.33 30.80268 1755.90348 157.085 $275,826.10 $0.00 $25,200.00 $63,159.85 $55,165.22 $132,301.03 $26,460.21 $105,840.82 $105,840.82 $60,056.93

2021 477.0717 696.495 337.0983 22.7372 1533.4022 169.44 $259,819.67 $0.00 $25,200.00 $55,156.48 $51,963.93 $127,499.26 $25,499.85 $101,999.41 $101,999.41 $51,676.07

2022 375.673 609.6352 285.9951 16.78359 1288.08689 176.5 $227,347.34 $0.00 $25,200.00 $46,332.49 $45,469.47 $110,345.38 $22,069.08 $88,276.31 $88,276.31 $39,931.72

2023 315.6769 533.6076 242.639 12.38891 1104.31241 188.855 $208,554.92 $0.00 $25,200.00 $39,722.12 $41,710.98 $101,921.82 $20,384.36 $81,537.46 $81,537.46 $32,931.61

2024 265.2623 467.0614 205.8556 9.144948 947.324248 194.15 $183,923.00 $0.00 $25,200.00 $34,075.25 $36,784.60 $87,863.15 $17,572.63 $70,290.52 $70,290.52 $25,347.47

2025 222.8991 408.8142 174.6484 6.750399 813.112099 199.445 $162,171.14 $0.00 $25,200.00 $29,247.64 $32,434.23 $75,289.27 $15,057.85 $60,231.42 $60,231.42 $19,392.90

2026 187.3014 357.8309 148.1721 4.98285 698.28725 210.035 $146,664.76 $0.00 $25,200.00 $25,117.39 $29,332.95 $67,014.42 $13,402.88 $53,611.53 $53,611.53 $15,412.03

2027 157.3888 313.2059 125.7096 3.678119 599.982419 218.86 $131,312.15 $0.00 $25,200.00 $21,581.37 $26,262.43 $58,268.35 $11,653.67 $46,614.68 $46,614.68 $11,964.83

2028 132.2533 274.146 106.6524 2.715026 515.766726 224.155 $115,611.69 $0.00 $25,200.00 $18,552.13 $23,122.34 $48,737.22 $9,747.44 $38,989.78 $38,989.78 $8,935.45

2029 111.132 239.9572 90.48415 2.004113 443.577463 227.685 $100,995.93 $0.00 $25,200.00 $15,955.48 $20,199.19 $39,641.27 $7,928.25 $31,713.01 $31,713.01 $6,489.11

Jul, 2030 56.43788 125.9049 46.30665 0.916974 229.566404 232.98 $53,484.38 $0.00 $25,200.00 $8,257.50 $10,696.88 $9,330.00 $1,866.00 $7,464.00 $7,464.00 $1,363.65

NPV $733,018.52

198

Infill Drilling Analysis

Table 39: Year 1 Economic Evaluation – 3 New Drills 2016.

Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross

RevenueCapex Fixed Opex Variable Opex Royalty Revenue Tax

Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 6822.61 $92.84 $633,410.69 $0.00 $25,200.00 $245,409.12 $126,682.14 $236,119.43 $47,223.89 $188,895.55 $188,895.55 $188,895.55

2016 5840.33 $111.20 $649,415.36 $22,837,682.14 $36,000.00 $5,005,989.88 $129,883.07 -$4,522,457.59 $54,691.13 -$4,577,148.72 -$27,414,830.86 -$24,477,527.55

2017 4970.45 $125.32 $622,871.91 $0.00 $36,000.00 $178,787.08 $124,574.38 $283,510.45 $56,702.09 $226,808.36 $226,808.36 $180,810.24

2018 4249.33 $134.14 $570,005.01 $0.00 $36,000.00 $152,848.37 $114,001.00 $267,155.64 $53,431.13 $213,724.51 $213,724.51 $152,124.88

2019 3636.31 $146.50 $532,701.84 $0.00 $36,000.00 $130,798.22 $106,540.37 $259,363.25 $51,872.65 $207,490.60 $207,490.60 $131,864.03

2020 3114.48 $157.09 $489,237.61 $0.00 $36,000.00 $112,027.74 $97,847.52 $243,362.35 $48,672.47 $194,689.88 $194,689.88 $110,472.27

2021 2729.71 $169.44 $462,521.40 $0.00 $36,000.00 $98,187.53 $92,504.28 $235,829.59 $47,165.92 $188,663.67 $188,663.67 $95,582.89

2022 2290.18 $176.50 $404,216.54 $0.00 $36,000.00 $82,377.73 $80,843.31 $204,995.50 $40,999.10 $163,996.40 $163,996.40 $74,183.64

2023 1965.99 $188.86 $371,286.25 $0.00 $36,000.00 $70,716.51 $74,257.25 $190,312.49 $38,062.50 $152,249.99 $152,249.99 $61,491.22

2024 1688.79 $194.15 $327,879.14 $0.00 $36,000.00 $60,745.88 $65,575.83 $165,557.43 $33,111.49 $132,445.95 $132,445.95 $47,761.34

2025 1451.58 $199.45 $289,509.54 $0.00 $36,000.00 $52,213.18 $57,901.91 $143,394.45 $28,678.89 $114,715.56 $114,715.56 $36,935.34

2026 1248.40 $210.04 $262,208.20 $0.00 $36,000.00 $44,905.03 $52,441.64 $128,861.52 $25,772.30 $103,089.22 $103,089.22 $29,635.69

2027 1074.26 $218.86 $235,111.50 $0.00 $36,000.00 $38,640.96 $47,022.30 $113,448.24 $22,689.65 $90,758.59 $90,758.59 $23,295.47

2028 924.88 $224.16 $207,316.71 $0.00 $36,000.00 $33,267.97 $41,463.34 $96,585.40 $19,317.08 $77,268.32 $77,268.32 $17,707.90

2029 796.67 $227.69 $181,389.99 $0.00 $36,000.00 $28,656.25 $36,278.00 $80,455.74 $16,091.15 $64,364.59 $64,364.59 $13,170.27

Jul, 2030 412.83 $232.98 $96,180.24 $0.00 $36,000.00 $14,849.36 $19,236.05 $26,094.83 $5,218.97 $20,875.87 $20,875.87 $3,813.94

NPV -$23,309,782.88

199


Year

Total

Cum.

