Depositional Environment and Reservoir Characterization of the Paleocene Fort Union Formation, Washakie Basin, Southwest Wyoming, U.S.A

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DEPOSITIONAL ENVIRONMENT AND RESERVOIR CHARACTERIZATION OF THE PALEOCENE FORT UNION FORMATION, WASHAKIE BASIN, SOUTHWEST WYOMING, U.S.A.

Matthew John Bircher

A thesis submitted to the Faculty and Board of Trustees of the Colorado School of Mines in partial fulfillment of the requirements for the degree of Master of Science (Geology).

Golden, Colorado

Date ______

Signed: ______Matthew J. Bircher

Signed: ______Dr. John B. Curtis Thesis Advisor

Golden, Colorado

Date ______

Signed: ______Dr. Paul Santi Professor and Head Department of Geology and Geological Engineering

ABSTRACT

Recent horizontal wells in the Washakie Basin of Southwestern Wyoming have targeted

liquids-rich fluvial sandstones within the Paleocene China Butte Member of the Fort Union

Formation. Deposition was in alternating meandering and braided fluvial successions which

created complex reservoir compartmentalization and depositional heterogeneity. Liquid-rich

hydrocarbons migrated from deeper source rocks or were generated from in situ interbedded

coals.

Four slabbed cores were described to determine relationships between facies, wireline log

data, and quantitative core data. Generally, cross-stratified and coarser-grained active channel fill

facies correspond to higher quality reservoir. Minor or abandoned channel fill facies are

generally finer-grained, clay and shale rich, and produce lower quality reservoirs. Locally, abrupt

contacts between channel sands indicate uninterrupted channel migration and deposition.

Floodplain deposits are abundant and comprised of mudrocks, carbonaceous shales, and coals.

Floodplain facies overlie levee deposits, and are subsequently overlain by younger channel fill

deposits associated with channel migration. In some stratigraphic intervals, amalgamated sands

with sparse interfluve sediments are associated with periods of lower-sinuosity, or braided fluvial deposition.

X-ray diffraction, scanning electron microscopy, and thin section petrography analyses were performed on all reservoir facies. In decreasing quantities, detrital grains consist of quartz and feldspar grains, with chert, metamorphic, and argillaceous rock fragments. Reservoir sandstones are well-consolidated, moderately sorted, medium to coarse-grained, subfeldspathic to feldspathic litharenites, sub-litharenites, and litharenites. Metamorphic,

iii plutonic, and sedimentary grains and rock fragments indicate variable clastic sources most likely originating from the Uinta and Wind River Mountains.

Fort Union sands were most certainly deposited by alternating cycles of high-sinuosity meandering and braided stream processes. Channel, channel margin, and floodplain facies are identified in wireline logs and cores, and are typical of high-sinuosity fluvial deposition.

Pervasive coal deposition indicates prolonged hiatus between established and confined fluvial channels.

Local carbonaceous shales are composed of Type III organic matter and source primarily gas within the system. Evidence for in-place liquid-hydrocarbons are Type II kerogen and fluorescence in coals. Deeper Type II source rocks in the Cretaceous Almond and Lewis

Formations may also be volumetrically contributing liquid hydrocarbons to the system via fractures and fault systems.

TABLE OF CONTENTS

ABSTRACT……………………………………………………………………………………...iii

LIST OF FIGURES……………………………………………………………………………...xii

LIST OF TABLES………………………………………………………………………………………xviii

ACKNOWLEDGMENTS………………………………………………………………………………..xix

CHAPTER 1 INTRODUCTION…………………………………………………………………………...1

1.1 Purpose and Scope……………………………………………………………………………………...5

1.2 Regional Geological Setting……………………………………………………………………………5

1.3 Location of Study Area………………………………………………………………………………...7

1.4 Research Objectives……………………………………………………………………………………7

1.5 Data Set and Methods…………………………………………………………………………………..7

1.6 Previous Research and Analogue Depositional Model………………………………………………...9

1.6.1 USGS Lower Tertiary Correlations and Nomenclature………………………………...... 9

1.6.2 Jonah Field Cretaceous Lance Deposition……………………………………………….10

1.6.3 Big Horn Basin Fort Union Deposition………………………………………………….10

1.6.4 Sand Wash Basin Fort Union Deposition………………………………………………..10

1.6.4.1 Lithofacies………………………………………………………………………13

1.6.4.2 Sand Wash Basin Depositional Trends………………………………………….14

1.6.4.3 Depositional Environment………………………………………………………14

1.6.4.4 Powder Wash Field……………………………………………………………...15

1.7 Fort Union Production History…………………………………………………………………...... 15

1.7.1 Washakie Basin…………………………………………………………………………..16

1.7.2 Sand Wash Basin……………………………………………………………………...... 17

1.8 Summary………………………………………………………………………………………...... 17

CHAPTER 2 GENERAL WASHAKIE BASIN FORT UNION FORMATION STRATIGRAPHY……18

2.1 Methodology……………………………………………………………………………………...... 18

2.2 Keystone Stratigraphy……………………………………………………………………………...... 18

2.2.1 Tertiary China Butte Member………………………………………………………...... 18

2.2.2 Cretaceous Red Rim Member……………………………………………………………21

2.3 Summary…………………………………………………………………………………………...... 21

CHAPTER 3 FORT UNION FORMATION CORE DESCRIPTIONS AND FACIES DEFINITIONS...25

3.1 Methodology……………………………………………………………………………………...... 25

3.2 Facies Analysis and Core Descriptions…………………………………………………………...... 26

3.2.1 Samson Resources Barricade #33-12…………………………………………………….26

3.2.1.1 Facies A – Siltstone and Very Fine-Grained Sandstone ………………………..26

3.2.1.2 Facies B – Sandstone Very Fine-Grained ………………………………………26

3.2.1.3 Facies C – Mudstone…………………………………………………...... 26

3.2.1.4 Facies D – Coal………………………………………………………………….29

3.2.1.5 Facies E – Carbonaceous Shale…………………………………………………29

3.2.1.6 Facies F – Sandstone Medium-Grained ………………………………………...29

3.2.1.7 Facies G – Sandstone Medium-Grained and Cross-Stratified ………………….29

3.2.1.8 Facies H – Sandstone Medium-Grained.………………………………………..35

3.2.2 Samson Resources Endurance #44-29 Core #1………………………………………….35

3.2.2.1 Facies 1A – Silt-Mudstone………………………………………...... 35

3.2.2.2 Facies 1B – Carbonaceous Shale………………………………………………..35

3.2.2.3 Facies 1C – Sandstone Fine-Grained and Burrow Mottled ………………….....35

3.2.2.4 Facies 1D – Mudstone………………………………………………...... 40

3.2.2.5 Facies 1E – Sandstone Lower Medium-Grained ……………………………….40

3.2.2.6 Facies 1F – Sandstone Fine-Grained …………………………………………...40

3.2.2.7 Facies 1G – Sandstone Medium-Grained and Cross-Stratified ………………...40

3.2.2.8 Facies 1H – Sandstone Coarse-Grained ……………………………………...... 40

3.2.2.9 Facies 1I – Sandstone Medium-Grained Cross-Stratified....……………………40

3.2.2.10 Facies 1J – Sandstone Fine-Grained.…………………………………………....46

3.2.2.11 Facies 1K – Sandstone Medium-Grained With Contorted Bedding ……………46

3.2.2.12 Facies 1L – Silt-Mudstone……………………………………...... 46

3.2.3 Samson Resources Endurance #44-29 Core #2………………………………………….46

3.2.3.1 Facies 2A – Mudstone………………………………………………...... 46

3.2.3.2 Facies 2B – Silt-Mudstone……………………………………...... 46

3.2.3.3 Facies 2C – Mudstone………………………………………………...... 53

3.2.3.4 Facies 2D – Carbonaceous Shale………………………………………………..53

3.2.3.5 Facies 2E – Siltstone…………………………………………………...... 53

3.2.3.6 Facies 2F – Sandstone Medium-Grained ……………………………………….53

3.2.4 Samson Resources Endurance #44-29 Core #3………………………………………….53

3.2.4.1 Facies 3A – Mudstone………………………………………………...... 53

3.2.4.2 Facies 3B – Sandstone Very Fine-Grained …………………………………...... 59

3.2.4.3 Facies 3C –Siltstone………………………………………...... 59

3.2.4.4 Facies 3D – Sandstone Fine-Grained and Cross-Stratified.………………….....59

3.2.4.5 Facies 3E – Carbonaceous Shale……………………………………...... 59

3.2.4.6 Facies 3F – Sandstone Medium-Grained Laminated...... …………………….59

3.2.4.7 Facies 3G – Sandstone Medium-Grained and Cross-Stratified ………………...59

3.3 Facies Associations………………………………………………………………………………...... 65

3.3.1 Active Fluvial Channel Fill………………………………………………………………65

3.3.2 Abandoned Channel Fill…………………………………………………………………65

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3.3.3 Channel Margin………………………………………………………………………….70

3.3.3.1 Levee…………………………………………………………………………….70

3.3.3.2 Crevasse Splay…………………………………………………………………..70

3.3.4 Floodplain Deposits……………………………………………………………………...72

3.3.4.1 Mud Rock……………………………………………………………………….72

3.3.4.2 Carbonaceous Shale……………………………………………………………..72

3.3.4.3 Coal……………………………………………………………………………...74

3.4 Relationships in Facies, Measured Core Data, and Open-hole Log Data……………...... 74

3.5 Depositional Environment………………………………………………………………...... 77

3.6 Summary…………………………………………………………………………………………...... 77

CHAPTER 4 FORT UNION FORMATION FACIES PETROGRAPHY AND MINERALOGY...... 79

4.1 X-Ray Diffraction (XRD) Analysis……………………………………………………………...... 79

4.2 XRD Results……………………………………………………………………………………...... 79

4.2.1 Barricade #33-12………………………………………………………………………....79

4.2.2 Endurance #44-29………………………………………………………………………..79

4.2.3 Barricade #21-11…………………………………………………………………...... 81

4.3 Scanning Electron Microscope (SEM) Analysis…………………………………………………...... 81

4.4 SEM Results……………………………………………………………………………………...... 81

4.4.1 Barricade #33-12………………………………………………………………………....81

4.5 Petrographic Methods…………………………………………………………………………...... 81

4.6 Petrographic Descriptions………………………………………………………………………...... 83

4.6.1 Facies H………………………………………………………………………………….83

4.6.2 Facies G………………………………………………………………………………….84

4.6.3 Facies F…………………………………………………………………………………..84

4.6.4 Facies 1K………………………………………………………………………………...85

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4.6.5 Facies 1J……………………………………………………………………………….....85

4.6.6 Facies 1I………………………………………………………………………………….86

4.6.7 Facies 1G………………………………………………………………………………...86

4.6.8 Facies 1C………………………………………………………………………………....87

4.6.9 Facies 2F………………………………………………………………………………....87

4.6.10 Facies 2B………………………………………………………………………………....88

4.6.11 Facies 3G………………………………………………………………………………...88

4.6.12 Facies 3D………………………………………………………………………………...89

4.6.13 Facies 3C………………………………………………………………………………....89

4.7 Interpretation of Mineralogical Results…………………………………………………………...... 90

4.7.1 Framework Grains……………………………………………………………………….90

4.7.2 Pore Types……………………………………………………………………………….90

4.7.3 Cementation……………………………………………………………………………...90

4.7.4 Microfracturing – Epifluorescence……………………………………………………....94

4.8 Clues to Provenance……………………………………………………………………………...... 94

4.9 Summary………………………………………………………………………………………...... 94

CHAPTER 5 WASHAKIE BASIN FORT UNION FORMATION THERMAL MATURITY……….....97

5.1 Regional Maturity……………………………………………………………………………...... 97

5.2 Organic Petrology……………………………………………………………………………...... 97

5.3 Organic Petrology Results……………………………………………………………………...... 99

5.4 Potential Liquid-Prone Source Rocks…………………………………………………………...... 99

5.4.1 Migration from Deeper Source Rocks………………………………………………...... 99

5.4.2 In-Situ Coals and Carbonaceous Shales………………………………………………..101

5.5 Summary………………………………………………………………………………………...... 101

CHAPTER 6 WASHAKIE BASIN FORT UNION FORMATION DEPOSITIONAL MODEL……....104

6.1 Model Inputs…………………………………………………………………………………...... 104

6.1.1 Regional Paleogeographic Position………………………………………………….....104

6.1.2 Paleo-current Data……………………………………………………………………...106

6.1.2.1 USGS Outcrop………………………………………………………………....106

6.1.2.2 Endurance #42-10……………………………………………………………...106

6.1.3 Facies Associations……………………………………………………………………..110

6.1.4 Mineralogy and Provenance…………………………………………………………....112

6.2 Depositional Model……………………………………………………………………………...... 114

6.3 Summary………………………………………………………………………………………...... 114

CHAPTER 7 SUMMARY, DISCUSSION, CONCLUSIONS, AND RECOMMENDATIONS…….....120

7.1 Conclusions……………………………………………………………………………………...... 120

7.1.1 Core Facies……………………………………………………………………………...120

7.1.2 Mineralogy……………………………………………………………………………...121

7.1.3 Depositional Environment……………………………………………………………...121

7.1.4 Source Rocks…………………………………………………………………………...121

7.2 Discussion………………………………………………………………………………………...... 122

7.2.1 Reservoir Connectivity………………………………………………………………....122

7.2.2 Source Variability……………………………………………………………………....122

7.2.3 Importance of an Integrative Reservoir Model………………………………………....123

7.3 Recommendations for Future Research………………………………………………………...... 123

REFERENCES CITED…………………………………………………………………………………..124

APPENDIX A…………………………………………………………………………………………....127

APPENDIX B…………………………………………………………………………………………....128

APPENDIX C…………………………………………………………………………………………....132

APPENDIX D…………………………………………………………………………………………....138

LIST OF FIGURES

Figure 1.1 Stratigraphic chart showing the Washakie Basin Fort Union Formation highlighted in red. Modified from USGS Southwestern Wyoming Province Assessment Team Digital Data Series, (2005)………………….2 Figure 1.2 Washakie Basin producing fields. Modified from USGS Southwestern Wyoming Province Assessment Team Digital Data Series, (2005). Production numbers from HIS, (2013)……………………………………3 Figure 1.3 Washakie Basin stratigraphic column with type well log. Modified from Hettinger and Honey, (2004). Main producing pay interval is roughly equivalent to USGS China Butte Member………………………………..4 Figure 1.4 Washakie Basin location map. Modified from USGS Southwestern Wyoming Province Assessment Team Digital Data Series, (2005)……...6 Figure 1.5 Study area and primary data set. Study area shaded in red, whole core data indicated by black stars, Cretaceous Almond structure contours…...8 Figure 1.6 USGS measured sections locations, geologic map. Modified from Hettinger and Honey, (2004)…………………………………...... 11 Figure 1.7 USGS stratigraphic divisions and nomenclature, red shading indicates main productive zone in Barricade and Endurance Units. Modified from Hettinger and Honey, (2004)...... 12 Figure 2.1 Type section of the Fort Union Formation in the Eastern Washakie Basin, China Butte Member shaded in red. Fillmore Ranch Coal zone is interpreted to be the most laterally extensive coal (Modified from Hettinger et. al. 2006)...... 19 Figure 2.2 Subsea structure map: top of China Butte Member of the Fort Union Formation of the Washakie Basin. Control points: blue circle. USGS subsurface correlations: yellow star. Eastern Fort Union outcrop: orange. Contemporary Fort Union production: white borders. Cooler colors indicate greater depth. C.I. = 100’...... 20 Figure 2.3 Barricade #33-12 well log with corresponding type section. Coal zones may not be readily correlatable regionally (Modified from Hettinger et. al. 2006)...... 22 Figure 2.4 Type section of the Lance Formation in the Eastern Washakie Basin, Red Rim Member shaded in red. Cretaceous-Tertiary contact marked by conglomerate horizon (Modified from Hettinger et al. 2006)...... 23

