adrian almanza thesis 2011

1

INTEGRATED THREE DIMENSIONAL GEOLOGICAL MODEL OF

THE DEVONIAN BAKKEN FORMATION ELM COULEE FIELD,

WILLISTON BASIN: RICHLAND COUNTY MONTANA

by

Adrian Almanza

ii

A thesis submitted to the Faculty and the 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______________________

Adrian Almanza

Signed______________________

Dr. J. Frederick Sarg

Thesis Advisor

Golden, Colorado

Date___________

Signed______________________

Dr. John D. Humphrey

Professor and Head

Department of Geology

And Geological Engineering

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ABSTRACT

The Bakken Formation of the Williston basin is a oil resource play that was

named the largest continuous oil accumulation in the lower 48 states by the United

States Geological Survey (USGS) in 2008. Although extensive the Bakken does not

have uniform properties throughout its areal extent. Identifying areas with porosity,

permeability, and fractures that permit highly productive wells is essential to commercial

petroleum recovery. The Elm Coulee Field is a giant oil field in Eastern Montana that

exhibits some of these critical reservoir properties. Geological modeling of these

reservoir properties provides a greater understanding of reservoir performance, and aids

in exploration and development of the Bakken Formation.

The Bakken Formation in the Elm Coulee Field consists of three members: an

upper shale, middle silty dolostone, and lower shale. The Elm Coulee Oil Field is a

stratigraphic trap with a pinch-out to the southwest and a diagenetic facies change in the

northeast. The primary reservoir is the silty dolostone of the Middle Bakken Member.

The purpose of this research is three fold: (1) complete an examination of the

reservoir properties of the Bakken petroleum system in Elm Coulee field; (2) construct a

three-dimensional geologic model that will show the distribution of the different facies

within the Bakken Formation and their reservoir properties; and (3) build a fracture

model and integrate it with the matrix porosity model. This study uses digital logs, core

data, petrographic thin sections, XRD analysis, DSTs, production data, and Petrel

software to characterize the Elm Coulee Field. Six cores are used to calibrate physical

properties to digital well logs, and core descriptions were used to construct detailed

facies maps.

The study correlates the core lithofacies to digital well logs resulting in maps of

the facies and the calculation of their associated thickness throughout the study area.

The data was then used to build a structural geomodel in Petrel software. The

geomodel is located in the central part of Elm Coulee in the congressional land blocks:

Township 53 Range 56, Township 57 Range 56, and Township 53 Range 58 of Richland

County, Montana. The structural model shows a thick Middle Bakken in the study area

with a thinning to the north, south, and west. The Lower Bakken Shale is absent in the

southern half of Richland County and the Upper Bakken Shale covers the entire study

area

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With the structural model in place, the digital well logs were used to distribute

petrophysical properties of the Middle Bakken throughout the Petrel model. The data

revealed that the reservoir is located in a northwest trend in the southern half of Richland

County. The petrophysics shows that the best reservoir properties are associated with

Middle Bakken faces B and C. Facies B and C have a high percentage of dolomite which

has the best reservoir properties (i.e., higher porosity and permeability). These data

were then used to build a matrix reservoir model.

The study also constructed a fracture model for Richland County. The Elm

Coulee fracture model was derived from seismic and production trends. The model uses

regional fracture trends to establish a fracture fabric. The regional fractures are oriented

to the northeast and have a spacing of approximately 1,250 feet (ft). An orthogonal set of

fractures are spaced 2,500 ft apart in the northwest direction. Production data allowed

for the detection of what is interpreted as fracture swarms. The swarms are oriented in

the maximum principal stress direction of N60E and have an approximate spacing of

25,000 ft.

The fracture model was combined with the matrix model to develop a dual

porosity model. This results in a combined model that has both fracture and matrix

reservoir properties that can be used in simulation. The dual porosity model reflects the

production in the study area, and the best reservoir properties align with the best

estimated ultimate recovery (EUR).

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TABLE OF CONTENTS

ABSTRACT ...................................................................................................................... iii

TABLE OF CONTENTS .................................................................................................... v

LIST OF FIGURES .......................................................................................................... viii

LIST OF TABLES ............................................................................................................ xv

ACKNOWLEDGMENTS .................................................................................................. xv

CHAPTER 1 ...................................................................................................................... 1

INTRODUCTION ............................................................................................................... 1

CHAPTER 2 ...................................................................................................................... 4

GEOLOGIC OVERVIEW ................................................................................................... 4

2.1 Tectonics ..................................................................................................................... 4

2.2 Stratigraphy ................................................................................................................. 4

2.2.1 Lower Shale ............................................................................................................. 6

2.2.2 Middle Member ........................................................................................................ 7

2.2.3 Upper Shale ............................................................................................................. 7

2.2.4 Source Rocks ........................................................................................................... 8

2.3 Key Previous Work ...................................................................................................... 8

2.4 Purpose and Objectives .............................................................................................. 9

2.5 Methodology .............................................................................................................. 10

CHAPTER 3 .................................................................................................................... 11

FACIES INTERPRETATION AND CORE DESCRIPTIONS ........................................... 11

3.1 Methods .................................................................................................................... 11

3.2 Facies Descriptions ................................................................................................... 14

3.2.1 Lower Bakken Shale. ............................................................................................. 14

3.2.2 Facies A. Intraclastic-Skeletal Lime Wackestone .................................................. 14

3.2.3 Facies B. Bioturbated Silty Dolostone .................................................................... 16

3.2.4 Facies C. Rhythmic Laminated Sandy to Silty Dolostone ...................................... 16

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3.2.5 Facies D. Fine Grained Quartz Rich Sandstone .................................................... 16

3.2.6 Facies E Silty Dolostone ........................................................................................ 16

3.2.7 Facies F Fossiliferous Wackestone ....................................................................... 16

3.2.8 Upper Bakken Shale. ............................................................................................. 21

3.3 Depositonal Model .................................................................................................... 21

3.4 Core Descriptions ...................................................................................................... 23

3.4.1 Brutus East Lewis 3-4 (Sec. 3-T24N-R57E) .......................................................... 23

3.4.2 RR Lonetree Edna 1-13 (Sec. 1-T23N-R56E) ....................................................... 26

3.4.3 Foghorn-Ervin 20-3 (Sec. 20-T23N-R58E) ............................................................ 26

3.4.3 Jackson Rowdy 3-8 (Sec. 3-T26N-R51E) .............................................................. 27

3.4.4 Vaira 44-24 (Sec. 24-T24N-R31E) ......................................................................... 28

3.4.5 Williams 1-4 (Sec. 4-T23N-R55E) .......................................................................... 29

3.5 Mineralogy and Diagenesis ....................................................................................... 29

CHAPTER 4 .................................................................................................................... 36

SUBSURFACE WELL LOG INTERPRETATION ............................................................ 36

4.1 Methods .................................................................................................................... 36

4.2 Structural Cross Section ........................................................................................... 36

4.3 Stratigraphic Cross Section ....................................................................................... 39

4.4 Structure Maps .......................................................................................................... 39

4.5 Isopach Maps ............................................................................................................ 39

CHAPTER 5 .................................................................................................................... 55

PETROPHYSICAL ANALYSIS AND RESERVOIR PROPERTIES ................................. 55

5.1 Core Properties Analysis ........................................................................................... 55

5.2 Conventional Well Log Analysis ................................................................................ 56

5.3 Drill Stem Tests ......................................................................................................... 71

CHAPTER 6 .................................................................................................................... 73

FRACTURES .................................................................................................................. 73

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6.1 Production Data. ....................................................................................................... 73

6.2 Other Available Data ................................................................................................. 74

6.3 Seismic Mapping in Billing Nose an analog for a local fracture fabric of the Elm

Coulee Field. ................................................................................................................... 74

6.4 Micro Seismic Study Elm Coulee Field. .................................................................... 78

6.5 Results ...................................................................................................................... 79

CHAPTER 7 .................................................................................................................... 83

3-D GEOLOGICAL MODELING ...................................................................................... 83

7.1 Modeling in Petrel ..................................................................................................... 83

7.3 Fracture Properties ................................................................................................... 88

