enpe 511 final report
TRANSCRIPT
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 Basinβs 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 β 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 β 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)β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦.β¦.β¦β¦β¦.1
Figure 2: Map of the Western Canada Sedimentary Basin β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦.β¦β¦2
Figure 3: Existing Facilities and Pipelines Within Township 65-08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦....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 Foothillsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.....................6
Figure 5: Modified Pickett Plot for all wells. They follow the first distinctive trend, with
m=2.2422, and a=0.5282β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦.β¦11
Figure 6: Modified Pickett Plot for all wells following the second distinctive trend, with
m=1.9455, and a=0.5282β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦β¦.12
Figure 7: Locations of the wells in each Pickett trendβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦12
Figure 8: Full core intervals for box 1 and 2 respectively. Core samples originate from well
00/12-32-065-08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..16
Figure 9: Grain size distribution in the first core boxβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦β¦17
Figure 10: Analysis of a core piece for well 00/12-32-065-08W6. Potential fracture zones are
markedβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦....18
Figure 11: Core sections from well 00/11-09-068-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦.β¦β¦β¦β¦β¦β¦β¦19
Figure 12: Log data of the cored interval shows a gamma ray spike and increasing neutron
porosityβ¦20
Figure 13: Core cross section and core face samples within the region of well 00/11-09-065-
08W6 show significant horizontal
fracturingβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦..20
Figure 14: A water beading test was performed on a core section from well 00/11-09-065-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦21
Figure 15: Different gamma ray responses in the cored interval determined the analyzed
regionsβ¦21
Figure 16: Core sections from well 00/11-09-068-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦22
Figure 17: A water beading test was performed on sections at the top of the core from well
00/10-29-065-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦.23
Figure 18: Analysis of a broken core section showed the presence of parallel
laminationsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦23
Figure 19: Core sections from well 00/11-09-068-08W6. The twelfth (pictured left) and
thirteenth (pictured right) core boxes are
shownβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦β¦β¦β¦24
Figure 20: A section of the core from box 13 of well 00/10-29-065-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦..25
Figure 21: Pore throat aperture for all available cores in the township. This relationship uses
maximum horizontal permeabilityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦..27
Figure 22: Pore throat aperture for all available cores in the township. This relationship uses 90β°
horizontal permeabilityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦27
Figure 23: Pore throat aperture for all available cores in the township. This relationship uses
vertical permeabilityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦28
Figure 24: Plot of Material Balance equation of P/Z versus cumulative
productionβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦34
Figure 25: Well 12-32-065 has 3 distinct slopes indicating the change in flow type as time
increaseβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.....β¦..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
2005β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦..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
flowβ¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦38
Figure 2: Well 15-13-065: has slope = -0.5 until the 32nd month (August 2003) then BDF
flowedβ¦β¦β¦β¦...β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..38
Figure 29: Shows estimated natural fractured zones in well 14-11-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦39
Figure 3: Well 09-34-065 shows a long period of formation damage until it reaches BDF at 28th
month ..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦ β¦β¦β¦β¦β¦β¦β¦β¦β¦41
Figure 31: Well 07-21-065 shows transitional behavior from linear flow to
BDFβ¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦..42
Figure 4: Well 13-30-065 shows transitional flow behavior therefore the flow is approaching
BDFβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.42
Figure 5: Determination of exponential decline equation constants for Well 14-11-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦.44
Figure 6: Illustration of production forecast and production history for well 14-11-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦.44
Figure 7: Determination of exponential decline equation constants for Well 12-32-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦β¦β¦β¦β¦β¦..44
Figure 8: Illustration of production forecast and production history for well 12-32-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦β¦β¦β¦.β¦.45
Figure 9: Illustration of pool production forecast and production historyβ¦β¦....β¦.β¦.46
Figure 10: Crossplot shows the flow types for the poolβ¦β¦β¦β¦β¦β¦...β¦.β¦β¦..β¦.β¦.46
Figure 11: The recoverable gas reserves in our pool by production history and extrapolated by
exponential decline method β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦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 historyβ¦β¦...49
Figure 14: Illustration of type well 2 production forecast and production history...β¦β¦49
15: Illustration of type well 3 production forecast and production historyβ¦β¦β¦β¦β¦...50
Figure 16: Illustration of type well 4 production forecast and production historyβ¦β¦β¦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
wellsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦.β¦β¦.β¦β¦.β¦β¦.β¦β¦β¦β¦β¦..β¦β¦β¦51
Figure 46: Plot of Flowing Material Balance equation of wellhead pressure versus cumulative
production........................................................................................................ β¦..............52
Figure 47: Comparison between vertical and horizontal
wellsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦.β¦β¦.β¦β¦.β¦β¦.β¦β¦.β¦β¦.β¦β¦.β¦β¦β¦β¦β¦β¦54
Figure 48: The four main horizontal drilling configurationsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..56
Figure 49: Comparison of drilling and completion costs for vertical and horizontal wells
.β¦ β¦.β¦β¦.β¦β¦.β¦β¦.β¦β¦β¦.β¦β¦.β¦β¦.β¦β¦.β¦β¦β¦.β¦β¦.β¦β¦.β¦β¦β¦.β¦β¦β¦.β¦.57
Figure 50: Schematic of a hydraulic fracture. Note that the fracture opens up parallel to the
minimum stressβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦58
Figure 51: Results of the Multistage fracture test performed within the Western Canada
Sedimentary Basinβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.59
Figure 52: Relationship between formation permeability and number of fracture stages for a tight
gas reservoirβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..60
Figure 53: Cumulative production of a reservoir over increasing fracture half
lengthsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦..60
Figure 54: Comparison between fracture half length and cumulative production....β¦β¦.61
Figure 55: Proppant concentration per unit of volume (in lbm/gal) for the stages.β¦.β¦..62
Figure 56: Common dry gas facility diagram (Gas Battery Diagram)β¦β¦β¦β¦..β¦.β¦β¦63
Figure 57: Stress Map of the Western Canada Sedimentary basinβ¦β¦β¦β¦β¦β¦β¦β¦β¦64
Figure 58: The learning curve associated with a horizontal drilling
jobβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦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.. β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦87
