HERRERA-THESIS-2013.Pdf (12.72Mb)

A PETROLEUM SYSTEM STUDY OF THE CRATONIC WILLISTON BASIN IN NORTH DAKOTA, U.S.A.: THE ROLE OF THE LARAMIDE OROGENY

A Thesis

Presented to

the Faculty of the Department of Earth and Atmospheric Sciences

University of Houston

------

In Partial Fulfillment

of the Requirements for the Degree

Master of Science

------

Henry Herrera

August 2013

A PETROLEUM SYSTEM STUDY OF THE CRATONIC WILLISTON BASIN IN NORTH DAKOTA, U.S.A.: THE ROLE OF THE LARAMIDE OROGENY

Henry Herrera

APPROVED:

Dr. Jolante Van Wijk, Chairman

Dr. Guoquan Wang

Dr. Constantin Sandu

Dean, College of Natural Science and Mathematics

DEDICATION

To Jesus, my mom, dad, and sister, and all the people that believed in me.

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ACKNOWLEDGEMENTS

I want to thank God because he is always with me.

Thanks to my mother, father, and sister because they are always there for me.

Thanks to Dr. Jolante Van Wijk because she supported me in good and bad moments during the thesis project, and did not let me quit.

Thanks to Dr. Constantin Sandu and Dr. Wang for being part of my committee.

I am thankful to Ismail Ahmad Abir and Kevin Schmidt for being patient helping me with my GIS problems.

Thanks to Simon Echegu for his geochemical advice and friendship.

Finally, thanks to the North Dakota Geological Survey (NDGS) for the provided information for the conclusion this thesis.

A PETROLEUM SYSTEM STUDY OF THE CRATONIC WILLISTON BASIN IN NORTH DAKOTA, U.S.A.: THE ROLE OF THE LARAMIDE OROGENY

An Abstract of a Thesis

Presented to

the Faculty of the Department of Earth and Atmospheric Sciences

University of Houston

------

In Partial Fulfillment

of the Requirements for the Degree

Master of Science

------

Henry Herrera

August 2013

ABSTRACT

The Williston Basin is a Phanerozoic intracratonic basin located in the northern USA

(North Dakota, South Dakota and Montana) and southern Canada (Manitoba and

Saskatchewan). The basin is known as a major hydrocarbon-producing basin in North

America, with a petroleum system characterized by multiple source rocks and reservoirs.

The aim of this study is to increase our understanding of the Williston Basin’s petroleum system in the North Dakota region. A detailed analysis of the source rocks in the basin will increase our knowledge about their generation potential and maturity, which could allow the identification of new prospective reservoirs. The source rocks have an average of total organic carbon content between 0.59 and 17.63%, and are type II kerogen, except for the Tyler Formation which is type III kerogen. This gives these formations a good quality status as a source rock, and potentially oil-and-gas prone source. Geochemical data (vitrinite reflectance %Ro, in this case) were used for model calibration. Results show a heat flow range between 41.91-65.14 mW/m2, with higher values toward the center of the basin in North Dakota where the sediment package thickens, and lower values toward the edges. My models predict that the end of the Upper Cretaceous is a critical period in the basin, when peak maturation and hydrocarbon generation are found for every source rock. In this same geologic time an increase in temperature is observed in the North Dakota area, as well as the maximum burial period. Subsidence curves show a slow and long tectonic subsidence period across the basin, with rapid subsidence stages during the Carboniferous in the center of the basin in North Dakota.

TABLE OF CONTENTS

CHAPTER 1. INTRODUCTION ...... 1

1.1 THE WILLISTON BASIN ...... 1

1.2 OBJECTIVES ...... 4

CHAPTER 2. STRATIGRAPHY OF THE WILLISTON BASIN ...... 5

2. 1 STRATIGRAPHIC SEQUENCES OF THE WILLISTON BASIN ...... 5

2.1.1 SAUK SEQUENCE ...... 5

2.1.2 TIPPECANOE SEQUENCE ...... 5

2.1.3 KASKASKIA SEQUENCE...... 6

2.1.4 ABSAROKA SEQUENCE ...... 7

2.1.5 ZUNI SEQUENCE ...... 8

2.1.6 TEJAS SEQUENCE ...... 8

2. 2 BAKKEN FORMATION ...... 11

2.3 AGES OF DEPOSITION ...... 14

2.3.1 EROSION AGES ...... 16

2.4 TECTONIC HISTORY OF THE WILLISTON BASIN ...... 17

2.4.1 TECTONIC SETTING ...... 18

2.5 SUBSIDENCE HISTORY...... 21

2.6 STRUCTURAL STYLE ...... 22 vii

2.7 THERMAL HISTORY ...... 23

CHAPTER 3. PETROLEUM GEOCHEMISTRY OF THE WILLISTON BASIN ...... 25

3.1 TOTAL ORGANIC CARBON CONTENT (TOC) ...... 25

3.2 KEROGEN TYPE ...... 26

3.3 ORGANIC MATTER MATURITY ...... 28

3.4 WILLISTON BASIN GEOCHEMISTRY ...... 30

3.5 PETROLEUM SYSTEMS OF THE WILLISTON BASIN ...... 32

CHAPTER 4. METHODS AND DATA ...... 37

4.1 METHODOLOGY ...... 37

4.1.1 METHODS ...... 38

4.2 PETROLEUM SYSTEMS MODELING ...... 38

4.3 BACKSTRIPPING AND PETROMOD ...... 40

4.4 DATA SOURCE ...... 40

4.4.1 2D CROSS SECTIONS ...... 41

4.5.1 KINETICS ...... 54

4.6 PETROLEUM SYSTEM ELEMENTS ...... 55

4.7 MODELS CALIBRATION ...... 56

4.8 SYN-RIFT PHASE ...... 62

4.9 BETA STRETCHING FACTOR ...... 64

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4.10 PALEOWATER DEPTHS ...... 64

CHAPTER 5. RESULTS ...... 66

5.1 SUBSIDENCE CURVES ...... 67

5.2 HEAT FLOW...... 73

5.3 BURIAL PLOTS ...... 82

5.3.1 N-S CROSS SECTION ...... 82

5.3.2 E-W CROSS SECTION ...... 93

5.4 VITRINITE REFLECTANCE...... 98

5.4.1 N-S CROSS SECTION ...... 98

5.4. 2 E-W CROSS SECTION WELLS ...... 105

5.5 TRANSFORMATION RATIO ...... 112

5.5.1 N-S CROSS SECTION ...... 112

5.5.2 E-W CROSS SECTION ...... 119

5.6 GENERATION MASS ...... 126

5.6.1 N-S CROSS SECTION ...... 126

5.6.1 E-W CROSS SECTION WELLS ...... 133

5.7 2D MODELING ...... 139

5.7.1 NORTH-SOUTH (N-S) CROSS SECTION ...... 139

5.7.2 EAST-WEST (E-W) CROSS SECTION...... 141

CHAPTER 6. DISCUSSION ...... 157

6.1 LARAMIDE OROGENY ...... 157

6.2 SUBSIDENCE ...... 158

6.3 HEAT FLOW...... 158

6.4 UPPER CRETACEOUS ...... 159

6.5 HYDROCARBON GENERATION AND MIGRATION ...... 160

CHAPTER 7. CONCLUSIONS ...... 162

REFERENCES ...... 166

LIST OF FIGURES

Figure 1.1. Williston Basin location (outlined in blue) and wells (1-9) used in the study.

Basin delineation from Khun et al. (2012)...... 1

Figure 1.2. Major structures in the Williston Basin (taken from USGS, Anna et al.,

2010(a)). Dominant structures include the NW-SE-oriented Cedar Creek Anticline, the

N-S-oriented Nesson Anticline, several domal structures, and the Brockton Froid Fault zone...... 3

Figure 2.1. Bakken Formation members’ lithology and average thickness (taken from

Khun et al., 2012)...... 11

Figure 2.2. Bakken Formation isopach map after Dembicki and Pirkle (1985)...... 12

Figure 2.3. Bakken Formation isopach map in a section of the Williston Basin in North

Dakota using well stratigraphic information provided by the North Dakota Geological

Survey (NDGS)...... 13

Figure 2.4. Tectonic subsidence curves for different cratonic basins from different authors, where curves number 3 (North Dakota) and 4 (Saskatchewan) correspond to the

Williston Basin (taken from Xie and Heller, 2009)...... 20

Figure 2.5. Heat flow values in the Williston Basin after basin modeling by Khun et al.

(2012). Figure taken from Khun et al.(2012) ...... 24

Figure 3.1. Kerogen type from the Van Krevelen Diagram (taken from Schlumberger,

2011)...... 28

Figure 3.2. Organic matter maturity parameters (taken from Hunt et al., 2002)...... 29

Figure 3.3. The Nesson Anticline is an example of traps in the Williston Basin. Figure taken from Osadetz et al. (2002) ...... 35

Figure 4.1. Petroleum systems elements and processes necessary for hydrocarbon generation (taken from Schlumberger, 2009)...... 39

Figure 4.2. N-S and E-W cross sections used in the study...... 42

Figure 4.3. Wells used in the study...... 45

Figure 4.4. Van Krevelen diagram for the Bakken Formation from Price et al. (1984) and

Webster (1984), where most results were type I and II kerogen (taken from Sonnenberg and Pramudito, 2009)...... 54

Figure 4.5. Bakken Formation vitrinite reflectance map used for model 1 calibration after

Dembicki and Pirkle (1985)...... 57

Figure 4.6. Bakken Formation vitrinite reflectance map used for model 2 calibration after

Webster (1984)...... 58

Figure 4.7. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 1...... 59

Figure 4.8. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 2...... 59

Figure 4.9. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 3...... 60

Figure 4.10. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 4...... 60

xii

Figure 4.11. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 5...... 61

Figure 4.12. Model calibration using Bakken Formation vitrinite reflectance (%Ro) for well 6...... 61

Figure 4.13. Model calibration using Bakken Formation vitrinite reflectance (%Ro) for well 7...... 62

Figure 4.14. Syn-rift phase by Olajide and Bend (2012). Figure taken from Olajide and

Bend (2012) ...... 63

Figure 4.15. Stretching factors for different types of basin (taken from Armitage and

Allen, 2010)...... 64

Figure 5.1. Subsidence curves for Wells 1-2-3 in the N-S cross section...... 69

Figure 5.2. Subsidence curves for Wells 4-5-6 in the N-S cross section...... 70

Figure 5.3. Subsidence curves for Wells 7-5 in the E-W cross section...... 71

Figure 5.4. Tectonic subsidence of the Williston Basin in North Dakota...... 72

Figure 5.5. Heat flow curves for Well 1 in the N-S cross section for both calibrated models...... 73

Figure 5.6. Heat flow curves for Well 2 in the N-S cross section for both calibrated models...... 74

Figure 5.7. Heat flow curves for Well 3 in the N-S cross section for both calibrated models...... 75

Figure 5.8. Heat flow curves for Well 4 in the N-S cross section for both calibrated models...... 76

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Figure 5.9. Heat flow curves for Well 5 in the N-S cross section for both calibrated models...... 77

Figure 5.10. Heat flow curves for Well 6 in the N-S cross section...... 78

Figure 5.11. Heat flow curves for Well 7 in the E-W cross section...... 79

Figure 5.12. Present-day heat flow map after calibrating the model 1 using Dembicki and

Pirkle (1985) Vitrinite reflectance...... 80

Figure 5.13. Present-day heat flow map after calibrating the model 1 using Webster

(1984) Vitrinite reflectance...... 81

Figure 5.14. Temperature burial plots for Well 1 in the N-S cross section for both calibrated models...... 82

Figure 5.15. Transformation ratio burial plots for Well 1 in the N-S cross section for both calibrated models...... 83

Figure 5.16. Temperature burial plots for Well 2 in the N-S cross section for both calibrated models...... 84

Figure 5.17. Transformation ratio burial plots for Well 2 in the N-S cross section for both calibrated models...... 85

Figure 5.18. Temperature burial plots for Well 3 in the N-S cross section for both calibrated models...... 86

Figure 5.19. Transformation ratio burial plots for Well 3 in the N-S cross section for both calibrated models...... 87

Figure 5.20. Temperature burial plots for Well 4 in the N-S cross section for both calibrated models...... 88

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Figure 5.21. Transformation ratio burial plots for Well 4 in the N-S cross section for both calibrated models...... 89

Figure 5.22. Temperature burial plots for Well 5 in the N-S cross section for both calibrated models...... 90

Figure 5.23. Transformation ratio burial plots for Well 5 in the N-S cross section for both calibrated models...... 91

Figure 5.24. Temperature burial plots for Well 6 in the N-S cross section...... 92

Figure 5.25. Transformation ratio burial plots for Well 6 in the N-S cross section...... 93

Figure 5.26. Temperature burial plots for Well 7 in the E-W cross section...... 94

Figure 5.27. Transformation ratio burial plots for Well 7 in the E-W cross section...... 94

Figure 5.28. Temperature burial plots for Well 8 in the E-W cross section...... 95

Figure 5.29. Transformation ratio burial plots for Well 8 in the E-W cross section...... 96

Figure 5.30. Temperature burial plots for Well 9 in the E-W cross section...... 97

Figure 5.31. Transformation ratio burial plots for Well 9 in the E-W cross section...... 97

Figure 5.32. Vitrinite reflectance evolution through geological time for the Tyler

Formation in all wells from the N-S cross section, and both calibrated models...... 98

Figure 5.33. Vitrinite reflectance evolution through geological time for the Lodgepole

Formation in all wells from the N-S cross section, and both calibrated models...... 99

Figure 5.34. Vitrinite reflectance evolution through geological time for the Upper

Bakken Formation in all wells from the N-S cross section, and both calibrated models.

...... 100

Figure 5.35. Vitrinite reflectance evolution through geological time for the Lower

Bakken Formation in all wells from the N-S cross section, and both calibrated models.

...... 101

Figure 5.36. Vitrinite reflectance evolution through geological time for the Duperow

Formation in all wells from the N-S cross section, and both calibrated models...... 102

Figure 5.37. Vitrinite reflectance evolution through geological time for the Winnipegosis

Formation in all wells from the N-S cross section, and both calibrated models...... 103

Figure 5.38. Vitrinite reflectance evolution through geological time for the Red River

Formation in all wells from the N-S cross section, and both calibrated models...... 104

Figure 5.39. Vitrinite reflectance evolution through geological time for the Tyler

Formation in all wells from the E-W cross section...... 105

Figure 5.40. Vitrinite reflectance evolution through geological time for the Lodgepole

Formation in all wells from the E-W cross section...... 106

Figure 5.41. Vitrinite reflectance evolution through geological time for the Upper

Bakken Formation in all wells from the E-W cross section...... 107

Figure 5.42. Vitrinite reflectance evolution through geological time for the Lower

Bakken Formation in all wells from the E-W cross section...... 108

Figure 5.43. Vitrinite reflectance evolution through geological time for the Duperow

Formation in all wells from the E-W cross section...... 109

Figure 5.44. Vitrinite reflectance evolution through geological time for the Winnipegosis

Formation in all wells from the E-W cross section...... 110

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Figure 5.45. Vitrinite reflectance evolution through geological time for the Red River

Formation in all wells from the E-W cross section...... 111

Figure 5.46. Transformation ratio evolution through geological time for the Tyler

Formation in all wells from the N-S cross section, and both calibrated models...... 112

Figure 5.47. Transformation ratio evolution through geological time for the Lodgepole

Formation in all wells from the N-S cross section, and both calibrated models...... 113

Figure 5.48. Transformation ratio evolution through geological time for the Upper

Bakken Formation in all wells from the N-S cross section, and both calibrated models.

...... 114

Figure 5.49. Transformation ratio evolution through geological time for the Lower

Bakken Formation in all wells from the N-S cross section, and both calibrated models.

