1. 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

2. 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.

3. 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.

4. 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

5. 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

6. 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

7. 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

8. 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
Figure 23: Pore throat aperture for all available cores in the township. This relationship uses
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

9. 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

10. 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
Figure 69: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
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
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……………………………………………………………………………..…107
Figure 72: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the NIikanassin Formation. This figure shows the logs made for well 00-13-30-65-
08W6……………………………………………………………………………..…108
Figure 73: Well Log for Well 00-08-22-65-08W6 obtained from
Accumap……………………………………………………………...……..………109
Figure 74: 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 00-08-22-65-
08W6……………………………………………………………………...……..….110

11. Figure 75: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-08-22-65-
08W6……………………………………………………………………………….111
Figure 76: Well Log for Well 00-07-12-65-08W6 obtained from
Accumap…………………………………………………………….……..………112
Figure 77: 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 00-07-12-65-
08W6……………………………………………………………………..…...……113
Figure 78: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-07-12-65-
08W6………………………………………………………………………..…...…114
Figure 79: Well Log for Well 00-07-26-65-08W6 obtained from
Accumap……………………………………………………………..…..…………115
Figure 80: 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 00-07-26-65-
08W6…………………………………………………………………..……..…….116
Figure 81: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-07-26-65-
08W6………………………………………………………………...……..………117
Figure 82: Well Log for Well 00-12-32-65-08W6 obtained from
Accumap……………………………………………………………..…………….118
Figure 83: 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 00-12-32-65-
08W6…………………………………………………………………..…………..119
Figure 84: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-12-32-65-
08W6…………………………………………………………………..….……….120
Figure 85: Well Log for Well 00-03-07-65-08W6 obtained from Accumap. ….…121
Figure 86: 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 00-03-07-65-
08W6…………………………………………………………..…………………..122
Figure 87: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-03-07-65-
08W6……………………………………………………………..…………..……123
Figure 88: Well Log for Well 00-11-09-65-08W6 obtained from
Accumap………………………………………………………..………………….124
Figure 89: 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 00-11-09-65-
08W6………………………………………………………..………………….….125

12. Figure 90: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-11-09-65-
08W6………………………………………………………………………..…….126
Figure 91: Well Log for Well 00-14-11-65-08W6 obtained from
Accumap…………………………………………………..………………………127
Figure 92: 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 00-14-11-65-
08W6………………………………………………………………………….…..128
Figure 93: Porosity, Water Saturation and Permeability Logs that were Built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-14-11-65-
08W6…………………………………………………………………………..…129
Figure 94: Well Log for Well 00-09-34-65-08W6 obtained from
Accumap……………………………………………………...…………………..130
Figure 95: 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 00-14-11-65-
08W6……………………………………………………………………………..131
Figure 96: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-09-34-65-
08W6……………………………………………………………………..………132
Figure 97: Well Log for Well 00-05-06-65-08W6 obtained from Accumap
……………………………………………………………………………………133
Figure 98: 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 00-05-06-65-
08W6……………………………………………………………………….…….134
Figure 99: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-05-06-65-
08W6……………………………………………………………………………..135
Figure 100: Well Log for Well 00-15-13-65-08W6 obtained from
Accumap……………………………………………………………...………….136
Figure 101: 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 00-15-13-65-
08W6…………………………………………………………………………….137
Figure 102: Porosity, Water Saturation and Permeability Logs that were built by analyzing the
logs for the Nikanassin Formation. This figure shows the logs made for well 00-15-13-65-
08W6……………………………………………………………………………138

13. 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
Figure 105: Modified Pickett Plot for well 00/03-07-065-08W6. Note that this well follows the
first distinctive trend, with m=2.2341, and
a=0.5426………………………………………………………………………140
Figure 106: Modified Pickett Plot for well 00/05-06-065-08W6. Note that this well follows the
first distinctive trend, with m=2.2305, and
a=0.5493……………………………………………………………………....140
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……………………………..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
Figure 109: Modified Pickett Plot for well 00/08-22-065-08W6. Note that this well follows the
first distinctive trend, with m=2.2478, and a=0.5352……..…………………142
Figure 110: Modified Pickett Plot for well 00/09-34-065-08W6. Note that this well follows the
first distinctive trend, with m=2.2632, and a=0.5352……..…………………142
Figure 111: Modified Pickett Plot for well 00/13-30-065-08W6. Note that this well follows the
first distinctive trend, with m=2.2552, and
a=0.5211…………………………………………….………………………..143
Figure 112: Modified Pickett Plot for well 00/14-11-065-08W6. Note that this well follows the
first distinctive trend, with m=2.2382, and
a=0.5070…………………………………………….………………………..143
Figure 113: Modified Pickett Plot for well 00/12-32-065-08W6. Note that this well follows the
second distinctive trend, with m=1.9294, and
a=0.5141………………………………….…………………………………..144
Figure 114: Modified Pickett Plot for well 00/15-13-065-08W6. Note that this well follows the
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