CHAPTER 8 DISSCUSSION .......................................................................................... 92

8.1 Structural-Stratigraphic Model ................................................................................... 92

8.2 Porosity Model ......................................................................................................... 93

8.3 Permeability Model .................................................................................................... 93

8.4 Fractures Model ........................................................................................................ 94

8.6 Production Data ........................................................................................................ 95

CHAPTER 9 CONCLUSIONS ......................................................................................... 98

9.1 Conclusions ............................................................................................................... 98

9.2 Recommendations .................................................................................................... 99

REFERENCES CITED .................................................................................................. 100

APPENDIX A CORE DESCRIPTIONS ...................................................................... 104

APPENDIX B STRUCTURAL CROSS SECTIONS ................................................... 112

APPENDIX C STRATIGRAPHIC CROSS SECTIONS .............................................. 118

APPENDIX D LIST OF WELLS USED IN PETREL MODEL ..................................... 123

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LIST OF FIGURES

Figure 1.1 Location Map, Elm Coulee Field, Richland County, Montana (Heck et

al.,2004). ........................................................................................................................... 1

Figure 1.2 Structure contour base of Mississippian (from Sonnenberg and Pramudito,

2009). ................................................................................................................................ 2

Figure 1.3 Digital log and core locations for Elm Coulee Field. ......................................... 3

Figure 2.1 Location of major structural provinces or orogeny (Williams et al; 1991) ......... 5

Figure 2.2 Major Paleozoic structural lineaments. (Brown and Brown, 1987). .................. 5

Figure 2.3 Schematic west-east cross section across the Williston basin (from

Sonnenberg and Pramudito (2009) after Meissner, (1978)).............................................. 6

Figure 2.4 Well log signatures of the Bakken Formation. (from Sonnenberg and

Pramudito., 2009). ............................................................................................................. 7

Figure 3.1 Green dots mark the locations of cored wells used in the Elm Coulee study. 13

Figure 3.2 Bakken lithofacies. ......................................................................................... 15

Figure 3.3 Lower Bakken Shale. The black and white scale bar segments are one

inch (from Alexandre, 2011). ........................................................................................... 17

Figure 3.4 Middle Bakken Facies A. The black and white scale bar segments are one


Figure 3.5 Middle Bakken Facies B. The black and white scale bar segments are one

inch. Dark blebs are Helminthopsis burrows (from Alexandre, 2011). ............................ 18

Figure 3.6 Middle Bakken Facies C. The black and white scale bar segments are one


Figure 3.7 Middle Bakken Facies D. The black and white scale bar segments are one


Figure 3.8 Middle Bakken Facies E. The black and white scale bar segments are one


Figure 3.9 Middle Bakken Facies F. The black and white scale bar segments are one


Figure 3.10 Upper Bakken Shale. The black and white scale bar segments are one


Figure 3.11 North American Paleogeographic Map Late Devonian, 360 Ma (Modified

from Blakey

2005)..22

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Figure 3.12 Bakken depositional model. Facies are labeled according to their position

on the model. HST (highstand systems tract), LST (Lowstand systems tract), TST

(transgressive systems tract)(from Simenson, 2010 modified from Smith and Bustin,

1996). .............................................................................................................................. 23

Figure 3.13 Brutus East Lewis 3-4-H core description (from Alexandre, 2011) .............. 25

Figure 3.14 RR Lonetree, gamma ray, porosity, and permeability and XRD analysis. ... 31

Figure 3.15 Jackson Rowdy, gamma ray, porosity, and permeability and XRD

analysis. .......................................................................................................................... 32

Figure 3.16 Brutus East Lewis cross plot of bulk density and XRD precentage of

dolomite and calcite (limestone). The colors refer to the depth of the Middle Bakken.

The red is at 7,636 ft and the dark blue is 7,6578 ft. Data shows that a high

precentage of dolomite corrospons to a bulk density of 2.63 g/cm3 and has a calicte

signature of 2.68 g/cm3 . ................................................................................................. 33

Figure 3.17 RR Lonetree Edna, cross plot of bulk density and XRD precentage of

dolomite. The colors refer to the depth of the Middle Bakken. The red is at 10,376 ft

and the dark blue is 10,408 ft. The data shows an average bulkdensity of 2.63 g/cm3

where there is a high precentage of dolomite. ................................................................ 34

Figure 3.18 Average bulk density map of the Middle Bakken. The average dolomite

signature (2.63-2.66 g/cm3) is observed in the southern half of the study area. The

calcite signature 2.68-2.69) g/cm3 is seen in the northern and western parts of the

study area and are considered diagenetic pinch outs of reservoir properties. ................ 35

Figure 4.1 Locatoin map of digital wells. Yellow squares mark digital well

locations...37

Figure 4.2 Location map of structural and stratigraphic cross sections. Top Bakken

structure map contour interval is 200

ft..38

Figure 4.3 Structural cross section G-G'. The Bakken (purple), Three Forks (Green),

and Birdbear (Orange) are formation tops correlated across the study area. The track

on the left is gamma ray (red) and the right track is resistivity

(black)...40

Figure 4.4 Stratigraphic corss section G-G'. The dark gray is the Upper and Lower

Bakken shales, the light gray is facies E and F, the light red is facies B and C and the

purple is facies A.41

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Figure 4.5 Thickness map of the Middle Bakken Member (facies A,B,C,D,E, and F).

Contour interval is 2.5 feet. The thickness ranges from 5.5 feet to 52 feet in the study

area. The Middle Bakken Member thins to the north and east and pinches out to the

south and west. ......................................................................................................... ..42

Figure 4.6 Structure Map Upper Bakken Shale. The structure map shows a dip to the

east. The contours interval is 100 ft. ............................................................................... 44

Figure 4.7 Structure Map Three Forks. The structure map shows a dip to the east. The

contours interval is 100 ft. ............................................................................................... 45

Figure 4.8 Structure Map Nisku (Birdbear) The structure map shows a dip to the east.

The contours interval is 100 ft. ........................................................................................ 46

Figure 4.9 Thickness map of the Upper Bakken Shale. Contour interval is one foot

(0.30 meters). The thickness ranges from 4.5ft to 13ft in the study area. ...................... 47

Figure 4.10 Thickness map of the CSM F facies. Contour interval is one foot (0.30

meters). The thickness ranges from 1.5 ft to five feet in the study area .......................... 48

Figure 4.11 Thickness map of the CSM E facies. Contour interval is one foot (0.30

meters). The thickness ranges from 1.5 ft to 7.5 ft in the study area .............................. 49

Figure 4.12 Thickness map of the CSM C facies. Contour interval is two feet (0.61

meters). The thickness ranges from 2.4ft to 17ft in the study area ................................. 50

Figure 4.13 Thickness map of the CSM B facies. Contour interval is one foot (0.30

meters). The thickness ranges from seven feet to 27 ft in the study area ....................... 51

Figure 4.14 Thickness map of the CSM A facies. Contour interval is one foot (0.30

meters). The thickness ranges from 1.5 ft to eight feet in the study area ....................... 52

Figure 4.15 Thickness map of the Lower Bakken Shale. Contour interval is one foot

(0.30 meters). The thickness ranges from 1.5 ft to six feet in the study area .................. 53

Figure 4.16 Thickness map of the Three Forks. Contour interval is ten feet (three

meters). The thickness ranges from 1.5ft to five feet in the study area ........................... 54

Figure 5.1 Porosity and Permeability cross plots. The Foghorn and Lonetree Wells

have good logarithmic regression line correlation. The Brutus and the Jackson Rowdy

well have poor logarithmic line colorations. The former two wells are situated in a

dolomitic setting as indicated by bulk density and XRD analysis. ................................... 57

Figure 5.2 Middle Bakken porosity and permeability crossplot (from Enerplus core

data) ................................................................................................................................ 58

