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2013-02-26 The Thermo-Tectonic and Petroleum System Evolution at Hoodoo Dome, Ellef Ringnes Island, Sverdrup Basin, Canadian High Arctic: Implications for Hydrocarbon Exploration and Regional Geology
Springer, Austin
Springer, A. (2013). The Thermo-Tectonic and Petroleum System Evolution at Hoodoo Dome, Ellef Ringnes Island, Sverdrup Basin, Canadian High Arctic: Implications for Hydrocarbon Exploration and Regional Geology (Unpublished master's thesis). University of Calgary, Calgary, AB. doi:10.11575/PRISM/28400 http://hdl.handle.net/11023/559 master thesis
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The Thermo Tectonic and Petroleum System Evolution at Hoodoo Dome, Ellef Ringnes Island,
Sverdrup Basin, Canadian High Arctic: Implications for Hydrocarbon Exploration and Regional
Geology
by
Austin C. Springer
A THESIS
SUBMITTED TO THE FACULTY OF GRADUATE STUDIES
IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE
DEGREE OF MASTER OF SCIENCE
DEPARTMENT OF GEOSCIENCE
CALGARY, ALBERTA
FEBRUARY, 2013
© AUSTIN C. SPRINGER 2013
UNIVERSITY OF CALGARY
FACULTY OF GRADUATE STUDIES
The undersigned certify that they have read, and recommend to the Faculty of Graduate Studies for acceptance, a thesis entitled “The Thermo Tectonic and Petroleum System Evolution at
Hoodoo Dome, Ellef Ringnes Island, Sverdrup Basin, Canadian High Arctic: Implications for
Hydrocarbon Exploration and Regional Geology” submitted by Austin C. Springer in partial fulfilment of the requirements for the degree of Master of Science.
______Supervisor, Dr. Bernard Guest, Department of Geoscience
______Dr. Keith Dewing, Department of Geoscience
______Dr. Benoit Beauchamp, Department of Geoscience
______Dr. Darren B Sjogren, Department of Geography
University of Calgary
______Date
ii Abstract
This study integrates detrital apatite (U Th)/He thermochronology with source rock
characterization and one dimensional burial and thermal history reconstruction modeling to better understand the thermal, tectonic, and petroleum systems at Hoodoo Dome, an evaporite diapir in the Canada's hydrocarbon bearing Sverdrup Basin. Thermochronology on Lower
Cretaceous rocks indicates a time of exhumation and cooling related to Eurekan deformation during the Latest Cretaceous (80 Ma) until Middle Eocene (41 Ma). Burial history modeling of an exploration well at Hoodoo Dome (Hoodoo Dome H 37) indicates that peak hydrocarbon generation and expulsion beneath Hoodoo Dome occurred during the Aptian and Albian.
Combined, these results indicate that the petroleum system below Hoodoo Dome generated and expelled its hydrocarbons prior to major structural trap formation associated with the Eurekan
Orogeny. As a result, the warrant to further explore for large hydrocarbon fields associated structural traps related to the Late Cretaceous to Eocene deformation is limited.
iii Acknowledgements
This project would have remained a dream had it not been for the support of many people. Many thanks to my supervisors, Dr. Bernard Guest and Dr. Keith Dewing for always being there for me when I needed to bounce ideas around, providing encouragement and direction when I needed it most, and finally for reading, editing and making numerous recommendations to this thesis. I'd like to thank the rest of my committee, Dr. Benoit
Beauchamp, and Dr. Daren Sjogren for their critical reviews and edits of this thesis.
I'd also like to thank my office mates and fellow geology researchers for their ongoing support, valuable discussions, and most importantly, their friendship and ability to have non geology related fun. In addition, my family and friends in Cincinnati for their continuing long distance support and encouragement.
A great thanks to Dr. Benoit Beauchamp, Dr. Stephen Grasby, the SUNBEAM program, the GSC's GEM program, and the Polar Continental Shelf Project for their logistical and financial support of this thesis. Without the support of these people and programs, this project and many others like it in the arctic would not have come to be.
I would like to thank Derrick Midwinter for his geological and cooking capabilities as my field assistant during our time on Ellef Ringnes Island. Thank you to the University of Kansas
(U Th)/He thermochronology lab, in particular Dr. Charlie Verdel, Dr. Roman Kislitsyn, and Dr.
Daniel Stockli who gave me a great deal of technical support and time during my stay at their lab. Finally, many thanks to Janelle Irvine. She has been my biggest source of support and encouragement throughout this thesis, providing me with numerous edits, ideas, discussions, companionship, and love.
iv Dedication
I dedicate this thesis to all of my family and friends.
v Table of Contents
Abstract ...... iii Acknowledgements ...... iv Dedication ...... v Table of Contents ...... vi List of Figures and Illustrations ...... viii List of Plates...... xiv List of Tables and Appendices ...... xv Extended Abstract: ...... 1
1.0 INTRODUCTION: ...... 3 1.1 Tectonic History of the Sverdrup Basin: ...... 5 1.2 Evaporites in the Sverdrup Basin: Deposition and Evolution ...... 10 1.3 Study Area: ...... 14 1.3.1 Introduction: ...... 14 1.3.3 Hoodoo Dome Field Mapping: ...... 17 1.4 Sverdrup Basin Petroleum System History: ...... 21
2.0 DETRITAL APATITE (U TH)/HE THERMOCHRONOLOGY: ...... 23 2.1 Introduction and Methods: ...... 23 2.1.1 He Diffusion in Apatite: ...... 27 2.1.2 α Particle Ejection and Ft Correction: ...... 28 2.1.3 Sampling Strategy: ...... 29 2.1.4 Analytical Technique: ...... 30 2.2 Results: ...... 32 2.3 Interpretation and Discussion ...... 34 2.3.1 Apatite Helium Age Reproducibility: ...... 34 Helium Rich Mineral Inclusions: ...... 34 Radiation Damage: ...... 35 U Th Zonation: ...... 38 Crystal Size Variations and Mismeasurements: ...... 39 Helium Implantation: ...... 40 Summary: ...... 40 2.3.3 Impact of Salt Structures on Cooling Histories: ...... 43 2.3.4 Summary of Apatite (U Th)/He Thermochronology Interpretations: ...... 44 2.4 Implications for Geologic History: ...... 46 2.4.1 Campanian Cooling: ...... 46 2.4.2 Cenozoic Cooling: ...... 49
3.0 1 D BASIN MODELING: ...... 54 3.1 Introduction: ...... 54 3.2 Methods: ...... 55 3.3 Data Sets and Input Parameters: ...... 60 3.3.1 Thermal Model: ...... 60 3.3.1.1 Hoodoo Dome H 37: Present and Paleo Temperature Data ...... 60
vi 3.3.2 Stratigraphy and Lithology: ...... 62 3.3.3 Timing of Uplift: ...... 63 3.3.4 Source Rocks and Source Rock Potential: ...... 64 3.3.4.1 Source Rock Characterization and Generation Potential: ...... 64 3.4 Results: ...... 68 3.4.1 Source Rock Characterization and Generation Potential: ...... 68 3.4.2 Burial and Thermal History Modeling: ...... 69 3.4.2.1 Temperature Modeling ...... 69 3.4.2.2 Timing of Thermal Maturation, Hydrocarbon Generation and Expulsion: ...... 70 3.5 Discussion: ...... 73 3.5.1 Source rocks: ...... 73 3.5.2 Thermal Maturity and Temperature Modeling: ...... 76 3.5.3 Timing and rate of Generation and Expulsion: ...... 81 3.6 Summary: ...... 83
4.0 (U TH)/HE THEMOCHRONOLOGY, BURIAL HISTORY MODELING AND SVERDRUP BASIN PETROLEUM SYSTEM: ...... 85 4.1 Better Understanding the Historical Discoveries: ...... 85 4.2 Future Prospective Hydrocarbon Exploration: ...... 91
5.0 SUMMARY AND FUTURE WORK: ...... 95 5.1 Summary of Present Work: ...... 95 5.2 Suggestions for Future Work: ...... 96
REFERENCES ...... 98
vii
List of Figures and Illustrations
Figure 1: Regional map of the Canadian Arctic Islands. The shaded pink area delineates the extent of the Sverdrup Basin. The red box outlines Ellef Ringnes Island, the island which Hoodoo Dome is located on. Map abbreviations stand for the following: MKI Mackenzie King Island; BI Borden Island; LHI Lougheed Island; ERI Ellef Ringnes Island; ARI Amund Ringnes Island; CWI Cornwall Island; EI Eglinton Island...... 119
Figure 2: Paleozoic and Mesozoic stratigraphy of the central Sverdrup Basin (modified after Macauley, 2009). The black stars represent the primary hydrocarbon source rocks of the basin, and the blue stars indicate the Basin’s primary reservoir rocks...... 120
Figure 3: Distribution of the major Carboniferous Otto Fiord Fm. cored evaporite structures within the Sverdrup Basin (salt structure locations from Embry, 2011)...... 121
Figure 4: Summarized Mesozoic stratigraphic cross section of the Sverdrup Basin. Note, salt intrusions and dykes are not illustrated in the figure (from Embry, 1991)...... 122
Figure 5: Map of Arctic landmasses showing the location and extent of volcanic and intrusive rocks (orange translucent) during the Cretaceous igneous event. The Sverdrup Basin is outlined by the black dashed line, and the hot spot trak of the Alpha Ridge is shown by the blue dashed line just to the north of the Sverdrup Basin.(from Jones et al., 2007) ...... 123
Figure 6: Generalized movement of the Greenland Plate relative to the North American Plate from Chrons C27N to C13N using Roest and Srivastava's (1989) model. The plate kinematic studies indicate a general north eastern movement of Greenland relative to North America from Chron 27 25N. Between Chrons 25 24N the motion becomes more north north east. By Chron 24N a major change in the direction of motion of the Greenland Plate occurs to a more north northwest motion. This continues until approximately Chron 13N (from Oakey & Chalmers, 2012)...... 124
Figure 7: Generalized deformation zones within the Sverdrup Basin. Note, deformation is most intense in the east, and decreases in intensity moving southwest across the basin (location of deformation zones are from Embry and Beauchamp, 2008)...... 125
Figure 8: Location and generalized structure of the wall and basin structure (WABS) province on Axel Heiberg Island (from Jackson and Harrison, 2006)...... 126
Figure 9: Bedrock geology map of Ellef Ringnes Island. The geology is the published work of Stott(1969). The red box in the southern portion of the island outlines the study area around Hoodoo Dome...... 127
Figure 10: Oil and Gas fields in the western Sverdrup Basin (location of discoveries are from Waylett & Embry, 1993). Sverdrup Basin outlined by dashed line...... 128
viii Figure 11: Thermal maturity map of the Triassic source rocks across the Sverdrup Basin (modified from Dewing & Obermajer, 2011). Note that Ellef Ringnes Island is on the boundary between the thermally over mature rocks in the eastern Sverdrup Basin and the rocks within the oil window in the western Sverdrup Basin. The black dots represent well locations that were used for the Triassic source rock characterization in this study. The blue dots represent the locations of the following wells: Hoodoo Dome H 37, Helicopter J 12, and Skybattle M 11...... 129
Figure 12: Schematic summarizing the burial/thermal relationships of helium diffusion in apatite grains within a detrital system...... 130
Figure 13: Cross section corresponding to sample collection transects indicated on the geological map in Plate 1. Sample locations are identified by red triangles, and their associated cooling ages are shown against time (Ma) as coloured diamonds. The cooling ages within the shaded blue area represent grains which postdate their Sverdrup depositional age. Cooling ages older than the shaded blue area indicate that some grains either did not experience significant helium diffusion or have U Th rich micro inclusions. These older ages suggest these strata were buried shallow (>3km) and to temperatures less than 70 degrees Celsius, while the younger ages provide evidence to suggest that these rocks were at least buried to within the HePRZ and experienced significant diffusion. The Formation abbreviations stand for the following. Ce= Carboniferous Otto Fiord Fm.; JR=Jurassic Ringnes; JDB= Jurassic Deer Bay Fm.; KlPI= Lower Cretaceous Patterson Island Member of Isachsen; KlWI= Lower Cretaceous Walker Island Member of Isachsen Fm.; KC= Christopher Fm.; KH= Cretaceous Hassel Fm.; KK= Cretaceous Kanguk Fm.; KAI= Cretaceous hydorthermal alteration zone...... 131
Figure 14: Radiation Damage (eU) vs. AHe cooling age plot for all analyzed grains at Hoodoo Dome. Apatite grains with low eU (<20 ppm), shown below the dashed red line, will not show a correlation with eU because radiation damage below 20 ppm will have minimal effect on helium diffusion within apatite. Grains with greater concentrations of eU (>20 ppm) still do not show a correlation with cooling age within this sample suite...... 132
Figure 15: Single grain radii (Equivalent Sphere Radius) of all sampled aliquots are plotted against AHe cooling ages to determine if there is a relationship between grain size and cooling age. The plot shows a cluster of younger ages between 40 and 80Ma which can be correlated with some of the smaller grain sizes, however, other small grains have old ages, while some larger grains have very young ages. As a result, this plot illustrates that grain size alone was not a major factor in the scatter of the observed 4He ages...... 133
Figure 16: Cooling age similarities between this study and apatite fission track results from Arne et al. (1998, 2002). Red boxes indicate the locations where the studies were undertaken. Despite more than 350 kilometers distance between the results on Hoodoo Dome and those in the eastern Sverdrup Basin, the timing of cooling initiation between the two is very similar...... 134
ix Figure 17: Summary of the transient heat flow used in the model. The spike in heat flow during the Early Cretaceous was estimated to reflect the wide spread igneous activity in the basin during that time...... 135
Figure 18: Burial and maturation history model of Hoodoo H 37. The model indicates several phases of moderate to rapid subsidence that caused the source rocks in the basin to mature. The Triassic source rocks enter the oil window by during the Jurassic and continue to mature into the late oil and gas generation window by the Late Cretaceous. The Jurassic source rocks appear to not buried as deeply, and only matured into the early oil mature window during the Late Cretaceous...... 136
Figure 19: Calibration of calculated versus measured maturity at Hoodoo H 37. Note, increasing the transient heat flow steepens the modeled temperature curve, whereas increasing the sediment load only shifts the modeled temperature curve either left (less thermally mature) or right (more thermally mature). These two values were estimated and adjusted to allow the model to better fit the constraints provided by the measured present day and paleo temperature data at Hoodoo Dome H 37...... 137
Figure 20: Depth Maturity plot for Hoodoo Dome H 37, showing the absence of igneous intrusions and their effect on the thermal maturity in this well (from Dewing et al., 2007)...... 138
Figure 21: Modified Van Krevelen diagram for the Deer Bay Formation source rocks based on oxygen index (OI) versus hydrogen index (HI), showing the gas prone type III kerogen. The Rock Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007)...... 139
Figure 22: Modified Van Krevelen diagram for the Ringnes Formation source rocks based on oxygen index (OI) versus hydrogen index (HI), showing the primarily oil prone type II kerogen. The Rock Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007)...... 140
Figure 23: Modified Van Krevelen diagram for the Hoyle Bay Formation source rocks based on oxygen index (OI) versus hydrogen index (HI), showing the primarily oil prone type II kerogen. The Rock Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007)...... 141
Figure 24: Modified Van Krevelen diagram for the Murray Harbour Formation source rocks based on oxygen index (OI) versus hydrogen index (HI), showing the primarily oil prone type II kerogen. The Rock Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007)...... 142
Figure 25: Deer Bay Formation: Plot of total organic carbon (TOC, wt%) versus the produced hydrocarbons remaining in the rock ( S1 mg HC/g rock) plus the remaining hydrocarbon potential within the rock (S2 mg HC/g rock), showing an overall poor petroleum generating potential for this formation. The Rock Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007)...... 143
x Figure 26: Ringnes Formation: Plot of total organic carbon (TOC, wt%) versus the produced hydrocarbons remaining in the rock ( S1 mg HC/g rock) plus the remaining hydrocarbon potential within the rock (S2 mg HC/g rock), showing an overall fair to very good petroleum generating potential for this formation. The Rock Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007)...... 144
Figure 27: Hoyle Bay Formation: Plot of total organic carbon (TOC, wt%) versus the produced hydrocarbons remaining in the rock ( S1 mg HC/g rock) plus the remaining hydrocarbon potential within the rock (S2 mg HC/g rock), showing an overall poor to very good/excellent petroleum generating potential for this formation. The Rock Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007). .. 145
Figure 28: Murray Harbour Formation: Plot of total organic carbon (TOC, wt%) versus the produced hydrocarbons remaining in the rock ( S1 mg HC/g rock) plus the remaining hydrocarbon potential within the rock (S2 mg HC/g rock), showing an overall poor to very good/excellent petroleum generating potential for this formation. The Rock Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007). .. 146
Figure 29: Deer Bay Formation's rate of hydrocarbon generation...... 147
Figure 30: Ringnes Formation's rate of hydrocarbon generation...... 148
Figure 31: Hoyle Bay Formation's rate of hydrocarbon generation...... 149
Figure 32: Murray Harbour Formation's rate of hydrocarbon generation...... 150
Figure 33: Modeled cumulative amount of generated and expelled hydrocarbons from the organic matter in the Late Jurassic / Early Cretaceous Deer Bay Fm. source rock at Hoodoo Dome H 37...... 151
Figure 34: Modeled cumulative amount of generated and expelled hydrocarbons from the organic matter in the Jurassic Ringnes Fm. source rock at Hoodoo Dome H 37...... 152
Figure 35: Modeled cumulative amount of generated and expelled hydrocarbons from the organic matter in the Triassic Hoyle Bay Fm. source rock at Hoodoo Dome H 37...... 153
Figure 36: Modeled cumulative amount of generated and expelled hydrocarbons from the organic matter in the Triassic Murray Harbour Fm. source rock at Hoodoo Dome H 37. . 154
Figure 37: Diagram showing the modeled timing and amount of hydrocarbon expulsion for the Deer Bay Formation at Hoodoo H 37. Because insignificant hydrocarbons were produced from this source rock, expulsion did not occur...... 155
Figure 38: Diagram showing the modeled timing and amount of hydrocarbon expulsion for the Ringnes Formation at Hoodoo H 37. Because insignificant hydrocarbons were produced from this source rock, expulsion did not occur...... 156
xi Figure 39: Diagram showing the modeled timing and amount of hydrocarbon expulsion for the bottom of Hoyle Bay Formation at Hoodoo H 37. The model indicates that expulsion occurred during the Albian...... 157
Figure 40: Diagram showing the modeled timing and amount of hydrocarbon expulsion for the Murray Harbour Formation at Hoodoo H 37. Expulsion of hydrocarbons from these rocks began during the Early Aptian and ceased by the end of the Albian...... 158
Figure 41: Depth Maturity plot for exploration well Helicopter J 12 located north east of Hoodoo Dome on eastern Ellef Ringnes Island (from Dewing et al., 2007). This depth maturity plot shows the clearly visable correlation between igneous intrusion and their effect on the thermal maturity values...... 159
Figure 42: Depth Maturity plot for exploration well Skybattle M 11(from Dewing et al., 2007). The anomalous thermal maturity values observed in the Jurassic rocks possibly is a reflection of more mature detrital material. This however, appears very different then thedepth maturity plot for Hoodoo Dome...... 160
Figure 43: Generalized diagram showing the differential entrapment of oil and gas via fill and spill in a structural trap play type environment, similar to the structural play type in the central Sverdrup Basin. During the early hydrocarbon generation stage, oil and gas filled the structural closures in the basin axis. Increased thermal maturity caused the source rocks to begin generating higher quantities of natural gas. Once volumes of hydrocarbons exceed the capacity of pore space in the traps, hydrocarbons are forced to migrate under the spill point and into the following closure. This process continues until petroleum charge stops (modified from Fustic et al., 2012)...... 161
Figure 44: Section across the Balaena and Char fields southwest of Ellef Ringnes Island. The figure illustrates how fractures and faulting over these fields resulted in significant vertical migration and escape of hydrocarbons (from Embry, 2011)...... 162
Figure 45: Petroleum events chart summarizing the major elements and events of the Triassic through Paleogene petroleum system regionally around Ellef Ringnes Island (modified from Magoon and Dow, 1994). Each of the coloured horizontal bars represents the time span of an event or process. Based on the results from this study, all of the essential elements and prcesses are present, however the timing of certain events (e.g., trap formation relative to petroleum generation) are not favourable for a conventional oil play...... 163
Figure 46: Map illustrating the Upper Triassic Cretaceous reservior structural closures within the western and central Sverdrup Basin. The closures were delineated using the legacy seismic available for the Sverdrup Basin, and although the density is such that it suggests no large strucutres have gone undetected, the poor resolution of the data suggests that many smaller, more complex strucutres are yet to be discovered (from Embry, 2011)...... 164
xii Figure 47: Stratigraphic cross section illustrating the possibilities of basin margin sandstone pinch out prospects in the Heiberg Formation lateral equivalent, the Early Jurassic King Christian Fm. (from Embry, 2011)...... 165
xiii List of Plates
Plate 1: Geological map of Hoodoo Dome...... 166
xiv List of Tables and Appendices
Table 1: Each aliquot is listed with corresponding single grain cooling ages. Resulting ages are within 2 standard deviations. (*) indicates grains which have helium re extractions above background levels (0.003 ppm) ...... 167
Appendix 1: Input paramerters used for Basin Mod 1 D® ...... 169
Appendix 2: Basin Mod 1D output formation reports. Indicate the level of maturity, hydrocarbons generated and expelled ...... 172
xv
Extended Abstract:
Over one hundred evaporite diapirs, cored by the Carboniferous Otto Fiord Fm., reside along the Sverdrup Basin's axis in the Canadian High Arctic. Due to the remoteness of this region, an understanding of their tectonic evolution and implications for hydrocarbon exploration potential remain inadequate. This study focuses on one of the better known diapirs, Hoodoo Dome, which is located in the southern portion of Ellef
Ringnes Island. Using ground based geologic mapping, apatite (U Th)/He thermochronology, source rock characterization, and burial and thermal history modeling at Hoodoo Dome, the aim of this project was to:
1) Investigate thermal and tectonic history of Hoodoo Dome
2) Characterize and model the type, timing, rate and quantities of hydrocarbon generation and expulsion of the petroleum system underlying the dome.
3) Identify the implications for future hydrocarbon exploration in the west central
Sverdrup Basin
The data provided by this study greatly increases the current understanding of the development and evolution of the thermo tectonic, evaporite, and petroleum systems at
Hoodoo Dome during the Mesozoic and Paleogene.
Detrital apatite (U Th)/He thermochronology conducted on the Lower Cretaceous sandstones of the Isachsen through Hassel Formations indicate these strata reached a maximum burial within the partial retention zone, followed by uplift and cooling during the Latest Cretaceous (80 Ma) through Middle Eocene (41 Ma). The post Lower
1
Cretaceous cooling ages of the apatite grains at Hoodoo Dome are interpreted to be a result of the early and peak stages of deformation related to the Eurekan Orogeny.
Rock Eval Pyrolysis data from the Sverdrup Basin's primary source rocks were used to evaluate their kerogen type, and generative potentials. Data from exploration well
Hoodoo H 37 in conjunction with geochemical and thermal maturity data were used for burial and thermal reconstruction modeling of Hoodoo Dome to identify the timing and rate, and quantities of hydrocarbon generation and expulsion. Results of the model indicate that peak generation and expulsion of hydrocarbons from the basins' major source rocks at Hoodoo Dome occurred during the latest Lower to Upper Cretaceous.
Based on these results, it can be concluded that the central Sverdrup Basin petroleum system hit peak hydrocarbon generation and expulsion prior to the tectonics which caused large scale uplift and cooling at Hoodoo Dome, and the development of major structural traps. This provides evidence to limit the warrant to further explore for large hydrocarbon fields associated structural traps related to the Late Cretaceous to
Eocene deformation.
2
1.0 INTRODUCTION:
Salt tectonics are of major interest to the oil and gas industry because many of the
world's largest petroleum discoveries are within salt basins (e.g., Ghawar, Saudi Arabia;
Gulf of Mexico, North Sea, offshore western Africa, offshore eastern South America).
Evaporites within basins have the potential to affect all aspects of a hydrocarbon system,
from creating and influencing the development of structural traps, to manipulating the
distribution of reservoir strata, as well as acting as seals to fluid flow (Hudec & Jackson,
2007).
The Sverdrup Basin (Figure 1) is a NE SW oriented, steep sided pericratonic
trough in the Canadian Arctic Archipelago that contains approximately 13 km (Figure 2)
of Carboniferous to Paleogene strata (Balkwill, 1978). Formation of the basin occurred
in response to continental rifting during the Carboniferous and Early Permian. During its
embryonic stage, Carboniferous evaporites, other clastic, and carbonate rocks were
deposited over thinned continental crust. A relatively uninterrupted phase of post rift
thermal subsidence lasted from the mid Permian until the Late Cretaceous. Lastly, the basin was tectonically inverted by the Eurekan Orogeny, which occurred from the Latest
Cretaceous to the Mid Paleogene.
In the Sverdrup Basin, over 100 evaporite piercement structures are found along
the basin axis. Most of these structures are located between Axel Heiberg and northwest
Melville Island and are cored by evaporites derived from the Carboniferous Otto Fiord
Fm (Figure 3). It is between these islands, and in association with these evaporite
structures, that the majority of the basins' hydrocarbon discoveries were made.
3
The Sverdrup Basin received a high level of exploration starting in the 1960s, but exploration efforts were short lived and ceased in the late 1980s as a result of falling oil and gas prices. During this relatively short exploration effort, 119 wells were drilled into the Mesozoic formations in the west and west central regions of the basin. This exploration led to the discovery of 19 major petroleum fields, almost all occurring within salt cored structural traps.
Until recently, few studies were completed to further the understanding of the timing and evolution of the evaporite piercement structures in the Sverdrup Basin
(Harrison, 1995; Jackson & Harrison, 2006; Boutilier et al., 2011). The goal of this study is to advance the understanding of the evaporite, tectonic, and petroleum systems at one salt cored structure, and to use these findings to evaluate hydrocarbon exploration potential in the west central region of the basin. The focus of this study is Hoodoo Dome, located on the southern margin of Ellef Ringnes Island, and just south of the basin's depositional axis. This evaporite cored dome was chosen because of its accessibility and surface exposure, surface and subsurface geological control provided by numerous wells in the area, and the availability of reliable thermal maturity data.
To improve the understanding of evaporite, tectonic, and petroleum systems at
Hoodoo Dome, the timing of major cooling and uplift (large scale structural trap formation) was constrained using apatite (U Th)/He thermochronology on detrital apatite grains from sandstones collected along two surface transects along the flanks of the dome. Source rock characterization and hydrocarbon generative potential was completed on the Sverdrup's primary source rocks (Murray Harbour, Hoyle Bay, Ringnes, and Deer
Bay formations) using Rock Eval. pyrolysis data from wells across the western Sverdrup
4
Basin. Finally, a burial and thermal history was reconstructed and modeled using
BasinMod 1 D on an exploration well at Hoodoo Dome (Hoodoo H 37) to deduce the timing, rate, and amount of maturation, hydrocarbon generation and expulsion of source rocks.
1.1 Tectonic History of the Sverdrup Basin:
The Sverdrup Basin is a deep pericratonic rift basin in the Canadian Arctic
Archipelago that extends ~1000 km in its E W dimension and ~ 350 km in its N S dimension (Figure 1). It originally developed as a rift basin above highly deformed
Paleozoic rocks of the Ellesmerian Orogenic belt, and now contains about 13 kilometers of Lower Carboniferous to Paleogene sedimentary strata (Embry & Beauchamp, 2008;
Figure 2 & 4). The remoteness and harsh climate of the region limit the opportunities for research, and as a result a comprehensive understanding of the basin's detailed geology and petroleum systems remains incomplete.
Several phases of rifting triggered the inception of the Sverdrup Basin during the
Early Carboniferous to Early Permian (Balkwill 1978; Embry, 1991; Embry &
Beauchamp, 2008). The initial extensional tectonics sub divided the Sverdrup Basin into two sub basins at Lougheed Island, and is marked by the deposition of restricted marine clastic sedimentary rocks followed by a succession of evaporites and deep water shales
(Balkwill 1978, Davies and Nassichuk, 1991). The evaporites deposited during this time are mainly composed of halite at depth, however, in the remobilized diapirs, gypsum and anhydrite are usually visible at the surface. These evaporite rocks are the source for a wide variety of salt structures (e.g. diapirs, pillows, walls, and canopies) which pierce and
5
in some cases on lap the Mesozoic and Cenozoic rocks along the axis of the basin
(Davies & Nassichuk, 1975; Balkwill, 1978; Harrison, 1995).
In the Early to Middle Permian, the extensional tectonics that dominated the development of the basin were interrupted by pulses of mild N NW to S SE oriented compression and uplift (Embry & Beauchamp, 2008). This phase of tectonism, termed the "Melvillian Disturbance" (Thorsteinsson & Tozer, 1970), caused minor folding, faulting, and local unconformities which are primarily observed along the southern margin of the basin on Melville Island (Stephenson et al., 1987; Davies and Nassichuk,
1991; Harrison, 1995).
During the late Middle Permian, the extensional tectonics ended, leading to a phase of slower, post rift crustal subsidence that was driven by thermal contraction and sediment loading (Stephenson et al., 1994). This phase continued relatively uninterrupted until the Middle Jurassic, filling the basin with several kilometers of siltstones and shales
(Stephenson et al., 1992; Embry & Beauchamp, 2008). Most notable of these Mesozoic strata are the shales of the middle and upper Triassic Schei Point Group because of their source rock potential (Embry et al., 1991).
By the Early Middle Jurassic, rift activity related to the initiation of the Amerasia
Basin to the northwest began to affect the development of the Sverdrup Basin. The
opening of the Amerasia Basin is suggested to have caused the counter clockwise
rotation of northern Alaska and adjacent northeastern Russia away from the Canadian
Arctic (Embry & Dixon, 1994; Stephenson et al., 1994). Continued rifting to the north
created a narrow positive rift shoulder, the “Sverdrup Rim", separating the Sverdrup
Basin from the embryonic Amerasia Basin (Meneley et al., 1975; Embry, 1992). The
6
development of this high created a minor, intermittent sediment source along the northwest margin of the Sverdrup Basin (Embry, 1992; Embry & Beauchamp, 2008).
During the Early and Late Cretaceous, ongoing rifting in the proto Amerasia
Basin peaked with seafloor spreading and the creation of oceanic crust. Timing of the onset of sea floor spreading and opening of the Arctic Ocean is still speculative (Grantz et al., 2011), however, paleomagnetic analysis indicates that initiated no later than the latest Valanginian to Hauterivian (Halgedahl & Jarrard, 1987). In the Sverdrup Basin, the opening of the Arctic Ocean is evidenced by regional uplift (Embry & Dixon, 1990,
1994) and widespread igneous activity (Embry & Osadetz, 1988).
The regional uplift created a number of related unconformities including the late
Valanginian to early Hauterivian, mid Berremian, and the mid Aptian (Emrby & Dixon
1990, 1994). Of these unconformities, the most notable is the Valanginian Hauterivian, which Embry & Dixon (1994) refer to as the "Break Up Unconformity", interpreted to represent the onset of sea floor spreading and the creation of oceanic crust in the adjacent
Amerasia Basin. The timing of the Break Up Unconformity is further supported by stratigraphic and paleomagnetic reconstructions by Grantz et al. (1998).
Between the Valanginian to Cenomanian, tholeiitic basalts, sills, and dykes, interpreted as continental flood basalts (Ricketts et al., 1985; Embry & Osadetz, 1988;
Estrada & Henjes Kunst, 2004), infiltrated the Sverdrup Basin from the north. Basalt flows spread as far west as Amund Ringnes Island, and associated dykes and sills extended as far southwestward as Melville Island (Figure 5). These igneous rocks are evidence of a High Arctic Large Igneous Province, possibly related to a mantle plume hot spot (Tarduno et al. 1998, Harrison et al., 1999), which formed a major volcanic
7
edifice known as the Alpha Ridge over the track of the active hot spot during the opening of the Arctic Ocean (Forsyth et al., 1986; Embry & Osadetz, 1988). This model is further supported by the radiating dyke swarm focused on northern Axel Heiberg and Ellesmere
Islands (Buchan & Ernst 2006).
During the Late Cretaceous to Paleogene, alkaline volcanics were emplaced on
North Greenland and northern Ellesmere Island (Trettin & Parrish 1987, Embry &
Osadetz 1988, Estrada & Henjes Kunst 2004). Felsic volcanics of the Hansen Point
Formation extruded during the Campanian mark the cessation of seafloor spreading to the north (Embry & Osadetz, 1988). This resulted in one last pulse of extension and renewed rifting within the Sverdrup Basin which caused an increase in subsidence, sediment loading, and normal faulting in the northern margins of the basin (Balkwill, 1978; Embry
& Osadetz, 1988; Embry & Dixon, 1994; Stephenson et al., 1994).
In its final phase of development, the Sverdrup Basin was uplifted and inverted during the Eurekan Orogeny. This orogenic event occurred in response to sea floor spreading in the Labrador Sea and Baffin Bay which caused the counter clock wise rotation of Greenland relative to North America (Balkwill, 1978). Ongoing movements between these two plates eventually resulted in collision between northeastern Ellesmere
Island and western Greenland (Roest & Srivastava, 1989). The Eurekan Orogeny began
as early as the Late Cretaceous (Balkwill, 1978; Balkwill & Bustin, 1980; Arne et al.,
1998, 2002), with compression peaking during the Middle Eocene (Ricketts &
Stephenson, 1994; Harrison et al., 1999), and ended in the Late Eocene (Roest &
Srivastava, 1989). While many studies have focused on the Eurekan Orogeny, the nature
and timing of this orogenic event are still not fully understood (De Paor et al., 1989).