Producti

on

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross

RevenueCapex Fixed Opex

Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 10911.31 $92.84 $1,013,006.06 $0.00 $25,200.00 $392,479.84 $202,601.21 $392,725.01 $78,545.00 $314,180.01 $314,180.01 $314,180.01

2016 9330.252 $111.20 $1,037,477.35 $22,837,682.14 $36,000.00 $5,131,522.41 $207,495.47 -$4,337,540.53 $91,674.54 -$4,429,215.07 -$27,266,897.21 -$24,345,443.94

2017 7950.462 $125.32 $996,312.09 $22,212,214.74 $46,800.00 $4,950,543.20 $199,262.42 -$4,200,293.52 $92,854.31 -$4,293,147.84 -$26,505,362.57 -$21,129,912.77

2018 6794.947 $134.14 $911,474.20 $0.00 $46,800.00 $244,414.25 $182,294.84 $437,965.12 $87,593.02 $350,372.09 $350,372.09 $249,387.94

2019 5811.734 $146.50 $851,389.98 $0.00 $46,800.00 $209,048.07 $170,278.00 $425,263.91 $85,052.78 $340,211.13 $340,211.13 $216,210.32

2020 4974.288 $157.09 $781,386.02 $0.00 $46,800.00 $178,925.14 $156,277.20 $399,383.68 $79,876.74 $319,506.95 $319,506.95 $181,296.82

2021 4380.345 $169.44 $742,205.57 $0.00 $46,800.00 $157,560.99 $148,441.11 $389,403.47 $77,880.69 $311,522.77 $311,522.77 $157,827.13

2022 3651.16 $176.50 $644,429.72 $0.00 $46,800.00 $131,332.22 $128,885.94 $337,411.55 $67,482.31 $269,929.24 $269,929.24 $122,102.28

2023 3130.947 $188.86 $591,295.04 $0.00 $46,800.00 $112,620.17 $118,259.01 $313,615.86 $62,723.17 $250,892.69 $250,892.69 $101,331.35

2024 2686.379 $194.15 $521,560.46 $0.00 $46,800.00 $96,629.05 $104,312.09 $273,819.32 $54,763.86 $219,055.46 $219,055.46 $78,993.59

2025 2306.188 $199.45 $459,957.71 $0.00 $46,800.00 $82,953.59 $91,991.54 $238,212.57 $47,642.51 $190,570.06 $190,570.06 $61,358.46

2026 1980.836 $210.04 $416,044.91 $0.00 $46,800.00 $71,250.67 $83,208.98 $214,785.25 $42,957.05 $171,828.20 $171,828.20 $49,396.50

2027 1702.239 $218.86 $372,551.97 $0.00 $46,800.00 $61,229.53 $74,510.39 $190,012.05 $38,002.41 $152,009.64 $152,009.64 $39,017.09

2028 1463.534 $224.16 $328,058.39 $0.00 $46,800.00 $52,643.31 $65,611.68 $163,003.40 $32,600.68 $130,402.72 $130,402.72 $29,884.94

2029 1258.892 $227.69 $286,630.82 $0.00 $46,800.00 $45,282.34 $57,326.16 $137,222.31 $27,444.46 $109,777.85 $109,777.85 $22,462.72

Jul, 2030 651.6068 $232.98 $151,811.36 $0.00 $46,800.00 $23,438.30 $30,362.27 $51,210.79 $10,242.16 $40,968.63 $40,968.63 $7,484.82

NPV -$43,844,422.73

200


Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 13870.6378 $92.84 $1,287,750.01 $0.00 $25,200.00 $498,926.84 $257,550.00 $506,073.17 $101,214.63 $404,858.54 $404,858.54 $404,858.54

2016 11866.9592 $111.20 $1,319,546.53 $22,837,682.14 $36,000.00 $5,222,767.77 $263,909.31 -$4,203,130.55 $118,556.54 -$4,321,687.09 -$27,159,369.22 -$24,249,436.81

2017 10110.3605 $125.32 $1,266,979.82 $22,212,214.74 $46,800.00 $5,028,234.76 $253,395.96 -$4,061,450.90 $120,622.84 -$4,182,073.74 -$26,394,288.48 -$21,041,365.18

2018 8643.6043 $134.14 $1,159,453.08 $21,638,869.76 $57,600.00 $4,855,073.10 $231,890.62 -$3,985,110.63 $111,810.40 -$4,096,921.03 -$25,735,790.79 -$18,318,227.55

2019 7395.72576 $146.50 $1,083,436.85 $0.00 $57,600.00 $266,024.26 $216,687.37 $543,125.22 $108,625.04 $434,500.18 $434,500.18 $276,132.72

2020 6332.86144 $157.09 $994,797.54 $0.00 $57,600.00 $227,793.03 $198,959.51 $510,445.01 $102,089.00 $408,356.00 $408,356.00 $231,712.16

2021 5576.6484 $169.44 $944,907.30 $0.00 $57,600.00 $200,592.04 $188,981.46 $497,733.80 $99,546.76 $398,187.04 $398,187.04 $201,733.95

2022 4653.25167 $176.50 $821,298.92 $0.00 $57,600.00 $167,377.46 $164,259.78 $432,061.67 $86,412.33 $345,649.34 $345,649.34 $156,354.21

2023 3992.62063 $188.86 $754,026.37 $0.00 $57,600.00 $143,614.56 $150,805.27 $402,006.53 $80,401.31 $321,605.22 $321,605.22 $129,890.96

2024 3427.84754 $194.15 $665,516.60 $0.00 $57,600.00 $123,299.68 $133,103.32 $351,513.60 $70,302.72 $281,210.88 $281,210.88 $101,407.46

2025 2944.6519 $199.45 $587,296.10 $0.00 $57,600.00 $105,919.13 $117,459.22 $306,317.75 $61,263.55 $245,054.20 $245,054.20 $78,900.89

2026 2530.95125 $210.04 $531,588.35 $0.00 $57,600.00 $91,038.32 $106,317.67 $276,632.36 $55,326.47 $221,305.89 $221,305.89 $63,620.15

2027 2176.51156 $218.86 $476,351.32 $0.00 $57,600.00 $78,289.12 $95,270.26 $245,191.93 $49,038.39 $196,153.55 $196,153.55 $50,347.73

2028 1872.64798 $224.16 $419,763.41 $0.00 $57,600.00 $67,359.15 $83,952.68 $210,851.58 $42,170.32 $168,681.26 $168,681.26 $38,657.39

2029 1611.98529 $227.69 $367,024.87 $0.00 $57,600.00 $57,983.11 $73,404.97 $178,036.79 $35,607.36 $142,429.43 $142,429.43 $29,143.88

