FORT BERTHOLD RESERVATION List of Topics - BIA · 2018-05-09 · The 100 and local roads. ... Lands nearly impossible to carry out due to the high fragmentation caused by within 7

FORT BERTHOLD RESERVATION List of Topics

BACKGROUND Reservation Overview Production Overview

GEOLOGIC OVERVIEW Geologic History Petroleum Systems Summary of Play Types

CONVENTIONAL PLAY TYPES Play 1 - Folded Structure-Mississippian Carbonate Play� Play 2 - Mississippian Shoreline Play� Play 3 - Mississippian Lodgepole Waulsortian Mounds� Play 4 - Ordovician Red River Play Play 5 - Devonian Nisku-Duperow Play Play 6 - Pre-Prairie (Winnipegosis/Interlake Play) Play 7 - Post Madison Clastics (Tyler-Heath) Play 8 - Pre-Red River Gas Play Play 9 - Bakken Fairway/Sanish Sand Play� �

UNCONVENTIONAL / HYPOTHETICAL PLAY TYPES Play 10 - Niobrara Microbial Gas Play

REFERENCES

OVERVIEW there are approximately 10 formations proved to be productive in the Fort FORT BERTHOLD RESERVATION Berthold area. Of further note, the facies distribution during lower Mississippian

time strongly suggests that Lodgepole trends are present on the Fort Berthold The Three Affiliated Tribes Indian Reservation (USGS). � The Three Affiliated Tribes have purchased seismic data from lines located in

Tribal Headquarter: New Town, North Dakota the western portion of the Reservation, which may be examined by parties Geologic Setting: � Williston Basin interested in oil and gas exploration. Some of the seismic data will be

reprocessed and may be correlated with borehole logs. Sections and data tapes Introduction reside with the Division of Energy and Minerals Resources of the Bureau of � The Fort Berthold Indian Reservation is located in west-central North Dakota Indian Affairs located in Denver, CO. approximately thirty miles southwest of the city of Minot. The Reservation contains portions of Dunn, McKenzie, McLean, Mercer, Mountrail and Ward Area Location and Access Counties and includes an area of about 1,530 square miles or 980,000 acres. � Fort Berthold Indian Reservation comprises parts of Dunn, McKenzie, These lands are located 15 miles east of the center of the Williston Basin, a McLean, Mercer, Mountrail, and Ward Counties in west-central North Dakota geologic area where undiscovered accumulations of oil and gas may be located. (Figure 1), near the confluence of the Missouri and Little Missouri River valleys. � Several studies have been published over the years which indicate high Total area is about 1,530 square miles, approximately 11 percent of which is potential for undiscovered oil and gas reserves on the Fort Berthold Reservation. covered by waters impounded by Garrison Dam (Lake Sakakawea). The lake There has been past interest exhibited by oil companies, however, high royalties, divides the reservation into four distinct areas, here referred to as the western, high lease acquisition costs, inability to assemble large blocks of acreage, rights southern, eastern, and north-central segments. to seismic data, Tribal Employment Rights Office (TERO) regulations, taxes, and � Although reservoir waters somewhat impede travel between the four land a 100 percent signature requirement imposed by the federal statute on Trust lands segments, most of the reservation is accessible over a system of State highways have served as deterrents to oil and gas exploration on the Reservation. The 100 and local roads. Rail service is provided to the northern part of the reservation by percent signature requirement regulation has made exploration on Tribal Allotted the Soo Line Railroad. A main east-west line of the Burlington Northern passes Lands nearly impossible to carry out due to the high fragmentation caused by within 7 miles of the reservation, roughly paralleling the southern boundary. heirship. The Tribes are currently working to correct these problems to open the door for future gas and oil exploration and development. The Three Affiliated Physiography Tribes are striving to work closer with oil companies to make oil and gas � The Fort Berthold Indian Reservation includes land that ranges from rugged exploration on Fort Berthold competitive with lands outside of the Reservation. badlands to rolling plains. Altitudes range from about 1,850 feet at Lake � The Fort Berthold Reservation possesses all the requisites for commercial Sakakawea to over 2,600 feet on Phaelen's Butte near Mandaree. The reservation petroleum development. According to an oil and gas study authorized by Joe H. is within the Northern Great Plains Physiographic Province and may be divided Rawlings, source rocks and reservoir caprock combinations are in evidence from into four physiographic units: (1) the Coteau Slope; (2) the Missouri River trench the Antelope field located near the northwest corner of the Reservation. This (now flooded); (3) the Missouri Plateau; and (4) the Little Missouri Badlands. field produces both oil and gas from four different zones. The relatively new South of Lake Sakakawea the reservation has a bedrock surface with scattered Plaza field, located near the east exterior boundary, is also a major producing oil areas of glacial drift. North of the lake, glacial deposits predominate and only field. Other fields were recently discovered on the Reservation while drilling the patches of bedrock crop out. The landscape reflects this distribution of sediments: Bakken and Mission Canyon formations. This multiplicity of geologic structures south of the lake, hills and badlands are common; north of the lake the glaciated argues the presence of the many deep traps. Regardless of the development of topography is mainly undulating to rolling. these fields, much of the Reservation has not been explored for accumulations of � The reservation area north of Lake Sakakawea is part of the Coteau Slope, oil and gas. which has both erosional and glacial landforms with glacial predominating. � The Williston Basin, which encompasses the Reservation, has a long history Gentle slopes characterize 50 to 80 percent of the area and local relief ranges of production. Much of the oil in this area was sourced by the organically rich from 50 to 200 feet. The Little Missouri Badlands lie adjacent to the Little Bakken Formation. New horizontal drilling technology has made production Missouri River south and west of Lake Sakakawea as well as in a few restricted from Bakken source rocks possible. A report written for the Bureau of Indian areas along the Missouri River. They consist of rugged, deeply-eroded, Affairs by Susan Race Wager, states that the Fort Berthold Reservation is hilly land in which gentle slopes characterize only 20 to 50 percent of the area favorably located for exploration in the Bakken Formation. and local relief is commonly over 500 feet. Areas other than badlands south and � According to George Long of the Bureau of Land Management (BLM), there west of the lake are part of the Missouri Plateau. In these areas, gentle slopes have been 571 tests for oil and gas on or immediately adjacent to the Fort characterize about 50 to 70 percent of the area and local relief ranges from 300 to Berthold Reservation resulting in a total of 392 producing wells and 179 plugged 500 feet. and abandoned wells; a 69% success ratio. The majority of these 179 plugged � The Missouri and Little Missouri Rivers and their larger tributaries have cut and abandoned wells did report oil and gas shows. Of special interest, there deeply into the bedrock and glacial deposits of various compositions. The appears to be production potential in the Mississippian Charles Formation which Missouri River is 300 to 500 feet below the upland plain. Near the western has been bypassed in all of the wells drilled except those few that are too shallow boundary of the reservation, the Little Missouri River has eroded a channel more to reach the Charles Formation located in the Mission Canyon. than 600 feet deep. Occasional ridges and bare buttes extend as much as 400 feet � Water saturation calculations were made on 60 wells to evaluate possible above the plain. bypassed production in the Mississippian Charles Formation. Possible oil and gas production was indicated in 52 of these 60 wells. According to the BLM,

Land Status � The Fort Berthold Indian Reservation was established by the Fort Laramie Treaty of September 17, 1851, for the Arikara, Mandan, and Hidatsa Tribes of Indians who later united to form the Three Affiliated Tribes. Executive Orders and Congressional Acts have limited the reservation to its present boundaries. The act of June 1, 1910, 36 Stat. 455, opened unallotted and unsold reservation lands to non Indians, thus creating the "ceded and diminished lands" boundary. It was assumed by many that only the remaining lands comprised the Fort Berthold Indian Reservation. A Federal appeals court (8th Cir. 1972), however, ruled that the 1910 Act did not change reservation boundaries and that the "homestead" (ceded) area remained a part of the reservation (City of New Town vs. United States, 454 F 2d 121) Public Law 437 and the Act of July 31, 1947 (amended October 29, 1947) made provision for lands inundated by the Garrison Dam reservoir. Table 1 summarizes the present extent of land holdings on the Fort Berthold Indian Reservation. Most of the north and northeast part of the reservation (the homestead area) is in private ownership. Land status data are from Bureau of Indian Affairs records. � Nearly 54 percent of the reservation's subsurface mineral rights are owned by the Three Affiliated Tribes. Mineral rights in the diminished reservation area are all tribally owned with the exception of 164.09 acres owned by the Federal government. The Tribes also retain mineral ownership for 110,623.13 acres of the homestead area. Lands in the Garrison reservoir area were severed.

Percentage

Classification � Acreage of total

Diminished Reservation Area Tribally-owned lands.� 57,954.20� 5.91 Allotted lands� 360,438.57� 36.76 Government-owned land� 164.09� 0.01 Privately owned (alienated) land� 55,865.14� 5.70

Subtotal� 474,422.00� 48.38

Reservoir Taking Area� 152,359.95� 15.54 Homestead (ceded) Area.� 353,792.59� 36.08 Total area of reservation.�

980,574.54� 100.00

TABLE 1 - Summary of land ownership, Fort Berthold Indian Reservation, N. Dakota

Contacts Inquiries concerning oil and gas leases on the Fort Berthold Reservation may

be directed to the Three Affiliated Tribes Natural Resources Department -telephone (701) 627-3627 or the Bureau of Indian Affairs, located in New Town,

North Dakota - (701) 627-3741.

85

73

94

2 8

94

83

52

52

8385

200

Williston

Stanley

Watford City

Minot

Underwood

Bismark

Belfield Dickinson

Beach

Williams

McKenzie

Billings Dunn

Mountrail

Ward

McHenry

McLean

Mercer

Oliver

Sheridan

Burleigh

Morton

FORT BERTHOLD

New Town

MO

NT

AN

AN

OR

TH

DA

KO

TA

Fort Berthold Reservation North Dakota OVERVIEW

Page 1 of 18

INTRODUCTION Fort Berthold Reservation

Williston Basin � Over 700 MMBO have been produced from the Williston Basin, one of the largest cratonic basins in North America. The reservation is ideally situated for numerous exploration targets within this basin. Several source rock horizons, including the world renown Bakken Formation, contribute to the prolific nature of the basin. � The Williston Basin contains an estimated mean value of 650 MMBO and 1.69 TCFG from undiscovered resources in conventional plays. Multiple episodes of maturation and migration occurred during Permian-Cretaceous time from these source intervals. Understanding the trapping mechanisms and migration pathways are critical to successful future exploration within the reservation area. Carbonate reservoirs in Paleozoic formations have been the primary focus of hydrocarbon exploration. Recent exploration targets include microbial gas in Cretaceous sediments and deep Paleozoic sandstone intervals.