...... 115

Figure 5.50. Transformation ratio evolution through geological time for the Duperow

Formation in all wells from the N-S cross section, and both calibrated models...... 116

Figure 5.51. Transformation ratio evolution through geological time for the

Winnipegosis Formation in all wells from the N-S cross section, and both calibrated models...... 117

Figure 5.52. Transformation ratio evolution through geological time for the Red River

Formation in all wells from the N-S cross section, and both calibrated models...... 118

Figure 5.53. Transformation ratio evolution through geological time for the Tyler

Formation in all wells from the E-W cross section...... 119

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Figure 5.54. Transformation ratio evolution through geological time for the Lodgepole

Formation in all wells from the E-W cross section...... 120

Figure 5.55. Transformation ratio evolution through geological time for the Upper

Bakken Formation in all wells from the E-W cross section...... 121

Figure 5.56. Transformation ratio evolution through geological time for the Lower

Bakken Formation in all wells from the E-W cross section...... 122

Figure 5.57. Transformation ratio evolution through geological time for the Duperow

Formation in all wells from the E-W cross section...... 123

Figure 5.58. Transformation ratio evolution through geological time for the

Winnipegosis Formation in all wells from the E-W cross section...... 124

Figure 5.59. Transformation ratio evolution through geological time for the Red River

Formation in all wells from the E-W cross section...... 125

Figure 5.60. Generation mass of the Tyler Formation in all wells from the N-S cross section, and both calibrated models...... 126

Figure 5.61. Generation mass of the Lodgepole Formation in all wells from the N-S cross section, and both calibrated models...... 127

Figure 5.62. Generation mass of the Upper Bakken Formation in all wells from the N-S cross section, and both calibrated models...... 128

Figure 5.63. Generation mass of the Lower Bakken Formation in all wells from the N-S cross section, and both calibrated models...... 129

Figure 5.64. Generation mass of the Duperow Formation in all wells from the N-S cross section, and both calibrated models...... 130

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Figure 5.65. Generation mass of the Winnipegosis Formation in all wells from the N-S cross section, and both calibrated models...... 131

Figure 5.66. Generation mass of the Red River Formation in all wells from the N-S cross section, and both calibrated models...... 132

Figure 5.67. Generation mass of the Tyler Formation in all wells from the E-W cross section...... 133

Figure 5.68. Generation mass of the Lodgepole Formation in all wells from the E-W cross section...... 134

Figure 5.69. Generation mass of the Upper Bakken Formation in all wells from the E-W cross section...... 135

Figure 5.70. Generation mass of the Lower Bakken Formation in all wells from the E-W cross section...... 136

Figure 5.71. Generation mass of the Duperow Formation in all wells from the E-W cross section...... 137

Figure 5.72. Generation mass of the Winnipegosis Formation in all wells from the E-W cross section...... 138

Figure 5.73. Generation mass of the Red River Formation in all wells from the E-W cross section...... 139

Figure 5.74. N-S cross section at 0 Ma and its stratigraphic layers...... 142

Figure 5.75. N-S cross section at 0 Ma showing hydrocarbon accumulations in the

Winnipegosis Formation...... 143

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Figure 5.76. N-S cross section at 26.62 Ma showing hydrocarbon accumulations in the

Kibbey and Winnipegosis Formations...... 144

Figure 5.77. N-S cross section at 73.62 Ma showing hydrocarbon accumulations in the

Kibbey and Winnipegosis Formations and the migration vectors after hydrocarbon generation...... 145

Figure 5.78. Hydrocarbon saturation of the Upper Bakken Formation at 0 Ma in the N-S cross section...... 146

Figure 5.79. Hydrocarbon saturation of the Middle Bakken Formation at 0 Ma in the N-S cross section...... 147

Figure 5.80. Hydrocarbon saturation of the Lower Bakken Formation at 0 Ma in the N-S cross section...... 148

Figure 5.81. N-S cross section hydrocarbon generation zones from the Vitrinite

Reflectance model of Sweeny and Burham (1990)...... 149

Figure 5.82. E-W cross section at 0 Ma and its stratigraphic layers...... 150

Figure 5.83. E-W cross section at 0 Ma showing hydrocarbon accumulations Kibbey,

Three Forks and Winnipegosis Formations...... 151

Figure 5.84. E-W cross section at 26.62 Ma showing hydrocarbon accumulations in the

Kibbey Formation and the migration vectors after hydrocarbon generation...... 152

Figure 5.85. E-W cross section hydrocarbon saturation of the Upper Bakken Formation at 0 Ma...... 153

Figure 5.86. E-W cross section hydrocarbon saturation of the Middle Bakken Formation at 0 Ma...... 154

Figure 5.87. E-W cross section hydrocarbon saturation of the Lower Bakken Formation at 0 Ma...... 155

Figure 5.88. E-W cross section hydrocarbon generation zones from the Vitrinite

Reflectance model of Sweeny and Burham (1990) ...... 156

Figure 6.1. The heat flow map for model 1 remarks the study area. The study area did not include major traps in the basin...... 161

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LIST OF TABLES

Table 2.1 Williston Basin Kaskaskia, Tippocanoe and Sauk Sequences (Carlson and

Anderson, 1965)...... 9

Table 2.2. Williston Basin Tejas, Zuni, and Absaroka sequences (Carlson and Anderson,

1965)...... 10

Table 2.3. Age of deposition according to LeFever and Crashell (1991)...... 14

Table 2.4. Age of deposition according to the North Dakota Geological Survey NDGS

(Murphy et al., 2009)...... 15

Table 2.5. Age of deposition at Williston Basin according to Khun et al. (2012) ...... 16

Table 3.1. Total Organic Carbon (TOC) content ranges for source rock quality assessment (Schlumberger, 2012)...... 25

Table 3.2. Source rock petroleum potential based on their organic enrichment (Peters and

Cassa, 1994)...... 26

Table 3.3. Kerogen type (taken from Selley (1998); weight percent data (Tissot & Welte,

1978); ratios (Dow, 1977)...... 27

Table 3.4. Approximate kerogen type ranges based on a thermally immature source rock.

(Peters and Cassa, 1994)...... 27

Table 3.5. Source rock thermal maturity stages based on different thermal maturity parameters. (Peters and Cassa, 1994)...... 30

Table 3.6. Vitrinite reflectance values, depths and location for the Bakken Formation in the Williston Basin at Saskatchewan, Canada (Jiang et al., 2001)...... 31

xxii

Table 3.7. Vitrinite reflectance values, depths and location for the Bakken Formation in the Williston Basin at North Dakota, USA (Leenheer, 1984)...... 31

Table 3.8. Proven (P) and Hypothetical (H) petroleum systems in Williston Basin and their oil production (taken from Jarvie, 2001)...... 32

Table 3.9. Some of the petroleum systems identified in the Williston Basin (Anna et al.,

2010(a); Anna, 2010; Anna et al., 2010(b))...... 33

Table 3.10. Organic enrichment of the Williston Basin source rocks (taken from Jarvie,

2001)...... 36

Table 4.1. Formation depths at different wells and locations provided by the Oil and Gas

Division of the North Dakota Geological Survey for the North-South Cross Section.

Boxes in green are hypothetical...... 43

Table 4.2. Formation depths at different wells and locations provided by the Oil and Gas

Division of the North Dakota Geological Survey for the East-West cross section. Boxes in green are hypothetical...... 44

Table 4.3. Well 1 data...... 46

Table 4.4. Well 2 data...... 47

Table 4.5. Well 3 data...... 48

Table 4.6. Well 4 data...... 49

Table 4.7. Well 5 data...... 50

Table 4.8. Well 6 data...... 51

Table 4.9. Well 7 data...... 52

Table 4.10. Source rocks geochemical information...... 53

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Table 4.11. Lithology and petroleum system elements in the Williston Basin by formation name...... 55

Table 4.12. Vitrinite reflectance values and depths used for models calibration with values taken from Webster (1984) and Dembicki and Pirkle (1985)...... 56

Table 4.13. Paleowater depths taken from Haq (et al., 1987) and Haq and Schutter (2008) and the assumption of 0 m PWD after the Laramide Orogeny (80-50 Ma)...... 65

Table 5.1. Present-day heat flow for the 2 generated models in all studied wells...... 79

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CHAPTER 1. INTRODUCTION

1.1 THE WILLISTON BASIN

The Williston Basin is located in USA (North Dakota, South Dakota, and Montana) and

South-Central Canada (Manitoba and Saskatchewan) territories (Figure 1.1). It is a large intracratonic basin on the western periphery of the North American craton (Gerhard et al.,

1982). The Williston Basin is an important hydrocarbon producing basin, with multiple source rocks and reservoir rocks.

Figure 1.1. Williston Basin location (outlined in blue) and wells (1-9) used in the study. Basin delineation from Khun et al. (2012).

The Williston Basin is a Phanerozoic cratonic basin, which preserves a thickness of almost 5km of predominantly marine sedimentary rocks from Cambrian age to Tertiary.

The basin is approximately 800 km in diameter and subcircular (Gerhard et al., 1982;

Obermajer et al., 2003), Figure 1.1. Some interesting facts of the Williston Basin are that its sediment thickness is up to 16,000 ft (4,875 m) in its deepest part; the deepest well ever drilled in the basin was at 15,340 ft (4,676 m) reaching Precambrian rocks, and the deepest producing formation is the Ordovician Red River Formation located at 14,343 ft

(4,372 m) (Gerhard et al., 1982).

The first oil discoveries in the Williston Basin occurred in different times on both sides of the border. In the USA, the first discovery was made in 1936 on the Cedar Creek anticline in Montana and in the Canadian side oil was first discovered in Manitoba in

1950. One year later in 1951, the first reservoir in North Dakota was found on the Nesson anticline (Gerhard et al., 1982). Since these discoveries, the Williston Basin has been a reliable provider of hydrocarbons. However, because of the existence of multiple source rocks, the definition of the petroleum systems (source rock-reservoir) has been a problem for geochemists. Most of the traps in the Williston Basin are anticlines with minor stratigraphic traps (Figure 1.2)

Figure 1.2. Major structures in the Williston Basin (taken from USGS, Anna et al., 2010(a)). Dominant structures include the NW-SE-oriented Cedar Creek Anticline, the N-S-oriented Nesson Anticline, several domal structures, and the Brockton Froid Fault zone.

In this study, a tectonic subsidence history profile of the basin has been constructed, as well as the petroleum system analysis of the cratonic Williston Basin. For these objectives, well data was collected from the American (Northern) and Canadian

(Southern) regions to make a comparison of results. In this dataset, the stratigraphic and geochemical information are going to be merged together in order to achieve the settled goals of the research.

1.2 OBJECTIVES

The petroleum system of the Williston Basin is debated and controversial, as a result of its multiple source rocks and pay zones (e.g. Dow, 1974; Jarvie, 2001). The Williston

Basin is also complex because of its tight reservoirs, compartmentalization of the reservoirs, and petroleum systems characterization. The aim of this study is to increase our understanding of the basin petroleum system. Further, a detailed analysis of the tectonic subsidence history of the basin will increase our understanding of the tectonic history of the Williston Basin and cratonic basins in general.

The objectives of this study include:

 Understand important geological events/periods for the petroleum system of the

Williston Basin

 Define the petroleum system elements and processes of the basin

 Interpretation of subsidence curves and burial acquired from the basin modeling, and

interpret the evolution of the cratonic Williston Basin

CHAPTER 2. STRATIGRAPHY OF THE WILLISTON BASIN

2. 1 STRATIGRAPHIC SEQUENCES OF THE WILLISTON BASIN

Many authors have described the stratigraphic sequences in the Williston Basin (e.g.

Carlson and Anderson, 1965; Gerhard et al., 1982; Meissner, 1984). These sequences are the Sauk, Tippecanoe, Kaskaskia, Absaroka, Zuni, and Tejas sequence, from oldest to youngest (Tables 2.1 and 2.2). The following sections include a summary of the stratigraphy of the Williston Basin.

2.1.1 SAUK SEQUENCE

The Sauk Sequence (Table 2.1) is the oldest known sequence in the Williston Basin, and is represented by the Deadwood Formation of Late Cambrian to Early Ordovician Age

(Carlson and Anderson, 1965). The Deadwood Formation is formed by basal sandstone, which is overlain by shale, carbonates, and sandstone, and its economic importance in terms of hydrocarbon production is very low with little amounts of condensate discovered adjacent to the Nesson anticline (e.g. Carlson and Anderson, 1965; Gerhard et al., 1982;

Meissner, 1984).

2.1.2 TIPPECANOE SEQUENCE

The Tippecanoe Sequence (Table 2.1) was deposited during the Middle Ordovician to

Early Devonian, and it is formed by the Winnipeg Group, Red River, Stoney Mountain,

Stonewall and Interlake Formations (e.g. Carlson and Anderson, 1965; Gerhard et al.,

1982; Meissner, 1984).

The Winnipeg Group (Middle Ordovician) is divided into 3 different formations: Black

Island, Icebox, and Roughlock. The Black Island Formation consists of sandstone primarily, the Icebox Formation of shale, and finally the Roughlock formation is formed by calcareous shale and siltstone (Carlson and Anderson, 1965). The Red River

Formation (Middle Ordovician) consists of limestone and dolomite (Carlson and

Anderson, 1965). The Stony Mountain Formation (Late Ordovician) is a carbonate strata and is divided into 2 members: Stoughton and Gunton. The Stoughton Member lithology consists of argillaceous limestone, and the Gunton Member consists of limestone and dolomite (Carlson and Anderson, 1965). The Stonewall Formation (Late Ordovician-

Early Siluarian) is formed by dolomite and limestone (Carlson and Anderson, 1965).

Finally the Interlake Formation (Silurian) consists mainly of dolomite (e.g. Carlson and

Anderson, 1965; Gerhard et al., 1982; Meissner, 1984).

2.1.3 KASKASKIA SEQUENCE

The deposition of the Kaskakia Sequence (Table 2.1) occurred during Early Devonian to

Late Mississipian, and the lithology of most of the stratigraphic formations consists mainly of carbonates. Devonian age formations such as the Winnipegosis, Dawson Bay

Souris River, and Birdbear Formations consist primarily of limestone and dolomite. In this sequence there is also the presence of evaporites represented by the Prairie

Formation, which consists of halite. The Three Forks Formation that is mainly formed by shale, siltstone and dolomite (e.g. Carlson and Anderson, 1965; Gerhard et al., 1982;

Meissner, 1984).

The Mississippian age formation and groups are the Bakken Formation, the Madison

Group, and the Big Snowy Group. The Bakken Formation consist of siltstone and shale; the Madison Group is mainly formed by interbedded limestone and evaporate, and limestone; and the Big Snowy Group, which is represented by the Heath, Otter and

Kibbey formation, which are basically shale, sandstone, and evaporates (e.g. Carlson and

Anderson, 1965; Gerhard et al., 1982; Meissner, 1984).

2.1.4 ABSAROKA SEQUENCE

The Absaroka Sequence (Table 2.2) was deposited between the Pennsylvanian and the

Triassic. Pennsylvanian rocks are represented by the Amsden Formation, which is formed by interbedded dolomite, limestone, shale, and sandstone, and the Minnelussa Formation, which is primarily sandstone and dolomite. Permian stratigraphic layers are the Opeche

Formation (shale, siltstone, and salt), and the Minnekhata Formation (limestone). The

Triassic period is represented by Spearfish Formation, which is consisting of siltstone, salt, and sandstone (e.g. Carlson and Anderson, 1965; Gerhard et al., 1982; Meissner,

1984).

2.1.5 ZUNI SEQUENCE

The Zuni Sequence (Table 2.2) was deposited during the Jurassic and Cretaceous Periods.

The Jurassic age is represented by the Piper Formation (limestone, anhydrite, salt, and red shale), the Sundance Formation (shale and sandstone), and finally the Morrison

Formation (shale and clay). During the Cretaceous, a more extended number of groups were deposited: the Dakota Group, the Colorado Group, and the Montana Group. The

Dakota Group consists mainly of clastic rocks, and it is formed by the Dakota (sandstone and shale), Fall River (sandstone and shale), Skull Creek (shale), Newcastle (sandstone), and the Mowry (shale) Formations. The Colorado Group is divided into 4 formations: the Belle Fourche, Greenhorn, Carlile and Niobrara Formations, and they mainly consist of shale. The Montana Group is formed by two formations: the Pierre Formation, which is consisting of shale, and the Fox Hills Formation which is a marine sandstone layer.

The shallowest formation of this sequence is the Hell Creek Formation that is basically formed by sandstone, shale, and lignite (e.g. Carlson and Anderson, 1965; Gerhard et al.,

1982; Meissner, 1984).

2.1.6 TEJAS SEQUENCE

The Tejas Sequence (Table 2.2) is the youngest stratigraphic sequence in the Williston

Basin, and it comprises the shallower formations and groups in the basin. Some of these formations and groups are represented by the Fort Union Group, and the Golden Valley and White River Formations. The Fort Union Group is divided in 3 different formations: the Ludlow Formation (sandstone, shale, and lignite), the Cannon Ball Formation (marine

8 sandstone and shale), and finally the Tongue River Formation (shale, sandstone, and lignite). At shallower depths, the Golden Valley and White River formations are found, and they consist primarily of shale and sandstone (e.g. Carlson and Anderson, 1965;

Gerhard et al., 1982; Meissner, 1984).

Sequence System Group or Formation Lithology Kaskaskia Mississippian Big Snowy Heath Shale Group Otter Sandstone Kibbey Limestone Madison Interbedded limestone and evaporates Limestone Bakken Siltstone and shale Devonian Three Forks Shale, siltstone and dolomite Birdbear Limestone Duperow Interbedded dolomite and limestone Souris River Interbedded dolomite and limestone Dawson Bay Dolomite and limestone Prairie Halite Tippecanoe Silurian Interlake Dolomite Stonewall Dolomite and limestone Ordovician Stony Mountain Gunton Member Limestone and dolomite Fm. Stoughton Member Argillaceous limestone Red River Limestone and dolomite Winnipeg Roughlock Calcareous shale and Group siltstone Icebox Shale Black Island Sandstone Sauk Cambrian Deadwood Limestone, shale and sandstone Table 2.1 Williston Basin Kaskaskia, Tippocanoe and Sauk Sequences (Carlson and Anderson, 1965).

Sequence System Group or Formation Lithology Glacial Deposits Glacial Drift White River Clay, Sand and Limestone Tejas Tertiary Golden Valley Clay, Sand and Silt Tongue River Shale, sandstone and lignite Fort Union Cannon Ball Marine sandstone and Shale Group Ludlow Sandstone, shale and lignite Zuni Hell Creek Sandstone, shale and lignite Montana Group Fox Hills Marine Sandstone Pierre Shale Niobrara Shale, Calcareous Colorado Group Carlile Shale Greenhorn Shale, Calcareous Cretaceous Belle Fourche Shale Mowry Shale Newcastle Sandstone Dakota Group Skull Creek Shale Fall River Sandstone and shale Dakota Sandstone and shale Morrison Shale, Clay Jurassic Sundance Shale, green and brown and sandstone Piper Limestone, anhydrite, salt and red shale Triassic Spearfish Limestone, salt and sandstone Permian Minnekahta Limestone Absaroka Opeche Shale, siltstone and salt Pennsylvanian Minnelusa Sandstone and dolomite Amsden Interbedded dolomite limestone, shale and sandstone

Table 2.2. Williston Basin Tejas, Zuni, and Absaroka sequences (Carlson and Anderson, 1965).

2. 2 BAKKEN FORMATION

The Bakken Formation is an important formation in the petroleum system of the

Williston Basin, due to its organic enrichment and extension across the basin. The

Bakken Formation is divided in three members: Upper, Middle, and Lower Bakken, where the upper and lower layers are organic rich shale, with an average of total organic carbon content (TOC) of about 10% (e.g. Jarvie, 2001), and type II kerogen (e.g Osadetz et al., 2002), which give these formations a good quality status as a source rock, and mainly oil-and-gas prone source (Figures 2.1). Several isopach maps have been published for the Bakken Formation (Figures 2.2 and 2.3) that are different with respect to the thickness and distribution of the layers.