Jul, 2030 834.866572 $232.98 $194,507.21 $0.00 $57,600.00 $30,030.15 $38,901.44 $67,975.62 $13,595.12 $54,380.50 $54,380.50 $9,935.11

NPV -$61,836,334.37

201


Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 18238.2488 $92.84 $1,693,239.02 $0.00 $25,200.00 $656,029.81 $338,647.80 $673,361.41 $134,672.28 $538,689.12 $538,689.12 $538,689.12

2016 15645.4452 $111.20 $1,739,695.28 $22,837,682.14 $36,000.00 $5,358,679.91 $347,939.06 -$4,002,923.69 $158,597.91 -$4,161,521.60 -$26,999,203.74 -$24,106,431.91

2017 13380.2904 $125.32 $1,676,751.09 $22,212,214.74 $46,800.00 $5,145,854.14 $335,350.22 -$3,851,253.27 $175,251.20 -$4,026,504.47 -$26,238,719.21 -$20,917,346.31

2018 11474.3628 $134.14 $1,539,171.03 $21,638,869.76 $57,600.00 $4,956,895.48 $307,834.21 -$3,783,158.66 $192,305.65 -$3,975,464.31 -$25,614,334.06 -$18,231,777.05

2019 9847.09336 $146.50 $1,442,549.94 $21,065,524.81 $68,400.00 $4,777,960.16 $288,509.99 -$3,692,320.20 $205,717.07 -$3,898,037.27 -$24,963,562.08 -$15,864,795.00

2020 8456.36284 $157.09 $1,328,367.76 $0.00 $68,400.00 $304,175.37 $265,673.55 $690,118.83 $138,023.77 $552,095.07 $552,095.07 $313,273.57

2021 7446.7101 $169.44 $1,261,770.56 $0.00 $68,400.00 $267,858.16 $252,354.11 $673,158.29 $134,631.66 $538,526.63 $538,526.63 $272,834.35

2022 6248.19507 $176.50 $1,102,806.43 $0.00 $68,400.00 $224,747.58 $220,561.29 $589,097.57 $117,819.51 $471,278.05 $471,278.05 $213,182.26

2023 5375.51273 $188.86 $1,015,192.46 $0.00 $68,400.00 $193,357.19 $203,038.49 $550,396.77 $110,079.35 $440,317.42 $440,317.42 $177,836.82

2024 4627.23264 $194.15 $898,377.22 $0.00 $68,400.00 $166,441.56 $179,675.44 $483,860.22 $96,772.04 $387,088.17 $387,088.17 $139,587.88

2025 3985.1794 $199.45 $794,824.10 $0.00 $68,400.00 $143,346.90 $158,964.82 $424,112.38 $84,822.48 $339,289.90 $339,289.90 $109,242.27

2026 3433.91445 $210.04 $721,242.22 $0.00 $68,400.00 $123,517.90 $144,248.44 $385,075.87 $77,015.17 $308,060.70 $308,060.70 $88,560.09

2027 2960.31216 $218.86 $647,893.92 $0.00 $68,400.00 $106,482.43 $129,578.78 $343,432.71 $68,686.54 $274,746.17 $274,746.17 $70,520.50

2028 2553.19328 $224.16 $572,311.04 $0.00 $68,400.00 $91,838.36 $114,462.21 $297,610.47 $59,522.09 $238,088.38 $238,088.38 $54,563.71

2029 2203.03169 $227.69 $501,597.27 $0.00 $68,400.00 $79,243.05 $100,319.45 $253,634.77 $50,726.95 $202,907.81 $202,907.81 $41,518.96

Jul, 2030 1143.11425 $232.98 $266,322.76 $0.00 $68,400.00 $41,117.82 $53,264.55 $103,540.39 $20,708.08 $82,832.31 $82,832.31 $15,133.15

NPV -$77,085,407.59

202

Table 43: Year 5 Economic Evaluation – 3 New Drills 2020

Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 20918.67 $92.84 $1,942,089.34 $0.00 $25,200.00 $752,444.57 $388,417.87 $776,026.91 $155,205.38 $620,821.52 $620,821.52 $620,821.52

2016 17893.59 $111.20 $1,989,677.70 $22,837,682.14 $36,000.00 $5,439,545.67 $397,935.54 -$3,883,803.51 $182,421.95 -$4,066,225.46 -$26,903,907.59 -$24,021,346.07

2017 15250.271 $125.32 $1,911,087.74 $22,212,214.74 $46,800.00 $5,213,117.35 $382,217.55 -$3,731,047.16 $186,703.59 -$3,917,750.75 -$26,129,965.48 -$20,830,648.50

2018 13037.88 $134.14 $1,748,901.16 $21,638,869.76 $57,600.00 $5,013,135.17 $349,780.23 -$3,671,614.25 $174,509.68 -$3,846,123.93 -$25,484,993.69 -$18,139,715.12

2019 11155.137 $146.50 $1,634,171.85 $21,065,524.81 $68,400.00 $4,825,010.50 $326,834.37 -$3,586,073.02 $167,537.44 -$3,753,610.46 -$24,819,135.26 -$15,773,009.15

2020 9551.2459 $157.09 $1,500,357.47 $20,544,302.31 $79,200.00 $4,657,861.80 $300,071.49 -$3,536,775.83 $155,505.53 -$3,692,281.36 -$24,236,583.67 -$13,752,488.46

2021 8423.5907 $169.44 $1,427,293.21 $0.00 $79,200.00 $302,996.56 $285,458.64 $759,638.01 $151,927.60 $607,710.41 $607,710.41 $307,885.00

2022 7016.3247 $176.50 $1,238,381.30 $0.00 $79,200.00 $252,377.20 $247,676.26 $659,127.84 $131,825.57 $527,302.28 $527,302.28 $238,524.77

2023 6019.2554 $188.86 $1,136,766.49 $0.00 $79,200.00 $216,512.62 $227,353.30 $613,700.57 $122,740.11 $490,960.46 $490,960.46 $198,290.69

2024 5166.9022 $194.15 $1,003,154.06 $0.00 $79,200.00 $185,853.47 $200,630.81 $537,469.78 $107,493.96 $429,975.82 $429,975.82 $155,053.59

2025 4437.728 $199.45 $885,082.66 $0.00 $79,200.00 $159,625.08 $177,016.53 $469,241.05 $93,848.21 $375,392.84 $375,392.84 $120,866.45

2026 3813.5001 $210.04 $800,968.49 $0.00 $79,200.00 $137,171.60 $160,193.70 $424,403.20 $84,880.64 $339,522.56 $339,522.56 $97,604.62