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Figure 3.1 Facies A. 10187.0 feet. Facies A is light gray siltstone showing contorted bedding, bioturbation with ripples and wavy lamination...... 27 Figure 3.2 Facies B. 10190.0 ft. Facies B is a fine-grained salt and pepper colored sandstone, mainly massive with some faint low-angle cross- stratification...... 28 Figure 3.3 Facies C. 10181.0 ft. Facies C is a heavily fractured mudstone. Sparse pyrite nodules are present and plant material lines fracture planes...... 30 Figure 3.4 Facies D. 10177.0 ft. Facies D is coal that commonly grades to carbonaceous shale...... 31 Figure 3.5 Facies E. 10175.0 ft. Facies D is heavily fractured, dark gray carbonaceous shale...... 32 Figure 3.6 Facies F. 10165.0 ft. Facies F is light to medium gray sandstone, mainly massive with shale rip-up clasts throughout...... 33 Figure 3.7 Facies G. 10160.0 ft. Facies G is salt and pepper colored, medium- grained, cross-stratified sandstone...... 34 Figure 3.8 Facies H. 10151.0 ft. Facies H is a light to medium gray, fine to medium- grained sandstone with disseminated carbonaceous material...... 36 Figure 3.9 Facies 1A. 9572 ft. Facies 1A is a medium to dark gray, heavily fractured silt-mudstone...... 37 Figure 3.10 Facies 1B. 9565.9 ft. Facies 1B is dark-black, carbonaceous shale with interbedded coal...... 38 Figure 3.11 Facies 1C. 9567.0 ft. Facies 1C is salt and pepper colored, fine-grained, and burrowed or rooted sandstone...... 39 Figure 3.12 Facies 1D. 9564.0 ft. Facies 1D is heavily fractured dark-gray shale and interbedded siltstone...... 41 Figure 3.13 Facies 1E. 9567.0 ft. Facies 1E is salt and pepper colored, massive to cross-stratified medium-grained sandstone...... 42 Figure 3.14 Facies 1F. 9560.0 ft. Facies 1F is light-gray, fine-grained sandstone with disseminated rip-up clasts...... 43 Figure 3.15 Facies 1G. 9558.0 ft. Facies 1G is salt and pepper colored, cross- stratified, medium-grained sandstone...... 44 Figure 3.16 Facies 1H. 9556.0 ft. Facies 1H is coarse-grained sandstone...... 45 Figure 3.17 Facies 1I. 9547.0 ft. Facies 1I is salt and pepper colored, moderate to well-sorted, cross-stratified, medium-grained sandstone...... 47

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Figure 3.18 Facies 1J. 9539.0 ft. Facies 1J is salt and pepper colored to light-gray, very fine-grained sandstone with shale rip-up clasts...... 48 Figure 3.19 Facies 1K. 9527.0 ft. Facies 1K is salt and pepper colored, contorted, fine-grained sandstone...... 49 Figure 3.20 Facies 1L. 9525.0 ft. Facies 1L is rust-colored, fractured, and contorted silty-mudstone...... 50 Figure 3.21 Facies 2A. 9828.0 ft. Facies 2A light to dark gray, heavily fractured mudstone...... 51 Figure 3.22 Facies 2B. 9810.0 feet. Facies 2B is a light-to medium-gray, rippled and bioturbated silt-mudstone...... 52 Figure 3.23 Facies 2C. 9802.0 ft. Facies 2C is dark-gray to black mudstone...... 54 Figure 3.24 Facies 2D. 9795.0 ft. Facies 2D is dark-gray to black, fractured carbonaceous shale...... 55 Figure 3.25 Facies 2E. 9785.0 ft. Facies 2E is light to medium gray, ripple laminated, and sparsely bioturbated siltstone to very fine-grained sandstone...... 56 Figure 3.26 Facies 2F. 9772.0 ft. Facies 2F is salt and pepper colored, moderate to well-sorted, medium to coarse-grained sandstone with intervals of contorted bedding...... 57 Figure 3.27 Facies 3A. 9869.0 ft. Facies 3A is dark-gray fractured mudstone...... 58 Figure 3.28 Facies 3B. 9868.0 ft. Facies 3B is light-gray, ripple laminated, very fine- grained, sandstone with shale rip-up clasts at the scour base...... 60 Figure 3.29 Facies 3C. 9867.0 ft. Facies 3C is medium gray to dark gray, ripple laminated siltstone to very fine-grained sandstone. Porosity is poor to fair...... 61 Figure 3.30 Facies 3D. 9859.0 ft. Facies 3D is brown, well-sorted, cross-stratified, fine grained, sandstone. The facies fine from base to top and has with fair to good porosity...... 62 Figure 3.31 Facies 3E. 9853.0 ft. Facies 3E is dark gray to black carbonaceous shale that grades at base and top to coal...... 63 Figure 3.32 Facies 3F. 9849.0 ft. Facies 3F is salt and pepper colored, medium- grained sandstone with shale laminations...... 64 Figure 3.33 Facies 3G. 9837.5 ft. Facies 3G is salt and pepper colored, cross- stratified, medium-grained sandstone...... 66

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Figure 3.34 Barricade #33-12 detail description showing interpreted abandoned (orange-F and H) and active channel fill (yellow-G) sandstones. AC: abrupt contact...... 68 Figure 3.35 Endurance #44-29 Core #1 detail description showing interpreted individual amalgamated and multi-storied sandstones. AC: abrupt contact, GC: gradational contact...... 69 Figure 3.36 Endurance #44-29 Core # 2 detail description shows crevasse splay deposits (dark brown) encased in floodplain mud rocks (gray). 2A3 indicates the third occurrence of Facies 2A in this core. 2D2 indicates the second occurrence of Facies 2D in this core...... 71 Figure 3.37 Barricade #33-12 detail description showing interpreted high-sinuosity channel succession. Levee (light brown) deposits are overlain by floodplain mud rocks, coals, and carbonaceous shales (gray). A2 indicates the second occurrence of Facies A in this core...... 73

Figure 3.38 Barricade #33-12 data shows high quality active channel fill sandstones (yellow) and corresponding high permeabilities, gas effect, and gas show. Abandoned channel fill sandstones (orange) have decreased relative core permeabilities and suppressed porosities...... 75

Figure 3.39 Endurance #44-29 core #1 data show equivalent open-hole log response for active channel fill sands (yellow) but relatively higher core permeabilities associated with facies 1I; illustrating reservoir heterogeneity that may be undetectable by conventional open-hole logs...... 76 Figure 3.40 This is a diagram of typical meandering fluvial succession including channel, levee, and floodplain deposits (Fichter, 2000)...... 78

Figure 4.1A Thin section photomicrograph from the Endurance #44-29 Core #1 Facies 1I, illustrating secondary porosity (Ps) via dissolution of unstable framework grains. Pore space stained with red fluorescent epoxy. Quartz (Q), Chert (Ch), and organic matter (Om). Depth: 9548.0, Magnification: 63X, Plane Light...... 91

Figure 4.1B Thin section photomicrograph from the Endurance #44-29 Core #1 Facies 1I, illustrating secondary porosity (Ps) via dissolution of unstable framework grains Depth: 9548.0, Magnification: 63X, Fluorescent Light...... 92

Figure 4.2 Thin section photomicrograph from the Barricade #33-12 Facies F, illustrating calcite cement (Ca) highlighted by alizarin red stain. Quartz (Q), Potassium Feldpsar (Kspar). Depth: 10163.20, Magnification: 63X, Plane Light...... 93

Figure 4.3 Thin section photomicrograph from the Endurance #44-29 Core #1 Facies 1G. Photomicrograph illustrates intergranular and intragranular fractures. Thin section stained with fluorescent epoxy. Depth: 9559.55, Magnification: 63X, Fluorescent light...... 95

Figure 4.4 Folk (1974, 1980) sandstone classification showing plotted Fort Union sandstones. Sandstones are primarily litharenites, sublitharenites, and feldspathic litharenites...... 96

Figure 5.1 Vitrinite reflectance at the base of the Paleocene Fort Union Formation in Southwestern Wyoming. Study area outlined in black dash, contemporary Fort Union production highlighted with red oval (Modified from USGS, 2005)...... 98

Figure 5.2 Two source concept as hypothesized for the Washakie Basin, showing in- situ gas charge as well as deeper migration (modified from Cumella, 2008)...... 102

Figure 6.1 Paleogeographic reconstruction of North America during the Early Paleocene. Wyoming: white outline; study area: red star (Modified from Blakey, 2011)...... 105

Figure 6.2 Location of USGS outcrop China Butte Member paleo-current data (blue star) and Endurance #42-10 FMI China Butte dip meter paleo-currents (red star). Top China Butte Member structure map; C.I. = 100 feet. Study area: outlined in red. Fort Union Formation outcrop: orange...... 107

Figure 6.3 Paleo-current azimuth from China Butte Member, showing a mean direction of 75 degrees (Modified from Hettinger et. al., 2006)...... 108

Figure 6.4 Interpreted paleo-current directions and FMI log from the China Butte Member of the Endurance #42-10. While average paleo-current direction is 115 degrees, significant variability (outcrop = 75 degrees) exists within the dataset which could suggest higher sinuosity channel flow...... 109

Figure 6.5 Barricade #33-12 core description interpreted as a partial meandering fluvial succession. Facies A – levee; Facies B – crevasse splay; Facies C – overbank mudrock; Facies D – coal; Facies E – carbonaceous shale; Facies F – abandoned channel fill; Facies G – active channel fill...... 111

Figure 6.6 Green River Basin and surrounding Laramide uplifts and general compositions. Study area: red dash (Modified from Kirschbaum, 1994)...... 113

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Figure 6.7 Proposed Washakie Basin Fort Union Formation depositional model. Model represents typical high-sinuosity meandering fluvial succession as evidenced in core and wireline log data set...... 115

Figure 6.8 Cross section of channel, channel margin, and floodplain environments (Modified from Weimer, 1973; Beaumont, 1979)...... 116

Figure 6.9 Proposed Washakie Basin Fort Union Formation depositional model. Model represents typical low-sinuosity braided fluvial deposition as detailed in core and wireline log data...... 117

Figure 6.10 Proposed Washakie Basin Fort Union Formation composite depositional model. Figure represents two phases of deposition: (1) low-sinuosity, high energy channel sands overlain by (2) high-sinuosity, low energy fluvial channel. Core and log correlations indicate high-sinuosity meandering channel belts...... 118

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LIST OF TABLES

Table 3.1 Individual core facies, bed forms, distinguishing characteristics, and depositional setting...... 67

Table 4.1 XRD Data: Cores, facies and corresponding mineral assemblages and quantities...... 80

Table 4.2 Barricade #33-12 SEM Data: Cores, facies and corresponding authigenic grains, accessory grains, clay matrix, secondary porosity (Ps), and grain size. Abbreviations: Qtz – quartz, D – dolomite, I/SM – mixed layer illite/smectite, Sd – siderite, Ch – chert, ARF – argillaceous rock fragments, CRF – carbonate rock fragments, VRF – volcanic rock fragments, Plag – plagioclase, Kspar – K-feldspar, LF – lower fine, UF – upper fine, LM – lower medium...... 82

Table 5.1 Organic petrology results for various samples showing an abundance of Vitrinite, a Type III kerogen maceral and trace amounts of Liptinite, a Type II kerogen maceral. Ro: Vitrinite reflectance under oil...... 100

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ACKNOWLEDGMENTS

First and foremost, thank you to my advisor Dr. John Curtis. This project would have been impossible without your time, advice, and direction. Thank you. I Hope now you can finally retire. Thank you to my committee members. Dr. Mike Hendricks, for your council and constant proofing, your expert eye was invaluable. Dr. Sonnenberg, for your expertise and criticism, I’ve always benefited from your unconventional perspective.

Thank you to Samson Resources for funding and supporting my thesis. Specifically, Rich Frommer, Jay Smith, Greg Anderson, Ken Tompkins, Jim Coogan and Tiffany Sessions. Each of you contributed to my educational process and I would not have finished without your ongoing support, advice, and flexibility.

To my teammates. Tammy, Jennifer, and Darin. Thank you for taking up the slack while I barricaded myself in my office to write. Your unspoken understanding, I’ll never forget.

Thank you to those that enabled my laboratory efforts, specifically, the folks at Core Lab and Butch Oliver, your constant accommodation made all the difference.

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CHAPTER 1

INTRODUCTION

Horizontal well development in the Washakie Basin has focused on the Paleocene Fort

Union Formation. The associated high liquids yield has substantially increased profitability.

Ahead of full-field development, it is now a critical time to properly evaluate and characterize a

complex reservoir in a data-poor area. Serious economic implications could exist if an improper

depositional model is assumed. This thesis developed an integrated depositional model and an

overall understanding of reservoir heterogeneity.

The Paleocene Fort Union Formation in the Washakie Basin is, on average, 3,400 ft thick and

comprised primarily of interbedded sandstone, siltstone, mudstone, carbonaceous shale, and coal

(Figure 1.1). It has produced gas and oil in twelve fields throughout the Greater Green River basin (Figure 1.2). Original gas-in-place in the Fort Union has been estimated to be as high as one hundred trillion cubic ft (Law, 1989). In the Washakie Basin, the Fort Union Formation produces high BTU gas and condensate from a gross 900-1,200 ft thick over-pressured, gas- saturated interval (Figure 1.3).

Regional Fort Union deposition has been characterized by previous workers as fluvial- lacustrine (Katz et al., 1993), presenting unique challenges related to reservoir heterogeneity. A key consideration to successful development of the Fort Union Formation within the study area rests in understanding the controls on deposition and variations in reservoir quality and heterogeneity. No previous published subsurface work has focused on this study area. A USGS outcrop study from Creston Junction to Baggs, WY (Hettinger et al., 1991, 2006) correlated six individual zones within the Fort Union Formation. This work defined the stratigraphy of the

Figure 1.1. Stratigraphic chart showing the Washakie Basin Fort Union Formation highlighted in red. Modified from USGS Southwestern Wyoming Province Assessment Team Digital Data Series, (2005).

Figure 1.2. Washakie Basin producing fields. Modified from USGS Southwestern Wyoming Province Assessment Team Digital Data Series, (2005). Production numbers from IHS, (2013).

Figure 1.3. Washakie Basin stratigraphic column with type well log. Modified from Hettinger and Honey, (2004). Main producing pay interval is roughly equivalent to USGS China Butte Member.

Fort Union Formation along the Washakie Basin’s eastern margin.

1.1. Purpose and Scope

The main purpose of this thesis is to establish a depositional model for the Fort Union

Formation within the study area, and investigate possible controls on reservoir heterogeneity. It is a primary hypothesis that a more comprehensive appreciation of reservoir variability and predictably will reduce the financial risk of developing an immature asset.

1.2. Regional Geologic Setting

The development of the Greater Green River Basin (GGRB) was greatly influenced by the emergence of the Western Cretaceous Seaway. In the mid-Cretaceous, subduction of the

Farallon plate beneath the North American plate created inland topography. This combined with rising sea level, resulted in the transgression of the Western Cretaceous Sea from the North. The seaway ultimately extended from the Arctic Circle to the Gulf of Mexico. The GGRB’s smaller sub-basins were created, primarily, as a result of Late Cretaceous Laramide tectonics (Beck,

1988).

The Washakie Basin is positioned within the eastern-most region of the GGRB. Its margins are confined by the Rock Springs Uplift to the west, Wamsutter Arch to the north, Sierra Madre to the east, and the Cherokee Arch to the south. The Washakie basin encompasses approximately 2200 square miles (Figure 1.4). Structural influence recognized within the reservoir can be attributed to late Cretaceous Laramide tectonics (Dickinson et al., 1988). The study area lies within the eastern margin of the deepest confines of the Washakie Basin, where the intense structural history of the GGRB is fully realized. Much of the Tertiary-Cretaceous stratigraphy was exposed to regional stresses resulting in significant wide-spread folding,

Figure 1.4. Washakie Basin location map. Modified from USGS Southwestern Wyoming Province Assessment Team Digital Data Series, (2005).

