Fort Berthold Reservation - US Department of Energy · PDF filepotential for undiscovered oil and gas reserves on the Fort Berthold Reservation. ... Table 1 summarizes the present

FORT BERTHOLD RESERVATIONList 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

Fort Berthold Reservation

OVERVIEW

FORT BERTHOLD RESERVATIONThe Three Affiliated Tribes

Tribal Headquarter: New Town, North DakotaGeologic Setting: Williston Basin

Introduction The Fort Berthold Indian Reservation is located in west-central North Dakota approximately thirty miles southwest of the city of Minot. The Reservation contains portions of Dunn, McKenzie, McLean, Mercer, Mountrail and Ward Counties and includes an area of about 1,530 square miles or 980,000 acres. These lands are located 15 miles east of the center of the Williston Basin, a geologic area where undiscovered accumulations of oil and gas may be located. Several studies have been published over the years which indicate high potential for undiscovered oil and gas reserves on the Fort Berthold Reservation. There has been past interest exhibited by oil companies, however, high royalties, high lease acquisition costs, inability to assemble large blocks of acreage, rights to seismic data, Tribal Employment Rights Office (TERO) regulations, taxes, and a 100 percent signature requirement imposed by the federal statute on Trust lands have served as deterrents to oil and gas exploration on the Reservation. The 100 percent signature requirement regulation has made exploration on Tribal Allotted Lands nearly impossible to carry out due to the high fragmentation caused by 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 Tribes are striving to work closer with oil companies to make oil and gas exploration on Fort Berthold competitive with lands outside of the Reservation. The Fort Berthold Reservation possesses all the requisites for commercial petroleum development. According to an oil and gas study authorized by Joe H. Rawlings, source rocks and reservoir caprock combinations are in evidence from the Antelope field located near the northwest corner of the Reservation. This field produces both oil and gas from four different zones. The relatively new Plaza field, located near the east exterior boundary, is also a major producing oil field. Other fields were recently discovered on the Reservation while drilling the Bakken and Mission Canyon formations. This multiplicity of geologic structures argues the presence of the many deep traps. Regardless of the development of these fields, much of the Reservation has not been explored for accumulations of oil and gas. The Williston Basin, which encompasses the Reservation, has a long history of production. Much of the oil in this area was sourced by the organically rich Bakken Formation. New horizontal drilling technology has made production from Bakken source rocks possible. A report written for the Bureau of Indian Affairs by Susan Race Wager, states that the Fort Berthold Reservation is favorably located for exploration in the Bakken Formation. According to George Long of the Bureau of Land Management (BLM), there have been 571 tests for oil and gas on or immediately adjacent to the Fort Berthold Reservation resulting in a total of 392 producing wells and 179 plugged and abandoned wells; a 69% success ratio. The majority of these 179 plugged and abandoned wells did report oil and gas shows. Of special interest, there appears to be production potential in the Mississippian Charles Formation which has been bypassed in all of the wells drilled except those few that are too shallow to reach the Charles Formation located in the Mission Canyon. Water saturation calculations were made on 60 wells to evaluate possible bypassed production in the Mississippian Charles Formation. Possible oil and gas production was indicated in 52 of these 60 wells. According to the BLM,

there are approximately 10 formations proved to be productive in the Fort Berthold area. Of further note, the facies distribution during lower Mississippian time strongly suggests that Lodgepole trends are present on the Fort Berthold Indian Reservation (USGS). The Three Affiliated Tribes have purchased seismic data from lines located in the western portion of the Reservation, which may be examined by parties 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 reside with the Division of Energy and Minerals Resources of the Bureau of Indian Affairs located in Denver, CO.

Area Location and Access Fort Berthold Indian Reservation comprises parts of Dunn, McKenzie, McLean, Mercer, Mountrail, and Ward Counties in west-central North Dakota (Figure 1), near the confluence of the Missouri and Little Missouri River valleys. Total area is about 1,530 square miles, approximately 11 percent of which is covered by waters impounded by Garrison Dam (Lake Sakakawea). The lake divides the reservation into four distinct areas, here referred to as the western, southern, eastern, and north-central segments. Although reservoir waters somewhat impede travel between the four land segments, most of the reservation is accessible over a system of State highways and local roads. Rail service is provided to the northern part of the reservation by the Soo Line Railroad. A main east-west line of the Burlington Northern passes within 7 miles of the reservation, roughly paralleling the southern boundary.