Figure 5.3 Photomicrograph showing examples of nonreservoir (A) and good

reservoir (B)..60

xi

Figure 5.4 Foghorn Ervin Core Data: gamma ray (GR), bulkdensity (ROBH),

neutron porosity (NPHI), water saturatoin (Core Sw), oil saturation (Core So),

Porosity, Permeavility(Core Kmax). Log templates constructed in Prism module of

Geographix...61

Figure 5.5 Brutus East-Lewis Core Data: gamma ray (GR), bulk density (RHOB),

neutron porosity (NPHI), water saturation (Core Sw), oil saturation (Core so),

porosity, permeability (Core Kmax). Log templates constructed in Prism module of

Geographix. ..................................................................................................................... 62

Figure 5.6 Lonetree-Edna Core Data: gamma ray (GR), bulk density (RHOB),



Geographix. ..................................................................................................................... 63

Figure 5.7 Jackson Rowdy Core Data: gamma ray (GR), bulk density (RHOB),



Geographix. ..................................................................................................................... 64

Figure 5.8 Viara Core Data: gamma ray (GR), bulk density (RHOB), neutron porosity

(NPHI), water saturation (Core Sw), oil saturation (Core so), porosity, permeability

(Core Kmax). Log templates constructed in Prism module of Geographix. ................... 65

Figure 5.9 Williams Core Data: gamma ray (GR), bulk density (RHOB), neutron

porosity (NPHI), water saturation (Core Sw), oil saturation (Core so), porosity,

permeability (Core Kmax). Log templates constructed in Prism module of

Geographix. ..................................................................................................................... 66

Figure 5.10 Facies C and B average porosity map of the Elm Coulee Field. The Best

porosity is found in the southern half of the study area........67

Figure 5.11 Jackson Rowdy, the thick red lines in the Porosity and PERM tracks are

the calculated average porosity (PHIA) and permeability (Perm). ................................. 68

Figure 5.12 Foghorn Ervin, the thick red lines in the Porosity and PERM tracks are

the calculated average porosity (PHIA) and permeability (Perm). ................................. 69

Figure 5.13 Middle Bakken SoPhiH Map indicating most petrophysicaly prospecitve

areas of Elm Coulee field...70

Figure 5.14 Horner plots of Elm Coulee Wells ................................................................ 72

Figure 6.1 First year cumulative production .................................................................... 75

xii

Figure 6.2 First year cumulative production and Operators ............................................ 75

Figure 6.3 Initial production trends with a N60E Bias. This bias data trend highlights

the fracture swarms that are interpreted in the study area .............................................. 76

Figure 6.4 Minimum curvature attirbute map, Bakken horizon (from Angster 2010).

Interpreted fractures are on the right

map....77

Figure 6.5 Summery of micro seismic observations (from O'Brien, Larson, & Parham,

2011...78

Figure 6.6 Micro seismic production traces and fracture height data. The average

fracture height was 290 ft. Radioactive tracer show zonal isolation averaged

approximately 1200ft (O'Brien, Larson, & Parham, 2011). .............................................. 79

Figure 6.7 Fracture lengths versus fracture spacing. The logarithmic plot shows the

power log relationship between the production, seismic and micoseismic data used

in the fracture model. ...................................................................................................... 81

Figure 6.8 Conceptual fracture model. The fracture swarm trends in the blue ovals

and are spaced ~4.75 miles or 25,000ft apart. The swarms have the greatest

influence on the fracture fabric. The green lines reflect the regional fracture fabric that

are oriented with the maximum principal stress and have a spacing of ~1,250ft this

was seen in both the micro seismic and Bicentennial seismic survey. The oranges

lines show the orthogonal spacing of fractures that are spaced ~2,500ft apart. ............. 82

Figure 7.1 The red box is the outline of the Petrel model and shows the location of

the digital wells used to distribute petrophysical properties. ........................................... 84

Figure 7.2 Petrel geo-model structural model and geo-cellar grid. The mapped

horizons are the Three Forks, Bakken, and Lodgepole Formations. .............................. 85

Figure 7.3 Middle bakken porosity distributioin. 3D view looking north. Purple is low

(0.0%) and red is high

(20.0%).....86

Figure 7.4 Middle Bakken permeability distribution. 3D view looking north. Purple is

low (0.001mD) and red is high (0.1mD) log scale ........................................................... 87

Figure 7.5 Localized fractures derived from Centennial seismic and the micro-seismic

study from Enerplus. The dominant fracture trend is the northeast orientations (blue

polygons) and the orthogonal northwest fracture set is represented by the purple

polygons. ......................................................................................................................... 88

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Figure 7.6 The figure shows the relationship of the two fracture patterns 1. regional

fracture pattern (purple polygons) and 2. contoured first year cumulative production

data, cropped from figure 6.3. The contoured interval is 2000 barrels of oil. Orange is

18,000 barrels and the blue is 4,000 barrels of oil.89

Figure 7.7 Localized fractures derived from Centennial seismic and the mico-seismic

study from Enerplus. The fractures have been related to the first year cumulative

production data and have varying degrees of fracture

influence....90

Figure 7.8 Oblique view highlighting the fracture variability in the fracture model. The

blue lines are the northwest fractures and the red lines area the northeast

fractures....91

Figure 7.9 Dual porosity model. Model shows the matrix model combined with the

fracture model creating a dual porosity model. ............................................................... 91

Figure 8.1 Diagram of the integrated geomodeling workflow showing the different

component models .......................................................................................................... 93

Figure 8.2 Initial first year cumulative production vs. Operator. The data does not

show any definite production trends associated with individual

operator.94

Figure 8.3 EUR well data. The graph shows the EUR production trends (>6%porosity+

fractures, >6%porosity-fractures,

xiv

Figure A4 RR Lonetree-Edna 1-13 Core description (from Alexandre, 2011) ............... 107

Figure A5 Foghorn-Ervin 20-3-H Core description (from Alexandre, 2011) .................. 108

Figure A6 Jackson Rowdy 3-8 Core description (from Alexandre, 2011) ..................... 109

Figure A7 Vaira 44-24 Core description (modified from Pramudito, 2008) ................... 110

Figure A8 Williams 1-4 Core description (modified from Pramudito 2008) ................... 111

Figure B1 Structural cross sections A-A`. The Bakken (Purple), Three Forks (Green)

and Birdbear (Orange) are formation tops correlated across the study area. The

track on the left is gamma ray (red) and the right track is resistivity (black). ................. 113

Figure B2 Structural cross sections B-B`. The Bakken (Purple), Three Forks (Green)



Figure B3 Structural cross sections C-C`. The Bakken (Purple), Three Forks (Green)



Figure B4 Structural cross sections D-D`. The Bakken (Purple), Three Forks (Green)


track on the left is gamma ray (red) and the right track is resistivity (black). ................ 115

Figure B5 Structural cross sections E-E`. The Bakken (Purple), Three Forks (Green)



Figure B6 Structural cross sections F-F`. The Bakken (Purple), Three Forks (Green)



Figure B7 Structural cross sections H-H`. The Bakken (Purple), Three Forks (Green)


track on the left is gamma ray (red) and the right track is resistivity (black) .................. 117

Figure C1 Stratigraphic cross sections A-A`. The dark gray is the Upper and Lower

Bakken Shales, the light gray is facies E and F, the light red is facies B and C and

the purple is facies A. .................................................................................................... 119

Figure C2 Stratigraphic cross sections B-B. The dark gray is the Upper and Lower


the purple is facies A. .................................................................................................... 119

xv

Figure C3 Stratigraphic cross sections C-C`. The dark gray is the Upper and Lower


purple is facies A. .......................................................................................................... 120

Figure C4 Stratigraphic cross sections D-D`. The dark gray is the Upper and Lower



Figure C5 Stratigraphic cross sections E-E`. The dark gray is the Upper and Lower



Figure C6 Stratigraphic cross sections F-F. The dark gray is the Upper and Lower



Figure C7 Stratigraphic cross sections H-H`. The dark gray is the Upper and Lower



LIST OF TABLES

Table 1. List of cored wells used in study. ...................................................................... 12

Table 2. Summary of service company DST results, compared to average core

permeability data (Sorenson well is in close proximity to the foghorn well and,

Bahl well is close to the Lonetree well.71

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ACKNOWLEDGMENTS

I would like to express my deep gratitude for all those that have made this

possible. First and foremost I would like to thanks my parents who have been my

biggest supporters and have provided me with love and encouragement to live to my

best potential. I would like give thanks to my advisor Rick Sarg and my committee

members Steve Sonnenberg and Hossein Kazemi for all their invaluable impute and

mentorship. I like to thank NETEL for providing funding for my thesis. Finally I would

like to thank my fellow cohorts of geology whose struggles, triumphs and most

importantly friendships helped my own journey.

