North Dakota Geological Survey

Examination of Hydrocarbon Saturation

within the upper Black Island Formation

(Garland Member), Winnipeg Group By

Timothy O. Nesheim

Geological Investigation No. 166

North Dakota Geological Survey

Edward C. Murphy, State Geologist

Lynn D. Helms, Director Dept. of Mineral Resources

2013

Introduction 1

Geology 1

Observations 1

Methodology 7

Interpretations and Discussion 8

Conclusions 17

References 17

Figures

Figure 1 Example log and illustrated core of the Black Island Formation 2

Figure 2 Isopach of Garland Member Sandstone A 3

Figure 3 Isopach of Garland Member Sandstone B 4

Figure 4 Isopach of Garland Member Sandstone C 5

Figure 5 East-west cross-section of the Black Island Fm. with core and log analysis data 6

Figure 6 Map depicting water analysis data from the Black Island Formation 9

Figure 7 Formation temperature map of the Black Island Formation 10

Figure 8 Wireline log from the Brenna-Lacey 1 #32 comparing core and log porosities 11

Figure 9 Wireline log from the McKeen #30-23 comparing core and log porosities 12

Figure 10 Log porosity map of Sandstone A 13

Figure 11 Hydrocarbon saturation map of Sandstone A with Black Island structure contours 14

Figure 12 Hydrocarbon saturation map of Sandstone A with Icebox thermal maturity area 16

Plate

Plate 1 Cross-sections and Isopach maps with core data of Sandstones A, B, and C

Appendixes (CD version only)

Shapes files for Figures 2, 3, 4, 10, and 11.

Compiled core analysis data from Black Island cores (PDF and Excel files)

Sandstones A-C tops data set (spreadsheet)

Introduction

The Black Island Formation represents the lower portion of the Winnipeg Group, which was deposited

during a middle Ordovician marine transgression (LeFever et al., 1987). Consisting mostly of sandstone

interbedded with shaly to shale intervals (Fig. 1), the Black Island Formation has produced over 17

million barrels of oil equivalent (boe) from only 18 vertical wells (Nesheim, 2012). Clean quartz arenite

intervals within the Garland Member (upper Black Island Fm.) have been the primarily completion target

of Winnipeg productive wells (Nesheim, 2012) and are the focus of this publication.

Geology

The Black Island Formation has been broken down into two members (Ellingson, 1995; Ellingson &

LeFever, 1995), the lower Hawkeye Valley Member and the upper Garland Member (Fig. 1). The

Hawkeye Valley Member consists primarily of redbeds, oxidized shales to sandstones (Fig. 1) deposited

in a continental fluvial/deltaic setting (Ellingson, 1995; Ellingson & LeFever, 1995). The Garland Member

was deposited in a shallow marine setting (Ellingson, 1995; Ellingson & LeFever, 1995) and consists

primarily of two lithofacies: shaly to silty bioturbated sandstone representing lower to upper offshore

(subtidal) deposits, and fine to medium grained, rounded to well rounded, well sorted, massive to cross-

bedded quartz arenites representing foreshore/shoreface deposits. Through examination of cores and

logs of the Garland Member, there appear to be three foreshore/shoreface sandstone (quartz arenite)

intervals preserved within the Garland Member: Sandstones A, B, and C (Fig. 1). Sandstones A-C are

assumed to be shoreline deposits, but could also consist in part of similar sandstone bodies such as bar

sand deposits.

Sandstone A tends to be the thickest of the three main quartz arenite intervals within the Garland

Member. Sandstone A reaches thicknesses of around 50 ft. along the Nesson Anticline (Fig. 2), away

from which it thins in all directions. Sandstones B and C tend to be thinner than Sandstone A, reaching

maximum thicknesses of 13 (Fig. 3) and 15 ft. (Fig. 4). Sandstones B and C are also more irregular in

their distribution and thickness than Sandstone A, but extend further to the south. The thickness

variations and irregular distributions of Sandstones B and C may be a function of deposition and/or

preservation. In an eastward trend, the gamma ray signature of the Garland Member decreases (Plate

1, cross-section A-A’) and Sandstones A-C appear to merge together, which is why the isopachs in this

publication end approximately in central North Dakota (Figs. 2-4).