Figure 2.1. Bakken Formation members’ lithology and average thickness (taken from Khun et al., 2012).

Bakken Formation isopach map after Dembicki and Pirkle (1985). Formation Pirkle and after map Bakken Dembicki isopach

Figure 2.2. Figure

Bakken Formation isopach map in a section of the Williston Basin in North Dakota in North Formation Williston the Basin a in map of Bakken isopach section

Figure 2.3. Figure (NDGS). the stratigraphic by information Dakota Survey well provided Geological North using

2.3 AGES OF DEPOSITION

There is general good agreement on the ages of deposition (Tables 2.3 and 2.4) for the

Williston Basin formations (e.g. LeFever and Crashell, 1991; Murphy et al., 2009). In this study, the age of deposition were taken from the published by the NDGS (Table 2.4).

Age Formation Age (Ma) Formation (Ma) Pierre 70 Charles 341 Niobrara 82 Lodgepole 355 Greenhorn 91 Bakken 362 Mowry 100 Three Forks 370 Inyan Kara 107 Birdbear 377 Swift 154 Duperow 381 Rierdon 160 Souris River 383 Spearfish Dawson Bay 385 Saude Member 246 Prairie 386 Pine Salt Member 250 Winnipegosis 387 Belfield Member 252 Ashern 389 Minnekahta 266 Interlake 409 Opeche 269 Stonewall 422 Stony Minnelusa 275 Mountain 432 Tyler 315 Red River 440 Winnipeg Otter 332 Group Kibbey Roughlock 446 Sandstone Member 335 Icebox 447 Limestone Member 337 Black Island 450 Shale Member 339 Deadwood 491

Table 2.3. Age of deposition according to LeFever and Crashell (1991).

Formation Age of deposition or Erosion before present (Ma) From Till Oahe 0.01 0 Coleharbor (Group) 2.6 0.01 Unnamed unit 5.3 2.6 Arikaree 23 5.3 White River (Group) 41.2 23 Golden Valley 56.3 41.2 Fort Union (Group) 65.5 56.3 Hell Creek 69.56 65.5 Fox Hills 73.62 69.56 Pierre 89.09 73.62 Niobrara 91.33 89.09 Carlile 94.7 91.33 Greenhorn 96.3 94.7 Dakota 145.5 99.6 Swift 168.6 145.5 Rierdon 171.9 168.6 Piper 191.6 171.9 Erosion 216.6 191.6 Spearfish 238 216.6 Minnekahta 267 263 Opeche 283 267 Amsden 310.2 299 Tyler 318 310.2 Kibbey 324.6 320.6 Charles/Base Last Salt 335.2 324.6 Lodgepole 351.1 348.8 Upper Bakken 352.4 351.1 Middle Bakken 353.3 352.4 Lower Bakken 354.6 353.3 Three Forks 361.2 354.6 Birdbear 364.5 361.2 Duperow 374.4 364.5 Souris River 382.1 374.4 Dawson Bay 386.5 382.1 Prairie 399.7 386.5 Winnipegosis 406.3 399.7 Ashern 410.7 406.3 Erosion 430.7 410.7 Interlake 437.6 430.7 Stonewall 445.8 437.6 Stony Mountain 450.4 445.8 Red River 465.1 450.4 Roughlock 466.9 465.1 Icebox 469.7 466.9 Black Island 473.3 469.7 Erosion 486.3 473.3 Deadwood 542 486.3

Table 2.4. Age of deposition according to the North Dakota Geological Survey NDGS (Murphy et al., 2009).

2.3.1 EROSION AGES

Erosion events for this study were based on assumptions about missing stratigraphic formations in some sections, and the thickness of the eroded layer (Table 2.1) was settled using authors work as a guide (Khun et al., 2012)

Age of deposition or Erosion Top of Group or Bottom of Group before present (Ma) Formation or Formation Thickness (m) Maximum From Till Quaternary Quaternary 150 1 0 Erosion 100 3.2 2 White River White River 95 38 3.2 Erosion 650 49.5 38 Upper Golden Valley Carlile 1400 83 50 Greenhorn Inyan Kara 750 119 83 Erosion 180 144 119 Swift Piper 610 181 144 Spearfish Minnekahta 250 255 181 Erosion 100 258 255 Opeche Tyler 370 325 258 Erosion 120 326 325 Big Snow Group Big Snow Group 150 333 326 Erosion 30 346.5 333 Charles Mission Canyon 570 354.5 346.5 Lodgepole Lodgepole 425 358 354.5 Upper Bakken Upper Bakken 9 359.5 358 Middle Bakken Middle Bakken 25 360.5 359.5 Lower Bakken Lower Bakken 17 362 360.5 Three Forks plus Dawson Bay 360 375 362 Prairie Prairie 200 378 376 Winnipegosis Ashern 215 380 378 Erosion 250 400 380 Interlake Winnipeg 650 458 400 Erosion 80 485 458 Deadwood Deadwood 270 525 485 Basement 600 550

Table 2.5. Age of deposition at Williston Basin according to Khun et al. (2012)

2.4 TECTONIC HISTORY OF THE WILLISTON BASIN

The Williston Basin is a Phanerozoic cratonic basin. These types of basins are generally subcircular located on granitic crust, and their basement is generally broken into horst and grabens, but not showing major rifting features (Selley, 1998). There are two types of cratonic basins, intracratonic basins (which are located on continental crust), and epicratonic basins (they are located partly on continental crust and partly on oceanic crust) (Selley, 1998). These basins are characterized by long subsidence periods (Xie and

Heller, 2009) and shallow marine and terrestrial sediment infill (Sloss and Speed, 1974).

The Williston Basin formed in stable continental lithosphere, but the origin of this cratonic basin as well as that of other cratonic basins is debated (Sloss and Speed, 1974;

Sloss, 1988). Some studies suggest that intracratonic basins form due to subsidence of the lithosphere caused by conductive lithospheric cooling following a heating event (Turcotte and Ahern, 1977; Sleep et al., 1980), or subsidence due to a metamorphic phase change in the lower crust (e.g. Armitage and Allen, 2010).. Intracratonic basins are formed in stable continental lithosphere (Sloss and Speed, 1974; Sloss, 1988). Others have said that these basins are formed as part of rift-drift suites at “low extensional stretch factors”

(Allen and Allen, 2005; Armitage and Allen, 2010). According to this model, slow rifting results in some asthenospheric upwelling below the rift and heating of the lithosphere, followed by a long phase of cooling and subsidence. This model is supported by the rift structures that have been found in the Williston Basin and other cratonic basins. The

COCORP (Consortium for Continental Reflection Profiling) seismic dataset and

Lithoprobe seismic reflection data seem to support the phase-change mechanism as the cause of subsidence (Baird et al., 1995).

The Williston Basin has a very complex tectonic history, and many have been the ideas suggested to explain its origin. Some studies suggest that sedimentation patterns and structural style of the basin is strictly related to the movement of basement blocks that were structurally developed previous to Phanerozoic time (Gerhard et al., 1982).

However, this explanation is not enough to satisfy the major questions related to this important hydrocarbon province.

2.4.1 TECTONIC SETTING

The Williston Basin in the North Dakota area was a stable cratonic shelf from Late

Cambrian to Early Ordovician when the deposition of the Sauk Sequence sediments started onlapping the Precambrian basement rocks (Wittstrom, 1990). Based on structural trends, some studies suggest that the major deformation in the Williston Basin is located in the western part of the basin and may be associated with an ancient wrench fault system (Fishcher et al., 1990)

Several major components have affected the earlier evolution of the Williston Basin, its sedimentary and structural configuration, and thermal patterns. The Trans-Hudson orogeny (post-1600 Ma) is believed to be responsible for the suture of the Archean

Superior craton and the Archean Wyoming craton, and as the result of this collision a

18 basin center was created by subsequent belt folding, and a north-south-oriented “strike slip fault and shear belt” (Green et al., 1985; Burret and Berry, 2000; Anna et al., 2010

(a)). Some authors have suggested that the Allegheny Orogeny (325-260Ma) affected the tectonic evolution of the Williston Basin during the earlier stages (e.g. Gaswirth et al.,

2010)

A wrench-fault tectonic system was identified in the western and southwestern areas of the Williston Basin from deformational and deposition patterns (Brown, 1978; Wittstrom,

1990). Basement deformation resulting from compressive Laramide orogenic forces controlled the paleotopographic conditions, sedimentation patterns and facies distribution across the basin (Wittstrom, 1990) around this time. In addition, this same Laramide compressive event was responsible for the formation of different fold structures such as the Nesson, Little Knife, and Billings anticlines (Wittstrom, 1990).

Most of the structural highs in the Williston Basin were probably generated during the

Devonian and Mississippian, and some major reliefs are associated with post deposition events for some formations as Niobrara (82 Ma, Laramide Orogeny), and Stonewall (422

Ma), and Ashern (389 Ma) Formations (LeFever and Crashell, 1991)

Figure 2.4. Tectonic subsidence curves for different cratonic basins from different authors, where curves number 3 (North Dakota) and 4 (Saskatchewan) correspond to the Williston Basin (taken from Xie and Heller, 2009).

Several major unconformities in the Williston Basin have been identified. They include the pre-Cambrian, pre-Middle Ordovician, pre-Devonian, pre-Mississippian, pre-

Pennsylvanian, and post-early Tertiary which were the result of orogenic events generating vertical uplift (Fishcher et al., 1990).

The boundaries of the Williston Basin are debated. The northwestern tectonic boundary is the Sweet-Grass-Battle River arch, the southern boundary is the Transcontinental arch, and the eastern division separates the “Precambrian Churchill and Superior Province rocks” (Gerhard et al., 1982; Fishcher et al., 1990). An informal suggested boundary is the Cedar Creek anticline, which could be considered a separation point between the

Williston Basin and the Powder River Basin (Fishcher et al., 1990)

2.5 SUBSIDENCE HISTORY

Many mechanisms have been proposed to explain the long period of subsidence of the

Williston Basin. Earlier explanations included meteorite impacts, failed rifts, intraplate suture or mass contraction (e.g. Sloss, 1987). More recently thermal contraction and eustatic sea-level changes have been suggested (Sloss, 1987). The thermal contraction theory has many detractors because it can successfully explain subsidence at passive margins, but for cratonic basins it cannot be adapted because it does not explain localized uplift at these basins, and that the rate of subsidence does not fit the t1/2 function of thermal contraction (e.g. Turcotte and Ahern, 1977; Sloss, 1987).

Studies based on subsidence estimations (Figure 2.4) across the basin have shown that subsidence increases toward to the basin center, and slightly decreases on structural highs, and these studies settle the beginning of the general subsidence at about 495 Ma

(LeFever and Crashell, 1991). LeFever and Crashell (1991) related subsidence patterns to major orogenic events, which are the Devonian subsidence with the “opening of the

Williston Basin to the Elk Point Basin”, the Mississippian subsidence to the Central

Montana Trough tectonic activity, and finally the Late Cretaceous subsidence event caused by the onset of the Laramide Orogeny.

2.6 STRUCTURAL STYLE

On the continental scale, previous published work has postulated that northeast-southwest and northwest-southeast orthogonal trends in the North America were developed during early Precambrian time, and that other trends such as north-northwest, east-west, or north-northeast were presumably developed post-Archean and Proterozoic time (Thomas,

1976; Anna et al., 2010(a)). Based on these assumptions, some authors suggest that

Precambrian tectonic events and basement block movements are responsible for the development of major fault and shear systems in the Williston Basin, and that the basin configuration was caused by structural deformation of pre-existing Precambrian structures, and the deformation generated by the Trans-Hudson orogeny (Anna et al.

2010(a)). The most important north-south-trending structural features in the Williston

Basin are the Nesson, Little Knife, and Billing anticlines, which “overlie zones of vertical basement faulting” (Montgomery, 1996).

There is a debate about the timing of the basement blocks. Most studies suggest basement block movement during the Carboniferous Ancestral Rocky Mountain Orogeny and Late

Cretaceous- Early Tertiary Laramide Orogeny (Gerhard and Anderson, 1988; Gerhard et al., 1991; Montgomery, 1996). The Laramide Orogen, which is associated with the subduction of the Farallon plate beneath the North American plate during the Middle

Eocene (Dewey and Bird, 1970; Horbury et al., 2003), generated basement uplifts and basement involved asymmetric anticlines in the Williston Basin. The Laramide Orogeny

(Late Cretaceous to Paleocene orogenic event, 80-50 Ma) is also responsible for the

22 formation of The Sierra Madre Oriental in Mexico, and the Laramide orogenic belt that includes also the Rocky Mountain fold and thrust belt in Canada, and the Laramide block uplifts in the USA (English at al., 2003; Soegaard et al., 2003)

Several studies have focused on sediment deposition time and major subsidence events.

One of these studies places the beginning of the sediment deposition during the Cambrian time, but pointing at the Ordovician time as the stage where major basin filling and subsidence occurred (e.g. Anna et al., 2010 (b)).

Due to the existence of deformed underlying basement rocks and major fault systems, many authors have given these two characteristics a major role in the development of faults and lineaments, thermal history, movement of block-faults, and sedimentation patterns, as well as in the generation, migration, and hydrocarbon distribution across the

Williston Basin (e.g. Montgomery,1996; Anna et al., 2010 (b)).

2.7 THERMAL HISTORY

Thermal evolution of the Williston Basin is extremely controversial. Many authors have proposed a heat flow for the basin of up to 80 mW/m2 and also mentioned thermal anomalies associated with the Nesson anticline formation among other causes (Burrus et al., 1996). Other studies have concluded that the average heat flow in the Williston Basin is 60 mW/m2, and found no thermal anomalies around the Nesson anticline based on thermal conductivity values (Gosnold and Huang, 1987; Gosnold, 1990; Burrus et al.,

1996) Previous studies have also mentioned a constant heat flow value of 55 mW/m2 away from the Nesson anticline, and a constant 65 mW/m2 close to this structure based on the fact of the Bakken Formation oil window and thermal maturity parameters and kinetics of the Williston Basin source rocks (Burrus et al., 1996).

Numerous different heat-flow values have been published in the past by different authors.

Some studies found values higher than 58.5 mW/m2 (Blackwell, 1969), a range of values between 43.3 to 91.08 mW/m2 (Combs and Simmons, 1973; Gosnold, 1990) and some areas with values as high as 100 mW/m2, and more recently (Khun et al., 2012) a range of values of 50 to 74 mW/m2 (Figure 2.5).

Figure 2.5. Heat flow values in the Williston Basin after basin modeling by Khun et al. (2012). Figure taken from Khun et al.(2012)

CHAPTER 3. PETROLEUM GEOCHEMISTRY OF THE WILLISTON BASIN

3.1 TOTAL ORGANIC CARBON CONTENT (TOC)

The total organic carbon content (TOC) is the first step for source rocks identification.

This value gives an estimation of the organic enrichment of the source rock, and the potential of the source rock to generate petroleum upon heating by measuring the organic carbon it contains. In order to consider a rock as a potential source rock, the TOC values need to be above 1 % after the combustion of the sample (Table 3.1).

Total Organic Carbon (% Kerogen Quality TOC) < 0.5 Very poor 0.5 – 1 Poor 1 – 2 Fair 2 – 4 Good 4- 12 Very good > 12 Excellent Table 3.1. Total Organic Carbon (TOC) content ranges for source rock quality assessment (Schlumberger, 2012).

Several parameters are used to analyze the petroleum potential of a source rock. These are based on information extracted from source rocks by rock-eval pyrolysis, bitumen extraction, or presence of hydrocarbon in the analyzed samples (Table 3.2).

Organic Matter Petroleum Bitumen Hydrocarbons Potential Rock-Eval Pyrolysis (ppm) a b TOC (wt. S1 S2 (wt. %) (ppm) %) Poor 0-0.5 0-0.5 0-2.5 0.-0.05 0-500 0-300 Fair 0.5-1 0.5-1 2.5-5 0.05-0.1 500-1000 300-600 Good 1-2 1-2 5-10 0.10-0.20 1000-2000 600-1200 Very Good 2-4 2-4 10-20 0.20-0.40 2000-4000 1200-2400 Excellent > 4 > 4 > 20 > 0.40 > 4000 > 2400 amg HC/g dry rock distilled by pyrolysis. bmg HC/g dry rock cracked from kerogen by pyrolysis. Table 3.2. Source rock petroleum potential based on their organic enrichment (Peters and Cassa, 1994).

3.2 KEROGEN TYPE

Three types of kerogen have been recognized. Type I kerogen or sapropelic kerogen

(algal material) is mainly oil prone; type II kerogen or mixed kerogen is typically oil and gas prone; and type III kerogen or humic kerogen (woody material), is generally gas prone (Tissot, 1997; Dow, 1977) (Table 3.3). They are different because of their composition (carbon, hydrogen, oxygen, nitrogen, and sulfur content), depositional environments, and petroleum type products upon heating and maturation. Type I kerogen

(oil prone) is hydrogen rich, while type III kerogen (gas prone) is hydrogen poor.

Organic matter environment is crucial at the time of kerogen formation. Type I kerogen is formed at marine environments, type II in transitional environments, and type III in terrestrial environments.

Weight percent Ratios Petroleum C H O N S H-C O-C Type Type I 75.9 8.84 7.66 1.97 2.7 1.65 0.06 Oil Algal Type II 77.8 6.8 10.5 2.15 2.7 1.28 0.1 Oil and gas Liptinic Type III 82.6 4.6 2.1 0.1 0.84 0.13 Gas Humic Table 3.3. Kerogen type (taken from Selley (1998); weight percent data (Tissot & Welte, 1978); ratios (Dow, 1977).