2027 3278.7679 $218.86 $717,591.14 $0.00 $79,200.00 $117,937.28 $143,518.23 $376,935.63 $75,387.13 $301,548.50 $301,548.50 $77,399.99

2028 2820.4149 $224.16 $632,210.10 $0.00 $79,200.00 $101,450.32 $126,442.02 $325,117.76 $65,023.55 $260,094.21 $260,094.21 $59,606.88

2029 2427.2998 $227.69 $552,659.76 $0.00 $79,200.00 $87,309.97 $110,531.95 $275,617.83 $55,123.57 $220,494.26 $220,494.26 $45,117.50

Jul, 2030 1256.907 $232.98 $292,834.19 $0.00 $79,200.00 $45,210.94 $58,566.84 $109,856.41 $21,971.28 $87,885.13 $87,885.13 $16,056.28

NPV -$90,579,980.00

203

Re-Perforation and Fracturing Analysis

Table 44: Year 2016 Economic Evaluation – Re-perforating and Fracturing.

Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 3863.435 $92.84 $358,681.31 $0.00 $25,200.00 $138,967.76 $71,736.26 $122,777.29 $24,555.46 $98,221.83 $98,221.83 $98,221.83

2016 3981.4629 $111.20 $442,718.77 $109,974.25 $25,200.00 $143,213.22 $88,543.75 $185,761.79 $37,152.36 $148,609.43 $38,635.18 $34,495.70

2017 3403.85853 $125.32 $426,554.53 $0.00 $25,200.00 $122,436.79 $85,310.91 $193,606.83 $38,721.37 $154,885.47 $154,885.47 $123,473.75

2018 2919.9883 $134.14 $391,687.23 $0.00 $25,200.00 $105,031.98 $78,337.45 $183,117.81 $36,623.56 $146,494.24 $146,494.24 $104,271.71

2019 2506.86892 $146.50 $367,243.76 $0.00 $25,200.00 $90,172.08 $73,448.75 $178,422.93 $35,684.59 $142,738.35 $142,738.35 $90,712.80

2020 2153.76878 $157.09 $338,324.77 $0.00 $25,200.00 $77,471.06 $67,664.95 $167,988.75 $33,597.75 $134,391.00 $134,391.00 $76,257.06

2021 1881.6498 $169.44 $318,826.74 $0.00 $25,200.00 $67,682.94 $63,765.35 $162,178.45 $32,435.69 $129,742.76 $129,742.76 $65,731.72

2022 1592.90439 $176.50 $281,147.62 $0.00 $25,200.00 $57,296.77 $56,229.52 $142,421.33 $28,484.27 $113,937.06 $113,937.06 $51,539.34

2023 1371.11611 $188.86 $258,942.13 $0.00 $25,200.00 $49,319.05 $51,788.43 $132,634.66 $26,526.93 $106,107.73 $106,107.73 $42,855.13

2024 1180.85485 $194.15 $229,262.97 $0.00 $25,200.00 $42,475.35 $45,852.59 $115,735.03 $23,147.01 $92,588.02 $92,588.02 $33,388.17

2025 1017.5191 $199.45 $202,939.10 $0.00 $25,200.00 $36,600.16 $40,587.82 $100,551.12 $20,110.22 $80,440.89 $80,440.89 $25,899.81

2026 877.20275 $210.04 $184,243.28 $0.00 $25,200.00 $31,552.98 $36,848.66 $90,641.64 $18,128.33 $72,513.31 $72,513.31 $20,845.84

2027 756.585319 $218.86 $165,586.26 $0.00 $25,200.00 $27,214.37 $33,117.25 $80,054.64 $16,010.93 $64,043.71 $64,043.71 $16,438.42

2028 652.839626 $224.16 $146,337.27 $0.00 $25,200.00 $23,482.64 $29,267.45 $68,387.17 $13,677.43 $54,709.74 $54,709.74 $12,538.06

2029 563.556063 $227.69 $128,313.26 $0.00 $25,200.00 $20,271.11 $25,662.65 $57,179.50 $11,435.90 $45,743.60 $45,743.60 $9,360.05

Jul, 2030 292.518704 $232.98 $68,151.01 $0.00 $25,200.00 $10,521.90 $13,630.20 $18,798.91 $3,759.78 $15,039.13 $15,039.13 $2,747.59

NPV $808,776.99

204


Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 3863.435 $92.84 $358,681.31 $0.00 $25,200.00 $138,967.76 $71,736.26 $122,777.29 $24,555.46 $98,221.83 $98,221.83 $98,221.83

2016 3981.4629 $111.20 $442,718.77 $109,974.25 $25,200.00 $143,213.22 $88,543.75 $185,761.79 $37,152.36 $148,609.43 $38,635.18 $34,495.70

2017 3403.85853 $125.32 $426,554.53 $0.00 $25,200.00 $122,436.79 $85,310.91 $193,606.83 $38,721.37 $154,885.47 $44,911.22 $35,802.95

2018 2919.9883 $134.14 $391,687.23 $0.00 $25,200.00 $105,031.98 $78,337.45 $183,117.81 $36,623.56 $146,494.24 $146,494.24 $104,271.71

2019 3188.70332 $146.50 $467,129.09 $109,974.25 $25,200.00 $114,697.66 $93,425.82 $233,805.62 $46,761.12 $187,044.49 $77,070.24 $48,979.53

2020 2750.56668 $157.09 $432,072.77 $0.00 $25,200.00 $98,937.88 $86,414.55 $221,520.33 $44,304.07 $177,216.26 $177,216.26 $100,557.27

2021 2404.021 $169.44 $407,337.32 $0.00 $25,200.00 $86,472.64 $81,467.46 $214,197.22 $42,839.44 $171,357.78 $171,357.78 $86,815.18

2022 2050.13079 $176.50 $361,848.08 $0.00 $25,200.00 $73,743.20 $72,369.62 $190,535.26 $38,107.05 $152,428.21 $152,428.21 $68,950.78

2023 1771.32181 $188.86 $334,522.98 $0.00 $25,200.00 $63,714.45 $66,904.60 $178,703.94 $35,740.79 $142,963.15 $142,963.15 $57,740.42

2024 1531.150848 $194.15 $297,272.94 $0.00 $25,200.00 $55,075.50 $59,454.59 $157,542.85 $31,508.57 $126,034.28 $126,034.28 $45,449.23

2025 1324.129799 $199.45 $264,091.07 $0.00 $25,200.00 $47,628.95 $52,818.21 $138,443.91 $27,688.78 $110,755.12 $110,755.12 $35,660.19