1

CHAPTER 1

INTRODUCTION

The Devonian-Mississippian (~350 million ma) Bakken Formation is the largest

continuous US oil accumulation assessed by the USGS. The Elm Coulee field is one of

the first discovered fields and currently produces over 50,000 barrels of oil per day

(Figure 1.1). The Bakken Formation consists of three members: an upper shale, middle

silty dolomite, and lower shale. The middle member is the main reservoir and consists

of six identified facies, from the base of the member upward: facies A,B,C,D,E, and F.

The two primary reservoir facies are B and C. They are characterized by a bioturbated

silty dolostone and a laminated silty dolostone respectively. The Bakken reservoir rocks

are characterized overall by low porosity and low permeability.

Figure 1.1. Location Map, Elm Coulee Field, Richland County, Montana (Heck et al.,2004).

2

Elm Coulee is located in Richland County, Montana in the southwest part of the

Williston basin (Figure 1.2). In the study area, the Middle Bakken interval is the thickest

in the middle of Richland County, and this thick trends in a northwest and southeast

direction. This unit thins in the northeast and southwest directions. In the study area,

there are six wells that have core data, and approximately 400 wells with digital logs.

The digital logs have good areal coverage in the field area, but are sparser in the

northeast portion of the field (Figure 1.3).

Figure 1.2. Structure contour base of Mississippian (from Sonnenberg and Pramudito, 2009).

3

Figure 1.3. Digital log and core locations for Elm Coulee Field.

4

CHAPTER 2

GEOLOGIC OVERVIEW

2.1 Tectonics

The Bakken Formation was deposited in the intracratonic Williston basin, which

formed in the Late Cambrian time (~500 ma). The Williston basin is thought to have

been formed by two major tectonic events. The first event was Precambrian

convergence of the Churchill Hinterland and the Superior Province, which formed the

Trans-Hudson Orogen (Figure 2.1). This newly created province was then subject to

uplift and erosion from thermal expansion, resulting in three kilometers of overburden

removal (Crowely, 1985). In the late Precambrian (~1000 ma), rifting of the ancient

North American plate created a series of major basement faults that now control the

structures and geometries of the Williston basin (Gerhard, 1990).

The second major tectonic event occurred during Late Paleozoic (~300 ma)

(Antler and Ancestral Rocky Mountains orogenies), in which plate collision from the west

realigned the deformation, and reactivated these deep-seated lineaments (Figure 2.2).

These were overprinted by the Laramide Orogeny in the latest Cretaceous (~60 ma) and

early Tertiary forming the structural features seen in the basin today.

2.2 Stratigraphy

The total preserved stratigraphic fill of the Williston basin is approximately 16,000

feet (ft). The sediment infill is characterized by cyclic deposition of clastics and

carbonates that range in age from Cambrian to Quaternary. Subsidence and tectonic

basin reconfiguration are the primary influences facilitating sediment infill. The

Cambrian strata are the result of Paleozoic seas that transgressed over the Williston

Basin, depositing sandstones, shales and shallow water carbonates. The Cambrian is

overlain by an unconformity that represents a sea level drop. The Ordovician to Silurian

strata mirror the basin geometry and are characterized by carbonates and anhydrites

(Vigrass, 1971).

5

Figure 2.1. Location of major structural provinces or orogeny (Williams et al; 1991)

Figure 2.2. Major Paleozoic structural lineaments. (Brown and Brown, 1987).

6

From Silurian to Devonian time, structural movement along the Trans-Continental

Arch caused a major unconformity and a seaway reorientation to the north. The

Devonian-Mississippian strata were deposited in this restricted basin and are

characterized by transgressive-regressive cycles. The strata that were deposited are

composed of carbonates, evaporites, and organic-rich shales. At the end of

Mississippian time (~320 ma), the basin experienced an additional reorientation that

occurred from the west.

The focus of this study is the Bakken Formation, which was deposited from Late

Devonian to early Mississippian time (~374-330 ma). In Montana, the Bakken is

uncomformably deposited on top of the Devonian Three Forks Formation. The Bakken

consists of three members: the lower member is an organic-rich shale; the middle

member is a silty dolostone; and the uppermost member is an organic-rich shale (Figure

2.4). The Bakken is overlain by the Lodgepole Formation. The Lower and Upper Bakken

Shales are considered source rocks for the Middle Bakken Member, Lodgepole

Formation, and Three Forks Formation. The Elm Coulee field forms a stratigraphic trap

by onlap of the middle Bakken strata to the northwest, northeast, and southwest

(Sonnenberg and Pramudito, 2009) (Figure 2.3).

Figure 2.3. Schematic west-east cross section across the Williston basin (from Sonnenberg and Pramudito (2009) after Meissner, (1978)).

2.2.1 Lower Shale

The lower shale ranges from siltstone to organic rich mudstone, and is dark gray

to brown in color. The shale is burrowed and contains fossil fragments. The lower shale

changes laterally from high resistivity and high gamma ray shale in the north, to lower

resistivity and lower gamma ray siltstone in the south (Sonnenberg and Pramudito,

7

2009) (Figure 2.4). The lower Bakken Shale is areally limited and pinches out to the west

and southwest in Elm Coulee Field (Figure 2.3).

2.2.2 Middle Member

The Middle Bakken Member is gray to buff, dolomitic fine-grained siltstone. The

middle member has ripple laminations, planar laminations, bioturbation and soft

sediment deformation. This interval is interpreted to be deposited in a tide-dominated

coastal environment. The middle member has a distinctive log signature (Figure 2.4).

The upper silty dolostone facies has a clean, low gamma-ray signature and the

bioturbated dolostone facies has a coarsening-upward log signature (Sonnenberg and

Pramudito., 2009).

2.2.3 Upper Shale

The upper shale is an organic rich, finely laminated, black to fissile, and slightly

calcareous source rock. The upper shale has disseminated kerogen throughout, and

shows a slight thickening toward the northwest. High gamma ray and resistivity

signatures are characteristic of this shale (Figure 2.4).

Figure 2.4. Well log signatures of the Bakken Formation. (from Sonnenberg and Pramudito., 2009).

8

2.2.4 Source Rocks

These shales are thermally mature at varying depths in the Williston basin. In

those places where the geothermal gradients were highest, hydrocarbon generation

occurred at depths of about 7,700 ft; and in areas with lower geothermal gradients,

generation occurred at depths of 10,000 ft (Price et al., 1984). Based on conodont color

alteration index values, Hayes (1985) also confirmed that the Bakken shales were

capable of oil generation at depths between 7,500 and 10,000 ft.

Though the Bakken was rapidly buried during the Mississippian, subsidence was

not enough to initiate oil generation until about 100 million years ago during the

Cretaceous. Then in the later part of the Cretaceous, once oil generation began and

pressures built up, a continuous phase oil expulsion occurred (Dow, 1974; Webster,

1984; Nordeng, 2009).

2.3 Key Previous Work

Petroleum geology of the giant Elm Coulee Field, Williston Basin (2009), by

Stephen Sonnenberg and Airs Pramudito, is a comprehensive summary of the Elm

Coulee field, and describes the stratigraphy, organic richness of the shale, and

properties of the Middle Bakken Member. Furthermore, it analyzes the porosity and

permeability of the middle member, and the distribution of the facies in the Elm Coulee

Field area. The paper also explains that the thickening of the Bakken in the Elm Coulee

area is a direct result of salt dissolution from the Prairie Formation, which created extra

accommodation space for the thickening of the Middle Bakken member in Richland

County.

Late Devonian and Early Mississippian Bakken and Exshaw Black Shale Source

Rocks, Western Canada Sedimentary Basin: A Sequence Stratigraphic Interpretation, by

Mark Smith and Marc Bustin (2000). The authors state that the Bakken and Exshaw

formations are time equivalent petroleum systems. They interpret three distinctive

system tracts: a transgressive systems tract, a lowstand systems tract, and a second

trangressive systems tract for the Middle Bakken member.