Physiography The Fort Berthold Indian Reservation includes land that ranges from rugged badlands to rolling plains. Altitudes range from about 1,850 feet at Lake Sakakawea to over 2,600 feet on Phaelen's Butte near Mandaree. The reservation is within the Northern Great Plains Physiographic Province and may be divided into four physiographic units: (1) the Coteau Slope; (2) the Missouri River trench (now flooded); (3) the Missouri Plateau; and (4) the Little Missouri Badlands. South of Lake Sakakawea the reservation has a bedrock surface with scattered areas of glacial drift. North of the lake, glacial deposits predominate and only patches of bedrock crop out. The landscape reflects this distribution of sediments: south of the lake, hills and badlands are common; north of the lake the glaciated topography is mainly undulating to rolling. The reservation area north of Lake Sakakawea is part of the Coteau Slope, which has both erosional and glacial landforms with glacial predominating. Gentle slopes characterize 50 to 80 percent of the area and local relief ranges from 50 to 200 feet. The Little Missouri Badlands lie adjacent to the Little Missouri River south and west of Lake Sakakawea as well as in a few restricted areas along the Missouri River. They consist of rugged, deeply-eroded, hilly land in which gentle slopes characterize only 20 to 50 percent of the area and local relief is commonly over 500 feet. Areas other than badlands south and west of the lake are part of the Missouri Plateau. In these areas, gentle slopes characterize about 50 to 70 percent of the area and local relief ranges from 300 to 500 feet. The Missouri and Little Missouri Rivers and their larger tributaries have cut deeply into the bedrock and glacial deposits of various compositions. The Missouri River is 300 to 500 feet below the upland plain. Near the western boundary of the reservation, the Little Missouri River has eroded a channel more than 600 feet deep. Occasional ridges and bare buttes extend as much as 400 feet above the plain.

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.

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

Percentage Classification Acreage of total

Diminished Reservation AreaTribally-owned lands. 57,954.20 5.91Allotted lands 360,438.57 36.76Government-owned land 164.09 0.01Privately owned (alienated) land 55,865.14 5.70 Subtotal 474,422.00 48.38

Reservoir Taking Area 152,359.95 15.54Homestead (ceded) Area. 353,792.59 36.08Total area of reservation. 980,574.54 100.00

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

BelfieldDickinson

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

�North DakotaOVERVIEW index

map topicsPAGE 1 of 18


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).

North Dakota

Fort Berthold ReservationGENERAL 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

INTRODUCTIONFort 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.

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

BakkenThree ForksNiskuDuperowSouris River

Winnipegosis

Red River

Winnipeg

Mowry

Muddy

Fall River

Sundance

Canyon Springs

Gypsum

Chugwater

Spearfish

Goose Egg

Minnelusa

Madison

LanceFox HillsMesaverdeCodyShannon

Frontier

MowryMuddyBear River

Cloverly

AnkarehThaynesWoodside

Dinwoody

Park City

Weber

AmsdenDarwin

Madison

Lodgepole

Gall

Flath

BlackleafBow Island

Cat CreekMoulton

Cut Bank

Amsden

Heath

Kibbey

Sun River

Lodgepole

Three Forks

NiskuDuperow

Souris River

Red River

Flathead

WESTERN WYOMING

SOUTHERN MONTANA

WESTERN NORTHERNMONTANA

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

NS

ILU

RIA

NO

RD

OV

ICIA

NC

AM

BR

IAN

ME

SO

ZO

IC

P

A

L

E

O

Z

O

I C

BI

OG

EN

IC

Sundance

Stump-Preuss

Twin Creek

Ellis Group

ReirdonSawtooth

WasatchWasatch

Lance

ParkmanSussexShannonNiobrara

Hell CreekJudith River

Eagle

NiobraraGreenhorn

Winnipeg

Tensleep

Swift Swift

Fort Union Fort Union

Teckla

Teapot

Telegraph Creek

S

S

S

S

S

S

Fort UnionFort Union

�Morrison

Ellis Group

ReirdonPiper

MorrisonGannet

MorrisonMorrison

NuggetChugwater

Phosphoria

Tyler Tyler

Big Snowy Group

Otter

Madison GroupCharlesMission Canyon

Englewood

Mission Canyon

Big Snowy Group

Otter

Madison Group

CharlesMission Canyon

Dawson Bay

Jefferson

Interlake Interlake

Stonewall

Stony MountainBig Horn Big Horn

Deadwood DeadwoodGros

Emerson

White River Green RiverWind River

Fox Hills

Eagle

Mesaverde

Frontier

NiobraraFrontier

Clagget

Dakota

Lakota

Dakota

Kootenai

Sunburst

Spearfish

Introduction

Jefferson

Darby

Minnekahta

indexmap topicsPAGE 2 of 18

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).

North Dakota

Wyoming

Cambrian and older rocks exposed

sandstone facies

shale, sandstone andminor limestone facies

green shale facies

110 105 100

AA'

South Dakota

Fort BertholdReservation

Montana

0

0

0

0

0

20

20

20

40

40

40

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100

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Antelope

Taylor

40 contour interval, in multiples of 10 feet

Triassic Rocks

Permian Rocks

Prairie Salt

Silurian Rocks

Cambrian RocksSands and Shales

Ordovician Rocks

Poplar Dome

Ordovician Rocks


Little Rocky Mountains

Pennsylvanian Rocks

Mississippian Rocks

Bakken Shale

Devonian Rocks

Bakken Shale

Bearpaw Uplift

Sweetgrass ArchPreCambrian Rocks

114 113 112 111 110 109 108 107 106 105


A

WEST

104 103 102 101 100

Rocky Mountain Trench

Overthrust Belt

0

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Thi

ckne

ss o

f Sed

imen

t (in

ft)

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A'Longitude Values (in Degrees)

Williston Basin


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).