Early Exploration in the Williston Basin and Fort Berthold Reservation � Early discoveries were made on large surface structures such as Nesson and Cedar Creek Anticlines, and Poplar Dome. The Williston Basin is distinctive among other Rocky Mountain basins because of its continuous basin subsidence and burial history throughout Paleozoic and Mesozoic time. Large volumes of clastic and carbonate sediments have been preserved. � Since the late 1940's, industry has found more than 960 fields and the basin has undergone multiple exploration cycles. The Williston Basin covers more than 143,000 sq. miles and Fort Berthold reservation covers about one percent of that total (1530 sq. miles). Most of the reservation is unexplored. � Gas was discovered at Cedar Creek Anticline in 1916; oil was discovered on Nesson Anticline in 1951. Nesson is located about 50 miles northwest of the reservation boundary. Antelope Field, a southeast plunging anticline, was discovered in 1953 and extends onto the reservation. Plaza and Wabek Fields, part of the Mississippian shoreline trend, were discovered in the 1980's. Condensate and gas were discovered in the Winnipeg and Deadwood Formations at Antelope Field in 1992.

Fort Berthold Reservation GENERAL PRODUCTION INFORMATION

U.S.G.S. Geologic Province - Williston Basin (031) Tectonic Province - Williston Basin

Fields within reservation boundaries 1996 cumulative production. Parentheses indicates discovery year

(1953) Antelope - 41 MMBO, 19.2 Mmcf, 30 oil wells, 2 gas wells (1989) Plaza - 2.9 MMBO, 3.9 Mmcf, 20 wells total (1982) Wabek - 5.4 MMBO, 3.9 Mmcf, 18 wells total

Nearby fields

(1955) Blue Buttes - 46 MMBO, 29.2 Mmcf, 44 wells total (1957) Bear Den - 1.5 MMBO, 1.7 Mmcf, 2 oil wells, 1 gas well (1952) Croff - 1.8 MMBO, 4.1 Mmcf, 3 wells total (1981) Spotted Horn - 108 MBO, 36,234 Mcf, (Abn'd) (1982) Squaw Creek - 195 MBO, 328,546 Mcf, 1 well total (1982) Mandaree - 160 MBO, 147,325 Mcf, 2 wells total (1990) Lucky Mound - 1.4 MMBO, 890, 670 MCF, 18 wells total

Figure FB-1.1. Producing horizon legend. Many of the potential reservoir intervals can be correlated into Wyoming and Montana. However, the Williston Basin is unique among other Rocky Mountain basins for its thick package of Paleozoic age carbonate sediments. While the other basins are known for their numerous clastic potential reservoir intervals, the Williston Basin is known as a carbonate province (modified after Seventh International Williston Basin Symposium Guidebook, 1995).

Fort Berthold Reservation North Dakota Introduction

Producing Horizon Legend (after Geomap Executive Reference Map, 1983)

= Source Rock

PRODUCING HORIZON LEGEND

Judith River

Niobrara

Greenhorn

Dakota Group

Nesson

Opeche

Minnelusa

Amsden

Heath

Kibbey

Lodgepole

Bakken Three Forks Nisku Duperow Souris River

Winnipegosis

Red River

Winnipeg

Mowry

Muddy

Fall River

Sundance

Canyon Springs

Gypsum

Chugwater

Spearfish

Goose Egg

Minnelusa

Madison

Lance Fox Hills Mesaverde Cody Shannon

Frontier

Mowry Muddy Bear River

Cloverly

Ankareh Thaynes Woodside

Dinwoody

Park City

Weber

Amsden Darwin

Madison

Lodgepole

Gall

Flath

Blackleaf Bow Island

Cat Creek Moulton

Cut Bank

Amsden

Heath

Kibbey

Sun River

Lodgepole

Three Forks

Nisku Duperow

Souris River

Red River

Flathead

WESTERN WYOMING

SOUTHERN MONTANA

WESTERN NORTHERN MONTANA

WILLISTON BASIN

POWDER RIVER BASIN

SE

RIE

S

SY

ST

EM

ER

A

TE

RT

IAR

Y

CE

NO

ZO

IC

CR

ETA

CE

OU

S

UP

PE

RLO

WE

R

JUR

AS

SIC

TR

IAS

SIC

PE

RM

IAN

PE

NN

SY

LVA

NIA

NM

ISS

ISS

IPP

IAN

DE

VO

NIA

N

SIL

UR

IAN

OR

DO

VIC

IAN

CA

MB

RIA

N

M E

S O

Z O

I C

P

A

L E

O

Z

O

I

C

B

I O

G

E

N

I

C

Sundance

Stump-Preuss

Twin Creek

Ellis Group

Reirdon Sawtooth

Wasatch Wasatch

Lance

Parkman Sussex Shannon Niobrara

Hell Creek Judith River

Eagle

Niobrara Greenhorn

Winnipeg

Tensleep

Swift Swift

Fort Union Fort Union

Teckla

Teapot

Telegraph Creek

S

S

S

S

S

S

Fort UnionFort Union

�Morrison

Ellis Group

Reirdon Piper

Morrison Gannet

Morrison Morrison

Nugget Chugwater

Phosphoria

Tyler Tyler

Big Snowy Group

Otter

Madison Group Charles Mission Canyon

Englewood

Mission Canyon

Big Snowy Group

Otter

Madison Group

Charles Mission Canyon

Dawson Bay

Jefferson

Interlake Interlake

Stonewall

Stony Mountain Big Horn Big Horn

Deadwood Deadwood Gros

Emerson

White River Green River Wind River

Fox Hills

Eagle

Mesaverde

Frontier

Niobrara Frontier

Clagget

Dakota

Lakota

Dakota

Kootenai

Sunburst

Spearfish

Jefferson

Darby

Minnekahta

Page 2 of 18

Alberta Shel f CANADA 97 98 114 113 100 99112 111 110 109 108 107 102 101 106 105 104 103 BF Sw

eetgrass

Hogeland Bearpaw Basin

Uplift

Dom

eBow

doin

UNITED STATES

Fault

A Poplar

BK Popla

r Faul

t

Hinsda

le

OVERTHRUST

FP Dome 48 Ness

on

Ant

iclin

e A'Little A

rch

Rocky Mtns Judith Mtns Blood

Big Little Snowy

Syncline

Creek

MONTANA Belt Mtns Cat Creek Fault

Weldo

n-Broc

kton F

ault

BR NORTH DAKOTA

WILLISTONBELT

Mtns Sumatra

Anticline C

edar CreekWheatland Willow

Fault Creek

Syncline

Porcupine BASIN Syncline Dome

Crazy BullMountains Mountains

Miles CityArch Basin

Lake SRBasin Fault Fault Nye-Bowler

Basin Beartooth

Pryor POWDER Mtns Mtns RIVER

Bighorn

BASIN BIGHORN SOU

TH DAKOTA AbsarokaM

tns BASIN Black

Owl

Mtns

Hills Uplift

Creek Mtns

IDAHO

Wind

WIND RIVER

Arch C

asper

WYOMING Fault

River

BASIN Casper Mt

n M

tns Sweetwater

Laramie GREEN Uplift Mtns Ha

rtville

Chadron

Upl

ift

RIVER HANNARED

Arch

BASIN BASINDESERT NEBRASKA Rock BASIN ALLIANCE

UTAH

Bow

Medicine

LARAMIE Springs Uplift BASIN BASIN

Sierra Uinta Mtns WASHAKE Madre

BASIN Mtns

Mtns COLORADO

EXPLANATION

Precambrian Basement Uplifts Anticline

Syncline Other Uplifts or Basins

Faults SR - Standing Rock BK - Fort Belknap Cenezoic Volcanic Fields BR - Fort Berthold BF - Blackfeet

A A' X-section FP - Fort Peck Reservations

Figure FB-2.1. Present day structural features of the northern Rocky Mountain region. Includes major fault zones, uplifts, basins, and reservation areas (modified after Peterson, 1987).

REGIONAL GEOLOGY� The Fort Berthold Reservation is situated near the deepest part of theWilliston Basin (see Fig. FB-2.1 A-A' and associated cross-sections). Duringthe Paleozoic and early part of the Mesozoic, the basin was a stable, cratonicdepocenter which received over 15,000' of sediments. Fort Bertholdreservation is located within the depocenter, near a major structural featurecalled the Nesson Anticline, which produces a significant percentage ofhydrocarbons within the basin. � Predominantly a carbonate depocenter in the Paleozoic, the basin is alsointerbedded with clastics and evaporites. The clastic intervals are composed of marine, organic rich shales which are the principal source rocks for thebasin. In addition, some of the clastic intervals also include nearshore marineor fluvial sandstone deposits. The carbonate and evaporite units are mainlytidal flat, bioherm/reef or sabhka deposits. Cyclic sedimentation of marineshales, limestones/dolomite, and anhydrites or salt are indicative of the Paleozoic section within the Williston Basin. � Potential reservoir intervals can be formed in the limestone or dolomite viaprimary or secondary porosity mechanisms. Porosity may be intergranular,vuggy, intercrystalline or fractured or combinations of all types depending on structural position and depositional environment.

Geologic History - Cambrian and older rocks � Precambrian age supracrustal sedimentary rocks are present in western Montana and extend into Glacier National Park (see Fig. FB-2.1). These rocks are estimated to be from 900 to 1400 million years old. No Precambrian rocks are exposed on the Fort Berthold Reservation. � During Cambrian time, a major seaway existed in western Montana and eastern Idaho (see Figs. FB-2.2 & 2.4). This seaway gradually transgressed from west to east across eastern Montana and the Dakotas. The dominant source of coarse-grained clastics was to the east (from the Sioux Arch) and gradually changed into shales and limestones to the west. Thickness of the Cambrian rocks varies from over 2000 feet in the Montana Disturbed Belt to less than 100 feet along the eastern edge of the Williston Basin. Cambrian sediments buried under the Fort Berthold Reservation are about 300-600 feet thick and composed predominantly of coarse-grained sandstone.