They also interpret a sequence boundary between the lower and middle member

of the Bakken Formation. They describe the Middle Bakken as a shallow marine deposit

9

that is characterized by an average upward increase in grain size, upward thickening in

sandstone beds, and an upward decrease in bioturbation.

Petroleum Geology of the Bakken Formation Williston Basin, North Dakota and

Montana, by Fred Meissner (1978). Meissner discusses the maturity of the Bakken

Formation and its relation to petrophysical properties. Meissner also examines the

overpressure in the Williston basin, and makes an interpretation on the origin and

migration of hydrocarbons from overpressured cells. Meissner states that areas with

mature oil-generating source rocks generally are overpressured, which has the potential

to fracture host and or adjacent rocks.

2.4 Purpose and Objectives

The purpose of this research is three fold: (1) to complete an in-depth

examination of the reservoir properties of the Bakken petroleum system in Elm Coulee

field; (2) to construct a three dimensional geologic model that will show the distribution of

the different facies within the Bakken Formation and their associated reservoir

properties: and (3) build a fracture model and integrate it with the matrix porosity model.

Since porosity and permeability are highly dependent on the reservoir facies

distribution, the knowledge of such properties will be useful in locating drilling targets,

and in predicting the most efficient way to develop the field. Porosity can be both matrix

and fracture in nature, and in Elm Coulee, matrix porosity and permeability, enhanced by

natural fractures, will be key in identification of reservoir sweet spots. Furthermore, the

construction of a reservoir model will facilitate identifying key production areas, and aid

in forecasting and developing secondary recovery techniques. To maximize the potential

of the Elm Coulee Field, a proper understanding of trap, seal and reservoir heterogeneity

is critical. Ultimately, the findings of this research may be used as an analog for similar

Bakken fields and play types that produce from tight reservoirs.

The specific plans of this research are to:

1) Understand the lateral and vertical facies variation within the Bakken Formation in the

Elm Coulee Field;

2) Correlate core data to the digital log data and distribute these properties throughout

the field;

10

3) Build a reservoir model that displays these properties, and provides information on the

depositional history of the Elm Coulee Field;

4) Use production data, drill stem tests, micro-seismic, 3D seismic and published

literature to identify fractures in the Elm Coulee Field. Key producing areas in Elm

Coulee Field can be found using traditional reservoir properties, and sweet spots can be

identified using production trends. It is hypothesized that the best production is

associated with fractured areas. This study will build both a matrix and fracture

distribution model.

2.5 Methodology

The research was conducted using core data, X-ray diffraction (XRD) data, and

digital log data. The geologic model was built using the geologic software: Petrel,

Geographix, and Prism log analysis. The study has six cores that were used to identify

facies, fractures, and reservoir properties (Alexandre, 2011). These cores where then

used to correlate approximately 400 digital logs in the Elm Coulee area. The cores were

also used to identify potential baffles and barriers that contribute to the heterogeneity of

the Elm Coulee reservoir facies. The well logs were used to construct structure and

isopach maps in the Elm Coulee Field, as well as to identify petrophysical properties.

The well log data will all be spatially referenced and depth calibrated to be imported into

Petrel 3D reservoir modeling software.

The reservoir model focuses on the Middle Bakken Member in the Elm Coulee

Field, and the core properties were used to construct a reservoir model in Petrel. This

model identifies the distribution of facies and their reservoir properties, as well as the

vertical and lateral changes in the Middle Bakken Member. Reservoir pressure was

determined from drill stem test data in the study area. Production data from IHS was

evaluated to help identity the best producing areas, as well as to assist in history

matching and fluid recovery rates for the Petrel model.

11

CHAPTER 3

FACIES INTERPRETATION AND CORE DESCRIPTIONS

Richland County has a number of vertical conventional cores through the Middle

Bakken, but only six cores were available for this study. Two of the cores were

previously studied and interpreted by Pramudito (2009) and four new cores were

interpreted and added to the CSM Elm Coulee database (Alexandre, 2011). The core

data is spatially located across the study area (Figure 3.1). The core data was used to

determine facies distributions and rock properties.

The core dataset for this study includes four primary cores in Richland County

that were donated by Enerplus Oil and Gas Corporation (Jackson Rowdy 3-8, Township

26 North, Range 51 East, Section 3; Brutus East Lewis 3-4-H, Township 24 North,

Range 57 East, Section 3; Foghorn-Ervin 20-3-HILD3, Township 23 North, Range 58

East, Section 20; RR Lonetree-Edna 1-13, Township 23 North, Range 56 East, Section

1). Two other cores were used to compliment and compare to the Enerplus core data

(Vaira 44-24, Township 24 North, Range 54 East, Section 24; Williams 1-4, Township 23

North, Range 55 East, Section 4). These two cores are located at the United States

Geological Survey (USGS) Core Research Facility in Denver, Colorado. (Table 1)

shows a summary of the cores used in this study. The cores were studied and used to

identify facies and their associated properties such as porosity and permeability.

Each Enerplus core has approximately 30 core plugs taken at one foot intervals.

The plugs are used to determine porosity and permeability. The core plugs were thin

sectioned and had X-ray diffraction (XRD) analysis run on them. The supporting data

was then used to quantify grain texture, fractures, digenesis and mineral composition.

3.1 Methods

Cores were described (Alexandre, 2011) (Pramudito, 2008) for their lithologic

characteristics, variations in mineral composition, grain size, fossil and trace fossil

associations, diagenetic features and sedimentary structures. Grain size was measured

using hand lens and petrographic thin sections.

12

Tab

le 1

. Lis

t of core

d w

ells

used in s

tudy.

13

Figure 3.1. Green dots mark the locations of cored wells used in the Elm Coulee study.

Petrographic thin sections and XRD data were used to determine mineral

composition. Sedimentary structures such as laminations, lag deposits and disturbed

bedding helped determine depositional environment.

The presence of calcite and dolomite minerals was determined with the use of

XRD data and petrographic thin sections. The presence of dolomite could also be

observed in thin sections in the form of dolomite crystals with rhombic shapes. XRD

analysis measured the mineral percentages contained in the middle member. The

Middle Bakken facies B and C with a high percentages of dolomite had the best

reservoir rock.

To map the facies and paleoenviormental interpretations, core data was

correlated to well log data. The well log data was used to construct cross-sections

across the study area. A series of structure and isopach maps were constructed to

display the areal distributions and thicknesses of the Middle Bakken facies.

14

3.2 Facies Descriptions

A facies is a body of rock characterized by a particular combination of lithology,

physical and biological structures that exhibit an aspect different from the bodies of rock

above, below, and laterally adjacent (Walker, 2006). Core observation, petrographic thin

sections, and XRD were utilized to help with facies interpretation.

One of the most important features for facies identification was fossil

identification, and both trace fossils and fossil fragments were instrumental in

determining facies boundaries (Alexandre, 2011).

The six cores used in this study all exhibit similar facies characteristics and

petrophysical properties. The Middle Bakken interval has six distinct facies that were

identified based on sedimentary structures, fossil content, textures and mineral

composition. The Middle Bakken has a facies designation from the base upwards of

lithofacies A,B,C,D,E, and F (Figure 3.2) (CSM 2010). These facies are summarized in

the following sections. The identified facies correlate well with gamma ray, neutron and

density log properties. The average core plug data from Enerplus was used for matrix

properties values.

3.2.1 Lower Bakken Shale.

The lower shale is an organic rich mudstone, and is dark gray to brown in color.

The shale is burrowed and contains fossil fragments including brachiopods and crinoids

(Figure 3.3). The lower shale is areally limited and pinches out to the west and

southwest in Richland County. Thin sections reveal that this facies has micro fractures

that are generally cemented by calcite and pyrite. Core data reports indicate an average

porosity of 3.1%.

3.2.2 Facies A. Intraclastic-Skeletal Lime Wackestone

Lithofacies A is composed of a silty clay-rich wackestone (Figure 3.4). The

facies is characterized by abundant fossil fragments consisting of brachiopods and

crinoids. Some cores have a low to moderate amount of bioturbation in the form of

horizontal burrows. Pyrite is present in the form of wisps and nodules (Alexandre,

2011). Petrophysical logs show an increase in

15

Fig

ure

3.2

. B

akken lithofa

cie

s.