Observations

Along the Nesson and Antelope Anticlines, the entire Black Island section appears to be hydrocarbon

charged based on core analyzes (Fig. 5) and production. From compiled core data, the silty to shaly

bioturbated sandstones along the Nesson and Antelope Anticlines average 5.0% porosity and 0.26

millidarcies of permeability with 13.3% oil saturation and 45.0% water saturation while the non-

1

6 16Caliper (in)

0 150Gamma Ray

0.3 -0.1Density Porosity0.3 -0.1Neutron Porosity

0.2 2000Resistivity

Iceb

oxFm

.

Win

nipe

g G

roup

(Ord

ovic

ian)

Gar

land

Mem

ber

Haw

keye

Val

ley

Mbr

.

(Lime)

(Lime)

Blac

k Is

land

For

mati

onD

eadw

ood

Form

atio

n

- Bioturbation- Cross-bedding

Sandstone A

Sandstone B

Sandstone C

Figure 1. Composite example log and illustrated core of the Black Island Formation along the Nesson and Antelope Anticline area. Wireline log sets from Amerada Hess’s Pederson #14-22 (NDIC: 12363, API: 33-105-01340-00-00, Sec. 14, T157N, R95W) and Brenna-Lacey 1 #32 (NDIC: 13405, API: 33-053-02397-00-00, Sec. 1, T152N, R95W) were combined to display the typical log signatures of the Garland Sandstones A, B, and C of the area. Illustrated core lithologies (right) are based off of several partial Black Island cores, primarily including: Amerada’s Antelope Unit “A” #1 (NDIC: 2373, API: 33-053-00410-00-00, Sec. 1, T152N, R95W), Amerada Hess’s Brenna Lacey 1 #32 and Oscar Moe #32-43 (NDIC: 13647, API: 33-053-02459-00-00, Sec. 32, T153N, R94W). Depths correlate with that of the Brenna-Lacey 1 #32.

8 ft.

16 ft.

24 ft.

32 ft

.40 ft

.

0 ft.

40

MILES

0

A’

A

Figure 2. Isopach of Sandstone A from the Garland Member, upper Black Island Formation. Black dots show the location of control wells. Contour lines are in 2 ft. intervals. A-A’ shows the location of the Figure 5 cross-section.

3

0 ft.

4 ft.

8 ft.12

ft.

12 ft

.

40

MILES

0

A’

A

Figure 3. Isopach of Sandstone B from the Garland Member, upper Black Island Formation. Black dots show the location of control wells. Contour lines are in 1 ft. intervals. A-A’ shows the location of the Figure 5 cross-section.

4

0 ft.

4 ft.

0 ft.

8 ft.

8 ft.

12 ft

.

8 ft.

40

MILES

0

A’

A

Figure 4. Isopach of Sandstone C from the Garland Member, upper Black Island Formation. Black dots show the location of control wells. Contour lines are in 1 ft. intervals. A-A’ shows the location of the Figure 5 cross-section.

5

Garland Mbr.Hawkeye Valley

Member

Sandstone A

Sandstone B

Sandstone C

13,7

00 �

.13

,800

�.

13,9

00 �

.

14,2

00 ft

.14

,100

ft.

14,0

00 ft

.

14,6

00 ft

.14

,500

ft.

14,4

00 ft

.

G l d MbG l d Mb

00

tt

111144,

4400

..

organic-rich shale interval

Caliper

Gamma

Density Porosity(Lime)

Neutron Porosity(Lime)

6 16

0 100Resistivity Oil %

0 100

100 0Water %

(Core)

(Core)0 2000Water %

100 0(Log)

-0.1 0.3

-0.1 0.3Caliper

Gamma

Density Porosity(Lime)

Neutron Porosity(Lime)

16

1000

6Resistivity

0 2000Water %

100 0(Log)

-0.1 0.3

-0.1 0.3Caliper6 16

0 100Gamma

Resistivity Oil %0 100

100 0Water %

0 3TOC wt. %

(Core)

(Core)

(Core)0 2000

Blac

k Is

land

Fm

.W

inni

peg

Gro

upD

eadw

ood

Form

atio

n(C

ambr

ian-

Ord

ovic

ian)

Iceb

ox F

m.