2026 1145.57595 $210.04 $240,611.04 $0.00 $25,200.00 $41,206.37 $48,122.21 $126,082.47 $25,216.49 $100,865.98 $100,865.98 $28,996.56

2027 991.489719 $218.86 $216,997.44 $0.00 $25,200.00 $35,663.89 $43,399.49 $112,734.07 $22,546.81 $90,187.25 $90,187.25 $23,148.82

2028 858.449126 $224.16 $192,425.66 $0.00 $25,200.00 $30,878.42 $38,485.13 $97,862.12 $19,572.42 $78,289.69 $78,289.69 $17,941.98

2029 743.524013 $227.69 $169,289.26 $0.00 $25,200.00 $26,744.56 $33,857.85 $83,486.85 $16,697.37 $66,789.48 $66,789.48 $13,666.45

Jul, 2030 386.947404 $232.98 $90,151.01 $0.00 $25,200.00 $13,918.50 $18,030.20 $33,002.31 $6,600.46 $26,401.85 $26,401.85 $4,823.52

NPV $805,522.11

205


Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 3863.435 $92.84 $358,681.31 $0.00 $25,200.00 $138,967.76 $71,736.26 $122,777.29 $24,555.46 $98,221.83 $98,221.83 $98,221.83

2016 3981.4629 $111.20 $442,718.77 $109,974.25 $25,200.00 $143,213.22 $88,543.75 $185,761.79 $37,152.36 $148,609.43 $38,635.18 $34,495.70

2017 3403.85853 $125.32 $426,554.53 $0.00 $25,200.00 $122,436.79 $85,310.91 $193,606.83 $38,721.37 $154,885.47 $154,885.47 $123,473.75

2018 2919.9883 $134.14 $391,687.23 $0.00 $25,200.00 $105,031.98 $78,337.45 $183,117.81 $36,623.56 $146,494.24 $146,494.24 $104,271.71

2019 3188.70332 $146.50 $467,129.09 $109,974.25 $25,200.00 $114,697.66 $93,425.82 $233,805.62 $46,761.12 $187,044.49 $77,070.24 $48,979.53

2020 2750.56668 $157.09 $432,072.77 $0.00 $25,200.00 $98,937.88 $86,414.55 $221,520.33 $44,304.07 $177,216.26 $177,216.26 $100,557.27

2021 2404.021 $169.44 $407,337.32 $0.00 $25,200.00 $86,472.64 $81,467.46 $214,197.22 $42,839.44 $171,357.78 $171,357.78 $86,815.18

2022 2735.56549 $176.50 $482,827.31 $109,974.25 $25,200.00 $98,398.29 $96,565.46 $262,663.56 $52,532.71 $210,130.85 $100,156.60 $45,305.76

2023 2371.63031 $188.86 $447,894.24 $0.00 $25,200.00 $85,307.54 $89,578.85 $247,807.85 $49,561.57 $198,246.28 $198,246.28 $80,068.35

2024 2056.59495 $194.15 $399,287.91 $0.00 $25,200.00 $73,975.72 $79,857.58 $220,254.61 $44,050.92 $176,203.69 $176,203.69 $63,540.82

2025 1784.0457 $199.45 $355,818.99 $0.00 $25,200.00 $64,172.12 $71,163.80 $195,283.07 $39,056.61 $156,226.46 $156,226.46 $50,300.74

2026 1548.13585 $210.04 $325,162.71 $0.00 $25,200.00 $55,686.45 $65,032.54 $179,243.72 $35,848.74 $143,394.98 $143,394.98 $41,222.63

2027 1343.84632 $218.86 $294,114.21 $0.00 $25,200.00 $48,338.15 $58,822.84 $161,753.21 $32,350.64 $129,402.57 $129,402.57 $33,214.42

2028 1166.86333 $224.16 $261,558.25 $0.00 $25,200.00 $41,972.07 $52,311.65 $142,074.53 $28,414.91 $113,659.62 $113,659.62 $26,047.85

2029 1013.47586 $227.69 $230,753.25 $0.00 $25,200.00 $36,454.73 $46,150.65 $122,947.87 $24,589.57 $98,358.30 $98,358.30 $20,126.06

Jul, 2030 528.590404 $232.98 $123,150.99 $0.00 $25,200.00 $19,013.40 $24,630.20 $54,307.40 $10,861.48 $43,445.92 $43,445.92 $7,937.41

NPV $964,578.99

206


Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 3863.435 $92.84 $358,681.31 $0.00 $25,200.00 $138,967.76 $71,736.26 $122,777.29 $24,555.46 $98,221.83 $98,221.83 $98,221.83

2016 3981.4629 $111.20 $442,718.77 $109,974.25 $25,200.00 $143,213.22 $88,543.75 $185,761.79 $37,152.36 $148,609.43 $38,635.18 $34,495.70

2017 3403.8585 $125.32 $426,554.53 $0.00 $25,200.00 $122,436.79 $85,310.91 $193,606.83 $38,721.37 $154,885.47 $154,885.47 $123,473.75

2018 2919.9883 $134.14 $391,687.23 $0.00 $25,200.00 $105,031.98 $78,337.45 $183,117.81 $36,623.56 $146,494.24 $146,494.24 $104,271.71

2019 3188.7033 $146.50 $467,129.09 $109,974.25 $25,200.00 $114,697.66 $93,425.82 $233,805.62 $46,761.12 $187,044.49 $77,070.24 $48,979.53

2020 2750.5667 $157.09 $432,072.77 $0.00 $25,200.00 $98,937.88 $86,414.55 $221,520.33 $44,304.07 $177,216.26 $177,216.26 $100,557.27

2021 2404.021 $169.44 $407,337.32 $0.00 $25,200.00 $86,472.64 $81,467.46 $214,197.22 $42,839.44 $171,357.78 $171,357.78 $86,815.18

2022 2735.5655 $176.50 $482,827.31 $109,974.25 $25,200.00 $98,398.29 $96,565.46 $262,663.56 $52,532.71 $210,130.85 $100,156.60 $45,305.76

2023 2371.6303 $188.86 $447,894.24 $0.00 $25,200.00 $85,307.54 $89,578.85 $247,807.85 $49,561.57 $198,246.28 $198,246.28 $80,068.35

2024 2056.5949 $194.15 $399,287.91 $0.00 $25,200.00 $73,975.72 $79,857.58 $220,254.61 $44,050.92 $176,203.69 $176,203.69 $63,540.82