Figure 60: Spider chart extrapolation showing the capital expense required for the project to
break evenβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦..β¦88
Figure 61: Map showing the location of the designated
townshipβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..95
Figure 62: Regional Boundaries of the Deep Basin, located within the Western Canada
Sedimentaryβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦96
Figure 63: Map of township 65-08W6. The wells selected for analysis are marked in
redβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦.97
Figure 64: Well cards for the 12 selected wells in the townshipβ¦β¦β¦..β¦β¦β¦β¦β¦..98
Figure 65: Wellbore Schematic 00/14-11-065-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.100
Figure 66: Sample log from well 00/09-34-065-08W6. This well does not penetrate the entire
Nikanassin formationβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦β¦β¦β¦β¦.102
Figure 67: Well Log for Well 00-07-21-65-08W6 obtained from
Accumapβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦.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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦β¦.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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...105
Figure 70: Well Log for Well 00-13-30-65-08W6 obtained from Accumapβ¦β¦.....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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦108
Figure 73: Well Log for Well 00-08-22-65-08W6 obtained from
Accumapβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦..β¦β¦β¦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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦..β¦.110
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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.111
Figure 76: Well Log for Well 00-07-12-65-08W6 obtained from
Accumapβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦..β¦β¦β¦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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦...β¦β¦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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦...β¦114
Figure 79: Well Log for Well 00-07-26-65-08W6 obtained from
Accumapβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦..β¦β¦β¦β¦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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦..β¦β¦.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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦..β¦β¦β¦117
Figure 82: Well Log for Well 00-12-32-65-08W6 obtained from
Accumapβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦.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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦..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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦.β¦β¦β¦.120
Figure 85: Well Log for Well 00-03-07-65-08W6 obtained from Accumap. β¦.β¦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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦..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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦..β¦β¦123
Figure 88: Well Log for Well 00-11-09-65-08W6 obtained from
Accumapβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦.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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦.β¦.125
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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦.126
Figure 91: Well Log for Well 00-14-11-65-08W6 obtained from
Accumapβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦β¦β¦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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦..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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦129
Figure 94: Well Log for Well 00-09-34-65-08W6 obtained from
Accumapβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦β¦β¦β¦..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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦132
Figure 97: Well Log for Well 00-05-06-65-08W6 obtained from Accumap
β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦.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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..135
Figure 100: Well Log for Well 00-15-13-65-08W6 obtained from
Accumapβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦.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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.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-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦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=0.5141β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦..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=0.5423β¦β¦β¦β¦β¦β¦.β¦β¦..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=0.5426β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦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=0.5493β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦....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=0.5141β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..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=0.5070β¦β¦β¦..β¦β¦β¦β¦β¦β¦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=0.5352β¦β¦..β¦β¦β¦β¦β¦β¦β¦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=0.5352β¦β¦..β¦β¦β¦β¦β¦β¦β¦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=0.5211β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦β¦β¦β¦β¦β¦β¦β¦..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=0.5070β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦β¦β¦β¦β¦β¦β¦β¦..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=0.5141β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..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=0.5423β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦β¦β¦β¦β¦β¦β¦β¦..144
Figure 115: Log-Core correlation for the analyzed interval of well 00/12-32-065-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.148
Figure 116: Log-Core correlation for the analyzed interval of well 00/11-09-065-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.149
Figure 117: Log-Core correlation for the two analyzed intervals of well 00/10-29-065-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.150
Figure 118: Relationship between the core and log porosity data for well 00/07-21-065-08W6,
before the depth correction was
performedβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.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 2.2mβ¦β¦β¦β¦β¦β¦β¦151
Figure 120: Correlation between log and core porosity values at the same depth interval for well
00/07-21-065-08W6. This well
featuredβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦..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
wellβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.152
Figure 122: Correlation between log and core porosity values at the same depth interval for well
00/10-29-065-08W6. β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦153
Figure 123: Correlation between log and core porosity values at the same depth interval for well
00/11-09-065-08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦β¦153
Figure 124: Pore throat aperture for well 00/06-02-065-08/W6. Max Horizontal permeability is
measured against porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦154
Figure 125: Pore throat aperture for well 00/06-02-065-08/W6. 90o Horizontal permeability is
measured against porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦154
Figure 126: Pore throat aperture for well 00/06-02-065-08/W6. 90o Horizontal permeability is
measured against porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦155
Figure 127: Pore throat aperture for well 00/06-02-065-08/W6. Max Horizontal permeability is
measured against porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦155
Figure 128: Pore throat aperture for well 00/05-06-065-08/W6. 90o Horizontal permeability is
measured against porosity.