100

A'

8000

Williston Basin

PreCambrian Rocks

Poplar Dome

Little Rocky Mountains

Bearpaw Uplift


Sweetgrass Arch

PreCambrian Rocks2000

3000

4000

5000

6000

1000

0


Overthrust Belt

Thic

knes

s of

Sed

imen

t (fe

et)

7000

West

A114 113 112 111 110 109 108 107 106 105 104 103 102 101


Fort Berthold ReservationLongitude Values (in degrees)East

North Dakota

REGIONAL GEOLOGY The Fort Berthold Reservation is situated near the deepest part of the Williston Basin (see Fig. FB-2.1 A-A' and associated cross-sections). During the Paleozoic and early part of the Mesozoic, the basin was a stable, cratonic depocenter which received over 15,000' of sediments. Fort Berthold reservation is located within the depocenter, near a major structural feature called the Nesson Anticline, which produces a significant percentage of hydrocarbons within the basin. Predominantly a carbonate depocenter in the Paleozoic, the basin is also interbedded with clastics and evaporites. The clastic intervals are composed of marine, organic rich shales which are the principal source rocks for the basin. In addition, some of the clastic intervals also include nearshore marine or fluvial sandstone deposits. The carbonate and evaporite units are mainly tidal flat, bioherm/reef or sabhka deposits. Cyclic sedimentation of marine shales, 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 via primary 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.

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

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).

BF

BK FP

BR

SR

Weldon-Brockton Fault

Cedar C

reek

Anticline

Miles CityArch

Cat Creek Fault

Syncline

SumatraSyncline

Blood Creek

Willow CreekFault

Lake Basin FaultNye-BowlerFault

BullMountains

Basin

WheatlandSyncline

CrazyMountains

Basin

Sw

eetgrassA

rch

Bowdoin

Dom

e

HinsdaleFault

PorcupineDome

Poplar Fault

PoplarDome

Nes

son

Ant

iclin

e

BASIN

Wind

River

BASIN

BIGHORN

WINDRIVER

Mtns

BighornM

tns

AbsarokaM

tns

OwlCreek

Mtns

BeartoothMtns

PryorMtns

LittleBelt

Mtns

JudithMtnsBig

SnowyMtns

OVERTHRUST

BELT

LittleRocky Mtns

BearpawUplift

Sweetwater

Uplift

Casper MtnFau

lt

Har

tville

Upl

ift

Casper

Arch

REDDESERTBASIN

HANNABASIN

ALLIANCEBASIN

GREENRIVERBASIN

WASHAKEBASIN

RockSpringsUplift

POWDERRIVER

BASIN

BlackHillsUplift

LaramieMtns

Medicine

BowM

tns

Sierra

MadreMtns

Chadron

Arch

WILLISTON

BASIN

Uinta Mtns

HogelandBasin

Alberta Shel f

114112 110 108 106 104 102 100

98105 103 101 99

97113 111 109 107

48A'A

NORTH DAKOTA

NEBRASKA

MONTANA

IDAHOWYOMING

UTAH

COLORADO

CANADA

UNITED STATES

EXPLANATION

Precambrian Basement Uplifts

Other Uplifts or Basins

Anticline

Syncline

FaultsCenezoic Volcanic Fields

Reservations X-sectionA A'

BASINLARAMIE

SOUTH DAKOTA

SR - Standing RockBR - Fort BertholdFP - Fort Peck

BK - Fort BelknapBF - Blackfeet

Geologic HistoryGEOLOGY OVERVIEW index


CretaceousEpeiric Seaway

United States

Mexico Cuba

Canada

Alaska Greenland



0

114 113 112 111 110 109 108 107 106 105

AWEST

104 103 102 101 100


Overthrust Belt

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Thi

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ft)

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EAST

A'Longitude Values (in Degrees) Fort Berthold

Reservation

Volcanics

Mississippian and OlderRocks

Poplar Dome

Upper Cretaceous

(Niobrara and Eagle Formations)

Lower Cretaceous(Mowry)

Lower Cretaceous(Kootenai)

Jurassic Rocks

Sweetgrass Arch

Bearpaw Uplift

Williston Basin

Geologic HistoryFort Berthold Reservation

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).

North Dakota

GEOLOGIC HISTORY (continued)

Geologic History - Ordovician to TriassicBy 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 CretaceousA 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 the reservation 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 QuaternaryAs 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. North Dakota

Wyoming

Cambrian and older ricks exposed

sandstone and sandyshale facies

110 105 100

AA'

South Dakota

Ft. BertholdReservation

Montana

0

00

green, gray, and red shalewith minor limestone

200 200 foot contour interval

Dickinson Field

200

200

400

400

400

600

600

600

600

600

8001000

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.