#932633-061-00282-00-00

SWNW Sec. 1, T156N, R92WGulf Oil Corp.Juma 1-1-1D

K.B. = 2,266 �.

#1340533-053-02397-00-00Sec. 1, T152N, R95W

Amerada Hess Corpora�onBrenna-Lacey 1 #32

K.B. =2,165 �.

#1269933-053-02293-00-00

SWNE Sec. 8, T148N, R100WConoco Inc.Schultz 8 #3

K.B. = 2,287 �.

Antelope An�cline

Figure 5. East-West Cross-Sec�on of the Black Island Forma�on with core and log analysis data. TOC wt. % data for Conoco’s Schultz 8 #3 was measured from core samples collected from the lower 25 �. of the Icebox Forma�on. While there is a lack of core data for the Hawkeye Valley Member, perfora�ons within the interval yield gas with minimal water sugges�ng overall good hydrocarbon satura�ons.

A A’

6

bioturbated sandstones (Sandstones A-C) average 5.7% porosity and 0.29 millidarcies permeability with

14.8% oil saturation and 22.6% water saturation. Production from vertical wells along the Nesson and

Antelope Anticlines yields primarily dry gas (~90% methane) with low amounts of water and condensate

(Nesheim, 2012). High gas concentrations explain why the core data displays significant empty pore

space (oil sat + water sat << 100%) in that gas will easily escape a core’s pore space shortly after a core is

cut. The low water production indicates that most of the water saturation observed in core is

irreducible (immobile) for both the bioturbated and non-bioturbated intervals.

Away from significant structure, limited core data suggests the Black Island Formation may be

continually hydrocarbon charged. For example, from Conoco’s Schultz 8 #3 (Fig. 5), an upper Black

Island core (Garland Member), consists of 30 ft. of silty to shaly bioturbated sandstone. Core analysis

data from this interval averages 6.4% porosity and 0.36 millidarcies permeability with 29.2% oil

saturation and 54.7% water saturation. These core analysis averages are similar to that of the

bioturbated sandstones along the Nesson and Antelope Anticlines, where the Black Island produces

hydrocarbons with a low water cut.

Methodology

To examine the regional distribution of hydrocarbon charge within the Black Island Formation, log

analysis is required due to the limited amount of Black Island cores. Both along and away from

structure, the clean, quartz arenite intervals (Sandstones A-C) within the Garland Member consistently

display high resistivity and neutron porosity cross-over signatures (Fig. 5, Plate 1 A-A’ & B-B’), indicating

these intervals are charged with significant amounts of gas. In order to better quantify these

observations, water saturations were calculated for Sandstone A using the Archie Equation (Eq. 1).

Eq. 1

Sw = (a x Rw) / (Rt x ϕm)

1/n

Where:

Sw = water saturation for interval of interest (uninvaded zone)

Rw = resistivity of formation water at formation temperature

Rt = true formation resistivity (i.e., deep resistivity)

ϕ = porosity

a = tortuosity factor

m = cementation exponent

n = saturation exponent

For several of the components within the Archie equation, constants were assumed. A tortuosity factor

(a) of 0.81 and a cementation exponent (m) of 2.0 were used, which are the recommended values for

7

consolidated sandstones from Asquith and Krygowski (2004). A saturation exponent (n) of 2.0 was also

assumed.

Formation water resistivity is a function of the total dissolved solids (TDS) content and the formation

temperature. To examine the TDS content of the water within the Black Island Formation, water

analysis data was compiled from water produced from the Black Island through production and drill

stem tests (DST’s) (Fig. 6). Based largely on water analyzed from productive wells completed only in the

Black Island, a TDS of 225,000 mg/L was used to calculate formation water resistivity. In order to adjust

the formation water resistivity for temperature, bottom hole temperatures were compiled from DST’s

run on the Black Island Formation (Fig. 7).