Other methods have been suggested for kerogen type identification, including besides the hydrogen index or atomic H/C, the ratio of the peak generation in the rock pyrolysis

S2/S3. This is helpful for determining the kerogen type of a specific source rock (Table

3.4).

Kerogen Type HI (mg HC/g S2 / S3 Atomic H/C Main Expelled Product at Peak TOC) Maturity I > 600 > 15 > 1.5 Oil II 300-600 10-15 1.2-1.5 Oil II/IIIa 200-300 5-10 1.0-1.2 Mixed oil and gas III 50-200 1-5 0.7-1.0 Gas IV < 50 < 1 < 0.7 None

Table 3.4. Approximate kerogen type ranges based on a thermally immature source rock. (Peters and Cassa, 1994).

A more graphic method for kerogen type identification is the Van Kravelen Diagram

(Figure 3.1), which consists of information from source rock evaluation such as the

27 hydrogen index and oxygen index. The graph describes of the petroleum product expected from a specific source rock.

Figure 3.1. Kerogen type from the Van Krevelen Diagram (taken from Schlumberger, 2011).

3.3 ORGANIC MATTER MATURITY

The most common parameters to determine source rock maturation are vitrinite reflectance (Ro), conodont color alteration index (CAI), and thermal alteration index

(Figure 3.2). These parameters are useful to determine if the source rock has generated hydrocarbons and the generation effectiveness of it, as well as the location of the oil and gas window. Vitrinite reflectance is measured as the reflectivity on the grains of vitrinite

(maceral) in the rock under a microscope. The conodont color alteration index is based on the maximum temperature reached in the rock by measuring the thermal alteration of the conodont fossils. Finally, thermal alteration index is determined in kerogen based on the transmitted light color of pollen and spores.

Figure 3.2. Organic matter maturity parameters (taken from Hunt et al., 2002).

Other source rock maturity assessments are based on maximum temperatures (Tmax) obtained in rock-eval pyrolysis experiments or by using oil generation data using bitumen/TOC ratios or production indexes. This information helps to predict the stage of thermal maturity (Table 3.5).

Maturation Generation Stage of Bitumen PIc a b Thermal Ro (%) Tmax (ºC) TAI Bitumen/TOC (mg/g [S1/(S1+S2)] Maturity for rock) Oil Immature 0.2-0.6 < 435 1.5-2.6 < 0.05 < 50 < 0.10 Mature Early 0.6-0.65 435-445 2.6-2.7 0.05-0.10 50-100 0.10-0.15 Peak 0.65-0.9 445-450 2.7-2.9 0.15-0.25 150-250 0.25-0.40 Late 0.9-1.35 450-470 2.9-3.3 > 0.40 Post-mature > 1.35 > 470 > 3.3 aTAI, Themal alteration index. b Mature oil-prone source rocks with type I or II kerogen commonly show Bitumen/TOC ratios in the range 0.05-0.25. Caution should be applied when interpreting extract yields from coals. For example, many gas-prone coals show high extract yields suggesting oil-prone character, but extract yield normalized to TOC is low (<30 mg HC/g TOC). Bitumen/TOC ratios over 0.25 can indicate contamination or migrated oil or can be artifacts caused by ratios of small, inaccurate numbers. cPI, production index. Table 3.5. Source rock thermal maturity stages based on different thermal maturity parameters. (Peters and Cassa, 1994).

3.4 WILLISTON BASIN GEOCHEMISTRY

Several studies focused on the Canadian and American provinces of the Williston Basin.

Vitrinite reflectance and total organic carbon content information from the different source rocks is available. However, vitrinite reflectance is available for the Bakken

Formation at different depths and locations, but not for most of the additional source

30 rocks in the basin (Tables 3.6 and 3.7). In the petroleum systems section of this study more geochemical information about the Williston Basin is discussed.

Strata Depth (m) Depth (ft) Ro (%) LAT LONG U. Bakken 2066.0 6778.2 0.68 51.32024 -102.01748 U. Bakken 1257.6 4126.0 0.47 51.21755 -103.39825 U. Bakken 1406.5 4614.5 0.5 50.98151 -102.93011 L. Bakken 1988.2 6523.0 0.67 51.68881 -102.35118 U. Bakken 1970.0 6463.3 0.66 51.68881 -102.35118 U. Bakken 1953.8 6410.1 0.66 50.70101 -102.52854 U. Bakken 1259.3 4131.6 0.46 52.07828 -103.75515 M. Bakken 2087.9 6850.1 0.67 49.82092 -102.35647 U. Bakken 2071.7 6796.9 0.54 49.82092 -102.35647 L. Bakken 1846.2 6057.1 0.54 50.60029 -102.86702 U. Bakken 1828.0 5997.4 0.62 50.06866 -102.63156 L. Bakken 1845.3 6054.1 0.65 50.06866 -102.63156 U. Bakken 2019.0 6624.0 0.61 49.52976 -102.67244 U. Bakken 2053.1 6735.9 0.53 49.35581 -102.57835

Table 3.6. Vitrinite reflectance values, depths and location for the Bakken Formation in the Williston Basin at Saskatchewan, Canada (Jiang et al., 2001).

Ro Strata Depth (ft) (%) LAT LONG U. Bakken 10516.0 1.01 47.71739 -102.579 L. Bakken 10578.0 0.78 47.71739 -102.579 L. Bakken 10596.0 1.01 47.71739 -102.579 U. Bakken 11235.0 1.26 47.63113 -103.163 L. Bakken 11274.0 1.34 47.63113 -103.163 L. Bakken 10044.0 0.58 47.02461 -102.589

Table 3.7. Vitrinite reflectance values, depths and location for the Bakken Formation in the Williston Basin at North Dakota, USA (Leenheer, 1984).

3.5 PETROLEUM SYSTEMS OF THE WILLISTON BASIN

Different petroleum systems have been recognized in the Williston Basin by different authors: Tyler, Bakken–Madison, and Winnipeg-Red River (Dow, 1974); Winnipeg-

Deadwood, Red River total petroleum system; Duperow total petroleum system (e.g.

Anna, 2010); Mission Canyon-Spearfish, Red River-Interlake, Red River-Winnipeg or

Bakken-Lodgepole (Jarvie, 2001). In addition to these petroleum systems, there are many others that are hypothetical and some that are proven (Tables 3.8 and 3.9). However, there is a debate on the main source rocks for the different reservoirs. This controversy is caused by the significant number of different source rocks, and the existence of multiple reservoir rocks.

Source Rock-Reservoir Production References Mission Canyon-Spearfish (P) > 0.4 MMBO Jarvie, 2001 Bakken-Spearfish (H) > 0.4 MMBO Osadetz and Snowdon, 1995 Tyler-Tyler (P) > 70 MMBO Williams, 1974; Dow, 1974 Ratcliffe-Ratcliffe (H) Na Jarvie, 2001 Mission Canyon-Mission Canyon (P) > 750 MMBO Jarvie, 2001; Jarvie and Walker, 1997 Bakken-Lodgepole (P) > 6 MMBO Jarvie, 2001; Jarvie and Walker, 1997 Bakken-Bakken (P) > 4 MMBO Williams, 1974; Dow, 1974 Bakken Nisku (P) > 5 MMBO Williams, 1974; Jarvie, 2001 Duperow-Duperow (H) > 120 MMBO Zumberge, 1983 Duperow-Dawson Bay (H) > 3 MMBO Jarvie, 2001 Winnipegosis-Winnipegosis (H) > 6 MMBO Osadetz and Snowdon, 1995 Winnipegosis-Interlake (H) > 55 MMBO Jarvie, 2001 Red River-Interlake (P) > 55 MMBO Jarvie, 2001 Red River-Red River (P) > 100 MMBO All post 1974 studies Red River-Winnipeg (P) > 0.03 MMBO Jarvie, 2001 Winnipeg-Winnipeg (H) > 0.03 MMBO Jarvie, 2001 Ordo/Cambro-Deadwood (H) Na Zumberge, 1983; Peterson, 1988

Table 3.8. Proven (P) and Hypothetical (H) petroleum systems in Williston Basin and their oil production (taken from Jarvie, 2001).

Petroleum Source Rock Reservoir Rock Trap Seal System Winnipeg-  Icebox  Deadwood Structural with Shales from the Deadwood Formation Formation minor structural Icebox Formation Total Petroleum  Winnipeg component and shale to system Group limestone Red River Total  Red River  Red River Structural with Lateral seals Petroleum Formation Formation stratigraphic System  Stony Mountain enhancement Formation  Stonewall Formation  Interlake Formation Winnipegosis  Winnipegosis  Winnipegosis Structural and Anhydrite, tight Total Petroleum Formation Formation stratigraphic traps dolomites or System  Ashern limestones (lateral Formation seals), salt (Prairie (Canada) Formation) Duperow Total  Duperow and  Dawson Bay  Nesson Reservoir top Petroleum Birdbear Formation Anticline seals: anhydrite, System Formations  Souris River  Structural salt,  Souris River Formation highs by salt cryptocrystalline and Dawson  Duperow dissolution dolomite, and Bay Formations Formation  Billings nose, anhydritic (less likely)  Birdbear Billings dolostone Formation Anticline and Mondak trend  Uncorformity stratrigraphic traps Tyler Total  Tyler  Tyler  Stratigraphic NA Petroleum Formation Formation traps System

Table 3.9. Some of the petroleum systems identified in the Williston Basin (Anna et al., 2010(a); Anna, 2010; Anna et al., 2010(b)).

The main Williston basin source rocks are Paleozoic source rocks. The most common source rocks (Table 3.10) are the following the Yeoman Formation (Upper Ordovician),

Winnipegosis Formation (Middle Devonian), Tyler Formation (Pennsylvanian), Bakken

Formation (Upper Devonian-Lower Carboniferous), Lodgepole Formation (Lower

Carboniferous) and the Ordovician Red River Formation (Jarvie, 2001; Osadetz et al.,

2002). In addition, there is a not well described Upper Cambrian- Lower Ordovician source rock from the Deadwood Formation (Osadetz et al., 2002). The Bakken Formation is an organic-enriched source rock, which presents TOC values from 0.65 to 10.33%, with an average of 3.84% (Meisner, 1984).

The kerogen kinetics in the basin is type II kerogen (oil and gas prone) except for

Yeoman Formation which is composed of type I organic matter (oil prone) (Osadetz et al., 2002). However, the Tyler Formation is being identified as type III kerogen due to its low hydrogen index values (e.g. Dow, 1974; Anna, 2010)

As was mentioned before, the Williston Basin has multiple pay zones, in other words, multiple reservoir rocks. The Mississippian Madison Group was until 1996, responsible for 61% of “North Dakota’s Williston Basin historical production” (Jarvie, 2001). Other important reservoirs are the Ordovician Red River Formation, and the Devonian

Duperow Formation, which combined with the Madison Group account for 80% of North

Dakota’s oil production (Jarvie, 2001). The most important reservoirs from the Madison

Group are the Charles Formation, Mission Canyon Formation, and the Lodgepole

Formation.

Traps in the Williston are mostly formed by anticlines (Figure 3.3). The Cedar Creek anticline discovered in eastern Montana in 1936 and the Nesson anticline (1951) are the most relevant anticlines in the basin (Figure 1.2) (Gerhard et al., 1982). There are other

34 trap structures such as the Red Wing Structure (Mississippian rocks), and the Newport

Structure (Deadwood Sandstone), and these are thought to be caused by meteorite impacts due to their geometries (Gerhard et al., 1982).

Seals within the Madison Group suggest the presence of multiple source horizons in the group, which might explain the different oil compositions derived from these source rocks. Madison oils and Bakken oils do not correlate except in strongly faulted or fractured zones, which may be explained by very effective seals between them. The cause of this is the presence of pressure seals, which would make this an effective pressure- sealed system (Jarvie, 2001).

Figure 3.3. The Nesson Anticline is an example of traps in the Williston Basin. Figure taken from Osadetz et al. (2002)

Formation Age Average TOC Average Hydrogen Reference (wt. %) Index (mg HC/g TOC) Winnipeg L. Ordovician 1.68 420 Jarvie, 2001 Icebox L. Ordovician 1.55 520 Osadetz & (Winnipeg) Snowdon, 1995 Yeoman Ordovician 9.07 728 Osadetz & Snowdon, 1995 Red River Ordivician 7.13 664 Jarvie, 2001 Brightholme (M. L. Devonian 7.38 515 Osadetz & Winnipegosis) Snowdon, 1995 Winnipegosis L. Devonian 0.59 120 Osadetz & Snowdon, 1995 Duperow Devonian 3.02 342 Jarvie, 2001 Bakken Dev.-Miss. 12.57 481 Price et al., 1984 (immature only) Bakken Dev.-Miss. 11.08 401 Muscio, 1994 (immature only) Lower Bakken Dev.-Miss. 17.63 410 Osadetz & Snowdon, 1995 Upper Bakken Dev.-Miss. 11.77 399 Osadetz & Snowdon, 1995 Lodgepole Mississippian 5.49 401 Osadetz & Snowdon, 1995 L. Mission Mississippian 1.96 394 Jarvie & Walker, Canyon 1997 M. Mission Mississippian 8.50 300 Jarvie & Walker, Canyon 1997 U. Mission Mississippian 1.92 273 Jarvie & Walker, Canyon 1997 Ratcliffe Mississippian 1.83 378 Jarvie, 2001 Tyler Pennsylvanian 0.8 Na Williams, 1974 Tyler Pennsylvanian 6.08 174 Jarvie, 2001 Heath Pennsylvanian 2.68 Na Williams, 1974 Heath Pennsylvanian 5.83 268 Jarvie, 2001 Table 3.10. Organic enrichment of the Williston Basin source rocks (taken from Jarvie, 2001).

CHAPTER 4. METHODS AND DATA

4.1 METHODOLOGY

For this research, the first step was reviewing the previous literature published for the

Williston Basin. Once all the information was collected, it was analyzed and paraphrased for background purposes. The information needed for this specific project included stratigraphic, lithological, tectonic, and geochemical data in order to perform the modeling of the basin in the North Dakota area.

The stratigraphic information of the basin was compiled from well information provided by the Oil and Gas Division of the North Dakota Geological Survey (NDGS), and the geologic formations lithology description was taken from published literature. A stratigraphic chart constructed by the NDGS was also used for the age of deposition of the geologic formations, and their respective maximum thicknesses were used as a guide to compared with the wells information. Although the Williston Basin is a cratonic basin and preserves most of the stratigraphic layers, it was not straight forward to construct the stratigraphic chart due to the absence of deep vertical wells because of the existence of unconventional reservoirs that obligates to drill wells horizontally or deviated.

The geochemical information was collected from previous published data. Average Total

Organic Carbon Content (% TOC) and Hydrogen Index (HI) values, and kerogen type have been published before and those are used in this study. In addition, for thermal maturity purposes, vitrinite reflectance (Ro) values have been published from the North

Dakota area and Saskatchewan in Canada. These thermal maturity values are used for the heat flow calibration of the model.

4.1.1 METHODS

Petromod (e.g. Schlumberger, 2012) was used to analyze the petroleum system of the

Williston Basin in North Dakota. Petromod simulates subsidence and thermal history of a basin to study the necessary conditions for the hydrocarbon generation when the petroleum system elements (source rocks, reservoirs, overburden rock, etc) are defined, and geochemical data compiled (%TOC, kerogen type) (Figure 2).

4.2 PETROLEUM SYSTEMS MODELING

Geoscientists create geologic models to recreate or imitate the natural processes by putting together different parameters. In the case of petroleum systems, a model is created to simulate processes involved in basin formation and petroleum generation to understand and predict them. In addition, a petroleum system model can also show a record of the generation, migration, accumulation and loss of hydrocarbons through geologic time.

In general terms, the purpose and main objective of a petroleum system model is to simulate the occurrence of processes and formation of the elements involved in a petroleum system in a geologic time framework (Figure 4.1).

Figure 4.1. Petroleum systems elements and processes necessary for hydrocarbon generation (taken from Schlumberger, 2009).

In this study, 1D models were created to analyze the hydrocarbon generation, vitrinite reflectance evolution, temperature, subsidence curves and kerogen transformation ratios.

These parameters helped to have a more clear understanding of the petroleum system and tectonic history of the basin.

In addition, 2D models were created in this study using stratigraphic data from well information for cross sections construction. This analysis provides information about the hydrocarbon generation and migration, and possible traps and reservoirs. These models also show the evolution of the basin through geological time.

4.3 BACKSTRIPPING AND PETROMOD

The backstripping concept was used for an understanding of the burial history through time. This method consists of removing the isostatic effects created by the sediment and water column load, so once this load has been removed, the total subsidence originated from tectonic driving force is obtained. This concept was proposed by Watts and Ryan

(1976). The method isolates the tectonic driving force by removing the isostatic effects of the sediment load.

Schlumberger created a software package called PetroMod that is used for the modeling of petroleum systems with entire workflow for 1D, 2D, and 3D modeling products. This software runs different simulations in different dimensions to make a better evaluation of the uncertainties in hydrocarbon migration. PetroMod 1D performs different analyses such as burial history, temperature-depth, thermal conductivity-depth, porosity-depth, thermal maturation, hydrocarbon generation, and pressure history, among other analyses.

PetroMod 2D is more sophisticated and provides a multidimensional simulation of the basin, and in addition runs a simulation of temperature and pressure simulation modules and full migration capabilities, using the information of lithology, organic enrichment, and type of source rock (Schlumberger, 2012).

4.4 DATA SOURCE

The Oil and Gas Division of North Dakota Geological Survey (NDGS) provided the required stratigraphic data from well information necessary for the model construction.

This institution also provided the lithology description and ages of deposition for the different formations of the Williston Basin.