6 faulting, and fracturing.

1.3. Location of Study Area

The Fort Union Formation exists within this 1000 square mile study area at an average aggregate thickness of 3400 ft in southwestern Wyoming on the eastern flank of the Washakie

Basin (Figure 1.5). This formation produces from a 900-1200 ft thick interval, stratigraphically in the middle of the Fort Union Formation. Surface elevations average 7000 ft and the mean annual surface temperature is 42 degrees Fahrenheit.

1.4. Research Objectives

The following are the study objectives:

1. Establish a regional stratigraphic context for the producing Fort Union interval by

correlating the China Butte Member interval into the subsurface.

2. Describe and interpret four subsurface cores from the China Butte Member producing

interval and utilize to develop an integrated depositional model for the Fort Union

Formation.

3. Evaluate and interpret facies associations and observe and document intra-reservoir rock

heterogeneity.

4. Identify potential liquid hydrocarbon source rocks.

5. Integrate X-ray diffraction (XRD) data, scanning electron microscope (SEM) data, and

thin section petrography.

1.5. Data Set and Methods

52 ft of conventional core were recovered in the Samson Resources Barricade #33-12 Fort

Figure 1.5. Study area and primary data set. Study area shaded in red, whole core data indicated by black stars, Cretaceous Almond structure contours.

Union test, located in Section 12 of Township 14N, Range 96W (Figure 1.5). Two conventional

cores of 60 ft and one conventional core of 41 ft were recovered in the Samson Resources

Endurance #44-29 Fort Union test, located in Section 29 of Township 15N, Range 95W (Figure

1.5). Fifty-nine sidewall cores were recovered from the Samson Resources Barricade #21-11,

located in section 11 of Township 14N, Range 96W. These core data served as the primary data

set for this study. Slabbed cores were visually described and compared to wireline logs and reservoir properties. Whole core and sidewall samples were subjected to routine conventional core analysis, including porosity, permeability, and mineralogy. Shale samples were analyzed for source rock potential and maturity by way of kerogen typing and vitrinite reflectance. Thirty-

four petrographic thin sections were utilized for describing diagenesis, porosity, and permeability

using advanced techniques including epifluorescence. A 343 digital well log data set was used to

correlate producing intervals to published USGS outcrop stratigraphic divisions and

nomenclature.

1.6. Previous Research and Analogue Depositional Model

Analogue depositional models in Jonah field, the Big Horn Basin, and the Sand Wash Basin

are discussed for comparisons in depositional trends, controls on production, and reservoir

continuity.

1.6.1. USGS Lower Tertiary Correlations and Nomenclature

An important component of reservoir characterization is understanding reservoir

heterogeneity within a given geographical area. Previous workers Hettinger et al. (1991)

developed regional correlations along the eastern margins of this study area. In this research,

major litho-stratigraphic zones were identified using available wireline logs in combination with

9 local outcrop work (Figures 1.6 and 1.7). Published USGS outcrop correlations are continued, where possible, into the subsurface throughout the study area. The nomenclature is utilized to record stratigraphic sub-divisions and their associations to producing intervals.

1.6.2. Jonah Field Cretaceous Lance Deposition

Reservoir characterization of the Cretaceous Lance Formation, at Jonah Field were developed using sedimentological descriptions from core data and quantitative reservoir properties in Shanley (2004). Facies, typical of multistory fluvial environments, were described from available core data and compared to conventional core analysis and subsurface well-logs.

An immediate correlation was observed between specific sedimentary structures, wireline log response, and measured porosity and permeability data. These relationships indicate that sand concentration is not the only control on reservoir quality in fluvial environments. Facies relationships also play an important role in productivity. This methodology is utilized in this study to characterize facies controls on reservoir performance.

1.6.3. Big Horn Basin Fort Union Deposition

In Yuretich et al. (1984), a fluvial-lacustrine depositional environment is invoked to describe the Paleocene Fort Union Formation in the Big Horn Basin. The authors point to local freshwater limestones and marls, preserved high-input clastic preservation, and laterally pervasive thin bedding as evidence.

1.6.4. Sand Wash Basin Fort Union Deposition

Beaumont (1979) proposes a fluvial-lacustrine depositional model for the Fort Union formation in the Sand Wash Basin of northwestern Colorado. Of particular importance,

Figure 1.6. USGS measured sections locations, geologic map. Modified from Hettinger and Honey, (2004).

Figure 1.7. USGS stratigraphic divisions and nomenclature, red shading indicates main productive zone in Barricade and Endurance Units. Modified from Hettinger and Honey, (2004).

Beaumont focuses on depositional trends, lithofacies, and the pervasiveness and significance of

coal. Proximity makes Beaumont’s study a significant analogue comparison to Fort Union

deposition in the Washakie basin and is described in the following section.

1.6.4.1. Lithofacies

Beaumont (1979) observes six separate lithofacies: conglomerate, sandstone, siltstone, shale, carbonate rocks, and coal. At the base of the Fort Union, conglomeratic rocks are arkosic with well-rounded to subrounded pebbles in a medium-grained sandstone matrix. These rocks weather poorly except in areas where calcite and iron oxide cements indurated the rocks and increased their resistance to weathering.

Fort Union sandstones are thick (greater than 5 ft) or thin (less than 5 ft). Thick sandstones are cross-stratified and contorted, average 30 ft in thickness, and are relatively continuous. The sandstones are medium to very coarse-grained, dominantly quartz (70%), carbonate cemented, and contain minor iron concretions . Thin sandstones are discontinuous (less than 5 ft thick), fine-grained, well to moderately sorted, salt and pepper in appearance, rooted, ripple laminated,

and cross-stratified. Siltstone is gray, ripple laminated, and root-mottled. Well-preserved fossil

leaves are common. Siltstone contacts are abrupt to gradational. Siltstone beds are generally

discontinuous and are present as 1 ft beds in shale units or as thin partings in coal beds.

Limestone is brown, micritic, unfossiliferous, and less than 1 ft thick. Thick siderite beds have

been observed in the northwest quadrant of the Sand Wash Basin. Subbituminous coal is present

throughout the basin and generally interbedded with shale. Laterally, coal beds vary in thickness

and commonly grade into carbonaceous shale. Some stratigraphically equivalent coals can be

correlated for approximately 12 miles.

1.6.4.2. Sand Wash Basin Depositional Trends

Beaumont (1979) recognized coal and sandstone depositional trends. Sandstone is concentrated in a north-northwest trending belt through the center of the basin and is thickest in the north-central portion of the basin. Shale concentrations increase on either side of the main sandstone depositional trend. Coal also appears to be concentrated in north-northwest trending belt flanking the areas of thickest sandstone accumulations in the north-central portions of the basin. Beaumont suggests that sandstone deposition was a major control on coal deposition.

1.6.4.3. Depositional Environment

Beaumont (1979) observed an absence of marine fossils, fining upward sequences, and signs of plant growth as evidence for a continental environment for the Fort Union. Beaumont classifies the upper Fort Union as having characteristics more closely related to a meandering fluvial environment , that is, low sand to shale ratio, fining upward sequences, sandstone lenticularity, abrupt lower contacts, gradational upper contacts, well preserved fossil leaves, compositions and textures of sandstones, unidirectional paleo-currents, and multi-storied sandstones. Lower Fort Union sediments were described as braided-fluvial, mostly due to the decrease in relative shale volumes. Coal was described as hypautochthonous (some coal formed in place while some formed from drifted plant material). Coals are variable in quality and thickness, grading both laterally and vertically into carbonaceous shales. Coals lack upright fossil trees, but have good preservation of fossil leaves and relatively low sulfur content. Beaumont concludes that the grading of coals laterally and vertically into carbonaceous shales indicates a transition from a reducing environment to an oxidizing environment, or from a poorly-drained swamp to a well-drained one. It is suggested that position of the water table greatly controlled

the areal extent of coal deposition, further, in cases of a low water table, near river or basin margins, organic debris either oxidized or decayed. In cases of a high water table, a lake formed and drowned vegetation along its shores. The relative abundance and thickness of Fort Union coals suggest relative stability of geological environment.

1.6.4.4 Powder Wash Field

Powder Wash Field, located in Moffat County, Colorado, produces from an approximate 200

ft four-way structural closure (Anderson, 2006). Discovered in 1931, it has produced in excess

of 276.8 BCF and 8.3 MMBO from fluvial sands within the Wasatch and Fort Union formations.

Productive Fort Union reservoirs typically display average porosities of approximately 14%

within an amalgamated 1200 ft thick interval, known locally as the Upper Sandy. Reservoir

lenticularity and heterogeneity make correlations between wells difficult. Here, increased well

density was used to more completely exploit available resource.

1.7. Fort Union Production History & Resource Estimates

Law et al. (1989) classified tight gas reservoirs within the GGRB and suggested estimates for

their ultimate gas-in-place. Law et al. suggests that source rocks within the Fort Union

Formation primarily contain Type III organic matter and produce mainly gas, and that, excluding

coal, average a total organic carbon content (TOC) of 2.04%. Law also explains that due to the

lenticular nature of the primarily fluvial reservoir, response to hydraulic fracturing is, in many

cases, inconsistent. This point greatly supports the need for valid reservoir characterization as a

predictive model for production.

Fort Union production has been established in a variety of fields in the Eastern Green River

basin. These fields, outlined below, can be viewed in relation to the study area in Figure 1.2.

These histories, in large part, were established by Colson, 1969 and updated with available contemporary production data.

1.7.1. Washakie Basin

The first Fort Union production in the Eastern Green River Basin was established in 1927 in

Hiawatha field in Sweetwater County, Wyoming (Figure 1.2). Discovered by Sormir Petroleum, production from both Wasatch and Fort Union was brought to market in 1929. Approximately

73 wells produce or have produced from two separate anticlinal structures. Cumulative production from Fort Union sands is in excess of 115 Bcf and 500 MBO (IHS, 2013).

Texaco, in 1946, added to the list of Fort Union discoveries with Table Rock Field in

Sweetwater County, Wyoming (Figure 1.2). The field originally produced from two wells from a structurally confined conglomeratic Fort Union interval. Cumulative production totals exceed

100 MMcf and 10.4 MBO (IHS, 2013).

In 1947, Kerr McGee along with Phillips Petroleum tested the Fort Union on the crest of a faulted anticline. In South Baggs field, Fort Union production from two wells is commingled with the Cretaceous. Production totals exceed 650 MMcf and 0.37 MBO (IHS, 2013).

State Line Field in Sweetwater Co, Wyoming was discovered in 1959 by Gulf Oil

Corporation and produces oil and gas from lenticular sands in the Fort Union formation from more than 12 wells (Colson, 1969). Production totals exceed 67 MMcf and 4 MBO (IHS, 2013).

Pioneer field, discovered by Mountain Fuel Supply in 1965, produces from lower Wasatch and two sands from the upper Fort Union. The accumulation is stratigraphically controlled on the faulted east flank of the Pioneer Anticline (Colson, 1969).

1.7.2. Sand Wash Basin

In 1931, Sand Wash Basin Fort Union production was established in the Powder Wash area

in Moffat County, Colorado (Figure 1.2). The discovery well was drilled by Mountain Fuel

Supply and has resulted in 100 completed Fort Union wells from structurally confined lenticular sands. Fort Union production here has exceeded 80 Bcf and 1.2 MMBO (IHS, 2013).

Mountain Fuel Supply discovered Shell Creek field in Moffat County, Colorado in 1955.

Several Fort Union wells have produced an estimated 80 Bcf and 1.2 MMBO (IHS, 2013) from structurally confined lenticular lower Fort Union sands.

Little Snake Field, covering both Sweetwater and Moffat Counties of Wyoming and

Colorado respectively, was discovered by Union Oil Company in 1958. Production was established in 1964 from four wells. Production from structurally controlled Fort Union

lenticular sands has produced in excess of 742 MMcf and 1.49 MBO (IHS, 2013).

Roundtable Field, also straddling Wyoming and Colorado, was discovered by Huber Oil

Company in 1967. Several wells have produced in excess of 10 MBO (IHS, 2013) of oil from

stratigraphically and structurally controlled Fort Union sands.

Pole Gulch Field, also in Moffat County, Colorado, was discovered by HLM Drilling

Company in 1965 and produces from one well in the Lower Fort Union formation.

1.8. Summary

Abundant economic potential exists in a contemporary Fort Union discovery in

Endurance/Barricade units in the Washakie Basin. Given the reservoir’s high liquid yield and current world commodity prices, it has become a significant asset. However, due to the inherent complex nature of Fort Union deposition, a detailed understanding of the reservoir, from outcrop to the microscopic level, is important to successfully exploit this resource.

CHAPTER 2

GENERAL WASHAKIE BASIN FORT UNION FORMATION STRATIGRAPHY

USGS outcrop stratigraphic nomenclature was correlated in the subsurface to establish a

stratigraphic context in the study area. The China Butte Member of the Paleocene Fort Union

Formation and the Red Rim Member of the Cretaceous Lance Formation generally confine the

producing interval within the study area (Figure 2.1). Local coal zones were utilized as a

framework for these correlations, however, uncertainly in lateral continuity challenged these correlations regionally. Therefore, detailed internal correlations are not included in this study.

2.1 Methodology

Utilizing a 343 well digital openhole log data set, stratigraphic classifications within the Fort

Union Formation were continued from eastern basin outcrops westward through the study area

(Figure 2.2). Gamma ray (GR), density (Rhob), and resistivity (ILD) logs, using specific cut-

offs, assisted in horizon identification and correlation; GR<75 API cut-off for clean sands,

GR>75 API cut-off for shales, Rhob <2.1 g/cm3 for coals, and ILD>25 ohm-m. Using these

parameters, a structure map for the top of the China Butte Member was constructed and coals

were correlated to the west as far as possible (Figure 2.2).

2.2 Keystone Stratigraphy

2.2.1 Tertiary Paleocene China Butte Member

The China Butte Member consists predominately of sandstone, siltstone, mudstone,

carbonaceous shale, and coal. In outcrop, sandstones within the China Butte Member show

periodic fining upward multi-storied units (Figure 2.1). Cross-bedding is relatively abundant and

Figure 2.1. Type section of the Fort Union Formation in the Eastern Washakie Basin, China Butte Member shaded in red. Fillmore Ranch Coal zone is interpreted to be the most laterally extensive coal (Modified from Hettinger et. al. 2006).

Figure 2.2. Subsea structure map: top of China Butte Member of the Fort Union Formation of the Washakie Basin. Control points: blue circle. USGS subsurface correlations: yellow star. Eastern Fort Union outcrop: orange. Contemporary Fort Union production: white borders. Cooler colors indicate greater depth. C.I. = 100’.

grain sizes range from fine to coarse. A conglomeratic unit marks the Cretaceous – Tertiary

boundary. Mudrocks occur as rippled, fissile gray siltstones and carbonaceous shales. Shales

grade locally to laterally extensive coals (Hettinger et al, 2006). A number of coals are present

within the China Butte Member, perhaps the most continuous of these is the Fillmore Ranch

Coal, which appears to traverse the study area.

The top of China Butte Member generally follows basin structure and correlates

sufficiently with the gross producing Fort Union interval in the study area (Figures 2.2 and 2.3).

Moving westward from the outcrop, correlations of internal coal zones are problematic, as a

paucity of wireline log decreases correlation confidence. It is uncertain how laterally pervasive

individual zones may be (Appendix A).