The next component needed for the Archie equation is the porosity (ϕ) of Sandstone A. Being that the

Black Island is comprised mostly of sandstone, the density porosity log curve (sandstone matrix) was

used for the porosity component. At times the density porosity and the core measured porosity data

sets for Sandstone A overlap very well (Fig. 8), and at other times the density porosity is consistently

higher than the core porosity values (Fig. 9). One possibility for the difference could be the varying

presence of natural fractures in the interval of interest where the log porosity is higher than that of the

core porosity. Variations in shale content, and possibly bioturbation, may play a role in the accuracy of

the log porosity as well. The quality of the log and/or core data could also play a role. Figure 10 displays

the contoured log porosity of Sandstone A.

Using the Archie Equation with components outlined above, water saturations (SW) were calculated for

Sandstone A from 52 wells across western North Dakota. Assuming all of the non-water filled pore

space is filled with hydrocarbons, hydrocarbon saturations for Sandstone A were calculated using 1-SW.

The calculated hydrocarbon saturations of Sandstone A were averaged by well and contoured to

generate Figure 11. In the study area, there were another 92 wells that penetrated Sandstone A, but

these wells either did not have a density porosity log or the density porosity log was unreliable due to

hole instability indicated by the caliper log.

Interpretations and Discussion

Utilizing the Archie equation, Sandstone A appears to be hydrocarbon charged (SW averages <50%)

across most of western-northwestern North Dakota (Fig. 11). Assuming the overlying Icebox Formation

is the source rock interval, and lateral hydrocarbon migration is minimal due to overall low permeability

within the reservoir (averages ~0.3 millidarcies), the entire Garland section should be hydrocarbon

charged wherever Sandstone A is charged. The high quartz sand content of the Garland Member likely

enhances its ability to take on a hydrocarbon charge.

The hydrocarbon saturations displayed in Figure 11 should be viewed cautiously for several reasons.

First, there is limited core data away from structure to validate the low calculated water saturations.

Second, factors such as changes in bioturbation grade, shale content, and variations in cementation

likely occur within Sandstone A across the study area, causing some variation in the accuracy of Archie

8

Nes

son

Ant

iclin

e

Antelope AnticlineHeart River Fault

Billi

ngs N

ose

Antic

line

Litt

le K

nife

Ant

iclin

e

Roug

h Ri

der

Antic

line

-9,5

00 ft

.

-7,5

00 ft

.

-11,500 ft.

-5,5

00 ft

.10

MILES

0

Area ofFigure

NDIC: #9056*TDS: 2,673 - 314,336 mg/LRw @ 68 F: 2.75 - 0.050 ohm-mWater Source: DST recovery

NDIC: #8169**TDS: 327,178 mg/LRw @ 70 F: 0.042 ohm-mWater Source: DST/Production?, Black Island/upper Deadwood

NDIC: #21235**TDS: ~225,000 mg/LRw @ 230 F: 0.015Water Source: ?

NDIC: #14815*TDS: 9,019 - 308,955 mg/LRw @ 77 F: 0.859 - 0.051 ohm-mWater Source: DST recovery

NDIC: #12831*TDS: ~266,000 mg/LRw @ 77 F: 0.042 ohm-mWater Source: Production, Garland Member (O-BI)

NDIC: #13682*TDS: ~139,970 mg/LRw @ 77 F: 0.042 ohm-mWater Source: Production, Black Island/upper DeadwoodNDIC: #4716*

TDS: 89,981 - 206,618 mg/LRw @ 77 F: 0.085 - 0.054 ohm-mWater Source: Production, Winnipeg Sand

* - Data retrieved from a Water Analysis Report (Oil & Gas well file)** - Data retrieved from a Oil & Gas hearing field file Figure 6. Map showing information on the Total Dissolved Solids (TDS) content and resistivity (Rw) of formation water collected from the Black Island Formation. Structure contours depict the top of the Icebox Formation. DST = Drill Stem Test

9

280°F26

0°F

240°F

220°F

240°F

200°F

205

218

246

244

218

200

238

214227

210245

200

214

230

212

224

264

270

274

282

280

275

296282

275

252

258

240

264

230

240

257

262180

191202

204196

205210

224

235

275

225249

238222

244

270

248

224226

225

219

224

256

304

244

283282

282

276

278278278

262

268

245

260

110

106

97

150?