β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦156
Figure 129: Pore throat aperture for well 00/05-06-065-08/W6. Vertical permeability is measured
against porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦156
Figure 130: Pore throat aperture for well 00/12-32-065-08/W6. Max Horizontal permeability is
measured against porosityβ¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦157
Figure 131: Pore throat aperture for well 00/05-06-065-08/W6. 90o Horizontal permeability is
measured against porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦157
Figure 132: Pore throat aperture for well 00/12-32-065-08/W6. Vertical permeability is measured
against porosityβ¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..158
Figure 133: Pore throat aperture for well 00/10-19-065-08/W6. Max Horizontal permeability is
measured against
porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦158
Figure 134: Pore throat aperture for well 00/10-19-065-08/W6. 90o Horizontal permeability is
measured against
porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦159
Figure 135: Pore throat aperture for well 00/10-19-065-08/W6. Vertical permeability is measured
against porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦159
Figure 136: Pore throat aperture for well 00/11-09-065-08/W6. Max Horizontal permeability is
measured against porosityβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦160
Figure 137: Pore throat aperture for well 00/07-21-065-08/W6. Max Horizontal permeability is
measured against porosity.β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦160
Figure 138: Cadomin Formation β Mercury-air ππ Vs ππ. β¦β¦β¦.β¦.β¦β¦β¦β¦163
Figure 139: Nikanassin Formation β Mercury-air ππ Vs ππ. β¦β¦β¦β¦β¦β¦β¦β¦163
Figure 140: Mercury-air ππ Vs ππ Using Average Propertiesβ¦β¦β¦β¦β¦β¦β¦β¦164
Figure 141: Gas Compressibility Factor and Formation Factor Averages for both Cadomin and
Nikanassin Formations. .β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦. β¦β¦β¦167
Figure 142: Gas Density and Viscosity Averages for both Cadomin and Nikanassin
Formationsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.167
Figure 143: Contour map presenting the tops of the Cadomin formationβ¦β¦β¦β¦.169
Figure 144: Contour map presenting the tops of the Nikanassin formationβ¦β¦β¦..170
Figure 145: Contour map presenting the gross thickness of the Cadomin
formationβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦.171
Figure 146: Contour map presenting the gross thickness of the Nikanassin
formationβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦..172
Figure 147:Cadomin SgΠ€hnet contour map. This is used in volumetric calculations for Original
Gas in Placeβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦173
Figure 148: Nikanassin SgΠ€hnet contour map. This is used in volumetric calculations for Original
Gas in Place β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦174
Figure 149: Map of the township showing the cross sectional cuts made through the formation. .
β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦175
Figure 150: North-south cross section through the townshipβ¦β¦β¦β¦.β¦β¦β¦β¦β¦..176
Figure 151: East-West Cross section through the township β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦177
Figure 152: Diagonal Cross Section of the township. This cut follows a southwest-northeast
trend, parallel to the trust beltβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦178
Figure 153: Cadomin Formation Bubble Map showing Cumulative Gas
Productionβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦..179
Figure 154: Nikanassin Formation Bubble Map showing Cumulative Gas
Productionβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦....179
Figure 155: Shows apparent natural fractured zones in Well 07-21-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦182
Figure 156: Shows apparent natural fractured zones in Well 09-34-065β¦β¦β¦β¦β¦.183
Figure 157: Shows apparent natural fractured zones in Well 13-30-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.184
Figure 158: Shows cumulative gas production for individual wellsβ¦β¦β¦.β¦β¦β¦β¦185
Figure 159: Shows forecast cumulative gas production for individual wellsβ¦β¦β¦β¦.185
Figure 160: Shows monthly gas production for individual wellsβ¦β¦β¦β¦β¦.β¦β¦β¦.186
Figure 161: Pool cumulative production history compared to forecast cumulative gas
productionβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦186
Figure 162: Pool monthly gas production then extrapolated by exponential decline method over
15 yearsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦187
Figure 163: Type well 1 cumulative production history then extrapolated by exponential decline
methodβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦187
Figure 164: Type well 2 cumulative production history then extrapolated by exponential decline
methodβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦187
Figure 165: Type well 3 cumulative production history then extrapolated by exponential decline
methodβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦188
Figure 166: Type well 4 cumulative production history then extrapolated by exponential decline
methodβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦188
Figure 167: Determination of exponential decline equation constants for the pool
β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..189
Figure 168: Determination of the exponential decline equation constants for well 07-21-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦..189
Figure 169: Determination of the exponential decline equation constants for well 15-13-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦..189
Figure 170: Determination of the exponential decline equation constants for well 14-11-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦..190
Figure 171: Determination of the exponential decline equation constants for well 13-30-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦..190
Figure 172: Determination of the exponential decline equation constants for well 12-32-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦..190
Figure 173: Determination of the exponential decline equation constants for well 09-34-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦..191
Figure 174: Determination of the exponential decline equation constants for well 08-22-
065β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦..191