2.2.2 Cretaceous Red Rim Member

The Red Rim Member of the Cretaceous Lance Formation marks the Cretaceous-Tertiary unconformable boundary. It consists primarily of fine to coarse-grained sandstone overlain by basal Fort Union conglomerate (Figure 2.4). Massive to cross-stratified, amalgamated sand bodies are separated by laterally extensive carbonaceous shales and mudstones (Hettinger et. al.,

2006). In outcrop, identification of the Cretaceous-Tertiary contact is marked by an extensive conglomerate horizon, but identification of this horizon with wireline logs is challenging.

2.3 Summary

Contemporary wells targeting the Fort Union Formation produce from the China Butte

Member as defined by the USGS (Hettinger et.al. 2006). Reservoir rocks at outcrop and in the subsurface consist of multistoried and often amalgamated sandstone intervals. Interbedded coals

Figure 2.3. Barricade #33-12 well log with corresponding type section. Coal zones may not be regionally correlatable (Modified from Hettinger et. al. 2006).

Figure 2.4. Type section of the Lance Formation in the Eastern Washakie Basin, Red Rim Member shaded in red. Cretaceous- Tertiary contact marked by conglomerate horizon (Modified from Hettinger et al. 2006).

and carbonaceous shales are locally pervasive but are difficult to correlate moving west from outcrop. The Fillmore Ranch Coal Zone may extend the farthest west as it thins towards basin center. Correlation difficulties result from inherent depositional heterogeneity.

CHAPTER 3

FORT UNION FORMATION CORE DESCRIPTIONS AND FACIES DEFINITIONS

Facies identification from detailed core work, and correlations to specific open-hole log response is recognized in this study as a useful approach to evaluate reservoir heterogeneity.

Further, contrasts in resolution between core data and log data, support an integrative and comprehensive reservoir analysis. Simply put, log data alone are insufficient to resolve the inherent complexity of this reservoir. Therefore, one must consider the rocks.

3.1 Methodology

Four proprietary Fort Union China Butte Member cores, located in Sweetwater Co.,

Wyoming, were described (Figure 1.5). Lithology, sedimentary structures, and significant surfaces were described. Grain size was determined using a 10 power hand lens and grain-size chart. Qualitative relationships in porosity, fracturing, and bioturbation were observed and recorded.

Facies were subdivided for each core, using observed variances in grain size, color, lithology, porosity, fracturing, and organic content. Facies were compared to open-hole log data to establish relationships. Stratigraphic heterogeneity and limited core data prohibit detailed facies correlations across large distances. In this study, individual facies may not be easily correlated between individual cores. Therefore, four generalized facies associations are representative examples of each of the four cores and are the primary inputs for the depositional model

(Chapter 6).

3.2 Facies Analysis and Core Descriptions

Facies were interpreted based on differences in lithology, grain size, and sedimentary structures. Based on grain size, sorting, and analytical porosity, reservoir quality was identified as poor to good.

3.2.1 Samson Resources Barricade #33-12

The Samson Resources Barricade #33-12 is located in Section 12, Township 14N, Range 96W

(Figure 1.5). The core recovered 52 feet of sandstone, siltstone, shale, and coal. Eight individual facies were recognized and catalogued.

3.2.1.1 Facies A – Siltstone and Very Fine-Grained Sandstone

Facies A is light gray, moderately sorted siltstone to very fine-grained sandstone. Facies A is rippled and wavy laminated throughout. Contorted bedding, bioturbation, and sparse fractures are present. Extensive shale rip-up clasts are observed throughout with increasing density in upper portions of the facies. Qualitative porosity is poor. (Figure 3.1).

3.2.1.2 Facies B – Sandstone Very Fine-Grained

Facies B is gray, salt and pepper colored, moderate to well-sorted, lower fine to upper fine- grained sandstone. This facies is massive in part with faint low-angle cross-stratification. Ripple laminations near the top of facies are associated with increased disseminated shale. Porosity is poor to fair (Figure 3.2).

3.2.1.3 Facies C – Mudstone

Facies C is a dark gray, heavily fractured mudstone showing faint root zones throughout.

Figure 3.1. Facies A. 10187.0 feet. Facies A is light gray siltstone showing contorted bedding, bioturbation with ripples and wavy lamination.

Figure 3.2. Facies B. 10190.0 ft. Facies B is a fine-grained salt and pepper colored sandstone, mainly massive with some faint low-angle cross- stratification.

Random pyrite nodules are present. Remnant plant material is evident within fracture planes

(Figure 3.3).

3.2.1.4 Facies D – Coal

Facies D is black, rubbblized, sub-bituminous coal that commonly grades into carbonaceous shale (Figure 3.4).

3.2.1.5 Facies E – Carbonaceous Shale

Facies E is dark gray, heavily fractured carbonaceous shale. This facies appears shattered and is commonly fissile. Fractures are partially healed with quartz cement (Figure 3.5).

3.2.1.6 Facies F – Sandstone Medium-Grained

Facies F is a light to medium gray, moderate to well-sorted, lower-fine to medium-grained sandstone. The facies is massive throughout and the upper contact is sand-on-sand. The sandstone fines from base to top. Shale rip-up clasts are abundant and increase near the scoured base. Shale lines planar laminations and increases toward the top of the facies. Facies F shows no fractures and no bioturbation. Qualitative porosity is fair to good, but diminishes near the top of the facies (Figure 3.6).

3.2.1.7 Facies G – Sandstone Medium-Grained and Cross-Stratified

Facies G is a salt and pepper colored, moderate to well-sorted, cross-stratified, partly massive, medium-grained sandstone. The facies fines from base to top. Planar shale laminations and contorted bedding are present near top of the facies. Facies G shows no fractures and no bioturbation. Qualitative porosity is good to very good. (Figure 3.7).

Figure 3.3. Facies C. 10181.0 ft. Facies C is a heavily fractured mudstone. Sparse pyrite nodules are present and plant material lines fracture planes.

Figure 3.4. Facies D. 10177.0 ft. Facies D is coal that commonly grades to carbonaceous shale.

Figure 3.5. Facies E. 10175.0 ft. Facies E is heavily fractured, dark gray carbonaceous shale.

Figure 3.6. Facies F. 10165.0 ft. Facies F is light to medium gray sandstone, mainly massive with shale rip-up clasts throughout.

Figure 3.7. Facies G. 10160.0 ft. Facies G is salt and pepper colored, medium-grained, cross-stratified sandstone.

3.2.1.8 Facies H – Sandstone Medium-Grained

Facies H is a light to medium gray, moderately well-sorted, lower fine to medium-grained

sandstone. This facies fines from base to top. Disseminated carbonaceous material and extensive

shale rip-up clasts are present throughout. There is no bioturbation. Fracturing is present near

the base. Induced fracturing is present near the top. Qualitative porosity is fair to good,

diminishing near the top of the sandstone. (Figure 3.8).

3.2.2 Samson Resources Endurance #44-29 Core #1

The Samson Resources Endurance #44-29 is located in Section 29 of Township 15N, Range

95W (Figure 1.5). Core #1 recovered 60 feet of sandstone, siltstone, and shale. Twelve

individual facies were recognized and catalogued.

3.2.2.1 Facies 1A – Silt-Mudstone

Facies 1A is a medium-to dark-gray, heavily fractured, silt-mudstone with minor bioturbation

near the base (Figure 3.9).

3.2.2.2 Facies 1B – Carbonaceous Shale

Facies 1B is dark-gray, heavily fractured, carbonaceous shale with interbedded coal in

fractures (Figure 3.10).

3.2.2.3 Facies 1C – Sandstone Fine-Grained and Burrow Mottled

Facies 1C is a salt and pepper colored, moderate-to well-sorted, fine-grained sandstone. This

facies is burrowed and/or rooted in-part, and fines from base to top. Carbonaceous material is

sparsely disseminated. Porosity is fair (Figure 3.11).

Figure 3.8. Facies H. 10151.0 ft. Facies H is a light to medium gray, fine to medium-grained sandstone with disseminated carbonaceous material.

Figure 3.9. Facies 1A. 9572 ft. Facies 1A is a medium to dark gray, heavily fractured silt- mudstone.

Figure 3.10. Facies 1B. 9565.9 ft. Facies 1B is dark-black, carbonaceous shale with interbedded coal.

Figure 3.11. Facies 1C. 9567.0 ft. Facies 1C is salt and pepper colored, fine-grained, and burrowed or rooted sandstone.

3.2.2.4 Facies 1D –Mudstone

Facies 1D is dark gray, heavily fractured shale with interbedded siltstone laminations near the top of the facies (Figure 3.12).

3.2.2.5 Facies 1E –Sandstone Lower Medium-Grained

Facies 1E is a salt and pepper colored, moderate-to well-sorted, lower medium-grained sandstone. Rip-up clasts are abundant at the base. Facies 1E is mainly massive with minor and faint cross-stratification near top (Figure 3.13).

3.2.2.6 Facies 1F – Sandstone Fine-Grained

Facies 1F is light-gray, moderate-to well-sorted, fine-grained sandstone with disseminated shale rip-up clasts. Porosity is poor (Figure 3.14).

3.2.2.7 Facies 1G – Sandstone Medium-Grained and Cross-Stratified

Facies 1G is a salt and pepper colored, moderate-to well-sorted, medium-grained, sandstone.

From base to top, Facies 1G is massive to cross-stratified. Planar shale laminations and rip-up clasts increase at the top of the sandstone. Porosity is fair to good (Figure 3.15).

3.2.2.8 Facies 1H – Sandstone Coarse-Grained

Facies 1H is light-gray to brown, coarse-grained, rubblized sandstone and appears to be poorly cemented and friable. Porosity is very good (Figure 3.16).

3.2.2.9 Facies 1I – Sandstone Medium-Grained Cross-Stratified

Facies 1I is a salt and pepper colored, moderate to well-sorted, cross-stratified, medium-

Figure 3.12. Facies 1D. 9564.0 ft. Facies 1D is heavily fractured dark-gray shale and interbedded siltstone.

Figure 3.13. Facies 1E. 9567.0 ft. Facies 1E is salt and pepper colored, massive to cross-stratified medium-grained sandstone.

Figure 3.14. Facies 1F. 9560.0 ft. Facies 1F is light-gray, fine-grained sandstone with disseminated rip-up clasts.

Figure 3.15. Facies 1G. 9558.0 ft. Facies 1G is salt and pepper colored, cross-stratified, medium- grained sandstone.

Figure 3.16. Facies 1H. 9556.0 ft. Facies 1H is coarse-grained sandstone.

grained sandstone that fines from base to top. Rip-up clasts are common at the top of facies.

Facies 1I has fair to good porosity. (Figure 3.17).

3.2.2.10 Facies 1J – Sandstone Fine-Grained

Facies 1J is a salt and pepper to light-gray, moderate-to well-sorted, very fine-to fine-grained

sandstone with common shale rip-up clasts throughout the facies (Figure 3.18).

3.2.2.11 Facies 1K – Sandstone Medium-Grained With Contorted Bedding

Facies 1K is salt and pepper colored, moderate-to well-sorted, highly contorted upper fine to

medium-grained sandstone with good porosity. Shale rip-up clasts are present near base of the sandstone, with rooted zones at top (Figure 3.19).

3.2.2.12 Facies 1L – Silt-Mudstone

Facies 1L is rust colored, fractured and contorted silty-mudstone (Figure 3.20).

3.2.3 Samson Resources Endurance #44-29 Core #2

The Endurance #44-29 Core #2 recovered 60 feet of sandstone, siltstone, and shale. Six

individual facies were recognized and catalogued.

3.2.3.1 Facies 2A – Mudstone

Facies 2A is light-to dark gray, heavily fractured mudstone. Fractures are commonly partly healed with calcite cement (Figure 3.21).

3.2.3.2 Facies 2B – Silt-Mudstone

Facies 2B is light to medium gray, bioturbated, and ripple laminated silty-mudstone. Facies

2B also has planar laminations, mottled bedding, and pyrite concretions (Figure 3.22).

Figure 3.17. Facies 1I. 9547.0 ft. Facies 1I is salt and pepper colored, moderate to well-sorted, cross- stratified, medium-grained sandstone.

Figure 3.18. Facies 1J. 9539.0 ft. Facies 1J is salt and pepper colored to light-gray, very fine-grained sandstone with shale rip-up clasts.

Figure 3.19. Facies 1K. 9527.0 ft. Facies 1K is salt and pepper colored, contorted, fine to medium- grained sandstone.

Figure 3.20. Facies 1L. 9525.0 ft. Facies 1L is rust- colored, fractured, and contorted silt-mudstone.

Figure 3.21. Facies 2A. 9828.0 ft. Facies 2A light to dark gray, heavily fractured mudstone.

Figure 3.22. Facies 2B. 9810.0 feet. Facies 2B is a light to medium gray, rippled and bioturbated silt- mudstone.

3.2.3.3 Facies 2C – Mudstone

Facies 2C is dark-gray to black, heavily rubblized mudstone (Figure 3.23).

3.2.3.4 Facies 2D – Carbonaceous Shale

Facies 2D is dark-gray to black, fractured carbonaceous shale that commonly grades above and below to coal. Fractures are partially healed with calcite cement. Some pyrite banding is present

(Figure 3.24).

3.2.3.5 Facies 2E – Siltstone

Facies 2E is light to medium gray, rippled laminated, and sparsely bioturbated siltstone to very fine-grained sandstone (Figure 3.25).

3.2.3.6 Facies 2F – Sandstone Medium-Grained

Facies 2F is salt and pepper colored, moderate to well-sorted, medium to coarse-grained sandstone. Contorted bedding is common and faint cross-stratification is present near the top of this sandstone. Shale rip-up clasts are present near the base. The facies has fair to good porosity

(Figure 3.26).

3.2.4 Samson Resources Endurance #44-29 Core #3

The endurance #44-29 Core #3 recovered 39 feet of sandstone, siltstone, and shale. Seven individual facies were recognized and catalogued.

3.2.4.1 Facies 3A – Mudstone

Facies 3A is dark-gray fractured mudstone (Figure 3.27).

Figure 3.23. Facies 2C. 9802.0 ft. Facies 2C is dark-gray to black mudstone.

Figure 3.24. Facies 2D. 9795.0 ft. Facies 2D is dark-gray to black, fractured carbonaceous shale.

Figure 3.25. Facies 2E. 9785.0 ft. Facies 2E is light to medium gray, ripple laminated, and sparsely bioturbated siltstone to very fine-grained sandstone.

Figure 3.26. Facies 2F. 9772.0 ft. Facies 2F is salt and pepper colored, moderate to well-sorted, medium to coarse-grained sandstone with intervals of contorted bedding.

Figure 3.27. Facies 3A. 9869.0 ft. Facies 3A is dark-gray fractured mudstone.

3.2.4.2 Facies 3B – Sandstone Very Fine-Grained

Facies 3B is light gray, ripple laminated, very fine-grained sandstone. Shale rip-up clasts are present at the scoured base. Porosity is fair (Figure 3.28).

3.2.4.3 Facies 3C – Siltstone

Facies 3C is medium gray to dark gray, ripple laminated, siltstone with poor to fair porosity

(Figure 3.29).

3.2.4.4 Facies 3D – Sandstone Fine-Grained and Cross-Stratified

Facies 3D is a brown, cross-stratified, fine-grained sandstone. Some bioturbation is evident near the gradational top. This facies fines from base to top. Porosity is fair to good. (Figure

3.30).

3.2.4.5 Facies 3E – Carbonaceous Shale

Facies 3E is dark gray to black, carbonaceous shale that grades above and below to coal

(Figure 3.31).

3.2.4.6 Facies 3F – Sandstone Medium-Grained Laminated

Facies 3F is salt and pepper colored, moderate to well-sorted, medium-grained sandstone. The sandstone has shale laminations, a scoured base, and gradational top. Porosity is good. (Figure

3.32).