Geologic History - Ordovician to Triassic � A major depocenter evolved along the eastern edge of the Williston Basin which was a stable, marine shelf area throughout much of the Paleozoic (see Fig. FB-2.3). Ordovician and Silurian rocks were deposited mostly in a shallow tidal flat environment which resulted in alternating cycles of limestone/dolomite, marine shales, and evaporites. By the end of Silurian time, a regional lowstand resulted in a basin-wide unconformity separating Silurian and Devonian rocks. This unconformity influenced the development of vuggy, karsted, carbonate sediments adjacent to this horizon. Present-day thickness of Ordovician and Silurian rocks in the reservation area are 1200 feet and 1000 feet , respectively. � Deposition during Devonian time proceeded much as it had in the Silurian except for the development of highly organic-rich shales within the carbonate intervals. Within the reservation boundaries, Devonian sediments are about 1700 feet thick and include the regional Prairie Salt (500-700'), and the Bakken Shale (70-100'). The Prairie Salt forms a regional seal for the older intervals and has been mobilized/dissolved out of this section near the western edge of the basin (105 degrees longitude). The Bakken Shale is thought to be one of the primary source intervals for Mississippian and younger production.

West EastLongitude Values (in degrees) Fort Berthold Reservation A'A

114 113 112 111 110 109 108 107 106 105 104 103 102 101 1000

Cambrian Rocks PreCambrian RocksCambrian Rocks Sands and Shales

1000 Sands and ShalesSweetgrass Arch

2000 Bearpaw Uplift

Thic

knes

s of

Sed

imen

t (fe

et) PreCambrian Rocks

Poplar Dome Williston Basin3000

Rocky Mountain Trench Little Rocky Mountains

4000Overthrust Belt

5000

6000

7000

8000

Figure FB-2.2. Generalized time-slice cross-section along A-A'. Line of section along 48degrees latitude with selected points every 1 degree longitude. Datum is base Ordovician.

WEST EAST Fort Berthold Longitude Values (in Degrees) Reservation

A A'114 113 112 111 110 109 108 107 106 105 104 103 102 101 100

0 Triassic Rocks

Pennsylvanian RocksBakken Shale Permian Rocks

1000 Williston Basin Devonian Rocks

2000 Mississippian Rocks

Thi

ckne

ss o

f Sed

imen

t (in

ft)

Bearpaw Uplift PreCambrian Rocks 3000 Cambrian Rocks Bakken Shale

Sweetgrass Arch Sands and Shales

Rocky Mountain Trench 4000 Ordovician Rocks

Overthrust Belt Little Rocky Mountains Prairie Salt

5000 Poplar Dome

Silurian Rocks

6000 Cambrian Rocks

Sands and Shales 7000

Ordovician Rocks 8000

Figure FB-2.3. Generalized time-slice cross-section A-A'. Triassic through Ordovician. Line of section along 48 degrees latitude with selected points every 1 degree of longitude. Datum is the base of Jurassic, Permian missing (from C.W. O'Melveny, July 1996).

110 100 105 0 100 40

A 20 0

100 60 A' 0

80 Antelope 120

120 Fort Berthold Taylor

100 Reservation

North Dakota 120 80

150 60 40

Montana 20 100

60 40 100

80Cambrian and older rocks exposed

Wyoming South Dakotasandstone facies

40 0 20shale, sandstone and 0 minor limestone facies

green shale facies

40 contour interval, in multiples of 10 feet

Figure FB-2.4. Map showing thickness of Cambrian-aged Deadwood and equivalent rocks along with facies information, location of analog fields from Cambrian sediments, location of reservation, and location of regional cross-section A-A' (modified after Peterson, 1987).

Fort Berthold Reservation North Dakota

GEOLOGY OVERVIEW Geologic History

Page 3 of 18

Cretaceous Epeiric Seaway

Greenland Alaska

Canada


United States

0 Cretaceous Epeiric Seaway

Mexico Cuba

Figure FB-3.3. Paleogeographic map of North America during Late Cretaceous time, showing the extent of the Cretaceous seaway (after Rice and Shurr, 1980).

GEOLOGIC HISTORY (continued)

Geologic History - Ordovician to Triassic By Mississppian time, the western portion of the Williston Basin was continuously receiving carbonates and evaporites in a shallow, marine shelf environment (see Figure BF-3.1). Most of the producing reservoirs in the basin are from these cyclic marine shales, limestone/dolomite porosity horizons, and evaporitic carbonate sequences. Eventually, the Charles Salt horizon would cover the entire basin and part of eastern and central Montana. By late Mississippian time, deposition of shales and mudstones were mainly confined to the central Williston area and the Big Snowy trough in central Montana. Total thickness of Mississippian rocks within the reservation boundaries is about 2400-2800 feet. � Another major lowstand at the end of the Mississippian time led to widespread erosion and karstification of the underlying carbonate intervals. Pennsylvanian sediments are confined to the center of the Williston basin and central Montana. Pennsylvanian rocks are about 400 feet thick. � Permian deposits are confined to the central Williston basin area and are predominantly sandstone/shale and evaporite sequences. As the Williston basin became filled to base-level, only shallow marine/terrestrial sediments were deposited. This also resulted in numerous unconformities in this horizon. A major unconformity at the end of Permian time has

removed any evidence of these rocks west of longitude 104 degrees. Permian rocks within the reservation are about 500 feet thick. Triassic-aged sediments are also present and of continental origin. Estimated thickness of Triassic rocks across the reservation are about 400-500 feet thick.

Geologic History - Jurassic to Cretaceous A tectonic structural reorganization of the North American continent occurred during Jurassic-Cretaceous time. This resulted in a major change in depocenter position of the Williston basin, shifting from the east to the western side (Figure 4.3). The inital pulses of the Sevier and later Laramide thrusting resulted in dominantly clastic deposition in the Cretaceous Seaway during this time (Figure 4.4). � Thickness of Jurassic rocks across the reservation area are estimated to be about 1200 to 1400 feet thick and are comprised of a complex mixture of nearshore marine, fluvial, and evaporitic deposits. Early Cretaceous-aged continental/fluvial sediments are about 300-400 feet thick. Provenance for these sediments are thought to have been from the southeast in what is present day South Dakota.� The Mowry/Skull Creek Formation is about 400-500 feet thick within thereservation area and was deposited in a transgressive marine sequence which extended from western Montana eastward into the Dakotas; from Texas northward into Canada. Numerous clastic sandstone deposits are present within this sequence and are the result of variations in sea level and clastic influx into the seaway. � During Upper Cretaceous time thrusting and crustal loading from the west had subsided enough to allow the re-establishment of carbonate deposition within the seaway. Extensive chalk deposits of the Greenhorn/Niobrara Formations were deposited as well as thousands of feet of marine carbonate/clastic shale. Upper Cretaceous rocks in the area are more than 2500 feet thick. As the Laramide Orogeny and associated thrusting began to exert influence, nearshore marine and fluvial sandstones began depositing along the shorelines of the seaway.

Geologic History - Tertiary and Quaternary As the orogenic uplifts of the Laramide Orogeny occurred during Late Cretaceous to Tertiary time, older Cretaceous rocks were uplifted and eroded. Only the central portion of the Williston preserved the swamp/peat deposits during the Paleocene and Eocene. Coal deposits of the Fort Union and equivalent rocks are the result. These sediments can be up to 1750 feet thick across the reservation. Alpine glaciers existed in Montana during Quaternary time and extensive glacial lakes and ice sheets covered the reservation area.

Fort Berthold WEST Longitude Values (in Degrees) EAST Reservation A A'

114 113 112 111 110 109 108 107 106 105 104 103 102 101 100 0

1000 Volcanics

Upper Cretaceous 2000

(Niobrara and Eagle Formations)

Thi

ckne

ss o

f Sed

imen

t (in

ft) 3000

4000 Jurassic Rocks

Lower Cretaceous 5000 (Mowry)

Poplar DomeMississippian and Older

6000 RocksLower Cretaceous (Kootenai) Bearpaw Uplift

7000 Sweetgrass Arch Williston Basin

Rocky Mountain Trench8000

Overthrust Belt

Figure FB-3.2. Generalized cross-section A-A' - Cretaceous and Older Rocks. Line of cross-section along 48 degrees latitude with selected points every 1 degree of longitude. Datum located at the top of the Cretaceous.

110 100 105

200

A 600 A'

400 600 Ft. Berthold

0 600 Reservation 600 Dickinson Field 0 1000 400

800 600 400 North Dakota

200

0

Montana

Wyoming

Cambrian and older ricks exposed

South Dakota sandstone and sandy shale facies

green, gray, and red shale with minor limestone

200 200 foot contour interval

Figure FB-3.4 Isopach map showing thickness and facies distribution of late Mississippian and Pennsylvanian sediments of the Tyler and Big Snowy Group suite of rocks. Location of Fort Berthold Reservation, any analog fields, and older basement rocks also shown (modified after Peterson, 1987).

Fort Berthold Reservation North Dakota GEOLOGY OVERVIEW

Geologic History

Page 4 of 18

A

Saskatchewan Manitoba

Poplar Dome

B

Cedar Creek Anticline Petroleum Province North Dakota

South Dakota

Montana

0 Wyoming

Nesson Anticline Petroleum Province

Madison Group Subcrop Petroleum Province

Region of Prairie Formation salt preservation

3000

5000

70

00

200km

Depth of base Madison (ft)

Figure FB-4.1 - Location of the Williston Basin with major petroleum provinces and line of section for burial history diagrams indicated. Structural contours are drawn on the base of the Madison Group (after J. Burrus, K. Osadetz, S. Wolf, et al, 1995).

Petroleum Systems

� Accumulations of hydrocarbons owe their genesis to several critical factors: generation and migration from source intervals, structural/stratigraphic trapping mechanisms, porous reservior rocks, and the appropriate timing of formation/generation of these factors. At least four petroleum systems are present within the Williston Basin with numerous underexplored potential hydrocarbon exploration targets. This discussion focuses on the source intervals.

Source rocks: Generation and Expulsion At least four source intervals have contributed to the hydrocarbon generation and

accumulation patterns within the Williston Basin and all are present in the reservation area.

� Ordovician Winnipeg shale - A very organic rich shale which exceeds richness values of the Bakken shale in some cases. This interval first entered the oil window in latest Cretaceous/Paleocene time. Peak generation and expulsion occurred between 55-38 mya and some generation continues today. Oils typed to this source are found in the Cedar Creek anticline, eastern Montana, and western North Dakota. However, structures which formed in latest Eocene or after (such as the Nesson Anticline) could not trap the oil migrating from this source. This suggests that much of Winnipeg- sourced oil migrated to the northeastern flank of the Williston Basin where undiscovered oil resource may be present in Ordovician and Silurian strata. This source interval is aerally restricted to the southern and central portions of the basin.