8
The sea floor spreading history of the Labrador Sea records the relative motion between Greenland and North America and is a key constraint on when the plate movements that later drove the Eurekan Orogenic phase began. Early work in the
Labrador Sea used alkali volcanic rocks of the Alexis Fm. and the deposition of syn rift sedimentary rocks found in NW SE trending half grabens to constrain the timing of initial rifting to the Early Cretaceous (Watt, 1969; Umplebye, 1979). However, more recent work has led to three hypotheses to explain the rifting history of the Labrador Sea:
1) Tectonic kinematic models (Roest & Srivastava, 1989; Srivastava & Roest 1995,
1999) and stratigraphy (Balkwill & McMillan, 1990) support an onset of seafloor spreading in the Labrador Sea at magnetic chron 33n (Campanian); 2) Chian et al. (1995) hypothesize based on crustal seismic velocity characteristics that seafloor spreading started between chrons 31 to 27 (Maastrichtian); 3) Chalmers andLarsen (1995) and
Chalmers & Pulvertaft (2001), on the basis of quantitative modeling of magnetic profiles coupled with seismic reflection data, propose that sea floor spreading began in the
Paleocene at chron 27n (mid Paleocene) because they were unable to identify older magnetic anomalies. Although the timing of the initiation of rifting remains controversial, the general plate motion path for Greenland from chron 27n to chron 25n
(e.g. Roest & Srivastava, 1989; Chalmers, 1991) is relatively well constrained (Figure 6).
By approximately chrons 25 24n (59Ma), a major change in the direction of magnetic anomalies is observed. The new orientation of magnetic anomalies is interpreted as a change to a counter clockwise north northwest rotation of Greenland relative to North America, causing convergence between the two plates. Seafloor spreading in the Labrador Sea ended by the Early Oligocene (Roest & Srivastava, 1989;
9
Chalmers, 1991; Chalmers & Larsen, 1995), coinciding with the cessation of Eurekan compression.
Similar to the uncertainties regarding the opening of the Labrador Sea and Baffin
Bay, the exact timing and nature of the Eurekan Orogeny and its effects on the Sverdrup
Basin are still not fully understood. Several authors (Balkwill, 1978; Balkwill & Bustin,
1980; Miall, 1984; De Paor et al., 1989) agree that Eurekan Orogeny deformation occurred in several phases beginning between the Late Cretaceous and Early Paleocene, and ending in the late Eocene. Others, however, suggest that the Eurekan Orogeny and related deformation occurred later during the late Paleocene and Eocene (Ricketts &
McIntyre, 1986; Stephenson et al., 1990; Lepvrier, 1996; Arne et al., 1998; Tessensohn &
Piepjohn, 1998; Harrison et al., 1999). This lack of agreement raises the level of uncertainty in our interpretations of deformation in the central Sverdrup.
Regardless of the timing, the link between the Eurekan Orogeny and the development of a complex fold and thrust belt in the eastern Sverdrup Basin is generally accepted (e.g., Balkwill, 1978; Roest & Srivastava, 1989). On Axel Heiberg and
Ellesmere islands, where deformation was most intense, the Eurekan Orogeny is characterized by large scale, high amplitude folds, reverse, thrust and strike slip faults, and crustal shortening (Figure 7). The deformation style changes to the west, between the Ringnes and Melville islands, where large uplifts, arches, and low amplitude lithospheric folds dominate (Stephenson, 1990; Embry & Beauchamp, 2008).
1.2 Evaporites in the Sverdrup Basin: Deposition and Evolution
The evaporites of the Sverdrup Basin accumulated during the initial phases of rifting from the Late Mississippian to Middle Pennsylvanian, along the embryonic basin's
10
depositional axis (Davies & Nassichuk, 1975). On northern Ellesmere Island, the
Carboniferous evaporites of the Otto Fiord Fm. are locally exposed and are characterized by bedded anhydrite interbedded with algal limestones. This depositional sequence is interpreted to record a cyclical evolution from open marine to hyper saline subaqueous environments (Davies & Nassichuk, 1991).
The Sverdrup Basin contains at least one hundred evaporite piercement structures
(Thorsteinsson, 1974). These structures are cored by halite at depth (e.g., exploration well Hoodoo L 41), and with the exception of a few cases where halite is exposed at the surface, the majority of piercement structures have a 200 800 meter thick upper cap of gypsified anhydrite (Heywood, 1955; Gould & Demille, 1964; Schwerdtner &
Clark,1967; Davies & Nassichuk,1975). Salt structures are located along the basin axis and are most common in the western Sverdrup Basin on western Axel Heiberg, Ellef
Ringnes, and northeastern Melville islands. The majority of the salt structures are characterized as either large, domal diapirs or thin, tabular diapirs and walls. However, unique to central and western Axel Heiberg Island, the structural style of the evaporite structures changes. Here, salt walls pierce the crests of tight anticlines, which are separated by broader synclinal sub basins in a region known as the "wall and basin structure" (WABS) province (Thorsteinsson, 1974; van Berkel et al., 1984; Jackson &
Harrison, 2006, Figure, 8).
The exact timing and mechanisms behind the initiation of salt movement in the
Sverdrup Basin is still poorly constrained. Geological and geophysical data adjacent to
salt diapirs indicates that these structures were subjected to an episodic and long term
growth dating back to at least the early Mesozoic (Gould & De Mille, 1964; Schwerdtner
11
& Osadetz, 1983; Jackson & Halls, 1985; van Berkel, 1989; Harrison, 1995). Proposed mechanisms for the initiation of diapirism in the Sverdrup Basin include: (1) reactive diapirism caused by rift related extension (Jackson & Harrison, 2006; Boutelier et al.,
2011); (2) differential loading as a result of prograding sediments (Balkwill, 1978;
Jackson & Harrison, 2006); and (3) differential loading above of faulted basement blocks
(Schwerdtner & Osadetz, 1983; Stephenson et al., 1992; Boutelier et al., 2011).
Once diapirism commenced in the early Mesozoic, the evaporites likely continued their ascent powered by continued deposition and differential loading. Eventually, this initiated a phase of active diapirism, where several kilometers of weakened overburden was shouldered aside, allowing salt to continue its upward path to the surface (Balkwill,
1978).
Geophysical data across the central and western Sverdrup Basin provide evidence to suggest that a change in the deformation style occurred during the Jurassic and Early
Cretaceous (Harrison, 1995). Thinned and drape folded units, debris flows, and unconformities along diapir flanks, and salt wings are observed in the Jurassic and
Cretaceous succession in a number of seismic profiles at Hoodoo Dome and other salt structures in the western Sverdrup Basin (Harrison, 1995; Boutelier et al., 2011). These features indicate that passive diapirism became the principal mechanism for diapir development during middle Mesozoic. This phase of passive diapir development was likely in response to vigorous sedimentation and differential loading that occurred during the Jurassic and Early Cretaceous (Ricketts & Stephenson, 1994; Boutelier et al., 2011).
12
Evaporite mobility in the Sverdrup Basin during the Mesozoic was strongly influenced by tectonic processes occurring in the adjacent Amerasia Basin. By Late
Jurassic Early Cretaceous time, the development of the Amerasia Basin to the north of the Sverdrup Basin resulted in several phases of regional uplift and increased sediment supply into the Sverdrup Basin (Embry & Beauchamp, 2008). However, the effect that the far field tectonics to the north had on the salt structures in the Sverdrup Basin vary drastically. On Ellef Ringnes Island, geophysical seismic surveys indicate that by this time, sediments on lapped dome margins ending the passive diapir phase that characterized their development throughout the Jurassic (Boutelier et al., 2011). This differs from the development of salt structures on Axel Heiberg Island to the East, where during the Hauterivian hiatus, far field tectonics are attributed as the cause to salt diapirs unroofing their thin covers, breaking out onto the surface extrusively, and coalescing to form a widespread allochthonous evaporite canopy which was subsequently buried during a phase of rapid subsidence and sedimentation (Jackson & Harrison, 2006; Figure
8).
In the Late Cretaceous Early Paleogene, salt was reactivated and exhumed in response to compressional forces related to the Eurekan Orogeny (Balkwill, 1978; van
Berkel et al., 1984; Embry and Beauchamp, 2008). This orogenic event is interpreted to have caused at least 60 salt structures to pierce their overburden and become sub aerially exposed along the basin axis (Balkwill, 1978). The deformation front related to this orogenic event helps explain the abrupt change from elongate, oval salt structures observed in the east central portion of the basin to the circular salt stocks that are
13
prevalent along the western margins of the basin (Gould and de Mille, 1964; Balkwill,
1978. Figure 3 highlights the regional extent of the Sverdrup Basin’s major salt structures.
1.3 Study Area:
1.3.1 Introduction:
Hoodoo Dome is an evaporite cored, doubly plunging anticline located on the southern margin of Ellef Ringnes Island. Ellef Ringnes is a north south trending elongate island in the Canadian Arctic Archipelago (Figure 9). The northern margin of Ellef
Ringnes Island reaches the northern edge of the Sverdrup Basin (Sverdrup Rim) where the Neogene sediments of the Beaufort Fm. unconformably overlie Triassic Jurassic rocks at the surface. Central and southern Ellef Ringnes Island is bisected by the
Sverdrup Basin's depositional axis, where a conformable succession of Mesozoic strata is exposed at the surface (Stott, 1969; Evenchick & Embry, 2012).
1.3.2 Stratigraphy and Structure:
The stratigraphy exposed at Hoodoo Dome (Figures 2 & Plate 1), and more regionally the west central Sverdrup Basin is dominated by Late Paleozoic and Mesozoic strata (Davies and Nassichuk, 1991).
Upper Paleozoic to Lower Triassic sediments are characterized by deep water, outer shelf, prodelta succession of shales, siltstones, carbonates, and evaporites
(Nassichuk & Davies, 1980; Davies & Nassichuk, 1988; Davies & Nassichuk, 1991). By the Late Triassic, fluvial dominated deltaic sediments and shelf sands of the Heiberg
Formation prograded across the eastern and central portions of the basin, covering the
14
thick prodelta and slope shales and siltstones until the Pliensbachian (Embry, 1982;
Embry, 1991; Embry & Johannessen, 1992).
Following the deposition of the Heiberg Formation, the basin was starved of sediments. During this time (Middle Jurassic Early Cretaceous), shales and siltstones of the Toarcian Aalenian Jameson Bay, Aalenian Sandy Point, Bajocian Callovian
McConnell Island, Oxfordian mid Kimmeridgian Ringnes and Awingak, and the
Kimmeridgian Valanginian Deer Bay formations were deposited (Embry, 1991).
By the late Valanginian renewed tectonism and uplift caused sediment supply into the basin to increase dramatically. As a result, fluvial dominated, deltaic coarse grained sands of the Lower Cretaceous Isachsen Formation prograded across the basin. The
Isachsen Fm. Sits unconformably above the Deer Bay Formation and was deposited until the latest Aptian. From the Late Aptian until the Maastrichtian the basin experienced a number of transgressive regressive (T R) cycles, leading to the deposition of a thick conformable package of Cretaceous sediment (Christopher Fm. shales, Hassel Fm. sandstones, and Kanguk Fm. shales) which are primarily characterized by alternating marine shelf and deltaic siltstones/shales and sandstones (Embry 1991).
Albian to Cenomanian aged igneous activity related to the development of the
Amerasia Basin caused dykes and sills to intrude much of Ellef Ringnes Island (Embry &
Osadetz, 1988). They are abundant at both the surface and in the subsurface, but are primarily concentrated in the Jurassic and Early Cretaceous formations in the northern portion of the Island and within the cores of some salt domes (Stott, 1969; Evenchick &
Embry, 2012). Regional mapping across Ellef Ringnes Island (Stott,1969; Evenchick &
15
Embry 2012) indicates the presence of one of these igneous bodies just southwest of
Hoodoo Dome, however, our field observations, and the detrital apatite (U Th)/He thermochronology results from these rocks indicate that they are not igneous, and instead are possibly the product of a low temperature hydrothermal vent.
Structurally, deformation on the island consists of large scale regional northwest
southeast trending anticlines and synclines, and ovate, domal evaporite structures. These
structures are primarily oriented perpendicular to the principal stress direction of the
Eurekan compressional deformation, and control the regional distribution of Cretaceous
and older strata across Ellef Ringnes Island (Stott, 1969; Evenchick & Embry, 2012).
A number of salt structures are subaerially exposed on Ellef Ringnes Island which
include, Hoodo , Mallock, Isachsen, Dumbells and Helicopter Domes. In general, these
domes are ovate shaped and, at the surface, their evaporite cores are primarily composed
of anhydrite and gypsum with varying amount of carbonate and igneous rocks. The
evaporite domes to the north of Hoodoo Dome are characterized by steeper dips in the
formations flanking the domes, some of which are overturned (e.g., Isachsen Dome), and
contain visible igneous bodies within their evaporite cores (e.g., Dumbells Dome).
At Hoodoo Dome, numerous structural features are observed both on the surface
and in the sub surface (e.g., Stott, 1969; Boutelier et al., 2011; Evenchick & Embry,
2012; Plate 1). Brittle deformation observed around the dome is controlled primarily by
extensional forces and include normal and tear faults which are oriented in a radial pattern around the dome (Plate 1). This style of deformation is typical around salt
16
diapirs, and forms in response to rock layers bending and stretching during salt's migration to the surface. Ductile folding is common along the flanks of Hoodoo Dome and is likely associated with compressional deformation, which caused the evaporites push towards the surface during the Eurekan Orogeny. Seismic surveys across Ellef
Ringnes Island have identified the presence of rim synclines off the flanks of the domes.
These formed in response to salt's movement out of its parent source bed, which subsequently imitated the down building of surrounding overburden rocks into the void space left behind be the evacuating salt from the source bed (Boutelier et al., 2011).
1.3.3 Hoodoo Dome Field Mapping:
Over a 4 week field season during the summer of 2010, detailed geological mapping and sample collection for (U Th)/He Thermochronology was done across
Hoodoo Dome. The results of the mapping and the locations of collected samples are illustrated in Plate 1.
The detailed mapping primarily focused on the inner core of the dome, and therefore the exposed Early Cretaceous Isachsen, Christopher and Carboniferous Otto
Fiord Formations; additional detailed mapping was done in the Hassel Formation where
(U Th)/He samples were collected and at Cretaceous hydrothermal alteration zones. Poor outcrop quality and variable magnetic declination across Hoodoo Dome ( 20 to 30 degrees) proved to make detailed mapping in the area more challenging and at time, measured orientations taken in the field were deemed unreliable. As a result, photo satellite imagery was used to augment and better constrain the accuracy of the field
17
mapping, and to help determine the magnetic declination and any associated measurement errors.
Hoodoo Dome is heavily a deformed ovate domal structure, where the eastern and western regions of the dome are separated and offset by a southwest northeast trending normal wrench fault. Stratigraphically, both sides of the dome exhibit similar depositional histories, however, the two sides of the dome are structurally dissimilar.
The western arm of the dome is characterized as an east west trending anticlinal structure with a surface exposure of the Carboniferous Otto Fiord Formation evaporites in the far western flank of the arm. At the surface, the evaporite piercement is approximately 1km in diameter, and primarily composed of gypsum, anhydrite, and selenite, with minor amounts of allochthonous carbonate and sandstone rocks. The Otto
Fiord Formation evaporites are in contact with the Lower Cretaceous sandstones of the
Isachsen Formation and shales of the Lower Cretaceous Christopher Formation. The contact between the Carboniferous evaporites at the core of the dome and the Cretaceous rocks at the surface is interpreted to be faulted. The Isachsen and Christopher formations flanking the western arm of Hoodoo Dome are typically dipping between 20° and 40° away from the core of the dome. The ≈20° dispersion that observed in the measurements along each limb can likely be attributed to the poor outcrop quality and the potential effects of frost heaving which is common in freeze thaw environment in the High Arctic.
The main east west trending anticline which characterizes this side of the dome may possibly indicate the dome's original, pre Eurekan orientation. A number of
18
additional smaller scale anticlines and synclines are present within the Paterson Island
Member of the Isachsen Formation in the western arm of the dome, and their general orientations parallel the E NE to W SW orientation of the main anticline that characterizes the western arm of the dome.
Normal faults are also observed in the western arm of Hoodoo Dome. These faults have an apparent northeast southwest strike slip displacement and are primarily found surrounding the exposed Otto Fiord Formation evaporites at the surface. However, these faults are interpreted to have developed and ceased during the late Early Cretaceous as normal faults associated with evaporite mobilization, which were later tilted by diapir rise and/or Eurekan deformation, an even which is reflected in their surface expression of lateral strike slip movement.
Eastern Hoodoo Dome is characterized by a north northwest south southeast oriented anticlinal structure. This anticline is likely part of the more regional
Meteorologist Anticline, which defines the regional structure of southern Ellef Ringnes
Island. The orientation of this anticline is such that it is perpendicular to the principal stress direction of the Eurekan compressional forces, and therefore, likely reflects the deformation associated with this orogenic event. The Otto Fiord evaporites are not exposed at the surface in this part of Hoodoo Dome. The dome flanking beds in eastern
Hoodoo Dome dip away from the core of the dome at dip angles similar to those observed in the western arm of the dome, with the exception of the of the steeply dipping beds in the northernmost exposed Isachsen Formation, and to the far east at the contact between the Christopher and Hassel Formations.
19
In the east, the overall number of faults increases. Fault traces in the eastern section of Hoodoo Dome produce a radial pattern that is perpendicular to the strike of the bedding. Similar to those in the western arm of the dome, these faults are interpreted to be of normal offset. The timing of when movement along the majority of these faults is constrained by the structural/stratigraphic relationships, where the fault traces are truncated within and do not extent beyond the late Aptian early Albian Christopher
Formation. Therefore the movement along these faults occurred during the late Early
Cretaceous. However, some faults were active after the Christopher Formation was deposited, as reflected in the offsets observed in the Christopher Hassel Formation contact. The overall number and density of faults in this region of the dome is higher than it is in the west. This may be a reflection of more intense salt movement and migration under this part of the dome during the late Early Cretaceous. The large wrench fault that separates the two sides of the dome may also have affected on the preferred deformation styles and types observed on both sides of the dome.
This mapping project also led to the discovery of additional rock outcrops of significant geological importance. Mapping within the Christopher Formation south of
Hoodoo Dome led to the discovery of a number of additional chemosynthetic methane seep mounds. Originally, only one methane seep mound had been observed where the
Christopher Formation shales juxtapose the evaporites in western flank of Hoodoo Dome.
The findings of the additional seeps prompted additional exploration at Hoodoo Dome and across southern Ellef Ringnes Island for others. These seeps are currently being studied at the University of Calgary by Krista Williscroft and Benoit Beauchamp. This
20
work also led to the discovery of 2 magnetite iron pyrite rich hydrothermal alteration zones, one located within the Christopher Formation shales southeast of the core of
Hoodoo Dome and the other on the east side of the dome, in an area that was previously mapped as an igneous intrusion. Detailed analysis of these alteration zones are currently being undertaken by staff at the GSC Calgary.
1.4 Sverdrup Basin Petroleum System History:
The Sverdrup Basin is home to one of Canada's largest untapped petroleum resources. Between the 1960s and 1980s the basin received a high level of attention and exploration. However, this effort was short lived and ceased in the late 1980s as a result of declining oil and gas prices. During this relatively short exploration effort, 119 wells were drilled into Mesozoic structures in the west and west central regions of the basin
(Chen et al., 2000). This resulted in the discovery of 19 major petroleum fields occurring within a broad fairway extending from Ellef Ringnes Island, southwest to northeastern
Melville Island (Figure 10). These discoveries host 8 oil and 25 gas pools with a total in place hydrocarbon reserve of 1.85 BBbls (billion barrels) of crude oil and 17.7 TCF
(trillion cubic feet) of natural gas (Chen et al., 2000), where natural gas makes up
approximately 75% of the known reserves (Jones et al., 2007).
Ten of these hydrocarbon fields are located within close proximity to Hoodoo
Dome, off the southwestern coast of Ellef Ringnes Island, and nearby King Christian
Island. Almost all known discoveries occur within salt cored, structural traps.
In the central regions of the basin, the majority of oil and gas accumulations are
found in the thick, and widespread Upper Triassic to Lower Jurassic, porous sandstone
units of the Heiberg Formation, and are sealed beneath the thick shales of the Toarcian
21
Jameson Bay Formation (Nassichuk, 1983). Additional minor reservoir rocks include the
Early Cretaceous sandstones of the Isachsen and Hassel formations. Hydrocarbon accumulations are primarily sourced from the Triassic Shei Point Group shales (Murray
Harbour and Hoyle Bay formations), with additional accumulations from the Jurassic
Ringnes and Deer Bay Formations (Brooks et al., 1992).
Thermal maturity of the Sverdrup Basin’s source rocks are described by numerous authors (e.g., Goodarzi et al., 1989; Gentzis et al., 1996; Gentzis & Goodarzi,
1998; Dewing and Obermajer 2011). The maturity pattern of the source rocks mimic the general depositional fill patterns of the Sverdrup's two sub basins. Therefore, it is characterized by less mature rocks along the basin’s margins that become increasingly more mature towards the deposition axis of the basin (Figure 11). Due to a thicker sediment package and more heavily impacted by igneous activity during the Cretaceous, the Sverdrup's eastern sub basin is more thermally mature compared to the western sub basin. The basin’s primary source rocks, the Triassic Shei Point Group shales are in the main gas window in the eastern Sverdrup Basin, whereas in the western sub basin, these same rocks reach thermal maturity levels to only within the mid to late oil windows
(Figure 11). At Hoodoo Dome, where this study is focused, the basin' Triassic source rocks sit on the boundary between the oil and gas windows (Figure 11). Additional, more minor source rocks deposited during the Jurassic are found stratigraphically higher in the section than the Triassic source rocks and therefore, their thermal maturities are lower.
22
2.0 DETRITAL APATITE (U-TH)/HE THERMOCHRONOLOGY:
2.1 Introduction and Methods:
Apatite (U Th)/He thermochronology is a relatively new low temperature
thermochronometer used to help constrain the timing and magnitude of cooling and
exhumation of rocks as they approach the Earth's surface due to deformation and
denudation (Farley et al., 1996; Wolf et al., 1996; House et al., 1997; Farley, 2002; Ehlers
& Farley, 2003; Reiners & Brandon, 2006). (U Th)/He dating technique was first carried
out by Rutherford (1904 & 1905) who recognized the relationship between the production of 4He alpha particles and parent uranium and thorium isotopes.
(U Th)/He dating relies on determining the ratio between the concentration of the daughter product 4He, which accumulates in mineral grains (e.g. zircon and apatite) by means of alpha decay, and the concentration of its parent isotopes 238 U, 235 U, 232 Th, and
147 Sm. These radioactive isotopes are found in measurable concentrations in minerals
such as apatite, zircon, titanite, and monazite; minerals that occur in many felsic igneous
rocks, and which due to their resistance to physical and chemical weathering, are preserved as detrital grains in clastic sedimentary rocks.
The measurable quantity of 4He within an apatite grain is controlled by the grain's
thermal history. 4He is lost by diffusion at temperatures between ≈ 40 and 70°C. At temperatures greater than ≈70°C 4He rapidly diffuses from the grain, however, at temperatures below ≈40°C the 4He diffusion system completely closes relative to geological time and 4He is entirely retained within the apatite's crystal lattice. Between 40
and 70°C, a temperature zone known as the Partial Retention Zone, 4He is only partially
retained (Wolf et al., 1996; Farley, 2002). Within this temperature zone, the rate of
23
diffusion becomes complicated by the physical and chemical properties that are unique to each individual apatite grain. The effects that these varying properties have on 4He diffusion rates within apatite are discussed in detail below.
Therefore at temperatures greater than 70°C, 4He produced is lost from the grain, resulting in a zero 4He age. At temperatures below 70°C 4He begins to accumulate and
therefore produces an age that correlates to the cooling. As a result, this dating technique
can provide temporal constraints on an apatite grains thermal cooling evolution.
The diffusive behavior of helium within apatite makes (U Th)/He dating of
apatite the lowest temperature thermochronometer known and provides geologists with a powerful tool for revealing the thermo tectonic evolution of rocks through the uppermost
1 3km of the Earth's crust. For example, this method is commonly used to help constrain
the timing, amounts, and rate of cooling/denudation associated with mountain building, basin subsidence, crustal deformation, volcanism, and landscape evolution (e.g., House et
al., 1997; Ehlers et al., 2003; Cecil et al., 2006; Flowers et al., 2008). For this study, (U
Th)/He thermochronology was used on detrital apatite grains to help improve
understanding of Hoodoo Dome’s thermo tectonic evolution.
The production of 4He (α particles) is defined by the following helium in growth
equation:
4He=8 238 U (e ʎ238t – 1) + 7/137.88 238 U (e ʎ235t – 1) + 232 Th (e ʎ232t – 1)
Where 4He, 238 U and 232 Th are the present day concentrations, t is the
accumulation time or the 4He age, and λ is the decay constant for each element
24
(λ238=1.55x10 10 yr 1, λ235=9.849x10 10 yr 1, λ232=4.948x10 11 yr 1). The preceding coefficients of the U and Th concentrations accounts, for the multiple α particles emitted during each decay series. Because the 235 U/ 238 U ratio is constant and equal to 1/137.88, the measurement of only one is needed, and thus the concentration of 238 U used (Farley,
2002). 4He ages produced from the equation assume the following conditions:
1) Secular equilibrium between all daughters in the decay chain. This means that
the decay rate of each daughter nuclide in the decay chain is equal to its parent. Under
most circumstances this assumption is correct, however, intermediate daughter nuclides
may be fractioned from other daughter nuclei during the early stages of mineral growth.
As a result, the decay of each parent isotope does not equal the number alpha particles
indicated in the previously mentioned equation, thus, producing an incorrect (older)
helium age. Regardless of the initial conditions, secular equilibrium is attained after
approximately 5 half lives of the longest lived intermediate nuclide experiencing
fractionation. For (U Th)/He dating, the longest lived daughter of the 238 U parent isotope is 234 U which has a half life of 2.48 x 10 5 years. Consequently, the (U Th)/He
thermochronology technique is limited to samples older than approximately 1.25 million
years old (Farley, 2002). Because secular equilibrium is reached after ≈ 1.25 million
years, it is not considered a potential factor for any resulting age variations in this study, because the apatites used in this study are sourced from rocks no younger than the Early
Cretaceous.
2) This equation assumes that the initial amount of 4He present in the crystal is
zero, which is typically a valid assumption given the rapid diffusion of helium at
temperatures higher than ~75°C. However, there are alternate sources of 4He. One
25
possible source for initial 4He, is 4He found in the atmosphere. Atmospheric 4He concentrations are very low (≈5 ppm), essentially making it an insignificant factor in the resulting helium age. Fluid and mineral (e.g., zircon) inclusions can contribute additional sources of initial 4He, and during the degassing stage of analysis, may contribute additional helium, resulting in an older helium age (Farley et al., 2002). These potential problems are avoided by selecting inclusion free grains during the picking process.
3) The derived cooling ages assume that U and Th zonation within the mineral structure is negligible. Zonation of U and Th would affect the distribution of 4He in the mineral grain and could therefore render the Ft correction, which assumes a homogenous
U and Th distribution (discussed later), invalid. Correcting a zoned grain for ejection related 4He loss could lead to anomalously older (U and Th concentrated in the core of
the grain) or younger (U and Th concentrated in the rim of the grain) cooling ages.
Heavily zoned apatites are very uncommon, and therefore, it is normal practice to assume
zonation is a not major factor in the resulting helium age.
4) 4He implantation or the "Bad Neighbor” problem as Taylor and Fitzgeral
(2010) refer to it as, occurs as a result of 4He diffusion from one radioactive grain to an adjacent grain. If the correct circumstances exist, implantation results in parentless 4He, and anomalously old cooling ages. Although theoretically possible the bad neighbor problem is less likely to be a concern in detrital samples, like those analyzed in this study because the likelihood of two accessory mineral phases (low amount of apatite in sandstones) being deposited adjacent to one another is extremely small.
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2.1.1 He Diffusion in Apatite:
The rate at which radiogenic 4He diffuses out of minerals is determined primarily by temperature, but is also affected by a mineral's composition and crystal structure. As a result, each radioactive mineral (i.e. apatite, zircon, monazite) has a unique 4He diffusion rate (Reiners & Brandon, 2006). Because the 4He diffusion system within apatite is
thermally active/closed, it is extremely important to understand: 1) What temperatures are
required for 4He diffusion in apatite, and how 4He diffuses out of apatite; and 2) At what temperature and why does 4He diffusion cease, allowing 4He to be retained within apatites crystal structure. The temperature at which 4He loss by diffusion becomes
negligible is called closure temperature (Tc).
For apatite, 4He is almost entirely retained at temperatures below 40°C, corresponding roughly to the upper 2 km of the crust. Assuming monotonic cooling at
10°C/Myr, temperatures above ~70 75°C cause 4He to completely diffuse from the grain,
resulting in a He age of zero (Farley, 2000). Between the ~ 40 70°C temperature range,
4He is only partially retained within the crystal structure (5 95% of the total 4He amount); this temperature range is known as the Helium Partial Retention Zone (HePRZ) (Wolf et al., 1998; Farley, 2002). Assuming a typical geothermal gradient of ~25°C/km, the
HePRZ corresponds to a depth interval of approximately 1 3km (Wolf et al., 1996, 1998).
Within this zone, helium ages are extremely sensitive to changes in temperature. As a result, helium age differences on the order of millions of years can occur due to extremely small changes in depth (Farley, 2002). This process is summarized in figure
12.
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Crystal size and radiation damage within grains can greatly affect the rate at which 4He diffusion occurs within apatite (Wolf et al., 1996;Reiners & Farley, 2001).
Both larger grains and grains with higher concentrations of radiation damage will retain
larger amounts of 4He compared to smaller grains or grains with lower radiation damage,
consequently producing older helium ages. The effects of grains size and radiation
damage as well as additional causes for anomalous cooling ages (mineral inclusions,
mineral zonation, etc.) are explained in detail below. It is important to realize that the
affect these factors have on resulting cooling histories become increasingly more evident
under conditions where the cooling rate is slow, or when apatite grains experience a long
residence in the HePRZ (Reiners & Farley, 2001).
2.1.2 α Particle Ejection and Ft Correction:
The energetic decay of parent isotopes 238 U, 235 U, 232 Th, and 147 Sm results in the production of 4He nuclei (α particles). During the decay process, a sufficient amount of
Milli electron volt (MeV) energy is created to propel newly produced helium α particles through a solid crystal lattice, while at the same time causing the parent nuclei to recoil in the opposite direction. The distance traveled by the α particles is referred to as the α stopping distance, and the movement of the parent isotope is termed alpha recoil.
In apatite, the alpha stopping distance is approximately 20µm (Farley et al, 1996).
As a result, diffusion occurring along the outer ≈ 20 µm of the crystal can result in α ejection, a process where 4He α particles are completely ejected from the mineral grain.
The loss of 4He by ejection leads to a lower ratio of helium to U Th and therefore necessitates a correction to obtain accurate cooling ages. The maximum probability of α
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ejection is 50% and only occurs when the parent isotope nucleus is located directly on the grains edge (Farley, 2002).
Grain size greatly influences the fraction of 4He ejected from the grain. In smaller
grains a higher percentage their 4He lost due to α particle ejection, and becomes a great concern in grains that are smaller than 60µm in their minimum dimension (Farley et al.,
1996).
Assuming that alpha ejection is roughly proportional to the surface/volume ratio of the grain being dated and that the distribution of its parent nuclide are homogenous, an analytical α ejection correction (Ft Correction) is used to adjust for the helium loss that occurs along the outmost 20 µm of the grain Farley et al., (1996). If the effects of α ejection are not corrected for, the resulting cooling ages will be anomalously low.
2.1.3 Sampling Strategy:
Surface bedrock samples were collected along two transects at Hoodoo Dome for detrital apatite (U Th)/He thermochronology (Plate 1, Figure 13). Ideally sandstone samples were to be collected at ≈100 200 meter intervals along each surface transect to ensure any minor changes diffusivity can be observed give the estimated 25±5°C/km geothermal gradient (Jones et al., 1989) in the Sverdrup Basin. At this resolution data would be collected at every 2.5°C to 5°C temperature interval, and may also help better our understanding of the geothermal gradient around Hoodoo Dome. Therefore, samples were to be collected from the Lower Cretaceous outcrops of the Isachsen Formation sandstones, sand lenses within the shale dominated Christopher Formation, and sandstones of the Hassel Formation. At Hoodoo Dome outcrop exposure is near 100%, however, in situ material needed for sampling is very limited thereby limited our ability
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to sample every 100 to 200 metres along the surface transects. This is likely the result of the cyclical freeze thaw climate in the Arctic, which, over time degrades bedrock, leaving behind mounds of unconsolidated material at the surface. Also, low lying or level areas are typically covered by thick tundra mats (Tundra Polygons), limiting access.
Outcrop condition and tundra cover limited the number of samples collected from each transect to nine samples each. Additional samples were collected from what we interpret as the remains of a paleo hydrothermal vent which crops out at the southern limit of the western transect. The additional samples were collected to see if there is a thermal signature associated with hydrothermal activity or possible gas venting along the flanks of the dome during the Cretaceous.
2.1.4 Analytical Technique:
After field collection, samples were shipped to the University of Calgary where they were mechanically separated for apatite and zircons by means of standard magnetic and heavy liquid techniques. Once mineral separates were obtained, grain picking and analysis of the apatite and zircon grains was carried out at University of Kansas (U
Th)/He Thermochronology Laboratory.
Individual grains from the apatite separates were hand selected using the following strict picking parameters to minimize analytical error. Using a Nikon SMZ U
Stereomicroscope, grains fitting the following parameters were selected: ≈ 70 and 90 microns (smallest dimension), euhedral, non mitamict, and lacking broken edges and inclusions. In the rare case where no grains meeting the selection criteria were found, slightly smaller, or mitamict grains were used. Digital photographs containing the
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morphometric measurements were taken of each grain and archived, and later used to calculate the alpha ejection correction.