2025 2473.9196 $199.45 $493,410.89 $109,974.25 $25,200.00 $88,986.89 $98,682.18 $280,541.83 $56,108.37 $224,433.46 $114,459.21 $36,852.80

2026 2151.9756 $210.04 $451,990.18 $0.00 $25,200.00 $77,406.56 $90,398.04 $258,985.59 $51,797.12 $207,188.47 $207,188.47 $59,561.73

2027 1872.3812 $218.86 $409,789.35 $0.00 $25,200.00 $67,349.55 $81,957.87 $235,281.93 $47,056.39 $188,225.54 $188,225.54 $48,312.81

2028 1629.4846 $224.16 $365,257.13 $0.00 $25,200.00 $58,612.56 $73,051.43 $208,393.14 $41,678.63 $166,714.51 $166,714.51 $38,206.66

2029 1418.4037 $227.69 $322,949.24 $0.00 $25,200.00 $51,019.98 $64,589.85 $182,139.41 $36,427.88 $145,711.53 $145,711.53 $29,815.47

Jul, 2030 741.0549 $232.98 $172,650.97 $0.00 $25,200.00 $26,655.74 $34,530.19 $86,265.03 $17,253.01 $69,012.03 $69,012.03 $12,608.24

NPV $1,011,087.60

207

Infill Drilling, Re-perforation and Fracturing Analysis

Table 48: Year 2016- Economic Evaluation – 3 New Wells and Re-perforating and Fracturing of 1 well.

Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 6822.7624 $92.84 $633,425.26 $0.00 $25,200.00 $245,414.76 $126,685.05 $236,125.45 $47,225.09 $188,900.36 $188,900.36 $188,900.36

2016 6518.1703 $111.20 $724,787.95 $22,947,656.39 $36,000.00 $5,030,371.83 $144,957.59 -$4,486,541.48 -$897,308.30 -$3,589,233.18 -$26,536,889.57 -$23,693,651.40

2017 5563.75746 $125.32 $697,222.27 $0.00 $36,000.00 $200,128.36 $139,444.45 $321,649.46 $64,329.89 $257,319.57 $257,319.57 $205,133.58

2018 4768.6455 $134.14 $639,666.11 $0.00 $36,000.00 $171,528.18 $127,933.22 $304,204.71 $60,840.94 $243,363.77 $243,363.77 $173,221.52

2019 4090.86064 $146.50 $599,290.63 $0.00 $36,000.00 $147,148.26 $119,858.13 $296,284.25 $59,256.85 $237,027.40 $237,027.40 $150,635.20

2020 3512.34226 $157.09 $551,736.28 $0.00 $36,000.00 $126,338.95 $110,347.26 $279,050.08 $55,810.02 $223,240.06 $223,240.06 $126,672.41

2021 3077.9537 $169.44 $521,528.47 $0.00 $36,000.00 $110,713.99 $104,305.69 $270,508.79 $54,101.76 $216,407.03 $216,407.03 $109,638.54

2022 2594.99618 $176.50 $458,016.83 $0.00 $36,000.00 $93,342.01 $91,603.37 $237,071.45 $47,414.29 $189,657.16 $189,657.16 $85,791.27

2023 2232.78952 $188.86 $421,673.46 $0.00 $36,000.00 $80,313.44 $84,334.69 $221,025.33 $44,205.07 $176,820.27 $176,820.27 $71,414.74

2024 1922.323496 $194.15 $373,219.11 $0.00 $36,000.00 $69,145.98 $74,643.82 $193,429.31 $38,685.86 $154,743.45 $154,743.45 $55,802.04

2025 1655.982798 $199.45 $330,277.49 $0.00 $36,000.00 $59,565.70 $66,055.50 $168,656.29 $33,731.26 $134,925.03 $134,925.03 $43,442.25

2026 1427.3179 $210.04 $299,786.72 $0.00 $36,000.00 $51,340.62 $59,957.34 $152,488.75 $30,497.75 $121,991.00 $121,991.00 $35,069.50

2027 1230.858138 $218.86 $269,385.61 $0.00 $36,000.00 $44,273.97 $53,877.12 $135,234.52 $27,046.90 $108,187.62 $108,187.62 $27,769.07

2028 1061.953952 $224.16 $238,042.29 $0.00 $36,000.00 $38,198.48 $47,608.46 $116,235.35 $23,247.07 $92,988.28 $92,988.28 $21,310.51

2029 916.649376 $227.69 $208,707.31 $0.00 $36,000.00 $32,971.88 $41,741.46 $97,993.97 $19,598.79 $78,395.18 $78,395.18 $16,041.21

Jul, 2030 475.778458 $232.98 $110,846.87 $0.00 $36,000.00 $17,113.75 $22,169.37 $35,563.74 $7,112.75 $28,450.99 $28,450.99 $5,197.89

NPV -$22,377,611.33

208

Table 49: Year 2019- Economic Evaluation – 12 New Wells drilled since 2016 and the second re-perforating and Fracturing well.

Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 18238.4058 $92.84 $1,693,253.59 $0.00 $25,200.00 $656,035.46 $338,650.72 $673,367.42 $134,673.48 $538,693.94 $538,693.94 $538,693.94

2016 16323.2867 $111.20 $1,815,067.86 $22,947,656.39 $36,000.00 $5,383,061.87 $363,013.57 -$3,967,007.58 -$793,401.52 -$3,173,606.06 -$26,121,262.45 -$23,322,555.76

2017 13973.5981 $125.32 $1,751,101.44 $22,212,214.74 $46,800.00 $5,167,195.42 $350,220.29 -$3,813,114.26 -$762,622.85 -$3,050,491.41 -$25,262,706.15 -$20,139,274.67

2018 11993.6792 $134.14 $1,608,832.13 $21,638,869.76 $57,600.00 $4,975,575.29 $321,766.43 -$3,746,109.59 -$749,221.92 -$2,996,887.67 -$24,635,757.43 -$17,535,245.53

2019 10983.4743 $146.50 $1,609,024.06 $21,175,499.06 $68,400.00 $4,818,835.78 $321,804.81 -$3,600,016.53 -$720,003.31 -$2,880,013.22 -$24,055,512.28 -$15,287,712.94

2020 9451.02604 $157.09 $1,484,614.43 $0.00 $68,400.00 $339,953.41 $296,922.89 $779,338.13 $155,867.63 $623,470.51 $623,470.51 $353,773.91

2021 8317.3289 $169.44 $1,409,288.21 $0.00 $68,400.00 $299,174.32 $281,857.64 $759,856.25 $151,971.25 $607,885.00 $607,885.00 $307,973.46