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).

GEOLOGY OVERVIEW indexmap topicsPAGE 4 of 18


Montana

Wyoming0 200km

North Dakota

South Dakota

Saskatchewan Manitoba

A

B

Cedar Creek AnticlinePetroleum Province

PoplarDome Nesson Anticline

Petroleum Province

Madison Group SubcropPetroleum Province

Region of PrairieFormation saltpreservation

3000

5000

7000

Depth of base Madison (ft)

North Dakota

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).

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)

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).

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.

Potential inOrdovician source &

Bakken

0Ma

Northern limit ofOrdovician source

Bakken thicknessexaggerated x 2.5

Winnipeg sourceinterval Bighorn

Interlake

Duperow

Madison

TR=.10

TR=.20

TR=.65

TR=.90

0

1

2

3

4

Dep

th (

km)

30025020015010050

Distance (km)A B250150

Potential inWinnipegosis &

Lodgepole

0Ma

TR=.10

TR=.20

TR=.90

0

1

2

3

4

Dep

th (

km)

30020010050

Distance (km)

Lodgepole

Winnepegosis thickness exaggeratedx 2.5 between 0-250km

TR=.65

HC saturation

< 2%

2 - 5%

5 - 10%

10 - 80%

> 80%

Prairiesalt horizon

A B

HC saturation

< 2%

2 - 5%

5 - 10%

10 - 80%

> 80%

Prairiesalt horizon

Petroleum Systemsindexmap topicsPAGE 5 of 18

Reservation:Geologic Province:Province Area:Reservation Area:

Fort BertholdCentral Wiliston BasinWilliston Basin (143,000 sq. miles)1530 sq. miles (980,000 acres)

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

Williston Basin1496 MMBO1735 BCFG192 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 USGS Designation

Unfavorable factorsFavorable factorsDrilling depthsPlay Probability(chance of success)Undiscovered Resource (MMBOE)Known AccumulationsOil or GasDescription of Play

Madison, structure

1

3101a folded structures, primaryand secondary porosityin carbonates

1high

878 MMBO916.5 BCFG77.9 MMBNGL(numbers include 1, 2,& 3)

3,000 - 12,000 ft 1) confirmed play; excellent production within reservation2) thermally mature source rocks3) source rocks and reservoir present4) seismic delineation is useful

1) lack of well control2) rough topography3) porosity and facies may be highly variable

Both

Madison shoreline/truncation play

2

3101b Cyclic evaporite/ carbonatesequence, structure/stratigraphicupdip pinchout, multiple shorelinecycles

1high


3,000 - 12,000 ft 1) confirmed play; excellent production within reservation2) thermally mature source rocks3) source rocks and reservoir present4) trend extends into reservation5) mostly shallow drilling depths

1) lack of well control2) rough topography3) porosity and facies may be highly variable4) seismic may not be able to delineate shoreline trends

Both

Miss. Lodgepole/Waulsortian Mound play

3

3101c Mound buildups; 'reefs', smallbut prolific structures; excellentporosity and permeability

1high


3,000 - 12,000 ft 1) confirmed play; trend probably extends to reservation2) thermally mature source rocks3) source rocks and reservoir present4) seismic may be very useful

1) lack of well control2) rough topography3) small areal extent, may be difficult to explore for

Both

Ordovician Red RiverPlay

4

3102 Cyclic evaporite/ carbonatesequence, structure/stratigraphicupdip pinchouts; multiple shorelinecycles

1high

188.3 MMBO555.7 BCFG70.5 MMBNGL

7,000 - 12,000 ft 1) confirmed play; production within reservation2) thermally mature source rocks3) source rocks and reservoir present4) seismic useful in locating structures

1) lack of well control2) rough topography3) possible small exploration targets

Both

Play TypesFort Berthold ReservationNorth Dakota

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.

Niobrara10 10

Upper Cretaceous

Jurassic

Triassic

Permian

Pennsylvanian

Mississippian

Mississippian

1

2 2

9

9

7

7

84

Devonian

Red River

356

Interlake

3

Bakken Shale

Schematic Diagram of Play Types - Fort Berthold ReservationWEST EAST

No scale implied - drawing is approximate width of Reservation

Winnipeg

Deadwood

Play Types - Explanation

1. Madison Structure Play

2. Madison Shoreline/Truncation Play

3. Mississippian Lodgepole Waulsortian Mound Play

4. Ordovician Red River Play

5. Devonian Nisku/Duperow Play

6. Silurian Interlake Play

7. Pennsylvanian Tyler-Heath Play

8. Pre-Red River Gas Winnipeg/Deadwood Clastics

9. Fractured Bakken Play

10. Shallow Microbial Gas Play

Precambrian

Limestone

Organic-richshale

Sandstone

Limestone shorelinesor Waulsortian Mounds

Dolomite Fluvial/Clastic dominated shorelines

Clastic/calcareous shale

Oil Gas

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

Table FB-5.1. Play summary chart

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

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

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

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) lack of well control2) rough topography3) Probable narrow bands of potential fractured reservoir zones