Using a state of the art, all metal, ultra high vacuum noble gas extraction and purification line, single grain apatites selected for analysis and packed in platinum tubes
were degassed by heating to ≈1080 °C for 5 minutes. Each aliquot was then re heated for
re extraction to verify that complete extraction occurred. This step helps to identify any
helium rich mineral inclusions such as zircon, monazite. Whenever possible, three
single grain aliquots were analyzed and dated for each sample location. Helium
degassing results can be found in Table one.
Following helium degassing, samples were sent to the ICP MS Lab at the
University Kansas for U Th Sm analysis. Each aliquot was heated and spiked with a
235 230 149 HNO 3 based solution containing a known amount of U, Th and Sm tracer. The amount of each parent isotope was then measured by isotope dilution using a dedicated fissions/VG Plasma Quad II Inductively couple plasma mass spectrometer. Once the amounts of parent and daughter isotopes were identified, the cooling ages of the apatite grains were calculated using equation above and the Ft correction applied using the measured grain dimensions.
To account for analytical uncertainty, well characterized apatite standards were analyzed alongside the apatite grains from Hoodoo Dome. The reported analytical uncertainties for apatite helium cooling ages are ≈6% (2σ) which is based on the reproducibility of laboratory standards. Whenever possible, 3 single grain apatite aliquots were used for each sample location to test reproducibility.
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2.2 Results:
Apatite helium cooling ages from samples collected at Hoodoo Dome are summarized in table 1. In general, a wide distribution of cooling ages is observed in the apatite (U Th)/He data, with ages ranging from 41.3 to 1606 Ma. These ages pre, syn, and post date their host rock’s 130 110 Ma (Early Cretaceous) depositional age. Only two sample locations, BG 14 35 2 and BG 14 34 4 show a fairly tight distribution of intra sample cooling ages.
Detrital apatite helium ages from the eastern transect of Hoodoo Dome are summarized in Figure 13 and Table one. Seven samples were collected along this transect, which extends east west across the Lower Cretaceous Isachsen to Hassel formations (Plate 1 & Figure 13). However, after examining the mineral separates, only four (3 aliquot) samples were suitable for dating. AHe cooling ages across this transect range from 41.3 Ma to 1606 Ma. The uppermost sample collected from this transect is from a sandstone lens of the upper Christopher Formation (AS 1 108 1), which yielded the following cooling ages: 64.6 ± 3.38, 145.5 ± 8.73, and 225.0 ± 13.5 (Plate 1 & Figure
13). Three samples, AS 1 108 2, BG 14 53 1, and AS 1 108 3 (Plate 1 & Figure 13) from the Walker Island Member sandstones of the Isachsen Formation were dated.
Collectively, their cooling ages are AS 1 108 2 (41.3±2.48, 42.6±2.55, and 1606 Ma);
BG 14 53 1 (80.3±4.82, 273.2±16.4, and 338.6±20.32 Ma); and AS 1 108 3
(103.7±6.22, 168±10.08, and 231±1309 Ma) (Plate 1 & Figure 13).
Along the western transect, nine samples were collected for (U Th)/He thermochronology, however only five were suitable for analysis. The western transect extends north south from the inner core of Hoodoo Dome to the south, across the
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Isachsen, Christopher, and Hassel formations (Plate 1 & Figure 13). Cooling ages from this transect range from approximately 53 to 992 Ma.
The structurally lowest samples were collected from the fluvial deltaic sandstones of the Paterson Island Mbr. of the Isachsen Formation. These samples flank the core of the salt dome and include; BG 14 35 2 (55.6±3.32, 56.4±3.38, and 65.9±3.95 Ma) and
BG 14 34 4 (52.5±3.15, 76.5±4.95, and 79.3±4.76 Ma) (Plate 1 & Figure 13). BG 14 35
2 and BG 14 34 4 have the tightest cooling age distributions of all the samples analyzed.
Sample BG 14 34 1 was collected from the Walker Island member of the
Isachsen Formation (Plate 1 & Figure 13). This sample yielded cooling ages of
465.4±4.76, 225±13.5, and 64.6±3.88 Ma. Farther south along the transect, one sample,
BG 14 45 2 (106.1±6.37, 337±20.23 Ma) was collected from the Cenomanian unconsolidated sandstones of the Hassel Formation. An additional sample, BG 14 45
1(169.8±10.19 991.6±59.5 Ma) was collected from a speculative paleo hydrothermal vent, not far from BG14 45 2. This sample was collected and analyzed to help constrain the timing and extent of thermal anomalies associated with this vent complex.
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2.3 Interpretation and Discussion
2.3.1 Apatite Helium Age Reproducibility:
(U Th)/He thermochronology results from Hoodoo Dome are shown in table 1
and Figure 13. The results show a wide dispersion of cooling ages between sample
locations as well as between aliquots within a sample. The simplest explanation for the
observed variance is that these grains experienced a prolonged residence in the AHe partial retention zone prior to reaching Tc. However, variance of cooling ages can be common in detrital (U Th)/He data sets and can be explained by other processes: Excess
He from U Th rich mineral inclusions, He trapping by radiation damage, inaccurate Ft corrections due to mineral zonation, grain size variability, mismeasured grains and Ft corrections, and lastly He implantation (Farley, 2000; Farley et al., 2002; House et al.,
2002; Shuster et al., 2006). The effect of these factors on apparent cooling ages are further enhanced in detrital systems that have highly heterogeneous detrital mineral populations and or have experienced a long residence time in the partial retention zone
(i.e., slow cooling) (Fitzgeral et al., 2006). The following is a discussion of these influencing factors and their effect on the helium cooling ages at Hoodoo Dome.
Helium Rich Mineral Inclusions:
A likely contributor to the wide dispersion of cooling ages observed in the
Hoodoo Dome samples is the presence of undetected U Th rich mineral inclusions. The helium in growth equation assumes that all 4He is produced from the radiogenic decay of
U, Th, and Sm found within the apatite crystal lattice (Farley et al., 2002). However, apatite grains can often contain micro inclusions of actinide rich minerals such as zircon, monazite and titanite. Of these, zircon is the most common and can contain 10 to 100
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times the U and Th concentration found in apatite, and therefore, produce much higher quantities of helium during radiogenic decay (Wedepehl, 1978). Undetected inclusions lead to excess 4He and, because they are not fully dissolved during chemical dissolution their U and Th concentrations are not measured. As a result, inclusion bearing samples contain excess 4He, and yield anomalously old cooling ages. However, unless the U or
Th concentrations within the inclusions are relatively high, the large disparity in volume between the apatite grain and internal micro inclusion results in minimal excess 4He. As a result, the effect of micro inclusions on the resulting cooling age can be nominal (Farley et al., 2002; Vermeesch, 2008).
To alleviate the inclusion problem, great care was taken during grain selection to ensure that grains with visible inclusions were not used. It can be seen, however, from helium re extractions above background levels (0.003ppm; seen in table 1), that there was some excess helium derived from inclusions or U or Th zonation in a number of grains.
Cooling ages from these grains are therefore interpreted with caution.
Radiation Damage:
The second likely source of cooling age dispersion comes from Tc variations related to varying amounts of radiation damage from grain to grain. Naturally occurring radioactivity can alter a mineral's crystal structure by introducing isolated defects and vacancies. In apatite, these defects are created during α decay. The atomic damage induced by recoil of heavy parent isotopes is known as "fission tracks", and each of which represent the permanent displacement of thousands of atoms. These measurable
"fission tracks" are commonly used for apatite fission track thermochronology.
However, in (U Th)/He dating, fission tracks obstruct the mobility of 4He α particles
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during diffusion. Shuster et al. (2006) refers to these vacancies as “energy wells or traps", from which He α particles must escape prior to diffusion through the crystal structure. The need for additional energy to escape fission tracks requires that the effective closure temperature for radiation damaged grains is higher than that for undamaged grains.
Radiation damage is proportional to the concentration of radioactive isotopes U,
Th, and Sm, and is represented by a quantity known as "effective uranium" or eU
(eU=[U] + 0.235 [Th]). Shuster et al., (2006) and Flowers et al., (2009) found that radiation damage associated with the decay of U, Th and, to a lesser extent Sm, within apatite crystals causes closure temperature to evolve through time.
At temperatures low enough for radiation damage to accumulate, apatite grains with higher eU will produce more radiation damage and "traps". As a result, higher temperatures are required to completely diffuse helium out of high eU grains. Apatites with lower eU concentrations produce fewer energy traps and consequently experience a higher rate of helium diffusion at lower temperatures. Variation of eU can create a range of closure temperatures that vary by up to ±15°C compared to the standard apatite Tc of ≈
70°C (Shuster et al., 2006). Also, apatites subjected to reheating and annealing after accumulating substantial radiation damage are more retentive than expected. This type of scenario is common in detrital systems.
The impact of eU on diffusion kinetics is further enhanced for detrital grains that experience prolonged residence in the partial retention zone. Modeling results from
Shuster et al., (2006), and Flowers et al., (2009) show that when peak temperatures are within the PRZ, there is an enormous variation in predicted (U Th)/He ages that can be
36
correlated with radiation damage (eU). These studies show that apatite grains with lower eU begin to diffuse helium, reducing their cooling ages, at lower temperatures compared to grains with higher eU concentrations. Grains with higher eU are almost completely unaffected by diffusive loss of helium until temperatures above apatite’s closure temperature are attained. As a result, apatite grains with a range of eU from the same sample should result in different grain to grain diffusion kinetics, and that a positive correlation between cooling age and eU should be observed (e.g., Shuster et al., 2006;
Flowers et al,. 2007; Flowers et al., 2009).
To check for correlation between eU concentrations and cooling age dispersion,
(eU) is plotted against the (U Th)/He cooling ages for all samples on Figure 14 and Table
1. These data show no clear correlation between eU and cooling age. Instead, many grains with lower eU yield older cooling ages. Consequently, radiation damage is ruled out as a major contributor to the helium age distribution at Hoodoo Dome.
A lack of correlation between eU and cooling ages could be the result of low eU concentrations across the sample suite, or due to quickly cooled samples. At Hoodoo
Dome, relatively low eU concentrations (below 20 ppm) are seen for the majority of the apatite grains analyzed (Figure 14). Concentrations below 20 ppm are indicative of low levels of radiation damage, and therefore, have little effect on diffusion of helium during decay.
Quickly cooled samples will typically show no correlation between eU and cooling age. However, this is only true for samples that have been fully reset, and therefore, have similar initial ratios of 4He to parent isotopes prior to cooling. Under these circumstances, cooling ages should fall within a narrow range regardless of eU
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because, the grains lacking helium "traps" do not have much time to lose relatively more helium before reaching their own, unique closure temperature. Therefore, the resulting cooling ages should be similar. In non reset detrital systems, where initial grain to grain
4He to parent isotopes ratios are often heterogeneous, the effects of varying 4He to parent isotope ratios overprint any correlation that might exist between cooling age and eU, regardless of cooling rate.
U Th Zonation:
Zonation within apatite's crystal structure is another possible cause of cooling age dispersion. The helium in growth equation (above) assumes that the effects of 4He zonation within the crystal structure are negligible, however, studies (e.g. Farley et al.,
1996; Farley, 2002; Ehlers & Farley, 2003) have shown that zoning of U and Th within apatite can affect resulting cooling ages, and should therefore be taken into consideration.
Zoned apatites with heterogeneous concentrations of U and Th will often lead to problems when correcting for α particle ejection compared to those with typical, homogeneous distributions, resulting in anomalous cooling ages (Ehlers & Farley, 2003).
For example, apatite grains with higher concentrations of U and Th near their rims will lose more helium to diffusion and ejection compared to non zoned apatite grains. Such a zone in apatite would experience significant He loss and yield a younger apparent cooling age. The opposite occurs in zoned grains with high U and Th concentrations in their cores. As a result, applying a typical Ft correction to strongly zoned apatite grains can result in an error of ±33% in the resulting cooling age (Farley et al., 1996).
Because apatite grains are not typically known for strong zoning, expensive SEM
CL imaging analysis that is needed to identify such mineral zonation was bypassed for
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this study. As a result, it is impossible to identify if, and to what extent, U Th zonation had on the resulting helium cooling ages at Hoodoo Dome.
Crystal Size Variations and Mismeasurements:
Crystal size also affects the rate at which 4He diffusion occurs within apatite.
Larger grains have higher effective closure temperatures and typically yield older cooling ages because it takes longer for helium to diffuse through their larger volume (Reiners &
Farley, 2001; House et al., 2002). Under conditions where the cooling rate is slow relative to 4He production, fractional helium loss occurs causing crystals of larger dimensions to retain a higher concentration ratio of 4He than smaller crystals. The effect
of crystal size on helium diffusion rates becomes increasingly more evident the longer an
apatite grain remains in the HePRZ (Reiners & Farley, 2001).
A comparison of cooling age vs. grain size is provided for the samples analyzed at
Hoodoo Dome in Figure 15. Results of the comparison show large a dispersion of data
with no major identifiable trends. While some of the youngest ages are from the smaller
apatite grains tested, other small grains gave significantly older cooling ages.
Conversely, some of the larger grains yielded young cooling ages, whereas other larger
grains yield older helium ages. Although grain size can be correlated with the cooling
ages of some of the apatite grains in this study, its effects on cooling ages for Hoodoo
Dome are not conclusive and not considered further.
Inaccuracies in grain size measurements can cause over or under estimates for Ft
corrections, resulting in unreliable helium ages (Farley et al., 1996). Great care was
taken to minimize measurement errors and therefore mismeasurements are not considered
an important source of the cooling ages dispersion observed in the Hoodoo Dome data.
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Helium Implantation:
Lastly, He implantation, also known as the "bad neighbor problem" (Spencer et al., 2004; Spiegel et al., 2009), can affect cooling ages, and must be considered. This phenomenon occurs when 4He diffusion and α ejection from one radiogenic mineral grain
implants α particles into an adjacent helium grain. During diffusion, α particles travel
through the crystal lattice; ≈20 µm for apatite and ≈19 µm for zircon (Farley et al., 1996).
It is therefore possible for radiation occurring within the outermost 20µm to eject α particles from one radiogenic grain, and implant them into an adjacent grain in close proximity (≤ 20µm). If this occurs, the 4He isotopes received are parentless, resulting in
older (U Th)/He cooling ages. However, in a detrital rock this requires that two
radiogenic grains are deposited and buried adjacent to one another. The likelihood of this
occurring is small, and we do not have a way to determine if this occurred. The bad
neighbor problem is therefore an unlikely and also untestable source of the data
dispersion in this study.
Summary:
The poor reproducibility of the cooling histories at Hoodoo Dome is most likely associated with some combination of undetected U and Th rich inclusions, radiation damage and grain size variation. Although the effects of these factors are quite subtle, with long residence times in the PRZ, their effects on the resulting cooling ages are strongly amplified because small variations in the grain to grain helium diffusion kinetics caused by these factors have a large amount of time over which to accumulate an effect.
These problems must be taken into account when the data are interpreted, but they also provide important constraints on the thermal history of the rocks in question.
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2.3.2 Partial resetting and cooling through the PRZ
The detrital apatite grains analyzed in this study have undergone at least one phase of 4He diffusion and accumulation, and are likely sourced from regions with
varying cooling histories and concentrations of U and Th parent isotopes. Therefore, it is
assumed the resulting cooling ages correspond to one of the following: 1) source region
exhumations cooling ages (if apatite was derived from a pluton or from deeply buried
clastic or volcanic rock); or 2) ages totally reset or partially reset by sedimentary or
tectonic burial and reheating prior to their most recent exhumation (Guest, 2004).
Apatite grains a greater concentration of He relative to their U, Th, and Sm parent
isotopes indicate older cooling ages compared to grains with lower concentrations of 4He.
At Hoodoo Dome, the apatite grains with cooling histories equal to or older than their
Sverdrup depositional age indicate that these grains were never fully reset after their deposition in the Sverdrup Basin. It is interpreted, therefore, that the formations these grains were derived from experienced sub ≈70°C maximum paleotemperatures during their residence in the Sverdrup Basin. We interpret the sub 70°C temperatures to be a result of shallow (less than 3km) burial, assuming a typical paleo geothermal gradient of
≈25°C/km. In contrast, the younger, Late Cretaceous and Cenozoic, cooling ages provide evidence that some grains experienced significant amounts of helium diffusion, and indicate they were exposed to temperatures greater than 40°C. Combined, these interpretations indicate that the formations analyzed for (U Th)/He thermochronology experienced a burial to temperatures at least within, but not greater than, the apatite helium partial retention zone (≈40 70°C).
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In the partial retention zone, variations in closure temperatures and helium inheritance between individual grains can result in a significant dispersion of cooling ages. Formations analyzed for AHe thermochronology at Hoodoo Dome were deposited in the Sverdrup Basin during the Early Cretaceous to earliest Late Cretaceous (130 110
Ma). After deposition, these strata experienced increasing temperatures as a result of burial throughout the remaining Mesozoic and early Paleogene (Balkwill, 1978;
Stephenson et al., 1994; Embry & Beauchamp, 2008; Boutelier et al., 2011).
As a result, the apatite grains from these formations continued to accumulate helium until they reached temperatures where helium diffusion rate surpassed the rate at which 4He was produced by α decay. With continued burial and increasing temperature, the rate at which helium is lost by diffusion also increased, until eventually, the diffusion rate within some grains was such that the 4He concentration decreased and lowered their
(U Th)/He age.
The results from this study show that only a portion of apatite grains analyzed at
Hoodoo Dome reached temperatures, and thereby diffusion rates, high enough to reset their helium clocks to or nearly to zero. The young cooling ages associated with these grains lost the majority of their detrital 4He by diffusion during their residence within the
Sverdrup Basin. Today the cooling ages associated with these grains reflect only the 4He concentration they have since retained after cooling following maximum burial and denudation in the Sverdrup Basin. Apatite grains that yield older cooling ages indicate a surplus of 4He than what is expected from 4He accumulation since their deposition in the
Sverdrup Basin. This is probably a result of only partial 4He diffusion or grains with 4He rich micro inclusions.
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While closure temperature (Tc) is the temperature at which diffusion is essentially negligible, it is also the temperature that needs to be exceeded to re initiate substantial diffusion and gas loss (Dodson, 1973). Consequently, significant 4He diffusion will initiate in apatite grains with lower Tc earlier and at lower temperatures than those with higher Tc. Therefore, we interpret that the apatite grains with younger helium ages at
Hoodoo Dome had lower closure temperatures, enabling significant 4He diffusion sooner and at lower temperatures compared to the apatite grains with older resulting cooling ages. Additionally, in thermal systems where cooling rates are relatively slow, apatite grains with lower Tc will continue significant 4He diffusion longer because they must
cool to or beyond their low Tc compared to grains with higher Tc. As a result, during periods of slow cooling, apatite grains with lower Tc will diffuse helium for a longer
duration compared to grains with higher Tc, reducing their resulting cooling age.
2.3.3 Impact of Salt Structures on Cooling Histories:
Salt has a thermal conductivity 2 4 times greater than that of typical sedimentary
rocks (Lerche & O'Brein, 1987). As a result, salt structures play an important role in the
evolution of sedimentary basin thermal histories. In the subsurface, salt acts as a conduit
for heat transport, both vertically and horizontally. High heat flow in salt can create
anomalies in the geothermal gradients above and adjacent to salt structures. These
anomalies are observed at salt structures around the globe, such as the Emba region of
Russia (Dzhangir'yantz, 1965), offshore Nova Scotia (Rashid & McAlary, 1977), and
offshore Louisiana in the Gulf of Mexico (Vizgirda et al., 1985).
Synthetic tests and numerical modeling show that salt in the subsurface
concentrates and disperses heat, creating positive heat anomalies over salt, and negative
43
anomalies beneath it. Results of numerical modeling on diapirs in the Gulf of Mexico show that above salt, the positive heat anomaly can be as much as ≈30°C (Vizgirda et al.,
1985; Yu et al., 1992). However, the magnitude of the temperature disturbances depends on the size, shape and depth of the salt diapir (Yu et al., 1992).
At Hoodoo Dome, only two samples show significant diffusion of He for all aliquots analyzed. These two samples (BG 14 35 2 and BG 14 34 4) are extremely close to the exposed evaporite at the surface of the core of the salt dome (within 400m), are from oldest exposed units, and were probably buried deepest (Plate 1 & Figure 13). As a result, these samples likely experienced higher paleotemperatures than samples collected at other locations. Because they are closest to the core of the dome, the anomalous geothermal gradients around salt may have also played a role in their thermal evolution.
Thermal maturity studies using vitrinite reflectance and Rock Eval data in the
Sverdrup Basin provide evidence to support this hypothesis. These studies suggest maximum paleotemperatures of strata are higher above and directly adjacent to diapirs, compared to the same strata further away from the salt structures cores (Gentzis &
Goodarzi, 1993; Gentzis & Goodarzi, 1998). If these anomalies exist around Hoodoo
Dome, they could be partially responsible for the younger, clustered cooling ages derived from BG 14 35 2 and BG 14 34 4. This data set does not, however, provide enough evidence to determine if, and to what extent, the evaporites at Hoodoo Dome controlled the thermal histories experienced by these apatite grains.
2.3.4 Summary of Apatite (U Th)/He Thermochronology Interpretations:
Based on the evidence provided above, we interpret the widespread dispersion of cooling ages at Hoodoo Dome to represent a relatively cool and protracted history within
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the partial retention zone. The older helium ages are likely the combined result of higher closure temperatures, partial diffusive loss of inherited helium, and undetected helium rich mineral inclusions. These results provide key evidence to suggest a shallow, low temperature burial of Lower Cretaceous rocks at Hoodoo Dome (Figure 13). In contrast, grains yielding younger post Early Cretaceous cooling ages indicate that these grains experienced temperatures at least within the partial retention zone and had lower closure temperatures, and therefore, enabled significant diffusion and helium loss, resetting them prior to cooling in the Sverdrup Basin (Figure 13).
For these reasons, the Campanian to Lutetian (≈80 41 Ma) cooling ages are interpreted as representing fully reset grains. If this is true, their cooling is probably related to the onset and development of deformation, uplift, exhumation, and erosion related to Eurekan tectonism. However, it is equally important to realize that all of the cooling ages presented here are a product of the helium diffusion kinetics within apatite, and therefore even the interpreted fully reset grains could be a result of partial resetting, partial resetting in addition to 4He rich micro mineral inclusions, or fully reset grains with
4He rich micro inclusions.
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2.4 Implications for Geologic History:
The interpretation presented in the previous section implies that the post Early
Cretaceous thermochronological cooling ages are related to significant diffusion followed by a period of cooling. These results provide important information regarding the thermal and tectonic evolution at Hoodoo Dome.
The wide dispersion of cooling age data provide excellent evidence to suggest the
Lower Cretaceous Isachsen through Hassel formations were buried to a shallow depth, likely between 2 3 km, into a fossil partial retention zone. The maximum paleotemperatures for these formations are partially constrained to less than ≈70°C, as indicated by numerous grains which did not appear to be fully reset. Most important in the data suite are the post depositional cooling ages between approximately 80 41M. If these cooling ages are representative of fully reset, inclusion free, apatite grains, they provide the first ever quantitative thermochronologic dataset to help constrain the timing of cooling and associated tectonics in this region of the Sverdrup Basin. We interpret the helium ages to indicate the possibility of two separate phases of cooling, one during the
Campanian (80 76Ma), followed by second phase which initiated by the earliest
Paleocene (≈ 65 Ma), continuing until at least the middle Eocene (≈ 41 Ma).
2.4.1 Campanian Cooling:
The Campanian cooling ages at Hoodoo Dome range from approximately 80 76
Ma and are found in two samples from the Paterson Island and Walker Island members of the Isachsen Formation (Figure 13). The Campanian is characterized as a transitional period between a long phase of tectonics related the development of the Amerasia Basin to the north and the onset of active tectonics between the North American and Greenland
46
Plates. During this time the black shales of the Kanguk Formation were being deposited across much of the Sverdrup Basin (Embry, 1991). Also during the Campanian, igneous activity related to the cessation of seafloor spreading to the north, and the onset of tectonics to the east have been shown to have affected localized regions in the Sverdrup
Basin. Presently, these dates are some of the first pieces of evidence suggesting previously unrecognized tectonic activity in the Sverdrup Basin at this time; correlating them to a specific geological event, however, is difficult.
Igneous activity within and nearby sedimentary basins can affect the results in detrital thermochronology studies. During the Campanian igneous activity in the
Sverdrup Basin was localized on northern Axel Heiberg and Ellesmere Islands (Trettin &
Parrish, 1987; Embry & Osadetz, 1988), over 400 kilometers northeast from Hoodoo
Dome. Therefore, the spatial relationship between Hoodoo Dome and this phase of igneous activity is such that the thermal effects of these igneous bodies would not have affected the thermal fields beyond the localized area on northern Ellesmere and Axel
Heiberg Islands.
Deformations' ability to cause uplift, exhumation and erosion is typically the main cause for cooling in detrital systems. By the late Cretaceous, movement between North
America and Greenland plates was well underway, however, the exact nature, timing and the effect these plate movements had on the Sverdrup Basin is poorly understood. A number of authors suggest that deformation related to the tectonics between these two plates began by the Late Cretaceous (Balkwill, 1978; Balkwill & Bustin, 1980; Miall,
1986; Mclytryre & Ricketts, 1989), fragmenting the Sverdrup Basin into a series of sub
47
basins and intervening upwarps and arches (Balkwill, 1978; Miall, 1981). The time of uplift for these arches is stratigraphically constrained to have occurred between the Late
Cretaceous (Campanian Maastrichtian) to Paleocene on Princess Margret Arch, where non marine sandstones of the Eureka Sound Fm. (Paleocene Miocene) lie unconformably on rocks as old as the Triassic (Balkwill, 1978).
Alternatively, the Campanian cooling ages could be a reflection of the compressional tectonics related to the development of the Canadian Cordillera. During the Campanian, compressional forces caused large scale deformation throughout much of western North America. To date, there is no direct evidence in the Canadian Arctic
Islands to suggest the tectonics to the west had an effect on the Sverdrup Basin.
At Hoodoo Dome, the Campanian cooling ages are not complemented by ground based geology. If the cooling of these rocks was related to uplift and exhumation, then a
Campanian unconformity should be present at Hoodoo Dome.; however, according to
Balkwill and Hopkins, (1976) there are no documented unconformities that would suggest a Campanian uplift at Hoodoo Dome. During the Campanian, black shales of the
Kanguk Fm. were being deposited. This formation appears to be conformable, and is described as a black bituminous rich shale at its base that gradationally transitions into a silt rich shale in its upper section (Balkwill & Hopkins 1976). However, west of Ellef
Ringnes Island, on northern Banks Island and Eglinton Island, the Kanguk Formation becomes increasingly more rich in sand (Jutard & Plauchut, 1973; Plauchut & Jutard,
1976; Miall, 1979). On Banks Island, the Kanguk Fm. is defined by a 15m thick sand and sandstone zone in its uppermost section (Jutard & Plauchut, 1973). On Eglinton
Island, the Kanguk Fm. is characterized by shale in the lower member, which transitions
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into approximately 50m of sands, sandstones, and conglomerates in its middle member before transitioning to shale, silty shales and sandstones in the upper member (Plauchut
& Jutard, 1976). The presence of these sandstones and conglomerates provides possible stratigraphic evidence which suggests the Sverdrup Basin was being tectonically modified during the Campanian, resulting in an influx of sands which form the middle and upper members of the Kanguk Formation.
Detrital (U Th)/He thermochronology results from a small number of apatite grains collected from well cuttings across the western Sverdrup Basin also indicate a
Campanian/Maastrichtian cooling event (Anfinson, 2012). This data is in agreeance with our Campanian cooling ages. Combined, these two datasets provide evidence to suggest a cooling event during the Campanian. It is therefore hypothesised that a previously unrecognized tectonic event, which resulted in uplift and cooling across the Sverdrup
Basin, occurred during the Campanian.
In summary, the Campanian cooling ages at Hoodoo Dome are enigmatic in the sense that they cannot be associated with any known geological thermal event; however, these dates have been interpreted to represent the timing of an unknown Late Cretaceous tectonic cooling event.
2.4.2 Cenozoic Cooling:
The Cenozoic cooling ages at Hoodoo Dome are interpreted to be related to
Eurekan compressional tectonics. During this time, a shift to the onset of major compressional tectonics between northeastern North America and western Greenland initiated (Balkwill, 1978; Ricketts & McIntyre, 1986; Roest and Srivastava, 1989;
Ricketts & Stephenson, 1994). Opinions are divided as to when deformation related to
49
the convergence between these two plates actually began, but the general consensuses are that it initiated sometime between the late Paleocene and early to middle Eocene
(Riediger et al., 1984; Stephenson et al., 1990; Lepvrier et al., 1996; Saalmann et al.,
2005).
Plate kinematic reconstructions using magnetic anomalies in the Labrador Sea and
Baffin Bay have been used to better understand the tectonic relationship between North
American and Greenland plates (e.g., Roest & Srivastava, 1989; Chalmers, 1991) The results of these studies illustrate that the general movement of Greenland was moving away from North America in a north northeast direction during most of the Paleocene.
However, by magnetic anomalies chron 25 24 (≈ 57 Ma) the Greenland plate began moving back towards the North American plate in a northwestern direction (Figure 6).
This movement is interpreted to have initiated the compressional deformation of the
Eurekan Orogeny. The magnitude of movement in this direction peaked by chron 21
(≈ 49 Ma), which has been interpreted as the climax of the Eurekan compressional tectonism (Roest & Srivastava, 1989). The results from plate kinematic model studies are further supported by numerous structural and stratigraphic observations in the eastern
Sverdrup Basin (e.g., Ricketts & Stephenson 1994; Lepvrier, 1996).
According to these plate kinematic reconstruction models, the initial movement of
Greenland relative to North America produced almost entirely sinistral, strike slip movement along the Nares Strait during the Paleocene. Detailed structural fault kinematics from eastern Ellesmere Island (Lepvrier, 1996; Saalmann et al,. 2005) provide additional evidence to suggest that a phase of sinistral strike slip and transpression
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tectonics dominated the eastern Sverdrup Basin during the Paleocene, and that major compression did not occur until the middle Eocene.
In addition, stratigraphic observations across the eastern Sverdrup Basin, on
Ellesmere and Axel Heiberg Islands, suggest that the compressional phase of the Eurekan deformation did not occur until after the Paleocene. The presence of Paleocene strata overlain with an angular unconformity by lower Miocene rocks north of Makinson Inlet on eastern Ellesmere Island indicates that southern Ellesmere Island was not affected by compressional forces until after the Paleocene (Riediger et al., 1984). During the Eocene the deposition of the Buchanan Lake Fm. conglomerates and the development of several syntectonic, intermontain sub basins across Ellesmere Island constrain the earliest signal of regional crustal failure in eastern Sverdrup Basin between the latest Paleocene to middle Eocene (Miall, 1979, 1984; Ricketts and McIntyre, 1986, Rickets & Stephenson,
1994)
Results from thermochronology studies across the basin indicate that significant cooling associated with Eurekan compressional tectonics began by the earliest Paleocene, which is much earlier than what is suggested by the studies mentioned above. While the results are limited to a few localities across the eastern and central Sverdrup Bain, the (U
Th)/He thermochronology results from Hoodoo Dome in this study are in general agreement with Apatite Fission Track (AFT) thermochronology dating results across northeastern Ellesmere Island from Arne et al. (1998; 2002).
The AFT dating results from Arne et al. (1998, 2002) combined with the
structural/stratigraphic relationships in Arne et al. (1998) provide a regional thermo
stratigraphic dataset across the northeastern Sverdrup Basin. The combined results from
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these studies constrain the onset of cooling related to the Eurekan compressional deformation to the Cretaceous Paleocene boundary (Figure 16). AFT cooling histories from these studies indicate an average weighted mean of 66 ± 3 Ma for the onset of cooling associated with basin inversion during the Eurekan Orogeny. At Hoodoo Dome, the apatite (U Th)/He cooling ages indicate the phase of Eurekan cooling initiated between the late Maastrichtian and Danian (≈ 65 Ma) and are in agreement with the timing of initial Eurekan Cooling as indicated by the results in Arne et al. (1998, 2002).
These results suggest that the deformation causing exhumation and cooling on Ellesmere
Island transferred across the basin approximately 400 kilometers west to Hoodoo Dome simultaneously.
The contemporaneous timing of cooling across such a regional scale is may be related to the Sverdrup Basin's thick underlying salt layer. Because salt is mechanically weak compared to most other sedimentary rocks, it could have acted as an incompetent, lubricated detachment zone during Eurekan compression. In the Sverdrup Basin, the
Carboniferous Otto Fiord Fm. evaporites decouple the upper Paleozoic and Mesozoic strata from the lower Paleozoic "basement" rocks. Under compression, a basal salt décollement usually has a lower friction coefficient which enables a greater basinward migration of the deformation front, compared to deformation zones in non evaporite basins (Davis & Engelder, 1985; Hudec & Jackson, 2007). Because salt structures are weaker than other parts of the basin, regional compression causes their roofs to shorten more easily compared to more competent adjacent areas of thicker overburden. As a result, during shortening, pre existing structures are typically amplified by arching of their roofs due to salt migration. The timing at which this occurs can be prior to, or
52
contemporaneous with thin skinned deformation in the more competent, overlying, sedimentary layers (Letouzey et al., 1995).
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3.0 1-D BASIN MODELING:
3.1 Introduction:
Burial and thermal maturation history modeling, and hydrocarbon generation and
expulsion analysis form the foundation of resource assessment. To better understand the
implications for hydrocarbon exploration potential at Hoodoo Dome, source rocks were
characterized, and a one dimensional burial and thermal history of Hoodoo Dome was
reconstructed using BasinMod 1 D software (Platte River Associates®). Using the
equations of back stripping and tectonic subsidence on the stratigraphy, lithology and
temperature data from wells, BasinMod 1 D is able to reconstruct the burial and thermal
history of a specific location within a basin (Ungerner et al., 1990).