2022 7010.23897 $176.50 $1,237,307.18 $0.00 $68,400.00 $252,158.30 $247,461.44 $669,287.45 $133,857.49 $535,429.96 $535,429.96 $242,201.32

2023 6042.52213 $188.86 $1,141,160.52 $0.00 $68,400.00 $217,349.52 $228,232.10 $627,178.89 $125,435.78 $501,743.11 $501,743.11 $202,645.63

2024 5211.05924 $194.15 $1,011,727.15 $0.00 $68,400.00 $187,441.80 $202,345.43 $553,539.92 $110,707.98 $442,831.94 $442,831.94 $159,689.64

2025 4496.1971 $199.45 $896,744.03 $0.00 $68,400.00 $161,728.21 $179,348.81 $487,267.01 $97,453.40 $389,813.61 $389,813.61 $125,509.55

2026 3881.20315 $210.04 $815,188.50 $0.00 $68,400.00 $139,606.88 $163,037.70 $444,143.93 $88,828.79 $355,315.14 $355,315.14 $102,144.61

2027 3351.81946 $218.86 $733,579.21 $0.00 $68,400.00 $120,564.95 $146,715.84 $397,898.42 $79,579.68 $318,318.74 $318,318.74 $81,704.49

2028 2895.87568 $224.16 $649,125.01 $0.00 $68,400.00 $104,164.65 $129,825.00 $346,735.36 $69,347.07 $277,388.29 $277,388.29 $63,570.24

2029 2502.97824 $227.69 $569,890.60 $0.00 $68,400.00 $90,032.13 $113,978.12 $297,480.35 $59,496.07 $237,984.28 $237,984.28 $48,696.30

Jul, 2030 1300.49525 $232.98 $302,989.38 $0.00 $68,400.00 $46,778.81 $60,597.88 $127,212.69 $25,442.54 $101,770.15 $101,770.15 $18,593.03

NPV -$74,039,592.79

209

Table 50: Year 2022- Economic Evaluation – 15 new wells drilled since 2016 and the third re-perforating and Fracturing well.

Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 20918.827 $92.84 $1,942,103.92 $0.00 $25,200.00 $752,450.21 $388,420.78 $776,032.92 $155,206.58 $620,826.34 $620,826.34 $620,826.34

2016 18571.431 $111.20 $2,065,050.28 $22,947,656.39 $36,000.00 $5,463,927.63 $413,010.06 -$3,847,887.40 -$769,577.48 -$3,078,309.92 -$26,025,966.31 -$23,237,469.92

2017 15843.579 $125.32 $1,985,438.09 $22,212,214.74 $46,800.00 $5,234,458.63 $397,087.62 -$3,692,908.15 -$738,581.63 -$2,954,326.52 -$25,166,541.26 -$20,062,612.61

2018 13557.196 $134.14 $1,818,562.26 $21,638,869.76 $57,600.00 $5,031,814.99 $363,712.45 -$3,634,565.18 -$726,913.04 -$2,907,652.14 -$24,546,521.90 -$17,471,729.44

2019 12291.518 $146.50 $1,800,645.97 $21,175,499.06 $68,400.00 $4,865,886.12 $360,129.19 -$3,493,769.35 -$698,753.87 -$2,795,015.48 -$23,970,514.53 -$15,233,695.33

2020 10545.909 $157.09 $1,656,604.13 $20,544,302.31 $79,200.00 $4,693,639.84 $331,320.83 -$3,447,556.53 -$689,511.31 -$2,758,045.22 -$23,302,347.53 -$13,222,377.79

2021 9294.2095 $169.44 $1,574,810.86 $0.00 $79,200.00 $334,312.72 $314,962.17 $846,335.97 $169,267.19 $677,068.78 $677,068.78 $343,024.11

2022 8463.8033 $176.50 $1,493,861.28 $109,974.25 $79,200.00 $304,443.00 $298,772.26 $811,446.02 $162,289.20 $649,156.81 $539,182.56 $243,898.81

2023 7286.5733 $188.86 $1,376,105.81 $0.00 $79,200.00 $262,098.04 $275,221.16 $759,586.60 $151,917.32 $607,669.28 $607,669.28 $245,427.43

2024 6276.1729 $194.15 $1,218,518.97 $0.00 $79,200.00 $225,753.94 $243,703.79 $669,861.23 $133,972.25 $535,888.99 $535,888.99 $193,246.94

2025 5408.6616 $199.45 $1,078,730.51 $0.00 $79,200.00 $194,549.56 $215,746.10 $589,234.85 $117,846.97 $471,387.88 $471,387.88 $151,774.28

2026 4663.3487 $210.04 $979,466.44 $0.00 $79,200.00 $167,740.65 $195,893.29 $536,632.50 $107,326.50 $429,306.00 $429,306.00 $123,415.22

2027 4022.6318 $218.86 $880,393.19 $0.00 $79,200.00 $144,694.06 $176,078.64 $480,420.49 $96,084.10 $384,336.39 $384,336.39 $98,649.58

2028 3471.5115 $224.16 $778,156.66 $0.00 $79,200.00 $124,870.27 $155,631.33 $418,455.06 $83,691.01 $334,764.05 $334,764.05 $76,719.28

2029 2997.1982 $227.69 $682,417.07 $0.00 $79,200.00 $107,809.22 $136,483.41 $358,924.44 $71,784.89 $287,139.55 $287,139.55 $58,754.44

Jul, 2030 1555.931 $232.98 $362,500.80 $0.00 $79,200.00 $55,966.84 $72,500.16 $154,833.80 $30,966.76 $123,867.04 $123,867.04 $22,630.05

NPV -$87,049,518.62

210

Table 51: Year 2025- Economic Evaluation – 15 new wells drilled since 2016 and the fourth re-perforating and Fracturing well.

Year

Total Cum.