3.2.4.7 Facies 3G – Sandstone Medium-Grained and Cross-Stratified

Facies 3G is salt and pepper to light brown, moderately sorted, cross-stratified and contorted,

Figure 3.28. Facies 3B. 9868.0 ft. Facies 3B is light- gray, ripple laminated, very fine-grained, sandstone with shale rip-up clasts at the scour base.

Figure 3.29. Facies 3C. 9867.0 ft. Facies 3C is medium gray to dark gray, ripple laminated siltstone to very fine-grained sandstone. Porosity is poor to fair.

Figure 3.30. Facies 3D. 9859.0 ft. Facies 3D is brown, well-sorted, cross-stratified, fine-grained, sandstone. The facies fines from base to top and has fair to good porosity.

Figure 3.31. Facies 3E. 9853.0 ft. Facies 3E is dark gray to black carbonaceous shale that grades at above and below to coal.

Figure 3.32. Facies 3F. 9849.0 ft. Facies 3F is salt and pepper colored, medium-grained sandstone with shale laminations.

64 medium-grained sandstone with abrupt basal and top contacts and fair to good porosity. Shale rip-up clasts are common near the base (Figure 3.33).

3.3 Facies Associations

Individual core facies were described and divided separately for each individual core. Based on similarities in log response, lithology, grain size, and sedimentary structures, individual facies were grouped into facies associations (Table 3.1). Four facies associations are interpreted; active channel fill, abandoned channel fill, channel margin, and floodplain.

3.3.1 Active Fluvial Channel Fill

Active channel fill deposits are cross-stratified, medium-grained sandstones with some normal grading (Appendix B.1-B.4). Abrupt basal contacts have significant shale rip-up clasts.

Active channel fill facies are associated with the highest quality reservoir. The best example is in

Facies G of the Barricade #33-12. Facies G shows relatively higher core permeabilities compared to adjacent sandstone Facies H and F (Appendix B.1, Figure 3.34). The active channel fill association in the Endurance #44-29 cores include facies 1E, 1G, 1H, 1I, 1K, 2F, and 3G

(Appendix B.2-B.4). Facies 1E-1K appear to be amalgamated multistoried sandstones associated with uninterrupted channel migration (Figure 3.35). Coarser grained detritus, scoured basal contacts, and sand-on-sand contacts indicate high energy flow regimes, channel migration, and erosional and subsequent deposition. This assemblage and associated facies are the highest quality reservoir rocks.

3.3.2 Abandoned Channel Fill

Abandoned channel fill deposits are very fine to fine-grained sandstone and shaley

Figure 3.33. Facies 3G. 9837.5 ft. Facies 3G is salt and pepper colored, cross-stratified, medium-grained sandstone.

Table 3.1. Individual core facies, bed forms, distinguishing characteristics, and depositional setting.

Figure 3.34. Barricade #33-12 detail description showing interpreted abandoned (orange-

F and H) and active channel fill (yellow-G) sandstones. AC: abrupt contact.

Figure 3.35. Endurance #44-29 Core #1 detail description showing interpreted individual amalgamated and multi-storied sandstones. AC: abrupt contact, GC: gradational contact.

sandstone. These sandstones indicate a decrease in depositional energy associated with channel

switching or avulsion and associated abandonment. Abandoned channel facies were identified in

all four cores (Appendix B.1-B.4). Contacts with active channel fill deposits are abrupt

indicating swift abandonment (Figure 3.34). As the amount of shale and mud increases and grain size decreases, core permeabilities diminish. These facies may be baffles or limited

barriers to reservoir connectivity. These sandstones are poor to fair reservoir rocks.

3.3.3 Channel Margin

Channel margin facies occur at or very near fluvial channel margins and include levee and

crevasse splay facies within the study area.

3.3.3.1 Levee

Levee deposits are poorly developed and difficult to recognize in cores, and most likely are

limited volumetrically relative to other facies. Levee facies are ripple laminated siltstone and

very fine-grained sandstone and are overlain by floodplain mud rocks in the Barricade #33-12

core (Appendix B.1). Levee deposits are absent or poorly developed where inter-channel fines

do not confine stream flow and channel migration. Where levee facies are preserved, complete

fluvial stacking may be present (Figure 3.36). Levee facies have poor porosity.

3.1.1.1 Crevasse Splay

Crevasse splays may also be considered avulsed channel fill in the data set. These deposits

are representative of breaches in either temporary or longer lived-channel boundaries, and are

interpreted to be deposited in near channel portions of the floodplain. Dependent on the

sediment load and rate of deposition of the avulsed channel, crevasse splays are a heterogeneous

Figure 3.36. Barricade #33-12 detail description showing interpreted high-sinuosity channel succession. Levee (light brown) deposits are overlain by floodplain mud rocks, coals, and carbonaceous shales (gray). A2 indicates the second occurrence of Facies A in this core.

assemblage of bed forms and grain sizes within the data set. In general, they are short-lived,

sandstone depositional pulses that were subsequently enclosed in floodplain mud rocks (Figure

3.37). Grain sizes range from silt to fine-grained sand. Beds are ripple laminated, cross-

stratified, and have intervals with shale rip-up clasts (Appendix B-1-B.4). This facies may be

good reservoir rock, but the rocks are isolated by surrounding shales and may be significantly

compartmentalized.

3.1.2 Floodplain Deposits

A floodplain is land immediately bordering a fluvial channel and is normally inundated during

ephemeral flooding (Bridge, 2006). Floodplain facies, within the study data set, include mud

rocks, carbonaceous shales, and coal.

3.1.2.1 Mud Rock

Mud rocks are present in the inter-channel floodplain as silty-mudstones and shales

(Appendix B.1-B.4). This facies is proximal to channel margins, and where present, commonly

caps levee deposits (Figure 3.37). Mud rock facies are generally overlain by carbonaceous

shale. Fractures in mud rocks are probably related to expulsion of hydrocarbon (Hunt, 1996).

Mud rocks, in some cases, may create significant lateral and vertical seals to reservoirs and may impede hydrocarbon migration and increased compartmentalization.

3.1.2.2 Carbonaceous Shale

Carbonaceous shales are present in all cores, and are heavily fractured, organic-rich, and grade into interbedded and finely laminated coal beds (Appendix B.1-B.4 and Figure 3.37).

These rocks were deposited in interfluve floodplains where terrestrial plants flourished and later

Figure 3.37. Endurance #44-29 Core # 2 detail description shows crevasse splay deposits (dark brown) encased in floodplain mud rocks (gray). 2A3 indicates the third occurrence of Facies 2A in this core. 2D2 indicates the second occurrence of Facies 2D in this core.

73 decayed in relatively undisturbed conditions. Carbonaceous shales probably generated hydrocarbons, and their relative position to potential reservoirs is most likely a significant control on reservoir variability.

3.1.2.3 Coal

Coal is present as thin lenses within carbonaceous shales, and as a 1 foot thick bed (Facies D in the Barricade #33-12 core, Appendix B.1 and Figure 3.36). Coal deposition was in isolated swamps within the floodplain. Although coals may be locally extensive, it is difficult to correlate a given coal regionally. Depositional conditions were not constant in this fluvial dominated system.

3.2 Relationships in Facies, Measured Core Data, and Open-hole Log Data

Active channel facies have relatively higher core permeabilities and cleaner gamma ray signatures (Figure 3.38). These observations are not surprising, given the increased grain size, porosity, and less clay as observed in facies G (Appendix B.1). Some exceptions may exist that are undetectable by conventional open-hole logging suites (Figure 3.39). Facies 1K and 1L exhibit almost identical open-hole log characteristics (equivalent gamma ray, resistivity, and porosity). As a result of these quantifiable equivalencies in log data, it is possible to mistakenly consider these individual facies as one contiguous reservoir. This presents significant difficulty in accurate reservoir and reserve prediction. Current interpretations suggest there may be a relationship between a given facies and reservoir quality that is beyond the resolution of open- hole log data, specifically, high quality reservoirs appear to correlate to medium grained cross- stratified sands (Appendix B.1-B.4).

Figure 3.38. Barricade #33-12 data shows high quality active channel fill sandstones (yellow) and corresponding high permeabilities, gas effect, and gas show. Abandoned channel fill sandstones (orange) have decreased relative core permeabilities and suppressed porosities.

Figure 3.39. Endurance #44-29 core #1 data show equivalent open-hole log response for active channel fill sands (yellow) but relatively higher core permeabilities associated with facies 1I; illustrating reservoir heterogeneity that may be undetectable by conventional open-hole logs.

3.3 Depositional Environment

Open-hole log and core data indicate periods of confined fluvial deposition (Figure 3.40).

Fluvial deposition appears to occur primarily as upper fine-to coarse-grained multistory, multilateral, and amalgamated sand bodies. Periods of reduced inter-channel fines are present,

and channel boundaries are marked by abrupt scoured contacts related to poorly constrained

channel migration. Intervals of normal grading are present. These intervals might be discrete

and longer lived channel deposition; however, it is difficult to quantify given the limitations of

the data. Given plausible variations in provenance, it is conceivable that as the clastic source

varied through time, so did depositional trends and fluvial architecture. Further, if clastic source

alternated from a more local source to a more regional, one might expect variations in stream

gradient, sediment load, and energy, ultimately influencing fluvial deposition.

Longer lived, local and regional floodplain deposits are present in cores and evident in logs,

representing more confined fluvial deposition. These deposits are marked by thick mudstones

and carbonaceous shales that laterally grade to coals, and potentially are significant contributors

to the hydrocarbon source within the system.

3.4 Summary

Amalgamated sand packages can create the illusion of a contiguous reservoir; however,

significant variability in reservoir quality may exist between specific channel facies that are

beyond the resolution of conventional open-hole logging suites. This variability could be a

strong control on reservoir productivity and overall well performance. More core data are

needed to justify a conclusion related to the benefits of certain facies, relative local

pervasiveness, connectivity, and subsequent implications on field development.

Figure 3.40. This is a diagram of typical meandering fluvial succession including channel, levee, and floodplain deposits (Fichter, 2000).

CHAPTER 4

FORT UNION FORMATION FACIES PETROGRAPHY AND MINERALOGY

Mineralogy for representative samples of relevant facies was determined using x-ray diffraction, scanning electron microscope, and thin section petrography. Samples from the

Barricade #33-12, Endurance #44-29, and Barricade #21-11 were evaluated.

4.1 X-Ray Diffraction (XRD) Analysis

XRD is the semi-quantitative identification of sample mineralogy. Clay-size fraction is removed from the bulk material and analyzed separately. Samples are typically glycolated to identify swelling clays, and heated, if necessary, to identify chlorite. This analysis provides identification of all inorganic crystalline compounds present in significant amounts, as well as all of the various clay minerals species, including the composition (% smectite layers) of the mixed- layer clays. Identification of minerals is based on comparison with reference standards provided by the International Centre for Diffraction Data database (Core Lab, 2014).

4.2 XRD Results

4.2.1 Barricade #33-12

Three samples from the Barricade #33-12 were analyzed using XRD for whole rock and clay fraction. Samples averaged 75.9% quartz, 3.5% K-feldspar, 5.5% plagioclase, 2.1% dolomite, 1.1% siderite, and trace amounts of pyrite. Clay fraction averaged 52.6% mixed layer illite/mica and 23.0% chlorite (Table 4.1).

4.2.2 Endurance #44-29

Eight samples from the Endurance #44-29 were analyzed using XRD for whole rock and

Table 4.1. XRD Data: Cores, facies and corresponding mineral assemblages and quantities.

80 clay fraction. Samples averaged 66.1% quartz, trace K-feldspar, 3.8% plagioclase, 2.3% calcite,

3.5% dolomite, 1.0% siderite, and trace pyrite. Clay fraction averaged 8.8% mixed layer illite/smectite, 7.7% illite and mica, 3.6% kaolinite, and 2.5% chlorite (Table 4.1).

4.2.3 Barricade #21-11

Five samples from the Barricade #21-11 were analyzed using XRD for whole rock and clay fraction. Samples averaged 75.8% quartz, trace K-feldspar, 2.3% plagioclase, trace calcite,

4.8% dolomite, trace siderite, and trace pyrite. Clay fraction averaged 5.4% mixed layer illite/smecite, 6.1% mixed layer illite/mica, 1.5% kaolinite, and 1.6% chlorite (Table 4.1).

4.3 Scanning Electron Microscope (SEM) Analysis

SEM provides for visual documentation of pore geometry and distribution of clay and/or other authigenic minerals (zeolites, pyrite, calcite, etc.) associated with the pore system of a rock

(Core Lab, 2014).

4.4 SEM Results

4.4.1 Barricade #33-12

Appendices C.1- C.6 catalogue the results of SEM analysis on 6 samples from the Barricade

#33-12 core. Observations identifying detrital grains and clays, diagenetic cements, authigenic minerals, and authigenic clays are summarized in Table 4.2.

4.5 Petrographic Methods

One inch wide thin-sections were prepared by various third-party vendors for relevant reservoir samples. Preparation included blue epoxy for porosity identification, red fluorescent epoxy for epifluorescence analysis, and alizarin red stain for calcite identification. Thin-section

Table 4.2. Barricade #33-12 SEM Data: Cores, facies and corresponding authigenic grains, accessory grains, clay matrix, secondary porosity (Ps), and grain size. Abbreviations: Qtz – quartz, D – dolomite, I/SM – mixed layer illite/smectite, Sd – siderite, Ch – chert, ARF – argillaceous rock fragments, CRF – carbonate rock fragments, VRF – volcanic rock fragments, Plag – plagioclase, Kspar – K-feldspar, LF – lower fine, UF – upper fine, LM – lower medium.

samples were evaluated for framework grain mineralogy, secondary porosity, cementation, and

micro-fracturing. Inferences on porosity quality were made using a qualitative scale ranging

from poor to good. Poor porosity has very little intergranular and/or secondary intragranular

porosity and minor amounts of pore connectivity. In these samples, pore space may never have

been developed or has been diagenetically occluded. Fair porosity has moderate amounts of

intergranular and/or secondary intragranular porosity and pore connectivity, however some pores may be occluded by authigenic cements or dissolution of framework grains may not be as pervasive and complete. Samples with good porosity have increased quantities of intergranular and/or secondary intragranular porosity and pore connectivity. In these samples, sparse cement occluded pore space and secondary porosity is abundant. In all samples with porosity, secondary porosity is abundant.

4.6 Petrographic Descriptions

Representative examples of each relevant facies are described, in detail, in the following section.