At Hoodoo Dome, BasinMod 1 D was used to carry out a burial and thermal
reconstruction model on Hoodoo H 37, an oil and gas exploration well just south of
Hoodoo Dome, along the hinge of the Meteorologist Anticline (Plate 1). Results from
this analysis were used to identify the major source rocks; hydrocarbon generative potential, kerogen type, timing of maturity, and the time, rate, and quantities of
hydrocarbon generation and expulsion.
While BasinMod 1 D is a useful tool for modeling and testing assumptions
regarding the Sverdrup Basin’s petroleum system, it is important to remember that the
outcome of the model is directly related to the validity of the initial geological
assumptions and input data. As a result, this model is probably not a unique solution.
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3.2 Methods:
To reconstruct the burial and thermal history of Hoodoo H 37, input parameters including the stratigraphy, lithology, source rock characteristics (TOC & kerogen type), timing of hiatuses, and erosion estimates, are entered into a master spreadsheet
(Appendix 1). Where well data are missing, nearby wells, surface geology (Evenchick &
Embry, 2012), and published seismic (Boutelier et al., 2011) were used and correlated to fill in data gaps.
Prior to acquiring a thermal maturity model from which the timing of maturity
and hydrocarbon generation can be derived, temperature modeling is. Temperature
modeling provides the burial history model with the boundary temperature conditions
required to meet both present day and paleotemperatures (Luc Rudiewizc et al., 2007).
Bore hole temperature and vitrinite reflectance data provided the present day and
maximum paleotemperatures used to cross check and constrain the modeled temperature
through time.
To reconstruct the thermal maturity evolution at Hoodoo Dome, the parameters of
crustal transient heat flow through time and the amount of unknown sedimentation and
subsequent erosion were estimated based on geological assumptions. Transient heat flow
estimations within the Sverdrup Basin are poorly constrained. The heat flow value of
46+/ 5 mW/m 2 as reported by Jones et al. (1989) for the Sverdrup Basin was used as the
initial and final transient heat flow values.
The model generates a depth vs. thermal maturity curve from the input parameters, which is then cross checked against the measured data from the Hoodoo H
37 well. If the model and measured data are inconsistent, estimated paleo heat flow and
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thicknesses of eroded sections are varied until the model results matched the measured present day temperatures and paleo maturity data. The estimated transient heat flow was modified a number of times at Hoodoo Dome until the modeled temperature data matched the measured maturity data. If the present day transient heat flow was used, the model generated a temperature curve that predicted a maximum paleotemperature lower than the measured Ro data. To adjust for this, the transient heat flow was elevated to 53 mW/m 2 (Figure 17) during the early Cretaceous (≈ 95 Ma), tapering back to 46.5 mW/m 2 by (≈ 70 Ma). This was done to reflect the widespread igneous activity observed across much of the Sverdrup Basin related to the rifting in the Amerasia Basin to the north
(Embry & Osadetz., 1988).
Once the thermal maturity model at Hoodoo Dome H 37 was in agreement with measured data, the model was then used to reconstruct the burial and thermal history for
Hoodoo H 37. A summary of the heat flow parameters used are illustrated in Figure 17 and appendix 1.
During basin and thermal reconstruction, BasinMod 1 D accounts for the following through time:
1) Compaction: Falvey and Middleton Method
Compaction and porosity corrections are essential to burial and thermal history reconstructions. While compaction has no effect on the absolute degree of maturity at present day, it can significantly affect the estimated timing of maturation, generation, and expulsion of hydrocarbons. Compaction is mainly a result of loading (mechanical compaction), but can be further complicated by over pressuring, cementation, and diagensis within rock units. Because data regarding these complication factors are not
56
available at Hoodoo Dome, the Falvey and Middleton Compaction correction method was used. This method only considers the effects of mechanical compaction based on empirically derived relationships from porosity depth data for specific lithologies. The model assumes that the thicknesses of sediments and rocks are reduced by a predictable amount according to the lithology and depth of burial using the following equation:
= + Where: P= porosity (%), Po = initial porosity (%), K= compaction factor adjusted for varying compressibilities of different lithologies (M 1), and z= depth (m). The varying lithologies used by the compaction correction are found in table below.
Lithology Po Compaction factor (K)
Sands 40 50% 1.5 2.0 km 1 shale 50 70% 2.0 2.5 km 1
2) Permeability: Modified Kozeny-Carman (Ungerer et al., 1990)
The intrinsic permeability is calculated as a function of porosity Φ using a modified Kozeny Carman relationship. This method is used because the classical
Kozeny Carman law would have underestimated the permeability of the low value porosities of the compacted shales in the Sverdrup Basin.
. − ≥ . = < 0.1 −
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2 Where: K = permeability (m ), Φ = porosity (dimensionless), and S O = specific surface
area of the rock (m 2).
3) Total Subsidence:
The total subsidence in a basin is a combination of subsidence due to tectonics and subsidence due to sediment loading. The process used to determine the amount of load induced subsidence related to tectonic forces is isostatic backstripping. This method removes sediment layers, correcting for de compaction, fluctuation in sea level and sea depth, and, assuming Airy isostacy, adjusts for isostatic rebound. Paleowater depths and sea level fluctuations were not included in the burial history modeling for Hoodoo Dome
H 37 because it is assumed that the estimated water depth during the modeled time interval reached a maximum of approximately 250 m (Stephenson et al., 1987).
Therefore, it is assumed that the effects of water loading on the model is negligible. The following equation was used to calculate the effects of load induced subsidence:
− = − ∆ − − ∆ − − Where: Y=depth of basement corrected for sediment load, S= total thickness of sediment
column corrected for compaction, ρ m = average mantle density, ρ s = average sediment
density, ρ w = average water density, ∆SL = change in elevation of mean sea level, and W d
= paleo sea depth
Once the load induced component of total subsidence is known, the amount of tectonic subsidence can also be determined (Allen and Allen, 1990). Results of this computation are displayed on back stripping subsidence curve (Figure 18).
4) Heat Flow:
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Transient heat flow, rather than static heat flow, was chosen for this model because it takes into account the heat capacity of different rock units, which results in more accurate thermal modeling. By using this method, sudden changes in heat flow do not result in sudden changes in the thermal profile, but will be smoothed out over time depending on the heat capacity, or thermal inertia, of the rock. BasinMod calculates transient heat flow using the transient diffusion equation to describe the thermal conduction and convection of the heat flow. Because BasinMod 1 D® is a one dimensional modeling tool, it assumes that heat flow is transferred by vertical conduction, and neglects lateral heat influences using the equation below. This could potentially be problematic if there was a high lateral heat flow related to the adjacent salt diapir.
= +
Where: T=temperature (K), k= thermal conductivity (W/m*°C), c=heat capacity
(kJ/m 3*°C), t= time (Ma), ρ = density (g/cm 3), and Q = heat generation (mg/g TOC) and
x = depth (m).
5) Kerogen Type and Maturity:
Utilizing the generative amounts of hydrocarbons and CO 2 from Rock Eval
Pyrolysis, Hydrogen and Oxygen Index values were determined and plotted on modified
van Krevelen diagrams after Peters (1986) and Peters et al., (2005) to characterize the
Basin’s source rock kerogen types.
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Predicted maturation and timing of hydrocarbon generation and expulsion are based on the Lawrence Livermore National Library (LLNL) vitrinite and kerogen kinetics. The maturation stages and their corresponding vitrinite reflectance values are as follows: 0.0 0.5 %Ro = immature zone, 0.5 0.7 %Ro = early mature (oil), 0.7 1.0 %Ro = mid mature (oil), 1.0 1.3 %Ro = late mature (oil), and >1.3 %Ro = mainly gas generation.
7) Hydrocarbon expulsion:
The rate and timing of hydrocarbon expulsion is estimated by the saturation method. This method is based on expulsion occurring when generation continues beyond a porosity saturation threshold. Because the porosity threshold for the major source rocks within the Sverdrup Basin has not yet been determined, the default threshold value for shales (0.20) was set for each of the Sverdrup's major source rocks.
3.3 Data-Sets and Input Parameters:
3.3.1 Thermal Model:
3.3.1.1 Hoodoo Dome H 37: Present and Paleo Temperature Data
Measured temperature data from Hoodoo Dome H 37 were important datasets
used to help validate the modeled temperature curve used in the burial and thermal
history reconstruction of the well. While the measured temperature data from the well
are not actual input parameters to the modeling, these data provide key constraints on the
temperature curve used to model the thermal history at Hoodoo Dome. The measured
temperature datasets were used to help identify to what extent the modeled temperature
60
curve needed to be modified in order to meet the well's paleo thermal maximum, while also meeting the present day thermal properties of the well. Bottom hole temperature data was used to constrain the present day thermal properties at the well, whereas the measured vitrinite reflectance (Ro%) data was used to constrain the models thermal maximum.
3.3.1.1.1 Bottom Hole Temperature Data:
Present day bottom hole temperature (BHT) data was provided in Hoodoo Dome
H 37 at six depths and provides the model with an estimated present day temperature curve (Figure 19). This temperature curve was used to help determine how the modeled temperature curve would be modeled to best meet the present day thermal properties of the rocks at Hoodoo Dome H 37.
3.1.1.1.2 Thermal Maturity Data "Vitrinite Reflectance":
Two hundred and eighty nine vitrinite reflectance measurements were conducted on 23 well cutting samples from Hoodoo Dome H 37 by Geo Optics Ltd. and Pan Arctic
Oils Ltd. Results from these analyses were obtained from Dewing et al. (2007), and were used to help validate the thermal maximum temperature the rocks in this well reached.
Vitrinite reflectance (%Ro) is a technique used to measure the reflectance of vitrinite particles that occur in organic matter. It is used in Devonian and younger rocks to determine the thermal maturity of organic matter. From the well cuttings at Hoodoo
H 37, kerogen was isolated from its sedimentary host rock and was fixed into an epoxy on a slide or plug and then polished. Using a microscope, the ratio of the intensity of light reflected from the polished kerogen plug and the intensity of the light source is used to determine the reflectance value. Reflectance is essentially a function of the index of
61
refraction and the index of absorption of the material and the media (Botstick & Alpern,
1977; Baskin 1979; Ting, 1991). Lower Ro% values indicate lower levels of maturity whereas higher Ro% indicates higher levels of maturity. These values are often correlated with burial depth and thickness of the current or previous overburden.
Predicted maturation values are based on the Lawrence Livermore National Library
(LLNL) vitrinite and kerogen kinetics. The maturation stages and their corresponding vitrinite reflectance values are as follows: 0.0 0.5 %Ro = immature zone, 0.5 0.7 %Ro = early mature (oil), 0.7 1.0 %Ro = mid mature (oil), 1.0 1.3 %Ro = late mature (oil), and
>1.3 %Ro = mainly gas generation
3.3.2 Stratigraphy and Lithology:
The stratigraphic and lithology input data include the present stratigraphic
thickness, lithology, and absolute ages. The formation thickness and absolute ages for
Hoodoo Dome H 37 were obtained from Dewing & Embry (2007). The primary
lithology for the formations was derived from data and descriptions in Balkwill (1978),
Embry (1991), and Embry and Beauchamp (2008). Wireline logs were used to estimate
specific lithology composition at Hoodoo Dome (wireline log data accessed using
Geoscout).
Hoodoo Dome H 37 is an exploration well just south of Hoodoo Dome (Plate 1),
and was chosen for the burial and thermal modeling because it is the most complete,
deepest penetrating well with the most reliable thermal maturity data in the region. The
well is drilled to a depth of 3374 meters and contains a sedimentary package from the
Lower Cretaceous Christopher Formation to the middle Upper Triassic, Barrow
Formation. The thermal maturity of Hoodoo Dome H 37 is well constrained by 289
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vitrinite reflectance analysis that span across its entire depth interval (Dewing et al.,
2007; Figure 20).
3.3.3 Timing of Uplift:
The timing of uplift used in the model is based on the (U Th)/He
thermochronology interpretations discussed in the previous chapter. Based on those
interpretations, two possible phases of uplift and exhumation are interpreted to have
occurred at Hoodoo Dome between the Late Cretaceous and the middle Eocene. The
earliest of these uplift events was during the Campanian between 80 and 76 Ma, where
exhumation caused an estimated 300m of section to be eroded away. While the
Campanian cooling event is enigmatic, additional detrital apatite (U Th)/He
thermochronology data (Anfinson, 2012) and the presence of sands in the Campanian
Kanguk Fm. to the west (e.g., Miall 1979) provide some additional evidence to suggest
that uplift during this time is reasonable assumption. As a result, a Campanian hiatus and
erosional event (80 76 Ma) was used to indicate the first phase of uplift in the basin
modeling at Hoodoo Dome. This was followed by a brief depositional period during the
Maastrichtian, where several hundred meters of marine clastic material of the Eureka
Sound Formation were deposited (Miall, 1981) before another interpreted uplift event
that lasted between approximately 66 to 41 Ma. This second phase of cooling at Hoodoo
Dome is interpreted to reflect the main compressional phase of the Eurekan Orogeny between Ellesmere Island and Greenland. During this cooling event, and estimated
1000m of sediment were eroded away. This estimated eroded section is partially
constrained of the known thicknesses of the remaining Christopher, Hassle, Kanguk, partial constraints on the Eureka sound Fm. from surface mapping (Stott, 1969;
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Evenchick & Embry, 2012; Plate 1), seismic (Boutelier et al., 2011), and nearby well data (Geoscout). The remaining eroded section is partially constrained by the (U Th)/He results and thermal maturity data of the well, which indicate that additional thicknesses of these rocks would have resulted in a higher number of reset apatite grains and higher vitrinite reflectance values within the Cretaceous section.
3.3.4 Source Rocks and Source Rock Potential:
The source rocks in the Sverdrup Basin have been studied by numerous authors
(e.g., Brooks, 1992; Goodarzi et al. 1992; Mukhopadhyay et al. 1997; Gentzis &
Goodarzi 1998). This study focuses on the four primary potential source rocks in the
Sverdrup Basin, which include: the Middle to Late Triassic Murray Harbour and Hoyle
Bay Formations of the Shei Point Group, and the Jurassic Ringnes and Deer Bay
Formations. Rock Eval Pyrolysis geochemical analysis and vitrinite reflectance datasets were obtained from Obermajer et al. (2007) and Dewing et al. (2007), and provided key information necessary to properly evaluate the petroleum potential of the source rocks listed above.
3.3.4.1 Source Rock Characterization and Generation Potential:
For decades Rock Eval pyrolysis has been used to better understand the quality, quantity, type, and degree of maturation of organic matter in sedimentary rocks (Espitalié et al. 1977). Across the Sverdrup Basin, pyrolysis experiments were conducted on the
Murray Harbour, Hoyle Bay, Ringnes, and Deer Bay Formations using Delsi Rock Eval
II and Rock Eval VI units equipped with a Total Organic Carbon analysis module. The results from these analyses are reported in Obermajer et al., (2007).
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Detailed summaries of the Rock Eval pyrolysis methodology can be found in
Espitalié et al. (1977) and Peters (1986). However, a brief overview of the technique is described below.
Results from Rock Eval pyrolysis are achieved by heating powdered samples of potential source rocks in a furnace for a set period of time at specific temperatures. As the rocks are heated, four basic measurements are taken to determine the type and maturity of organic matter and the potential of a given source rock.
During the first stage of heating (300°C for three minutes in an inert helium atmosphere), the amount of free hydrocarbons in the sample (i.e. the amount of already generated hydrocarbons within the sample) is volatized and the corresponding parameter
(S 1 peak) is measured by a flame ionized detector (FID). During the second phase of pyrolysis, the decomposition of kerogen occurs as the oven temperature is increased at a
rate of 25°C/min to a temperature of 600°C. Throughout this phase, the FID detects and
measures the amount of hydrocarbons generated by thermal cracking of non volatile
organic matter (S 2 peak). The temperature measured at the apex of the S 2 peak provides
the temperature at which the pyrolytic yield of hydrocarbons reaches its maximum
(Tmax). Tmax is a reliable indicator of maturity for immature to mature rocks, provided
the rock generates enough hydrocarbons during pyrolysis. The amount of CO 2 generated between temperatures of 300 390°C defines the S 3 peak. Finally, total organic carbon content (TOC) of a source rock is calculated using the S 1 and S 2 peaks with the percentage of carbon in CO 2 generated during oxidation at 600°C.
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The results from the Rock Eval Pyrolysis done on the Sverdrup's primary source rocks (Obermajer et al., 2007) were used in this study to help determine their kerogen type and petroleum generating potential.
The type of kerogen in the rock is illustrated using the Hydrogen Index (HI, where HI=[100*S2]/TOC) versus the Oxygen Index (OI, where OI=[100*S3]/TOC) modified van Krevelen diagram (Peters, 1996). Kerogen types produced from organic matter within the source rocks are classified into three categories (Tissot and Welte,
1984). Samples that have a high ratio of hydrogen to carbon (high HI) signify kerogens of type I and II and correspond to lipid and protein rich organic matter, which is typical of marine organisms and algae. Kerogens of type III are typified by a high ratio of oxygen to carbon (high OI), corresponding to remains of terrestrial plants and inert organic material (residual organic matter). Type I and II kerogens generate most of the world's oil when subjected to burial temperatures between 60°C and 160°C, whereas Type III kerogens typically generate natural gas. Type I kerogens can yield up to 80 wt.% hydrocarbons during pyrolysis, corresponding to an HI of 800 mg/g TOC; whereas type
II kerogens typically yield between 50 60 wt.% hydrocarbons or an HI of 500 600 mg/g
TOC; and finally, type III kerogens typically yield15 30 wt% hydrocarbons at most (HI of 150 300 mg/g TOC).
Additionally, data from Rock Eval Pyrolysis were used to help identify the generation potential for the major source rocks of the Sverdrup Basin. Total organic carbon (TOC, wt. %) and the potential yield of source rocks provide a better understanding of a source rocks total generative potential. While organic richness (TOC) alone is a very important constraint on a rocks generative potential, it alone is not a clear
66
indicator of a rock's petroleum generating potential. As pointed out by Peters and Casa
(1994), some rocks with high TOC values have very little if any generative potential because the measured organic matter is gas prone or inert. Therefore, plotting TOC vs. petroleum generation potential (S1+S2 values), provides a better prediction of a source rock's potential of generating hydrocarbons.
It should be noted that Rock Eval/TOC parameters are only significant above threshold TOC values. Samples with TOC values less than or equal to 0.3% means that all parameters have questionable significance. For samples with TOC values less than or equal to 0.5%, the significance of their Oxygen Index (OI) become uncertain. As a result, any sample with TOC values equal to or below 0.3% were discarded for the interpretation, and samples with less than or equal to 0.5% TOC were removed when classifying the source rocks organic types (Dewing et al., 2007).
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3.4 Results:
3.4.1 Source Rock Characterization and Generation Potential:
Modified van Krevelen plots of hydrogen index (S2/TOC x 100) verses oxygen index (S3/TOC x 100) are used to classify the dominant kerogen type for potential source rocks (Tissot & Welte, 1978; Bordenave, 1993). These plots illustrate that the primary source strata in the Sverdrup Basin have a range of type I, type II, and type III kerogens, however, appear to be predominately type II or type III (Figures 21 24).
The Triassic Murray Harbour and Hoyle Bay Formations (Figures 23 & 24) show a wide distribution of data in both HI and OI parameters. Geochemistry data from these shales suggests they are primarily composed of type II marine kerogen organic matter, with minor contributions from oil prone Type I and gas prone Type III organic matter
(Goodarzi et al., 1987; Brooks et al., 1992). The lower Upper Jurassic Ringnes shales
(Figure 22), consist of a mixture of Type II marine organic material with some terrestrial type III kerogen organic matter (Stewart et al., 1992). This dataset indicates that the
Upper Jurassic Deer Bay Formation (Figure 21) is composed of primarily gas prone, terrestrial Type III organic matter.
Hydrocarbon generation potential plots (TOC vs. potential yield) for the basin's primary source rocks illustrate a wide range of generative potentials (Figures 25 28). The
Rock Eval data from the Triassic Murray Harbour and Hoyle Bay formations (Figures 27
& 28) indicate similar petroleum generative potentials, which range from poor to excellent, illustrated by the relatively linear distribution of data. Geochemical data from the Ringnes Formation (Figure 26) primarily suggests a fair to very good/excellent generation potential, with minor contributions of data to suggest a poor generative
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potential. Results for the Late Jurassic/Early Cretaceous Deer Bay Formation (Figure 25) suggest a poor to fair petroleum generation potential, with a limited population of data suggesting a good to very good/excellent potential.
3.4.2 Burial and Thermal History Modeling:
3.4.2.1 Temperature Modeling
Temperature modeling at Hoodoo Dome H 37 was only done down to
depths/formations corresponding to the basin's oldest primary source rocks. As a result,
the base of the hydrocarbon rich Shei Point Group shales, the Blind Fiord Fm., was used
as the lower bound for temperature modeling at Hoodoo Dome H 37.
Results of the modeled thermal maturity for Hoodoo Dome H 37 are outlined in
Figure 19. Bottom hole temperature (BHT) and maximum paleotemperature (vitrinite
reflectance) data were used to determine the maturity, and constrain calibrating the
temperature model. The solid black line represents the modeled temperature, and
matches the constraints provided by the max paleotemperature data (white diamonds),
and the present day BHT data (dashed black line) to the deepest data from the well at a
depth of 3300m. Beyond this depth, the modeled temperature curve is no longer
constrained by measured temperature or maturity data from the well and follows a nearly
linear path of increasing maturity. Due to the lack of constraints below 3300 m, the
results of the modeled maturity for formations below this depth may be less reliable.
The modeled maturity ranges from immature in the upper ~1400 meters of the
well, increasing maturity with depth, reaching the main gas window by ~4300 meters
(Figure 19). This temperature curve indicates that the Triassic source rocks of the basin
reached a maximum maturity within the late oil and main gas window, whereas the
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Jurassic Ringnes and Deer Bay Formations only reached maximum maturities to within the early oil window (%Ro < 0.7).
At a number of depths, the calculated temperature model is either lower than or higher than the measured vitrinite reflectance maturity data. In the upper 1700m of the well, the measured Ro values are much higher than the BasinMod 1 D modeled maturity curve. At deeper depths, between 2800 2500m, however, the calculated maturity values are slightly higher than the measured maturity data.
3.4.2.2 Timing of Thermal Maturation, Hydrocarbon Generation and Expulsion:
The simulated burial history shown in Figure 18, illustrates three phases of
moderate to rapid subsidence and sedimentation since the Triassic. The first phase
occurred throughout the Triassic, and was followed by two additional periods during the
Cretaceous. Each phase of subsidence and sedimentation was separated by periods of
lower magnitude subsidence or tectonic quiescence. Additionally, the model illustrates
basin inversion and cooling occurring in the Late Cretaceous and Eocene. The timing of
uplift and cooling is based on the results from the apatite (U Th)/He thermochronology
done at Hoodoo Dome discussed above in chapter 2.
The one dimensional burial and thermal maturity model constructed using
BasinMod 1 D for Hoodoo H 37 provides a fundamental guideline for describing the
maturation and hydrocarbon generation potential of the basin’s source rocks beneath
Hoodoo Dome. Figure 18 summarizes the results of the burial reconstruction and
indicates the hydrocarbon source strata reached their maximum burial by the
Cretaceous/Paleogene boundary. During the Mesozoic, the relatively continuous
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subsidence and deposition eventually caused the Triassic source rocks to enter into the hydrocarbon thermal window by the Early Jurassic, continuing to mature until the Late
Cretaceous. The Jurassic source beds, however, did not enter the oil and gas window until the middle of the Cretaceous (Figure 18; Appendix 2).
The base of the Murray Harbour Formation entered the early oil window at approximately 193 Ma at a depth of ≈2770 meters. This formation continued to mature over the next one hundred million years, reaching the main gas window by approximately
96 Ma and at a depth of ≈5350 m.
The Late Triassic Hoyle Bay Formation entered the early mature window during
the Middle Jurassic (171 Ma). Similar to its older Triassic counterpart, it progressively
matured into the main gas window by ≈88 Ma.
The Jurassic Ringnes and Deer Bay Formations were not buried as deeply as the
Triassic source rocks. As result, these rocks reached much lower thermal maturities, at a
later time relative to their Triassic counterparts. The model illustrates that the Ringnes
and Deer Bay formations did not enter into the oil and gas window until the early Late
Cretaceous. During this time, the Ringnes Fm. entered the early mature window at ≈ 99
Ma, and the Deer Bay Fm. at ≈ 93 Ma. According to the model, the thin overburden prevented both of the Jurassic source rocks from reaching maturity levels beyond the
early mature oil window.
Finally, cooling in the basin occurs during two phases of uplift and exhumation
during the late Cretaceous and middle Eocene as discussed previously. These interpreted
cooling events ended deposition and therefore slowed and stopped any additional
subsidence/load induced thermal maturation at Hoodoo Dome.
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BasinMod 1 D utilizes kinetic modeling, an accurate method for determining the timing and volumes of hydrocarbons generated. This method considers the diversity of composition distribution of the original kerogen and calculates multiple parallel reactions that occur as organic matter undergoes degradation into hydrocarbons in response to maturity (Waples, 1994). The results of the model are summarized in appendix 2 and in
Figures 29 through 32. While the modeling process has uncertainties, the results provide a valuable tool for the evaluation of exploration potential in the area with regards to the quality, quantity, and the thermal maturation of source rocks.
At Hoodoo H 37, BasinMod predicts hydrocarbon generation of the Triassic
Schei Point Group source rocks (Figures 31 & 32) commenced by the Norian (≈211 Ma), and continued until the Miocene (≈19 Ma). The majority of hydrocarbon generation from these rocks took place between ≈140 100 Ma, which was followed by second phase of gas generation between ≈100 50 Ma, as a result of oil to gas cracking.
The Murray Harbour Fm. hydrocarbon generation peaked between 113 108 Ma at ≈ 25 mg/g TOC/My (oil) and ≈ 4.8 mg/g TOC/My (gas). This unit is estimated to have generated a total of ≈350 g/mg TOC (oil) and ≈102 g/mg TOC (gas) (Figure 32 & 36).
Hydrocarbon generation in the Hoyle Bay Fm. peaked between 107 100 Ma at
≈43 mg/g TOC/My (oil) and ≈8 mg/g TOC/My (gas), with total generation estimates of
≈348 mg/g TOC (oil) and ≈82 mg/g TOC (gas) (Figures 31 & 35).
Hydrocarbon generation results from the Jurassic Ringnes and Deer Bay formations predict extremely low generation rates, well below 0.05 mg/g TOC/my for both oil and gas (Figures 29 and 30). These formations are not predicted to generate significant quantities of hydrocarbons as illustrated in Figures 33 & 34 and appendix 2.
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Hydrocarbon expulsion from source rocks is assumed to occur only when both fluid pressure and hydrocarbon saturation within the pore space reach or exceed the critical saturation threshold (Burnham & Braun, 1990; Ungerer, 1990). Expulsion results from BasinMod 1 D are summarized in Figures 37 through 40, and indicate that hydrocarbon expulsion only occurred from the Triassic source rocks at Hoodoo H 37.
The Murray Harbour Formation is predicted to have started expelling hydrocarbons by the early Aptian (≈ 121 Ma), and continued until the Albian Cenomanian boundary (≈ 99
Ma). The expulsion from the Hoyle Bay Formation occurred later, initiating at ≈ 110 Ma, and ceasing by the early Paleocene (≈ 62 ma).
3.5 Discussion:
3.5.1 Source rocks:
Rock Eval data from select formations were used to determine the kerogen type and petroleum generating potential for the Sverdrup Basin's primary source rocks. The wide dispersion of data seen in the kerogen type (Figures 21 24) and generative potential
(Figures 25 28) diagrams is observed for all of the source strata analyzed, but is most prominent in the Triassic rocks.
Most geochemical parameters are a function of both the organic matter (kerogen) composition and the thermal maturity level of the organic matter. Because Hoodoo Dome
H 37 only contained Rock Eval measurements for the Ringnes Formation, a compilation of geochemical data from numerous wells across the western Sverdrup Basin was used to characterize the potential source rocks. As a result, the data dispersion in the plots can likely be attributed to spatial and lateral variations in thermal maturity, and to a lesser extent changes in the depositional facies across the basin.
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Geochemical measurements from Rock Eval Pyrolysis indicate the present day values of a number of geochemical parameters. As source rocks mature, generate, and expel hydrocarbons, measureable changes in their geochemistry occur. Understanding how these parameters change with maturity is essential to properly characterize and evaluate their kerogen types and generative potentials. In mature and over mature rocks that have generated and expelled hydrocarbons, values such as TOC and S 2 are residual,
therefore the present day values are lower than their original. (Peters & Casa, 1994). This
is due to a large percentage of carbon lost during hydrocarbon expulsion and migration.
For example, in over mature rocks, TOC values are typically depleted by greater than
50% (Cooles et al., 1986; Rullerkotter et al., 1988). S 2 values also decrease with increasing generation and expulsion because only a fraction of the original hydrocarbons remain in the source rock to produce the S 2 peak during pyrolysis. Depletion of these parameters can greatly change how source rocks are characterized. During catagenesis
and metagenesis, TOC and S 2 depletions lead to a decrease in the Hydrogen Index
(HI=S 2/TOC) and a reduction of both measured values on the generative potential plots.
The thermal maturity of the Sverdrup Basin's Triassic source rocks has been
studied by numerous authors, including Goodarzi et al. (1989), Goodarzi et al. (1992),
Gentzis & Goodarzi (1998), Dewing & Obermajer (2011). Figure 11 summarizes the
regional thermal maturity of the Triassic source rocks and the location of Triassic well
cuttings used for Rock Eval Pyrolysis. In general, the maturity pattern for these rocks
follows the shape of the basin, which is illustrated by less mature rocks along the basin
margins, which become more mature towards the axis of the basin. This is concordant to
the increasing thickness of the Mesozoic sedimentary package in the basin's center
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(Figures 11 & 4). Ellef Ringnes Island lies on a boundary which separates thermally over mature Triassic rocks in the eastern Sverdrup Basin from less mature rocks within the oil window in the western Sverdrup Basin (Figure 11).
The degree of thermal maturity for the Triassic source rocks (Figures 11 & 18) is likely the main cause for the data dispersion observed in the geochemistry results
(Figures 23,24, 27 & 28). Both the Murray Harbour and the Hoyle Bay formations exhibit the largest data dispersions in the kerogen and generative potential plots relative to the other source rocks characterized in this study. The measured maturity and the modeled thermal history at Hoodoo Dome indicate that these rocks are thermally mature and have generated and expelled significant quantities of hydrocarbons. So, it is not surprising to see changes in their geochemistry (Pesters and Casa, 1994). However, the same cannot be said for the Sverdrup Basin's Jurassic source rocks.
The thermal maturity data for the Jurassic Ringnes and Deer Bay formations across the western Sverdrup Basin indicate that these rocks did not reach optimum maturity levels for significant hydrocarbon generation (Stewart et al., 1992; Gentzis et al.,
1993). The Ringnes Formation ranges from immature on the basin flanks, to mid mature in some areas along the basin. The Deer Bay Fm. is thermally immature across almost the entire western portion on the basin (Gentzis et al., 1993). At Hoodoo Dome, the measured and modeled maturities indicate that the Ringnes and the base of the Deer Bay formations are within the early oil window (Figure 18), and that the upper section of the
Deer Bay Fm. is thermally immature. Therefore, the geochemical results represent non residual, original values, exhibiting minimal dispersion in kerogen type and generative potential (Figures 23,24, 27 & 28).
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A second, but less satisfying explanation, for dispersion in the geochemistry data is variance due to lateral differences in depositional environments between samples.
Lateral facies changes across a basin can affect the biological, dilution, and the preservation properties of source rocks (Peters, 1986; Arthur & Sageman, 1994; Canfield,
1994), altering their geochemistry and the way they are characterized. Because this study
uses Rock Eval data from across the entire Sverdrup Basin (Figure 11), it is very likely
that lateral facies changes do occur. For example, the Ringnes Formation ranges from
type II to type III depending on lateral position within the basin. Along the basin
margins, the Ringnes Fm. is characterized primarily containing a terrestrial type III
kerogen, transitioning into a marine type II kerogen towards the basin axis (Gentzis et al.,
1996). However, due to the low density of detailed stratigraphic analysis needed to fully
understand these stratigraphic changes, it is impossible for us to quantify how and to
what extent any stratigraphic variations affected the legacy geochemical results used in
this study. The fact that the data distribution is relatively continuous and linear for
samples from Triassic source strata, suggests that the observed variations are an artifact
of thermal maturity and significant hydrocarbon generation.
3.5.2 Thermal Maturity and Temperature Modeling:
As previously mentioned, there are inconsistencies between the measured present
day and maximum paleotemperatures and BasinMod's modeled thermal maturity for
Hoodoo Dome H 37. At a number of depths the modeled temperature curve is either
slightly lower or higher than the actual measured temperature data.
The discrepancies observed in the upper several hundred meters of the well
(Figure 19) are likely related to the extremely cold annual mean surface temperatures,
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and the presence of permafrost in the first several hundred meters (350 – 400m) of the well. These conditions introduce complications that make it difficult for modeled maturity to meet the measured data in the upper several hundred meters of the well.
Similar complications have been identified by numerical modeling studies in the West
Siberian Basin, where results indicate that permafrost can affect temperature modeling results in the upper 1.5 km of the sedimentary section by up to 10 17°C (Galushkin,
1997; Galushkin et al.,1999).
In the upper 1000m of the well, the measured and modeled data do not match, with the measured Ro values anomalously high, compared to the modeled maturity curve.