� Bakken Shale - Known as a world-class source interval, the Bakken has an average of 11.33 wt. % organic carbon. Oil generation was probably initiated about 75 mya with initial expulsion occurring about 70mya (late Cretaceous). Calculations based on pyrolysis data suggest that between 92.3 - 110 billion barrels of oil have been generated from the Bakken. Except for a few fields utilizing the Bakken as the reservoir, significant volumes of Bakken sourced oil have not been discovered to date. Some researchers suggest that most of the expelled Bakken oil is probably lost into the drainage system, where it remains dispersed, at very low saturations (see Figures 2.2 and 2.3 below). Most of the larger structures in the Williston Basin contain mixtures of Lodgepole (Madison) and Bakken oils with the latter at low relative concentrations.

� Lodgepole source interval - This zone contains predominantly carbonate source horizons with relatively low initial yields; 8 kg HC/t rock. However, large volumes of oil have been discovered typed to this source interval, especially within the Nesson Anticline Petroleum Province. This horizon seems to be geographically restricted to the central and southern portions of the Williston Basin. It appears that migration and trapping efficiencies were much higher in this horizon when compared to the Bakken. This may be due to advantageous timing of structure development relative to expulsion/migration.

� Winnipegosis source interval - The rich, basinal carbonate horizons within this unit (47 kg HC/t rock) are restricted to a starved, Devonian which begins along the northern end of the Nesson anticline and continues north into Canada. This interval charges many of the Waulsortian mounds found in some of the Mississippian-aged sequences.

A Distance (km) B50 100 150 200 250 300

0

1

2

Potential in Ordovician source &

Bakken

0Ma

Northern limit of Ordovician source

Bakken thickness exaggerated x 2.5

Madison

Duperow

Interlake Winnipeg source

Bighorn interval

TR=.10

TR=.20

TR=.65

TR=.90

HC saturation

< 2%

2 - 5%

5 - 10%

10 - 80%

> 80%

Prairie salt horizon

Dep

th (

km)

3

4

Figure FB-4.2 - Burial history model with patterns of transformation ratio (TR) at the present and distribution of oil saturations, calculated using a finite model, two-dimensional computer model that simulates oil generation, expulsion, and migration. Generation kinetics determined by experimental data from Williston Basin source rocks. Thermal history model constrained by both present temperature and source rock maturity data. Saturations compared to known patterns of hydrocarbon accumulation within the basin. Saturations between 2-5% represent dispersed oil; saturations above 10% represent oil accumulation or depleted source rocks. Arrows show patterns of active oil migration (after J. Burrus, K. Osadetz, S. Wolf, et al., 1995)

A Distance (km) B 50 100 150 200 250 300

Potential in Winnipegosis &

Lodgepole

0Ma

TR=.10

TR=.20

TR=.90

0

1

Dep

th (

km)

2

3

4

Lodgepole

Winnepegosis thickness exaggerated x 2.5 between 0-250km

HC saturation

TR=.65

< 2%

2 - 5%

5 - 10%

10 - 80%

> 80%

Prairie salt horizon

Figure FB-4.3- Burial history model with patterns of transformation ratio (TR) at the present and distribution of oil saturations, calculated using a finite model, two-dimensional computer model that simulates oil generation, expulsion, and migration. Generation kinetics determined by experimental data from Williston Basin source rocks. Thermal history model constrained by both present temperature and source rock maturity data. Saturations compared to known patterns of hydrocarbon accumulation within the basin. Saturations between 2-5% represent dispersed oil; saturations above 10% represent oil accumulation or depleted source rocks.Arrows show patterns of active oil migration (after J. Burrus, K. Osadetz, S. Wolf, et al., 1995).

Fort Berthold Reservation North Dakota Petroleum Systems

Page 5 of 18

Schematic Diagram of Play Types - Fort Berthold Reservation WEST EAST

Upper Cretaceous

Play Types - Explanation

1. Madison Structure Play Niobrara

10 10 2. Madison Shoreline/Truncation Play

Jurassic 3. Mississippian Lodgepole Waulsortian Mound Play

Triassic 4. Ordovician Red River Play

Permian 5. Devonian Nisku/Duperow Play

Pennsylvanian 7 6. Silurian Interlake Play1

2 2 7 7. Pennsylvanian Tyler-Heath Play

9 8. Pre-Red River GasMississippian 3 Winnipeg/Deadwood Clastics 35 Bakken Shale MississippianDevonian 9. Fractured Bakken Play6 9

Red River 4 10. Shallow Microbial Gas PlayInterlake8 Winnipeg

Deadwood

No scale implied - drawing is approximate width of Reservation Dolomite Precambrian Fluvial/Clastic dominated shorelines

Limestone Sandstone Clastic/calcareous shale

Organic-rich Limestone shorelines shale or Waulsortian Mounds

Oil Gas

Figure FB-5.1. Schematic diagrams of play types at Blackfeet Reservation

Play Summary

The diagram and summary charts are coded to the play type number and provide a quick reference to the discovered and undiscovered resource for the reservation area. Also listed are USGS (1996) risk estimates and designations for each of the play types. A qualitative brief review of the summary aspects of each play are also shown.

Reservation: Geologic Province: Province Area: Reservation Area:

Fort Berthold Central Wiliston Basin Williston Basin (143,000 sq. miles) 1530 sq. miles (980,000 acres)

Total Production ( by province-1996) Oil: Gas: NGL:

Williston Basin 1496 MMBO 1735 BCFG 192 MBNGL

Undiscovered resources and numbers of fields arefor Province-wide plays. No attempt has been madeto estimate number of undiscovered fields within theFort Berthold Reservation

Play Type USGSDesignation

Description of Play Oil or Gas Known Accumulations Undiscovered Resource (MMBOE) Play Probability (chance of success) Drilling depths Favorable factors Unfavorable factors

Madison, structure

1

3101a folded structures, primary and secondary porosity in carbonates

Both 878 MMBO 916.5 BCFG 77.9 MMBNGL (numbers include 1, 2,& 3)

Median: 600 MMBO(30 fields @ 20MMBO)

Field Size (> 1 MMBOE) 2 MMBO (min), 20 MMBO (median), 5.3 MMBO(mean)

No. of undiscovered fields (> 1 MMBOE) 9 (min) 30 (median) 60 (max) 31.9 (mean) numbers include plays 1, 2, & 3

1 high

3,000 - 12,000 ft 1) confirmed play; excellent production within reservation

2) thermally mature source rocks 3) source rocks and reservoir present 4) seismic delineation is useful

1) lack of well control 2) rough topography 3) porosity and facies may be

highly variable

Madison shoreline/ truncation play

2

3101b Cyclic evaporite/ carbonate sequence, structure/stratigraphic updip pinchout, multiple shoreline cycles


Median of 600 MMBO (30 fields @ 20MMBO)

Field Size ( >1 MMBOE) 2 MMBO(min) 20 MMBO(median) 5.3 MMBO(mean)

No of undiscovered fields (> 1 MMBOE) 9 (min) 30 (median) 60 (max) 31.9 (mean) numbers include plays 1, 2, & 3

1 high

3,000 - 12,000 ft 1) confirmed play; excellent production within reservation

2) thermally mature source rocks 3) source rocks and reservoir present 4) trend extends into reservation 5) mostly shallow drilling depths

1) lack of well control 2) rough topography 3) porosity and facies may be

highly variable 4) seismic may not be able to

delineate shoreline trends

Miss. Lodgepole/ aulsortian Mound play W

3

3101c Mound buildups; 'reefs', small but prolific structures; excellent porosity and permeability


Median of 600 MMBO (30 fields @ 20MMBO)

Field Size ( >1 MMBOE) 2 MMBO(min) 20 MMBO(median) 5.3 MMBO(mean)

No of undiscovered fields (> 1 MMBOE) 9 (min) 30 (median) 60 (max) 31.9 (mean) numbers include plays 1, 2, & 3

1 high

3,000 - 12,000 ft 1) confirmed play; trend probably extends to reservation

2) thermally mature source rocks 3) source rocks and reservoir present 4) seismic may be very useful

1) lack of well control 2) rough topography 3) small areal extent, may

be difficult to explore for

Ordovician Red River Play

4

3102 Cyclic evaporite/ carbonate sequence, structure/stratigraphic updip pinchouts; multiple shoreline cycles

Both 188.3 MMBO 555.7 BCFG 70.5 MMBNGL

Median of 250 MMBO (25 fields @ 10 MMBO)

Field Size ( >1 MMBOE) 2 MMBO/10 BCFG(min) 10 MMBO/35 BCFG(median) 2.1 MMBO/11.7 BCFG(mean)

No of undiscovered fields (> 1 MMBOE) 5 (min) 25 (median) 50 (max) 26 (mean)

1 high

7,000 - 12,000 ft 1) confirmed play; production within reservation

2) thermally mature source rocks 3) source rocks and reservoir present 4) seismic useful in locating

structures

1) lack of well control 2) rough topography 3) possible small exploration

targets

able FB-5.1. Play summary chart T

Fort Berthold Reservation North Dakota Play Types

Page 6 of 18

Reservation: Fort Berthold Total Production ( by province-1996) Williston Basin Undiscovered resources and numbers of fields are Geologic Province: Central Williston Basin Oil: 1496 MMBO for Province-wide plays. No attempt has been made Province Area: Williston Basin (143,000 sq. miles) Gas: 1735 BCFG to estimate number of undiscovered fields within the Reservation Area: 1530 sq. miles (980,000 acres) NGL: 192 MBNGL Fort Berthold Reservation

USGS Undiscovered Resource (MMBOE) Play Probability Play Type Description of Play Oil or Gas Known Accumulations Drilling depths Favorable factors Unfavorable factors Designation Field Size (> 1 MMBOE) min, median, mean (chance of success)

Median 250 MMBO (25 fields @ 10 MMBO) Nisku and Duperow 3103 Cyclic evaporite/carbonate Both 160.5 MMBO 1 8,000 - 12,500 ft 1) confirmed play; 1) lack of well control sequences. Structural and 159.2 BCFG Field Size (> 1MMBOE) high production within reservation 2) rough topography