The geochemical data was compiled from different studies on the total organic carbon content (%TOC) average values and kinetics of the source rock (kerogen type) (Jarvie,

2001; Osadetz et al., 2002). The model was calibrated using vitrinite reflectance values from Dembicki and Pirkle (1985)

4.4.1 2D CROSS SECTIONS

Two 2D cross sections (Figure 4.2) were constructed for this investigation: one North-

South (N-S), and one East-West (E-W). For the N-S cross section, which covers approximately 209 km in distance, six wells were used for the stratigraphic correlation between top formations (Table 4.1). In the case of the E-W cross section, which covers approximately 95 km, four wells were used for the formations top correlation (Table 4.2).

The information for the formation tops was provided by the North Dakota Geological

Survey using oil companies’ real data. It is important to highlight that the depths used for these stratigraphic correlations were depth subsea, and that most of the formations above the Greenhorn Formation were hypothetical depths as there is no reliable information about the shallower formations (LeFever and Crashell, 1991).

W cross sections used in the study the in used Wsections cross

S and E Sand

Figure 4.2. Figure

Formation Well 1 Well 2 Well 3 Well 4 Well 5 Well 6 Depth Subsea (ft) Quaternary -2436 -2282 -2390 -2318 -2298 -2272 Neogene -1350 -1300 -1400 -1300 -1100 -1100 Pierre -700 -600 -830 -600 -200 -292 Greenhorn 1659 1750 1492 1716 2197 1818 Dakota 2246 2439 1846 2114 2667 2612 Swift 2659 2848 2642 2852 3404 Rierdon 3032 3293 3070 3394 3925 3444 Piper 3655 3470 3690 Spearfish 3636 3735 3630 3933 4407 Minnekahta 4320 4605 4042 Opeche 4056 4349 4648 4086 Amsden 4382 4696 5105 Tyler 4460 5008 5718 4862 Kibbey 4317 4996 5082 5596 6152 5251 Charles 4947 5739 5896 6406 6714 5733 Lodgepole 5681 6853 6676 7208 7435 6375 Upper Bakken 6374 7240 7398 7988 8290 7131 Middle Bakken 6393 7257 7412 8001 8299 7143 Lower Bakken 6468 7321 7465 8051 8333 7150 Three Forks 6510 7357 7494 8079 8351 7154 Birdbear 6695 7580 7692 8280 8573 7331 Duperow 6815 7690 7776 8385 8653 7409 Souris River 7333 8140 8212 8798 8994 7668 Dawson Bay 7625 8408 8471 9058 9244 7858 Prairie 7940 8541 8609 9184 9360 7939 Winnipegosis 8275 8875 8884 9362 9430 Ashern 8355 9095 9060 9574 Interlake 8430 9194 9193 9734 9699 8254 Stonewall 10236 10712 Stony Mountain 9441 10278 10353 11032 10732 9014 Red River 9550 10459 10485 11178 10752 9138 Roughlock 11084 14126 Icebox 14178 Black Island 11277 14324 Deadwood 11429 14520 TD 9950 10798 11810 14802 11182 10108

Table 4.1. Formation depths at different wells and locations provided by the Oil and Gas Division of the North Dakota Geological Survey for the North-South Cross Section. Boxes in green are hypothetical.

Well N° Formation 7 8 9 5 Depth Subsea (ft) Quaternary -2578 -2423 -2705 -2318 Neogene -1450 -1350 -1650 -1100 Pierre -600 -500 -700 -200 Greenhorn 2145 2210 1939 2197 Dakota 3057 3214 2882 2667 Swift 3243 3404 Rierdon 4024 3731 3925 Piper 4349 3795 Spearfish 4510 4086 4407 Minnekahta 4932 4575 4605 Opeche 4972 4664 4648 Amsden 5080 4921 5105 Tyler 5744 5324 5718 Kibbey 6022 6178 5673 6152 Charles 6156 6323 5821 6714 Lodgepole 7489 7594 7435 Upper Bakken 8182 8406 8290 Middle Bakken 8415 8299 Lower Bakken 8441 8333 Three Forks 8187 8444 8351 Birdbear 8338 8657 8573 Duperow 8412 8734 8653 Souris River 8751 9102 8994 Dawson Bay 8910 9329 9244 Prairie 9000 9410 9360 Winnipegosis 9080 9478 9430 Ashern Interlake 9259 9686 9699 Stonewall 9922 11032 Stony Mountain 10042 10652 10752 Red River 10106 10794 10908 TD 10502 11109 10496 11182

Table 4.2. Formation depths at different wells and locations provided by the Oil and Gas Division of the North Dakota Geological Survey for the East-West cross section. Boxes in green are hypothetical.

4.4.2 WELLS

In this study, 9 different wells were used for basin modeling purposes (Tables 4.1 and

4.2; Figure 4.3). Wells 1 to 6 were used to construct the N-S cross section (Tables 4.3,

4.4, 4.5, 4.6, 4.7, 4.8), and wells 7 to 9 and well 5, were the wells used for the E-W cross section construction (Tables 4.2 and 4.9).

Figure 4.3. Wells used in the study.

Age of Erosion (Ma) Deposition (Ma) Top Base Thickness Erosion Formation From To From To (ft) (ft) (ft) (ft) Quaternary -2436 -1350 1086 2.6 0.01 Neogene -1350 -700 650 23 2.6 Pierre -700 1659 2359 700 89.09 73.62 70 23 Greenhorn 1659 2246 587 96.3 94.7 Dakota 2246 2659 413 145.5 99.6 Swift 2659 3032 373 168.6 145.5 Rierdon 3032 3636 604 171.9 168.6 Spearfish 3636 4317 681 413 238 216.6 216.6 171.9 Kibbey 4317 4947 630 276 324.6 320.6 320.6 238 Charles 4947 5681 734 335.2 324.6 Lodgepole 5681 6374 693 351.1 348.8 Upper 6374 6393 19 352.4 351.1 Bakken Middle 6393 6468 75 353.3 352.4 Bakken Lower 6468 6510 42 354.6 353.3 Bakken Three Forks 6510 6695 185 361.2 354.6 Birdbear 6695 6815 120 364.5 361.2 Duperow 6815 7333 518 374.4 364.5 Souris River 7333 7625 292 382.1 374.4 Dawson Bay 7625 7940 315 386.5 382.1 Prairie 7940 8275 335 399.7 386.5 Winnipegosis 8275 8355 80 406.3 399.7 Ashern 8355 8430 75 410.7 406.3 Interlake 8430 9441 1011 574 437.6 430.7 430.7 410.7 Stony 9441 9550 109 0 450.4 445.8 445.8 437.6 Mountain Red River 9550 9950 400 465.1 450.4 TD 9950 10450 500 0 600 542 542 465.1

Table 4.3. Well 1 data.

Age of Deposition (Ma) Erosion (Ma) Top Base Thickness Erosion Formation (ft) (ft) (ft) (ft) From To From To Quaternary -2282 -1300 982 2.6 0.01 Neogene -1300 -600 700 23 2.6 Pierre -600 1750 2350 700 89.09 73.62 70 23 Greenhorn 1750 2439 689 96.3 94.7 Dakota 2439 2848 409 145.5 99.6 Swift 2848 3293 445 168.6 145.5 Rierdon 3293 3655 362 171.9 168.6 Piper 3655 3735 80 191.6 171.9 Spearfish 3735 4996 1261 413 238 216.6 216.6 191.6 Kibbey 4996 5739 743 276 324.6 320.6 320.6 238 Charles 5739 6853 1114 335.2 324.6 Lodgepole 6853 7240 387 351.1 348.8 Upper Bakken 7240 7257 17 352.4 351.1 Middle Bakken 7257 7321 64 353.3 352.4 Lower Bakken 7321 7357 36 354.6 353.3 Three Forks 7357 7580 223 361.2 354.6 Birdbear 7580 7690 110 364.5 361.2 Duperow 7690 8140 450 374.4 364.5 Souris River 8140 8408 268 382.1 374.4 Dawson Bay 8408 8541 133 386.5 382.1 Prairie 8541 8875 334 399.7 386.5 Winnipegosis 8875 9095 220 406.3 399.7 Ashern 9095 9194 99 410.7 406.3 Interlake 9194 10278 1084 574 437.6 430.7 430.7 410.7 Stony Mountain 10278 10459 181 0 450.4 445.8 445.8 437.6 Red River 10459 10798 339 465.1 450.4 TD 10798 11298 500 0 600 542 542 465.1

Table 4.4. Well 2 data.

Age of Deposition (Ma) Erosion (Ma) Top Base Thickness Erosion Formation (ft) (ft) (ft) (ft) From To From To Quaternary -2390 -1400 990 2.60 0.01 Neogene -1400 -830 570 23.00 2.60 Pierre -830 1492 2322 700 89.09 73.62 70.00 23.00 Greenhorn 1492 1846 354 96.30 94.70 Dakota 1846 2642 796 145.50 99.60 Swift 2642 3070 428 168.60 145.50 Rierdon 3070 3470 400 171.90 168.60 Piper 3470 3630 160 191.60 171.90 Spearfish 3630 4056 426 413 238.00 216.60 216.60 191.60 Opeche 4056 4382 326 0 283.00 267.00 267.00 238.00 Amsden 4382 4460 78 310.20 299.00 Tyler 4460 5082 622 318.00 310.20 Kibbey 5082 5896 814 276 324.60 320.60 320.60 318.00 Charles 5896 6676 780 335.20 324.60 Lodgepole 6676 7398 722 351.10 348.80 Upper 7398 7412 14 352.40 351.10 Bakken Middle 7412 7465 53 353.30 352.40 Bakken Lower 7465 7494 29 354.60 353.30 Bakken Three Forks 7494 7692 198 361.20 354.60 Birdbear 7692 7776 84 364.50 361.20 Duperow 7776 8212 436 374.40 364.50 Souris River 8212 8471 259 382.10 374.40 Dawson Bay 8471 8609 138 386.50 382.10 Prairie 8609 8884 275 399.70 386.50 Winnipegosis 8884 9060 176 406.30 399.70 Ashern 9060 9193 133 410.70 406.30 Interlake 9193 10353 1160 574 437.60 430.70 430.70 410.70 Stony 10353 10485 132 0 450.40 445.80 445.80 437.60 Mountain Red River 10485 11084 599 465.10 450.40 Roughlock 11084 11277 193 466.90 465.10 Black Island 11277 11429 152 0 473.30 469.70 469.70 466.90 Deadwood 11429 11810 381 184 542.00 486.30 486.30 473.30 TD 11810 12310 500 600.00 542.00

Table 4.5. Well 3 data.

Age of Deposition (Ma) Erosion (Ma) Top Base Thickness Erosion Formation (ft) (ft) (ft) (ft) From To From To Quaternary -2318 -1300 1018 2.60 0.01 Neogene -1300 -600 700 23.00 2.60 Pierre -600 1716 2316 700 89.09 73.62 70.00 23.00 Greenhorn 1716 2114 398 96.30 94.70 Dakota 2114 2852 738 145.50 99.60 Swift 2852 3394 542 168.60 145.50 Rierdon 3394 3690 296 171.90 168.60 Piper 3690 3933 243 191.60 171.90 Spearfish 3933 4320 387 413 238.00 216.60 216.60 191.60 Minnekahta 4320 4349 29 267.00 263.00 Opeche 4349 4696 347 283.00 267.00 Amsden 4696 5008 312 310.20 299.00 Tyler 5008 5596 588 318.00 310.20 Kibbey 5596 6406 810 276 324.60 320.60 320.60 318.00 Charles 6406 7208 802 335.20 324.60 Lodgepole 7208 7988 780 351.10 348.80 Upper 7988 8001 13 352.40 351.10 Bakken Middle 8001 8051 50 353.30 352.40 Bakken Lower 8051 8079 28 354.60 353.30 Bakken Three Forks 8079 8280 201 361.20 354.60 Birdbear 8280 8385 105 364.50 361.20 Duperow 8385 8798 413 374.40 364.50 Souris River 8798 9058 260 382.10 374.40 Dawson Bay 9058 9184 126 386.50 382.10 Prairie 9184 9362 178 399.70 386.50 Winnipegosis 9362 9574 212 406.30 399.70 Ashern 9574 9734 160 410.70 406.30 Interlake 9734 10236 502 574 437.60 430.70 430.70 410.70 Stonewall 10236 11032 796 445.80 437.60 Stony 11032 11178 146 450.40 445.80 Mountain Red River 11178 11808 630 465.10 450.40 Roughlock 11808 11860 52 466.90 465.10 Icebox 11860 12006 146 469.70 466.90 Black Island 12006 12202 196 473.30 469.70 Deadwood 12202 12484 282 184 542.00 486.30 486.30 473.30 TD 12484 12984 500 600.00 542.00

Table 4.6. Well 4 data.

Age of Deposition (Ma) Erosion (Ma) Top Base Thickness Erosion Formation (ft) (ft) (ft) (ft) From To From To Quaternary -2298 -1100 1198 1.00 0.00 Neogene -1100 -200 900 23.00 2.60 Pierre -200 2197 2397 700 89.09 73.62 70.00 23.00 Greenhorn 2197 2667 470 96.30 94.70 Dakota 2667 3404 737 145.50 99.60 Swift 3404 3925 521 168.60 145.50 Rierdon 3925 4407 482 171.90 168.60 Spearfish 4407 4605 198 413 238.00 216.60 216.60 171.90 Minnekahta 4605 4648 43 267.00 263.00 Opeche 4648 5105 457 283.00 267.00 Amsden 5105 5718 613 310.20 299.00 Tyler 5718 6152 434 318.00 310.20 Kibbey 6152 6714 562 276 324.60 320.60 320.60 318.00 Charles 6714 7435 721 335.20 324.60 Lodgepole 7435 8290 855 351.10 348.80 Upper 8290 8299 9 352.40 351.10 Bakken Middle 8299 8333 34 353.30 352.40 Bakken Lower 8333 8351 18 354.60 353.30 Bakken Three Forks 8351 8573 222 361.20 354.60 Birdbear 8573 8653 80 364.50 361.20 Duperow 8653 8994 341 374.40 364.50 Souris River 8994 9244 250 382.10 374.40 Dawson Bay 9244 9360 116 386.50 382.10 Prairie 9360 9430 70 399.70 386.50 Winnipegosis 9430 9699 269 406.30 399.70 Interlake 9699 10732 1033 574 437.60 430.70 430.70 406.30 Stony 10732 10752 20 0 450.40 445.80 445.80 437.60 Mountain Red River 10752 11182 430 465.10 450.40 TD 11182 11682 500 500 600.00 542.00 542.00 465.10

Table 4.7. Well 5 data.

Age of Deposition (Ma) Erosion (Ma) Top Base Thickness Erosion Formation (ft) (ft) (ft) (ft) From To From To Quaternary -2272 -1100 1172 1.00 0.00 Neogene -1100 -292 808 23.00 2.60 Pierre -292 1818 2110 700 89.09 73.62 70.00 23.00 Greenhorn 1818 2612 794 96.30 94.70 Dakota 2612 3444 832 145.50 99.60 Rierdon 3444 4086 642 0 171.90 168.60 168.60 145.50 Opeche 4086 4862 776 413 283.00 267.00 267.00 171.90 Tyler 4862 5251 389 0 318.00 310.20 310.20 299.00 Kibbey 5251 5733 482 276 324.60 320.60 320.60 318.00 Charles 5733 6375 642 335.20 324.60 Lodgepole 6375 7131 756 351.10 348.80 Upper 7131 7143 12 352.40 351.10 Bakken Middle 7143 7150 7 353.30 352.40 Bakken Lower 7150 7154 4 354.60 353.30 Bakken Three 7154 7331 177 361.20 354.60 Forks Birdbear 7331 7409 78 364.50 361.20 Duperow 7409 7668 259 374.40 364.50 Souris 7668 7858 190 382.10 374.40 River Dawson 7858 7939 81 386.50 382.10 Bay Prairie 7939 8254 315 399.70 386.50 Interlake 8254 9014 760 574 437.60 430.70 430.70 399.70 Stony 9014 9138 124 0 450.40 445.80 445.80 437.60 Mountain Red River 9138 10108 970 465.10 450.40 TD 10108 10608 500 0 600.00 542.00 542.00 465.10

Table 4.8. Well 6 data.

Age of Deposition (Ma) Erosion (Ma) Top Base Thickness Erosion Formation (ft) (ft) (ft) (ft) From To From To Quaternary -2578 -1450 1128 1.00 0.00 Neogene -1450 -600 850 23.00 2.60 Pierre -600 2145 2745 700 89.09 73.62 70.00 23.00 Greenhorn 2145 3057 912 96.30 94.70 Dakota 3057 4024 967 145.50 99.60 Rierdon 4024 4349 325 0 171.90 168.60 168.60 145.50 Spearfish 4349 4932 583 413 238.00 216.60 216.60 171.90 Minnekahta 4932 4972 40 267.00 263.00 Opeche 4972 5080 108 283.00 267.00 Amsden 5080 6022 942 310.20 299.00 Kibbey 6022 6156 134 276 324.60 320.60 320.60 310.20 Charles 6156 7489 1333 335.20 324.60 Lodgepole 7489 8182 693 351.10 348.80 Bakken 8182 8187 5 354.60 351.10 Three Forks 8187 8338 151 361.20 354.60 Birdbear 8338 8412 74 364.50 361.20 Duperow 8412 8751 339 374.40 364.50 Souris River 8751 8910 159 382.10 374.40 Dawson Bay 8910 9000 90 386.50 382.10 Prairie 9000 9080 80 399.70 386.50 Winnipegosis 9080 9259 179 406.30 399.70 Interlake 9259 9922 663 574 437.60 430.70 430.70 406.30 Stonewall 9922 10042 120 445.80 437.60 Stony 10042 10106 64 450.40 445.80 Mountain Red River 10106 10502 396 465.10 450.40 TD 10502 11002 500 184 600.00 542.00 542.00 465.10

Table 4.9. Well 7 data.