Based on the estimated amounts of eroded overburden, the Christopher and base of the
Isachsen formations appear to have slightly higher than expected Ro values. In the Arctic
Islands, anomalously high thermal maturity data are common, and often attributed to either igneous intrusions, however, salt's thermal conductive properties, and mature, recycled detrital material have also been speculated to cause anomalously high thermal maturity (Gentzis, 1991; Gentzis & Goodarzi, 1998 ).
The majority of atypically high Ro values in Sverdrup Basin wells can largely be attributed to Early Cretaceous igneous intrusions (Gentzis, 1991). Raymond &
Murchison (1991) and Dewing & Sanei (2009), have shown that the spatial relationships between the igneous sills and elevated values of thermal maturities are correlated in many wells across the basin.
However, the depth maturity plot for Hoodoo Dome H 37 (Figures 20) indicate the absence of igneous intrusions at Hoodoo Dome ( Dewing et al., 2007). While there is an absence of igneous intrusions in Hoodoo Dome H 37, regional surface mapping and
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nearby wells indicate the presence of Cretaceous sills across Ellef Ringnes Island
(Dewing et al., 2007; Evenchick & Embry, 2012). These igneous bodies however, are typically found in the Jurassic shales, increasing the thermal maturity of only the Jurassic rocks they intrude (Figures 41 & 42). So, while intrusions within the Jurassic strata exist in the area, they cannot be correlated with the anomalously high Ro values of the
Cretaceous rocks in Hoodoo Dome H 37.
New evidence from surface mapping (Evenchick & Embry, 2012) has identified igneous intrusions in Cretaceous rocks on Ellef Ringnes Island, though these are not identified at the surface nor in the subsurface (Boutelier et al., 2011) at Hoodoo Dome.
This does however lead to the possibility that future research may show there to be igneous intrusions in the shallow subsurface below Hoodoo Dome, which may have affected the local maturity.
As discussed in chapter two, salt's high thermal conductivity properties can also alter thermal fields in sedimentary basins. Salt structures are often associated with anomalously high geothermal gradients (Rashid & McAlary, 1977; Issler, 1984). In the
Sverdrup Basin, high geothermal gradients associated with evaporite diapirs are inferred to cause abnormally high T max values (Gentzis & Goodarzi, 1998). Therefore, it is possible that a high geothermal gradient associated with the salt at the core of Hoodoo
Dome could have increased the thermal maturity of these rocks.
Finally, there is some evidence that weather and re working of detrital material
from older, more thermally mature rock into younger, immature strata may yield higher
than expected thermal maturity values in the Sverdrup Basin (Utting et al., 2004). The
Skybattle M 11 well to the west, on Lougheed Island shows (Figures 41 & 11) increasing
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Tmax values moving up the well between the Jurassic Deer Bay Formation and the Early
Cretaceous Isachsen Formation. The resulting pattern could be related to higher amounts of thermally more mature recycled material that was being deposited with coarser sediments from the north. Recycling of this sort may account for the anomalously high
Ro data observed in the Early Cretaceous rocks from Hoodoo Dome H 37.
While both igneous intrusions and the increased geothermal gradients associated with salt structures may be valid explanations for higher than expected thermal maturity levels, at Hoodoo Dome, they are not, however, the preferred explanations. The abnormally high Ro values observed in the Early Cretaceous strata of the Christopher and
Isachsen Formations at Hoodoo Dome H 37 are within the early oil window, which corresponds to temperatures greater than or at least 60°C (Hunt, 1996). At temperatures equal to and greater than 60°C, significant diffusion of helium in apatite is expected
(Farley et al., 2002). At Hoodoo Dome, (U Th)/He thermochronology data from the
Isachsen and Christopher formations show no evidence of thermal resetting across the entire sample suite. If the maturity levels for these formations reflect non detrital, maximum temperatures in the Sverdrup Basin, the (U Th)/He data should indicate that all apatite grains experienced significant helium diffusion, fully or nearly resetting their helium clocks. Instead, the (U Th)/He results from Hoodoo Dome indicate that the majority of the grains did not reach temperatures high enough to cause significant helium diffusion. This is supported by the fact that more than half of the grains analyzed yield cooling ages that are older than or equal to their Sverdrup depositional age. Because the thermal maturity of this data is not in agreement with the (U Th) results, the Ro values in the upper sections of the well are likely anomalous, and probably not related to an actual
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thermal event. As a result, these Ro values can possibly be related to detrital material, therefore, the Ro values in the upper 1700m of the well should be evaluated with caution.
At greater depths, the modeled temperature curve indicates a higher thermal maturity than the measured Ro values. Ro values are expected to increase with increasing depth assuming simple burial and thermal regime, however, at Hoodoo Dome
H 37 Ro values between 1800 2500 meters stay relatively constant despite the 700 metre increase in depth.
Suppression of measured vitrinite reflectance data has been recorded in numerous wells across the Sverdrup Basin. Previous studies identified the primary cause for the majority of the Ro suppression in the basin as attributed to contamination of less mature, well cavings from higher sections in the well (Gentzis, 1996; Gentzis & Goodarzi,1998;
Dewing & Sanei, 2009).
While well cavings are the most likely cause for Ro suppression, a number of authors have suggested that hydrogen and bitumen rich organic matter can also suppress
Ro values (e.g., Price & Barker, 1985; Snowdon, 1995; Carr, 2000). In the Canadian
Arctic, hydrogen rich organic matter is said to have caused Ro suppression in
Carboniferous oil shales by as much as 0.4% (Goodarzi et al., 1987).
In summary, the modeled maturity of this study corresponds relatively well with the measured thermal maturity studies in this region (e.g. Gentzis et al., 1992; Gentzis &
Goodarzi, 1998; Dewing & Obermajer, 2011). The primary Triassic source rocks in this part of the basin have experienced thermal maturity levels to the late oil or the main gas
window, whereas the Jurassic source rocks reached the early oil window. The upper
1700 meters of the well are complicated by the extremely cold present day surface and
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subsurface temperatures (permafrost) and the anomalously higher Ro values possibly as a result of recycled detrital material. At deeper levels, the suppressed measured maturity is likely related to contamination from less mature well cavings.
3.5.3 Timing and rate of Generation and Expulsion:
This study indicates that the Triassic source rocks have the necessary types and amounts of organic matter, and have reached thermal maturity levels necessary for significant oil and gas generation. The timing and rate at which source rocks generate and expel hydrocarbons is directly linked to the depositional and thermal evolution of their host basin. Therefore, a temporal relationship should exist between the Sverdrup
Basin's depositional evolution and the rate of hydrocarbon generation and expulsion.
The results from this study suggest that the Sverdrup Basin's Triassic source rocks started generating hydrocarbons as early as the beginning of the Jurassic at Hoodoo
Dome. However, "peak" generation, resulting in the production of large volumes of hydrocarbons, did not occur until the Aptian/Albian (Figures 31,32, and 45), concurrent with the deposition of the Christopher Formation shales. The subsidence/burial history curve for Hoodoo Dome H 37 indicates that prior to and during the deposition of the
Christopher shales, the depositional history of the Sverdrup Basin is characterized by moderate to rapid subsidence (Figure 18). The modeled maturity curve presented in this thesis is constrained by and is in general agreement with a number of subsidence and burial history curves across the central and western Sverdrup Basin (e.g., Goodarzi et al.,
1992; Ricketts & Stephenson, 1994; Stephenson et al., 1994). In particular, the results of this study are very similar to the subsidence curve for numerous wells across Ellef
Ringnes Island which are illustrated in Boutelier et al. (2011). The moderate to rapid
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subsidence indicated by the previously mentioned studies is concurrent with the timing of major hydrocarbon generation, and demonstrates a link between hydrocarbon generation and substantial depositional rates in the basin. This phase of rapid subsidence and sedimentation during the Early Cretaceous is interpreted to have caused the Triassic source rocks to enter the “hydrocarbon kitchen”.
During the Cenomanian, much of the Triassic source rock package became thermally mature, and entered into the main gas generation window (Figure 18). Based on the modeling results, this marked the end of peak hydrocarbon generation for the
Triassic rocks at Hoodoo Dome (Figures 31 & 32). By the end of peak generation, both the Murray Harbour and Hoyle Bay Formations had produced ≈420 450mg/g TOC of cumulative hydrocarbons (Figures 35 & 34; Appendix 2) . Once in the gas window, the hydrocarbons remaining in these rocks were thermally cracked into natural gas and inert residue, leaving behind over mature, essentially exhausted Triassic source strata, with only the ability to generate dry gas. This is shown by the secondary phase of gas generation, reflecting the timing of when the Triassic kerogens were thermally cracked into natural gas, during the Upper Cretaceous (Figures 31 & 32).
While the Jurassic source rocks generated oil and gas during the Late Cretaceous and Early Paleogene, their generation levels are considered to be insignificant (Figures
29, 30, 33, and 34). This is a result of their low maturity levels which reflect their relatively shallow burial and thin cover. At Hoodoo Dome these source rocks are estimated to have reached a maximum burial to less than 3km, corresponding to temperatures no greater than the early oil window (Figure 18). These paleotemperatures
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were too low to generate significant quantities of thermogenic oil and gas, rendering these formations as insignificant source rocks in this part of the basin.
Only the Triassic source rocks generated the quantities of hydrocarbons required to cause expulsion at Hoodoo Dome. Between ~120 Ma and 100 Ma, the hydrocarbon generation in these shales reached and exceeded the porosity saturation threshold set for this model (Figures 39 & 40). Once the saturation threshold was surpassed, any additional hydrocarbons generated were expelled. The insignificant hydrocarbon generation of the Jurassic source rocks was not enough to meet the porosity saturation threshold required to expel hydrocarbons, and therefore, the hydrocarbons generated from these sources remain within their strata.
The results of the modeling at Hoodoo Dome are complemented by the presence of Albian chemosynthetic cold seep communities observed at Hoodoo Dome
(Beauchamp et al., 1989), and across southern Ellef Ringnes Island (Williscroft personal communication, 2012). Sourced at least partially by thermogenic methane, these seeps indicate that hydrocarbon expulsion and thereby generation had occurred no later than the
Albian (Beauchamp et al., 1989; Beauchamp & Savard, 1992). If the methane feeding these seeps is sourced from the Triassic source rocks beneath Hoodoo Dome, which these studies suggest, then the temporal relationship between the modeled timing of hydrocarbon generation, expulsion and development of these cold seep communities are in good agreement.
3.6 Summary:
In summary, the burial and thermal reconstruction model on Hoodoo H 37 indicates that the primary source rocks underlying Hoodoo Dome generated the majority
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of their hydrocarbons during the Early Cretaceous. Only the Triassic source strata generated significant quantities of liquid and gas hydrocarbons. Generation within these rocks exceeded the saturation threshold needed to expel hydrocarbons, resulting in hydrocarbon expulsion by the early Aptian (≈ 120Ma), and continuing until the end of the
Albian (≈ 100 Ma). The presence of Albian methane seeps indicates that vertical migration reached the Christopher Formation at the same time as peak hydrocarbon generation and expulsion as predicted by the model. According to the model results, the
Jurassic sources rocks generated insignificant volumes of hydrocarbons. As a result, they are not considered to be major contributors to the petroleum system at Hoodoo Dome and this portion of the Sverdrup Basin. Figure 45 summarizes the temporal relationships of this areas petroleum system.
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4.0 (U-TH)/HE THEMOCHRONOLOGY, BURIAL HISTORY MODELING AND
SVERDRUP BASIN PETROLEUM SYSTEM:
4.1 Better Understanding the Historical Discoveries:
Successful petroleum systems require geological components such as mature source rock, reservoir rock, seals, migration pathways, and traps. The relative timing of the formation of each of these elements is crucial for hydrocarbons to generate, accumulate, and be preserved.
In the Sverdrup Basin, the successful drilling and exploration efforts between the
1960's and 1980's led to the discovery of a total estimated reserve of 17.7 TCF (trillion cubic feet) of natural gas and 1.85 BBbls (billion barrels) of oil in 19 fields (Chen et al.,
2000). With the exceptions of a minor field on Ellesmere Island, nearly all of the
Sverdrup Basin discoveries occur within a structural play fairway between Melville and
Ellef Ringnes Islands (Figure 10). The discovered fields are found within structurally contained Mesozoic strata associated with both high and low amplitude salt cored, anticlines and 4 way anticlinal closures (Embry et al., 1991).
The discovered fields in the Sverdrup Basin are divided into 3 regions on the basis of their spatial distribution, structural style, and the type and quantities of the hydrocarbons they contain. These regions include an area around Ellef Ringnes Island, a northwest southeast trending region around Lougheed Island, and region in the far western portion of the basin around Melville Island.
Ten discoveries have been made around Ellef Ringnes Island, all of which occur within salt cored anticlinal structures (Figure 10). The discoveries in this region contain natural gas, oil, or a combination of the two. King Christian, Wallis, Sculpin, Jackson
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Bay, and Kristopher Bay fields contain dry gas only; Thor, Char, and Cape MacMillian fields contain primarily gas with minor amounts of oil; Cape Allison field, the only field in this area to contain significant amounts of both oil and gas; and finally, the Balaena field, which contains only highly biodegraded oil (Embry et al., 1991; Waylett & Embry,
1992). Combined, these fields contain an estimated total hydrocarbon reserve of 6.1 TCF natural gas and 0.988 MMBbl oil (Chen et al., 2000). The fields these hydrocarbons are within can be generally characterized as high amplitude structures that are drastically under filled with natural gas.
The structural closures the fields lie within are almost entirely related to the protracted development of the Mesozoic salt structures. In the west and central Sverdrup
Basin, the Early Mesozoic mobilization of evaporites and their continual development in response to subsidence and sedimentation created a range of low amplitude, diapir growth related structures which include: anticlines, domes, drape folds and overturned sediments, stratigraphic pinchouts, rim synclines, salt wings, and canopies (Harrison,
1995; Jackson & Harrison 2006; Boutelier et al., 2011). These structures are thought to have trapped migrating hydrocarbons that were generated and then expelled in the axis of the basin during the Cretaceous, on their way up dip to the basin’s margins (Waylett &
Embry, 1992). Finally, many of these structures were then modified and amplified to their current configuration by deformation associated with Eurekan tectonism (Waylett &
Embry, 1992; Embry, 2011).
Assuming that the data set from this study can be extrapolated to the geologic and petroleum systems around Ellef Ringnes Island, regional assumptions can be made in regards to the previously discovered fields and implications for discovering new fields in
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this portion of the basin. The following sections discuss how the results from this study help us to better understand and explain our current knowledge of the region's petroleum system, and provide us new insights for future exploration.
As previously mentioned, the discovered fields in this region of the basin are almost entirely gas. Source rock characterization and the results of the burial history model at Hoodoo Dome indicate that the major hydrocarbon contributors, the Triassic source rocks, produced significant volumes of both oil and gas. However, the majority of the discovered fields around Ellef Ringnes Island are almost entirely composed of natural gas (Chen et al., 2000). If we assume the existence of vertical migration pathways,
BasinMod 1 D results indicate that generated oil and gas began filling the existing, low amplitude structures in this region by the late Early Cretaceous. With time, the maturity of the Triassic source rocks eventually rose into the late oil and main gas windows, causing these rocks to generate and expel higher concentrations of natural gas.
Based on the observations by Waylett & Embry (1992) and the results from this study, the continued generation of oil and gas from the Triassic source rocks around Ellef
Ringnes Island produced significant volumes of hydrocarbons, enough to fill the low amplitude traps in this region of the basin to spill point. Once full, low density gas proceeded to enter the structural traps, displacing the heavier oil through a process known
as “gas flushing” (Gussow, 1954). This is thought to have continued until the traps were
completely or almost completely flushed of oil (Figure 43). As a result, today, the traps
around Ellef Ringnes Island are filled primarily with natural gas with minor traces of
residual oil, with the exception of the Balaena field which contains highly biodegraded
oil (Chen et al., 2004). This idea has also been suggested by Waylett & Embry (1992).
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The oil that was flushed from these traps experienced a secondary migration, which likely forced it out of the basin center and towards the margins
The discovered fields around Ellef Ringnes and Lougheed Islands are also under filled. Around Ellef Ringnes Island, fields are typically only filled to approximately 10% of their estimated capacity. Moving west however, the fields become more and more full, where fields around Lougheed Island are filled to approximately 50%, and in far west regions of the basin, some fields are filled all the way to their spill points (e.g. Drake and Hecla fields) (Waylett & Embry, 1992; Chen et al., 2000; Dewing & Obermajer,
2011).
There are two possible explanations why the discovered fields around Ellef
Ringnes Island are under filled: 1) the amplification of structural traps after the main phase of hydrocarbon generation and expulsion, and 2) hydrocarbon leakage associated with the faults or fractures common above many of the high amplitude structural closures in this region. These factors do not necessarily work independently of each other, and may have worked simultaneously together to affect the resulting volume within the traps.
However, the latter of the two is also considered a main cause for why many field in this region of the basin are underfilled (Waylett & Embry, 1992).
Results from the burial and thermal history modeling on Hoodoo H 37 indicate that peak petroleum generation and expulsion occurred between the Aptian and
Cenomanian. We speculate that the hydrocarbons generated and expelled during this time filled the pre existing low amplitude, diapir growth related structures to spill point.
These hydrocarbon bearing structures were then reactivated and amplified by
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compressional deformation related to the Eurekan Orogeny into their current configuration (Embry, 1991 chapter 20; Waylett & Embry, 1992).
Based on the (U Th)/He thermochronology data from Hoodoo Dome discussed in chapter two of this thesis, cooling associated with uplift and exhumation occurred between late Cretaceous and Middle Eocene. The Campanian cooling is not yet fully
understood, however, the latest Cretaceous mid Eocene cooling are interpreted to
represent the timing of cooling associated with onset of the Eurekan Orogeny and major
deformation across the basin, and as a result, the timing of when these structural traps
where modified and amplified. This interpretation is further supported by the ovate shape
and stratigraphic/structural relationships of many of the salt domes on Ellef Ringnes
Island. These structural stratigraphic relationships suggests that the domes on Ellef
Ringnes Island were structural modified into their current configuration by compressional
forces after the deposition of the Kanguk Fm (Evenchick & Embry, 2012; Plate 1).
Therefore, the temporal relationships between petroleum generation and trap
amplification resulted in an increase to the trap volume without an increase to the volume
of hydrocarbons. As a result, structural traps that were likely once filled to capacity are
now under filled (Figure 43).
This differs from the fields to the west of Ellef Ringnes Island, which are
characterized as lower amplitude structural closures, that become increasingly more full
moving west across the basin. The structures these fields lie within are thought to be
fuller because they were established prior to receiving hydrocarbons during the Late
Cretaceous, and then less affected by Eurekan deformation (Dewing & Obermajer, 2011).
89
Hydrocarbon escape via faults and fractures has also been identified as a reason for many of the discovered fields in the central Sverdrup Basin to be under filled. The presence of oil staining, stacked traps, and Albian methane seeps are likely associated with hydrocarbon loss via vertical migration through fault and fracture conduits
(Beauchamp et al., 1989; Waylett & Embry, 1992). The faults and fractures are often found on the crests of many of the higher amplitude folds in this portion of the basin, such as the ones seen at the Cape Allison, Skate (Lougheed Island), Balaena, and Char fields (Waylett & Embry, 1992), and at the surface at Hoodoo Dome and southern Ellef
Ringnes Island (Beauchamp et al., 1989; Williscroft personal comm., 2012). Figure 44 shows an example of two fields in the Sverdrup Basin that have data to suggest vertical migration and loss of hydrocarbons through fractures and faults.
At both the Cape Allison (Cape Allison C 47) and Skate (Skate C 59) fields, gas columns are seen overtop of substantial 25+ metre oil columns. However, electric log tests for these wells show that most of the oil column within these fields is residual staining, and that less than ~30% of the oil column is from the producible oil zone
(Waylett & Embry, 1992). Waylett and Embry (1992) interpreted that some of the many faults overtop of these fields acted as conduits for gas and possibly oil to escape.
Leakage of gas from the crests of these structures allowed the remaining hydrocarbon column to ascend higher into the trap, replacing the lost gas, and leaving behind a zone of residual oil.
Stacked traps in the Belaena (Belaena D 58) and Char (Char G 07) fields to the south of Ellef Ringnes Island provide additional evidence to suggest that faults and
90
fractures provided conduits for oil and gas vertical migration into higher stratigraphic reservoirs (Figure 44).
At Hoodoo Dome, a number of surface observations including the presence of oil staining and methane seep mounds provide additional evidence to suggest that hydrocarbons were lost by vertical migration via a network of faults and fractures. Oil staining is observed in the Isachsen Fm. sandstones along at least one fault contact in the south eastern portion of Hoodoo Dome (Plate 1). In addition, Albian chemosynthetic methane seep mounds are found at the base of the Christopher Fm. at Hoodoo Dome and across southern areas of Ellef Ringnes Island. These seeps are thought to be at least partially sourced by thermogenic methane gas generated by the Sverdrup Basin source rocks (Beauchamp et al., 1989; Beauchamp & Savard, 1992; Williscroft personal communication, 2012). Combined, these observations provide evidence to suggest that vertical hydrocarbon migration to the surface occurred no later than the Albian at Hoodoo
Dome. This is likely the reason why the underlying field at Hoodoo Dome and others in this region are either dry or have lost significant quantities of gas and are under filled.
4.2 Future Prospective Hydrocarbon Exploration:
Increasing global energy demand and dwindling hydrocarbon reserves are beginning to push exploration into the world's most remote, frontier basins. As a result, future exploration of the Canadian Arctic's hydrocarbon bearing Sverdrup Basin will likely be renewed. Although the previous exploration of this basin between the 1960's and 1980's was deemed a success, recent modeling by Chen and Osadetz (2011) suggest that substantial amounts of hydrocarbons, between 2.35 2.55 BBbls of oil and 24.2
24.8 TCF of natural gas, still remain undiscovered. This thesis provides important
91
quantitative temporal information regarding the petroleum and tectonic systems around
Ellef Ringnes Island, which can be used to help future explorationists better understand the type, quantity, and risk associated with new fields in this region of the basin.
While future exploration of the basin's central structural play will inevitably lead to new discoveries in this region, the results of this study combined with others (e.g.,
Embry 1991; Waylett & Embry, 1992; Gentzis et al., 1996) suggest that the structural fields in this region of the basin have experienced gas flushing, post hydrocarbon generation/expulsion structural trap development and amplification, and hydrocarbon leakage associated with fractures and faults. Therefore future exploration of this play type will likely yield discoveries that are characteristically similar to those found during the basin's initial exploration in this region of the basin. However, future discoveries within this structural play type will likely be smaller than those already discovered, because the regional extent and density of the legacy seismic data is such that it is doubtful any large structures have gone undetected (Embry, 2011).
Although there are many risks associated with central Sverdrup Basin structural play, there is still significant potential. Figure 46 illustrates the locations of both tested and non tested fields that have been delineated using the available legacy seismic,
However, Chen and Osadetz (2011) note that the data's low resolution could mean that additional medium to smaller, and more complex structural closures with adequate seals still remain to be identified.
The results of this study indicate that the temporal relationships between the petroleum generation and expulsion and trap development is such that it extremely reduces future exploration of this play type for liquid rich hydrocarbons. Based on
92
source rock characterization and the modeling results, the Triassic source strata is oil prone, and produced significant volumes oil; however, the majority of the basin's discoveries are composed of natural gas as a result of gas flushing. As a result, the copious amounts of oil that were likely generated by these rocks probably re migrated up dip towards the basin's margins, where it either: 1) escaped to the surface, or 2) was trapped by secondary structural or stratigraphic traps.
Over the last three decades, detailed studies on the Basin's stratigraphy and depositional facies (e.g., Embry, 1982, 1983, 1991; Embry & Podruski, 1988; Embry &
Johannessen, 1993; Embry, 2011) have identified great potential for a stratigraphic trap play type. This play type focuses primarily along Sverdrup Basin margins, where porous stratigraphy of the Triassic and Jurassic reservoir rocks (the Heiberg Fm., its lateral equivalent the King Christian Fm., and the Awingak Fm.) are truncated by basin margin unconformities (Figure 47), however, there are also possible opportunities in basinward pinch outs where the porous facies become non porous (Embry & Johannessen, 1993;
Embry, 2011). These stratigraphic traps developed syndepositionaly during Triassic and
Jurassic, and therefore were present long before significant oil and gas generation and expulsion (Aptian – Cenomanian) as proposed by our model at Hoodoo Dome. The timing of their development and their spatial distribution of the basin margin traps suggests that they likely escaped gas flushing, and are less prone to fault and fracture related leakage, both of which compromise many of the structural closures in the central
Sverdrup Basin. As a result, the stratigraphic trap play along the basins' margins is suggested to have the greatest liquid rich resource potential in the basin (Embry, 2011).
93
Normal faulting along the northern margins of the basin associated with the development of the Amerasia Basin to the north could have significant implications for hanging wall, foot wall normal fault traps. These structures developed between Ellef
Ringnes and Mackenzie King Islands during the Late Jurassic and Early Cretaceous, and therefore were in place prior to peak hydrocarbon generation and subsequent expulsion.
Similar to the stratigraphic basin margin play suggested above, these structures could be more prone to liquid rich hydrocarbon discoveries, as they would have been up dip of the central basin traps during gas flushing.
Finally, the results of the modeling indicate that some portion of the hydrocarbons generated from these rocks never escaped and remain within the source strata (Figures 35
& 36). This possibly opens the door for an unconventional in situ shale oil play type in the basin's center, which could be accessed by use of modern directional/horizontal drilling and hydraulic fracturing techniques, an idea previously speculated by Dewing and Obermajer (2011).
94
5.0 SUMMARY AND FUTURE WORK:
5.1 Summary of Present Work:
The following conclusions can be made from the data presented above.
• The dispersion of helium cooling ages indicates that the Early Cretaceous Isachsen
through Hassel formations were buried shallowly, to less than 3 kilometers.
• The (U Th)/He results indicate two possible cooling events.
o A Campanian (≈ 80 76 Ma) cooling event. This cooling event remains
enigmatic because it cannot be associated with an known geological event.
However, these dates do suggest a previously unrecognized cooling event did
occur at this time.
o A cooling event that initiated during the Late Cretaceous Paleocene
boundary (≈ 65 Ma) and continued until the middle Eocene (≈ 41 Ma). The
Paleogene (U Th)/He ages are interpreted to reflect exhumation and cooling
associated with Eurekan deformation, an interpretation which is supported by
additional thermochronologic data in the basin.
• One dimensional basin modeling indicates that the Triassic Murray Harbour and
Hoyle Bay formations generated and expelled significant volumes of hydrocarbons
between the Aptian and Albian (≈ 120 100 Ma). Due to low thermal maturity, the
Jurassic source rocks are considered to be an insignificant source to the petroleum
system in this region of the Basin.
• The combined methods used in this study illustrate that the petroleum system was
essentially exhausted by the time major structural traps formed in the basin's center,
resulting in underfilled traps.
95
• Early low amplitude structural traps filled to capacity during the early petroleum
generation stage. However, continued maturation and late stage hydrocarbon
generation, specifically gas generation flushed oil from traps, leaving behind
structural closures filled primarily with natural gas.
• Future exploration of conventional play types in this region of the basin will likely
lead to more natural gas discoveries. The oil the was generated in this region of the
basin left the basin center by the Late Cretaceous and migrated up dip towards the
basin margins and either leaked to the surface or is now trapped in stratigraphic or
structural closures.
5.2 Suggestions for Future Work:
The presented thesis provides new understandings to the development and evolution of the Sverdrup Basin’s thermo tectonic and petroleum systems. However, many questions regarding these basin systems are still not answered.
Low temperature thermochronology studies are a relatively new technique being implemented in the Sverdrup Basin to better understand its thermal history. The
Campanian cooling ages from this study and in Anfinson (2012) provide the first evidence to suggest a phase of previously unidentified tectonics was possibly affecting the Sverdrup Basin at this time. Additional low temperature thermochronology and stratigraphic studies will further enhance our understanding of the basin's development during the Campanian. Future thermochronology work should be supplemented with additional thermal maturity data (vitrinite reflectance) to reduce confusion associated with the interpretation of partially reset samples, as was the case with the data set
96
presented in this thesis. Because much of the Campanian Kanguk Formation has been eroded away, stratigraphic studies focusing on this time interval may be difficult to accomplish. Additional exploration wells and new, higher resolution, seismic may also help answer questions regarding the Campanian development of the Sverdrup Basin.
While the 1 D burial history modeling conducted on Hoodoo Dome H 37 provides a strong fundamental understanding of the petroleum system underlying Hoodoo
Dome, additional modeling across the basin is suggested to better understand the localized and the more regional Sverdrup Petroleum system. Once more 1 D models are made, future work should try to implement 2 D and 3 D models to allow us to better understand how and to what extent the impact of the basin's massive salt accumulations have on the basin's petroleum and thermal systems. 2 D and 3 D modeling may also provide valuable information on hydrocarbon migration within the basin. To make future studies of this nature more accurate, datasets (e.g., source rock geochemical data) should be locally confined to the area of interest to minimize possible risks associated with broad, regional scale assumptions, like the ones that were used to generate this model.
To do this however, models will have to be run on wells, or in an area with wells, which have sufficient quality datasets. As a result, additional exploration wells would be beneficial for studies like this; additional data such as geochemistry, thermal maturity, etc. would allow for more detailed, higher resolution studies to be conducted.
97
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118 G r e e n l a n d n a l n e e r G
70°0'0"W 80°0'0"N 74°0'0"N
Greenland
Baffin Bay Baffin Ellesmere Island Ellesmere
90°0'0"W
Devon Island Devon
Island
Axel Heiberg Heiberg Axel
CWI
ARI
ERI
Bathurst Island Bathurst
LHI
Sverdrup Basin Sverdrup
BI
Melville I. Melville MKI
110°0'0"W
Basin Axis Basin EI
150 Prince Patrick I. Patrick Prince Arctic Ocean Arctic Kilometers 0 80°0'0"N 74°0'0"N 130°0'0"W Figure 1: Regional map of the Canadian Arctic Islands. The shaded pink area delineates the extent of the Sverdrup Ba - Sverdrup of the extent the delineates area pink shaded The Islands. Arctic the Canadian of map 1: Regional Figure stand abbreviations Map on. Hoodoo is located which Dome island the Island, Ellef outlines Ringnes red box sin. The ERI- Ellef Island; Ringnes LHI- Lougheed Island; Island; Borden BI- Island; King MKI- Mackenzie the following: for Island. EI- Eglinton Island; CWI- Cornwall Island; Ringnes ARI-Amund
119 * * * * * * * Isachsen Heiberg Expedition Hassle Barrow Kanguk Ringnes Deer Bay Hoyle Bay Hoyle Otto Fiord Hare Fiord Hare Blind Fiord Hauen Van Borup ord Christopher Emma Fiord Jamesson Bay Trappers Cove Trappers Murray Harbour Murray McConnell Island McConnell Formation Maclean Strait Skybattle Bay Pat Lougheed Island Lougheed King Christian Grosverner Island Grosverner Sandy Point Rondon Mbr Roche Point Walker Is. Mbr Is. Walker Mrb Is. Paterson Awingak Visean Norian Induan Anisian Carnian Albian Asselian Roadian Aptian Wprdian Ladinian Gzhelian Rhaetian Toarcian Bajocian Artinskian Olenekian Bashkirian Aalenian Kungurian Sakmarian Turonian Moscovian Capitanian Callovian Tithonian Toumaisian Berriasian Kasimovian Coniacian Oxfordian Campanian Santonian Barremian Bathonian
Hettangian Sinemurian Hauterivian Valanginian Serpukhovian
Cenomanian Wuchiapingian Changhsingian Maastrichtian Pliensbachian Kimmeridgian
Late Early Late Middle Early Late M E L Early Late Early
M
161 200 245 251 176 100 146 260 272 296 228 320
Triassic Permian Carboniferous Age (Ma) Age Cretaceous Jurassic Figure 2: Paleozoic and Mesozoic stratigraphy of the central The black stars 2009). Sverdrup Basin (modified after Macauley, represent the primary hydrocarbon source rocks of basin, and primary reservoir rocks. the blue stars indicate Basin’s
120 80°0'0"N 78°0'0"N 76°0'0"N 74°0'0"N
-
, Ellesmere Island Ellesmere
90°0'0"W
Devon Island Devon
Island
Axel Heiberg Heiberg Axel ARI
100°0'0"W
Bathurst Island Bathurst
ERI
Lougheed I. Lougheed
Sverdrup Basin Sverdrup
Melville I. Melville MKI 110°0'0"W
150 Kilometers Axis Basin Salt-cored Structure
0 Prince Patrick I. Patrick Prince rite structures within the Sverdrup Basin (salt structure locations from Embry Figure 3: Distribution of the major Carboniferous Otto Fiord Fm. cored evapo 2011). 80°0'0"N 74°0'0"N 78°0'0"N 76°0'0"N
121 , 1991). Figure 4: Summarized Mesozoic stratigraphic cross-section of the Sverdrup Basin. Note, salt intrusions and dykes are not illustrated in the figure (from Embry
122 Figure 5: Map of Arctic landmasses showing the location and extent of volcanic and intrusive rocks (orange translucent) during the Cretaceous igneous event. The Sverdrup Basin is outlined by the black dashed line, and the hot spot trak of the Alpha Ridge is shown by the blue dashed line just to the north of the Sverdrup Basin.(from Jones et al., 2007)
123 Ellesmere Island
Greenland
Ba n Bay
Labrador Sea
Figure 6: Generalized movement of the Greenland Plate relative to the North American Plate from Chrons C27N to C13N using Roest and Srivastava’s (1989) model. The plate kinematic studies indicate a general north eastern movement of Greenland relative to North America from Chron 27-25N. Between Chrons 25- 24N the motion becomes more north-north east. By Chron 24N a major change in the direction of motion of the Greenland Plate occurs to a more north-northwest motion. This continues until approximately Chron 13N (from Oakey & Chalmers, 2012).