16

gamma ray values that generally are assumed to be associated with an increase in

organic material (Pramudito, 2008). The thickness of the interval averages four feet.

The average porosity is four percent and average permeability is 0.12 md.

3.2.3 Facies B. Bioturbated Silty Dolostone

Lithofacies B is composed of a highly bioturbated silty dolostone (Figure 3.5).

The facies is characterized by a high amount of bioturbation. The primary trace fossils

are helminthopsis burrows. There are rare occurrences of thin laminations and

brachiopod fragments. The clay content decreases toward the top of this interval. The

thickness of the interval averages 15 ft. The average porosity is six percent and the

average permeability is 0.1 md.

3.2.4 Facies C. Rhythmic Laminated Sandy to Silty Dolostone

Lithofacies C is composed of a laminated silty dolostone (Figure 3.6). The facies

is characterized by the rhythmically bedded laminations. The types of lamination

observed in the facies are parallel, wavy, and cross laminations. There is a low amount a

bioturbation observed in this facies. The thickness of the interval averages seven feet.

The average porosity is six percent and the average permeability is 0.06 md.

3.2.5 Facies D. Fine Grained Quartz Rich Sandstone

Lithofacies D is composed of dolomitic fine-grained sandstone (Figure 3.7). The

types of lamination observed in the facies are parallel, wavy, and cross laminated. The

facies is very thin, averaging less than one foot. This is below the resolution of the digital

curves and is not mapped in the field area. This facies is combined with facies C when

mapping across the study area.

3.2.6 Facies E Silty Dolostone

Lithofacies E is composed of a laminated to bioturbated silty dolostone (Figure

3.8). There are wavy discontinuous laminations observed throughout this interval. The

thickness of the interval averages 2.6 ft. This is not a major reservoir facies in the

Middle Bakken.

3.2.7 Facies F Fossiliferous Wackestone

Lithofacies F is composed of fossiliferous dolomitic to lime wackestone (Figure

3.9).

17

Figure 3.3. Lower Bakken Shale. The black and white scale bar segments are one inch (from Alexandre, 2011).

Figure 3.4. Middle Bakken Facies A. The black and white scale bar segments are one inch (from Alexandre, 2011).

18

Figure 3.5. Middle Bakken Facies B. The black and white scale bar segments are one inch. Dark blebs are Helminthopsis burrows (from Alexandre, 2011).

Figure 3.6. Middle Bakken Facies C. The black and white scale bar segments are one inch (from Alexandre, 2011).

19

Figure 3.7. Middle Bakken Facies D. The black and white scale bar segments are one inch (from Alexandre, 2011).

Figure 3.8. Middle Bakken Facies E. The black and white scale bar segments are one inch (from Alexandre, 2011).

20

Figure 3.9. Middle Bakken Facies F. The black and white scale bar segments are one inch (from Alexandre, 2011).

Figure 3.10. Upper Bakken Shale. The black and white scale bar segments are one inch (from Alexandre, 2011).

21

The beds contain brachiopods found as articulated shells or fragments. There is fair to

moderate bioturbation observed. The thickness of the interval averages 2.6 ft. The

facies is generally hard to detect on wire line logs do to its thin nature and its proximity to

the high radioactivity of the overlying Upper Bakken Shale.

3.2.8 Upper Bakken Shale.

The upper shale is an organic rich mudstone, and is black to dark brown in color

(Figure 3.10). The Upper Bakken Shale is areally distributed throughout the Elm Coulee

Field. The facies has micro fractures that are generally cemented by calcite and pyrite.

The upper shale has disseminated kerogen throughout, and shows a slight thickening

toward the northwest. High gamma ray and resistivity signatures are characteristic of

this shale. Core measurements show an average porosity of 1.7%.

3.3 Depositonal Model

The Bakken Formation was deposited in a restricted basin during a time of

relative sea level rise (Webster,1984; Price,1985) (Figure 3.11). The lower and upper

organic rich shales are interpreted to be deposited in a stratified water column. The

anoxic bottom waters allowed for the preservation of high amounts of organic matter, an

absence of bioturbation and the formation of pyrite. (Webster,1984; Price,1985).

The depositional model for the Middle Bakken in Richland County is an offshore

marine carbonate bar complex (Sonnenberg and Pramudito, 2009) The carbonate bar

complex is interpreted to be deposited in accommodation that was the result of the

dissolution of the underlying Prairie salts (Sonnenberg and Pramudito, 2009)

Facies A,B, and C are interpreted to have been deposited in a highstand systems

tract (HST) (Figure 3.12). Facies A is interpreted to be deposited in an offshore marine

environment. The facies does not have any wave or current features. There is a very low

amount of bioturbation, Facies B is interpreted to be have been deposited in a lower

shoreface environment. This facies has a high amount of bioturbation from deposit

feeders and shows little to no wave or current features (Simenson, 2010). Facies C is

interpreted to have been deposited in the intertidal environment, and is characterized by

laminated silty dolostone. The top of Facies C marks the end of the HST.

Facies E is interpreted to have been deposited in a lower intertidal environment.

There is fair to moderate amount of bioturbation and some current and tidal features.

22

Facies F is interpreted to have been deposited in an offshore subtidal environment due

to an increase in clay content. There are also abundant fossil fragments concentrated in

thin layers, that are interpreted to be storm deposits. Facies E and F are interpreted to

have been deposited during a transgressive systems tract (TST) (Figure 3.12).

Figure 3.11 North American Paleogeographic Map Late Devonian, 360 Ma (modified from Blakey 2005).

Williston Basin

23

Figure 3.12. Bakken depositional model. Facies are labeled according to their position on the model. HST (highstand systems tract), LST (Lowstand systems tract), TST (transgressive systems tract)(from Simenson, 2010 modified from Smith and Bustin, 1996).

3.4 Core Descriptions

Cores were examined using hand lens, petrographic thin sections and aided by

the use of digital well logs, XRD and core plug sample analysis. Two core wells, (Vaira,

Williams), were previously studied by Pramudito (2009). A comprehensive analysis of

the four Enerplus Oil Corporation cores has been completed Alexandre (2011), and the

following descriptions are a brief summary of this work. The facies found in these key

well cores were used to define layers in the geologic model.

3.4.1 Brutus East Lewis 3-4 (Sec. 3-T24N-R57E)

The Brutus Lewis 3-4 well is located in the north-east area of the Elm Coulee

Field. The cored interval is 10,372-10,435 ft and contains both of the Bakken Shales and

six of the Bakken facies: A, B, C, D, E, and F (Figure 3.13).

24

The lower shale is an organic rich mudstone that is dark brown in color. The

shale has thin millimeter sized laminations. The facies has microfractures that are

generally cemented by calcite and pyrite.

Facies A is composed of a silty clay rich wackestone that is light gray to gray.

There are fossil fragments that consist of brachiopod and crinoid fragments. There is a

fair to moderate amount of bioturbation in the form of horizontal burrows. Pyrite is

present in the form of wisps and nodules.

Facies B is composed of a silty dolostone that is gray to light brown. Facies B

has a high amount of bioturbation. The primary trace fossils are helminthopsis burrows.

There are rare occurrences of thin laminations and brachiopod fragments.

Facies C is composed of a laminated silty dolostone that is light gray to light

brown. Facies C is characterized by the rhythmically bedded laminations. The types of

lamination observed in the facies are parallel, wavy, and cross laminated. There is a low

amount a bioturbation observed in this facies.

Facies D is very fine grained sandstone that is light brown. This facies is quartz

rich. There are millimeter sized laminations with some minor amount of bioturbation

found in Facies D.

Facies E is composed of a laminated to bioturbated silty dolostone that is gray to

light brown. There are wavy discontinuous laminations observed throughout this

interval.

Facies F is a fossiliferous dolomitic to lime wackestone that is dark gray to

brown. There are sporadic laminations found through the section, and fair to moderate

bioturbation is observed.