14. 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
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…………………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
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…………………………………………………………………………….152
Figure 122: Correlation between log and core porosity values at the same depth interval for well
00/10-29-065-08W6. …………………………………………………….……153
Figure 123: Correlation between log and core porosity values at the same depth interval for well
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
Figure 126: Pore throat aperture for well 00/06-02-065-08/W6. 90o
Horizontal permeability is
measured against porosity……………………………………………..………155
Figure 127: Pore throat aperture for well 00/06-02-065-08/W6. Max Horizontal permeability is
measured against porosity……………………………………………..………155
Figure 128: Pore throat aperture for well 00/05-06-065-08/W6. 90o
Horizontal permeability is
measured against porosity.
…………………………………………………………………………………156
Figure 129: Pore throat aperture for well 00/05-06-065-08/W6. Vertical permeability is measured
against porosity……………………………………………………..…………156
Figure 130: Pore throat aperture for well 00/12-32-065-08/W6. Max Horizontal permeability is
measured against porosity……………………..………………………………157
Figure 131: Pore throat aperture for well 00/05-06-065-08/W6. 90o
Horizontal permeability is
measured against porosity………………………………………..……………157

15. Figure 132: Pore throat aperture for well 00/12-32-065-08/W6. Vertical permeability is measured
against porosity………………..………………………………………………..158
Figure 133: Pore throat aperture for well 00/10-19-065-08/W6. Max Horizontal permeability is
measured against
porosity…………………………………………………………………………158
Figure 134: Pore throat aperture for well 00/10-19-065-08/W6. 90o
Horizontal permeability is
measured against
porosity…………………………………………………………………………159
Figure 135: Pore throat aperture for well 00/10-19-065-08/W6. Vertical permeability is measured
against porosity…………………………………………………………………159
Figure 136: Pore throat aperture for well 00/11-09-065-08/W6. Max Horizontal permeability is
measured against porosity………………………………………………………160
Figure 137: Pore throat aperture for well 00/07-21-065-08/W6. Max Horizontal permeability is
measured against porosity.………………………………………………………160
Figure 138: Cadomin Formation – Mercury-air 𝑃𝑐 Vs 𝑆 𝑊. ……….….…………163
Figure 139: Nikanassin Formation – Mercury-air 𝑃𝑐 Vs 𝑆 𝑊. ……………………163
Figure 140: Mercury-air 𝑃𝑐 Vs 𝑆 𝑊 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

16. 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
Figure 164: Type well 2 cumulative production history then extrapolated by exponential decline
method…………………………………………………………………………..………187
Figure 165: Type well 3 cumulative production history then extrapolated by exponential decline
method……………………………………………………………………..……………188
Figure 166: Type well 4 cumulative production history then extrapolated by exponential decline
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
Figure 169: Determination of the exponential decline equation constants for well 15-13-
065……………………………………………………………………………..………..189
Figure 170: Determination of the exponential decline equation constants for well 14-11-
065…………………………………………………………………………..…………..190
Figure 171: Determination of the exponential decline equation constants for well 13-30-
065………………………………………………………………………..……………..190

17. Figure 172: Determination of the exponential decline equation constants for well 12-32-
065………………………………………………………………………..…………..190
Figure 173: Determination of the exponential decline equation constants for well 09-34-
065…………………………………………………………………..………………..191
Figure 174: Determination of the exponential decline equation constants for well 08-22-
065……………………………………………………………………..……………..191
Figure 175: Determination of the exponential decline equation constants for Type well
1……………………………………………………………………………..………..191
Figure 176: Determination of the exponential decline equation constants for Type well
2………………………………………………………………………..……………..192
Figure 177: Determination of the exponential decline equation constants for Type well
3……………………………………………………………………..………………..192
Figure 178: Determination of the exponential decline equation constants for Type well
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

18. 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

19. 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

20. 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 41: Year 3 Economic Evaluation – 3 New Drills 2018. ………………………..200
Table 42: Year 4 Economic Evaluation – 3 New Drills 2019. ………………………..201
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

21. 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

22. 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.

23. 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.

24. 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.

25. 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

26. 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.

27. 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

28. 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.

29. 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 25o
C
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, 91o
C,
using the equation:
𝑅 𝑇2 = 𝑅 𝑇2 (
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

30. 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
+ ∅ 𝑁
2
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:

31. 11
𝑆 𝑤
2
=
𝑎(1 − 𝑉𝑙𝑎𝑚)𝑅 𝑤
∅ 𝑒
′ 𝑚 (
1
𝑅𝑡
−
𝑉𝑙𝑎𝑚
𝑅 𝑠ℎ
)
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(𝑎𝑅 𝑤) + log(𝑆 𝑤)−2
𝐴𝑙𝑎𝑚 =
(𝑅 𝑠ℎ − 𝑅𝑡 𝑉𝑙𝑎𝑚)(1 − 𝑉𝑙𝑎𝑚)
𝑅 𝑠ℎ
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

32. 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.

33. 13
3.7: Log property averaging
Porosity and water saturation have been arithmetically averaged for the Cadomin and Nikanassin
∅ 𝑒
′
𝑎𝑣𝑔
=
(∑ ∅ 𝑒𝑖
′
ℎ𝑖)𝑛
𝑖=1
∑ ℎ𝑖
𝑛
𝑖=1
𝑆 𝑤𝑖 =
∑ 𝑆 𝑤𝑗ℎ𝑗
𝑛
𝑗=1
∑ ℎ𝑗
𝑛
𝑗=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.

34. 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

35. 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

36. 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

37. 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.

38. 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.

39. 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.

40. 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.

41. 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.

42. 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.