Figure 175: Determination of the exponential decline equation constants for Type well
1β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦..191
Figure 176: Determination of the exponential decline equation constants for Type well
2β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦..192
Figure 177: Determination of the exponential decline equation constants for Type well
3β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦..192
Figure 178: Determination of the exponential decline equation constants for Type well
4β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦..192
Figure 179:Perforation data for wells within township 065-08W6 β¦β¦β¦.β¦β¦β¦β¦194
Figure 180:Schematic of horizontal drilling techniques. The process shown in this diagram
corresponds to short radius drillingβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦..195
Figure 181: Spider chart for the single year infill drilling projectβ¦β¦β¦β¦.β¦β¦β¦..211
Figure 182: Tornado Chart for the two year infill drilling projectβ¦β¦β¦β¦β¦..β¦β¦212
Figure 183: Tornado Chart for the three year infill drilling projectβ¦β¦β¦β¦β¦β¦β¦213
Figure 184: Tornado Chart for the four year infill drilling project β¦β¦β¦β¦β¦..β¦..214
Figure 185: Tornado Chart for the five year infill drilling projectβ¦β¦β¦β¦β¦β¦..β¦215
Figure 186: Gantt chart showing the work done by each team member this
semesterβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦216
List of tables:
Table 1: Results of the Volumetrics OGIP calculations based on the thickness maps for
formations of interestβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.33
Table 2: Summarizes radius of drainage for individual wells. Well 14-11-065 have no significant
BDF within a period of 15
yearsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.48
Table 3: Summarizes radius of drainage for type wells and the pool
β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦.48
Table 4: Drilling costs for an infill well. Costs are analyzed on a vertical
basisβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦.70
Table 5: Factor cost increase used to estimate horizontal well expenses from vertical well
dataβ¦..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦.71
Table 6: Cost of Horizontal drill jobs, per well, over each year of the project..β¦.β¦..72
Table 7: Completion costs for an infill drilled well in township 065-08W6β¦β¦β¦β¦76
Table 8: Total capital expense for the infill drilling projectβ¦β¦β¦..β¦β¦β¦β¦..β¦β¦..80
Table 9: Total capital expenses for the reperforation and fracturing project, per stage
performedβ¦β¦.β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦......82
Table 10: Capital Cost and Operating Cost per 3 wells for the Infill Drilling
Analysisβ¦β¦β¦.β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦..84
Table 11: Capital and operating costs for the reperforation and fracturing project, per stage
performed for a single well β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦85
Table 12: Allowable tolerance on each economic variable before the Base Case becomes the
more effective
methodβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦β¦β¦..β¦β¦85
Table 13: Sensitivity analysis on the parameters for a single year infill drilling
projectβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦.β¦β¦..86
Table 14: Net Present Worth of each infill drilling project with Abandonment
consideredβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..89
Table 15: Table 15: List and definition of symbols used in this
reportβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..95
Table 16: Production history within the township of
interestβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦.100
Table 17: Drillstem test results from available
wellsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦...β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..100
Table 18: Sample chart containing log readings and calculations for the Cadomin section of well
00/09-34-065-
08W6β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦...102
Table 19: Average Porosity and Water Saturation within each well, for each
formationβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦.147
Table 20: Gross Pay, net Pay and Net/Gross Ratio within each well, within the Cadomin.
β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦147
Table 21: Gross Pay, net Pay and Net/Gross Ratio within each well, within the Nikanassinβ¦..
β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..148
Table 22: Important reservoir properties for the geostatistically interpolated
wellsβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦....148
Table 23: Pay intervals for the geostatistically interpolated wellsβ¦β¦β¦β¦β¦β¦β¦...149
Table 24: Permeability averages for the geostatistically interpolated wells. β¦β¦..β¦.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..β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..161
Table 26: Average maximum horizontal permeability for each well, in each
formationβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.161
Table 27: Average 90o horizontal permeability for each well, in each
formationβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.162
Table 28: Average vertical permeability for each well, in each
formationβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦162
Table 29: Empirical Values of A and B in Capillary
Pressureβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦....β¦164
Table 30: Well 00-11-09-065-08W6 Gas
Analysisβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦..β¦165
Table 31: Calculated gas compressibility factors and gas formation factors for Cadomin and
Nikanassin formations along with the averages.
β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦.β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦166
Table 32: Calculated gas density and gas viscosity for Cadomin and Nikanassin formations along
with the averages. β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦..β¦β¦β¦..β¦167
Table 33: Results of the 2 methods used to calculate the OGIPβ¦..β¦β¦β¦β¦β¦β¦..180
Table 34: P/Z and cumulative production values for the wells that produced from Cadomin and
Nikanassin Formations in our townshipβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.180
Table 35: Production history for wells producing from the Cadomin and
Nikanassinβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..181
Table 36 : Wellhead pressures and cumulative production values for the wells that produced