Production

(E3m3)

Alberta

Reference

Average

Price -

Current

(C$/E3m3)

Gross


Variable


Taxed

RevenueCash Flow

Discounted

Cash Flow

2015 20918.8272 $92.84 $1,942,103.92 $0.00 $25,200.00 $752,450.21 $388,420.78 $776,032.92 $155,206.58 $620,826.34 $620,826.34 $620,826.34

2016 18571.4311 $111.20 $2,065,050.28 $22,947,656.39 $36,000.00 $5,463,927.63 $413,010.06 -$3,847,887.40 -$769,577.48 -$3,078,309.92 -$26,025,966.31 -$23,237,469.92

2017 15843.5789 $125.32 $1,985,438.09 $22,212,214.74 $46,800.00 $5,234,458.63 $397,087.62 -$3,692,908.15 -$738,581.63 -$2,954,326.52 -$25,166,541.26 -$20,062,612.61

2018 13557.1959 $134.14 $1,818,562.26 $21,638,869.76 $57,600.00 $5,031,814.99 $363,712.45 -$3,634,565.18 -$726,913.04 -$2,907,652.14 -$24,546,521.90 -$17,471,729.44

2019 12291.5183 $146.50 $1,800,645.97 $21,175,499.06 $68,400.00 $4,865,886.12 $360,129.19 -$3,493,769.35 -$698,753.87 -$2,795,015.48 -$23,970,514.53 -$15,233,695.33

2020 10545.9091 $157.09 $1,656,604.13 $20,544,302.31 $79,200.00 $4,693,639.84 $331,320.83 -$3,447,556.53 -$689,511.31 -$2,758,045.22 -$23,302,347.53 -$13,222,377.79

2021 9294.2095 $169.44 $1,574,810.86 $0.00 $79,200.00 $334,312.72 $314,962.17 $846,335.97 $169,267.19 $677,068.78 $677,068.78 $343,024.11

2022 8463.80326 $176.50 $1,493,861.28 $109,974.25 $79,200.00 $304,443.00 $298,772.26 $811,446.02 $162,289.20 $649,156.81 $539,182.56 $243,898.81

2023 7286.57334 $188.86 $1,376,105.81 $0.00 $79,200.00 $262,098.04 $275,221.16 $759,586.60 $151,917.32 $607,669.28 $607,669.28 $245,427.43

2024 6276.17289 $194.15 $1,218,518.97 $0.00 $79,200.00 $225,753.94 $243,703.79 $669,861.23 $133,972.25 $535,888.99 $535,888.99 $193,246.94

2025 6098.5355 $199.45 $1,216,322.41 $109,974.25 $79,200.00 $219,364.32 $243,264.48 $674,493.61 $134,898.72 $539,594.89 $429,620.64 $138,326.35

2026 5267.1884 $210.04 $1,106,293.92 $0.00 $79,200.00 $189,460.77 $221,258.78 $616,374.37 $123,274.87 $493,099.49 $493,099.49 $141,754.32

2027 4551.16668 $218.86 $996,068.34 $0.00 $79,200.00 $163,705.47 $199,213.67 $553,949.21 $110,789.84 $443,159.36 $443,159.36 $113,747.97

2028 3934.1328 $224.16 $881,855.54 $0.00 $79,200.00 $141,510.76 $176,371.11 $484,773.67 $96,954.73 $387,818.94 $387,818.94 $88,878.09

2029 3402.126 $227.69 $774,613.06 $0.00 $79,200.00 $122,374.47 $154,922.61 $418,115.97 $83,623.19 $334,492.78 $334,492.78 $68,443.85

Jul, 2030 1768.39549 $232.98 $412,000.78 $0.00 $79,200.00 $63,609.19 $82,400.16 $186,791.44 $37,358.29 $149,433.15 $149,433.15 $27,300.88

NPV -$87,003,010.00

211

Appendix N: Sensitivity Analysis

Figure 181: Spider chart for the single year infill drilling project. Only the parameters showing

major variance in the previous sensitivity analysis are shown here, in order to prevent clutter.

212

Year 2

Factor NPV High, +20% ($) NPV Low, -20% ($)

NPV ($)

Fixed Opex -43897911.63 -43790933.84 -43844422.73

Taxes -43957144.46 -43731701 -43844422.73

Royalties -44035978.49 -43652866.98 -43844422.73

Variable Opex -44106269.94 -43582575.53 -43844422.73

Production -43340046.91 -44348798.55 -43844422.73

Gas Price -43207864.49 -44480980.98 -43844422.73


Capex -51464068.58 -36224776.89 -43844422.73 Table 52: Sensitivity analysis on the parameters for a two year infill drilling project.

Figure 182: Tornado Chart for the two year infill drilling project.

213

Year 3

Factor NPV High, +20% ($) NPV Low, -20% ($) NPV ($)

Fixed Opex -61898672.04 -61773996.71 -61836334.37

Taxes -61981288.79 -61691379.96 -61836334.37

Royalties -62080174.97 -61592493.77 -61836334.37

Variable Opex -62169541.45 -61503127.29 -61836334.37

Production -61194179.06 -62478489.69 -61836334.37

Gas Price -61025803.98 -62646864.77 -61836334.37


Capex -72536404.23 -51136264.51 -61836334.37

Table 53: Sensitivity analysis on the parameters for a three year infill drilling project.

Figure 183: Tornado Chart for the three year infill drilling project.

-73000000 -68000000 -63000000 -58000000 -53000000

Fixed Opex

Taxes

Royalties

Variable Opex

Production

Gas Price

Var field expenses

Capex

Tornado Chart Infill drilling: 3 years

214

Year 4

Factor NPV High, +20% ($) NPV Low, -20% ($)

NPV ($)

Fixed Opex -77155364.06 -77015451.12 -77085407.59

Taxes -77296940.87 -76873874.31 -77085407.59

Royalties -77409676.22 -76761138.96 -77085407.59

Variable Opex -77415176.59 -76755638.59 -77085407.59

Production -76245667.82 -77925147.36 -77085407.59

Gas Price -76020337.63 -78150477.55 -77085407.59

Var field expenses -79894698.18 -74276117 -77085407.59

Capex -90462981.82 -63707833.36 -77085407.59

Table 54: Sensitivity analysis on the parameters for a four year infill drilling project.

Figure 184: Tornado Chart for the four year infill drilling project

215

Year 5

Factor NPV High (+20%) NPV Low (-20%)

NPV

Fixed Opex -90656457.11 -90503502.89 -90579980

Taxes -90737148.94 -90422811.06 -90579980

Royalties -90947719.78 -90212240.21 -90579980

Variable Opex -91082505.11 -90077454.88 -90579980

Production -89611545.97 -91548414.03 -90579980

Gas Price -89357608.29 -91802351.7 -90579980

Var field expenses -93878880.92 -87281079.08 -90579980

Capex -106289032 -74870928 -90579980

Table 55: Sensitivity analysis on the parameters for a five year infill drilling project.

Figure 185: Tornado Chart for the five year infill drilling project

216

Appendix O: Gantt Chart

Figure 186: Gantt chart showing the work done by each team member this semester

enpe 511 final report

Documents