Figure 7. Formation temperature map of the Black Island Formation. The contours displayed are meant to generalize the formation temperatures of the Black Island Formation and are based off of bottom hole temperatures (BHT) measured during Black Island drill stem tests (DST’s). BHT’s measured during DST’s are typically assumed to represent minimum formation temperatures. Black dots show control wells with the BHT listed next to each respective well. Some of the DST’s used above tested both the Black Island and the upper Deadwood Formations.

10

14,1

00 ft

.

14,1

00 ft

.14

,000

ft.

14,2

00 ft

.

Water SaturationsLog %

Core %100 0

Sandstone A

Sandstone B

Core - 3 ft. = Log

Sandstone A Average Core Porosity = 5.5%Average Log Porosity = 5.6%

- Bioturba�on

Caliper (in)0 100

Gamma Ray

0.2 2000Deep Resistivity

Caliper (in)

Gamma Ray Core Porosity0

0

15%

15%Density Porosity

(Sst. Matrix)

0

6

100

16

6 16

Haw

keye

Val

ley

Mem

ber

Gar

land

Mem

ber

Blac

k Is

land

For

mat

ion

Win

nipe

g G

roup

(Ord

ovic

ian)

Dea

dwoo

dFo

rmat

ion

Iceb

ox F

m.

#1340533-053-02397-00-00Sec. 1, T152N, R95W

Amerada Hess Corpora�onBrenna-Lacey 1 #32

K.B. =2,165 �.

Figure 8. Wireline log of the Black Island Forma�on from Amerada Hess’s Brenna-Lacey 1 #32 comparing core measured and log calculated water satura�on (le�) as well as core and log porosity (right). Note how well the core and log water satura�ons overlap for the clean, non-bioturbated sandstone intervals iden�fied in core within Sandstone A but tend to vary more in shaly and/or bioturbated intervals. The core and log porosity of any given point along Sand A differs by 0-3% porosity while the overall porosity averages are approximately the same.

11

14,4

00 ft

.

Caliper (in)

Gamma Ray

Density Porosity (Sst.)

Core Porosity00

6

100

16 0

20%

20%

Core - 4 ft. = Log

Haw

keye

Val

ley

Mem

ber

Gar

land

Mem

ber

Blac

k Is

land

For

mat

ion

Win

nipe

g G

roup

(Ord

ovic

ian)

Deadwood Fm.

Iceb

ox F

m.

14,3

00 ft

.14

,400

ft.

14,5

00 ft

.

Gamma Ray

Caliper (in) Resistivity0 100

6 16

Water Saturations

Log

Core100 00.2 2000

#1258933-053-02267-00-00Sec. 30, T153N, R94WAmerada Hess Corp.

McKeen #30-23K.B. = 2,269 ft.

Figure 9. Wireline log of the Black Island Forma�on from Amerada Hess’s McKeen #30-23 comparing core measured and log calculated water satura�on (le�) as well as core and log porosity (right) of the Garland Member Sandstone A. The core measured porosity values tend to be 2-5% porosity lower than the log porosity curve. The core measured and log calculated water satura�ons overlap closely for the upper 14 �. of Sandstone A, where the core and log porosity values trend more closely together.