4.6.1 Facies H

Well: Barricade #33-12 Depth: 10143.20 Microfacies Description: fine-grained sandstone Lithology: sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: fine Grain Shape: angular to sub-rounded Sorting: moderate Pore Types: intergranular and secondary Visible Porosity: 2-5% Cements: clay and quartz

Paragenesis: compaction and quartz overgrowth Neomorphism and Replacement: None Reservoir Quality: poor-fair Appendix: D.1, D.2

4.6.2 Facies G

Well: Barricade #33-12 Depth: 10161.20 Microfacies Description: medium-grained sandstone Lithology: Sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: medium Grain Shape: angular to sub-rounded Sorting: moderate Pore Types: intergranular and secondary Visible Porosity: 5-8% Cements: clay and quartz Paragenesis: compaction and quartz overgrowth Neomorphism and Replacement: none Reservoir Quality: good Appendix: D.3, D.4

4.6.3 Facies F

Well: Barricade #33-12 Depth: 10163.20 Microfacies Description: lower fine-grained sandstone Lithology: sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: lower fine Grain Shape: angular to sub-rounded Sorting: moderate to well Pore Types: intergranular and secondary Visible Porosity: 0-2% Cements: clay, quartz, and calcite Paragenesis: compaction, quartz overgrowth, and precipitation of calcite Neomorphism and Replacement: calcite 84

Reservoir Quality: poor Appendix: D.5, D.6

4.6.4 Facies 1K

Well: Endurance #44-29 Core #1 Depth: 9528.15 Microfacies Description: upper fine-grained sandstone Lithology: sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: upper fine Grain Shape: angular to sub-rounded Sorting: moderate to well Pore Types: intergranular and secondary Visible Porosity: 5-8% Cements: trace calcite, trace quartz Paragenesis: compaction, quartz overgrowth, and precipitation of calcite Neomorphism and Replacement: calcite Reservoir Quality: fair Appendix: D.7-D.9

4.6.5 Facies 1J

Well: Endurance #44-29 Core #1 Depth: 9539.55 Microfacies Description: lower fine-grained sandstone and shale Lithology: sandstone and shale Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: lower fine Grain Shape: angular to sub-rounded Sorting: poor Pore Types: intergranular Visible Porosity: 1-3% Cements: clay Paragenesis: compaction, clay Neomorphism and Replacement: trace calcite Reservoir Quality: poor Appendix: D.10-D.12 85

4.6.6 Facies 1I

Well: Endurance #44-29 Core #1 Depth: 9548.0 Microfacies Description: medium-grained sandstone Lithology: sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: medium Grain Shape: angular to sub-rounded Sorting: moderate to well Pore Types: intergranular and secondary Visible Porosity: 5-8% Cements: trace quartz, trace calcite Paragenesis: compaction, quartz overgrowth Neomorphism and Replacement: trace calcite Reservoir Quality: good Appendix: D.13-D.15

4.6.7 Facies 1G

Well: Endurance #44-29 Core #1 Depth: 9559.55 Microfacies Description: lower medium-grained sandstone Lithology: Sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: lower medium Grain Shape: angular to sub-rounded Sorting: moderate Pore Types: intergranular and secondary Visible Porosity: 2-5% Cements: trace quartz, trace calcite, minor dolomite Paragenesis: compaction, quartz overgrowth Neomorphism and Replacement: None Reservoir Quality: poor to fair Appendix: D.16-D.18

4.6.8 Facies 1C

Well: Endurance #44-29 Core #1 Depth: 9567.20 Microfacies Description: middle fine-grained sandstone Lithology: sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: middle fine Grain Shape: angular to sub-rounded Sorting: moderate to well Pore Types: intergranular and secondary Visible Porosity: 1-4% Cements: quartz, calcite, dolomite, and siderite Paragenesis: heavy compaction, quartz overgrowth Neomorphism and Replacement: calcite Reservoir Quality: poor Appendix: D.19-D.21

4.6.9 Facies 2F

Well: Endurance #44-29 Core #2 Depth: 9772.15 Microfacies Description: upper medium to coarse-grained sandstone Lithology: sandstone Allochems: N/A Matrix: Clay Crystal Size: N/A Crystal Shape: N/A Grain Size: upper medium to coarse Grain Shape: angular to sub-rounded Sorting: moderate Pore Types: intergranular and secondary Visible Porosity: 2-6% Cements: quartz, calcite, dolomite, and siderite Paragenesis: heavy compaction, quartz overgrowth Neomorphism and Replacement: trace calcite Reservoir Quality: fair to good Appendix: D.22-D.24

4.6.10 Facies 2B

Well: Endurance #44-29 Core #2 Depth: 9815.20 Microfacies Description: upper very fine-grained sandstone Lithology: sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: upper very fine Grain Shape: angular to sub-rounded Sorting: moderate to well Pore Types: trace secondary Visible Porosity: 1-3% Cements: trace calcite Paragenesis: compaction Neomorphism and Replacement: trace calcite Reservoir Quality: poor Appendix: D.25-D.27

4.6.11 Facies 3G

Well: Endurance #44-29 Core #3 Depth: 9840.9 Microfacies Description: lower medium-grained sandstone Lithology: sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: lower medium Grain Shape: angular to sub-rounded Sorting: moderate to well Pore Types: intergranular and secondary Visible Porosity: 4-8% Cements: minor quartz and trace calcite Paragenesis: heavy compaction Neomorphism and Replacement: minor calcite Reservoir Quality: good Appendix: D.28-D.30

4.6.12 Facies 3D

Well: Endurance #44-29 Core #3 Depth: 9859.40 Microfacies Description: middle fine-grained sandstone Lithology: sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: middle fine Grain Shape: angular to sub-rounded Sorting: well Pore Types: intergranular and secondary Visible Porosity: 2-5% Cements: minor quartz and trace calcite Paragenesis: compaction Neomorphism and Replacement: trace dolomite and pyrite Reservoir Quality: poor-fair Appendix: D.31-D.33

4.6.13 Facies 3C

Well: Endurance #44-29 Core #3 Depth: 9866.35 Microfacies Description: lower very fine-grained sandstone Lithology: sandstone Allochems: N/A Matrix: clay Crystal Size: N/A Crystal Shape: N/A Grain Size: lower very fine Grain Shape: angular to sub-rounded Sorting: well Pore Types: intergranular and secondary Visible Porosity: 1-3% Cements: minor quartz and trace calcite Paragenesis: compaction Neomorphism and Replacement: trace dolomite and pyrite Reservoir Quality: poor Appendix: D.34-D.36

4.7 Interpretation of Mineralogical Results

4.7.1 Framework Grains

Detrital grains observed in all thin-section samples include primarily quartz. Quartz appears as monocrystalline grains with variable percentages of disseminated dark gray to black chert grains (salt and pepper appearance). Quartz grains are generally sub-rounded to angular.

Plagioclase is sparse and its inferred dissolution is a primary driver for secondary porosity generation. Potassium feldspar is present but in trace or minor quantities. Lithic grains and fragments are contributors to grain assemblages and include chert fragments and argillaceous, metamorphic, and volcanic grains. Accessory grains include primarily biotite, muscovite, and organic matter with variable quantities of chlorite (Appendix C and D).

4.7.2 Pore Types

Pore types are both intragranular (secondary) and intergranular. Primary intragranular porosity is a result of dissolution of unstable framework grains, probably plagioclase feldspar

(Figure 4.1). Feldspar dissolution can be observed in SEM and thin section at varying stages.

Facies with increased porosity and permeability correlate to increased feldspar dissolution.

Some primary intergranular porosity is visible; however, it is often occluded by quartz overgrowths, calcite cement, or authigenic clay (Appendix C and D).

4.7.3 Cementation

Calcite is a dominant cement throughout the data set. In lesser amounts, authigenic quartz, siderite, pyrite, and dolomite are observed in some samples as cements and replacing grains (Figure 4.2).

Figure 4.1A. Thin section photomicrograph from the Endurance #44-29 Core #1 Facies 1I, illustrating secondary porosity (Ps) via dissolution of unstable framework grains. Pore space stained with red fluorescent epoxy. Quartz (Q), Chert (Ch), and organic matter (Om). Depth: 9548.0, Magnification: 63X, Plane Light.

Figure 4.1B. Thin section photomicrograph from the Endurance #44-29 Core #1 Facies 1I, illustrating secondary porosity (Ps) via dissolution of unstable framework grains

Depth: 9548.0, Magnification: 63X, Fluorescent Light.

Figure 4.2. Thin section photomicrograph from the Barricade #33-12 Facies F, illustrating calcite cement (Ca) highlighted by alizarin red stain. Quartz (Q), Potassium Feldpsar (Kspar). Depth: 10163.20, Magnification: 63X, Plane Light.

4.7.4 Microfracturing – Epifluorescence

Microfracturing may be a significant contributor to porosity and permeability. Intergranular and intragranular fractures are present in some samples, and where present, are readily visible

with fluorescent light (Figure 4.3). Epifluorescence enhances the ability to observe qualitative differences in porosity and permeability. An immediate relationship is observed between reservoir quality and porosity under fluorescent light in all samples. Higher porosity samples show stronger fluorescence, while the inverse is true for samples with lower porosity.

4.8 Clues to Provenance

Tectosilicates are the most important rock forming minerals on earth, and quartz and

plagioclase feldspar are the most abundant (Raymond, 2002). Tectosilicates are present in

plutonic and volcanic rocks. Phyllosilicates, or sheet silicates, are a primary constituent of

igneous rocks and include biotite, muscovite, and chlorite (Raymond, 2002). Clastic sources for

Fort Union sands in the Washakie Basin are most likely plutonic or metamorphic in origin, and

include the Wind River and Uintah mountains (Johnson, 1990; Kirschbaum,1994).

4.9 Summary

Reservoir sandstones in the Fort Union formation are primarily feldspathic litharenites,

litharenites and sublitharenites (Figure 4.4). Reservoir quality appears to vary on a relatively

small scale, and inferred dissolution of feldspar framework grains is a key driver of porosity in

high quality sands. The overall mineralogical assemblage suggests a clastic source that is

plutonic and/or metamorphic in origin. These data will be combined, in chapter 6, with regional

paleocurrent data in order to better support a provenance model.

Figure 4.3. Thin section photomicrograph from the Endurance #44-29 Core #1 Facies 1G. Photomicrograph illustrates intergranular and intragranular fractures. Thin section stained with fluorescent epoxy. Depth: 9559.55, Magnification: 63X, Fluorescent light.

Figure 4.4. Folk (1974, 1980) sandstone classification showing plotted Fort Union sandstones. Sandstones are primarily litharenites, sublitharenites, and feldspathic litharenites.

CHAPTER 5

WASHAKIE BASIN FORT UNION FORMATION THERMAL MATURITY

Liquid yield is an obvious and significant contributor to the profitably of the Fort Union

Formation in the study area and little is known regarding its source. Some source rock and

maturity data exist that suggests production should be primarily gas, therefore the high liquids

yield is somewhat troublesome and should be a focus as it pertains to the overall petroleum

system. Regional published maturity data provides a modest framework for the overall source

maturity within the study area and can be corroborated with proprietary data. However, in light

of insufficient data, significant uncertainty still exists in identifying liquid-prone source rocks.

While concrete conclusions are not obvious, some possibilities for these source rocks can be

proposed.

5.1 Regional Maturity

Generally, local carbonaceous shales within the Lance and Fort Union formations are

considered to be the primary hydrocarbon source rocks within the study area (USGS, 2005).

These apparent source rocks are primarily derived from Type III kerogens and therefore are

considered to produce mainly gas (Peters, 1986). Published regional work suggests hydrocarbon

generation occurs between vitrinite reflectance (Ro) values of 0.7 and 1.1 for Type III kerogens

(USGS, 2005). Data from producing Fort Union wells within the study area closely match the

published Ro window between 0.8 and 1.1 (Figure 5.1).

5.2 Organic Petrology

Vitrinite reflectance is used as a qualitative measure of thermal stress and as a proxy to

Figure 5.1. Vitrinite reflectance at the base of the Paleocene Fort Union Formation in Southwestern Wyoming. Study area outlined in black dash, contemporary Fort Union production highlighted with red oval (Modified from USGS, 2005).

thermal maturation. Visual kerogen analysis provides for the recognition and distribution of specific kerogen maceral classes in a given rock. These analyses can provide insight into the

thermal history and hydrocarbon source capacity of a given source rock.

5.3 Organic Petrology Results

Seven samples were analyzed by organic petrography from the Barricade #21-11 and two

samples from the Endurance #44-29 (Table 5.1). Primary observed macerals were vitrinite with

minor and trace amounts of inertinite and liptinite. Vitrinite is a component of Type III kerogen

and as such is gas prone. Inertinite, generally, consists of reworked organic matter and is

considered to be inert and non-hydrocarbon bearing. Liptinite is a Type II kerogen maceral, oil

and gas prone, and here, is associated with coal. Presence of Type II kerogen could provide

insight into the source of liquids within the study area.

5.4 Potential Liquid-Prone Source Rocks

5.4.1 Migration from Deeper Source Rocks

Given that the majority of kerogens are Type III, it seems logical that liquid

hydrocarbons could have migrated from deeper source rock horizons to porous Fort Union sands.

Vehicles for migration could include fractures and faults (USGS, 2005). Organic-rich shales in

the Cretaceous Almond and Lewis formations could have generated and expelled a significant

portion of the liquid hydrocarbons sourcing Fort Union reservoirs. Organic-rich Lewis and

Almond Formation shales locally have been shown to contain Type II/III kerogens and could

under certain thermal conditions generate, expel, and migrate liquid hydrocarbons to shallower

reservoirs (Pasternack, 2006; Coalson, 2011).

Table 5.1. Organic petrology results for various samples showing an abundance of Vitrinite, a Type III kerogen maceral and trace amounts of Liptinite, a Type II kerogen maceral. Ro: Vitrinite reflectance under oil.

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5.4.2 In-situ Coals and Carbonaceous Shale

In general, coals are hydrogen poor and generate only gas. However in some cases, coals with hydrogen indices between 200 and 300 and certain types of organic matter, mainly associated algal, pollen, and spore components, have been documented to produce significant quantities of liquid hydrocarbons (Fleet and Scott, 2014). In these cases, the elevated hydrogen content allows for the generation of hydrogen-rich gases and liquids, ultimately sourcing oils or liquids-rich gases with associated condensate (Van Kooten, 2012). This might also be true for other formations in the basin. Source rocks in the upper Almond Formation in the Washakie

Basin contain hydrogen rich Type III kerogens and are hypothesized by some authors to potentially source liquid hydrocarbons (Garcia-Gonzalez and Surdam, 1992, 1995). Given the occurrence of liptinite and sporinite, Type II kerogens sourced by pollen and spores, in sampled coals in the study area, it might also be plausible that these coals could source liquid hydrocarbons, however more data are needed to further develop this possibility.

5.5 Summary

Hydrocarbon source rocks are potentially numerous within the study area and are likely a combination of local interbedded coals, carbonaceous shales and deeper organic-rich shales

(Figure 5.2). Migration of high pressured gas from a deeper source has been hypothesized as a primary source component in an analogue field in the Piceance Basin. Here, vertical migration of gas from coal and shale beds in the Cretaceous Williams Fork Formation to overlying strata in the Wasatch and Green River Formations has been documented by carbon isotope analysis

(Cumella, 2008). It’s conceivable that this concept could also be a primary source component in the Washakie Basin. Highly pressured gas in coals and shales within the Cretaceous Almond

101

Figure 5.2. Two source concept as hypothesized for the Washakie Basin, showing in-situ gas charge as well as deeper migration (modified from Cumella, 2008).

102 and Lewis Formations could have migrated vertically and preferentially through areas of increased structural complexity. Reservoir heterogeneity could perpetuate as lenticular sands are preferentially charged via fractures from depth and by variable in-situ source rock thicknesses and concentrations.

103

CHAPTER 6

WASHAKIE BASIN FORT UNION FORMATION DEPOSITIONAL MODEL

Understanding the inherent variability in reservoir quality is critical in any oil and gas play.

This variability can be significantly influenced by depositional heterogeneity, and therefore it is

essential to establish a data-supported depositional model. Primary data inputs for the

depositional model include regional paleogeography, literature, regional and local paleo-current

data, subsurface image logs, facies associations, core descriptions, mineralogy, thin section

petrography, and XRD data. These data were combined and integrated to generate a depositional

model. It is likely that depositional rates, sediment load, provenance, accommodation space, and

stream gradients have greatly influenced deposition of the Fort Union Formation. These

variations may not be completely captured, given the resolution of the data analyzed. Therefore,

the proposed depositional model represents a specific data set, and is expected to be refined with

additional data.

6.1 Model Inputs

6.1.1 Regional Paleogeographic Position

Paleogeographic reconstructions for the early Paleocene place southwestern Wyoming in

a landlocked continental depositional setting (Figure 6.1). At the beginning of the Tertiary, the

Washakie Basin is completely surrounded by Laramide-age uplifts. Due to the relative distance from the sea, Fort Union Formation deposition in the Washakie Basin is most certainly continental-fluvial. Throughout geologic time, controls on Fort Union deposition were dynamic and created significant variability in internal reservoir configurations. Further, fluvial architecture would have been significantly influenced by variations in provenance that include

104

Figure 6.1. Paleogeographic reconstruction of North America during the Early Paleocene. Wyoming: white outline; study area: red star (Modified from Blakey, 2011).