124
60°0'0"W
Greenland Baffin Bay Baffin 82°0'0"N
74°0'0"N
Ellesmere Island Ellesmere
Devon Island Devon Island
84°0'0"N Axel Heiberg Heiberg Axel
ARI
ERI Bathurst Island Bathurst
LHI 84°0'0"N Basin Sverdrup
Arctic Ocean Arctic
Melville I. Melville MKI 150
Mild Deformation: & Salt Domes Folds & Domes folds Broad
Intense Deformation: faults & Folds Thrust Prince Patrick I. Patrick Prince Kilometers 74°0'0"N 0 82°0'0"N 140°0'0"W Figure 7: Generalized deformation zones within the Sverdrup Basin. Note, is most intense in the east, and decreases in intensity moving southwest across basin (location of deformation zones are from Embry and Beauchamp, 2008).
125 Figure 8: Location and generalized structure of the wall-and-basin-structure (WABS) province on Axel Heiberg Island (from Jackson and Harrison, 2006).
126 Figure 9. Bedrock geology map of Ellef Ringnes Island. The geology is the unpublished work of C. Harrison, and and Harrison, of C. work geology The is unpublished the Ellef 9. Bedrock Island. Ringnes of Figure geology map Balkwill and (1978) for & Roy Ellef Island, Ringnes (1969) for Stott from are used in the compilation the maps Hoodoo around area study the outlines island of the in red portion the southern box The Christian Island. King Dome.
127 76°0'0"N 78°0'0"N
150
Island Axel Heiberg Heiberg Axel
Kilometers ARI & Embry, Waylett Sverdrup Basin Sverdrup Oil and Gas Discoveries in the Oil and Gas Discoveries Cape MacMillanCape Char 0 Cape Allison Cape 100°0'0"W
Jackson Bay
Bathurst Island Bathurst ERI Kristo er Balaena Gas Fields Oil Fields Oil and Gas Fields Thor Wallis
Maclean Sverdrup Basin Sverdrup Sculpin Skate Cisco White sh
Drake Point Drake
BI
Melville I. Melville MKI Roche Point 110°0'0"W
Hecla
Sverdrup Basin Sverdrup
Arctic Ocean Arctic Prince Patrick I. Patrick Prince 78°0'0"N 76°0'0"N 120°0'0"W Figure 10: Oil and Gas fields in the western Sverdrup Basin (location of discoveries is from 1993). Sverdrup Basin outlined by dashed line.
128 80°0'0"W 78°0'0"N 74°0'0"N 1.
The black dots
Ellesmere Island Ellesmere
!
! Devon Island Devon
82°0'0"N
Island
!
Axel Heiberg Heiberg Axel ARI
H-37 !
Hoodoo Dome !
100°0'0"W
Helicopter J-12 ! ERI
!
Bathurst Island Bathurst
!
!
!
!
LHI ! !
! !
!
Sverdrup Basin Sverdrup
!
! Skybattle M-11 !
!
!
!
!
! !
! !
!
!
! ! ! !
Arctic Ocean Arctic
!
!
!
!
!
!
! ! !
!
82°0'0"N !
Melville I. Melville !
! MKI
! !
!
150 !
!
! ! !
Gas Window (> 1.35%) Window Gas Oil (1.0 - 1.35%) Late Early Oil (0.6 - 1.0%) (0.0 - 1.6%) Immature Kilometers I. Patrick Prince 0 Inferred Vitrinite Re ectance (%) Vitrinite Inferred 120°0'0"W 80°0'0"W 74°0'0"N Figure 11: Thermal maturity map of the Triassic source rocks across the Sverdrup Basin (modified from Dewing Triassic Thermal maturity map of the Figure 11: Note that Ellef Ringnes Island is on the boundary between thermally over mature rocks 2011). & Obermajer, in the eastern Sverdrup Basin and rocks within oil window western Basin. The blue dots source rock characterization in this study. Triassic represent well locations that were used for the represent the locations of following wells: Hoodoo Dome H-37, Helicopter J-12, and Skybattle M-1
129 Apatite grain retains helium as it is produced 4He (tracks calendar time) 4He 4He 4He 4He 4He 4He 0km
1km
≈40°C Isotherm 4 4 He 4 He He Apatite grain partially retains Helium P 2km 4He 4 4He He Depth (km) 4He R
Z ≈70°C Isotherm 3km 4He 4He 4He Apatite grain loses all helium as it is produced (Helium age =0) 4He 4He 4He
Figure 12: Schematic summarizing the burial/thermal relationships of helium diffusion in apatite grains within a detrital system.
130 350.0
300.0
250.0
200.0
150.0
(U-Th)/He Cooling Ages (Ma) Ages Cooling (U-Th)/He 100.0 (Ma) Ages Cooling (U-Th)/He
50.0
0.0 S N W E B B’ 200m A’ A 200m sea level sea level -200m KH ? KK -200m ? KAI KH ? ? -600m -600m KC -1000m -1000m KlWI KC KlPI -1400m -1400m Ce Ce KlWI -1600m -1600m KlPI -2000m -2000m JDB -2400m -2400m JDB JR -2600m -2600m
Scale: 1:20,000 Scale: 1:20,000 Figure 13: Cross-section corresponding to sample collection transects indicated on the geological map in Plate 1. Sample locations are identified by red triangles, and their associated cooling ages are shown against time (Ma) as coloured diamonds. The cooling ages within the shaded blue area represent grains which postdate their Sverdrup depositional age. Cooling ages older than the shaded blue area indicate that some grains either did not experience significant helium diffusion or have U-Th rich micro inclusions. These older ages suggest these strata were buried shallow (>3km) and to temperatures less than 70 degrees Celsius, while the younger ages provide evidence to suggest that these rocks were at least buried to within the HePRZ and experienced significant diffusion. The Formation abbreviations stand for the following. Ce= Car- boniferous Otto Fiord Fm.; JR=Jurassic Ringnes; JDB= Jurassic Deer Bay Fm.; KlPI= Lower Cretaceous Patterson Island Member of Isachsen; KlWI= Lower Cretaceous Walker Island Member of Isachsen Fm.; KC= Christopher Fm.; KH= Cretaceous Hassel Fm.; KK= Cretaceous Kanguk Fm.; KAI= Cretaceous hydorthermal alteration zone.
131 500.0 400.0 300.0 200.0 Th)/He Cooling age (Ma) age Cooling Th)/He - (U 100.0 Radiation Damage Vs. Age Cooling Vs. Damage Radiation 0.0
5.0 0.0
50.0 45.0 40.0 35.0 30.0 25.0 20.0 15.0 10.0 eU Concentration (ppm) Concentration eU Figure 14: Radiation Damage (eU) vs. AHe cooling age plot for all analyzed grains at Hoodoo Dome. Apatite AHe cooling age plot for all analyzed grains at Hoodoo Dome. Figure 14: Radiation Damage (eU) vs. grains with low eU (<20 ppm), shown below the dashed red line, will not show a correlation because within apatite. Grains with greater on helium diffusion radiation damage below 20 ppm will have minimal effect concentrations of eU (>20 ppm) still do not show a correlation with cooling age within this sample suite.
132 500.0 AHe cooling ages to 400.0 , other small grains have old ages, while 300.0 The plot shows a cluster of younger ages between 200.0 Th)/He Cooling age (Ma) age Cooling Th)/He - (U Grain Size vs. vs. Age Size Cooling Grain 100.0 0.0
65 60 55 50 45 40 35 30 25 m) μ Radius ( Radius determine if there is a relationship between grain size and cooling age. 40 and 80Ma which can be correlated with some of the smaller grain sizes, however As a result, this plot illustrates that grain size alone was not major factor in the grains have very young ages. some larger scatter of the observed 4He ages. Figure 15: Single grain radii (Equivalent Sphere Radius) of all sampled aliquots are plotted against
133 105°0'0"W 95°0'0"W 85°0'0"W 75°0'0"W
0 150
Kilometers
80°0'0"N
Sverdrup Basin Axel Heiberg 80°0'0"N Island
Ellesmere Island
Initiated cooling 78°0'0"N Cooling betweenERI by ≈ 66 Ma
≈ 66 - 41 Ma ARI
78°0'0"N
105°0'0"W 95°0'0"W 85°0'0"W
Figure 16: Cooling age similarities between this study and apatite fission track results from Arne et al. (1998, 2002). Red boxes indicate the locations where the studies were undertaken. Despite more than 350 kilometers distance between the results on Hoodoo Dome and those in the eastern Sverdrup Basin, the timing of cooling initiation between the two is very similar.
134 Figure 17: Summary of the transient heat flow used in the model. The spike in heat flow during the Early Cretaceous was estimated to reflect the wide spread igneous activity in the basin during that time.
135 Figure 18: Burial and maturation history model of Hoodoo H-37. The model indicates several phases of moderate to rapid subsidence that caused the source rocks in the basin to mature. The Triassic source rocks enter the oil window by during the Jurassic and con- tinue to mature into the late oil and gas generation window by the Late Cretaceous. The Jurassic source rocks appear to not buried as deeply, and only matured into the early oil mature window during the Late Cretaceous.
136 Figure 19: Calibration of calculated versus measured maturity at Hoodoo H-37. Note, in- creasing the transient heat flow steepens the modeled temperature curve, whereas increas- ing the sediment load only shifts the modeled temperature curve either left (less thermally mature) or right (more thermally mature). These two values were estimated and adjusted to allow the model to better fit the constraints provided by the measured present day and paleo temperature data at Hoodoo Dome H-37. 137 Hoodoo Dome H-37 Reflectance (Ro %) 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 0
Christopher Fm
Isachsen Fm
1000
Deer Bay Fm
Ringnes Fm 2000
Jameson Bay Fm Remus Mbr
Fosheim Mbr D e p t h ( m )
3000 Romulus Mbr
Barrow Fm
CHRISTOPHER FM 4.9 ISACHSEN FM 411.5 4000 WALKER ISLAND MBR 411.5 RONDON MBR 600.0 PATERSON ISLAND MBR 652.0 Bitumen DEER BAY FM 1146.4 Inertinite RINGNES FM 1752.6 Phytoclast MCCONNELL ISLAND FM 1958.3 Rockeval Tmax (converted) SANDY POINT FM 2090.9 Vitrinite JAMESON BAY FM 2124.5 HEIBERG FM 2301.0 REMUS MBR 2301.0 5000 FOSHEIM MBR 2353.1 ROMULUS MBR 2787.4 BARROW FM 3246.2 TOTAL DEPTH 3374.8
Figure 20: Depth Maturity plot for Hoodoo Dome H-37, showing the absence of igneous intrusions and their effect on the thermal maturity in this well (from Dewing et al., 2007).
138 Figure 21: Modified Van Krevelen diagram for the Deer Bay Formation source rocks based on oxygen index (OI) versus hydrogen index (HI), showing the gas prone type III kerogen. The Rock-Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007).
139 Figure 22: Modified Van Krevelen diagram for the Ringnes Formation source rocks based on oxygen index (OI) versus hydrogen index (HI), showing the primarily oil prone type II kerogen. The Rock-Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007).
140 Figure 23: Modified Van Krevelen diagram for the Hoyle Bay Formation source rocks based on oxygen index (OI) versus hydrogen index (HI), showing the primarily oil prone type II kerogen. The Rock-Eval® geochemical data used to generate this plot was de- rived from Obermajer et al., (2007).
141 Figure 24: Modified Van Krevelen diagram for the Murray Harbour Formation source rocks based on oxygen index (OI) versus hydrogen index (HI), showing the primarily oil prone type II kerogen. The Rock-Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007).
142 Figure 25: Deer Bay Formation: Plot of total organic carbon (TOC, wt%) versus the produced hydrocarbons remaining in the rock ( S1 mg HC/g rock) plus the remaining hy- drocarbon potential within the rock (S2 mg HC/g rock), showing an overall poor petro- leum-generating potential for this formation. The Rock-Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007).
143 Figure 26: Ringnes Formation: Plot of total organic carbon (TOC, wt%) versus the pro- duced hydrocarbons remaining in the rock ( S1 mg HC/g rock) plus the remaining hydro- carbon potential within the rock (S2 mg HC/g rock), showing an overall fair to very good petroleum-generating potential for this formation. The Rock-Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007).
144 Figure 27: Hoyle Bay Formation: Plot of total organic carbon (TOC, wt%) versus the produced hydrocarbons remaining in the rock ( S1 mg HC/g rock) plus the remaining hydrocarbon potential within the rock (S2 mg HC/g rock), showing an overall poor to very good/excellent petroleum-generating potential for this formation. The Rock-Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007).
145 Figure 28: Murray Harbour Formation: Plot of total organic carbon (TOC, wt%) versus the produced hydrocarbons remaining in the rock ( S1 mg HC/g rock) plus the remain- ing hydrocarbon potential within the rock (S2 mg HC/g rock), showing an overall poor to very good/excellent petroleum-generating potential for this formation. The Rock-Eval® geochemical data used to generate this plot was derived from Obermajer et al., (2007).
146 Figure 29: Deer Bay Formation’s rate of hydrocarbon generation.
147 Figure 30: Ringnes Formation’s rate of hydrocarbon generation.
148 Figure 31: Hoyle Bay Formation’s rate of hydrocarbon generation.
149 Figure 32: Murray Harbour Formation's rate of hydrocarbon generation.
150 Deer Bay Fm.
K P E O M P 0.8
0.6 TOC ) (mg/g
0.4 HC Cumulative
0.2
in-situ Oil in-situ Gas in-situ Residue expelled Oil 0 expelled 160 150 100 50 0 Gas Age (my) Figure 33: Modeled cumulative amount of generated and expelled hydrocarbons from the organic matter in the Late Jurassic / Early Cretaceous Deer Bay Fm. source rock at Hoodoo Dome H-37.
151 Ringnes Fm.
10 K P E O M P
8
6 TOC ) (mg/g HC
4 Cumulative
2 in-situ Oil in-situ Gas in-situ Residue expelled Oil 0 expelled 160 150 100 50 0 Gas Age (my) Figure 34: Modeled cumulative amount of generated and expelled hydrocarbons from the organic matter in the Jurassic Ringnes Fm. source rock at Hoodoo Dome H-37.
152 Hoyle Bay Fm.
T J K P E O M P 500
400
300 TOC ) (mg/g HC
200 Cumulative
100 in-situ Oil in-situ Gas in-situ Residue expelled Oil 0 expelled 250 200 150 100 50 0 Gas Age (my) Figure 35: Modeled cumulative amount of generated and expelled hydrocarbons from the organic matter in the Triassic Hoyle Bay Fm. source rock at Hoodoo Dome H-37.
153153 Murray Harbour Fm.
T J K P E O M P 500
400
300 TOC ) (mg/g HC
200 Cumulative
100 in-situ Oil in-situ Gas in-situ Residue expelled Oil 0 expelled 250 200 150 100 50 0 Gas Age (my) Figure 36: Modeled cumulative amount of generated and expelled hydrocarbons from the organic matter in the Triassic Murray Harbour Fm. source rock at Hoodoo Dome H-37.
154 Figure 37: Diagram showing the modeled timing and amount of hydrocarbon expulsion for the Deer Bay Formation at Hoodoo H-37. Because insignificant hydrocarbons were produced from this source rock, expulsion did not occur.
155 Figure 38: Diagram showing the modeled timing and amount of hydrocarbon expulsion for the Ringnes Formation at Hoodoo H-37. Because insignificant hydrocarbons were produced from this source rock, expulsion did not occur.
156 Figure 39: Diagram showing the modeled timing and amount of hydrocarbon expulsion for the bottom of Hoyle Bay Formation at Hoodoo H-37. The model indicates that ex- pulsion occurred during the Albian.
157 Figure 40: Diagram showing the modeled timing and amount of hydrocarbon expulsion for the Murray Harbour Formation at Hoodoo H-37. Expulsion of hydrocarbons from these rocks began during the Early Aptian and ceased by the end of the Albian.
158 Helicopter J-12 Reflectance (Ro %) 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 0
Isachsen
1000
Deer Bay
2000
Ringnes D e p t h ( m )
3000 McConnell Island
Jameson Bay
Heiberg
4000
ISACHSEN FM 6.7 Intrusion WALKER ISLAND MBR 6.7 RONDON MBR 455.0 Bitumen PATERSON ISLAND MBR 552.0 Inertinite DEER BAY FM 1353.9 RINGNES FM 2307.4 Phytoclast MCCONNELL ISLAND FM 2974.9 Rockeval Tmax (converted) SANDY POINT FM 3334.5 JAMESON BAY FM 3358.6 Vitrinite HEIBERG FM 3698.8 TOTAL DEPTH 3813.7 5000
Figure 41: Depth Maturity plot for exploration well Helicopter J-12 lo- cated north east of Hoodoo Dome on eastern Ellef Ringnes Island (from Dewing et al., 2007). This depth maturity plot shows the clearly visable correlation between igneous intrusion and their effect on the thermal maturity values.
159 Skybattle M-11 Reflectance (Ro %) 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 0
Christopher Fm
Isachsen Fm 1000
Deer Bay Fm
Awingak Fm
Jameson Bay Fm King Christian Fm 2000
Murray Harbour FM D e p t h ( m ) Bjorne Fm
CHRISTOPHER FM 19.8 3000 ISACHSEN FM 759.0 WALKER ISLAND MBR 759.0 RONDON MBR 903.1 PATERSON ISLAND MBR 944.0 DEER BAY FM 1129.9 AWINGAK FM 1421.9 RINGNES FM 1544.1 MCCONNELL ISLAND FM 1578.0 SANDY POINT FM 1622.2 JAMESON BAY FM 1654.2 KING CHRISTIAN FM 1763.9 WHITEFISH MBR 1763.9 4000 STUPART MBR 1797.1 DRAKE POINT MBR 1800.2 LOUGHEED ISLAND FM 1834.9 MACLEAN STRAIT FM 1866.9 GROSVENOR ISLAND FM 1904.1 Bitumen SKYBATTLE FM 1947.1 Inertinite BARROW FM 1961.1 PAT BAY FM 2043.1 Phytoclast HOYLE BAY FM 2183.0 Rockeval Tmax (converted) CAPE RICHARDS MBR 2183.0 Vitrinite EDEN BAY MBR 2192.1 ROCHE POINT FM 2339.1 GORE POINT MBR 2339.1 5000 CHADS POINT MBR 2420.1 CAPE CALEDONIA MBR 2436.0 ELDRIDGE BAY MBR 2531.4 MURRAY HARBOUR FM 2532.0 BJORNE FM 2696.9 TOTAL DEPTH 2785.0
Figure 42: Depth Maturity plot for exploration well Skybattle M- 11(from Dewing et al., 2007). The anomalous thermal maturity values observed in the Jurassic rocks possibly is a reflection of more mature detrital material. This however, appears very different then thedepth maturity plot for Hoodoo Dome.
160 Spill Point Basin Axis Basin Margin
Reservoir Rock Seal Rock (Shale) Salt (e.g., Heiberg Fm.) Gas ushing Early Generation (displaces all oil)
Leakage Hydrocarbon migration from source rock
Salt Displaced oil accumulation
Late Generation Traps under lled
Gas
Eurekan ampli cation of Salt Oil structural closures *Not to scale (Paleogene)
Figure 43: Generalized diagram showing the differential entrapment of oil and gas via fill and spill in a structural trap play type environment, similar to the structural play type in the central Sverdrup Basin. During the early hydrocarbon generation stage, oil and gas filled the structural closures in the basin axis. Increased thermal maturity caused the source rocks to begin generating higher quantities of natural gas. Once volumes of hy- drocarbons exceed the capacity of pore space in the traps, hydrocarbons are forced to migrate under the spill point and into the following closure. This process continues until petroleum charge stops (modified from Fustic et al., 2012).
161 Figure 44: Section across the Balaena and Char fields southwest of Ellef Ringnes Island. The figure illustrates how fractures and faulting over these fields resulted in significant vertical migration and escape of hydrocarbons (from Embry, 2011).
162 Age, In Millions Of Years
250 200 150 100 70 60 50 40 30 20 10 0 Geologic Time Mesozoic Cenozoic Scale Triassic Jurassic Cretaceous Paleogene Neogene Petroleum System Events E M L E M L E L Paleo. Eocene Olig. Mio. Plio.
Insigni cant source rocks Source Rock Reservoir Rock
Seal Rock Elements Overburden Rock Eurekan Low-amplitude salt structures Deformation Trap Formation
Peak Generation Generation - Processes Migration - Preservation Accumulation Critical Moment
Figure 45: Petroleum events chart summarizing the major elements and events of the Tri- assic through Paleogene petroleum system regionally around Ellef Ringnes Island (modi- fied from Magoon and Dow, 1994). Each of the coloured horizontal bars represents the time span of an event or process. Based on the results from this study, all of the essential elements and prcesses are present, however the timing of certain events (e.g., trap forma- tion relative to petroleum generation) are not favourable for a conventional oil play.
163 Figure 46: Map illustrating the Upper Triassic - Cretaceous reservior struc- tural closures within the western and central Sverdrup Basin. The closures were delineated using the legacy seismic available for the Sverdrup Basin, and although the density is such that it suggests no large strucutres have gone undetected, the poor resolution of the data suggests that many smaller, more complex strucutres are yet to be discovered (from Embry, 2011).
164 - gin sandstone pinch out pros pects in the Heiberg Formation lateral equivalent, the Early Jurassic King Christian Fm. (from Embry, 2011). Formation lateral equivalent, the Early Jurassic King Christian Fm. (from Embry, pects in the Heiberg Figure 47: Stratigraphic cross section illustrating the possibilities of basin mar
165 1:20,000 Scale Geological map of Hoodoo Dome, Ellef Ringnes Island Plate 1: Geological Map of Hoodoo Dome.
100°10'0"W 100°0'0"W 99°50'0"W 99°40'0"W
50
KK QUATERNARY 50 M Sur cial deposits(Q): sand, silt, clay, and gravel; undivided e Q te alluvium, colluvium, and marine deposits. o KE ro lo 50 CRETACEOUS g i st 50 UPPER CRETACEOUS A n Late Campanian and Maastrichtian t i KH cl in Expedition Formation (KE): very ne - and ne - grained e KE sandstone (and unconsolidated sand), shale, mudstone; minor coal and medium-grained sandstone. KH Early Turonian to Late Campanian
Kanguk Formation (KK): Basal unit is characterized as black to dark grey shales, bituminous shale, with an isolated KK yellow bentonite clay layer which becomes increasingly 78°12'0"N lighter in colour and silt and (sand?) content.
44 78°12'0"N 24 LOWER CRETACEOUS KIWI Late Albian to Cenomanian
38 35 27 Hassel Formation (KH): Quartz sandstone, siltstone with 28 42 32 KH minor shale and coal. Locally this formation is primarily 23 unconsolidated at the surface.
20 50 24 Late Aptian to Late Albian
100 Christopher Formation (KC): dark grey shale, siltstone, and very ne-grained sandstone, calcareous mudstone 33 21 concretions/nodules; locally this formation includes glen- 21 15 donites and chemosynthetic carbonate seep mounds in its 15 17 KK KC 21 31 lower section southwest of Hoodoo Dome. siltstones and
100 23 ne-grained sandstones become increasingly more frequent 28 in the upper portion of the formation. 18 20 15 25 KIWI 76 59 KC Late Valanginian to Late Aptian
12 25 Isachsen Formation KC 14 KIWI 28 14 17 100 IR K 20 Walker Island Member (KIWI): Fine to coarse grained quartz B’ 100 15 sandstone, carbonaceous siltstone, carbonaceous shale, and 15 18 KIWI 19 15 55 minor pebble conglomerates and stream channel deposits. 38 16 18 25 50 15 50 AS 1-108-1 KIR Rondon Member (KIR): Shale, siltstone, minor coal 25 19 21 10 34 30 25 35 16 16 21 Paterson Island Member (KIPI): Light brown to white, very 25 32 17 15 42 35 ne to coarse-grained quartz sandstone and unconsolidated 50 KIPI 12 28 40 sand, cloudy white smooth vein quartz pebble sands, 12 23 siltstones, and minor coal seams (<1.5 m)
8 30 17 20 78°10'0"N 12 42 11 AS 1-108-3 CARBONIFEROUS TO CENOZOIC 100 15 17 36 20 18 KIPI 28 23 50 AS 1-108-2
150 12 A 34 27 50 78°10'0"N 23 Ce Ce Otto Fiord Formation (Carboniferous Evaporite): Anhydrite, 20 36 17 gypsum, selenite KIPI 27 150 50 16 24
25 46 73 23 50 Al BG 14-35-2 21 K K Early Cretaceous (?) magnetite and pyrite bearing hydro- 76 10 20 15 IR 18 thermal alteration zone 14 22 45 K 28 23 B 30 IWI 25 27 25 KIR 28 12 BG 14-34-4 Contact (De ned, approximate, inferred) 30 17 20 20 100 28 36 KIWI 15 25 50 45 Normal Fault (de ned, approximate) 20 26 32 23 13 25 26 20 12 Anticline (de ned, approximate) 23 BG 14-34-1 41 21 40 20
100 20 20 Syncline (de ned, approximate) 12 31 30 24 35 18 100 13 Bedding (strike and dip) 12 100 25 17 21 40
37 100 Apatite (U-Th)/He Thermochronology sample location
20 14-53-1 35 100 100 25 12 22 Exploration well location: 20 52 24 25 Ce KIR Methane seep location:
23 100 28 Location of oil seep: 22 BG 14-45-2 78°8'0"N KAl KAl BG 14-45-1 23 KIWI 78°8'0"N
50 25 25 15 20 100 20 150 KAl
21 KH
A’
100
KC
KK
100 M e KC te
150 o ro 100 lo
100 g i st A n Hoodoo Dome ti cl in H-37 e Regional geological map of Ellef Ringnes Island (Surface Geology from Stott (1969). The red box denotes Hoodoo KE 150 Dome and the location of the detailed geological map shown to the left.
78°6'0"N
Magnetic declination varies from about -20 to -30 degrees at Hoodoo Dome. As a result, some
50 78°6'0"N eld measurements using a compass were inconsistent with bedding traces visible in the satellite imagery. Therefore, some strike measurements from the eld were modi ed to re ect the actual strike observed in the satellite imagery.
150
Map Produced by: Austin C Springer Datum: NAD 1983 Zone 14N Projection: UTM Kilometers 0 0.5 1 2 3 4 Date: 5/11/2011
Scale: 1 : 20,000
100°10'0"W 100°0'0"W 99°50'0"W 99°40'0"W
166
Table 1: Each aliquot is listed with corresponding single grain cooling ages. Resulting ages are within 2 standard deviations. (*) indicates grains which have helium re extractions above background levels (0.003 ppm) Equiv. Age ±2σ U Th 147Sm [U]e He mass Sphere 4He Re Sample Th/U Ft (Ma) (My) (ppm) (ppm) (ppm) (ppm) (nmol/g) (µg) radius extraction(ppm) (µm) AS1-108-1-1 225.0 13.50 14.5 50.8 21.6 26.3 3.51 21.7 2.52 0.66 46.18 *0.015676 AS1-108-1-2 64.6 3.88 1.5 5.3 18.2 2.8 3.59 0.7 2.53 0.67 47.01 -0.00609 AS1-108-1-3 145.5 8.73 20.0 4.2 27.6 21.1 0.21 11.5 2.46 0.69 45.72 *0.013365 AS1-108-2-1 41.3 2.48 16.0 4.7 36.3 17.2 0.30 2.6 2.12 0.68 45.75 0.000772 AS1-108-2-2 1670.6 100.24 1.4 5.1 50.9 2.8 3.57 19.2 1.96 0.65 44.70 *0.008528 AS1-108-2-3 42.6 2.55 2.5 32.6 51.7 10.3 12.83 1.5 1.27 0.59 37.75 0.003801 AS1-108-3-1 168.0 10.08 6.0 10.1 41.8 8.6 1.69 5.3 2.62 0.66 45.33 -0.0035 AS1-108-3-2 103.7 6.22 4.9 12.6 56.1 8.1 2.56 3.1 2.19 0.66 45.50 0.000141 AS1-108-3-3 231.7 13.90 2.3 0.5 14.2 2.5 0.20 2.4 4.35 0.74 57.36 0.002244 BG14-34-1-1 64.6 3.88 0.3 1.8 0.7 *0.7 7.13 0.2 2.49 0.67 47.78 -0.00949 BG14-34-1-2 225.0 13.50 2.0 7.8 14.4 3.9 3.89 3.0 1.70 0.62 40.52 -0.00121 BG14-34-1-3 465.4 27.92 15.5 5.0 9.9 16.7 0.32 26.2 1.12 0.61 35.91 *0.006288 BG14-34-4-1 76.5 4.59 3.5 14.2 37.9 6.9 4.10 1.8 1.34 0.60 38.13 0.00112 BG14-34-4-2 52.5 3.15 5.3 63.6 54.1 20.2 12.00 3.6 2.02 0.62 40.70 *0.004163 BG14-34-4-3 79.3 4.76 6.8 58.5 48.7 20.5 8.55 5.4 1.45 0.60 38.76 *0.006288 BG14-35-2-1 56.4 3.38 3.5 39.6 38.5 12.8 11.28 2.4 1.50 0.60 38.74 *0.005687
167
Equiv. Age ±2σ U Th 147Sm [U]e He mass Sphere 4He Re Sample Th/U Ft (Ma) (My) (ppm) (ppm) (ppm) (ppm) (nmol/g) (µg) radius extraction(ppm) (µm) BG14-35-2-2 55.4 3.32 1.8 50.4 26.5 13.5 28.29 2.6 2.01 0.62 41.87 -0.00491 BG14-35-2-3 65.9 3.95 7.8 91.6 61.4 29.2 11.71 6.7 1.92 0.62 41.41 -0.00443 BG14-45-1-1 169.8 10.19 2.0 0.7 14.2 2.2 0.35 1.4 1.96 0.67 44.57 -0.01171 BG14-45-1-2 204.4 12.27 45.2 0.4 61.0 45.6 0.01 30.1 0.89 0.59 33.04 0.002434 BG14-45-1-3 991.6 59.50 11.9 2.9 41.7 12.8 0.24 48.1 1.63 0.65 40.67 *0.02939 BG14-45-2-1 106.1 6.37 3.2 25.4 58.6 9.3 8.02 3.6 1.98 0.64 44.00 *0.005534 BG14-45-2-2 337.2 20.23 6.3 17.2 49.9 10.5 2.75 13.9 3.14 0.70 52.41 *0.018583 BG14-53-1-1 80.3 4.82 10.9 2.3 22.2 11.5 0.21 3.8 5.31 0.76 60.99 -0.00741 BG14-53-1-2 273.2 16.39 0.6 1.9 26.3 1.1 3.41 1.4 6.63 0.74 60.53 -0.00395 BG14-53-1-3 338.6 20.32 6.7 5.3 12.1 8.0 0.80 10.8 4.20 0.72 54.75 *0.016851
168
Appendix 1: Input parameters used for Basin-Mod 1-D®
169
formation/event name Type Begin Well Present Missing Lithology Kerogen TOC % Age Top (m) Thick Thick Type (Ma) (m) (m) Hiatus H 41 Erosion E 66 -1000 EUREKA SOUND D 75 350 Eureka Erosion I E 80 -300 KANGUK D 97.5 450 Shale HASSEL D 101 200 Sandstone CHRISTOPHER DEP D 106 300 0-20-80 CHRISTOPHER F 110 4.9 406.6 0-20-80 WALKER ISLAND MBR F 118 411.5 188.5 Sandstone RONDON MBR F 125 600 52 Shale PATERSON ISLAND F 130 652 494.4 Sandstone MBR DEER BAY FM F 142 1146.4 606.2 Shale Type III 1 RINGNES FM F 149 1752.6 205.7 Shale Type II 2 MCCONNELL ISLAND F 173 1958.3 132.6 Shale FM SANDY POINT FM F 180 2090.9 33.6 Sandstone JAMESON BAY FM F 183 2124.5 176.5 Shale REMUS MBR F 212 2301 52.1 Sandstone FOSHEIM MBR F 214 2353.1 434.3 Sandstone ROMULUS MBR F 219 2787.4 458.8 80-10-10 BARROW FM F 222 3246.2 128.6 Shale BARROW BELOW F 225.2 3374.8 372 Shale PAT BAY F 227 3746.8 32.3 Sandstone HOYLE BAY FM F 229 3779.1 640 0-20-80 Type II 2 ROCHE POINT F 236 4419.1 65 0-20-80 MURRAY HARBOUR F 240 4484.1 175 Shale Type II 2 BOTTOM F 250 4659.1 500 Shale
170
Age Heat Surface (Ma) Flow temp mW/m^2 2 46 0 5 46 5 20 46 5 23 46 1 70 46.5 1 95 53 0 120 44 5 195 43.98 250 44
171
Appendix 2: Basin Mod 1D output formation reports. Indicate the level of maturity, hydrocarbons generated and expelled.