1) lack of well control2) rough topography3) reservoir continuity is problematic4) areal extent may be small

Fractured Bakken

9

3111 Organic rich shale, marine siltstone;fractured; thermally mature oil shale

10.2 (20%)

No information availableOil shows from Sanish sandstones

not estimated70.3 MMBO/ sq. mile generated hydrocarbons56.24 MMCFG/ sq. mile generated hydrocarbonsArea of play = 8185 sq. miles7806 sq. miles untested

7,500 - 11,100 ft 1) confirmed play; production within reservation2) thermally mature source rocks3) source rocks and reservoir present4) seismic delineation is useful

Both

Niobrara MicrobialGas Play

10

3113 Niobrara limestone and othershallow reservoirs, self-sourced;porosity decreasing with increasingdepth. Large volume accumulationspossible

10.5 (50%)

Only production to date is fromCedar Creek Anticline and Bowdoin dome. These fields arefrom shallow Eagle Formation sandstones, not Niobrara.

not estimated180 MMCFG/160 acres (median)256 MMCFG/160 acres (mean)Area of play = 55,000 sq. miles29,958 sq. miles untested (mean)

500 - 4500 ft 1) large volume play2) shallow drilling depths3) accumulations in structural traps, seismic may be useful in delineation of traps

Microbial gas

Reservation:Geologic Province:Province Area:Reservation Area:

Fort BertholdCentral Williston BasinWilliston Basin (143,000 sq. miles)1530 sq. miles (980,000 acres)

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

Williston Basin1496 MMBO1735 BCFG192 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 USGS Designation

Unfavorable factorsFavorable factorsDrilling depthsPlay Probability(chance of success)

Undiscovered Resource (MMBOE)Field Size (> 1 MMBOE) min, median, mean

Known AccumulationsOil or GasDescription of Play

Nisku and Duperow

5

3103 Cyclic evaporite/carbonatesequences. Structural andstratigraphic pinchouts. Excellentporosity and permeability

1high

160.5 MMBO159.2 BCFG12.7 MMBNGL

8,000 - 12,500 ft 1) confirmed play;production within reservation2) thermally mature source rocks3) source rocks and reservoir present4) seismic delineation is useful

1) lack of well control2) rough topography

Both

Silurian Winnipegosisand Interlake

6

3105 Cyclic evaporite/ carbonatesequence, erosional surfaces.Primary and secondary porosity.Structural and unconformity relatedtrapping mechanisms

1mod.- high

55.5 MMBO180 MMCFG24.8 MMBNGL

8,000 - 12,500 ft 1) confirmed play; production within reservation2) thermally mature source rocks3) source rocks and reservoir present4) seismic useful in prospect delineation

1) lack of well control2) rough topography

Both

Post MadisonPenn. Tyler/Heath

7

3106 Fluvial and nearshore sandstoneswith structural closures. Traps mayalso occur as discontinuous sandstonelenses.

1mod.-high

133.5 MMBO28.8 BCFG

5,500 - 9,000 ft 1) Thermally mature source rocks2) source rocks and reservoir present3) shallow drilling depths

1) No production withinreservation2) rough topography3) lack of well control4) depositional area withinreservation may be marineinstead of shoreline

Both

Ordovician Pre-Red RiverPlay

8

3107 Clastic sequences, fluvial andnearshore blanket sandstones.Large, faulted structures

1moderate

no informationavailable

10,000 - 16,000 ft 1) confirmed play; production within reservation2) thermally mature source rocks3) source rocks and reservoir present4) seismic useful in locating structures5) high volume reserves

1) lack of well control2) rough topography3) low BTU, contains nitrogen

NGL and lowBTU gas

Fort Berthold ReservationNorth Dakota

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

Unconventional/Hypothetical play type

Median 16 MMBO (8 fields @ 2 MMBO)

Field Size (> 1MMBOE)2 MMBO 10 MMBO 2.1 MMBO

No of undiscovered fields (> 1 MMBOE)4 (min) 8 (median) 15 (max) 8.6 (mean)

Median 50 BCFG (5 fields @ 10 BCFG)

Field Size (> 1MMBOE)10 BCFG 25 BCFG 13.1 BCFG

No. of undiscovered fields (> 1 MMBOE)1 (min) 5 (median) 20 (max) 7.3 (mean)


Field Size (> 1MMBOE)3 MMBO/15 MCFG(min) 15 MMBO/90 MMCFG(median)3.3 MMBO/19.7 MMCF(mean)

No. of undiscovered fields (> 1 MMBOE)5 (min) 15 (median) 25 (max) 15 (mean)