105 distance from source, modes of sediment transport, and periodic breaks in deposition. High rates of subsidence created ideal conditions for source rocks to be developed and preserved.

Carbonaceous shales and coals are significant contributors to hydrocarbon volumes in these fluvial sandstone reservoirs.

6.1.2 Paleo-current Data

Paleo-current data from published USGS work and dip meter data from a Halliburton focused microimager log (FMI) were used to establish regional and local paleo-current context

(Figure 6.2). In this study, paleo-current analyses in the China Butte Member of the Fort Union

Formation focused on azimuthal trends. These analyses indicate a variable paleo-current data set that is centered on 115 degrees.

6.1.2.1 USGS Outcrop

Regional paleo-current data from outcrop work on the Eastern Washakie Basin indicate an easterly flow direction (Figure 6.3). Sixty three paleo-current measurements were taken in the

China Butte Member of the Fort Union Formation. These measurements indicate a mean direction of 75 degrees. This average is consistent with published paleo-current data along the

Western Washakie Basin near the Rock Springs Uplift (Kirschbaum, 1994).

6.1.2.2 Endurance #42-10

Dip meter data collected from an FMI log in the Endurance #42-10 were used to evaluate possible paleo-current trends in the China Butte Member within the study area. Thirty seven paleo-current azimuths were interpreted and show variable paleo-current directions (Figure 6.4).

This variability could be representative of a higher sinuosity channel pattern. In contrast, one

106

Figure 6.2. Location of USGS outcrop China Butte Member paleo-current data (blue star) and Endurance #42-10 FMI China Butte dip meter paleo-currents (red star). Top China Butte Member structure map; C.I. = 100 feet. Study area: outlined in red. Fort Union Formation outcrop: orange.

107

Figure 6.3. Paleo-current azimuth from China Butte Member, showing a mean direction of 75 degrees (Modified from Hettinger et. al., 2006).

108

Figure 6.4. Interpreted paleo-current directions and FMI log from the China Butte Member of the Endurance #42-10. While average paleo-current direction is 115 degrees, significant variability (outcrop = 75 degrees) exists within the dataset which could suggest higher sinuosity channel flow.

109

might expect a unimodal paleo-current direction in low-sinuosity and braided fluvial

environments.

6.1.3 Facies Associations

Facies associations provide clues to depositional settings and are a key component to

framing the depositional model within the study area. Associations include active channel fill,

abandoned channel fill, channel margin, and floodplain. Through time, variations in depositional

cycles, clastic source, and topography most likely influenced fluvial deposition and architecture

over the entire China Butte Member. Therefore, the resolution of the data set may not be entirely representative of the entire Fort Union Formation.

The Barricade #33-12 is the most complete core available in this study and will be referenced heavily for conclusions regarding depositional setting. The core contains all four facies associations described in Chapter 4: channel margin, floodplain, abandoned channel fill, and active channel fill (Figure 6.5). This core includes a partial meandering fluvial succession in

which migrating multistoried channels are preserved.

Facies A in the Barricade #33-12 is upper channel levee deposits. Contained within these

siltstones and very fine-grained sandstones are ripples, planar lamination, and burrow mottling.

Levee deposits are overlain by floodplain deposits including Facies C, D, and E. Facies C

overlies levee deposits in the Barricade #33-12 and consists of heavily fractured and often rooted

mudrock. This floodplain deposit is overlain by Facies D and E, sub-bituminous coal and

carbonaceous shales. These facies are examples of floodplain and back swamp deposits typical

of interfluve environments, and are probably significant contributors to hydrocarbons within the

system. Facies B is interpreted to be a representative example of a crevasse splay and is

110

Figure 6.5. Barricade #33-12 core description interpreted as a partial meandering fluvial succession. Facies A – levee; Facies B – crevasse splay; Facies C – overbank mudrock; Facies D – coal; Facies E – carbonaceous shale; Facies F – abandoned channel fill; Facies G – active channel fill.

111

classified within the channel margin facies association. Flooding conditions can create avulsions in weaker levee walls and deposit finer-grained sandstones and siltstones into the floodplain

(Beaumont, 1979). These deposits are generally isolated sand bodies in the greater floodplain

complex. Amalgamated and multistoried sand bodies are present in the Barricade #33-12 core.

These stacked channel bars show signs of migration by scoured, sand-on-sand contacts. Facies F

is fine-grained sandstone with increased clay and shale concentration and is abandoned channel

fill. An upper scoured surface is overlain by Facies G. This sand-on-sand contact is younger

active channel migration over an older abandoned channel. Facies G is cross-stratified, medium-

grained, active channel-fill sandstone (Figure 6.5). Active channel-fill sandstones comprise the highest quality rock in the data set, and are significant contributors to productivity.

6.1.4 Mineralogy and Provenance

Specific mineralogical assemblages can be diagnostic of clastic source and sediment transport distance. Mineralogical data from SEM, XRD, and thin section petrography were compared for compositional similarities. These data show significant percentages of quartz, chert, feldspars, biotite, muscovite, and minor amounts of chlorite grains. The relative abundance of these detrital grains indicates a clastic source that is plutonic and/or metamorphic in origin. The pervasive angularity of grains indicates proximity to provenance. Adjustments in clastic source through time cannot be completely recognized in this study given inherent limitations in data resolution. It is conceivable that the clastic sources relocated several times over Fort Union history, creating variable depositional profiles at given times. Possible regional

and local clastic sources for Fort Union sand deposition include the Wind River Range and Uinta

Mountains (Figure 6.6). During the early Paleocene, exposed Mesozoic metamorphic rocks of

the Uinta Mountain Group and plutonic and metamorphic rocks have been documented as clastic

112

Figure 6.6. Green River Basin and surrounding Laramide uplifts and general compositions. Study area: red dash (Modified from Kirschbaum, 1994).

113 sources near the Rock Springs Uplift (Kirschbaum, 1994). These mountain ranges most likely continued sourcing Fort Union sediments. Core mineralogy is consistent with expected mineral assemblages: plutonic and metamorphic rock fragments and feldspar-rich sandstones.

6.2 Depositional Model

 Fort Union Formation deposition in the Washakie Basin was within a continental-fluvial

setting (Figure 6.7 and 6.8). Channel, floodplain, and backswamp accumulations are

immediately recognizable in core sections and by wireline log response.

 Gamma ray electric log responses and outcrop work in the Red Rim Member of the

Lance Formation and other intervals within the China Butte Member of the Fort Union

Formation indicate transitions in depositional patterns. This suggests periods of braided,

low sinuosity fluvial deposition in addition to meandering fluvial deposition (Figure

6.9).

 China Butte Member paleo-current data are variable, which most likely indicate high

sinuosity channel flow typical of a meandering stream.

 Regional clastic source is most likely a combination of Uinta Mountains and the Wind

River Range, as mineralogical components are primarily metamorphic and plutonic.

Regional and local paleo-current data indicate southern and then easterly stream flow

from these source areas.

6.3 Summary

Depositional setting within the study area is interpreted as continental fluvial with alternating cycles of high-sinuosity migrating fluvial belts and low-sinuosity braided channels (Figure 6.10).

Typical architectural components of a meandering fluvial system are present and include channel, floodplain, and back swamp deposits. Clastic source was cyclic and variable, and

114

Figure 6.7. Proposed Washakie Basin Fort Union Formation depositional model. Model represents typical high-sinuosity meandering fluvial succession as evidenced in core and wireline log data set.

115

Figure 6.8. Cross section of channel, channel margin, and floodplain environments (Modified from Weimer, 1973; Beaumont, 1979).

116

Figure 6.9. Proposed Washakie Basin Fort Union Formation depositional model. Model represents typical low-sinuosity braided fluvial deposition as detailed in core and wireline log data.

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Figure 6.10. Proposed Washakie Basin Fort Union Formation composite depositional model. Figure represents two phases of deposition: (1) low- sinuosity, high energy channel sands overlain by (2) high-sinuosity, low energy fluvial channel. Core and log correlations indicate high-sinuosity meandering channel belts.

118

primarily originated from the Wind River and Uinta Mountains. Shifts in provenance, deposition, and subsidence most likely influenced fluvial deposition within the Fort Union

Formation over time. Variations in fluvial deposition and patterns could vary in different stratigraphic intervals.

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CHAPTER 7

SUMMARY, DISCUSSION, CONCLUSIONS, AND RECOMMENDATIONS

FOR FUTURE RESEARCH

The main objective of this study was to establish a depositional model for the Fort Union

Formation in the Washakie Basin, and investigate possible controls on reservoir heterogeneity.

7.1 Conclusions

The following are study conclusions:

7.1.1 Core Facies

 Cross-stratified, coarser-grained, active channel facies correspond to better measured

core porosity and permeabilities and include Facies G, 1G, and 1I. These facies are

upper fine to coarse-grained sandstones with significant secondary porosity.

 Floodplain facies associations are present in all available core data. Abundant interfluve

coals and carbonaceous shales are present throughout the study area.

 Channel margin facies including levee deposits and crevasse splays are present in the

core data set. Levee deposits consist of siltstones to very fine-grained sandstones, and

are commonly bioturbated, ripple laminated, and overlain by floodplain mud rocks.

Crevasse splay deposits are heterogeneous sandstones and siltstones that are encased and

isolated within floodplain deposits.

 Minor or abandoned channels are finer-grain sandstones with an increase in the

percentage of clay (shale).

 Abrupt and scoured contacts between sandstones indicate channel migration.

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7.1.2 Mineralogy

 Primary detrital grains consist of quartz with accessory grains of feldspar, chert,

metamorphic, argillaceous, and plutonic rock fragments.

 Sandstones are subfeldspathic to feldspathic litharenites, sub-litharenites, and

litharenites.

 Reservoir sandstones are medium to coarse-grained, well consolidated, and moderately

sorted.

 Reservoir porosity is primarily secondary, resulting from dissolution of less stable

feldspar framework grains and possibly rock fragments.

 Intergranular porosity is generally occluded by authigenic silica, calcite, and pyrite.

 Metamorphic, plutonic, and sedimentary constituents indicate variable clastic sources,

most likely originating from the Uinta and Wind River Mountains.

7.1.3 Depositional Environment

 Channel, channel margin, and floodplain facies are all typical of high-sinuosity fluvial

deposition.

 Regional and local paleocurrent data suggests variable stream flow directions.

 Pervasive coal deposition indicates long-lived hiatus between established and confined

fluvial channels.

7.1.4 Source Rocks

 Hydrocarbon source is bimodal - interbedded Fort Union coals and carbonaceous shales

and deeper migrated hydrocarbons.

 Local carbonaceous shales are composed of Type III kerogens that sourced primarily

gas.

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 Sporinite and liptinite in coal are Type II kerogen macerals that are capable of producing

liquid hydrocarbons, but these macerals may not be present in sufficient quantities.

 Migrated liquid hydrocarbons from deeper source rocks and interbedded coals are

feasible explanations for high liquid yields within the study area.

7.2 Discussion

Reservoir heterogeneity and facies predictability could adversely affect production and hydrocarbon-in-place numbers. Improper recognition of fluvial depositional trends could negatively impact development strategy and risk unnecessary capital. Outlined below are several reservoir components that may influence productivity.

7.2.1 Reservoir Connectivity

The depositional model assumes significant reservoir compartmentalization. High sinuosity channels are expected to be relatively discontinuous laterally and compartmentalized by floodplain mudstones. These mudstones most likely act as barriers to fluid migration and segregate productive reservoirs. Areas of vertical channel aggradation may create amalgamated reservoirs and increase the volume of potential targets. Development of this reservoir must be carefully approached in areas where subsurface data are sparse. Within amalgamated reservoirs, some heterogeneity still exists and is reflected in specific facies. Facies exert significant controls on well productivity, but facies predictability is difficult with available data sets.

7.2.2 Source Variability

Hydrocarbon liquid yield ratios are a central driver in current well economics. Higher liquid yields generate higher profit. Variable high liquid yields associated with contemporary

Fort Union production in the Washakie Basin are somewhat problematic. Hydrocarbon source and migration timing is currently uncertain. The actual yield ratio may be dependent on

122

preferential sourcing of reservoirs. Further, areas rich in natural fracturing and faulting may create better conditions to assist hydrocarbon migration from deeper, marine Type II kerogen source beds. Local floodplain thickness most likely also influences preferential sourcing of sandstone reservoirs. Sandstones adjacent to relatively thicker carbonaceous shales and coals are expected to be sourced at increased volumes, assuming similar organic quality, quantity, and thermal maturity.

7.2.3 Importance of an Integrative Reservoir Model

Discontinuous and heterogeneous reservoirs require a comprehensive and integrative approach to successfully prevent costly missteps. This study illustrates the variability in reservoir identification given different dataset resolutions. Well log data alone may incorrectly identify and, more importantly, incorrectly predict reservoir location and quality. These data must be integrated with available core, seismic, and production data to better quantify reservoir quality.

7.3 Recommendations for Future Research

 Additional data throughout the study area would be helpful in confining depositional

trends and fluvial patterns including core, vertical wells, 3D seismic, open-hole logs, and

production.

 A more robust core data set and correlations to open-hole logs would assist in a better

understanding of the pervasiveness and trends of higher quality productive facies.

 Verifying the hydrocarbon source history will have great implications on liquids yield

prediction as it is expected to vary significantly throughout the basin.

 3D seismic coherency and attribute mapping may uncover channel patterns, depositional

trends, and increased reservoir density.

123

REFERENCES CITED

Anderson, G.P., 2006, Geologic study of Powder Wash Field, Moffat County, Colorado: The Mountain Geologist, v. 43, no. 2, p. 135-144.

Beaumont, E.A., 1979, Depositional environments of the Fort Union sediments (Tertiary, Northwest Colorado) and their relation to coal: AAPG Bulletin, v. 63, no.2, p. 194-217.

Beck, R.A., Vondra, C.F., Filkins, J.E., and Olander, J.D., 1988, Syntectonic sedimentation and Laramide basement thrusting, Cordilleran foreland; timing of deformation, in Schmidt, C.J., and Perry, W.J., eds., Interaction of the Rocky Mountain foreland and Cordilleran thrust belt: Geological Society of America Memoir 171, p. 465-487.

Bishop, Michele G., 2000, Petroleum system of the Gippsland Basin, Australia. U.S. Geological Survey E-Bulletin: Open-File Report 99-50-Q.

Blakey, R.C., 2011, North American paleogeographic maps: Paleogene Paleocene (60ma), http://jan.ucc.nau.edu/rcb7/namPe50.jpg (accessed March 1st, 2014).

Coalson, E.B., 2011, Producibility of Almond Formation “tight” gas sandstones, Washakie Basin, Wyoming, USA, Ph.D. dissertation, Colorado School of Mines, Golden CO, USA, 351p. Colson, C.T., 1969, Stratigraphy and production of the Tertiary formations in the Sand Wash and Washakie Basins: Wyoming Geological Association Guidebook, p. 121-128. Cummela, S.P., and J. Scheeval, 2008, The influence of stratigraphy and rock mechanics on Mesaverde gas distribution, Piceance Basin, Colorado, in S.P. Cummela, K.W. Shanley, and W.K. Camp, eds., Understanding, exploring, and developing tight-gas sands, 2005 Vail Hedberg Conference: AAPG Hedberg Series, no. 3, p. 137-155.

Dickinson, W.R., Klute, M.A., Hayes, M.J., Janecke, S.U., Lundin, E.R., McKittrick, M.A., and Olivares, M.D., 1988, Paleogeographic and paleotectonic setting of Laramide sedimentary basins in the central Rocky Mountain region: Geological Society of America Bulletin, v. 100, p. 1023-1039.

Gonzales, M.G., R.C. Surdam, 1995, Hydrocarbon generation potential and expulsion efficiency in shales and coals: example from Washakie basin, Wyoming, Wyoming Geological Association Guidebook, p. 225-245.