Units:
Stratigraphic Age: (my) Depth: (m) Maturity: (%Ro) Oil Generated: (mg/g TOC) Gas Generated: (mg/g TOC) Residue Generated: (mg/g TOC) Oil Expulsion: (mg/g TOC) Gas Expulsion: (mg/g TOC)
172
Formation Name: Deer Bay Fm. (Late Jurassic - Early Jurassic)
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 142 0 0 0.2 0.2 0 0 0 0 0 0 0 0 0 0 141 0 99.67 0.2 0.23 0 0 0 0 0 0 0 0 0 0 140 0 186.88 0.2 0.23 0 0 0 0 0 0 0 0 0 0 139 0 266.86 0.2 0.23 0 0 0 0 0 0 0 0 0 0 138 0 342.02 0.2 0.24 0 0 0 0 0 0 0 0 0 0 137 0 413.66 0.2 0.25 0 0 0 0 0 0 0 0 0 0 136 0 482.59 0.2 0.26 0 0 0 0 0 0 0 0 0 0 135 0 549.38 0.2 0.26 0 0 0 0 0 0 0 0 0 0 134 0 614.4 0.2 0.26 0 0 0 0 0 0 0 0 0 0 133 0 677.94 0.2 0.27 0 0 0 0 0 0 0 0 0 0 132 0 740.23 0.2 0.28 0 0 0 0 0 0 0 0 0 0 131 0 801.42 0.2 0.29 0 0 0 0 0 0 0 0 0 0 130 0 861.66 0.2 0.3 0 0 0 0 0 0 0 0 0 0 129 141.26 948.36 0.22 0.3 0 0 0 0 0 0 0 0 0 0 128 273.4 1042.57 0.23 0.3 0 0 0 0 0 0 0 0 0 0 127 399.14 1140.21 0.23 0.3 0 0 0 0 0 0 0 0 0 0 126 520.12 1239.4 0.23 0.3 0 0 0 0 0 0 0 0 0 0 125 637.36 1339.22 0.24 0.31 0 0 0 0 0 0 0 0 0 0 124 649.17 1349.44 0.24 0.31 0 0 0 0 0 0 0 0 0 0 123 660.71 1359.45 0.25 0.31 0 0 0 0 0 0 0 0 0 0 122 672.02 1369.29 0.25 0.32 0 0 0 0 0 0 0 0 0 0 121 683.11 1378.96 0.25 0.32 0 0 0 0 0 0 0 0 0 0 173
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 120 694.02 1388.5 0.25 0.32 0 0 0 0 0 0 0 0 0 0 118 715.34 1407.19 0.26 0.33 0 0 0 0 0 0 0 0 0 0 117 739.03 1428.05 0.26 0.33 0 0 0 0 0 0 0 0 0 0 116 763.07 1449.31 0.26 0.33 0 0 0 0 0 0 0 0 0 0 115 787.35 1470.88 0.26 0.33 0 0 0 0 0 0 0 0 0 0 114 811.78 1492.67 0.26 0.34 0 0 0 0 0 0 0 0 0 0 113 836.33 1514.65 0.26 0.34 0 0 0 0 0 0 0 0 0 0 112 860.93 1536.76 0.26 0.34 0 0 0 0 0 0 0 0 0 0 111 885.58 1558.98 0.26 0.34 0 0 0 0 0 0 0 0 0 0 110 910.23 1581.29 0.26 0.34 0 0 0 0 0 0 0 0 0 0 109 1038.08 1698.05 0.27 0.35 0 0 0 0 0 0 0 0 0 0 108 1153.16 1804.46 0.27 0.35 0 0 0 0 0 0 0 0 0 0 107 1262.02 1906.07 0.29 0.36 0 0 0 0 0 0 0 0 0 0 106 1367 2004.8 0.3 0.37 0 0 0 0 0 0 0 0 0 0 105 1423.79 2058.48 0.3 0.39 0 0 0 0 0 0 0 0 0 0 104 1479.89 2111.66 0.31 0.41 0 0 0 0 0 0 0 0 0 0 103 1535.39 2164.41 0.32 0.42 0 0 0 0 0 0 0 0 0 0 102 1590.35 2216.79 0.33 0.43 0 0 0 0 0 0 0 0 0 0 101 1644.84 2268.85 0.34 0.43 0 0 0 0 0 0 0 0 0 0 100.13 1678.11 2300.68 0.35 0.44 0 0 0 0 0 0 0 0 0 0 99.25 1713.24 2334.35 0.35 0.45 0 0 0 0 0 0 0 0 0 0 98.38 1749.72 2369.35 0.35 0.46 0 0 0 0 0 0 0 0 0 0 97.5 1787.2 2405.36 0.36 0.47 0 0 0 0 0 0 0 0 0 0 96.67 1804.4 2421.9 0.36 0.47 0 0 0 0 0 0 0 0 0 0 95.83 1821.13 2437.99 0.36 0.48 0 0 0 0 0 0 0 0 0 0 174
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 95 1837.49 2453.74 0.37 0.49 0 0 0 0 0 0 0 0 0 0 94.15 1853.81 2469.46 0.37 0.49 0 0 0 0.1 0 0 0 0 0 0 92.46 1885.72 2500.22 0.38 0.5 0 0 0 0.1 0 0 0 0 0 0 91.61 1901.39 2515.33 0.38 0.51 0 0 0 0.1 0 0 0 0 0 0 90.77 1916.9 2530.29 0.39 0.51 0 0 0 0.1 0 0 0 0 0 0 89.79 1934.64 2547.42 0.39 0.51 0 0.1 0 0.1 0 0 0 0 0 0 88.81 1952.22 2564.4 0.4 0.52 0 0.1 0 0.1 0 0 0 0 0 0 87.83 1969.66 2581.25 0.4 0.52 0 0.1 0 0.2 0 0 0 0 0 0 86.85 1986.98 2597.99 0.41 0.53 0 0.1 0 0.2 0 0 0 0 0 0 85.87 2004.18 2614.63 0.41 0.53 0 0.1 0 0.2 0 0 0 0 0 0 84.89 2021.28 2631.18 0.41 0.53 0 0.1 0 0.2 0 0 0 0 0 0 83.91 2038.29 2647.64 0.42 0.54 0 0.1 0 0.3 0 0 0 0 0 0 82.94 2055.21 2664.04 0.42 0.54 0 0.1 0 0.3 0 0 0 0 0 0 81.96 2072.06 2680.36 0.42 0.55 0 0.1 0 0.3 0 0 0 0 0 0 80.98 2088.84 2696.62 0.42 0.55 0 0.2 0 0.3 0 0 0 0 0 0 80 2105.56 2712.83 0.42 0.55 0 0.2 0 0.4 0 0 0 0 0 0 79 2045.56 2652.83 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 78 1985.56 2592.83 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 77 1925.56 2532.83 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 76 1865.56 2472.83 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 75 1805.56 2412.83 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 74 1850.76 2458.03 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 73 1893.58 2500.85 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 72 1934.53 2541.8 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 71 1973.97 2581.24 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 175
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 70 2012.15 2619.42 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 69 2049.26 2656.53 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 68 2085.46 2692.73 0.43 0.56 0 0.2 0 0.4 0 0 0 0 0 0 66 2141.5 2747.7 0.43 0.56 0 0.2 0 0.5 0 0 0 0 0 0 65 2101.5 2707.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 64 2061.5 2667.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 63 2021.5 2627.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 62 1981.5 2587.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 61 1941.5 2547.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 60 1901.5 2507.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 59 1861.5 2467.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 58 1821.5 2427.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 57.25 1791.5 2397.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 57 1781.5 2387.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 56 1741.5 2347.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 55 1701.5 2307.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 54 1661.5 2267.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 53.5 1641.5 2247.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 53 1621.5 2227.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 52 1581.5 2187.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 51 1541.5 2147.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 50 1501.5 2107.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 49 1461.5 2067.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 48.5 1441.5 2047.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 48 1421.5 2027.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 176
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 47 1381.5 1987.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 46 1341.5 1947.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 45 1301.5 1907.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 44 1261.5 1867.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 42 1181.5 1787.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 41 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 40 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 39 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 38 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 37 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 36 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 35 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 34 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 33 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 32 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 31 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 30 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 29 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 28 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 27 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 26 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 25 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 24 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 23 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 22 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 177
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 21 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 20 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 19 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 18 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 17 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 15 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 14 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 13 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 12 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 11 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 10 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 9 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 8 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 7 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 6 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 5 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 4 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 3 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 2 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 1 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0 0 1141.5 1747.7 0.43 0.57 0 0.2 0 0.5 0 0 0 0 0 0
178
Top of Early Mature (oil) = 0.5 (%Ro) found at 93.0 (my) at bed bottom.
179
Formation Name: Ringnes (Middle Jurassic) Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 149 0 0 0.2 0.2 0 0 0 0 0 0 0 0 0 0 148 0 61.03 0.2 0.22 0 0 0 0 0 0 0 0 0 0 147 0 116.46 0.2 0.23 0 0 0 0 0 0 0 0 0 0 146 0 168.13 0.2 0.23 0 0 0 0 0 0 0 0 0 0 145 0 217.04 0.2 0.23 0 0 0 0 0 0 0 0 0 0 144 0 263.83 0.2 0.24 0 0 0 0 0 0 0 0 0 0 143 0 308.92 0.2 0.24 0 0 0 0 0 0 0 0 0 0 142 0 352.61 0.2 0.25 0 0 0 0 0 0 0 0 0 0 141 99.67 423.81 0.23 0.25 0 0 0 0 0 0 0 0 0 0 140 186.88 492.41 0.23 0.26 0 0 0 0 0 0 0 0 0 0 139 266.86 558.92 0.23 0.26 0 0 0 0 0 0 0 0 0 0 138 342.02 623.71 0.24 0.27 0 0 0 0 0 0 0 0 0 0 137 413.66 687.06 0.25 0.27 0 0 0 0 0 0 0 0 0 0 136 482.59 749.17 0.26 0.28 0 0 0 0 0 0 0 0 0 0 135 549.38 810.22 0.26 0.29 0 0 0 0 0 0 0 0 0 0 134 614.4 870.33 0.26 0.3 0 0 0 0 0 0 0 0 0 0 133 677.94 929.62 0.27 0.3 0 0 0 0 0 0 0 0 0 0 132 740.23 988.16 0.28 0.3 0 0 0 0 0 0 0 0 0 0 131 801.42 1046.05 0.29 0.31 0 0 0 0 0 0 0 0 0 0 130 861.66 1103.33 0.3 0.32 0 0 0 0 0 0 0 0 0 0 129 948.36 1186.22 0.3 0.32 0 0 0 0 0 0 0 0 0 0 128 1042.57 1276.79 0.3 0.33 0 0 0 0 0 0 0 0 0 0 127 1140.21 1371.12 0.3 0.33 0 0 0 0 0 0 0 0 0 0
180
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 124 1349.44 1574.48 0.31 0.34 0 0 0 0 0 0 0 0 0 0 123 1359.45 1584.24 0.31 0.34 0 0 0 0 0 0 0 0 0 0 122 1369.29 1593.84 0.32 0.35 0 0 0 0 0 0 0 0 0 0 121 1378.96 1603.28 0.32 0.35 0 0 0 0 0 0 0 0 0 0 120 1388.5 1612.59 0.32 0.35 0 0 0 0 0 0 0 0 0 0 119 1397.9 1621.77 0.32 0.35 0 0 0 0 0 0 0 0 0 0 118 1407.19 1630.84 0.33 0.35 0 0 0 0 0 0 0 0 0 0 117 1428.05 1651.22 0.33 0.36 0 0 0 0 0 0 0 0 0 0 116 1449.31 1672.01 0.33 0.36 0 0 0 0 0 0 0 0 0 0 115 1470.88 1693.1 0.33 0.36 0 0 0 0 0 0 0 0 0 0 114 1492.67 1714.43 0.34 0.36 0 0 0 0 0 0 0 0 0 0 113 1514.65 1735.94 0.34 0.36 0 0 0 0 0 0 0 0 0 0 112 1536.76 1757.6 0.34 0.36 0 0 0 0 0 0 0 0 0 0 111 1558.98 1779.38 0.34 0.37 0 0 0 0 0 0 0 0 0 0 110 1581.29 1801.24 0.34 0.37 0 0 0 0 0 0 0 0 0 0 109 1698.05 1915.87 0.35 0.37 0 0 0 0 0 0 0 0 0 0 108 1804.46 2020.53 0.35 0.38 0 0 0 0 0 0 0 0 0 0 107 1906.07 2120.62 0.36 0.39 0 0 0 0 0 0 0 0 0 0 106 2004.8 2217.99 0.37 0.41 0 0 0 0 0 0 0 0 0 0 105 2058.48 2270.97 0.39 0.42 0 0 0 0 0 0 0 0 0 0 104 2111.66 2323.5 0.41 0.43 0 0 0 0 0 0 0 0 0 0 103 2164.41 2375.62 0.42 0.45 0 0.1 0 0 0 0 0 0 0 0 102 2216.79 2427.41 0.43 0.46 0 0.1 0 0 0 0 0 0 0 0 101 2268.85 2478.9 0.43 0.48 0 0.2 0 0 0 0 0 0 0 0 100.13 2300.68 2510.4 0.44 0.49 0.1 0.2 0 0 0 0 0 0 0 0 181
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 98.38 2369.35 2578.36 0.46 0.51 0.1 0.4 0 0.1 0 0 0 0 0 0 97.5 2405.36 2614.02 0.47 0.51 0.1 0.5 0 0.1 0 0 0 0 0 0 96.67 2421.9 2630.4 0.47 0.52 0.1 0.5 0 0.1 0 0 0 0 0 0 95.83 2437.99 2646.34 0.48 0.52 0.1 0.6 0 0.1 0 0 0 0 0 0 95 2453.74 2661.94 0.49 0.53 0.2 0.8 0 0.1 0 0 0 0 0 0 94.15 2469.46 2677.51 0.49 0.53 0.2 0.9 0 0.2 0 0 0 0 0 0 93.31 2484.94 2692.85 0.5 0.54 0.3 1.1 0 0.2 0 0 0 0 0 0 92.46 2500.22 2707.99 0.5 0.55 0.3 1.3 0.1 0.2 0 0 0 0 0 0 91.61 2515.33 2722.96 0.51 0.55 0.4 1.5 0.1 0.3 0 0 0 0 0 0 90.77 2530.29 2737.79 0.51 0.56 0.4 1.7 0.1 0.3 0 0 0 0 0 0 89.79 2547.42 2754.77 0.51 0.56 0.5 1.9 0.1 0.4 0 0 0 0 0 0 88.81 2564.4 2771.6 0.52 0.57 0.5 2.2 0.1 0.4 0 0 0 0 0 0 87.83 2581.25 2788.31 0.52 0.58 0.6 2.5 0.1 0.5 0 0 0 0 0 0 86.85 2597.99 2804.9 0.53 0.58 0.7 2.8 0.1 0.5 0 0 0 0 0 0 85.87 2614.63 2821.4 0.53 0.59 0.8 3.2 0.1 0.6 0 0 0 0 0 0 84.89 2631.18 2837.81 0.53 0.6 0.9 3.5 0.2 0.7 0 0 0 0 0 0 83.91 2647.64 2854.14 0.54 0.6 1 3.9 0.2 0.7 0 0 0 0 0 0 82.94 2664.04 2870.4 0.54 0.61 1.1 4.3 0.2 0.8 0 0 0 0 0 0 81.96 2680.36 2886.59 0.55 0.61 1.2 4.7 0.2 0.9 0 0 0 0 0 0 80.98 2696.62 2902.72 0.55 0.61 1.4 5.1 0.3 1 0 0 0 0 0 0 80 2712.83 2918.8 0.55 0.62 1.5 5.6 0.3 1 0 0 0 0 0 0 79 2652.83 2858.8 0.56 0.62 1.6 5.9 0.3 1.1 0 0 0 0 0 0 78 2592.83 2798.8 0.56 0.62 1.6 6.1 0.3 1.1 0 0 0 0 0 0 77 2532.83 2738.8 0.56 0.62 1.7 6.3 0.3 1.2 0 0 0 0 0 0 76 2472.83 2678.8 0.56 0.62 1.7 6.3 0.3 1.2 0 0 0 0 0 0 182
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 75 2412.83 2618.8 0.56 0.62 1.7 6.4 0.3 1.2 0 0 0 0 0 0 73 2500.85 2706.82 0.56 0.62 1.7 6.4 0.3 1.2 0 0 0 0 0 0 72 2541.8 2747.77 0.56 0.62 1.7 6.4 0.3 1.2 0 0 0 0 0 0 71 2581.24 2787.21 0.56 0.62 1.7 6.5 0.3 1.2 0 0 0 0 0 0 70 2619.42 2825.39 0.56 0.62 1.8 6.5 0.3 1.2 0 0 0 0 0 0 69 2656.53 2862.51 0.56 0.62 1.8 6.6 0.3 1.2 0 0 0 0 0 0 68 2692.73 2898.71 0.56 0.62 1.8 6.7 0.3 1.2 0 0 0 0 0 0 67 2723.4 2929.29 0.56 0.62 1.8 6.7 0.3 1.3 0 0 0 0 0 0 66 2747.7 2953.4 0.56 0.62 1.8 6.8 0.3 1.3 0 0 0 0 0 0 65 2707.7 2913.4 0.57 0.63 1.9 6.9 0.3 1.3 0 0 0 0 0 0 64 2667.7 2873.4 0.57 0.63 1.9 7 0.4 1.3 0 0 0 0 0 0 63 2627.7 2833.4 0.57 0.63 1.9 7.1 0.4 1.3 0 0 0 0 0 0 62 2587.7 2793.4 0.57 0.63 1.9 7.1 0.4 1.3 0 0 0 0 0 0 61 2547.7 2753.4 0.57 0.63 1.9 7.2 0.4 1.3 0 0 0 0 0 0 60 2507.7 2713.4 0.57 0.63 2 7.2 0.4 1.3 0 0 0 0 0 0 59 2467.7 2673.4 0.57 0.63 2 7.2 0.4 1.3 0 0 0 0 0 0 58 2427.7 2633.4 0.57 0.63 2 7.2 0.4 1.3 0 0 0 0 0 0 57.25 2397.7 2603.4 0.57 0.63 2 7.2 0.4 1.3 0 0 0 0 0 0 57 2387.7 2593.4 0.57 0.63 2 7.2 0.4 1.3 0 0 0 0 0 0 56 2347.7 2553.4 0.57 0.63 2 7.2 0.4 1.3 0 0 0 0 0 0 55 2307.7 2513.4 0.57 0.63 2 7.2 0.4 1.3 0 0 0 0 0 0 54 2267.7 2473.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 53.5 2247.7 2453.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 53 2227.7 2433.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 52 2187.7 2393.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 183
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 51 2147.7 2353.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 50 2107.7 2313.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 48.5 2047.7 2253.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 48 2027.7 2233.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 47 1987.7 2193.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 46 1947.7 2153.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 45 1907.7 2113.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 44 1867.7 2073.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 43 1827.7 2033.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 42 1787.7 1993.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 41 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 40 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 39 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 38 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 37 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 36 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 35 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.3 0 0 0 0 0 0 34 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 33 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 32 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 31 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 30 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 29 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 28 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 27 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 184
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 26 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 25 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 24 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 22 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 21 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 20 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 19 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 18 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 17 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 16 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 15 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 14 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 13 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 12 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 11 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 10 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 9 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 8 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 7 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 6 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 5 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 4 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 3 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 2 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 1 1747.7 1953.4 0.57 0.63 2 7.3 0.4 1.4 0 0 0 0 0 0 185
Top of Early Mature (oil) = 0.5 (%Ro) found at 93.0 (my) at bed top. Top of Early Mature (oil) = 0.5 (%Ro) found at 99.6 (my) at bed bottom
186
Formation Name: Hoyle Bay (Late Triassic) Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 229 0 0 0.2 0.2 0 0 0 0 0 0 0 0 0 0 228 0 531.29 0.2 0.24 0 0 0 0 0 0 0 0 0 0 227.5 0 746.3 0.2 0.26 0 0 0 0 0 0 0 0 0 0 227 0 950.54 0.2 0.27 0 0 0 0 0 0 0 0 0 0 226.1 26.36 965.37 0.22 0.3 0 0 0 0 0 0 0 0 0 0 225.2 52.3 980.62 0.22 0.3 0 0 0 0 0 0 0 0 0 0 224.4 230.84 1099.51 0.23 0.3 0 0 0 0 0 0 0 0 0 0 223.6 380.49 1212.72 0.23 0.31 0 0 0 0 0 0 0 0 0 0 222.8 516.69 1322.92 0.25 0.32 0 0 0 0 0 0 0 0 0 0 222 644.73 1431.02 0.26 0.34 0 0 0 0 0 0 0 0 0 0 221 701.51 1480.07 0.27 0.35 0 0 0 0 0 0 0 0 0 0 220 757.28 1528.8 0.28 0.36 0 0 0 0 0 0 0 0 0 0 219 812.17 1577.25 0.29 0.37 0 0 0 0 0 0 0 0 0 0 218 904.96 1660.13 0.29 0.37 0 0 0 0 0 0 0 0 0 0 217 1004.3 1750.02 0.3 0.38 0 0 0 0 0 0 0 0 0 0 216 1106.14 1843.23 0.3 0.39 0 0 0 0 0 0 0 0 0 0 215 1208.81 1938.11 0.3 0.39 0 0 0 0 0 0 0 0 0 0 214 1311.56 2033.85 0.3 0.4 0 0 0 0 0 0 0 0 0 0 213 1542.8 2251.65 0.31 0.4 0 0 0 0 0 0 0 0 0 0 212 1775.18 2473.04 0.31 0.41 0 0 0 0 0 0 0 0 0 0 211 1777.08 2474.86 0.32 0.41 0 0 0 0 0 0 0 0 0 0 210 1778.98 2476.68 0.32 0.42 0 0 0 0 0 0 0 0 0 0 209 1780.89 2478.5 0.33 0.42 0 0 0 0 0 0 0 0 0 0
187
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 208 1782.79 2480.33 0.33 0.42 0 0 0 0 0 0 0 0 0 0 207 1784.7 2482.15 0.33 0.43 0 0 0 0 0 0 0 0 0 0 206 1786.6 2483.97 0.33 0.43 0 0 0 0 0 0 0 0 0 0 205 1788.5 2485.8 0.34 0.43 0 0 0 0 0 0 0 0 0 0 204 1790.41 2487.62 0.34 0.43 0 0 0 0 0 0 0 0 0 0 203 1792.31 2489.44 0.34 0.43 0 0 0 0 0 0 0 0 0 0 202 1794.21 2491.26 0.34 0.43 0 0 0 0 0 0 0 0 0 0 201 1796.12 2493.09 0.34 0.44 0 0 0 0 0 0 0 0 0 0 200 1798.02 2494.91 0.34 0.44 0 0 0 0 0 0 0 0 0 0 199 1799.92 2496.73 0.35 0.44 0 0 0 0 0 0 0 0 0 0 198 1801.83 2498.56 0.35 0.44 0 0 0 0 0 0 0 0 0 0 197 1803.73 2500.38 0.35 0.44 0 0 0 0 0 0 0 0 0 0 196 1805.63 2502.2 0.35 0.44 0 0 0 0 0 0 0 0 0 0 195 1807.53 2504.03 0.35 0.45 0 0 0 0 0 0 0 0 0 0 194 1809.44 2505.85 0.35 0.45 0 0 0 0 0 0 0 0 0 0 193 1811.34 2507.67 0.35 0.45 0 0.1 0 0 0 0 0 0 0 0 192 1813.24 2509.49 0.35 0.45 0 0.1 0 0 0 0 0 0 0 0 191 1815.14 2511.32 0.35 0.45 0 0.1 0 0 0 0 0 0 0 0 190 1817.04 2513.14 0.35 0.45 0 0.1 0 0 0 0 0 0 0 0 189 1818.95 2514.96 0.35 0.45 0 0.1 0 0 0 0 0 0 0 0 188 1820.85 2516.79 0.35 0.45 0 0.1 0 0 0 0 0 0 0 0 187 1822.75 2518.61 0.35 0.46 0 0.1 0 0 0 0 0 0 0 0 186 1824.65 2520.43 0.35 0.46 0 0.1 0 0 0 0 0 0 0 0 185 1826.55 2522.26 0.35 0.46 0 0.1 0 0 0 0 0 0 0 0 184 1828.45 2524.08 0.36 0.46 0 0.1 0 0 0 0 0 0 0 0 188
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 183 1830.35 2525.9 0.36 0.46 0 0.1 0 0 0 0 0 0 0 0 182 1911.39 2603.72 0.36 0.46 0 0.1 0 0 0 0 0 0 0 0 181 1985.13 2674.7 0.36 0.46 0 0.1 0 0 0 0 0 0 0 0 180 2055.08 2742.17 0.36 0.47 0 0.1 0 0 0 0 0 0 0 0 179 2059.06 2746.01 0.36 0.47 0 0.1 0 0 0 0 0 0 0 0 178 2063.08 2749.89 0.37 0.48 0 0.1 0 0 0 0 0 0 0 0 177 2067.13 2753.8 0.37 0.48 0 0.2 0 0 0 0 0 0 0 0 176 2071.22 2757.75 0.37 0.49 0 0.2 0 0 0 0 0 0 0 0 175 2075.33 2761.72 0.38 0.49 0 0.2 0 0 0 0 0 0 0 0 174 2079.47 2765.73 0.38 0.49 0 0.2 0 0 0 0 0 0 0 0 173 2083.65 2769.76 0.38 0.5 0 0.2 0 0 0 0 0 0 0 0 172 2090.39 2776.27 0.38 0.5 0 0.3 0 0 0 0 0 0 0 0 171 2097.07 2782.73 0.39 0.5 0 0.3 0 0.1 0 0 0 0 0 0 170 2103.72 2789.15 0.39 0.5 0 0.3 0 0.1 0 0 0 0 0 0 169 2110.32 2795.53 0.39 0.51 0 0.3 0 0.1 0 0 0 0 0 0 168 2116.88 2801.88 0.39 0.51 0 0.3 0 0.1 0 0 0 0 0 0 167 2123.41 2808.19 0.4 0.51 0 0.4 0 0.1 0 0 0 0 0 0 166 2129.9 2814.47 0.4 0.51 0 0.4 0 0.1 0 0 0 0 0 0 165 2136.36 2820.72 0.4 0.51 0 0.4 0 0.1 0 0 0 0 0 0 164 2142.8 2826.95 0.4 0.51 0 0.4 0 0.1 0 0 0 0 0 0 163 2149.21 2833.15 0.4 0.52 0 0.5 0 0.1 0 0 0 0 0 0 162 2155.59 2839.32 0.41 0.52 0 0.5 0 0.1 0 0 0 0 0 0 161 2161.95 2845.48 0.41 0.52 0 0.5 0 0.1 0 0 0 0 0 0 160 2168.28 2851.61 0.41 0.52 0 0.6 0 0.1 0 0 0 0 0 0 159 2174.6 2857.72 0.41 0.52 0 0.6 0 0.1 0 0 0 0 0 0 189
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 158 2180.89 2863.82 0.41 0.53 0 0.7 0 0.1 0 0 0 0 0 0 157 2187.16 2869.89 0.41 0.53 0 0.7 0 0.1 0 0 0 0 0 0 156 2193.42 2875.95 0.42 0.53 0 0.7 0 0.1 0 0 0 0 0 0 155 2199.66 2881.99 0.42 0.53 0 0.8 0 0.1 0 0 0 0 0 0 154 2205.88 2888.02 0.42 0.53 0 0.8 0 0.2 0 0 0 0 0 0 153 2212.08 2894.03 0.42 0.53 0 0.9 0 0.2 0 0 0 0 0 0 152 2218.27 2900.03 0.42 0.54 0 0.9 0 0.2 0 0 0 0 0 0 151 2224.44 2906.01 0.42 0.54 0 1 0 0.2 0 0 0 0 0 0 150 2230.6 2911.98 0.42 0.54 0 1 0 0.2 0 0 0 0 0 0 149 2236.75 2917.94 0.42 0.54 0 1.1 0 0.2 0 0 0 0 0 0 148 2269.02 2949.25 0.42 0.55 0 1.2 0 0.2 0 0 0 0 0 0 147 2300.98 2980.27 0.43 0.55 0 1.3 0 0.2 0 0 0 0 0 0 146 2332.68 3011.05 0.43 0.55 0 1.4 0 0.3 0 0 0 0 0 0 145 2364.14 3041.62 0.43 0.56 0 1.5 0 0.3 0 0 0 0 0 0 144 2395.4 3072.02 0.43 0.56 0 1.6 0 0.3 0 0 0 0 0 0 143 2426.48 3102.26 0.43 0.57 0 1.8 0 0.3 0 0 0 0 0 0 142 2457.4 3132.36 0.44 0.57 0 2.1 0 0.4 0 0 0 0 0 0 141 2509.29 3182.91 0.44 0.58 0 2.4 0 0.4 0 0 0 0 0 0 140 2560.83 3233.15 0.45 0.59 0.1 2.8 0 0.5 0 0 0 0 0 0 139 2612.06 3283.14 0.45 0.59 0.1 3.3 0 0.6 0 0 0 0 0 0 138 2663.01 3332.9 0.46 0.6 0.1 4.1 0 0.8 0 0 0 0 0 0 137 2713.73 3382.46 0.47 0.61 0.1 5.1 0 0.9 0 0 0 0 0 0 136 2764.23 3431.84 0.48 0.62 0.2 6.4 0 1.2 0 0 0 0 0 0 135 2814.53 3481.07 0.49 0.63 0.2 8.2 0 1.5 0 0 0 0 0 0 134 2864.66 3530.15 0.5 0.64 0.3 10.4 0.1 1.9 0 0 0 0 0 0 190
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 133 2914.62 3579.1 0.51 0.64 0.4 13.4 0.1 2.5 0 0 0 0 0 0 132 2964.44 3627.93 0.52 0.65 0.5 17.1 0.1 3.2 0 0 0 0 0 0 131 3014.11 3676.65 0.53 0.66 0.7 21.8 0.1 4 0 0 0 0 0 0 130 3063.65 3725.26 0.54 0.67 1 27.6 0.2 5.1 0 0 0 0 0 0 129 3135.96 3796.26 0.55 0.68 1.3 33.6 0.2 6.2 0 0 0 0 0 0 128 3215.74 3874.65 0.55 0.69 1.5 38.9 0.3 7.2 0 0 0 0 0 0 127 3299.59 3957.11 0.56 0.7 1.8 43.6 0.3 8.1 0 0 0 0 0 0 126 3385.85 4041.99 0.57 0.7 2 47.9 0.4 8.9 0 0 0 0 0 0 125 3473.61 4128.41 0.57 0.71 2.3 52.1 0.4 9.7 0 0 0 0 0 0 124 3482.65 4137.31 0.58 0.71 2.5 56.4 0.5 10.5 0 0 0 0 0 0 123 3491.51 4146.05 0.58 0.71 2.8 60.8 0.5 11.3 0 0 0 0 0 0 122 3500.23 4154.63 0.59 0.72 3.1 65.3 0.6 12.1 0 0 0 0 0 0 121 3508.8 4163.08 0.6 0.72 3.5 70 0.6 13 0 0 0 0 0 0 120 3517.27 4171.42 0.6 0.73 3.8 74.7 0.7 13.9 0 0 0 0 0 0 119 3525.62 4179.65 0.61 0.73 4.2 79.8 0.8 14.8 0 0 0 0 0 0 118 3533.88 4187.79 0.61 0.73 4.7 85.5 0.9 15.9 0 0 0 0 0 0 117 3552.45 4206.09 0.61 0.74 5.2 91.7 1 17 0 0 0 0 0 0 116 3571.41 4224.78 0.62 0.74 5.8 98.3 1.1 18.3 0 0 0 0 0 0 115 3590.68 4243.77 0.62 0.74 6.4 105.3 1.2 19.6 0 0 0 0 0 0 114 3610.19 4263.01 0.63 0.75 7.1 112.6 1.3 20.9 0 0 0 0 0 0 113 3629.89 4282.44 0.63 0.75 7.9 120.3 1.5 22.4 0 0 0 0 0 0 112 3649.75 4302.03 0.63 0.76 8.8 128.4 1.6 23.9 0 0 0 0 0 0 111 3669.75 4321.75 0.64 0.76 9.7 136.9 1.8 25.4 0 0 0 0 0 0 110 3689.85 4341.58 0.64 0.76 10.7 145.8 2 27.1 0 0 0 0.5 0 0.1 109 3795.61 4445.94 0.64 0.77 12.3 157.7 2.3 29.3 0 0 0 15.7 0 2.9 191
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 108 3892.7 4541.81 0.65 0.78 15.4 178.3 2.9 33.1 0 0 0 39.1 0 7.3 107 3985.97 4633.95 0.66 0.8 21.7 211.2 4 39.3 0 0 0 74.6 0 13.9 106 4077.07 4723.99 0.68 0.84 33.6 253.7 6.2 47.2 0 0.1 0 119.4 0 22.2 105 4126.78 4773.14 0.71 0.87 52.8 296.1 9.8 55.1 0 0.1 0 163.1 0 30.3 104 4176.15 4821.97 0.73 0.9 78.3 316.4 14.5 59 0 0.2 0 184.5 0 34.4 103 4225.24 4870.52 0.74 0.93 108.4 331.1 20.1 61.8 0 0.3 0 200.4 0 37.3 102 4274.09 4918.85 0.76 0.98 143.3 341.3 26.6 63.9 0 0.5 0 211.6 0 39.5 101 4322.73 4966.99 0.78 1.03 181.1 345.3 33.7 64.9 0 0.7 35.2 216.6 6.5 40.4 100.13 4352.53 4996.48 0.8 1.07 210.3 347.4 39.1 65.5 0 1 65.3 219.1 12.1 40.9 99.25 4384.07 5027.71 0.82 1.1 234 348.7 43.5 66.1 0.1 1.4 90.1 220.9 16.7 41.3 98.38 4416.91 5060.22 0.84 1.13 253.2 349.4 47.1 66.6 0.1 1.7 110.2 222.1 20.5 41.5 97.5 4450.74 5093.71 0.85 1.14 268.6 349.7 50 67 0.1 2.1 126.5 223 23.5 41.7 96.67 4466.29 5109.11 0.86 1.16 280.9 349.9 52.3 67.4 0.1 2.5 139.3 223.2 25.9 41.7 95.83 4481.43 5124.1 0.87 1.17 291.9 350 54.3 67.9 0.1 2.9 150.7 223.3 28.1 41.8 95 4496.25 5138.78 0.88 1.19 301.7 350 56.2 68.5 0.2 3.5 161 223.3 30 41.8 94.15 4511.05 5153.44 0.89 1.21 310 350 57.8 69.1 0.2 4.1 169.7 223.3 31.6 41.8 93.31 4525.63 5167.89 0.9 1.23 316.4 350 59 69.8 0.2 4.8 176.4 223.3 32.9 41.8 92.46 4540.04 5182.15 0.91 1.25 321.3 350 59.9 70.5 0.3 5.5 181.8 223.3 33.9 41.8 91.61 4554.28 5196.27 0.93 1.26 325.4 350 60.7 71.2 0.3 6.2 186.2 223.3 34.7 41.8 90.77 4568.4 5210.25 0.94 1.28 328.7 350 61.4 71.9 0.3 6.9 189.8 223.3 35.4 41.8 89.79 4584.57 5226.27 0.95 1.29 331.9 350 62 72.7 0.4 7.7 193.5 223.3 36.1 41.8 88.81 4600.61 5242.16 0.96 1.31 334.5 350 62.6 73.5 0.4 8.5 196.5 223.3 36.6 41.8 87.83 4616.53 5257.93 0.97 1.32 336.7 350 63 74.3 0.5 9.3 199.1 223.3 37.1 41.8 86.85 4632.35 5273.61 0.98 1.33 338.4 350 63.4 75.1 0.5 10.1 201.2 223.3 37.5 41.8 85.87 4648.09 5289.2 0.99 1.34 339.9 350 63.7 75.8 0.6 10.8 203.1 223.3 37.9 41.8 192
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 84.89 4663.74 5304.72 1 1.35 341.1 350 64 76.5 0.6 11.5 204.7 223.3 38.2 41.8 83.91 4679.33 5320.17 1.01 1.36 342.1 350 64.2 77.3 0.7 12.3 206 223.3 38.4 41.8 82.94 4694.86 5335.55 1.02 1.37 342.9 350 64.4 77.9 0.7 12.9 207.3 223.3 38.7 41.8 81.96 4710.32 5350.88 1.02 1.38 343.6 350 64.6 78.6 0.8 13.6 208.3 223.3 38.9 41.8 80.98 4725.74 5366.16 1.03 1.38 344.2 350 64.7 79.2 0.8 14.2 209.3 223.3 39.1 41.8 80 4741.11 5381.4 1.04 1.39 344.8 350 64.9 79.9 0.9 14.9 210.2 223.3 39.2 41.8 79 4681.11 5321.4 1.04 1.39 345.2 350 65 80.4 0.9 15.4 210.6 223.3 39.3 41.8 78 4621.11 5261.4 1.05 1.4 345.4 350 65.1 80.8 0.9 15.8 210.8 223.3 39.4 41.8 77 4561.11 5201.4 1.05 1.4 345.5 350 65.1 81 0.9 16 210.9 223.3 39.4 41.8 76 4501.11 5141.4 1.05 1.4 345.6 350 65.1 81.1 0.9 16.1 211 223.3 39.4 41.8 75 4441.11 5081.4 1.05 1.4 345.6 350 65.1 81.2 0.9 16.2 211 223.3 39.4 41.8 74 4486.31 5126.6 1.05 1.4 345.7 350 65.1 81.2 1 16.2 211 223.3 39.4 41.8 73 4529.13 5169.42 1.05 1.4 345.7 350 65.2 81.3 1 16.3 211.1 223.3 39.4 41.8 72 4570.08 5210.37 1.05 1.4 345.7 350 65.2 81.3 1 16.3 211.1 223.3 39.4 41.8 71 4609.52 5249.8 1.05 1.4 345.8 350 65.2 81.4 1 16.4 211.1 223.3 39.4 41.8 70 4647.7 5287.99 1.05 1.4 345.8 350 65.2 81.4 1 16.4 211.1 223.3 39.4 41.8 69 4684.81 5325.1 1.05 1.4 345.8 350 65.2 81.5 1 16.5 211.2 223.3 39.4 41.8 68 4721.01 5361.3 1.05 1.4 345.9 350 65.2 81.6 1 16.6 211.2 223.3 39.4 41.8 67 4751.14 5391.34 1.05 1.41 345.9 350 65.2 81.7 1 16.7 211.5 223.3 39.5 41.8 66 4774.2 5414.2 1.06 1.41 346 350 65.3 81.8 1 16.8 212.2 223.3 39.6 41.8 65 4734.2 5374.2 1.06 1.41 346.1 350 65.3 81.9 1 16.9 212.2 223.3 39.6 41.8 64 4694.2 5334.2 1.06 1.41 346.1 350 65.3 82 1 17 212.3 223.3 39.7 41.8 63 4654.2 5294.2 1.06 1.41 346.1 350 65.3 82.1 1 17.1 212.3 223.3 39.7 41.8 62 4614.2 5254.2 1.06 1.41 346.2 350 65.3 82.1 1 17.1 212.4 223.3 39.7 41.8 61 4574.2 5214.2 1.06 1.41 346.2 350 65.3 82.2 1 17.2 212.4 223.3 39.7 41.8 193
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 60 4534.2 5174.2 1.06 1.41 346.2 350 65.3 82.2 1 17.2 212.4 223.3 39.7 41.8 59 4494.2 5134.2 1.06 1.41 346.2 350 65.3 82.3 1 17.3 212.4 223.3 39.7 41.8 58 4454.2 5094.2 1.06 1.41 346.3 350 65.3 82.3 1 17.3 212.4 223.3 39.7 41.8 57.25 4424.2 5064.2 1.06 1.41 346.3 350 65.3 82.3 1 17.3 212.4 223.3 39.7 41.8 57 4414.2 5054.2 1.06 1.41 346.3 350 65.3 82.3 1 17.3 212.4 223.3 39.7 41.8 56 4374.2 5014.2 1.06 1.41 346.3 350 65.3 82.3 1 17.3 212.4 223.3 39.7 41.8 55 4334.2 4974.2 1.06 1.41 346.3 350 65.3 82.3 1 17.3 212.4 223.3 39.7 41.8 54 4294.2 4934.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 53.5 4274.2 4914.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 53 4254.2 4894.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 52 4214.2 4854.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 51 4174.2 4814.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 50 4134.2 4774.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 49 4094.2 4734.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 48.5 4074.2 4714.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 48 4054.2 4694.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 47 4014.2 4654.2 1.06 1.41 346.3 350 65.3 82.4 1 17.4 212.5 223.3 39.7 41.8 46 3974.2 4614.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 45 3934.2 4574.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 44 3894.2 4534.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 43 3854.2 4494.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 42 3814.2 4454.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 41 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 40 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 39 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 194
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 38 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 37 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 36 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 35 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 34 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 33 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 32 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 31 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 30 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 29 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 28 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 27 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 26 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 25 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 24 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 23 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 22 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 21 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 20 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 19 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 18 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 17 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 16 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 15 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 14 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 195
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 13 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 12 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 11 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 10 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 9 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 8 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 7 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 6 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 5 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 4 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 3 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 2 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 1 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8 0 3774.2 4414.2 1.06 1.41 346.3 350 65.4 82.4 1 17.4 212.5 223.3 39.7 41.8
196
Top of Early Mature (oil) = 0.5 (%Ro) found at 134.3 (my) at bed top. Top of Early Mature (oil) = 0.5 (%Ro) found at 171.8 (my) at bed bottom. Bottom of Early Mature (oil) = 0.7 (%Ro) found at 105.3 (my) at bed top. Bottom of Early Mature (oil) = 0.7 (%Ro) found at 126.1 (my) at bed bottom. Top of Mid Mature (oil) = 0.7 (%Ro) found at 105.3 (my) at bed top. Top of Mid Mature (oil) = 0.7 (%Ro) found at 126.1 (my) at bed bottom. Bottom of Mid Mature (oil) = 1 (%Ro) found at 84.7 (my) at bed top. Bottom of Mid Mature (oil) = 1 (%Ro) found at 101.6 (my) at bed bottom. Top of Late Mature (oil) = 1 (%Ro) found at 84.7 (my) at bed top. Top of Late Mature (oil) = 1 (%Ro) found at 101.6 (my) at bed bottom. Bottom of Late Mature (oil) = 1.3 (%Ro) found at 89.3 (my) at bed bottom. Top of Main Gas Generation = 1.3 (%Ro) found at 89.3 (my) at bed bottom.