from Cadomin and Nikanassin Formations in our
townshipβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.193
Table 37: Gas Price Forecast by Deloitte. β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.β¦β¦β¦β¦β¦...196
Table 38: Base Case Economic Evaluation. β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦...197
Table 39: Year 1 Economic Evaluation β 3 New Drills 2016. β¦β¦β¦β¦β¦β¦β¦β¦β¦..198
Table 40: Year 2 Economic Evaluation β 3 New Drills 2017β¦β¦β¦β¦β¦β¦β¦β¦..β¦..199
Table 41: Year 3 Economic Evaluation β 3 New Drills 2018. β¦β¦β¦β¦β¦β¦β¦β¦β¦..200
Table 42: Year 4 Economic Evaluation β 3 New Drills 2019. β¦β¦β¦β¦β¦β¦β¦β¦β¦..201
Table 43: Year 5 Economic Evaluation β 3 New Drills 202β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..202
Table 44: Year 2016 Economic Evaluation β Re-perforating and Fracturing. β¦β¦β¦..203
Table 45: Year 2019 Economic Evaluation β Re-perforating and Fracturing. β¦β¦β¦..204
Table 46: Year 2022 Economic Evaluation β Re-perforating and Fracturingβ¦β¦β¦....205
Table 47: Year 2025 Economic Evaluation β Re-perforating and Fracturingβ¦β¦..β¦..206
Table 48: Year 2016- Economic Evaluation β 3 New Wells and Re-perforating and Fracturing of
1 well. β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦β¦β¦β¦..207
Table 49: Year 2019- Economic Evaluation β 12 New Wells drilled since 2016 and the second
re-perforating and Fracturing well. β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..208
Table 50: Year 2022- Economic Evaluation β 15 new wells drilled since 2016 and the third re-
perforating and Fracturing wellβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..209
Table 51: Year 2025- Economic Evaluation β 15 new wells drilled since 2016 and the fourth re-
perforating and Fracturing wellβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..210
Table 52: Sensitivity analysis on the parameters for a two year infill drilling
projectβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦..212
Table 53: Sensitivity analysis on the parameters for a three year infill drilling
projectβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦213
Table 54: Sensitivity analysis on the parameters for a four year infill drilling
projectβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦..β¦β¦..214
Table 55: Sensitivity analysis on the parameters for a five year infill drilling
projectβ¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦β¦.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 βregionally extensive pools of gas or hydrocarbonsβ, which βfeature no
obvious seal or trapβ, 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 βwater blockβ (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 βan extensive area of hydrocarbon saturated, abnormally
pressured, thermally mature clastic rocks, with minor associated carbonate sequences.β (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 βthick wedge of non-
marine strata located within the Alberta Foothillsβ (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 β 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 β 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:
π π2 = π π2 (π1 + 21.5
π2 + 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:
ππ βπ =(πΊπ )πππβ(πΊπ )πππππ
(πΊπ )π βπππβ(πΊπ )πππππ ππ β = 1.7 β [3.38 β (ππ βπ + 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:
β π = ββ π·
2 + β π2
2
This formula is specific to gas saturated porous space. Effective porosityβs are then corrected
based on the shale content of the depth increment:
β πβ² = β π(1 β ππ β)
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
ππ€2 =
π(1 β ππππ)π π€
β πβ²π (
1
π π‘β
ππππ
π π β)
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 (π π‘
π΄πππ) = βππππ(β π
β²) + log(ππ π€) + log (ππ€)β2
π΄πππ =(π π β β π π‘ππππ)(1 β ππππ)
π π β
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 βaβ 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 lithologyβs 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
β πβ²ππ£π
=(β β ππ
β²βπ)ππ=1
β βπππ=1
ππ€π =β ππ€πβπ
ππ=1
β βπππ=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 Π€eβ=4.94% and Sw= 48.47%. The
Nikanassin presents averages of Π€eβ= 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 β 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 β 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 β 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 β 1.325m of core
Core 2: 00/11-09-065-08W6 β 1.250m of core
Core 2: 00/10-29-065-08W6 β 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:
ππ35 = 2.665(π
100β πβ²)
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,
permeabilityβs 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
.
Figure 21: Pore throat aperture for all available cores in the township. This relationship uses
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 90β°
horizontal permeability. Most pore throats are Mesopores or Macropores
29
Figure 23: Pore throat aperture for all available cores in the township. This relationship uses
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)
ππππ₯ = (250β πβ²3
ππ€β )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:
πΎππ£π ππππ‘βπππ‘ππ =β πΎπβπ
β βπ πΎππ£π βπππππππ =
β βπ
β(βππΎπ
) πΎππ£π ππππππ‘πππ = ββ πΎπ
βππ
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):
ππ = π΄[π
(100β )]βπ΅
Where ππ is the mercury-air capillary pressure, k is formation permeability, β is porosity, A is a
function of ππ€ 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 SgΠ€hnet 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 SgΠ€hnet value reaches a maximum around the center of the township.
Values for the SgΠ€hnet 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. SgΠ€hnet 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 SgΠ€hnet 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 SgΠ€hnet 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 Nikanassinβs 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 = Ahβ (1 β Sw)
Bg
V =h
2[Ao + 2A1 + 2A2 + . . . + 2An β 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 β with a slope of -0.5 E3m3/month
2. Bilinear flow β slope of -0.25 E3m3/month
3. Boundary Dominated Flow (BDF) β 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 wasnβt 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 β 3092.5) m and (3097.6 β 3099.8) m, both
in the Cadomin formation.
Well 09-34-065: fractured zone is (2842.5 β 2845.3) m in the Nikanassin formation.