Field Size (> 1MMBOE)2 MMBO/10 BCFG 10 MMBO/60 BCFG 2.1 MMBO/13.1 BCFG

No.of undiscovered fields (> 1 MMBOE)9 (min) 25 (median) 60 (max) 26.9 (mean)

Summary of Plays (continued)indexmap topicsPAGE 7 of 18

A A'

GR

Texaco#4 Gov't-Dorough

Se Sw Sec. 21KB 2690'

A.P.C.#20 SivertsonSe Se Sec. 20

KB 2493'

A.P.C.#2 Selliseth


A.P.C.#1 Aura

Se Se Sec. 19KB 2388'

A.P.C.#3 M Aura


Mississippian

Madison

Formation

Last Charles Salt

Gamma Ray MarkerTop Blue Buttes Pay

9700

9600

9500

9500

9400

9400

9400

9400

9300

9300

9300

9300

9200

9200

9200

9100

9100

9100

9000 -6500

-6600

-6700

-6800

-6900

-7000

9000

9100

9200

9300

Blue Buttes Field Structural Cross-Section

LLGR

LL

161

7 12

1318

19 24

2530

3136 36

161

7 12

1318

1924 24

R 96 W R 95 W

T151N

T150N

Blue Buttes Field

Top Lower Charles Salt Structure Map

CI = 20 feet

Note: Only Madison penetrationsare shown

R 95 WR 96 W

A A'

-670

0

-670

0

-680

0

-660

0

-660

0


Kibbey

Charles

Madison

Kibbey

Charles

MadisonLodgepole

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

-6575

TD -6866

-5000

TD -6908

TD -7212

unconformity horizons

TD -8255

TD -8570

-5000'

A.P.C. #1 Swenson HeirsC Se Ne 11-152N-95W

2242 KB

A.P.C. #1 AB Fleming EstateC Nw Nw 12-152N-95W

2210 KB

A.P.C. #1 T Larson Tract 1C Se Sw 1-152N-95W

2136 KB

A.P.C. #1 Antelope Unit 'A' Ne Se 1-152N-95W

2117 KB

A.P.C. Gulf #1 J Strand S/2 Nw/4 6-152N-94W

2129 KB

A.P.C. Carter #1 Reed-Norby Unit Lot 2 6-152N-94W

2198 KB

R 94 W

T152N

Fort Berthold ReservationA

B'

Index Map

Structural Cross Section

Antelope FieldMcKenzie Co., North Dakota

B B'

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

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

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.

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.

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

Average net pay: variable

Other shows: Sanish, Duperow, Interlake.

Other information: contains 4.7% H2S

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


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

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)

CONVENTIONAL PLAY TYPE 1Folded Structure - Mississippian Carbonate Play


GR GR GRCNL/FDC CNL/FDC CNL/FDC

Se Se 3152N-88W

Se Nw 2152N-88W

Sw Sw 32152N-87W

A A'

SW NE

72007300

7500

72007300

7500

72007300

7400

Rival

L. Bluell

Sherwood

Mohall

Glenburn

IPF 259 BO, 129 MCFG &0 BWPD

Perfs: 7354-7390

IPF 308 BO, 134 MCFG &0 BWPD

Perfs: 7324-7366

D & ADST: Rec. 45' SO&GCM,

270' GCW

Intershoal Mudstone

Wabek Field Cross-section

8 ø8 ø

8 ø

DEN POR DEN POR DEN POR

NEU POR NEU PORNEU POR

GR GR GRCNL/FDC CNL/FDC CNL/FDC

Ne Ne 20152N-88W

Ne Ne 21152N-88W

Ne Ne 22152N-88W

B B'

West East

Rival

L. Bluell

Sherwood

Mohall

Glenburn

IPP 29 BO, 45 MCFG &65 BWPD

Perfs: 7482-7484, 7490-7496

IPP 34 BO, 15 MCFG &57 BWPD

Perfs: 7415-7424,7436-7438

IP: Non-commercialPerfs: 7388-7402, 7408-7412

7416-7422

Plaza Field Cross-section

8 ø8 ø

8 ø

DEN ø DEN ø DEN ø

NEU ø NEU øNEU ø

74007600

7700

73007400

75007600

73007500

Canada

U.S.A.

Carnduff

Elmore

MouseRiverPark

Lake

Darling

LoneTree

Wabek

Plaza

Lucky Mound

Centennial

SherwoodShoreline

Burke

North Dakota

Renville

Bottineou

Mountrail

Ward McHenry

McLean

Index Map0 12 24

miles

North Dakota

StudyArea

PlazaField

(Bluell Production)

WabekField

(Sherwood Prod.)

R 87 WR 88 W

T153N

T152N

-5200

-5300

-5400

-5500

B B'

A

A'

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


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

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)

PLAY TYPE 2 Mississippian Shoreline Play

General characteristics - This play is an extension of the northeast shelf play which 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 banks along 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.