197
Formation Name: Murray Harbour Fm. (Middle Triassic) Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 240 0 0 0.2 0.2 0 0 0 0 0 0 0 0 0 0 239 0 93.43 0.2 0.23 0 0 0 0 0 0 0 0 0 0 238 0 175.61 0.2 0.23 0 0 0 0 0 0 0 0 0 0 237 0 251.13 0.2 0.23 0 0 0 0 0 0 0 0 0 0 236 0 322.14 0.2 0.24 0 0 0 0 0 0 0 0 0 0 235 20.67 336.39 0.22 0.25 0 0 0 0 0 0 0 0 0 0 234 40.59 350.55 0.23 0.25 0 0 0 0 0 0 0 0 0 0 233 59.87 364.61 0.23 0.25 0 0 0 0 0 0 0 0 0 0 232 78.59 378.57 0.23 0.26 0 0 0 0 0 0 0 0 0 0 231 96.83 392.45 0.23 0.26 0 0 0 0 0 0 0 0 0 0 230 114.63 406.23 0.23 0.26 0 0 0 0 0 0 0 0 0 0 229 132.05 419.93 0.23 0.26 0 0 0 0 0 0 0 0 0 0 228 621.29 851.95 0.25 0.27 0 0 0 0 0 0 0 0 0 0 227.5 830.53 1049.87 0.26 0.29 0 0 0 0 0 0 0 0 0 0 227 1031.03 1242.57 0.28 0.3 0 0 0 0 0 0 0 0 0 0 226.1 1045.64 1256.69 0.3 0.32 0 0 0 0 0 0 0 0 0 0 225.2 1060.66 1271.23 0.3 0.33 0 0 0 0 0 0 0 0 0 0 224.4 1177.94 1385 0.31 0.34 0 0 0 0 0 0 0 0 0 0 223.6 1289.85 1494.01 0.32 0.35 0 0 0 0 0 0 0 0 0 0 222.8 1398.95 1600.62 0.34 0.35 0 0 0 0 0 0 0 0 0 0 222 1506.1 1705.62 0.35 0.37 0 0 0 0 0 0 0 0 0 0
198
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 221 1554.76 1753.37 0.36 0.39 0 0 0 0 0 0 0 0 0 0 220 1603.12 1800.88 0.37 0.4 0 0 0 0 0 0 0 0 0 0 219 1651.23 1848.17 0.38 0.41 0 0 0 0 0 0 0 0 0 0 218 1733.54 1929.19 0.39 0.42 0 0 0 0 0 0 0 0 0 0 217 1822.88 2017.22 0.39 0.42 0 0 0 0 0 0 0 0 0 0 216 1915.56 2108.65 0.4 0.43 0 0 0 0 0 0 0 0 0 0 215 2009.95 2201.87 0.41 0.43 0 0 0 0 0 0 0 0 0 0 214 2105.23 2296.06 0.41 0.43 0 0 0 0 0 0 0 0 0 0 213 2322.12 2510.74 0.41 0.44 0 0 0 0 0 0 0 0 0 0 212 2542.72 2729.44 0.42 0.44 0 0 0 0 0 0 0 0 0 0 211 2544.54 2731.24 0.42 0.45 0 0.1 0 0 0 0 0 0 0 0 210 2546.35 2733.04 0.43 0.45 0 0.1 0 0 0 0 0 0 0 0 209 2548.17 2734.85 0.43 0.46 0 0.1 0 0 0 0 0 0 0 0 208 2549.99 2736.65 0.43 0.46 0 0.1 0 0 0 0 0 0 0 0 207 2551.81 2738.45 0.43 0.47 0 0.1 0 0 0 0 0 0 0 0 206 2553.62 2740.25 0.44 0.47 0 0.1 0 0 0 0 0 0 0 0 205 2555.44 2742.06 0.44 0.47 0 0.1 0 0 0 0 0 0 0 0 204 2557.26 2743.86 0.44 0.48 0 0.1 0 0 0 0 0 0 0 0 203 2559.07 2745.66 0.44 0.48 0 0.1 0 0 0 0 0 0 0 0 202 2560.89 2747.47 0.44 0.48 0 0.2 0 0 0 0 0 0 0 0 201 2562.71 2749.27 0.45 0.49 0.1 0.2 0 0 0 0 0 0 0 0 200 2564.52 2751.07 0.45 0.49 0.1 0.2 0 0 0 0 0 0 0 0 199 2566.34 2752.87 0.45 0.49 0.1 0.2 0 0 0 0 0 0 0 0 198 2568.16 2754.68 0.45 0.49 0.1 0.2 0 0 0 0 0 0 0 0 197 2569.98 2756.48 0.45 0.49 0.1 0.2 0 0 0 0 0 0 0 0 199
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 196 2571.79 2758.28 0.46 0.5 0.1 0.2 0 0 0 0 0 0 0 0 195 2573.61 2760.09 0.46 0.5 0.1 0.2 0 0 0 0 0 0 0 0 194 2575.43 2761.89 0.46 0.5 0.1 0.3 0 0 0 0 0 0 0 0 193 2577.25 2763.69 0.46 0.5 0.1 0.3 0 0 0 0 0 0 0 0 192 2579.06 2765.49 0.46 0.5 0.1 0.3 0 0.1 0 0 0 0 0 0 191 2580.88 2767.3 0.46 0.5 0.1 0.3 0 0.1 0 0 0 0 0 0 190 2582.7 2769.1 0.47 0.5 0.1 0.3 0 0.1 0 0 0 0 0 0 189 2584.51 2770.9 0.47 0.51 0.1 0.3 0 0.1 0 0 0 0 0 0 188 2586.33 2772.71 0.47 0.51 0.1 0.3 0 0.1 0 0 0 0 0 0 187 2588.15 2774.51 0.47 0.51 0.1 0.3 0 0.1 0 0 0 0 0 0 186 2589.97 2776.31 0.47 0.51 0.1 0.3 0 0.1 0 0 0 0 0 0 185 2591.78 2778.12 0.47 0.51 0.1 0.4 0 0.1 0 0 0 0 0 0 184 2593.6 2779.92 0.47 0.51 0.1 0.4 0 0.1 0 0 0 0 0 0 183 2595.42 2781.72 0.48 0.51 0.1 0.4 0 0.1 0 0 0 0 0 0 182 2673 2858.72 0.48 0.51 0.1 0.4 0 0.1 0 0 0 0 0 0 181 2743.77 2928.98 0.48 0.51 0.1 0.4 0 0.1 0 0 0 0 0 0 180 2811.05 2995.81 0.48 0.52 0.2 0.5 0 0.1 0 0 0 0 0 0 179 2814.89 2999.62 0.49 0.52 0.2 0.6 0 0.1 0 0 0 0 0 0 178 2818.76 3003.46 0.49 0.52 0.2 0.6 0 0.1 0 0 0 0 0 0 177 2822.66 3007.33 0.5 0.53 0.2 0.7 0 0.1 0 0 0 0 0 0 176 2826.59 3011.24 0.5 0.53 0.3 0.8 0 0.2 0 0 0 0 0 0 175 2830.55 3015.18 0.5 0.54 0.3 0.9 0.1 0.2 0 0 0 0 0 0 174 2834.55 3019.14 0.51 0.54 0.3 1 0.1 0.2 0 0 0 0 0 0 173 2838.57 3023.14 0.51 0.54 0.4 1.1 0.1 0.2 0 0 0 0 0 0 172 2845.06 3029.59 0.51 0.54 0.4 1.1 0.1 0.2 0 0 0 0 0 0 200
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 171 2851.51 3035.99 0.51 0.55 0.4 1.2 0.1 0.2 0 0 0 0 0 0 170 2857.91 3042.35 0.51 0.55 0.4 1.3 0.1 0.2 0 0 0 0 0 0 169 2864.27 3048.68 0.52 0.55 0.5 1.4 0.1 0.3 0 0 0 0 0 0 168 2870.6 3054.96 0.52 0.56 0.5 1.5 0.1 0.3 0 0 0 0 0 0 167 2876.9 3061.22 0.52 0.56 0.5 1.6 0.1 0.3 0 0 0 0 0 0 166 2883.16 3067.44 0.52 0.56 0.6 1.7 0.1 0.3 0 0 0 0 0 0 165 2889.4 3073.64 0.52 0.57 0.6 1.8 0.1 0.3 0 0 0 0 0 0 164 2895.61 3079.81 0.53 0.57 0.7 2 0.1 0.4 0 0 0 0 0 0 163 2901.79 3085.95 0.53 0.57 0.7 2.1 0.1 0.4 0 0 0 0 0 0 162 2907.95 3092.07 0.53 0.57 0.8 2.2 0.1 0.4 0 0 0 0 0 0 161 2914.09 3098.17 0.53 0.58 0.8 2.4 0.2 0.4 0 0 0 0 0 0 160 2920.21 3104.25 0.53 0.58 0.9 2.5 0.2 0.5 0 0 0 0 0 0 159 2926.3 3110.31 0.54 0.58 0.9 2.7 0.2 0.5 0 0 0 0 0 0 158 2932.38 3116.35 0.54 0.59 1 2.8 0.2 0.5 0 0 0 0 0 0 157 2938.44 3122.38 0.54 0.59 1 3 0.2 0.6 0 0 0 0 0 0 156 2944.49 3128.38 0.54 0.59 1.1 3.2 0.2 0.6 0 0 0 0 0 0 155 2950.51 3134.37 0.55 0.6 1.2 3.3 0.2 0.6 0 0 0 0 0 0 154 2956.53 3140.35 0.55 0.6 1.2 3.5 0.2 0.7 0 0 0 0 0 0 153 2962.52 3146.31 0.55 0.6 1.3 3.7 0.2 0.7 0 0 0 0 0 0 152 2968.51 3152.25 0.55 0.6 1.4 3.9 0.3 0.7 0 0 0 0 0 0 151 2974.48 3158.19 0.56 0.61 1.5 4.1 0.3 0.8 0 0 0 0 0 0 150 2980.43 3164.11 0.56 0.61 1.5 4.4 0.3 0.8 0 0 0 0 0 0 149 2986.37 3170.01 0.56 0.61 1.6 4.6 0.3 0.9 0 0 0 0 0 0 148 3017.6 3201.06 0.56 0.61 1.7 4.9 0.3 0.9 0 0 0 0 0 0 147 3048.55 3231.82 0.57 0.62 1.8 5.2 0.3 1 0 0 0 0 0 0 201
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 146 3079.26 3262.36 0.57 0.62 2 5.6 0.4 1 0 0 0 0 0 0 145 3109.77 3292.69 0.57 0.62 2.2 6 0.4 1.1 0 0 0 0 0 0 144 3140.1 3322.85 0.58 0.62 2.4 6.6 0.4 1.2 0 0 0 0 0 0 143 3170.27 3352.86 0.58 0.63 2.7 7.3 0.5 1.4 0 0 0 0 0 0 142 3200.3 3382.73 0.59 0.63 3 8.1 0.6 1.5 0 0 0 0 0 0 141 3250.74 3432.91 0.6 0.63 3.4 9.2 0.6 1.7 0 0 0 0 0 0 140 3300.89 3482.79 0.6 0.64 4 10.6 0.7 2 0 0 0 0 0 0 139 3350.78 3532.43 0.61 0.64 4.8 12.4 0.9 2.3 0 0 0 0 0 0 138 3400.44 3581.85 0.62 0.65 5.8 14.8 1.1 2.7 0 0 0 0 0 0 137 3449.91 3631.09 0.63 0.65 7.2 17.9 1.3 3.3 0 0 0 0 0 0 136 3499.2 3680.15 0.63 0.66 9 21.9 1.7 4.1 0 0 0 0 0 0 135 3548.33 3729.07 0.64 0.67 11.4 27 2.1 5 0 0 0 0 0 0 134 3597.33 3777.85 0.65 0.68 14.5 33.3 2.7 6.2 0 0 0 0 0 0 133 3646.19 3826.51 0.65 0.69 18.4 41 3.4 7.6 0 0 0 0 0 0 132 3694.94 3875.05 0.66 0.7 23.2 50.2 4.3 9.3 0 0 0 0 0 0 131 3743.58 3923.49 0.67 0.72 29.3 61 5.4 11.3 0 0 0 0 0 0 130 3792.12 3971.84 0.69 0.73 36.7 73.6 6.8 13.7 0 0 0 0 0 0 129 3863.02 4042.46 0.7 0.73 44.3 85.8 8.2 15.9 0 0 0 0 0 0 128 3941.29 4120.44 0.7 0.74 50.8 95.9 9.4 17.8 0 0 0 0 0 0 127 4023.63 4202.48 0.71 0.74 56.5 104.5 10.5 19.4 0 0 0 0 0 0 126 4108.39 4286.96 0.72 0.75 61.7 112.3 11.5 20.9 0 0 0 0 0 0 125 4194.7 4372.97 0.72 0.75 66.7 119.6 12.4 22.2 0 0 0 0 0 0 124 4203.59 4381.84 0.72 0.75 71.8 126.8 13.3 23.6 0 0 0 0 0 0 123 4212.31 4390.53 0.73 0.76 77 134.1 14.3 24.9 0 0 0 0 0 0 122 4220.88 4399.08 0.73 0.76 82.3 141.3 15.3 26.3 0 0 0 0 0 0 202
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 121 4229.33 4407.49 0.73 0.77 87.7 148.6 16.3 27.6 0 0 0 6.8 0 1.3 120 4237.65 4415.79 0.74 0.77 93.2 155.8 17.3 29 0 0 0 14.3 0 2.7 119 4245.87 4423.98 0.74 0.77 99.1 163.3 18.4 30.4 0 0 0 22 0 4.1 118 4254 4432.08 0.74 0.78 105.6 171.6 19.6 31.9 0 0 0 30.5 0 5.7 117 4272.28 4450.31 0.75 0.78 112.7 180.3 20.9 33.5 0 0 0 39.8 0 7.4 116 4290.95 4468.91 0.75 0.79 120.2 189.4 22.3 35.2 0 0 0 49.4 0 9.2 115 4309.92 4487.83 0.75 0.8 128.1 198.6 23.8 36.9 0 0 0 59.2 0 11 114 4329.13 4506.98 0.76 0.8 136.3 207.9 25.3 38.6 0 0 0 69 0 12.8 113 4348.53 4526.32 0.76 0.81 144.8 217.3 26.9 40.4 0 0 1.2 79 0.2 14.7 112 4368.1 4545.83 0.77 0.82 153.7 226.8 28.6 42.2 0 0 10.7 89.1 2 16.6 111 4387.79 4565.47 0.77 0.82 162.9 236.4 30.3 43.9 0 0.1 20.5 99.1 3.8 18.4 110 4407.6 4585.21 0.78 0.83 172.4 245.9 32 45.7 0 0.1 30.6 109.2 5.7 20.3 109 4511.84 4689.15 0.79 0.84 185.1 257.9 34.4 48 0 0.1 46.4 124.1 8.6 23.1 108 4607.61 4784.65 0.8 0.86 206.3 276.6 38.4 51.5 0 0.1 70.3 145.3 13.1 27 107 4699.65 4876.44 0.82 0.88 238.7 301.6 44.4 56.1 0.1 0.1 105.2 172.5 19.6 32.1 106 4789.6 4966.16 0.86 0.91 280 320.8 52.1 59.8 0.1 0.2 148.8 193.9 27.7 36.1 105 4838.7 5015.13 0.89 0.95 310.4 336.4 57.8 62.8 0.2 0.4 180.4 210.5 33.6 39.2 104 4887.48 5063.79 0.92 1.01 326.6 344 60.9 64.5 0.3 0.6 197.7 219 36.8 40.9 103 4935.99 5112.18 0.97 1.07 339 347.2 63.4 65.4 0.4 0.9 211.2 223 39.4 41.7 102 4984.27 5160.35 1.02 1.12 344.5 349.4 64.6 66.3 0.7 1.4 217.6 225.9 40.6 42.2 101 5032.37 5208.33 1.07 1.15 347.4 350 65.5 67.1 1 2.1 221.3 227.1 41.3 42.5 100.13 5061.83 5237.73 1.11 1.18 348.9 350 66.2 67.9 1.4 2.9 223.3 227.1 41.7 42.5 99.25 5093.03 5268.85 1.13 1.21 349.6 350 66.7 68.8 1.8 3.8 224.4 227.2 42 42.5 98.38 5125.51 5301.26 1.15 1.23 349.9 350 67.2 69.8 2.3 4.8 225 227.2 42.1 42.5 97.5 5158.98 5334.65 1.17 1.26 350 350 67.7 70.8 2.7 5.8 225.5 227.2 42.2 42.5 203
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 96.67 5174.36 5350 1.18 1.28 350 350 68.3 71.9 3.3 6.9 225.5 227.2 42.2 42.5 95.83 5189.34 5364.95 1.2 1.31 350 350 68.9 73.1 3.9 8.1 225.5 227.2 42.2 42.5 95 5204.01 5379.58 1.22 1.33 350 350 69.6 74.5 4.6 9.5 225.5 227.2 42.2 42.5 94.15 5218.65 5394.2 1.25 1.36 350 350 70.4 76.2 5.4 11.2 225.5 227.2 42.2 42.5 93.31 5233.09 5408.6 1.27 1.38 350 350 71.3 77.9 6.3 12.9 225.5 227.2 42.2 42.5 92.46 5247.34 5422.82 1.29 1.4 350 350 72.2 79.6 7.2 14.6 225.5 227.2 42.2 42.5 91.61 5261.44 5436.89 1.3 1.41 350 350 73.1 81.2 8.1 16.2 225.5 227.2 42.2 42.5 90.77 5275.41 5450.84 1.32 1.42 350 350 74 82.8 9 17.8 225.5 227.2 42.2 42.5 89.79 5291.42 5466.8 1.34 1.44 350 350 75 84.6 10 19.6 225.5 227.2 42.2 42.5 88.81 5307.29 5482.65 1.35 1.45 350 350 76 86.3 11 21.3 225.5 227.2 42.2 42.5 87.83 5323.06 5498.38 1.36 1.46 350 350 77 88 12 23 225.5 227.2 42.2 42.5 86.85 5338.72 5514.01 1.37 1.47 350 350 77.9 89.5 12.9 24.5 225.5 227.2 42.2 42.5 85.87 5354.3 5529.56 1.38 1.48 350 350 78.9 91 13.9 26 225.5 227.2 42.2 42.5 84.89 5369.81 5545.03 1.39 1.49 350 350 79.8 92.3 14.8 27.3 225.5 227.2 42.2 42.5 83.91 5385.24 5560.43 1.4 1.5 350 350 80.6 93.6 15.6 28.6 225.5 227.2 42.2 42.5 82.94 5400.62 5575.77 1.41 1.51 350 350 81.4 94.9 16.4 29.9 225.5 227.2 42.2 42.5 81.96 5415.93 5591.06 1.41 1.51 350 350 82.2 96 17.2 31 225.5 227.2 42.2 42.5 80.98 5431.2 5606.3 1.42 1.52 350 350 83 97.1 18 32.1 225.5 227.2 42.2 42.5 80 5446.42 5621.49 1.43 1.53 350 350 83.8 98.1 18.8 33.1 225.5 227.2 42.2 42.5 79 5386.42 5561.49 1.43 1.53 350 350 84.4 99 19.4 34 225.5 227.2 42.2 42.5 78 5326.42 5501.49 1.43 1.54 350 350 84.8 99.5 19.8 34.5 225.5 227.2 42.2 42.5 77 5266.42 5441.49 1.44 1.54 350 350 85.1 99.9 20.1 34.9 225.5 227.2 42.2 42.5 76 5206.42 5381.49 1.44 1.54 350 350 85.2 100.1 20.2 35.1 225.5 227.2 42.2 42.5 75 5146.42 5321.49 1.44 1.54 350 350 85.3 100.2 20.3 35.2 225.5 227.2 42.2 42.5 74 5191.62 5366.69 1.44 1.54 350 350 85.4 100.3 20.4 35.3 225.5 227.2 42.2 42.5 204
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 73 5234.44 5409.51 1.44 1.54 350 350 85.4 100.3 20.4 35.3 225.5 227.2 42.2 42.5 72 5275.39 5450.46 1.44 1.54 350 350 85.5 100.4 20.5 35.4 225.5 227.2 42.2 42.5 71 5314.83 5489.9 1.44 1.54 350 350 85.5 100.5 20.5 35.5 225.5 227.2 42.2 42.5 70 5353.01 5528.08 1.44 1.54 350 350 85.6 100.6 20.6 35.6 225.5 227.2 42.2 42.5 69 5390.13 5565.19 1.44 1.54 350 350 85.7 100.7 20.7 35.7 225.5 227.2 42.2 42.5 68 5426.33 5601.39 1.44 1.55 350 350 85.8 100.8 20.8 35.8 225.5 227.2 42.2 42.5 67 5456.36 5631.4 1.44 1.55 350 350 85.9 101 20.9 36 225.5 227.2 42.2 42.5 66 5479.2 5654.2 1.44 1.55 350 350 86 101.1 21 36.1 225.5 227.2 42.2 42.5 65 5439.2 5614.2 1.44 1.55 350 350 86.2 101.3 21.2 36.3 225.5 227.2 42.2 42.5 64 5399.2 5574.2 1.44 1.55 350 350 86.3 101.4 21.3 36.4 225.5 227.2 42.2 42.5 63 5359.2 5534.2 1.44 1.55 350 350 86.4 101.6 21.4 36.6 225.5 227.2 42.2 42.5 62 5319.2 5494.2 1.44 1.55 350 350 86.4 101.7 21.4 36.7 225.5 227.2 42.2 42.5 61 5279.2 5454.2 1.44 1.55 350 350 86.5 101.7 21.5 36.7 225.5 227.2 42.2 42.5 60 5239.2 5414.2 1.44 1.55 350 350 86.5 101.8 21.5 36.8 225.5 227.2 42.2 42.5 59 5199.2 5374.2 1.44 1.55 350 350 86.6 101.8 21.6 36.8 225.5 227.2 42.2 42.5 58 5159.2 5334.2 1.45 1.55 350 350 86.6 101.9 21.6 36.9 225.5 227.2 42.2 42.5 57.25 5129.2 5304.2 1.45 1.55 350 350 86.6 101.9 21.6 36.9 225.5 227.2 42.2 42.5 57 5119.2 5294.2 1.45 1.55 350 350 86.6 101.9 21.6 36.9 225.5 227.2 42.2 42.5 56 5079.2 5254.2 1.45 1.55 350 350 86.7 101.9 21.7 36.9 225.5 227.2 42.2 42.5 55 5039.2 5214.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 54 4999.2 5174.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 53.5 4979.2 5154.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 53 4959.2 5134.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 52 4919.2 5094.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 51 4879.2 5054.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 205
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 50 4839.2 5014.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 49 4799.2 4974.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 48.5 4779.2 4954.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 48 4759.2 4934.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 47 4719.2 4894.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 46 4679.2 4854.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 45 4639.2 4814.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 44 4599.2 4774.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 43 4559.2 4734.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 42 4519.2 4694.2 1.45 1.55 350 350 86.7 102 21.7 37 225.5 227.2 42.2 42.5 41 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 40 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 39 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 38 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 37 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 36 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 35 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 34 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 33 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 32 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 31 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 30 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 29 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 28 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 27 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 206
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 26 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 25 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 24 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 23 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 22 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 21 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 20 4479.2 4654.2 1.45 1.55 350 350 86.7 102.1 21.7 37.1 225.5 227.2 42.2 42.5 19 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 18 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 17 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 16 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 15 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 14 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 13 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 12 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 11 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 10 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 9 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 8 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 7 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 6 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 5 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 4 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 3 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 2 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 207
Top Bottom Top Top Top Bottom Top Age Top Bottom Top Bottom Oil Oil Gas Bottom Resid. Bottom Oil Oil Gas Bottom (Ma) Depth Depth Maturity Maturity Gen. Gen Gen. Gas Gen. Gen. Resid. Gen. Exp. Exp. Exp. Gas Exp. 1 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5 0 4479.2 4654.2 1.45 1.55 350 350 86.8 102.1 21.8 37.1 225.5 227.2 42.2 42.5
Top of Early Mature (oil) = 0.5 (%Ro) found at 176.4 (my) at bed top. Top of Early Mature (oil) = 0.5 (%Ro) found at 193.5 (my) at bed bottom. Bottom of Early Mature (oil) = 0.7 (%Ro) found at 128.5 (my) at bed top. Bottom of Early Mature (oil) = 0.7 (%Ro) found at 132.3 (my) at bed bottom. . Units: Top of Mid Mature (oil) = 0.7 (%Ro) found at 128.5 (my) at bed top. Stratigraphic Age: (my) Top of Mid Mature (oil) = 0.7 (%Ro) found at 132.3 (my) at bed bottom. Depth: (m) Bottom of Mid Mature (oil) = 1 (%Ro) found at 102.4 (my) at bed top. Maturity: (%Ro) Bottom of Mid Mature (oil) = 1 (%Ro) found at 104.2 (my) at bed bottom. Oil Generated: (mg/g TOC) Top of Late Mature (oil) = 1 (%Ro) found at 102.4 (my) at bed top. Gas Generated: (mg/g TOC) Top of Late Mature (oil) = 1 (%Ro) found at 104.2 (my) at bed bottom. Residue Generated: (mg/g TOC) Bottom of Late Mature (oil) = 1.3 (%Ro) found at 91.8 (my) at bed top. Oil Expulsion: (mg/g TOC) Bottom of Late Mature (oil) = 1.3 (%Ro) found at 96.1 (my) at bed bottom. Gas Expulsion: (mg/g TOC) Top of Main Gas Generation = 1.3 (%Ro) found at 91.8 (my) at bed top. Top of Main Gas Generation = 1.3 (%Ro) found at 96.1 (my) at bed bottom.
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