Well 13-30-065: fractured zone is (3073.2 β 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 havenβt 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:π = πππβππ‘ therefore;
πΏπ(π) = πΏπ(ππ) β ππ‘
Where;
π = ππππ‘βππ¦ πππ πππππ’ππ‘πππ
ππ = πΌπππ‘πππ ππππ‘βππ¦ πππ πππππ’ππ‘πππ
π = πππππππ ππππ π‘πππ‘ (1
ππππ‘β)
π‘ = π‘πππ (ππ’ππππ ππ ππππ‘βπ )
A plot of Ln (Q) versus t in a linear scale produce line with a slope = - c. The determined values
of c and ππ are as follows:
Well 14-11-065: c = 0.004/month
ππ = 105.5305 E3m3/month
Well 12-32-065: c = 0.0187/month
ππ = 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
ππ = 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)
Number of months from Nov 2005
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
βπ
(E3
M3
)
βCUMULATIVE 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
βQ
(E3
M3
)
βCUMULATIVE 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
zoneβs fluid parameters; permeability, porosity, total compressibility (estimated using the ideal
gas behavior,πΆπ‘ =1
ππ ) 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,
π π· = βππ‘
948β ππΆπ‘
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
Type well 2 9879.418
Type well 3 3749.656
Type well 4 3708.127
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 itβs 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
Figure 42: Illustration of type well 2 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)
Number of months from Nov 2003
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
Figure 43: Illustration of type well 3 production forecast and production history
Figure 44: Illustration of type well 4 production forecast and production history
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)
Number of months from Nov 2005
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 βflowingβ 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 β 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:
$112,000 (1999 CAD dollars) per well
$336,000 (1999 CAD dollars) for three wells
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,
landmanβs fees, easements, capital damage, first yearβs 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:
$250,000 (1999 CAD dollars) per well
$750,000 (2008 CAD dollars) for three wells
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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
(AadnΓΈy, 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
AadnΓΈy, 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:
$17,000 (1999 CAD dollars) per well
$51,000 (1999 CAD dollars) for three wells
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:
$27,500 (1999 CAD dollars) per well
$82,500 (1999 CAD dollars) for three wells
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
$24,500 (1999 CAD dollars) per well
$73,500 (1999 CAD dollars) for three wells
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
$40,000 (1999 CAD dollars) per well
$120,000 (1999 CAD dollars) for three wells
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:
$20,000 (1999 CAD dollars) per well
$60,000 (1999 CAD dollars) for three wells
70
Boiler:
$40,000 (1999 CAD dollars) per well
Campsites:
$60,000 (1999 CAD dollars) per well
$180,000 (1999 CAD dollars) for three wells
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:
$108,000 (1999 CAD dollars) per well
$324,000 (1999 CAD dollars) for three wells
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:
$26,632 (1999 CAD dollars) per well
$76,896 (1999 CAD dollars) for three wells
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 β 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:
$19,500 (1999 CAD dollars) per well
74
$58,500 (1999 CAD dollars) for three wells
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 βbuyproppant.comβ, 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:
$385,200 (2014 CAD dollars) per well
$1,115,600 (2014 CAD dollars) for three wells
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:
$20,000 (1999 CAD dollars) per well
$60,000 (1999 CAD dollars) for three wells
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:
$55,000 (1999 CAD dollars) per well
$165,000 (1999 CAD dollars) for three wells
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
$1,358,394 (2015 CAD dollars) per well
$4,075,182 (2008 CAD dollars) for three wells
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.
$15,000 (2015 CAD dollars) per well
$45,000 (2015 CAD dollars) for three wells
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:
$1,470,000 (1999 CAD dollars) per well
$2,101,129 (2015 CAD dollars) per well
$6,303,387 (2015 CAD dollars) for three wells
Note that abandonment does not occur until the end of the project.
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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:
$100,000 (1999 CAD dollars) per well
$142,933.95 (2015 CAD dollars) per well
$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 4β treater is
selected for this project. The cost of the selected battery is, as provided by Sproule Association,
as follow:
$75,000 (1999 CAD dollars) per well
$107,200.46 (2015 CAD dollars) per well
$321,601.38 (2015 CAD dollars) per 3 wells
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:
$60,000 (1999 CAD dollars) per well
$85,760.37 (2015 CAD dollars) per well
$257,281.11 (2015 CAD dollars) per 3 wells
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:
$385,921.66 (2015 CAD dollars) per 3 wells
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
$517,825 (1999 CAD dollars) per well
$740,147.72 (2015 CAD dollars) per well
$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 β 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
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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.
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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:
πππ = β(ππΆπΉ)
(1 + π)π
π
π=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.
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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 Sprouleβs 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 Sprouleβs
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 Sprouleβs 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
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94
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95
Appendix A: Nomenclature
Table 14: List and definition of symbols used in this report
Symbol Description Units β Porosity
β π Neutron Porosity
β π Density Porosity
β π Effective Porosity
β πβ² Effective Shale Corrected Porosity
β πβ²ππ―π
Average Shale Corrected Porosity
ππ° Water Resistivity Ohm*m
ππ° π¦π Water Resistivty at 25oC Ohm*m
ππ Total Resistivity Ohm*m
ππ¬π‘ Shale Resistivity Ohm*m
ππ₯ππ¦ Laminated Shale Coefficient
ππ¦π Measured conditions temperature (25oC) oC
ππ Average Formation Temperature oC
m Cementation Exponent
a Archie rock property constant
ππ¬π‘π’ Uncorrected Shale Volume fraction
ππ¬π‘ Corrected Shale Volume fraction
πππ₯π¨π Formation Gamma Ray Reading API
ππππ₯πππ§ Clean Sand Gamma Ray Reading API
πππ¬π‘ Shale Gamma Ray Reading API
ππ¬π‘ Shale Volume
π Absolute Temperature K
ππ° Water Saturation
ππ° ππ―π Average Water Saturation
ππ Gas Saturation
ππππ Original Gas in Place
π‘ Interval Thickness m
π‘π§ππ Net Pay Thickness m
π/π Net to Gross Pay Ratio
ππ Formation Gas Volume Factor Sm3/m3
k Permeability mD
π€π¦ππ± Maximum Horizontal Permeability mD
π€ππ 90o Horizontal Permeability mD
π€π―ππ«π Vertical Permeability mD
rp35 Pore throat aperture at 35% Mercury Saturation nm
π Gas Viscosity Pa.s
π 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.
(Β°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
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
105
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.
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
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.
109
Figure 73: Well
Log for Well 00-
08-22-65-08W6
obtained from
Accumap.
110
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.
111
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.
112
Figure 76: Well
Log for Well 00-
07-12-65-08W6
obtained from
Accumap.
113
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.
114
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.
115
Figure 79: Well
Log for Well 00-
07-26-65-08W6
obtained from
Accumap.
116
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.
117
Figure 81: Porosity, Water Saturation and Permeability Logs that were built by analyzing the logs for the
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
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
120
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
121
Figure 85: Well
Log for Well 00-
03-07-65-08W6
obtained from
Accumap.