2 MMBO/10 BCFG 10 MMBO/60 BCFG 2.1 MMBO/13.1 BCFG stratigraphic pinchouts. Excellent 12.7 MMBNGL 2) thermally mature source rocks porosity and permeability No.of undiscovered fields (> 1 MMBOE) 3) source rocks and reservoir present 5 9 (min) 25 (median) 60 (max) 26.9 (mean) 4) seismic delineation is useful

Silurian Winnipegosis Median 225 MMBO (15 fields @ 15 MMBO)3105 Cyclic evaporite/ carbonate Both 55.5 MMBO 1 8,000 - 12,500 ft 1) confirmed play; 1) lack of well control and Interlake Field Size (> 1MMBOE)sequence, erosional surfaces. 180 MMCFG mod.- high production within reservation 2) rough topography

3 MMBO/15 MCFG(min) 15 MMBO/90 MMCFG(median)Primary and secondary porosity. 24.8 MMBNGL 2) thermally mature source rocks 3.3 MMBO/19.7 MMCF(mean) Structural and unconformity related 3) source rocks and reservoir present 6 trapping mechanisms No. of undiscovered fields (> 1 MMBOE) 4) seismic useful in prospect 5 (min) 15 (median) 25 (max) 15 (mean) delineation

Post Madison 3106 Fluvial and nearshore sandstones Both 133.5 MMBO Median 16 MMBO (8 fields @ 2 MMBO) 1 5,500 - 9,000 ft 1) Thermally mature source rocks 1) No production within Penn. Tyler/Heath with structural closures. Traps may 28.8 BCFG mod.-high 2) source rocks and reservoir present reservation

Field Size (> 1MMBOE) also occur as discontinuous sandstone 3) shallow drilling depths 2) rough topography 2 MMBO 10 MMBO 2.1 MMBO lenses. 3) lack of well control 7 4) depositional area within No of undiscovered fields (> 1 MMBOE)

reservation may be marine 4 (min) 8 (median) 15 (max) 8.6 (mean) instead of shoreline

Ordovician Pre-Red River 3107 Clastic sequences, fluvial and NGL and low no information Median 50 BCFG (5 fields @ 10 BCFG) 1 10,000 - 16,000 ft 1) confirmed play; 1) lack of well control Play nearshore blanket sandstones. BTU gas available moderate production within reservation 2) rough topography

Field Size (> 1MMBOE) Large, faulted structures 2) thermally mature source rocks 3) low BTU, contains 10 BCFG 25 BCFG 13.1 BCFG

3) source rocks and reservoir present nitrogen 8 4) seismic useful in locating No. of undiscovered fields (> 1 MMBOE) 1 (min) 5 (median) 20 (max) 7.3 (mean) structures

5) high volume reserves

Fractured Bakken 3111 Organic rich shale, marine siltstone; Both No information available not estimated 1 7,500 - 11,100 ft 1) confirmed play; 1) lack of well control fractured; thermally mature oil shale Oil shows from Sanish sandstones 70.3 MMBO/ sq. mile generated hydrocarbons 0.2 (20%) production within reservation 2) rough topography

56.24 MMCFG/ sq. mile generated hydrocarbons 2) thermally mature source rocks 3) Probable narrow bands of Area of play = 8185 sq. miles 3) source rocks and reservoir present potential fractured reservoir 9 7806 sq. miles untested 4) seismic delineation is useful zones

Niobrara Microbial 3113 Niobrara limestone and other Microbial gas Only production to date is from not estimated 1 500 - 4500 ft 1) large volume play 1) lack of well control Gas Play shallow reservoirs, self-sourced; Cedar Creek Anticline and 180 MMCFG/160 acres (median) 0.5 (50%) 2) shallow drilling depths 2) rough topography

porosity decreasing with increasing Bowdoin dome. These fields are 256 MMCFG/160 acres (mean) 3) accumulations in structural 3) reservoir continuity isdepth. Large volume accumulations from shallow Eagle Formation Area of play = 55,000 sq. miles traps, seismic may be useful problematic 10 possible sandstones, not Niobrara. 29,958 sq. miles untested (mean) in delineation of traps 4) areal extent may be small

Table BR-6.1. Play type summaries. Conventional play type

Unconventional/Hypothetical play type

Fort Berthold Reservation North Dakota Summary of Plays (continued)

Page 7 of 18

A A.P.C. A.P.C. A' #3 M Aura #1 Aura

Se Sw Sec. 19 Se Se Sec. 19 KB 2346' KB 2388'

GR

A.P.C. A.P.C. #2 Selliseth Texaco

#20 Sivertson Se Sw Sec. 20 #4 Gov't-Dorough

Se Se Sec. 20 KB 2495' Se Sw Sec. 21

KB 2493' KB 2690'

Last Charles Salt

Mississippian

Madison

Gamma Ray MarkerFormation

Top Blue Buttes Pay

90

00

91

00

91

00

93

00

91

00

92

00

92

00

94

00

92

00

93

00

93

00

95

00

93

00

94

00

94

00

96

00

94

00

95

00

97

00

-6500

-6600

-6700

-6800

-6900

-7000

90

00

91

00

92

00

93

00

LL GR

LL

Blue Buttes Field Structural Cross-Section

Figure FB-7.1. Blue Buttes Field structural cross-section (after Connelly, North Dakota Geological Society, 1962).

Blue Buttes Field Parameters

Formation: � Mississippian Madison

Lithology: Interbedded limestones and dolomites.

Average depth: 9200 feet (in reservation area)

Porosity: � averages 7.7%

Permeability: � 0.1-8 md, average is 3 md.

Oil/gas column: � oil 280 feet

Average net pay: � variable

Other Formations with shows: Kibbey sandstone, Kibbey limestone and Charles Formation

161

7 12

1318

19 24

2530

3136 36

161

7 12

1318

1924 24

R 96 W R 95 W

T 151 N

T 150 N

Blue Buttes Field

Top Lower Charles Salt Structure Map

CI = 20 feet

Note: Only Madison penetrations are shown

R 95 WR 96 W

A A'

-670

0

-670

0

-680

0

-660

0

-660

0

Figure FB-7.2. Structure contour map of Blue Buttes Field showing location of cross-section A-A'. Structure on top of Lower Charles Salt.

PLAY TYPE 1

Folded Structure - Mississippian Carbonate Play

General Characteristics - The Mississippian Madison play is primarily a structural play combined with superimposed facies/porosity changes and pinch-outs. This play is the dominant hydrocarbon producer in the Williston basin. The Madison is subdivided into several producing horizons (see cross-sections below), based on porosity zones. These zones are overlain by evaporite or shale seals. The Charles Salt horizon is a regional evaporite seal which overlies most of the Madison Formation. � Reservoir rocks are generally dolomitized carbonate rocks with either algal, oolitic, crinoidal, or micritic components. Source rocks are thought to be either of Bakken origin or cyclic marine shales within the evaporite-carbonate cycle. Onset of oil generation and migration is modeled to begin in the Late Cretaceous.

Analog Fields (*) denotes fields within Reservation

Antelope* - � 39 MMBO� 18.9 Mmcf(includes Bakken, Duperow, and Interlake)

Blue Buttes -� 45 MMBO� 28.3 Mmcf (includes Duperow, Interlake, and Red River)

Bear Den -� 1.4 MMBO� 1.5 Mmcf (Madison, Duperow)

Croff -� 1.7 MMBO� 4.0 Mmcf (Madison, Duperow)

Antelope Field Parameters

Formation:� Mississippian Madison

Lithology:� Limestone, brown, dolomitic, fossil fragments, occasional chalky horizons.

Average depth: � 9100 feet

(in reservation area).�

Porosity: � 4.7% gross, intergranular, vuggy

Permeability: � info. not available

Oil/gas column: � highly variable


Other shows: � Sanish, Duperow, Interlake.

Other information: contains 4.7% H2S

Kibbey Kibbey

Charles Charles

Madison Madison Lodgepole

Bakken

Three Forks - Nisku

Duperow

Souris River

Dawson Bay-Prairie Evaporite

Winnipegosis- Elm Point - Ashern

Silurian

Stony Mountain

Red River

Winnipeg

Cambrian ?

PreCambrian

-5603 -5589 -5557 -5494 -5619 -5876

-6161

-6809

-8555

-5908

-6536

-8226

-5794

-6409

-8081

-8367

-8770 -8997

-9273

-9631

-10779 -10993

-11632

-12274

-13012

-5838

-6466

-5882

-6492

-5889

-5000

-6575

TD -6866 TD -6908

TD -7212

unconformity horizons

A.P.C. #1 Swenson Heirs A.P.C. #1 AB Fleming Estate A.P.C. #1 T Larson Tract 1 A.P.C. #1 Antelope Unit 'A' A.P.C. Gulf #1 J Strand A.P.C. Carter #1 Reed-Norby UnitC Se Ne 11-152N-95W C Nw Nw 12-152N-95W C Se Sw 1-152N-95W Ne Se 1-152N-95W S/2 Nw/4 6-152N-94W Lot 2 6-152N-94W

2242 KB 2210 KB 2136 KB 2117 KB 2129 KB 2198 KB

-5000'

TD -8255

TD -8570

R 94 W

Fort Berthold Reservation

T 152 N

B'

A

Structural Cross Section

Antelope Field McKenzie Co., North Dakota

Index Map

B B'

Figure FB-7.3. Antelope field cross-section (after North Dakota Geological Society, 1962).


CONVENTIONAL PLAY TYPE 1 Folded Structure - Mississippian Carbonate Play

Page 8 of 18

Analog Fields (*) denotes fields which lie within reservation

Plaza* - 2.6 MMBO, 1.7 Mmcf out of 20 wells, 3-4 MMBO ultimate (Bluell)

Wabek* - 5.1 MMBO, 3.6 Mmcf, out of 18 wells, 6-7 MMBO ultimate (Sherwood)

Carnduff

Elmore

MouseRiverPark

Lake

Darling

LoneTree

Wabek

Plaza

Lucky Mound

Centennial

Renville

Ward

McLean

0

Canada

StudyArea

North Dakota

U.S.A. North Dakota

Burke Bottineou

McHenry

Mountrail

Sherwood Shoreline

Index Map 12 24

miles

Figure FB-8.1. Sherwood shoreline trend and position of major oil fields ( after Sperr et al, 1993).