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Hettinger, R. D., J.G. Honey, and D.J Nichols, 1991, Chart showing correlations of upper Cretaceous Fox Hills sandstone and Lance formation, and lower Tertiary Fort Union, Wasatch, and Green River formations, from the eastern flank of the Washakie Basin to the Southeastern part of the Great Divide Basin, Wyoming: Geological Survey Scientific Investigations Map 2151, 1 Plate. Hettinger, R.D., and J.G. Honey, 2005, Geologic map and coal stratigraphy of the Doty Mountain quadrangle, Eastern Washakie Basin, Carbon County, Wyoming: U.S. Geological Survey Scientific Investigations Map 2925, 17p. Johnson, Philip, L., 1990, Laramide basin subsidence and fluvial architecture of the Fort Union and Wasatch Formations, Southern Green River Basin, Wyoming, Master of Science, San Jose State University.

Katz, B.J., L.M. Liro, 1993, The Waltman Shale member, Fort Union formation, Wind River basin: a Paleocene clastic lacustrine source system: Wyoming Geological Association Guidebook, p. 163-174. Kirschbaum, M.A., D.W. Anderson, R.L. Helm, and R.J. Baldwin, 1994, Paleocene drainage systems, Rock Springs Uplift, Wyoming: The Mountain Geologist, v. 31, no. 1, p. 19- 28.

Law, B.E., C.W. Spencer, R.R. Charpentier, R. A. Crovelli, R.F. Mast, G.L Dolton, and C.J. Wandrey, 1989, Estimates of gas resources in overpressured low-permeability Cretaceous and Tertiary sandstone reservoirs, greater Green River basin, Wyoming, Colorado, and Utah: Wyoming Geological Association Guidebook, v. 40, p. 39-61. Meyer, H.J., H.W. McGee, 1985, Oil and gas accompanied by geothermal anomalies in the Rocky Mountain region: AAPG Bulletin, v. 69, no. 6, p. 933-945. Peters, K.E., 1986, Guidelines for evaluating petroleum source rock using programmed pyrolysis: AAPG, v. 70, p. 318.329. Pasternack, I., 2006, The Lewis Shale petroleum system, Eastern Greater Green River Basin, Wyoming and Colorado, Ph.D. dissertation, Colorado School of Mines, Golden CO, USA, 275p. Raymond L.A., 2002, Petrology: the study of igneous, sedimentary and metamorphic rocks: New York, McGraw-Hill, 720 p. Roberts, S.B., 2005, Geologic assessment of undiscovered resources in the Lance-Fort Union composite total petroleum system, Southwestern Wyoming province, Wyoming and Colorado, in Petroleum systems and geologic assessment of oil and gas in the Southwestern Wyoming province, Wyoming, Colorado, and Utah: U.S. Geological Survey Digital Data Series DDS-69-D, Chapter 11.

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Shanley, K.W., 2004, Fluvial reservoir description for a giant, low permeability gas field: Jonah Field, Green River Basin, Wyoming, U.S.A, in J.W. Robinson, and K.W. Shanley, eds., Jonah Field: case study of a giant tight-gas fluvial reservoir: 2004 AAPG Guidebook, Chapter 10, p.159-182.

Van Kooten, G., 2012, Coal as oil source rocks: a brief geochemical and geological review. Petrotechnical Resources Alaska Technical Report, http://www.doyonoil.com/resources (accessed March 20th, 2014).

Yuretich, R.F., Hickey, L.J., Gregson, B.P., and Yuan-Lun Hsia, 1984, Lacustrine deposits in the Paleocene Fort Union Formation, Northern Bighorn Basin, Montana: Journal of Sedimentary Petrology, v. 54, no. 3, p. 836-852.

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APPENDIX A REGIONAL CROSS-SECTION SW NE

China Butte Member

Chicken Springs Coal Zone

Fillmore Ranch Coal Zone

Muddy Creek Coal Zone

Separation Creek Coal Zone

Olson Draw Coal Zone

Appendix A. Interpretive cross-section from NE near surface well logs towards basin center. Interpretive black color fill indicates coals can be relatively discontinuous, excepting the Fillmore Ranch Coal zone, as it extends pervasively towards basin center.

127 APPENDIX B CORE MONTAGES

Abandoned Channel Fill (H)

Low Core Permeability

AC Active Channel Fill (G)

Gas High Core Effect Abandoned Channel Fill (F) Permeability AC

Low Core Permeability AC

GC AC Appendix B.1. Core Montage of the Barricade #33-12 illustrating relationships between core facies, openhole logs, thin sections, and quantitative core measurements.

128 Facies 1K

Facies 1J

GC GC AC Low Core Permeability Facies 1I

GC Facies 1G GC

High Core Permeability Facies 1F AC

GC GC AC AC AC GC

Appendix B.2. Core Montage of the Endurance #44-29 Core #1 illustrating relationships between core facies, openhole logs, thin sections, and quantitative core measurements.

129 Facies 2F

GC GC

GC Facies 2B

Appendix B.3. Core Montage of the Endurance #44-29 Core #2 illustrating relationships between core facies, openhole logs, thin sections, and quantitative core measurements.

130 Facies 3G

AC Facies 3D

Facies 3C GC AC GC

GC GC GC AC AC GC

GC AC

Appendix B.4. Core Montage of the Endurance #44-29 Core #3 illustrating relationships between core facies, openhole logs, thin sections, and quantitative core measurements.

131 APPENDIX C

SEM PHOTOMICROGRAPHS

Appendix C.1. Facies H. Depth: 10145.26. Primarily quartz with secondary porosity from dissolution of framework grains.

132

Appendix C.2. Facies H. Depth: 10145.26. Detrital grains: primarily quartz, some chert, argillaceous rock fragments and volcanic rock fragments. Authigenic grains: quartz, dolomite, and illite/smectite. Clay matrix: illite (I) and smectite. Porosity: Mainly secondary (Ps) from dissolution of plagioclase and K-feldspar. Grain size: lower fine (modified from Core Lab proprietary report).

133

Appendix C.3. Facies G. Depth: 10156.45. Primarily quartz with secondary porosity from dissolution of framework grains, disseminated rock fragments.

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Appendix C.4. Facies G. Depth: 10156.45. Detrital grains: primarily quartz, plagioclase, K-feldspar, volcanic rock fragments, argillaceous rock fragments, carbonate rock fragments, and some chert. Authigenic grains: quartz, dolomite, and illite/smectite. Clay matrix: illite and smectite. Secondary porosity: dissolution of feldspar (Ps). Grain size: upper fine.

135

Appendix C.5. Facies G. Depth: 10157.82. Primarily quartz with secondary porosity from dissolution of framework grains, disseminated rock fragments. Secondary quartz overgrowths (QO).

136

Appendix C.6. Facies G. Depth: 10157.82. Detrital grains: primarily quartz. Accessory grains: plagioclase, K-feldspar, volcanic rock fragments, argillaceous rock fragments, carbonate rock fragments, and chert. Clay matrix: illite (I). Secondary porosity: dissolution of K-feldspar. Grain size: lower medium.

137

APPENDIX D

THIN-SECTION PHOTOMICROGRAPHS

A B C D E F G H I J K L M N O P 10

1 SCALE ______0.32mm

Appendix D.1. Facies H. Depth: 10143.20. 25X, Plane Light. Fine grained, moderately sorted and consolidated, sublitharenite.

138

A B C D E F G H I J K L M N O P 10

Plag 9

ARF 6

5 Ch Plag Q 4 Ps 3

1 SCALE ______0.13mm

Appendix D.2. Facies H. Depth: 10143.20. 63X, Plane Light. Abundant secondary porosity by way of feldspar dissolution, chiefly plagioclase (Ps). Argillaceous rock fragments (ARF) and chert (Ch) present throughout.

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A B C D E F G H I J K L M N O P 10

1 SCALE ______0.32mm

Appendix D.3. Facies G. Depth: 10161.20. 25X, Plane Light. Upper fine to lower medium grained, moderately sorted, sublitharenite.

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9 Ps 8

Ps 7

Q 6

Q 5

Qo 3 Ps Q Ch 2

1 SCALE ______0.13mm

Appendix D.4. Facies G. Depth: 10161.20. 63X, Plane Light. Detrital grains consisting mainly of quartz (Q). Secondary porosity (Ps) by way of dissolution of unstable framework grains, primarily feldspar. Large assemblages of chert (Ch) throughout. Clay and authigenic quartz (Qo) in part occlude pore space.

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1 SCALE ______0.32mm

Appendix D.5. Facies F. Depth: 10163.20. 25X, Plane Light. Lower fine grained, moderate to well-sorted and consolidated sublitharenite.

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1 SCALE ______0.13mm

Appendix D.6. Facies F. Depth: 10163.20. 63X, Plane Light. Detrital grains are primarily quartz (Q) with various rock fragments. Calcite (Ca) occludes much of the available pore space.

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1 SCALE ______0.32mm

Appendix D.7. Facies 1K. Depth: 9528.15. 25X, Plane Light. Pore space stained with red epoxy. Upper fine grained, moderately sorted and compacted, sublitharenite.

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1 SCALE ______0.13mm

Appendix D.8. Facies 1K. Depth: 9528.15. 63X, Plane Light. Primary grains are quartz (Q) with accessory feldspars. Apparent organic material (Om). Secondary porosity (Ps) is abundant via feldspar dissolution, chiefly plagioclase.

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1 SCALE ______0.13mm

Appendix D.9. Facies 1K. Depth: 9528.15. 63X, Epifluorescence.

Facies 1K shows fair to good interpore connectivity with some apparent intragranular microfracturing.

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1 SCALE ______0.32mm

Appendix D.10. Facies 1J. Depth: 9539.55. 25X, Plane Light. Mixed lithology. Poorly sorted sublitharenite and shale.

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1 SCALE ______0.13mm

Appendix D.11. Facies 1J. Depth: 9539.55. 63X, Plane Light. Mixed lithology. Quartz (Q) grains suspended in clay (Cl) cement and interlaminated with shale. Chert (Ch) is abundant. Both primary and secondary porosity is limited as clay cement has all but occluded available pore space.

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1 SCALE ______0.13mm

Appendix D.12. Facies 1J. Depth: 9539.55. 63X, Epifluorescence.

Facies 1J is abundantly cemented limiting porosity and permeability. Some intergranular fracturing may support limited fluid flow.

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1 SCALE ______0.32mm

Appendix D.13. Facies 1I. Depth: 9548.0. 25X, Plane Light.

Intergranular porosity is abundant in this moderately sorted, medium grained, sublitharenite.

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1 SCALE ______0.13mm

Appendix D.14. Facies 1I. Depth: 9548.0. 63X, Plane Light. Well compacted detrital quartz (Q) is abundant. Porosity is primarily secondary via feldspar dissolution (Ps). Disseminated chert (Ch) and organic material (Om).

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1 SCALE ______0.13mm

Appendix D.15. Facies 1I. Depth: 9548.0. 63X, Epifluorescence.

Abundant dissolution porosity highlighted by fluorescent epoxy.

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1 SCALE ______0.32mm

Appendix D.16. Facies 1G. Depth: 9559.55. 25X, Plane Light.

Intergranular porosity is poor in this moderately sorted and compacted sublitharenite.

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1 SCALE ______0.13mm

Appendix D.17. Facies 1G. Depth: 9559.55. 63X, Plane Light. Primary detrital grains are quartz (Q). Chert (Ch) and volcanic rock fragments (VRF) are abundant. Intragranular microfracturing observed in preserved feldspar grain (Kspar).

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1 SCALE ______0.13mm

Appendix D.18. Facies 1G. Depth: 9559.55. 63X, Epifluorescence.

Intergranular and intragranular microfracturing visible under fluorescent light.

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1 SCALE ______0.32mm

Appendix D.19. Facies 1C. Depth: 9567.20. 25X, Polarized. Middle fine, moderate to well sorted and consolidated, sublitharenite.

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1 SCALE ______0.13mm

Appendix D.20. Facies 1C. Depth: 9567.20. 63X, Plane Light. Main detrital grains are angular to sub-rounded quartz (Q). Organic material (Om) finely disseminated. Porosity is secondary via dissolution of unstable framework grains, primarily feldspars (Ps).

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1 SCALE ______0.13mm

Appendix D.21. Facies 1C. Depth: 9567.20. 63X, Epifluorescense. Pore connectivity is visibly poor under fluorescent light.

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1 SCALE ______0.32mm

Appendix D.22. Facies 2F. Depth: 9772.15. 25X, Polarized. Facies 2F is a moderately sorted, angular to sub-rounded, well consolidated litharenite.

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1 SCALE ______0.13mm

Appendix D.23. Facies 2F. Depth: 9772.15. 63X, Plane Light. Primary detrital grains are quartz (Q) and various rock fragments (Ch). Organic matter (Om) disseminated in available pore space. Secondary porosity abundant via partial and complete dissolution of unstable feldspar grains (Ps).

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1 SCALE ______0.13mm

Appendix D.24. Facies 2F. Depth: 9772.15. 63X, Epifluorescence. Good pore space connectivity as intergranular and dissolution porosity visible under fluorescent light.

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1 SCALE ______0.32mm

Appendix D.25. Facies 2B. Depth: 9815.20. 25X, Polarized. Moderate to well sorted and consolidated very fine grained litharenite.

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1 SCALE ______0.13mm

Appendix D.26. Facies 2B. Depth: 9815.20. 63X, Plane Light. Detrital grains are primarily quartz (Q). Porosity completely or in-part occluded by clay cement, authigenic pyrite (Py) and organic matter (Om).

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1 SCALE ______0.13mm

Appendix D.27. Facies 2B. Depth: 9815.20. 63X, Epifluoresence. Very little pore space connectivity and available porosity is visible under fluorescent light.

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1 SCALE ______0.32mm

Appendix D.28. Facies 3G. Depth: 9840.9. 25X, Plane Light. Moderately well sorted except in portions with shale clasts. Lower medium grained, angular to sub-rounded litharenite.

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1 SCALE ______0.13mm

Appendix D.29. Facies 3G. Depth: 9840.9. 63X, Plane Light. Primary detrital grains are quartz (Q) with accessory chert rock fragments (Ch). Dissolution of unstable framework grains (Ps) creates abundant secondary intergranular porosity. Finely disseminated organic material (Om). Some apparent intragranular fracturing may be present.

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1 SCALE ______0.13mm

Appendix D.30. Facies 3G. Depth: 9840.9. 63X, Epifluorescence. Abundant intergranular and some intragranular pore connectivity is visible under fluorescent light.

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1 SCALE ______0.32mm

Appendix D.31. Facies 3D. Depth: 9859.40. 25X, Polarized. Well sorted, angular to sub-rounded and well consolidated sublitharenite.

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1 SCALE ______0.13mm

Appendix D.32. Facies 3D. Depth: 9859.40. 63X, Plane Light. Abundant quartz (Q) with accessory grains of chert (Ch) and K-feldspar (Kspar). Intergranular porosity driven primarily as dissolution from unstable framework grains (Ps).

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1 SCALE ______0.13mm

Appendix D.33. Facies 3D. Depth: 9859.40. 63X, Epifluorescence. Minor pore space connectivity visible under fluorescent light.

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1 SCALE ______0.32mm

Appendix D.34. Facies 3C. Depth: 9866.35. 25X, Plane Light. Fine grained, well-sorted and consolidated sublitharenite.

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1 SCALE ______0.13mm

Appendix D.35. Facies 3C. Depth: 9866.35. 63X, Plane Light. Quartz (Q) is primary detrital grain. Abundant clay cement (Cl) occluding available pore space. Organic matter (Om) disseminated as wispy seams throughout sample.

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1 SCALE ______0.13mm

Appendix D.36. Facies 3C. Depth: 9866.35. 63X, Epifluorescence. Trace pore space connectivity visible under fluorescent light.

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