122
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
123
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
124
Figure 88: Well
Log for Well 00-
11-09-65-08W6
obtained from
Accumap.
125
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
126
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
127
Figure 91: Well
Log for Well 00-
14-11-65-08W6
obtained from
Accumap.
128
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
129
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
130
Figure 94: Well
Log for Well 00-
09-34-65-08W6
obtained from
Accumap.
131
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
132
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
133
Figure 97: Well
Log for Well 00-
05-06-65-08W6
obtained from
Accumap.
134
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
135
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
136
Figure 100: Well
Log for Well 00-
15-13-65-08W6
obtained from
Accumap.
137
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
138
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
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
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
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
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
distinctive trend, with m=2.2499, and a=0.5070
142
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
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
143
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
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
144
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
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
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 SgΠ€hnet
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 SgΠ€hnet
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
SgΠ€hnet Gross Pay
(m)
Net Pay
(m)
N/G
Ratio
SgΠ€hnet
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
Figure 116: Log-Core
correlation for the analyzed
interval of well 00/11-09-
065-08W6.
150
Figure 117: Log-Core
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
against porosity. Note that most pore throats in this well are between Mesopores and Megapores.
155
Figure 126: Pore throat aperture for well 00/06-02-065-08/W6. 90o Horizontal permeability is measured
against porosity. Note that most pore throats in this well are between Mesopores and Marcopores.
Figure 127: 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.
156
Figure 128: Pore throat aperture for well 00/05-06-065-08/W6. 90o Horizontal permeability is measured
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
Figure 130: Pore throat aperture for well 00/12-32-065-08/W6. Max Horizontal permeability is measured
against porosity. Note that most pore throats in this well are between Mesopores and Megapores.
Figure 131: Pore throat aperture for well 00/05-06-065-08/W6. 90o Horizontal permeability is measured
against porosity. Note that most pore throats in this well are between Mesopores and Megapores.
158
Figure 132: Pore throat aperture for well 00/12-32-065-08/W6. Vertical permeability is measured against
porosity. Note that most pore throats in this well are between Mesopores and Megapores.
Figure 133: Pore throat aperture for well 00/10-19-065-08/W6. Max Horizontal permeability is measured
against porosity. Note that most pore throats in this well are between Mesopores and Megapores.
159
Figure 134: Pore throat aperture for well 00/10-19-065-08/W6. 90o Horizontal permeability is measured
against porosity. Note that most pore throats in this well are between Mesopores and Megapores.
Figure 135: Pore throat aperture for well 00/10-19-065-08/W6. Vertical permeability is measured against
porosity. Note that most pore throats in this well are between Mesopores and Megapores.
160
Figure 136: Pore throat aperture for well 00/11-09-065-08/W6. Max Horizontal permeability is measured
against porosity. Note that most pore throats in this well are between Micropores and Megapores.
Figure 137: Pore throat aperture for well 00/07-21-065-08/W6. Max Horizontal permeability is measured
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 β Mercury-air ππ Vs ππ.
Figure 139: Nikanassin Formation β Mercury-air ππ Vs ππ.
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)
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
164
Figure 140: Mercury-air ππ Vs ππ 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)
Water Saturation (%)
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:
π΅π = 5.037 βπ§π
π
Where the gas compressibility factor is given by,
π§ = π΄ + (1 β π΄) exp(βπ΅) + πΆπππ·
The coefficients are given by,
π΄ = 1.39(ππ β 0.92)0.5 β 0.36ππ β 0.101
π΅ = (0.62 β 0.23ππ)ππ + (0.066
ππ β 0.68β 0.037) ππ
2 + 0.32ππ
6
109(ππβ1)
πΆ = 0.132 β 0.32log (ππ)
π· = 10(0.3106β0.49ππ+0.1824ππ2)
ππ =π
ππ, πππ ππ =
π
ππ
in which the unit of π πππ ππ is Β°π and the unit of π πππ ππ is Psia.
Cadomin Nikanassin
Pc (Psia) 679.30 678.14
Tc (Β°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 π©π π©π π©π
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
ππ = 10β4πΎ exp(πππ(2.4β0.2π))
Where,
πΎ =(9.4 + 0.02π)π1.5
209 + 19π + π
π = 3.5 +986
π+ 0.01π
ππ = 0.0014935ππ
π§π
in which the unit of π is Β°π ,the unit of π is Psia, and M is the molar mass of the gas.
167
P (psia) Cadomin Nikanassin Average Cadomin Nikanassin Average
ππ ππ ππ ππ ππ ππ
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 SgΠ€hnet contour map. This is used in volumetric calculations for Original Gas in Place.
174
Figure 148: Nikanassin SgΠ€hnet 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 SgΠ€hnet values. Those wells without logs were subject to correlations based on nearby well data, in order to
find SgΠ€hnet
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
Figure 156: Shows apparent
natural fractured zones in Well
09-34-065
184
Natural fracture:(3073.2-3082)m
Well 13-30-065
Figure 157: Shows apparent
natural fractured zones in Well
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
βπ
β(πΆπ’πππ’πππ‘ππ£π ππππ.)