Plaza Field Parameters

Formation: Mississippian Mission Canyon, Bluell subinterval

Lithology: Light brown-brown, peloidal, oolitic pisolitic, intraclastic and composite 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%


Oil/Gas column: at least 100 feet

Average net pay: 26 feet

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

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

CONVENTIONAL PLAY TYPE 2Mississippian Shoreline Play


WILLISTON BASINLodgepole Buildups

West East

sea level

MontanaTrough

basin shelfshelfslope

Grainstone-packstone beds on flanks of mound

Bryozoan-crinoid buildup facies (potentialhydrocarbon reservoir)

Mudstone-wackestone core facies of mound

Wackestone-packstone buildup facies

Explanation

CANADA

Montana TroughLB

BS

B

500

500

700900

100

300 500

300

500

SS

S ?

?

?

?

?

Postulated Waulsortian mounds

Known Waulsortian mounds

Approximate erosionallimit of Madison Formation

Fort Berthold

260

240

237

234

262

303

255

368 378

20' Contour Interval

R 96 WR 97 W

T140N

T139N

Dickinson Field, Lodgepole FormationWilliston Basin

CONOCO, INC.Kadramas 75

NW SE 31-140-96Stark Co., N.D.

9200

9300

9400

9500

9600

9700

9800

9900

10000

10100Three Forks

Bakken

LowerLodgepole

Lodgepole

MissionCanyon

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

Supra Mound

Mound Core

medium to dark gray-brown slightlyargillaceous and cherty skeletalwackestones and mudstones

light to medium gray-brown mottledwith dark brown, bryozoan baffle andboundstones with grainstone, packstone,and wackestone matrix; abundant coarsecalcite cement

black shale interbedded withargillaceous mudstone and calcareous siltstones

light brown gray dolomite interbedded withgray green shale

log marker

(-7365)

oil/water

contact

DLLGR

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).

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).

Figure FB-9.4. Generalized Lodgepole section depicting Waulsortian Mound Buildup (after Burke and Lasemi, 1995).


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

PLAY TYPE 3

Mississippian LodgepoleWaulsortian 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.

CONVENTIONAL PLAY TYPE 3Mississippian Lodgepole Waulsortian Mound Play


Wyoming

Ordovician orolder rocks exposed

Dolomite facies - Red River

110 105 100

AA'

South Dakota

contour interval, 200'400

Limestone and dolomite faciesRed River

North DakotaMontana

Antelope

Blue Buttes

300

300

300

300

300

100

100

100

500500

500

500

700


30 29 28 27 26

31 32 33 34 35

123

10 11 12

6 5 4

7 8 9


R 95 W R 94 W

T153

N

T153

N

R 95 W R 94 W

T152

N

T152

N

Note: Wells shown are Red River penetrationsonly.

Red River production was established atAntelope Field in 1989 with the 30-23 Mckeenwell in section 30, T 153 N, R 94 W

ANTELOPE FIELDRed River Structure Map

C.I. = 50 feet

-10,993

-11,145

-11,000

-11,000-11,100

-11,200 -11,080

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).

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

161

7 12

1318

19 24

2530

3136 36

161

7 12

1318

1924 24

R 96 W R 95 W

T151N

T150N

11,600

11,500

11,400

11,300

11,300

11,400

11,500

11,500

11,400

Blue Buttes Field

Red River Structure Map

CI = 25 feet

Note: Only Red River penetrationsare shown

R 95 WR 96 W

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

Ordovician Red River PlayFort Berthold ReservationNorth Dakota

PLAY TYPE 4

Ordovician Red River Play

General Characteristics: This is the second most productive formation in the Williston basin. Reservoirs are dolomite intervals and dolomitic limestones formed from bioclastic mounds and tidal flat deposits. Cyclic deposits of carbonate, 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 over basement 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.


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


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


Other shows: Kibbey Sandstone, Kibbey Limestone Charles Formation

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

CONVENTIONAL PLAY TYPE 4 indexmap topicsPAGE 11 of 18

North Dakota

Wyoming

Silurian and older rocks exposed

Limit of Bakken sourcerocks

110 105 100

A A'

South Dakota


Montana

contour interval, 200'

Antelope

400

200

200

400

400

200

200600

600800

80010001000

20001200

1400

1600

1800

1200

600

Bear Den

Limit of Prairie salt

23 24 19

26 25 30

35 36 31

R 96 W R 95 W

T149N

-9000

-8950

-8900

-8900

Birdbear

Duperow

Souris River

Ne Ne Sec. 36, T 149 N, R 96 WGR Laterolog

dolomite

evaporite

shale

11,300

11,250

Bear Den - Devonian FieldMckenzie County

North Dakota

TOP DUPEROW STRUCTURECI= 50'

30 29 28 27 26

31 32 33 34 35

123

10 11 12

131415

2422

6 5 4

7

18

18

30 29 28

20 21

17 16

8 9

R 95 W R 94 W

T153

N

T153

N

R 95 W R 94 W

T152

N

T152

N

ANTELOPE FIELD

Devonian DuperowStructure Map

C.I. = 100 feet


-8200

-8100

-8300

-8400

-8600

DevonianDuperow

Bakken

Limestone

Shale

Dolomite

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).