PLAY TYPE 2

Mississippian Shoreline Play

General characteristics - This play is an extension of the northeast shelf playwhich produces from Sherwood and Bluell porosity cycles. In an eastward direction the Mississippian interval subcrops the following formations: Midale, Nesson, Bluell, Sherwood, Mohall, Glenburn, Landa, Wayne, and Lodgepole. Reservoirs are dolomitized carbonates of either algal, oolitic, or bioherm banksalong the shoreline trend. The updip seal can either be an evaporite or a shale. Source rocks are likely contained within the Bakken or other marine shales within the evaporite sequence.R 88 W R 87 W

Figure FB-8.2. Structure map of the Sherwood subinterval - Plaza and Wabek fields (after Sperr et al, 1993).

T 153

Wabek N Field

(Sherwood Prod.) A'

-5200

A

Plaza Field

(Bluell Production)

T 152 N

B B' -5300

-5500

-5400

Plaza Field Parameters

Formation: Mississippian Mission Canyon, Bluell subinterval

Lithology: Light brown-brown, peloidal, ooliticpisolitic, intraclastic andcomposite wackestone-grainstone

Average depth: � 7400-7500 feet

Porosity: � intergranular, vugular, intraparticle; 6-16%

Permeability:� no information

Oil/Gas column:� at least 120 feet, no oil/water contact known

Average net pay: 6 feet

Wabek Field Parameters

Formation: Mississippian Mission Canyon Sherwood subinterval

Lithology: � Light brown-brown, peloidal, oolitic, pisolitic intraclastic and composite wackestone-grainstone

Average depth: � 7300-7500 feet

Porosity: � intergranular, vugular, intraparticle 6-26%, ave.=10%

Permeability: � no information

Oil/Gas column: � at least 100 feet

Average net pay: � 26 feet

7200

7200

Rival

7200

7300

7300

7300L. Bluell

Sherwood

Mohall 7400

Glenburn

7500

7500 D & AIPF 308 BO, 134 MCFG & DST: Rec. 45' SO&GCM,

0 BWPD 270' GCWPerfs: 7324-7366

DEN POR DEN PORDEN POR

8 ø 8 ø

8 ø

NEU POR NEU POR NEU POR

A Se Se 3 Se Nw 2 Sw Sw 32 A'

SW 152N-88W 152N-88W 152N-87W NE

GR CNL/FDC GR CNL/FDC GR CNL/FDC

IPF 259 BO, 129 MCFG & Intershoal Mudstone0 BWPD

Perfs: 7354-7390

Wabek Field Cross-section

Figure FB-8.3. Wabek Field cross-section showing position of productive interval. Datum is top of Sherwood horizon (after Sperr et al, 1993)).

B Ne Ne 20 Ne Ne 21 Ne Ne 22 B'

West 152N-88W 152N-88W 152N-88W East

GR CNL/FDC GR CNL/FDC GR CNL/FDC

IPP 29 BO, 45 MCFG &65 BWPD

Perfs: 7482-7484, 7490-7496 Plaza Field Cross-section

Figure FB-8.4. Plaza field cross-section showing position of productive interval. Datum is top of Sherwood horizon (after Sperr et al, 1993).

Rival

L. Bluell

Sherwood

Mohall

Glenburn IPP 34 BO, 15 MCFG & IP: Non-commercial 57 BWPD Perfs: 7388-7402, 7408-7412

Perfs: 7415-7424,7436-7438 7416-7422

DEN ø DEN ø DEN ø

8 ø 8 ø

8 ø

NEU ø NEU ø NEU ø

7300

7400 7300

7400 7500

7600 7500

7600

7700

Fort Berthold Reservation North Dakota CONVENTIONAL PLAY TYPE 2

Mississippian Shoreline Play

Page 9 of 18

WILLISTON BASIN Lodgepole Buildups

West East

Trough shelfbasin shelf

sea level

Montana

slope

Explanation

Grainstone-packstone beds on flanks of mound

Bryozoan-crinoid buildup facies (potential hydrocarbon reservoir)

Mudstone-wackestone core facies of mound

Wackestone-packstone buildup facies

Figure FB-9.1. Diagrammatic cross-section of Waulsortian Mounds within the Williston Basin, shows facies distribution and general location within the basin (after Burke and Lasemi, 1995).

CANADA

S S

S ?

?

100

300 500 ?

? Montana 900

LB Trough 700 500

BS 500

B ?

300 500

Approximate erosional limit of Madison Formation

Postulated Waulsortian mounds

Known Waulsortian mounds

Fort Berthold

Figure FB-9.2. Generalized isopach map (c.i.=200') of the Lodgepole Formation, Williston Basin in relation to the Fort Berthold Reservation. LB=Little Belt Mountains, B=Bridger Range, BS=Big Snowy Mountains, D=Dickinson Lodgepole Field, S=Saskatchewan (modified from Burke and Lasemi, 1995).

PLAY TYPE 3

Mississippian Lodgepole Waulsortian Mounds

General Characteristics - No production has been established within the reservation, however, there is a productive trend in neighboring Stark County. Similar mounds have been found in outcrop in the big Snowy Mountains, Montana. � Waulsortian facies within the Lodgepole formation are lens-like buildups of massive limestone with abundant crinoid and bryozoan fragments. Potential reservoir intervals are boundstones whose framework constituents consist of crinoids, bryozoans, and lesser amounts of mollusks and corals. Inter and intra-particle porosity is the result of leaching and alteration of these particles.

260

240

234

237

262

303

255

368

Dickinson Field, Lodgepole Formation Williston Basin

R 97 W R 96 W

T 140 N

378

T 139 N

20' Contour Interval

Figure FB-9.3. Isopach map of lower Lodgepole at Dickinson Field (after Burke and Lasemi,1995).

Dickinson Field Lodgepole Parameters

Formation:� Mississippian Lodgepole

Lithology: primarily fossiliferous grainstones with minor amounts of dolomite boundstones, packstones

Average depth: � 9800 feet

Porosity: � 9.4-10% mound core up to 15% in mound flanks

Permeability: � variable, up to 460md

Oil/Gas column: � no information

Average net pay: � at least 50 feet

Other shows: � no information

CONOCO, INC. Figure FB-9.4. Generalized Lodgepolesection depicting Waulsortian MoundKadramas 75 Buildup (after Burke and Lasemi, 1995).NW SE 31-140-96

Stark Co., N.D.

9200

9300

9400

9500

9600

9700

9800

9900

10000

10100

Mission oolitic, pelletal, light yellow-brown, Canyon dolomitic, skeletal packstone to wackestone

Lodgepole

Supra Mound medium to dark gray-brown slightly argillaceous and cherty skeletal wackestones and mudstones

Lower Mound Core Lodgepole light to medium gray-brown mottled with dark brown, bryozoan baffle and

boundstones with grainstone, packstone, and wackestone matrix; abundant coarse calcite cement

Bakken black shale interbedded with argillaceous mudstone and calcareous siltstones

Three Forks light brown gray dolomite interbedded with gray green shale

log marker

GR DLL

oil/water

contact (-7365)


CONVENTIONAL PLAY TYPE 3 Mississippian Lodgepole Waulsortian Mound Play

Page 10 of 18

110 100105

A 300 A'

500 100 Antelope300 Ft. Berthold

Blue Buttes Reservation500

700

100

500 North Dakota Montana 500

300 300

300

Ordovician or 100 South Dakota older rocks exposed

Dolomite facies -Red River Wyoming Limestone and dolomite facies Red River

400 contour interval, 200'

Figure FB-10.1. Map showing thickness of Ordovician Red River Formation within the Williston basin and surrounding area, location of analog fields and reservation, and location of regional cross-section A-A' (modified after Peterson, 1987).

PLAY TYPE 4

Ordovician Red River Play

General Characteristics: This is the second most productive formation in theWilliston basin. Reservoirs are dolomite intervals and dolomitic limestonesformed from bioclastic mounds and tidal flat deposits. Cyclic deposits ofcarbonate, evaporite, and organic rich shale provide reservoir, source, and seal.Major accumulations are found on structural noses such as Nesson and Cedar Creek Anticlines. Smaller fields are found in fold structures draped overbasement fault blocks, or small carbonate mounds.� The source intervals are thermally mature to overmature at the basin center,and become somewhat immature along the basin flanks. Winnipeg shale and marine shales in the Red River Formation are thought to be the primary source of the reservoir oil. Hydrocarbon generation and migration is estimated to have begun in late Paleozoic time.

R 95 W R 94 W

30 29 28 27 26

-11,000 T T 153 -11,145 153

N N

31 32 33 34 35

-11,200 -11,080

-11,100 -11,000

3 2 1 6 5 4

T T -10,993 152 152

N N

7 8 9 10 11 12


R 95 W R 94 W

Note: Wells shown are Red River penetrations only.

Red River production was established at ANTELOPE FIELD Antelope Field in 1989 with the 30-23 Mckeen Red River Structure Map well in section 30, T 153 N, R 94 W

C.I. = 50 feet

Figure FB-10.2. Structure contour map of the Red River Fm., Antelope Field. Contours show the general trend of anticline/fold development.


Formation: Ordovician Red River

Lithology: black to dark gray dolomite, limestone very fine grained to crystalline � occasionally sucrosic texture

Average depth: � -11,300 MSL

Porosity: � 9.8%

Permeability: � 1.0 md

Oil/Gas column: � unknown

Average net pay thickness: � 23 feet

Other shows: � Kibbey Sandstone, Kibbey Limestone Charles Formation

Other information:� Initial IP 564 BOPD, API 58 2928 Mcfgpd-discovery well

R 96 W R 95 W

11,300

1 6 1

11,400

11,400 7 12

11,500

T 18 13 11,500 151

N

19 24 11,600

30 25

36 31 36

11,300 1 6 1

7 12 T

11,400 150 N

11,500 18 13

24 19 24

R 96 W R 95 W

Note: Only Red River penetrations Blue Buttes Field are shown

Red River Structure Map

CI = 25 feet

Figure FB-10.3. Red River Structure Map - Blue Buttes Field. Showstrend of Anticline development and production.


Formation: Ordovician Red River

Lithology: black to dark gray limestone/dolomite very fine grained to crystalline Occasionally sucrosic texture

Average depth: � 13,480-13,490 feet

Porosity: � 12% log density porosity

Permeability: � not known


Average net pay thickness: � 10 feet

Other shows:� Minnelusa and Charles Formations

Cumulative production: (1995)� 94 MBO, 1.15 Mmcf API 56.2, IP 113 BC, 1452 Mcfgpd


CONVENTIONAL PLAY TYPE 4 Ordovician Red River Play

Page 11 of 18

North Dakota

Wyoming

110 100 105

Silurian and older rocks exposed

Limit of Bakken source rocks

A A'

South Dakota

Ft. Berthold Reservation

Montana

contour interval, 200'

Antelope

400

400

200 400

200 200

200

600

600

1000 800

800 1000

2000 1200

1400

1600 1200

1800

600

Bear Den

Limit of Prairie salt

Figure FB-11.1. Map showing thickness of Devonian rocks, limit of Prairie salt, limit of Bakken source rock, location of analog fields and reservation, and location of regional cross-section A-A' (modified after Peterson, 1987).