Sandstone AAverage Core Porosity = 4.5%Average Log Porosity = 8.2%

- Bioturba�on

12

6.7% (3)

4.2% (1)

4.9% (30)

5.5% (44)6.4% (15)

4.5% (37)

5.6% (40)

5.2% (35)5.5% (42)

7.2% (40)

10.6% (2)

11.5% (3)

3%

5%

7%

9%

11%13%

15%17%

Holte #6-21

Figure 10. Log (Density Porosity-sandstone matrix) averaged porosity map of Sandstone A” Black dots show control wells. Orange stars show locations of partial to complete cores of Sandstone A with the average core measured porosity listed and number of core analyzes in paretheses. Note how Sandstone A is more porous east of the Nesson Anticline than to the west. Core measured porosity averages are similiar to the log porosity average, but the core averages vary a little more over short distances. The caliper log of each well was examined to determine if the density porosity curve was reliable or not. The intervals in which the borehole diameter notably increased, based on the caliper log, were removed from the density porosity average.

13

70-80%60-70%50-60% 30-40% 10-20%

<10 %20-30%40-50%> 80%~Hydrocarbon Saturation

-11,500 ft.

-9,500 ft.

-7,5

00 ft

.

-5,5

00 ft

.

Sandstone A absent

Nes

son

Anti

clin

e

Billi

ngs

Nos

e

Roug

h Ri

der A

nticl

ine

Heart River Fault

Antelope Anticline

Little Knife A

nticline

New

burgh Syncline

NewporteImpact Structure

Area of Figure

Figure 11. Hydrocarbon saturation map for Sandstone A of the Garland Member (upper Black Island Formation). Contours were initially generated using the map module in Petra and before being modified manually. The dotted lines depict structure contours on the Black Island Formation surface.

14

Equation calculations. For example, shale content increases an intervals electrical conductivity, which

artificially increases the calculated water saturation. Third, non-hydrocarbon gases such as carbon

dioxide and nitrogen make up 3-32% of gas produced from Black Island vertical completions across

western North Dakota (Nesheim, 2012), and therefore occupy some of the non-water filled pore space

within Sandstone A. Across the Nesson and Antelope Anticlines, analyzed Black Island gases have

averaged approximately 83.1% methane, 10.8% nitrogen, 3.5% carbon dioxide, 1.4% ethane, and 0.2%

propane.

The Sandstone A hydrocarbon charged area correlates well with where the overlying Icebox Formation

has been modeled to be near its maximum thermal maturation (Fig. 12). Geochemical data from Icebox

samples from southern Saskatchewan (compiled from Osadetz et al., 1992 & Siebel, 2002) average as a

good quality source (~1-2% TOC), supporting the idea that the Icebox has sourced the Black Island’s

hydrocarbons. Sandstone A is located 60-100 ft. below the base of the Icebox throughout most of

western North Dakota (Fig. 1, Plate 1 A-A’ & B-B’). Therefore, in order to expel enough hydrocarbon

volume to adequately charge the underlying Black Island reservoir to include Sandstone A, the Icebox

Formation likely needs to be near its peak thermal maturity.

Two anomalous regions of higher water saturation in Sandstone A occur within the area of peak Icebox

maturation (≥95% kerogen conversion). Along the southern extent of Sandstone A, calculated water

saturations increase to upwards of 75% (Fig. 11 & 12). This southern area, however, is where Sandstone

A thins and pinches out (Fig. 2), possibly grading into shaly, bioturbated sandstone. The thinning of

Sandstone A along with a possible increase in the reservoir’s heterogeneity (bioturbation) and shale

content likely both diminishes the reservoir quality of Sandstone A and the accuracy of the Archie

Equation. The second anomalous area is located in northwestern North Dakota along the Canadian

border (Fig. 11 and 12). Within Jordan Exploration’s Holte #6-21 (NDIC: 15137, SENW Sec. 21, T162N,

R94W), located in western Burke County (Fig. 10 & 12), Sandstone A’s log porosity is anomalously low

with an average of only 1.7%. The surrounding wells average 4-8% log porosity for Sandstone A. So

either the log porosity of Sandstone A from the Holte #6-21 is inaccurate, making the log calculation

inaccurate, or the well was drilled within a zone of extremely low porosity where Sandstone A was

unable to take on a significant hydrocarbon charge.