The upper shale is an organic rich mudstone, and is black to dark brown in color.

The shale has millimeter sized laminations, is slightly burrowed, and contains minor

fossil fragments. The upper contact is sharp with the overlying Lodgepole Formation.

25

Figure 3.13. Brutus East Lewis 3-4-H core description (from Alexandre, 2011)

26

3.4.2 RR Lonetree Edna 1-13 (Sec. 1-T23N-R56E)

The Lonetree Edna well is located just east of the central part of Elm Coulee

Field. The cored interval is 10,362-10,421 ft and contains only the Upper Bakken Shale

and three of the Bakken facies: A, B, and C (Figure A4).

Facies A is composed of a silty clay-rich wackestone that is light gray to gray.

The facies has abundant fossil fragments that consist of brachiopod and crinoid

fragments. There is a fair to moderate amount of bioturbation. Facies A is the base of

the Bakken Formation and sits unconformably on the Three Forks Formation.

Facies B is composed of a silty dolostone that is gray to light brown. The facies


There are rare occurrences of thin laminations and brachiopod fragments. Clay content

decreases near the top of the facies.


brown. Facies C is characterized by the rhythmically bedded laminations. XRD data

indicates that the amount of clay content increase near the top of Facies C.

The upper shale is an organic-rich mudstone that is black to dark brown in color.

The shale has millimeter sized laminations, the occasional burrowed interval and

contains fossil fragments. The upper contact is conformable with the Lodgepole

Formation.

3.4.3 Foghorn-Ervin 20-3 (Sec. 20-T23N-R58E)

The Foghorn Ervin 20-3 well is located in the south-east area of the Elm Coulee

Field. The cored interval is 10,487-10,546 ft and contains the Upper Bakken Shale and

five of the Bakken facies: A, B, C, E, and F (Figure A5).


This facies has abundant fossil fragments that consist of brachiopod and crinoid

fragments. There is a fair amount of bioturbation and some horizontal burrows. Facies A

forms the basal unit of the Bakken Formation, and sits uncomformably on top of the

Three Forks Formation.

27



Facies B tends to have less clay content toward the top.

Facies C is a laminated silty dolostone that is light gray to light brown. This facies

has cross and wavy laminations and some minor bioturbation is observed.


light brown. The facies is more bioturbated at the base and has a few laminations

toward the top.

Facies F is a fossiliferous dolomitic to lime wackestone. The facies is dark gray to

brown, and abundant brachiopod fragments are found throughout this facies.

The upper shale is an organic-rich mudstone, and is black to dark brown in color.

The shale has millimeter-sized laminations which become less frequent toward the top.

The upper contact is conformable with the Lodgepole Formation.

3.4.3 Jackson Rowdy 3-8 (Sec. 3-T26N-R51E)

The Jackson Rowdy 3-8 well is located in the north-west area of the Elm Coulee

Field. The cored interval is 7,627-7,683 ft and contains both of the Bakken shales and

six of the Bakken facies: A, B, C, D, E, and F (Figure A6).

The lower shale is an organic rich mudstone, and is dark in color. The shale has

thin millimeter sized laminations. The facies has micro-fractures that are generally

cemented by calcite and pyrite.

Facies A is composed of a silty clay rich wackestone that is light gray to gray.


fragments. There is a low to fair amount of bioturbation that increases toward the top of

the facies.



There are rare occurrences of thin laminations and brachiopod fragments.

28


brown. The facies is characterized by the rhythmically bedded laminations. There is a

low amount a bioturbation observed at the base of this section.

Facies D is very fine-grained quartz-rich sandstone that is light brown. There are

millimeter sized laminations found in Facies D.


light brown. The laminations are discontinuous to wavy, and become more rare toward

the top of the interval where the bioturbation increases.

Facies F is a fossiliferous dolomitic to lime wackestone that is dark gray to

brown. Brachiopods fragments are observed in this facies, and there is a fair to

moderate amount of bioturbation.

The upper shale is an organic-rich mudstone, and is black to dark brown in color.

The shale has millimeter sized laminations, is burrowed, and contains fossil fragments.

There is some pyrite nodules observed in the upper shale.

3.4.4 Vaira 44-24 (Sec. 24-T24N-R31E)

The Vaira well is located in a central part of Elm Coulee Field. The cored interval

is 9,998-10,035 ft and contains the Upper Bakken Shale and three of the Bakken facies:

A, B, and C (Figure A7).



fragments. Bioturbation is moderate to low in this interval.



There is a higher amount of bioturbation toward the base of the interval.


brown. The facies is characterized by the ripple and parallel laminations. There is a

higher amount a bioturbation observed at the base of this section.

29

The upper shale is an organic-rich mudstone that is black to dark brown in color.

The shale has millimeter sized parallel laminations. The upper contact is conformable

with the Lodgepole Formation.

3.4.5 Williams 1-4 (Sec. 4-T23N-R55E)

The Williams well is located in a central part of Elm Coulee Field. The cored

interval is 10,047-10,072 ft and contains the Upper Bakken Shale and three of the

Bakken facies: A, B, and C (Figure A8).

Facies A is composed of a silt-rich wackestone. The facies is light gray to gray.


fragments. Bioturbation is low to absent in this interval.

Facies B is composed of a silty dolostone. The facies is gray to light brown. The

facies has a high amount of bioturbation. The primary trace fossils are helminthopsis

burrows. There is a higher amount of bioturbation toward the base of the interval.

Facies C is composed of a laminated silty dolostone. The facies is light gray to

light brown. The facies is characterized by the ripple laminations. There is a higher

amount a bioturbation observed at the base of this section.

The upper shale is an organic rich mudstone, and is black to dark brown in color.

The shale has millimeter sized parallel laminations.

3.5 Mineralogy and Diagenesis

Analysis of the mineralogy and diagenesis of the Elm Coulee Field is critical

component of reservoir quality. The reservoirs with the best reservoir characteristics

tend to be high in dolomite, and low in calcite and clay minerals. The process of

dolomitization is the key process in developing reservoir quality rock. Dolomitiztion is the

exchange of calcium ion with magnesium ion in carbonate rocks. The volume of the

magnesium ion is less than that of a calcite ion so the exchange can increase the pore

spaces in carbonate rocks up to 13%.

The importance of dolomite was noted in core studies (Figures 3.14 and 3.15).

The high percentages of dolomite corresponded with high porosity and permeability

values. To identify dolomite in non-cored wells,a series of cross plots were made. The

plots compare the percentage of dolomite seen in the XRD data with bulk density well

30

log values. The results of this study indicate that the dolomite signature is between 2.63

g/cm3 and 2.66 g/cm3 (Figure 3.16 and 3.17). The calcite is 2.8-2.9 g/cm3 on the bulk

density curves (Figure 3.17).

The average bulk density in Facies B and Facies C was mapped across the

study area (Figure 3.16). The trends on the map highlight that the dolomitic signature

was found in southern parts of the study area. These areas tend to have the best

porosity and associated production in Richland County. There are diagenetic pinch-outs

of the dolomite facies to the northeast and northwest of Richland County (Figure 3.18).

These pinchouts may also act as diagenetic traps that are a result of poor reservoir

quality in the key facies.

In addition to having better matrix porosity and permeability, the dolomite tends

to be more brittle and thus more susceptible to the tectonic stress in the study area.

These stresses can cause fractures in the rocks and can contribute to reservoir quality.

31

Figure 3.14. RR Lonetree, gamma ray, porosity, and permeability and XRD analysis. The well log data shows good porosity and permeability corresponding to areas with high amounts of dolomite and low amounts of calcite and chlorite.

32

Figure 3.15. Jackson Rowdy, gamma ray, porosity, and permeability and XRD analysis. The well log data shows good porosity and permeability corresponding to areas with high amounts of dolomite and low amounts of calcite and chlorite.

33

Fig

ure

3.1

6. B

rutu

s E

ast Le

wis

cro

ss p

lot of

bu

lk d

en

sity a

nd X

RD

pre

centa

ge

of

dolo

mite a

nd

calc

ite

(lim

esto

ne).

T

he c

olo

red d

ots

refe

r to

the

de

pth

of th

e M

iddle

Ba

kken.