PLAY TYPE 5

Devonian Nisku-Duperow Play

General Characteristics- This play consists of a carbonate evaporite sequence interbedded with cyclic marine shales. Reservoir rocks are typically dolomite or dolomitized limestone. Source rock for the oil is thought to be from the Bakken interval which is mature-overmature in the central portion of the basin and immature on the flanks. Oil migration and generation are estimated to have begun in early to late Cretaceous time. � Traps are gentle folds and closures related to carbonate bank deposition on paleohighs or shelf areas. These paleostructures are present on regional structural trends such as the Nesson Anticline and Antelope Anticline.

Analog Fields (*) denotes fields which lie within Reservation

Antelope*- � 39 MMBO, 18.9 Mmcf (includes Bakken, Duperow, and Interlake)

Blue Buttes - � 45 MMBO, 28.3 Mmcf (includes Duperow, Interlake, and Red River)

Bear Den - � 1.4 MMBO, 1.5 Mmcf (includes Madison, Duperow)

Croff - � 1.7 MMBO, 4.0 Mmcf (includes Madison, Duperow)

R 96 W R 95 W

Ne Ne Sec. 36, T 149 N, R 96 W GR Laterolog

Birdbear

Duperow

11,300

11,250

T 149 N

-8900

23 24 19

-8950

-9000

26 25 30

-8900

35 36 31

Souris River

dolomite

evaporite Bear Den - Devonian Field shale Mckenzie County

North Dakota

TOP DUPEROW STRUCTURE CI= 50'

Figure FB-11.2. Bear Den - Devonian Field. Shows position of dolomitic intervals relative to the interbedded evaporite seals. Productive interval indicated in black.

Bear Den Field Parameters

Formation: Devonian Duperow

Lithology: microcrystalline dolomite with fair microsucrosic porosity

Average depth: � 11,300 feet

Porosity: � variable, microsucrosic

Permeability: � not known

Oil/Gas column: � variable

Average net pay thickness: 13 feet

Other info: � no H2S


Formation: � Devonian Duperow

Lithology: � dolomite, brown, finely crystalline, granular to vugular limestone intervals, fossiliferous

Average depth:� 10,750 feet

Porosity: � variable, granular, vuggy

Permeability:� not known

Oil/Gas column:� variable

Average net pay thickness:� variable

Other shows:� Madison, Interlake, Sanish

Other information:� No H2S

Figure FB-11.3. Structure map of Antelope Field. Shows general anticlinal fold trend to the southeast. Inset shows position of Bakken relative to Duperow Formation.

R 95 W R 94 W

30 29 28 27 26

T T 153 153

N N

31 32 33 34 35

R 95 W R 94 W

3 2 1 6 5 4

T T 152 152

N N

7 8 9 10 11 12

18 17 16 15 14 13

18 20 21

22 24

30 29 28

ANTELOPE FIELD

Devonian Duperow Structure Map

C.I. = 100 feet


-8200

-8100

-8300

-8400

-8600

Bakken

Devonian Duperow

Limestone

Shale

Dolomite


CONVENTIONAL PLAY TYPE 5 Devonian Nisku - Duperow Play

Page 12 of 18

Ft. Berthold 110 105 Reservation 100

A 1100 Antelope

A'

900

700 0

500 0

North Dakota 300

South Dakota

100 Montana

Wyoming

Silurian and older rocks exposed

Limey dolomite facies

dolomite facies


Figure FB-12.1. Map showing thickness of Silurian Interlake Formation, facies type, location of analog field and reservation, and location of regional cross-section A-A' (modified after Peterson, 1987).

PLAY TYPE 6

Pre-Prairie ( Winnipegosis/Interlake Play)

General Characteristics - Regional carbonate units of lower Devonianand Silurian age are overlain by the Prairie Evaporite which acts as a seal rock. Typical reservoirs in the Winnipegosis are reefs or dolomitized carbonate mounds. Unconformity traps are thought to exist in the Silurian Interlake Formation which can result in dolomitized reefs, minor karsting, and dissolution porosity in tidal deposits. � The Ordovician Red River shales are thought to be the source rocks for this play and are thermally mature within the basin center. Typical traps consist of gentle folds with flexure faulting associated with the regionalstructure. Stratigraphic traps (either pinch-outs or porosity variations) may exist as well.


Formation:� Silurian Interlake

Lithology: dolomite, cream to dark brown possible algal forms, microcrystalline and vugular in part

Average depth: � -9600 feet MSL

Porosity:� variable, granular, vuggy, 7.5%

Permeability:� 1.3md

Oil/Gas column:� variable

Average net pay thickness:� variable

Other shows:� Madison, Duperow, Sanish


Formation:� Silurian Interlake

Lithology:� Dolomite

Average depth:� 12,300 feet (-9967 MSL)

Porosity:� 12%

Permeability:� not known

Oil/Gas column:� not known

Average net pay thickness:� 30 feet Borehole Compensated

Sonic Log Amerada Hess

9-43 Jones ne se 9-150n-95w

Interlake: 12,315-12,356 12,372-12,394 12,404-12,418

1220

012

300

Productiveinterval

1240

012

500

Figure FB-12.2. Example of wireline log through Silurian interval in Blue Buttes Field.

T 30 25

152-9898 N

NDE NDE

NDE 32 36

NDE

NDE

-9951 NDE NDE NDE

5 1 -9917

NDE-9997

NDE NDE

8 12

NDENDE

-10027 T -9967

NDE 17 13 151

-9996 N NDENDE -9935

-10022 -9880

20 24

Blue Buttes Field 25

Interlake Structure Map Fort Berthold

C.I. = 25 feet R 96 W

Figure FB-12.3. Structure contour map of Interlake interval, Blue Buttes Field. Shows anticlinal nose development withproduction located somewhat off structure. This indicates a strong stratigraphic component which assists trapping mechanism.

Laterolog with Gamma Ray

Amerada Petroleum 1 Antelope Unit 'A' ne se 1-152n-95w

Silurian 11,727-11826

1170

0

ProductiveInterval

1180

0

Figure FB-12.4. Example of Antelope Field wireline log in the Silurian interval.

R 95 W R 94 W

-9759

30 29 28 27 26-9733

T -9702 T153 -9755 153

N -9694 N

31 32 33 34 35 -9650

-9722 -9600

-9653

3 2 1 6 5 4

-9800 -9700 -9600 TT 152152 -9615 NN

Fort Berthold Reservation7 8 9

10 11 12

R 95 W R 94 W

Note: Wells shown are deeper than Devonian

ANTELOPE FIELDSilurian Structure Map

C.I. = 25 feet

Figure FB-12.5. Silurian structure map, Antelope Field. Shows anticlinal fold trend to thesoutheast with production strongly coincident with structure.


CONVENTIONAL PLAY TYPE 6 Pre-Prairie (Winnipegosis/Interlake Play)

Page 13 of 18

110 100 105

200

A 600 A'

400 600 Ft. Berthold

0 Reservation 600 600 Dickinson Field 0 1000 400

800 600 400 North Dakota

200

0

Montana

Cambrian and older rocks exposed

sandstone and sandy Wyoming South Dakota shale facies 0 green, gray, and red shale with minor limestone

200 200 foot contour interval

Figure FB-13.1. Thickness of Upper Mississippian - Lower Pennsylvanian Big Snowy Group interval (Tyler-Heath), location of Fort Berthold Reservation, Dickinson Field (analog), and location of regional cross-section A-A' (modified after Peterson, 1987).

Fd

Gamma Ray / Neutron Log UNITEX Ltd. 6 - 1 Walton

ne ne 6 - 139n - 96w HEATH 7,800- 7,832 FT

7500

7600

7700

7800

Productive interval

Figure FB-13.3. Well log example from Dickinson Field. Upper Mississippian -Lower Pennsylvanian

Dickinson Field - Heath Pool R 97 W R 98 W

6 1 6 1

T 140 N

-5380

-5360 -5320

-5300 -5340

31 36 31 -5280 36 -5240

6 -5260 6 1 -5260

T 139 CI = 20 ' N

igure FB-13.2. Structure map of Dickinson Field, top of Heath. Complex structural configuration reflects the epositional patterns associated with fluvial, deltaic and nearshore marine environments (after Williston Basin Field

Summaries, 1984).

PLAY TYPE 7 Post Madison Clastics (Tyler-Heath)

General Characteristics - Regional deposition of fluvial, deltaic, and nearshore marine sandstones and carbonates provides the potential reservoirs for this play type. Dark gray to black, organic rich, marine shales of the Tyler are considered to be the main source rock which charge these reservoirs. The shales are thermally mature in the center of the basin and immature along the flanks. Onset of oil generation and migration is thought to have occurred in late Cretaceous to early Tertiary time. � Lateral discontinuity of potential reservoirs in the well-sorted fluvial and nearshore marine sandstones is the norm. In general, areal extent of reservoirs is limited with possible internal porosity and permeability barriers. Overall porosities may be quite good (10-16%). Tyler sandstones are roughly time equivalent to the Morrow sandstones of the mid-continent.

Dickinson Field Parameters

Formation: � Pennsylvanian TylerMississippian Heath

Lithology: Interbedded sandstones and

shales

Average Depth: � 7800 feet

Porosity: � 12%

Permeability: � 194 md

Oil/Gas Column: � not known


Other Shows: � shows in deeper Mississippian intervals�


CONVENTIONAL PLAY TYPE 7 Post Madison Clastics (Tyler-Heath)

Page 14 of 18

110 100 105 0 100 40 20 0

A 100 60 A' 0 80 Antelope

120 Ft. Berthold Reservation 120

Taylor 100

North Dakota 120 80

150 60 40

Montana 20 100

60 40 100

80 Cambrian and older rocks exposed

Wyoming South Dakota sandstone facies

40 0 20shale, sandstone and 0 minor limestone facies

green shale facies


Figure FB-14.1. Thickness of Deadwood and equivalent rocks, location of analog fields, location of reservation, and location of regional cross-section A-A' (modified after Peterson, 1987).