The hydrocarbon potential of the Black Island Formation is not limited to just gas. While Winnipeg

(Black Island) production has consisted of wet to dry gas in North Dakota to date, Winnipeg production

in southern Saskatchewan has yielded primarily oil (Nesheim, 2012). Geochemical data reported by

Siebel (2002) indicates the Icebox Formation contains Type I to Type II kerogen, which is prone to

generating oil. With an oil-prone source rock, the hydrocarbon content of the Black Island reservoir

likely contains separate dry gas, wet gas, and oil windows depending on the level of maturation of the

system. Therefore, oil production from the Black Island Formation is possible at depths shallower than

current production in North Dakota.

15

70-80%60-70%50-60% 30-40% 10-20%

<10 %20-30%40-50%> 80%~Hydrocarbon Saturation

Sandstone A absent

95% kerogen conversion (Icebox Fm

.)

Area of Figure

Holte #6-21

Figure 12. Hydrocarbon saturation map for Sandstone A overlain by the model area of 95% conversion of Icebox kerogen to hydrocarbons (Nesheim and Nordeng, 2013).

16

Conclusions

The Garland Member (upper Black Island Formation) contains three regionally extensive clean

sandstone intervals: Sandstones A, B, and C. In the deeper portions of the Williston Basin, these clean

sandstone intervals display high resistivity and neutron porosity crossover signatures indicating

significant gas presence. Based on core analysis data, Sandstones A-C average 5-6% porosity, ~0.3

millidarcies permeability, and 10-20% water saturation, indicating they may represent a series of tight

gas reservoirs. Using the Archie Equation, the lower most clean sandstone interval, Sandstone A,

appears to average ≥60% hydrocarbon saturation in most of western-northwestern North Dakota which

suggests the entire Garland section is hydrocarbon charged. The area where Sandstone A appears to be

hydrocarbon charged correlates well with where the overlying Icebox Formation has been modeled to

be near peak thermally maturity. Based on the Icebox’s type I-II oil prone kerogen, and the observed

Winnipeg oil production in southern Saskatchewan, the Black Island Formation may transition from a

gas to an oil play in portions of North Dakota.

References

Asquith, G., and Krygowski, D., 2004, Log Interpretation, in G. Asquith and D. Krygowski, Basic Well Log Analysis: AAPG Methods in Exploration 16, p. 115-135.

Ellingson, J.B., 1995, Depositional Environments and Paleogeography of the Winnipeg Group (Ordovician), Williston Basin, North Dakota, University of North Dakota Master of Science Thesis, 231 pp.

Ellingson, J.B., and LeFever, R.D., 1995, Depositional Environments and History of the Winnipeg Group (Ordovician), Williston Basin, North Dakota: 7th International Williston Basin Symposium, p. 129-141.

LeFever, R.D., Thompson, S.C., and Anderson, D.B., 1987, Earliest Paleozoic history of the Williston Basin in North Dakota: Saskatchewan and North Dakota Geological Societies, Fifth International Williston Basin Symposium, p. 22-36.

Nesheim, T.O., 2012, Review of Ordovician Black Island Formation (Winnipeg Group) Oil and Gas Production: North Dakota Geological Survey, Geologic Investigations No. 161.

Nesheim, T.O., and Nordeng, S.H., 2013, Production and Hydrocarbon Shows from the Black Island Formation, Winnipeg Group (Ordovician): North Dakota Geological Survey, Geologic Investigations No. 167.

Osadetz, K.G., Brooks, P.W., and Snowdon, L.R., 1992, Oil families and their sources in Canadian Williston Basin (southeastern Saskatchewan and southwestern Manitoba): Bulletin of Canadian Petroleum Geology, v. 40, no. 3, p. 254-273.

Seibel, Christopher, 2002, An examination of the Source Rock Potential of the Deadwood and Winnipeg

Formations of Southern Saskatchewan: Masters of Science Thesis University of Regina, Regina, SK,

Canada, 140 p.

17

Smith, M.C., 2005, Geochemical analysis and familial association of oils and potential source rocks of the Ordovician Winnipeg Formation and Cambrian Deadwood Formation, Williston Basin, University of Regina Master of Science Thesis, 101 pp.

18