4.5 SOURCE ROCKS

There are 7 different source rocks in the study. For modeling and hydrocarbon generation purposes the kinetics of the source rocks primarily type II kerogen of Behar et al. (1997), except for the Tyler Formation which is type III kerogen of Behar et al. (1997). Flannery

(2006) used this type of kerogen in his study for hydrocarbon generation purposes. The additional geochemical data was compiled from Jarvie (2001), who made a summary of the different average total organic carbon content values (TOC) for every source rock from proper studies and from other authors. The hydrogen index values were also taken from the same investigation mentioned before (Table 4.10)

Total Organic Carbon Content Hydrogen Formation TOC (%) Kinetics Index HI Tyler 6.08 Behar_et_al(1997)_TIII- 174.00 (Dogger) Lodgepole 5.49 Behar_et_al(1997)_TII(PB) 401.00 Upper 11.77 Behar_et_al(1997)_TII(PB) 399.00 Bakken Lower 17.63 Behar_et_al(1997)_TII(PB) 410.00 Bakken Duperow 3.02 Behar_et_al(1997)_TII(PB) 342.00 Winnipegosis 0.59 Behar_et_al(1997)_TII(PB) 120.00 Red River 7.13 Behar_et_al(1997)_TII(PB) 664.00 Table 4.10. Source rocks geochemical information.

4.5.1 KINETICS

Price et al. (1984) and Webster (1984), published the kerogen type for the Bakken

Formation at the Williston Basin using the modified Van Krevelen diagram (Figure 4.4) using hydrogen-carbon and oxygen-carbon ratios from analyzed samples, and the majority of results were positioned at type I and II kerogen, which are mainly oil and gas prone (Sonnenberg and Pramudito, 2009). For this specific research and modeling purposes, Behar et al. (1997) type II kerogen was selected based on the published hydrogen index for source rocks in the basin, and for the fact that most of the source rocks at the Williston Basin have type II kerogen, except for the Winnipegosis Formation which is is type III (Jarvie, 2001; Osadetz et al., 2002).

Figure 4.4. Van Krevelen diagram for the Bakken Formation from Price et al. (1984) and Webster (1984), where most results were type I and II kerogen (taken from Sonnenberg and Pramudito, 2009).

4.6 PETROLEUM SYSTEM ELEMENTS

For each formation a petroleum system element was assigned based on previous published literature and their lithology (Table 4.11). Source rocks, reservoir rocks, seal rocks, overburden rocks, and underburden rocks were identified for modeling purposes.

Petroleum System Element Formation Lithology (PSE) Quaternary Shale (typical) Overburden Rock Neogene Shale (typical) Overburden Rock Pierre SHALE Overburden Rock Greenhorn SHALEcalc Overburden Rock Dakota Sandstone (clay rich) Overburden Rock Swift Sandstone (clay rich) Overburden Rock Rierdon SHALEcarb Overburden Rock Piper SHALEcarb Overburden Rock Spearfish SILT&SAND Reservoir Rock Minnekahta LIMESTONE Overburden Rock Opeche SILT&SAND Reservoir Rock Amsden Dolomite (organic lean, sandy) Overburden Rock Tyler Shale (typical) Source Rock Kibbey SANDshaly Seal Rock Charles Limestone (shaly) Reservoir Rock Lodgepole Limestone Source Rock Upper Bakken Shale (organic lean, typical) Source Rock Middle Bakken Siltstone Reservoir Rock Lower Bakken Shale (organic lean, typical) Source Rock Three Forks LIMEdolom Seal Rock Birdbear LIMEdolom Reservoir Rock Duperow Dolomite Source Rock Souris River Dolomite Reservoir Rock Dawson Bay Dolomite Underburden Rock Prairie Halite Seal Rock Winnipegosis LIMEdolom Source Rock Ashern Dolomite Underburden Rock Interlake LIMEdolom Reservoir Rock Stonewall LIMEdolom Underburden Rock Stony Mountain Dolomite Reservoir Rock Red River LIMEdolom Source Rock Roughlock SHALEcalc Underburden Rock Icebox SHALEcarb Underburden Rock Black Island SANDshaly Underburden Rock Deadwood LIMEsandy Underburden Rock TD Basement Underburden Rock

Table 4.11. Lithology and petroleum system elements in the Williston Basin by formation name. 55

4.7 MODELS CALIBRATION

The models calibration was made using source rock thermal maturity values (Table 4.12), vitrinite reflectance (%Ro), published by different authors: Wesbter (1984) and Dembicki and Pirkle (1985). Both investigations published vitrinite reflectance maps for the Bakken

Formation and those values were georeferenced by the author of this research, and given for different depths to the formation mentioned before (Figures 4.5 and 4.6). After the compilation of vitrinite reflectance in each well for the Bakken Formation, all wells were calibrated using PetroMod (Tables 4.7, 4.8, 4.9, 4.10, 4.11, 4.12, and 4.13). Every well was calibrated using 2 different vitrinite reflectance values or models, except for wells 6 and 7.

Well N° Formation Depth (ft) % Ro (Webster, 1984) % Ro (Dembicki and Pirkle, 1985) 1 Upper Bakken 6374 0.54 0.68 2 Upper Bakken 7240 0.7 0.8 3 Upper Bakken 7398 0.78 0.9 4 Upper Bakken 7988 0.85 0.87 5 Upper Bakken 10608 0.65 0.6 6 Upper Bakken 9423 0.41 0.6 Table 4.12. Vitrinite reflectance values and depths used for models calibration with values taken from Webster (1984) and Dembicki and Pirkle (1985).

Dembicki and Pirkle (1985) Pirkle and Dembicki

Bakken Formation vitrinite reflectance map used after 1 model used map for Formation calibration Bakken vitrinite reflectance

. Figure 4.5 Figure

Bakken Formation vitrinite reflectance map used for model 2 calibration after Webster Webster after 2 model used map (1984) for Formation calibration Bakken vitrinite reflectance

4.6 re

Figu

Figure 4.7. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 1.

Figure 4.8. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 2.

Figure 4.9. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 3.

Figure 4.10. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 4.

Figure 4.11. Models calibration using Bakken Formation vitrinite reflectance (%Ro) for well 5.

Figure 4.12. Model calibration using Bakken Formation vitrinite reflectance (%Ro) for well 6.

Figure 4.13. Model calibration using Bakken Formation vitrinite reflectance (%Ro) for well 7.

4.8 SYN-RIFT PHASE

Olajide and Bend (2012) suggested that a minor rift phase occurred between 550-460 Ma

(Figure 4.14). Major rifting structures are absent in the basin, so this rifting period is considered an assumption (Nelson et al., 1993; Anna et al., 2010(a))

Olajide and Bend (2012) Bend and Olajide

rift phase by Olajide and Bend (2012). Figure taken from (2012). Figure and phase Bend Olajide by rift

Syn

Figure 4.14. Figure

4.9 BETA STRETCHING FACTOR

The acceptable stretching factors for cratonic basins (Figure 4.14) vary between 1.1 and

1.5 according to previous studies (Xie and Heller, 2009; Armitage and Allen, 2010). In this research, the stretching factor values were between 1.15 and 1.3.

Figure 4.15. Stretching factors for different types of basin (taken from Armitage and Allen, 2010).

4.10 PALEOWATER DEPTHS

The paleowater depth values (Table 4.13) were primarily taken from Haq (et al., 1987) and Haq and Schutter (2008), but following the Laramide Orogeny (80-50 Ma), which is supposed to have affected the Williston Basin, paleowater depth values were set at 0

64 meters, in accordance with basin modeling studies at the nearby Western Canada

Sedimentary Basin in Alberta, Canada (Berbesi et al., 2012).

Age (Ma) PWD (ft) Age (Ma) PWD (ft) Age (Ma) PWD (ft) Age (Ma) PWD (ft) 0 0 150 394 300 295 450 689 5 0 155 262 305 262 455 755 10 0 160 197 310 164 460 755 15 0 165 328 315 33 465 591 20 0 170 262 320 66 470 591 25 0 175 131 325 131 475 623 30 0 180 180 330 164 480 623 35 0 185 131 335 230 485 591 40 0 190 131 340 295 490 525 45 0 195 115 345 361 495 459 50 0 200 0 350 394 500 427 55 0 205 -16 355 361 505 394 60 0 210 -16 360 361 510 361 65 0 215 82 365 394 515 295 70 0 220 230 370 459 520 230 75 0 225 246 375 492 525 180 80 0 230 197 380 591 530 164 85 755 235 115 385 623 535 131 90 804 240 98 390 591 540 115 95 787 245 49 395 525 545 98 100 722 250 -82 400 459 550 66 105 558 255 -33 405 459

110 541 260 -16 410 525

115 591 265 131 415 558

120 427 270 164 420 623

125 328 275 164 425 689

130 476 280 164 430 656

135 476 285 164 435 656

140 558 290 164 440 525

145 459 295 197 445 525 Table 4.13. Paleowater depths taken from Haq (et al., 1987) and Haq and Schutter (2008) and the assumption of 0 m PWD after the Laramide Orogeny (80-50 Ma).

CHAPTER 5. RESULTS

The purpose of this study was to perform a basin analysis of the Williston Basin. The compilation of stratigraphic, geochemical, tectonic, and geological data from the basin, the basin modeling analysis was done in order to study the tectonic evolution of the basin, the petroleum system, and general information of hydrocarbon production in cratonic basins.

Subsidence curves give an idea about the evolution of the basin through time, and although cratonic basins are known for slow and long subsidence periods, it is important to evaluate them to understand major tectonic events through geologic time.

After the model calibration using vitrinite reflectance for different wells across the basin, heat flows values were used in order to understand temperatures in the basin, source rock maturity, and hydrocarbon generation. Knowing the heat flow values in different parts of the basin is important for predicting possible hydrocarbon reservoirs, as well as transformation ratios of source rock, vitrinite reflectance evolution through time, and oil generation prediction. These parameters were evaluated using 1D models in the different wells in the study.

In addition, in this study 2D models were constructed using stratigraphic information from different wells and geochemical information. These models give an idea of possible traps and reservoirs and hydrocarbon generation through geological time.

5.1 SUBSIDENCE CURVES

Subsidence curves are similar for the two different models because they depend primarily in the stretching factor used and the stratigraphic configuration, and these parameters were the same for each well and model. Uplift periods observed in the subsidence curves represent the erosion events that occurred in the Williston Basin for some geologic time intervals.

In all subsidence curves for the different wells, long and slow subsidence periods are observed, that reflect an almost 5000 foot-subsidence (1524 m) in a 500 Ma time interval

(Figure 5.1). Analyzing the subsidence curves in more detail reveals estimated tectonic subsidence at the maximum burial time during the Upper Cretaceous. In well 1 an estimate tectonic subsidence of approximately 4250 ft (1295 m) is found; in well 2, a tectonic subsidence value of about 4500 ft (1372 m) is found; and at well 3, an estimated

4750 ft (1448 m) of tectonic subsidence was calculated (Figure 5.1).

In well 4, a larger tectonic subsidence of approximately 5250 ft (1600 m) is found; in well 5, tectonic subsidence decreases to a value of about 4500 ft (1372 m); and at well 6, the estimated tectonic subsidence is approximately 5000 ft (1524 m) (Figure 5.2).

Most of the analyzed wells show the same pattern of long and slow subsidence, except for wells 3, 4, and 5 in some periods of time (Figures 5.1 and 5.2). The area where these wells are located experienced rapid subsidence in the Carboniferous at the end of

Mississippian, which can be addressed to a possible faulted zone.

A comparison of well 7 and well 5 that are both part of the E-W cross section, shows that in well 7 the tectonic subsidence is about 4000 ft (1219 m), and in well 5, the tectonic subsidence is approximately 4500 ft (1372 m) according to the generated models.

Figure 5.1. Subsidence curves for Wells 1-2-3 in the N-S cross section.

Figure 5.2. Subsidence curves for Wells 4-5-6 in the N-S cross section.

Figure 5.3. Subsidence curves for Wells 7-5 in the E-W cross section.

From a geographic point of view the largest subsidence values are observed toward the center of the basin in North Dakota, and with minor subsidence values toward the edges

(Figure 5.4).

Tectonic subsidence of the Williston Dakota in subsidence the of Tectonic North Basin

. Figure 5.4 Figure

5.2 HEAT FLOW

In model 1, well 1 during the rift phase the heat values fluctuated between 58.75 and

60.22 mW/m2, and post-rift heat flow values started to decrease to an almost constant

56.18 mW/m2 (Figure 5.5). On the other hand, in model 2 at well 1 in the rift phase the heat flow values were in a range between 43.85 and 45.10 mW/m2, and post-rift heat flow values started to decrease to an barely constant 41.91 mW/m2.

Figure 5.5. Heat flow curves for Well 1 in the N-S cross section for both calibrated models.

In model 1, well 2, during the rift phase the heat values were between 64.64 and 65.96 mW/m2, and after rifting, heat flow decreased to an approximated constant value of 62.17 mW/m2 (Figure 5.6). However, in model 2 for the same well, while during the syn-rift phase the heat flow values fluctuated between 56.16 and 57.71 mW/m2, and post-rift heat flow values started to decrease to an almost constant 53.54 mW/m2.

Figure 5.6. Heat flow curves for Well 2 in the N-S cross section for both calibrated models.

In model 1 at well 3, during the rift phase the heat values were in a range between 67.53 and 68.86 mW/m2, and after the rifting period, heat flow started decreasing to a constant value of about 65.14mW/m2 (Figure 5.7). Comparing model 2 with model 1, in model 2 during the rift phase, the heat flow values oscillated between 60.85 and 62.27 mW/m2, and post-rift heat flow values started to decrease to an almost constant 58.32 mW/m2.

Figure 5.7. Heat flow curves for Well 3 in the N-S cross section for both calibrated models.

In well 4 for model 1, during the syn-rift phase the heat values oscillated between 64.33 and 65.71 mW/m2, and after rifting, heat flow started decreasing to an approximately constant value of 61.86mW/m2 (Figure 5.8). In model 2 the values were very similar, during the rift phase, the heat flow values were between 62.89 and 64.25 mW/m2, and post-rift heat flow values started to decrease to an almost constant 60.39 mW/m2.

Figure 5.8. Heat flow curves for Well 4 in the N-S cross section for both calibrated models.

In well 5 for model 1, during the rift phase the heat values were between 44.19 and 46.05 mW/m2, and after rifting, heat flow started to decrease to an approximated value of 41.40 mW/m2. The results in model 2 were different, where in the rift phase the heat values fluctuated between 49.17 and 50.92 mW/m2, and post-rift heat flow started to decrease to an approximate constant value of 46.42mW/m2.

Figure 5.9. Heat flow curves for Well 5 in the N-S cross section for both calibrated models.

In the case of model 1 for well 6, during the rift phase the heat values were between

47.17 and 48.06 mW/m2, and after rifting, heat flow decreased to an approximately constant value of 44.37 mW/m2 (Figure 5.10).

Figure 5.10. Heat flow curves for Well 6 in the N-S cross section.

In well 7, model 1 showed during the rift phase heat values fluctuating between 68.06 and 69.36 mW/m2, and post-rift heat flow values started to decrease to an almost constant

56.18 mW/m2 (Figure 5.11).

Figure 5.11. Heat flow curves for Well 7 in the E-W cross section.

Almost the same results are observed in the 2 generated models, however in model 2 the lower heat flow values are seen in the northern and southern parts of North Dakota, and the higher values are concentrated toward the center of the basin (Table 5.1).

Well N° Model 1 Heat Flow Model 2 Heat Flow (mW/m2) Difference in Heat Flow (mW/m2) between models (mW/m2) 1 56.18 41.91 14.27 2 62.17 53.54 8.63 3 65.14 58.32 6.82 4 61.86 60.39 1.47 5 41.40 46.42 5.02 6 44.37 NA NA 7 56.18 NA NA

Table 5.1. Present-day heat flow for the 2 generated models in all studied wells.

Analyzing the results in a geographic perspective, the higher heat flow values are concentrated in the northern and western part of the Williston Basin in North Dakota, and the lower values are observed in the southern section in the same area (Figures 5.12 and

5.13).

Figure 5.12. Present-day heat flow map after calibrating the model 1 using Dembicki and Pirkle (1985) Vitrinite reflectance.

Figure 5.13. Present-day heat flow map after calibrating the model 1 using Webster (1984) Vitrinite reflectance.

5.3 BURIAL PLOTS

5.3.1 N-S CROSS SECTION

In well 1, temperatures reached a maximum temperature of about 100-150 °C for model

1, and close to 100 °C for model 2, and this can be observed during the maximum burial period that occurred approximately at 80 Ma in the Upper Cretaceous before the beginning of the Laramide Orogeny. During this event the basin started to cool down because of the crust uplift (Figure 5.14).

Figure 5.14. Temperature burial plots for Well 1 in the N-S cross section for both calibrated models.

Most transformation ratios for source rocks at well 1 are very small, except for the Red

River Formation. This formation showed a ratio of approximately 50% in model 1 during the Upper Cretaceous until the present-day (Figure 5.15).

Figure 5.15. Transformation ratio burial plots for Well 1 in the N-S cross section for both calibrated models.

Compared to well 1, the temperature at well 2 was higher for both tested models. In model 1, the temperature reached a maximum of about 150 °C during the Upper

Cretaceous, and in model 2 the temperature was close to 100 °C, and during the

Paleogene the basin started to decrease in temperature as a result of the crust uplift

(Figure 5.16).

Figure 5.16. Temperature burial plots for Well 2 in the N-S cross section for both calibrated models. 84

In well 2, transformation ratios for source rocks were higher than those in well 1. The highest transformation ratios were observed in the deeper source rocks varying from 50 in the shallower source rocks to almost 100 % in the deeper source rocks (Figure 5.17).

Figure 5.17. Transformation ratio burial plots for Well 2 in the N-S cross section for both calibrated models.

In the case of well 3, maximum temperatures were reached during the maximum burial period at the end of the Upper Cretaceous with temperatures close to 200 °C in model 1, and 150 °C in model 2 (Figure 5.18).