PLAY TYPE 8

Pre-Red River Gas Play

General Characteristics - Production has been established from Ordovician (Winnipeg) and Cambrian (Deadwood) sandstones. These units are located within the thermally mature or overmature hydrocarbon window of the Williston basin. Both gas and condensate are produced. � Reservoir intervals contain a 'clean' quartz sandstone, silica cement, and enhanced fracture porosity. Source rock is considered to be a marine shale either within the Deadwood or the Winnipeg sandstone. Hydrocarbon generation is thought to have occurred in late Cretaceous to early Tertiary time. Traps are generally asymmetric folds associated with major structural fault zones or hinge lines. � Locations of the fields used as analogs for this play type are noted on the regional facies map. Fort Berthold reservation is bracketed by these fields and in an optimum facies position for possible plays of this type to occur within the boundary of the reservation.

Taylor Field - Winnipeg Pool R 93 W R 92 W

T

-9650 140 N

-9600

-9550

-9500

-9550 TA

-9450

-9362 TA -9453 TA -9400 Taylor Field T Area 139

-9500 -9400

-9350 N -9336 -9322

-9450

-9300

-9248 -9400

-9250

-9350

T -9300 -9200-9250 138

N

-9200 -9150 CI=50 ft

Figure FB-14.4. Taylor Field, Winnipeg Structure. Production strongly correlated to major fault with associated anticlinal nose development to the northwest (from Williston Basin Summaries, 1994).

R 95 W R 94 W

30 29 28 27 26

T -12,044 T 153 153

N N

31 32 33 34 35 -11,622

-12,000-11,700

-11,830

3 2 1 6 5 4 -11,647

T T 152 152

NN 7 8 9

10 11 12 Fort Berthold Reservation

R 95 W R 94 W

Note: Gas wells shown are Winnipeg/Deadwood penetrations only.

ANTELOPE FIELD Winnipeg/Deadwood production was established at the 1-32 Brenna Lacy well in Winnipeg Structure Map section 1, T 152 N R 95 W. Cumulative production (1995) is 3037 BO and 5.3 MMcf.

C.I. = 100 feet

Figure FB-14.2. Structure contour map of the Winnepeg Fm., Antelope Field. Shows Winnepeg production correlated with anticlinal fold trend to the southeast.


Formation: Ordovician Winnipeg and Cambrian Deadwood

Lithology: very fine to fine grained, occasionally medium grainedquartz sandstone, occasionally carbonaceous and pyritic

Average Depth:� 13,900 feet

Porosity:� 12-18% depending upon interval


Oil/Gas column:� no information

Average net pay: � 40-50 feet

Other shows:� no information

Other information: 1-32 Brenna-Lacy (1992) completed in Winnipeg-Deadwood. IPF 8BCPD, 5924 MCFGPD. SI for gas. Cumulative production - (1995) 3037 BO, 5.4 MMCF.

Compensated Densilog-Compensated Neutron-Gamma Ray Log

Gulf Oil 1-24-1C Ogre

se nw 24-139n-93w

1140

011

400

1150

0

GR

1160

011

700

N

D

1180

0

Productiveinterval

Figure FB-14.3. Example of Winnipeg-Deadwood formation log signature from Taylor field.

Taylor Field Parameters

Formation: � Ordovician Winnipeg and Cambrian Deadwood

Lithology:� Interbedded shales and sandstones Sandstone consists of very fine grained quartz (based on Richardson Field core, Gulf Oil Leviathan 1-21-B

Average depth: � 11,760-11,780 feet

Porosity: � variable, 12-14% density log porosity


Oil/gas column: � no information

Average net pay: no information

Other shows: � no information

Other information: Discovery well for Taylor Field, 120 BCPD, 4.54 MMCFPD, 57.9 API. Cumulative production (1995) 128,730 BO, 5.3 MMCF.

Fort Berthold ReservationNorth Dakota

CONVENTIONAL PLAY TYPE 8 Pre - Red River Gas Play

Page 15 of 18

?

Canada United States

100

? 200

225

125

? 250

225 Immature

200 "Low-Resistivity"

Approximate Limit Of Bakken Formation Bakken Shale (Modified from Sandberg, 1962) Organic-rich rocks

175 150 have not yet generated

Mature "High" Resistivity Bakken Shale hydrocarbons - matrix Organic-rich rocks have generated porosity is water

Resistivity hydrocarbons-matrix porosity is saturated. Control Point oil saturated. (Induction or Laterolog)

North Dakota

South Dakota

Mon

tana

Figure FB-15.1. Areas of "high" and "low" electrical resistivity in Bakken shales, with subsurface isotherm contours (degrees) and interpreted area of source-rock maturity (after Messiner, 1984).

PLAY TYPE 9

Bakken Fairway/Sanish Sand Play

General Characteristics - The fractured Bakken Formation can be subdivided into three distinct rock types. The upper and lower zones are black shale with a high organic matter content. The middle zone is a relatively lean organic shale/siltstone. U.S.G.S. analyses of the Bakken indicates that 11.5-12.1 weight percent of the shale is organic carbon. Evidence suggests that the Bakken has generated hundreds of billions of barrels of oil. � The Bakken Fm, where it exists, is thermally mature (see map). It forms a continuously sourced, self-sealed reservoir. Production is

controlled by fractures; matrix porosity and permeability are low. Different fairways are assumed to exist. The areas with the highest potential have elevated thermal maturity, proximity to subcrop, close fracture spacing and proximity to basin flexure hinge lines. Vitrinite reflectance should be greater than 0.9-1.02. � The United States Geological Survey considers Antelope field a special category of Bakken fairway production. The Sanish sand is locally developed, brown, dolomitic, friable, and a slightly argillaceous sandstone with about 6-7% porosity.

Fort Berthold reservation is ideally situated for mature Bakken production. The Bakken source interval is thought to have generated over 1 billion barrels of oil but production/migration from the interval is problematic. Mechanisms for emplacement outside the Bakken interval are described below in the west/east cross-section. Production within the Bakken must be concentrated in intervals where fractures (original or induced) can remain open to fluid flow.

Dakota

CANADA

North

South Dakota

USA

-5500

Oil and/or Gas Production

Contour Interval 500 Feet

-2000 -2000

Rock

ton-Fr

oid

Fault

Zone

-3000

-4000 W

eldon

Fau

lt

-9000

-5000

South Limit

-800

0-7

000

-6000

of Bakken

-600

0

-4000-3000

-5500 Formation

-500

0

-500

0

-400

0

-500

0

-300

0

-200

0

Mo

nt.

-100

0

Wyo

min

g -1000

-2000

Figure FB-15.2. Williston Basin with structure contours on the base of Mississippian strata and limit of Bakken Formation (after Webster, 1987).

Borehole Compensated Sonic Log

William C. Kirkwod 42-8 Melby

se ne 8-152n-94w

Caliper SPHI Limestone 6.0 GR 16.0 6.300 DT -0.100 0.0 100.0 96.00 40.00

10500

caliper

GR

10600

DT

Ø Bakken Shale

interval

10700

Figure FB-15.3. Example of log signature from Antelope Field showing Bakken shale interval with sand/silt development

Antelope Field - Sanish Pool R 94 W

-8362

-8350

-8483

-8404

-8450

-8425

-8400

-8375 -8475

-8450

-8468

-8477

T

153

N

T 151 N


Formation:� Bakken shale/Sanish sandstone interval

Lithology: � sandstone, dolomitic, brown, friable, slightly argillaceous

Average depth:� 10,525 feet

Porosity: � 7.4 average

Permeability:� low, changes across structure with the sand/silt content


Average net pay: variable

Other formations Mission Canyon, with shows:� Devonian and Winnipegosis

Other information: Discovery well was Woodward Star-Tribal, sw se 21 T152N R 94 W; 550 BOPD (1953)

Figure FB-15.4. Structure map of the Sanish Pool, Antelope field (from Williston Basin Field Summaries, 1984).

West

Nesson Axis

Source Rock (Upper and Lower Bakken Shales)

Charles Formation

Bakken Formation "Maturity"

? East

Jurassic Jurassic

Big Snowy Group

Triassic

Devonian

Madison Group (L-M Miss.)Mission Canyon Fm.

Lodgep

ole

Nisku Fm.

Poor Porosity

Good Porosity

Interbedded Salt, Anhydrite and generally Black organic-rich Shale: Upper and "Maturity" dense "tight" Dolomite and Limestone: Lower Bakken Shale Members Charles Formation Hydrocarbon Accumulation

Migration Flow Direction Light-colored generally porous Limestone and Dolomite- Calcareous-dolomitic Siltstone: Middle oolitic, pelletal and skelletal i.p.: Mission Canyon and Bakken Siltstone Member Nisku Fms.

Dark-colored generally dense "tight" Shaley Limestone- Grey-green-red Dolomite, Shale, and Overpressure Cell Siliceous (tr iangle), i.p.: Lodgepole Formation Siltstone: Three Forks Formation Fractures

Figure FB-15.5. Schematic east-west section across the Williston Basin showing source-rock maturity, fluid over-pressure, fracture, migration and hydrocarbon accumulation patterns in the Bakken formation and adjacent units (after Messiner, 1984).


UNCONVENTIONAL PLAY TYPE 9 Bakken Fairway/Sanish Sand Play

Page 16 of 18

http:0.9-1.02


Greenland Alaska

Canada


United States

0 Cretaceous Epeiric Seaway

Mexico Cuba

Figure FB-16.1. Paleogeographic map of North America during Late Cretaceous time, showing the extent of the Cretaceous seaway (after Rice and Shurr, 1980).

Sys

tem

Ser

ies

Formations

Te

rtia

ry

Pa

leo

cen

e

Fort Union Formation

Hell Creek Formation

Fox Hills Sandstone

Bearpaw Shale

Judith River Formation

Up

per PierreClaggett Shale

Shale

Eagle Sandstone Gammon

Shale

Cre

tace

ou

s

Niobrara Formation

Carlile Shale

Greenhorn Formation

Belle Fourche Shale

Mowry Shale

Muddy Sandstone unconformity

Skull Creek Shalenonmarine

Lo

wer

Fall River Sandstone rocks coastal sandstones

Kootenai Formation calcareous rocks

Sunburst SS Mbr. marine siltstones and shalesCut Bank SS Mbr.

uncon

FORT BERTHOLD RESERVATION List of Topics - BIA · 2018-05-09 · The 100 and local roads. ... Lands nearly impossible to carry out due to the high fragmentation caused by within 7

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