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
Figure 163: Type well 1 cumulative production history then extrapolated by exponential decline
method
Figure 164: Type well 2 cumulative production history then extrapolated by exponential decline
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
)
Cumulative Gas Production (E3m3)
Type well 2: Cumulative Production
From Production History
Extrapolated by Exponential decline method
188
Figure 165: Type well 3 cumulative production history then extrapolated by exponential decline
method
Figure 166: Type well 4 cumulative production history then extrapolated by exponential decline
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
)
Cumulative Gas Production (E3m3)
Type well 3: Cumulative Gas Production
From Production History
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
)
Cumulative Gas Production (E3m3)
Type well 4: Cumulative Gas Production
From Production History
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
Figure 169: Determination of the exponential decline equation constants for well 15-13-065
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)
t (number of months)
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)
Well 07-21-065: Ln (Q) vs. time
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)
Well 15-13-065: Ln (Q) vs. time
190
Figure 170: Determination of the exponential decline equation constants for well 14-11-065
Figure 171: Determination of the exponential decline equation constants for well 13-30-065
Figure 172: Determination of the 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
-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)
Well 13-30-065: Ln (Q) vs time
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)
Well 12-32-65: Ln (Q) vs. time
191
Figure 173: Determination of the exponential decline equation constants for well 09-34-065
Figure 174: Determination of the exponential decline equation constants for well 08-22-065
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)
Well 09-34-065: Ln (Q) vs. time
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)
Well 08-22-065: Ln (Q) vs. time
y = -0.0145x + 6.8868
0
2
4
6
8
0 20 40 60 80 100 120 140 160
Ln (
Q)
t (number of months)
Type well 1: Ln (Q) vs. time
192
Figure 176: Determination of the exponential decline equation constants for Type well 2
Figure 177: Determination of the exponential decline equation constants for Type well 3
Figure 178: Determination of the exponential decline equation constants for Type well 4
y = -0.0111x + 6.1667
0
1
2
3
4
5
6
7
8
0 20 40 60 80 100 120 140
Ln (
Q)
t (number of months)
Type well 2: Ln (Q) vs. time
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)
t (number of months)
Type well 3: Ln (Q) vs. time
y = -0.0137x + 5.8866
0
1
2
3
4
5
6
7
0 20 40 60 80 100 120 140
Ln (
Q)
t (number of months)
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 $733,018.52
198
Infill Drilling Analysis
Table 39: Year 1 Economic Evaluation β 3 New Drills 2016.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/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 -$23,309,782.88
199
Table 40: Year 2 Economic Evaluation β 3 New Drills 2017.
Year
Total
Cum.
Producti
on
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
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 -$43,844,422.73
200
Table 41: Year 3 Economic Evaluation β 3 New Drills 2018.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
Taxed
RevenueCash Flow
Discounted
Cash Flow
2015 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 -$61,836,334.37
201
Table 42: Year 4 Economic Evaluation β 3 New Drills 2019.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
Taxed
RevenueCash Flow
Discounted
Cash Flow
2015 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 -$77,085,407.59
202
Table 43: Year 5 Economic Evaluation β 3 New Drills 2020
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
Taxed
RevenueCash Flow
Discounted
Cash Flow
2015 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 -$90,579,980.00
203
Re-Perforation and Fracturing Analysis
Table 44: Year 2016 Economic Evaluation β Re-perforating and Fracturing.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
Taxed
RevenueCash Flow
Discounted
Cash Flow
2015 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 $808,776.99
204
Table 45: Year 2019 Economic Evaluation β Re-perforating and Fracturing.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
Taxed
RevenueCash Flow
Discounted
Cash Flow
2015 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 $805,522.11
205
Table 46: Year 2022 Economic Evaluation β Re-perforating and Fracturing.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
Taxed
RevenueCash Flow
Discounted
Cash Flow
2015 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 $964,578.99
206
Table 47: Year 2025 Economic Evaluation β Re-perforating and Fracturing.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
Taxed
RevenueCash Flow
Discounted
Cash Flow
2015 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 $1,011,087.60
207
Infill Drilling, Re-perforation and Fracturing Analysis
Table 48: Year 2016- Economic Evaluation β 3 New Wells and Re-perforating and Fracturing of 1 well.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
Taxed
RevenueCash Flow
Discounted
Cash Flow
2015 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 -$22,377,611.33
208
Table 49: Year 2019- Economic Evaluation β 12 New Wells drilled since 2016 and the second re-perforating and Fracturing well.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
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 -$74,039,592.79
209
Table 50: Year 2022- Economic Evaluation β 15 new wells drilled since 2016 and the third re-perforating and Fracturing well.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
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 -$87,049,518.62
210
Table 51: Year 2025- Economic Evaluation β 15 new wells drilled since 2016 and the fourth re-perforating and Fracturing well.
Year
Total Cum.
Production
(E3m3)
Alberta
Reference
Average
Price -
Current
(C$/E3m3)
Gross
RevenueCapex Fixed Opex
Variable
OpexRoyalty Revenue Tax
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
Var field expenses -45444548.36 -42244297.11 -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 ($)
Fixed Opex -61898672.04 -61773996.71 -61836334.37
Taxes -61981288.79 -61691379.96 -61836334.37
Royalties -62080174.97 -61592493.77 -61836334.37
Variable Opex -62169541.45 -61503127.29 -61836334.37
Production -61194179.06 -62478489.69 -61836334.37
Gas Price -61025803.98 -62646864.77 -61836334.37
Var field expenses -64083349.04 -59589319.7 -61836334.37
Capex -72536404.23 -51136264.51 -61836334.37
Table 53: Sensitivity analysis on the parameters for a three year infill drilling project.
Figure 183: Tornado Chart for the three year infill drilling project.
-73000000 -68000000 -63000000 -58000000 -53000000
Fixed Opex
Taxes
Royalties
Variable Opex
Production
Gas Price
Var field expenses
Capex
Tornado Chart Infill drilling: 3 years
214
Year 4
Factor NPV High, +20% ($) 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