Figure 5.18. Temperature burial plots for Well 3 in the N-S cross section for both calibrated models.

In well 3, it can clearly be seen that the Red River Formation starting converting kerogen into hydrocarbons earlier than other source rocks, which according to the models occurred as earlier as the Permian. In general, transformation ratios for all source rocks were between 50 and 75% approximately (Figure 5.19).

Figure 5.19. Transformation ratio burial plots for Well 3 in the N-S cross section for both calibrated models.

In well 4, temperatures for both tested models are very similar to each other.

Temperatures reached an approximate of 170 °C according to the models. Again the maximum temperatures were observed during the Upper Cretaceous at the maximum burial period of the basin, which is found in all tested models (Figure 5.20).

Figure 5.20. Temperature burial plots for Well 4 in the N-S cross section for both calibrated models.

The transformation ratios in well 4 for all source rocks were very similar to the ones found in well 3. The values varied between 50 to 100% from the shallower to the deeper source rock respectively (Figure 5.21).

Figure 5.21. Transformation ratio burial plots for Well 4 in the N-S cross section for both calibrated models.

In well 5, temperatures were lower than in well 4. Temperatures are very constant (with values between 50 to 100 °C) through geological time with a slight increase during the maximum burial stage and deeper parts of the section (Figure 5.22).

Figure 5.22. Temperature burial plots for Well 5 in the N-S cross section for both calibrated models.

In well 5, transformation ratios decreased dramatically compared to well 4. Heat flows and temperatures decreased systematically when going south through the section. Only in model 2 the Red River Formation source rock shows a transformation ratio close to approximately 30% (Figure 5.23).

Figure 5.23. Transformation ratio burial plots for Well 5 in the N-S cross section for both calibrated models.

In well 6, results are similar to the obtained in well 5. Temperatures reached to about 100

°C in the deeper parts of the section, and during the maximum burial period during the

Upper Cretaceous temperature did not increase considerably. In well 6, only one model was tested due to the absence of vitrinite reflectance data in other studies (Figure 5.24).

Figure 5.24. Temperature burial plots for Well 6 in the N-S cross section.

As it was explained in the temperature burial plot for well 6, temperatures in the model are very low, and as a consequence transformation ratios for kerogen in source rocks are expected to be low. Only at the Red River Formation transformation ratio was predicted that probably reaches 10-20% during the Upper Cretaceous (Figure 5.25).

Figure 5.25. Transformation ratio burial plots for Well 6 in the N-S cross section.

5.3.2 E-W CROSS SECTION

Well 7 is part of the East-West cross section used in this study. As it was explained and seen in the previous temperature burial plots, the maximum temperatures were observed at the end of the Cretaceous, and in well 7 specifically maximum temperatures were close to 150 °C according to the models (Figure 5.26).

Transformation ratios for almost all source rocks in well 7 were very high. The values observed were between 50-80% from shallower to deeper formations, and in a period of time that covers from the Upper Cretaceous to the present-day (Figure 5.27).

Figure 5.26. Temperature burial plots for Well 7 in the E-W cross section.

Figure 5.27. Transformation ratio burial plots for Well 7 in the E-W cross section.

Temperatures in well 8 were very similar to the ones observed in well 7, where maximum temperature values were approximately 150 °C during the maximum burial period at the end of the Cretaceous (Figure 5.28). Well 8 is part of a 1D extraction (synthetic well) from the E-W 2D model because of the lack of stratigraphic information from the well.

Figure 5.28. Temperature burial plots for Well 8 in the E-W cross section.

Transformation ratios in well 8 can be considered as good. Values vary from 50 to 75% approximately for most of the source rocks, where the deeper rocks have the higher values (Figure 5.29).

Figure 5.29. Transformation ratio burial plots for Well 8 in the E-W cross section.

Also well 9 is part of a 1D extraction from the E-W 2D. The results for the temperature burial plot showed maximum temperatures at end of the Cretaceous with values close to

150 °C (Figure 5.30).

Transformation ratios in well 9 are basically the same as observed in well 8, where values varied from 50 to 75% approximately for most of the source rocks, where the deeper rocks have the higher values (Figure 5.31).

Figure 5.30. Temperature burial plots for Well 9 in the E-W cross section.

Figure 5.31. Transformation ratio burial plots for Well 9 in the E-W cross section.

5.4 VITRINITE REFLECTANCE

5.4.1 N-S CROSS SECTION

The Tyler Formation vitrinite reflectance remained almost constant at 0.35 from the

Permian to the Upper Cretaceous, where maturation values were close to 0.7 in model 1, and 0.6 in model 2 (Figure 5.32).

Figure 5.32. Vitrinite reflectance evolution through geological time for the Tyler Formation in all wells from the N-S cross section, and both calibrated models.

The first maturation peak occurred for the Lodgepole Formation during the

Carboniferous, where it started to slowly maturate until the Upper Cretaceous when the major peak maturation was reached with values of 0.8 for model 1 in wells 3 and 4, and

0.7 for model 2 (Figure 5.33).

Figure 5.33. Vitrinite reflectance evolution through geological time for the Lodgepole Formation in all wells from the N-S cross section, and both calibrated models.

Maturation started in the Upper Bakken after the Mississippian, and started slowly increasing until the Upper Cretaceous when the maximum maturation stage occurred in wells 3 and 4 with values close to 0.85. In other wells, the Upper Bakken Formation is more immature with values lower than 0.6 in some cases (Figure 5.34).

Figure 5.34. Vitrinite reflectance evolution through geological time for the Upper Bakken Formation in all wells from the N-S cross section, and both calibrated models.

100

The maturation behavior of the Lower Bakken is very similar to the Upper Bakken. This source rock started slowly maturating from the Mississippian reaching its peak maturation during the Upper Cretaceous with approximated values of 0.8 at wells 3 and 4 in model 1, and 0.6 and 0.75 for model 2. As it was mentioned for other source rocks, the maturation is lower in the other studied wells (Figure 5.35).

Figure 5.35. Vitrinite reflectance evolution through geological time for the Lower Bakken Formation in all wells from the N-S cross section, and both calibrated models.

101

The pattern followed by most of the source rocks in the Williston Basin is that they started slowly maturating during the Carboniferous until they obtained their peak maturation in the Upper Cretaceous. The Duperow Formation follows exactly that same pattern, and during the Upper Cretaceous had vitrinite reflectance values of approximately 0.9 for model 1 in wells 3 and 4, and between 0.7 and 0.8 for the same wells in model 2 (Figure 5.36).

Figure 5.36. Vitrinite reflectance evolution through geological time for the Duperow Formation in all wells from the N-S cross section, and both calibrated models.

102

Even though the Winnipegosis Formation is one of the deepest source rocks in the

Williston Basin, the vitrinite reflectance values were not that high until the Upper

Cretaceous, when values increased dramatically from 0.7 to 1.0 in both models (Figure

5.37).

Figure 5.37. Vitrinite reflectance evolution through geological time for the Winnipegosis Formation in all wells from the N-S cross section, and both calibrated models.

103

The Red River Formation is the more mature source rock in this study. It started its maturation during the Carboniferous like the other studied source rocks, and reached vitrinite reflectance values higher than 1 in wells 3 and 4 for both models during the

Upper Cretaceous (Figure 5.38).

Figure 5.38. Vitrinite reflectance evolution through geological time for the Red River Formation in all wells from the N-S cross section, and both calibrated models.

104

5.4. 2 E-W CROSS SECTION WELLS

Vitrinite reflectance values observed in the Tyler Formation are mainly constant at approximately 0.3 until the Upper Cretaceous when they increase in magnitude to about

0.65, with these higher values observed in wells 7 and 8 (Figure 5.39).

Figure 5.39. Vitrinite reflectance evolution through geological time for the Tyler Formation in all wells from the E-W cross section.

105

In the Lodgepole Formation, vitrinite reflectance values observed remained barely constant at approximately 0.45 until the Upper Cretaceous when maturity increases in magnitude to about 0.9, with these higher values observed in wells 7, 8, and 9 (Figure

5.40).

Figure 5.40. Vitrinite reflectance evolution through geological time for the Lodgepole Formation in all wells from the E-W cross section.

106

In the case of the Upper Bakken Formation, the vitrinite reflectance values observed remained almost constant at approximately 0.55 until the Upper Cretaceous when thermal maturity increases to an approximate value of about 0.9, with these higher values observed in wells 7, 8, and 9 (Figure 5.41).

Figure 5.41. Vitrinite reflectance evolution through geological time for the Upper Bakken Formation in all wells from the E-W cross section.

107

In the Lower Bakken Formation, the vitrinite reflectance values observed remained almost constant at approximately 0.55 until the Upper Cretaceous when thermal maturity increases to an approximate value of about 0.95, with these higher values observed in wells 7, 8, and 9. This pattern is almost exactly the observed in the Upper Bakken

Formation (Figure 5.42).

Figure 5.42. Vitrinite reflectance evolution through geological time for the Lower Bakken Formation in all wells from the E-W cross section.

108

The vitrinite reflectance values observed in the Duperow Formation are steady at an almost constant value of about 0.6 until the Upper Cretaceous when maturity in the source rock increases to an approximate value of about 1.05, with these higher values observed in wells 7, 8, and 9 (Figure 5.43).

Figure 5.43. Vitrinite reflectance evolution through geological time for the Duperow Formation in all wells from the E-W cross section.

109

In the Winnipegosis Formation, vitrinite reflectance values observed are almost a constant value of about 0.6 until the Upper Cretaceous when thermal maturity in the source rock increases to an approximate value of about 1.1, with these higher values observed in wells 7, 8, and 9. This pattern is very repetitive in most of the source rocks in this study (Figure 5.44).

Figure 5.44. Vitrinite reflectance evolution through geological time for the Winnipegosis Formation in all wells from the E-W cross section.

110

The vitrinite reflectance values observed in this study follow a pattern that shows values that are almost constant in the early stages after deposition of the source rock, and then in the Upper Cretaceous the thermal maturity of these rocks increases dramatically and could be considered in a maturation peak stage. In the case of the Red River Formation, a steady constant value of about 0.65 is found until the Upper Cretaceous when maturity in the source rock increases to an approximate value of about 1.3, with these higher values observed in wells 7, 8, and 9.

Figure 5.45. Vitrinite reflectance evolution through geological time for the Red River Formation in all wells from the E-W cross section.

111

5.5 TRANSFORMATION RATIO

5.5.1 N-S CROSS SECTION

Transformation ratio values for the Tyler Formation are very low. In model 1, it can be observed that only wells 3 and 4 show values between and 0.5 and 1%, and in model 2 the same wells have values in range of 0.1 to 0.3 % (Figure 5.46).

Figure 5.46. Transformation ratio evolution through geological time for the Tyler Formation in all wells from the N-S cross section, and both calibrated models. 112

Lodgepole Formation has acceptable transformation ratio values, and the higher values are observed in wells 2, 3, and 4 for both models, and are in range between 20 and 40%.

The peak transformation ratios started at the end of the Cretaceous for all wells (Figure

5.47).

Figure 5.47. Transformation ratio evolution through geological time for the Lodgepole Formation in all wells from the N-S cross section, and both calibrated models.

113

The Upper Bakken Formation has very similar values to the Lodgepole Formation in terms of kerogen transformation ratio. The higher values in a range between 25 and 50% in both models are observed in wells 2, 3, and 4, and the peak transformation started at the end of Upper Cretaceous (Figure 5.48).

Figure 5.48. Transformation ratio evolution through geological time for the Upper Bakken Formation in all wells from the N-S cross section, and both calibrated models. 114

The Lower Bakken Formation in this case shares basically the same transformation ratio values with the other shale member of the Bakken Formation, Upper Bakken. The peak generation started at the end of the Cretaceous, and values vary between 25 and 50% in wells 2, 3, and 4 for both models (Figure 5.49).

Figure 5.49. Transformation ratio evolution through geological time for the Lower Bakken Formation in all wells from the N-S cross section, and both calibrated models. 115

The Duperow Formation follows the same pattern of peak transformation at the end of the Cretaceous but shows different results between the two models. In model 1, transformation ratio values are in range between 40 to 60% for wells 2, 3, and 4, and in model 2, these values decreased to a range between 20 and 45% (Figure 5.50).

Figure 5.50. Transformation ratio evolution through geological time for the Duperow Formation in all wells from the N-S cross section, and both calibrated models. 116

The Winnipegosis Formation differs from the shallower source rocks. This source rock reaches at the end of the Cretaceous transformation ratio values of 90% in wells 3 and 4 in model 1, and above 50% in well 4 in model 2. The history is different for the other wells, where values are below 50% (Figure 5.51).

Figure 5.51. Transformation ratio evolution through geological time for the Winnipegosis Formation in all wells from the N-S cross section, and both calibrated models.

117

The transformation ratio values vary in the Red River Formation in different wells and through geologic times. During the Permian or probably as early as the Pennsylvanian, an important kerogen transformation occurred in wells 3 and 4, reaching almost the maximum transformation at the Middle Upper Cretaceous. In the other wells, the values are lower than 50% in the Red River Formation (Figure 5.52).

Figure 5.52. Transformation ratio evolution through geological time for the Red River Formation in all wells from the N-S cross section, and both calibrated models.

118

5.5.2 E-W CROSS SECTION

The Tyler Formation has very poor transformation ratios. Kerogen started transforming to hydrocarbons in the Upper Cretaceous, and the higher values are observed in wells 8 and

9 with values between 15 and 20% (Figure 5.53).

Figure 5.53. Transformation ratio evolution through geological time for the Tyler Formation in all wells from the E-W cross section.

The Lodgepole Formation has good transformation ratio values. Kerogen started conversion to hydrocarbons in the Upper Cretaceous, and the higher values are observed in well 7, 8 and 9 with values between 30 to 50% (Figure 5.54).

119

Figure 5.54. Transformation ratio evolution through geological time for the Lodgepole Formation in all wells from the E-W cross section.

Similar to the Lodgepole Formation, the Upper Bakken Formation shows very good transformation ratios. Kerogen started converting into hydrocarbons during the Upper

Cretaceous, and the higher values are observed in wells 8 and 9 with values between 30 and 60% (Figure 5.55).

120

Figure 5.55. Transformation ratio evolution through geological time for the Upper Bakken Formation in all wells from the E-W cross section.

Also the Lower Bakken Formation shows acceptable transformation ratio values.

Kerogen was converted into hydrocarbons during the Upper Cretaceous, and the higher values are observed in wells 8 and 9 with values between 35 and 60% (Figure 5.56).

121

Figure 5.56. Transformation ratio evolution through geological time for the Lower Bakken Formation in all wells from the E-W cross section.

The Duperow Formation is one of the deepest source rocks in this study, and it shows very good transformation ratio values. Kerogen conversion into hydrocarbons started during the Upper Cretaceous, and the higher values are observed in wells 7, 8, and 9 with values as high as 70% (Figure 5.57).

122

Figure 5.57. Transformation ratio evolution through geological time for the Duperow Formation in all wells from the E-W cross section.

Also the Winnipegosis Formation shows good transformation ratio values. Kerogen started converting into hydrocarbons during the Upper Cretaceous, and the higher values are observed in wells 7, 8, and 9 with values in a range between 50 and 75% (Figure

5.58).

123

Figure 5.58. Transformation ratio evolution through geological time for the Winnipegosis Formation in all wells from the E-W cross section.

The Red River Formation shows the highest transformation ratios of all studied source rocks. Kerogen started converting into hydrocarbons during the Upper Cretaceous, and the higher values are observed in wells 7, 8, and 9 with values as high as 90% in well 7

(Figure 5.59).

124

Figure 5.59. Transformation ratio evolution through geological time for the Red River Formation in all wells from the E-W cross section.

125

5.6 GENERATION MASS

5.6.1 N-S CROSS SECTION

Generation mass for the Tyler Formation is very low, as in all wells from the N-S cross section (Figure 5.60). Only in well 3, the values are somewhat higher. The generation mass predicted by model 1 are higher than those predicted in model 2. These values are related to the poor organic enrichment of this source rock. The peak generation occurred at the end of the Upper Cretaceous (Figure 5.60).

Figure 5.60. Generation mass of the Tyler Formation in all wells from the N-S cross section, and both calibrated models.

126

The Lodgepole Formation has a higher hydrocarbon generation than the Tyler Formation.

In well 3, the maximum generation predicted by the models, with values approximated 5

Mtons in model 1, and 3 Mtons for model 2, where the peak generation is observed at the end of Cretaceous (Figure 5.61).

Figure 5.61. Generation mass of the Lodgepole Formation in all wells from the N-S cross section, and both calibrated models.

127

The generation of the Upper Bakken Formation is totally related to the layer thickness, which is very thin. The peak generation is observed in both models at end of the

Cretaceous, with higher values for wells 3 and 4 (Figure 5.62).

Figure 5.62. Generation mass of the Upper Bakken Formation in all wells from the N-S cross section, and both calibrated models.

128

Compared to the Upper Bakken, the Lower Bakken Formation has a higher hydrocarbon generation potential because it is thicker. The values obtained in the Lower Bakken triple the values for generation in the Upper Bakken according to the models. The maximum generation started at the Upper Cretaceous, and wells 3 and 4 had the higher generation mass values (Figure 5.63).

Figure 5.63. Generation mass of the Lower Bakken Formation in all wells from the N-S cross section, and both calibrated models.

129

The Duperow Formation had its peak generation at the Upper Cretaceous, with approximated values of 2 Mtons for model 1, and 1.3 Mtons for model 2. The maximum generation potential for this source rock was observed in wells 2 and 3 (Figure 5.64).

Figure 5.64. Generation mass of the Duperow Formation in all wells from the N-S cross section, and both calibrated models.

130

In all source rocks analyzed in this study, where the peak generation starts at the Upper

Creteceous, and Winnipegosis follows the same pattern. The organic enrichment of the

Winnipegosis Formation is very poor, which explains the low values observed in terms of generation. Higher values are part of well 2 and 3 (Figure 5.65).