The

red

is a

t 7,6

36 f

t a

nd the d

ark

blu

e is

7,6

78

ft. D

ata

sh

ow

s t

hat

a h

igh

pre

ce

nta

ge

of

dolo

mite

co

rre

sp

on

ds t

o a

bu

lk d

en

sity o

f 2

.63

g/c

m3,

an

d t

he

ca

licte

sig

natu

re is 2

.68 g

/cm

3 .

34

Figure 3.17. RR Lonetree Edna, cross plot of bulk density and XRD precentage of dolomite. The colors refer to the depth of the Middle Bakken. The red is at 10,376 ft and the dark blue is 10,408 ft. The data shows an average bulk density of 2.63 g/cm3 where there is a high precentage of dolomite.

35

Fig

ure

3.1

8. A

vera

ge

bulk

den

sity m

ap o

f th

e M

iddle

Ba

kken.

Th

e a

vera

ge

do

lom

ite s

ignatu

re (

2.6

3-2

.66 g

/cm

3)

is o

bse

rved in

the

south

ern

ha

lf o

f th

e s

tud

y a

rea.

Th

e c

alc

ite s

ignatu

re 2

.68

-2.6

9)

g/c

m3 is s

een

in the n

ort

hern

and

weste

rn p

art

s o

f th

e s

tud

y a

rea

, and

are

consid

ere

d a

s d

iagen

etic p

inch o

uts

of

reserv

oir p

ropert

ies.

36

CHAPTER 4

SUBSURFACE WELL LOG INTERPRETATION

Digital well logs were acquired for 421 wells in the Elm Coulee study area (Figure

4.1). All of the wells are vertical penetrations. The wells were selected on the

availability of resistivity, gamma ray, and density-neutron logs. All of the digital logs were

obtained from TGS Geological Products and Services. There are six wells that had

conventional cores that could be used to compare with the digital logs. Wells that did not

penetrate the Bakken Formation were not used in this study. Strata from the Devonian

Three Forks to the Mississippian Lodgepole formations were identified and used in

subsurface mapping. Using well log signatures, a series of cross sections, and structure

and isopach maps were constructed.

4.1 Methods

The well logs were loaded into Geographix geologic mapping and correlation

software. Petrophysical log signatures of gamma ray and density-neutron porosity were

compared to the six Elm Coulee whole cores to enable Bakken Formation facies

correlation. The Upper Bakken Shale, Lower Bakken Shale, and Middle Bakken A, B, C,

E and F facies were mapped over the Elm Coulee Field. The underlying Three Forks

Formation and the Nisku (BirdBear) Formation were also mapped.

Formation Tops were picked in the 421 wells and used to construct a series of

northwest-southeast and northeast-southwest cross sections (Figure 4.2). Isopach and

structure maps were constructed to determine the areal distribution of the individual

Bakken facies. The maps also exhibit the overall geometry of the Elm Coulee Field seen

in the mapping of the major units.

4.2 Structural Cross Section

Eight structural cross sections were constructed across the Elm Coulee Field

area, cross sections A-A ,B-B, and C-C are oriented in the northwest-southeast

orientation. Cross sections D-D, E-E, F-F, G-G, and H-H are in a northeast- southwest

orientation (Figures 4.3 and B1 through B7). The structural cross sections are used to

37

Fig

ure

4.1

. L

ocation m

ap o

f dig

ital w

ells

. Y

ello

w s

quare

s m

ark

dig

ital w

ell

loca

tio

ns

38

map TVDSS

contour interval is 200ft.

Fig

ure

4.2

. Location m

ap o

f str

uctu

ral an

d s

tratigra

phic

cro

ss s

ections.

Top

Bakke

n s

tructu

re m

ap.

Conto

ur

inte

rval is

200

ft.

39

determine the geometry of Elm Coulee Field. The top formation picks are used to

generate depth calibrated structural surfaces that will be used in Petrel.

4.3 Stratigraphic Cross Section

Eight stratigraphic cross sections were constructed across the Elm Coulee Field

area, cross sections A-A, B-B, and C-C are oriented in the northwest-southeast

orientation (Figures 4.4 and C1 through C8). Cross sections D-D, E-E, F-F, G-G, and

H-H are in a northeast southwest orientation. The stratigraphic cross sections helped in

mapping of the individual Bakken facies and their log character across the field. The

thickness of the individual facies and their areal extent are displayed in a series of

isopach maps. The total Middle Bakken isopach shows a thick orientation in the

northwest in the middle of Richland County (Figure 4.5).

4.4 Structure Maps

Structure maps were made on the top of the Upper Bakken Shale, Three Forks,

and Nisku (Birdbear) formations (Figures 4.6 through 4.8) . All three fromations are

present in the digital logs selected for this study. The maps show a dip to the southeast.

The maps do not show any major fault features, however, there are some contour

anamolies that may suggests subtle tectonic activity. These anomalies are present as

bends and noses in the contours. There is also a change in dip in the north-west portion

of the study area.

4.5 Isopach Maps

Isopach maps were constructed for the Bakken facies and the Three Forks

formations. The Bakken Formation is divided into seven facies (Figures 4.10 through

4.16). The mapping of the Bakken facies helped to determine areal extent and

depositional thickness of the producing formations in the Elm Coulee Field. The top of

the Bakken formation was used as a stratigraphic datum. This was used because its a

conformable surface with overlying strata, and is areal extensive across the study area.

The depocenter for the Bakken Formation in the study area has a northwest to southeast

orientation across Richland County (Pramudito, 2008). The Bakken Formation ranges

from 5.5ft to 52ft thick with an average thickness of 36ft in the study area (Figure 4.5.)

40

Fig

ure

4.3

. S

tructu

ral cro

ss s

ection

s G

-G`.

Th

e B

akke

n (

Pu

rple

), T

hre

e F

ork

s (

Gre

en)

an

d B

irdb

ear

(Ora

ng

e)

are

fo

rmation t

op

s c

orr

ela

ted a

cro

ss t

he s

tudy a

rea

. T

he t

rack o

n th

e left is g

am

ma r

ay (

red

) an

d th

e r

ight

tra

ck is

resis

tivity (

bla

ck).

G

G

SW

N

E

41

light gray is facies E and F, the light

red is facies B and C and the purple is facies A.

Fig

ure

4.4

. S

tratigra

phic

cro

ss s

ection

G-G

`. T

he d

ark

gra

y is t

he

Upper

and

Lo

wer

Bakke

n S

hale

s. T

he lig

ht gra

y is

facie

s E

an

d F

, th

e lig

ht

red is facie

s B

and C

, an

d th

e p

urp

le is facie

s A

.

G

G

SW

N

E

42

). Contour

interval is 2.

5ft. The thickness ranges from 1.5ft to 5ft in the study area

Fig

ure

4.5

. T

hic

kn

ess m

ap o

f th

e M

idd

le B

akke

n M

em

ber

(facie

s A

,B,C

,D,E

, an

d F

). C

onto

ur

inte

rval

is 2

.5 f

ee

t. T

he th

ickn

ess r

an

ges fro

m 5

.5 f

ee

t to

52

fe

et in

the s

tud

y a

rea

. T

he

Mid

dle

Ba

kke

n

Mem

ber

thin

s t

o t

he n

ort

h a

nd e

ast and p

inches o

ut

to t

he

south

an

d w

est.

43

The Lower Bakken facies pinches out to the south of Elm Coulee Field. The

Lower Bakken Shale is only found in the northen parts of the field area (Figure 4.15).

Facies A, B and C thicken in the middle of Elm Coulee, and thin to the north and pinch

out to the south.

The E and F faices are found restricted to the northern parts of the study area,

and thicken toward the center of the basin. The Upper Bakken Shale extends over the

total study area and thins toward the south. The Three Forks Formation ranges in

thickness from 80ft to 180 ft. This formation thins to the southwest. Pramudito (2008)

suggested that the southern portion of the study area was preferentially uplifted

adrian almanza thesis 2011

Documents

elm coulee oil field

lower bakken shale

upper bakken shale

thick middle bakken

middle bakken member

bakken petroleum system

critical reservoir properties

structural model