Figure 5.65. Generation mass of the Winnipegosis Formation in all wells from the N-S cross section, and both calibrated models.

131

Finally, the Red River Formation showed very interesting results. The generation in well

3 is different from the other wells, and a considerable generation started at the

Pennsylvanian. The peak generation at the end of the Cretaceous similar to the other wells (Figure 5.66).

Figure 5.66. Generation mass of the Red River Formation in all wells from the N-S cross section, and both calibrated models.

132

5.6.1 E-W CROSS SECTION WELLS

The Tyler Formation is absent in well 7. The primary generation for this source rock started during the Upper Cretaceous, and the peak generation began during the Oligocene and continued until the present-day. The higher values in terms of generation were observed in wells 8 and 9 (Figure 5.67).

Figure 5.67. Generation mass of the Tyler Formation in all wells from the E-W cross section.

In the Lodgepole Formation hydrocarbon generation began during the Upper Cretaceous, and the peak generation began during the Oligocene continuing until the present-day. The

133 higher values in terms of generation were found in wells 8 and 9, but also well 7 showed a significant amount of generated hydrocarbons (Figure 5.68).

Figure 5.68. Generation mass of the Lodgepole Formation in all wells from the E-W cross section.

The Upper Bakken Formation started generating hydrocarbons during the Upper

Cretaceous, and the peak generation began during the Eocene, continuing until the present-day. The higher generation values were observed in wells 8 and 9.

134

Figure 5.69. Generation mass of the Upper Bakken Formation in all wells from the E-W cross section.

In the Lower Bakken Formation hydrocarbon generation started in the Upper Cretaceous, and the peak generation began during the Oligocene continuing until the present-day.

Higher generation values were found in well 9, and minor generation in wells 7 and 5

(Figure 5.70).

135

Figure 5.70. Generation mass of the Lower Bakken Formation in all wells from the E-W cross section.

In the Duperow Formation, the primary generation started during the Upper Cretaceous, and also its peak generation occurred during that same period of time. The higher values in terms of generation were observed in wells 7 and 8 and with minor generation in well

7 (Figure 5.71).

136

Figure 5.71. Generation mass of the Duperow Formation in all wells from the E-W cross section.

The Winnipegosis Formation main generation stage started during the Upper Cretaceous.

The higher values in terms of generation were observed in wells 8 and 9, and well 7 showed a minor amount of generated hydrocarbons (Figure 5.72).

137

Figure 5.72. Generation mass of the Winnipegosis Formation in all wells from the E-W cross section.

The Red River Formation primary generation started during the Upper Cretaceous, and the higher values in terms of generation were observed in wells 8 and 9 (Figure 5.73).

The amount of hydrocarbons generated in this formation is larger in great magnitude than in the other source rocks in the basin due to its thickness and organic enrichment and burial.

138

Figure 5.73. Generation mass of the Red River Formation in all wells from the E-W cross section.

5.7 2D MODELING

5.7.1 NORTH-SOUTH (N-S) CROSS SECTION

In the N-S cross section, two models were tested using PetroMod, but both models were the same in terms of hydrocarbon generation (Figure 5.74). Although the heat flow values used were different in the two models, this difference was smaller than 20mW/m2 in the wells that were part of the study. In addition, the results provided by PetroMod were given in million barrels, which can mean that the results may be different in smaller amounts (Figure 5.75).

139

The hydrocarbon accumulation predicted by the models is lower in present days than in the past (Figures 5.75 and 5.76). This result might be related to the erosion events that occurred in the basin through geologic time, which may have caused the upward migration or loss of the generated hydrocarbons. The accumulations are seen to be trapped in structures that resemble anticlines or folded structures, although in some cases stratigraphic traps are observed too. According to the models, these reservoirs are in the

Kibbey, Amsden and Winnipegosis Formations (Figure 5.77).

Unfortunately, in this study the Bakken Formation could not be well studied in the 2D models because the formation is too thin. PetroMod predicts hydrocarbon saturations

(Figures 5.78, 5.79, and 5.80) in the Upper and Lower Bakken (members of the Bakken

Formation that are considered source rocks), but it does not show major hydrocarbon accumulations. In the Middle Bakken there are no visible hydrocarbon accumulations either. These results can be related to the thin thickness of these 3 members of the

Bakken Formation. However, in the 1D models, results can be more complete. In the 2D models, PetroMod uses elements to calculate generation and migration. These elements have a certain size that the user can define. If the elements are too large, PetroMod cannot perform calculations in the layer. A second point is the visualization with PetroMod, which has a limited resolution.

Using 2D models, the oil generation can be predicted using PetroMod vitrinite reflectance ranges from Sweeny and Burham (1990). The early oil window is placed at

140 approximately 3500 ft (1067 m) and the wet gads window at 11000 ft (3353 m) (Figure

5.81).

5.7.2 EAST-WEST (E-W) CROSS SECTION

In the E-W cross section (Figure 5.82), results were very similar to the N-S model.

However, for this case only one model was generated using the heat flow values obtained with the model 1 in the 1D models. In present days the hydrocarbon accumulations are lower than in the past, which could be related to the erosion events in the basin through time, and that hydrocarbon migrated in some other direction due to the tectonic evolution in the basin (Figures 5.83 and 5.84). Erosion events can be responsible of the loss of hydrocarbons by eroding traps, seals or possible reservoirs. The traps in this model appear to be anticlines or folded structures, and the reservoirs are the Kibbey, Amsden,

Winnipegosis, and Three Forks Formations (Figure 5.83). Also, in this model, the

Bakken Formation could not be well studied due to its thin thickness, and only very low hydrocarbon saturations are shown in their members (Figures 5.85, 5.86, and 5.87). The early oil window is placed at approximately 3200 ft (975 m) and the wet gads window at

10800 ft (3292 m) (Figure 5.88).

141

S cross section at 0 Ma and its stratigraphic layers. stratigraphic its and Ma 0 at section cross S

Figure 5.74. Figure

142

Winnipegosis Formation. Winnipegosis

S cross section at 0 Ma showing hydrocarbon hydrocarbon in showing Ma 0 section accumulations Sthe at cross

. Figure 5.75 Figure

143

Formations.

S cross section at 26.62 Ma showing hydrocarbon accumulations in the Kibbey and hydrocarbon showing Winnipegosis in Ma 26.62 section accumulations SKibbey the at cross

. Figure 5.76 Figure

144

Formations and the migration vectors after hydrocarbon generation. hydrocarbon after migration the and vectors Formations

S cross section at 73.62 Ma showing hydrocarbon accumulations in the Kibbey and hydrocarbon showing Winnipegosis in Ma 73.62 section accumulations SKibbey the at cross

5.77 Figure Figure

145

ss section ss

Scro

in the N the in

Hydrocarbon saturation of the Upper Bakken Ma 0 Upper the Formationat of Bakken Hydrocarbonsaturation

. Figure 5.78 Figure

146

Ssection cross

in the N the in

Hydrocarbon saturation of the Middle Bakken Formation at 0 0 at Bakken Ma Middle the Formation of Hydrocarbonsaturation

. Figure 5.79 Figure

147

cross section cross

in the N the in

Hydrocarbon saturation of the Lower Bakken Ma 0 Formationat the of Bakken Lower Hydrocarbonsaturation

. Figure 5.80 Figure

148

Burham (1990). Burham

S cross section hydrocarbon generation zones from the Vitrinite Reflectance model of Sweeny and and model Sweeny of Vitrinite the Reflectance section Szones from hydrocarbon cross generation

. Figure 5.81 Figure

149

W cross section at 0 Ma and its layers. stratigraphic Wand Ma 0 section at cross

. Figure 5.82 Figure

150

Winnipegosis Formations. Winnipegosis

W cross section at 0 Ma showing hydrocarbon accumulations Kibbey, Three Forks and Forks Three Kibbey, accumulations hydrocarbon showing Ma 0 at section Wcross

. Figure 5.83 Figure

151

rbon rbon generation.

migration vectors hydroca after migration

W cross section at 26.62 Ma showing hydrocarbon accumulations in the Kibbey Formation and the the and Formation Kibbey the in accumulations hydrocarbon showing Ma 26.62 at section Wcross

. Figure 5.84 Figure

152

W cross section hydrocarbon saturation of the Upper Bakken Formation at 0 Ma. 0 at BakkensaturationUpper the Formation W section of hydrocarbon cross

. Figure 5.85 Figure

153

W cross section hydrocarbon saturation of the Middle Bakken Formation at 0 Ma. 0 at Formation Bakken saturationMiddle the W section of hydrocarbon cross

. Figure 5.86 Figure

154

Lower Bakken Formation at 0 Ma. 0 at BakkenFormation Lower

W cross section hydrocarbon saturation the W section of hydrocarbon cross

. Figure 5.87 Figure

155

Sweeny and Burham and (1990)Burham Sweeny

cross section hydrocarbon generation zones from the Vitrinite Reflectance model model of Reflectance Vitrinite the from zones generation hydrocarbon section cross

. Figure 5.88 Figure

156

CHAPTER 6. DISCUSSION

The models predicted results that can lead to the understanding of tectonic events that affected the basin, heat flow values in the North Dakota area in the basin, or hydrocarbon generation and entrapment, among other aspects.

6.1 LARAMIDE OROGENY

The models predict that the Laramide Orogeny played an important role in the basin evolution. In the models, temperature decreased in the basin due to uplift of the crust, and many traps (such as the Nesson anticline) were formed by the Laramide compressive forces. This tectonic episode is thus suggested to be the main event for basin deformation, responsible for the creation of many traps (e.g. anticlines) for hydrocarbon reservoirs.

This finding is in agreement with previous studies that suggested that the Laramide

Orogeny played an important role in the structural configuration of the basin (e.g.

Gaswirth et al., 2010; Anna et al. 2010(a); Anna et al., 2010(b)). Preceding the Laramide

Orogeny, parameters such as the transformation ratio, vitrinite reflectance, and generation mass underwent a phase of rapid increase. This rapid increase came to a halt when the basin uplifted as a result of the orogeny. The Laramide Orogeny in the Williston Basin thus formed many of the traps, and affected the petroleum system.

157

6.2 SUBSIDENCE

The tectonic subsidence curves clearly show the long and slow subsidence pattern in the

Williston Basin, which is typical for cratonic basins according to previous studies (e.g.

Xie and Heller, 2009; Armitage and Allen, 2010). Although the subsidence pattern is very slow and long, it is also continuous. Some minor more rapid subsidence episodes, as well as phases of uplift, are present in the subsidence curves. The most prominent phase of rapid subsidence is the period just preceding the Laramide Orogeny, when about 1500 ft (457 m) of subsidence occurs in about 40 m.y. This period corresponds to a rapid increase in transformation ratio and vitrinite reflectance. Xie and Heller (2009) published tectonic subsidence curves in the Williston Basin from Bond and Kominz (1984), and

Fowler and Nisbet (1985) in North Dakota and Saskatchewan (Canada), respectively.

These curves show that tectonic subsidence is larger in North Dakota than in

Saskatchewan, which is in agreement with this study. The total tectonic subsidence in this study varies between 4500 and 5000 ft (1372 and 1524 m) approximately, which is larger than the tectonic subsidence found by Olajide and Bend (2012) of about 2600 ft (792 m).

After a detailed analysis of the subsidence curves there is no strong evidence of rifting in the Williston Basin in the North Dakota area in this study.

6.3 HEAT FLOW

Different studies have analyzed the heat flow values across the Williston Basin. Burrus et al. (1996) suggested that the heat flow values in the basin are about 65 mW/m2 nearby the

Nesson Anticline, and 55 mW/m2 in the other areas. Khun et al. (2012) suggests that the

158 heat flow values vary between 50 and 70 mW/m2. In this study, the heat flow values were found in the range between 41.91 and 65.14 mW/m2, and the higher values were obtained in the area where the basin thickens. Heat flow in the basin will vary depending on the study area. I speculate that the high heat flow values in the areas where the sedimentary package is thicker could be the result of a thick layer of heat-producing shales.

6.4 UPPER CRETACEOUS

The Upper Cretaceous period can be considered a critical moment in the basin. Peak hydrocarbon generation, peak source rock maturation, and peak kerogen transformation ratios occurred. At the end of Upper Cretaceous, there is a significant temperature increase in the deeper parts of the basin, which coincided with the maximum burial period in the basin. Also at the very end of the Upper Cretaceous, there is a basin uplift created by the Laramide Orogeny, which caused a temperature decrease and the equilibrium in hydrocarbon generation, source rock maturation and kerogen transformation ratios. Burrus et al. (1996) suggested that expulsion and migration occurred between the Late Cretaceous-Paleocene and no earlier than the Eocene in some source rocks in the Williston Basin, which coincides with the results found in this study.

The onset of hydrocarbon generation for the Bakken Formation in previous studies occurred during the maximum burial period or subsidence in the basin, which are similar to the results in this study (Khun et al., 2012).

159

6.5 HYDROCARBON GENERATION AND MIGRATION

The hydrocarbon generation predicted by this study is difficult to compare to earlier studies because it depends on the size of the study area, kinetics used, and model calibration. However, possible traps and reservoirs could be predicted. In this study, the main traps are the folded structures. The migration paths in the basin can be assessed by analyzing the 2D models, but the accuracy of the model results is dependent on lateral facies changes, compartmentalized reservoirs, or rocks/sediment compaction changes in the same formation, and they are not well constrained in the study area. These factors may change the migration trajectory. As it was mentioned before, kinetics of the source rocks used for modeling purposes is very sensitive at the time of volumetrics calculations.

A type II kerogen from different studies will result in very different results. Varying heat flow values in this study did not affect the hydrocarbon generation, which corresponds to

Flannery (2006) results, where thermal history or source richness had no influence in the hydrocarbon generation prediction. Unfortunately the wells used in this study are to the west of the Nesson anticline (Figure 6.1), so that migration in the anticline could not be studied.

160

rks the study area. The study area did not did area The study area. rksstudy the

include major traps in the traps major basin. include

The heat flow map for model 1 rema 1 model Thefor heat map flow

Figure 6.1. Figure

161

CHAPTER 7. CONCLUSIONS

A complete basin analysis in the North Dakota area of the Williston Basin was the main purpose of this study. I used Schlumberger’s software PetroMod to help obtain a better understanding of the tectonic evolution and hydrocarbon potential in the basin.

Tectonic subsidence curves give an idea of the tectonic evolution of sedimentary basins.

In the case of the Williston Basin, subsidence curves show what is typical of cratonic basins; a long and slow subsidence period interrupted by short phases of uplift. However, at wells that were at the center of the basin in North Dakota, there were rapid subsidence events which could be related to fault activity close to that area. The tectonic subsidence curves do not indicate a rift origin for the Williston Basin.

The models were calibrated with vitrinite reflectance data. After generating vitrinite reflectance maps and calibration, reliable heat flow values were obtained, and several hydrocarbon generation parameters were calculated.

For hydrocarbon generation purposes and reserves estimation it is important to know the kinetics of the source rock. Kerogen type sensitivity for modeling is very strong; kerogen type II models developed by different authors for different basins resulted in very different predictions. For example, Bakken Formation modeled using Berhar et al.

(1997), and Burham (1989), shows a transformation ratio difference of approximately

162

40%. For that reason, it is important to know the exact geochemical information of each source studied if the main goal is reserves estimation.

Heat flow in the Williston Basin was analyzed in two cross sections generated using well information from North Dakota. Heat flow increased toward the center of the basin in

North Dakota and, and decreased toward the edges. As it is common in cratonic basins, after rifting or heating periods, heat flow starts to decrease until it becomes practically constant.

The Laramide Orogeny, which occurred approximately between 80 to 50 Ma, apparently had an important role in the basin evolution. The beginning of this event, which generated uplift of the crust in the basin, marked the peak values for many parameters in the basin such as source rock maturity and hydrocarbon generation. It also marks the start of basin cooling caused by the uplift as it can be seen in the temperature burial plots.

Burial plots are very useful for basin evolution purposes. Temperature and transformation ratio of source rock burial plots were generated using Petromod. In the Williston Basin, temperature burial plots show the maximum burial period at the end of the Upper

Cretaceous, where temperature increases considerably, and after that event, uplift occurred in crust, which caused the decrease in temperature by denudation. In the case of the transformation ratio burial plots, they give an idea of the kerogen transformation for each source rock, and particularly for the Williston Basin. They show major kerogen

163 transformation ratios at deeper source rocks. One of the limitations of the transformation ratio burial plots is that because of scale problems, transformation ratio values of thin source rocks like the Bakken Formation are difficult to calculate.

The end of the Upper Cretaceous can be considered as the critical period for main geologic events to occur. Analysis of the vitrinite reflectance, generation mass and transformation ratio time plots can support this statement. These time plots were generated for each source rock in the study. Vitrinite reflectance time plots give an idea of the maturation through time for in every rock. This parameter is used to assess the oil and gas window for a specific source rock. In the case of the Williston Basin, maturation of source is mainly until the Upper Cretaceous when the peak maturation occurred in every source in the basin. The higher vitrinite reflectance values were observed in the deeper source rocks. Transformation ratio time plots also have a pattern similar to the vitrinite reflectance plots. The kerogen transformation ratio in the different source rocks increased dramatically at the end of the Upper Cretaceous. Similar results were found in the generation mass time plots. The peak hydrocarbon generation of the source rocks occurred also at the end of the Cretaceous. The major hydrocarbon generation amount depended primarily on the source rock thickness and its organic enrichment.

Two models were generated and studied in the 2 different cross sections, one North-

South (209 km length) and one E-W (95 km length). Even though different heat flows were generated from the two generated models, the hydrocarbon generation was

164 apparently not affected. However, the heat flow difference was 15 mW/m2 in well 1 of the N-S cross section, and the difference between the other 5 wells was in the range of 1-

5 mW/m2. Different kinetic models had a much larger effect on the results.

165

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