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

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.


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)

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.

Bear Den Field Parameters

Formation: Devonian Duperow

Lithology: microcrystalline dolomite with fair microsucrosic porosity

Average depth: 11,300 feet

Porosity: variable, microsucrosic


Oil/Gas column: variable


Other info: no H2S


Formation: Devonian Duperow

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


Porosity: variable, granular, vuggy



Average net pay thickness: variable

Other shows: Madison, Interlake, Sanish

Other information: No H2S

Devonian Nisku - Duperow PlayCONVENTIONAL PLAY TYPE 5 index


30 29 28 27 26

31 32 33 34 35

123

10 11 12

6 5 4

7 8 9Fort Berthold Reservation

R 95 W R 94 W

T153

N

T153

N

R 95 W R 94 W

T152

N

T152

N

Note: Wells shown are deeper than Devonian

ANTELOPE FIELDSilurian Structure Map

C.I. = 25 feet

-9759

-9755

-9733

-9702

-9694

-9650

-9615

-9600

-9653

-9722

-9800 -9700 -9600

North Dakota

Wyoming

Silurian and older rocks exposed

Limey dolomite facies

dolomite facies

110 105 100

AA'

South Dakota


Montana

contour interval, 200'

100

300

500

700

900

1100

0

0

Antelope

100

1250

012

400

1230

012

200

Productive interval

Borehole CompensatedSonic Log

Amerada Hess9-43 Jones

ne se 9-150n-95wInterlake: 12,315-12,356

12,372-12,39412,404-12,418 -9898

NDE

NDE

NDENDE

NDE

-9951 NDENDE NDE

NDE

-9917

-9997

NDE NDE

NDE NDE

-10027

-9996

NDE

NDE-9967

-9935NDE

-9880-10022

2530

32 36

15

8 12

1317

20 24

25

Blue Buttes Field

Interlake Structure MapFort Berthold

C.I. = 25 feet

T152N

T151N

R 96 W


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).

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

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

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

North Dakota

PLAY TYPE 6

Pre-Prairie ( Winnipegosis/Interlake Play)

General Characteristics - Regional carbonate units of lower Devonian and 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 regional structure. Stratigraphic traps (either pinch-outs or porosity variations) may exist as well.

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


Formation: Silurian Interlake

Lithology: Dolomite

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

Porosity: 12%


Oil/Gas column: not known



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


Average net pay thickness: variable

Other shows: Madison, Duperow, Sanish

1170

011

800

Productive Interval

Laterolog with Gamma Ray

Amerada Petroleum1 Antelope Unit 'A'ne se 1-152n-95w

Silurian 11,727-11826

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


A

200

North Dakota

Wyoming


sandstone and sandyshale facies

110 105 100

A'

South Dakota


Montana

0

0

00

green, gray, and red shalewith minor limestone200 foot contour interval

Dickinson Field

200

200

400

400

400

600

600

600

600

600

8001000


-5380

-5360

-5340

-5320

-5300

-5280

-5260-5260

-5240

16

31 36

1

31 36

6

166

R 97 W R 98 W

T140N

T139N

Dickinson Field - Heath Pool

CI = 20 '

7500

7600

7700

7800

Productive interval

Gamma Ray / Neutron LogUNITEX Ltd. 6 - 1 Walton

ne ne 6 - 139n - 96wHEATH 7,800- 7,832 FT

North Dakota

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).

Figure FB-13.2. Structure map of Dickinson Field, top of Heath. Complex structural configuration reflects the depositional patterns associated with fluvial, deltaic and nearshore marine environments (after Williston Basin Field Summaries, 1984).

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

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


North Dakota

Wyoming


sandstone facies

shale, sandstone andminor limestone facies

green shale facies

110 105 100

AA'

South Dakota


Montana

0

0

0

0

0

20

20

20

40

40

40

40

60

60

60

80

80

80

100

100

100

100

120

120

120

100

150

Antelope

Taylor

40 contour interval, 20'

-12,000-11,700

30 29 28 27 26

31 32 33 34 35

123

10 11 12

6 5 4

7 8 9

-12,044

-11,622

-11,830

-11,647


R 95 W R 94 W

T153

N

T153

N

R 95 W R 94 W

T152

N

T152

N

Note: Gas wells shown are Winnipeg/Deadwoodpenetrations only.

Winnipeg/Deadwood production wasestablished at the 1-32 Brenna Lacy well insection 1, T 152 N R 95 W. Cumulativeproduction (1995) is 3037 BO and 5.3 MMcf.

ANTELOPE FIELD

Winnipeg Structure Map

C.I. = 100 feet

GR

N

D

1140

0

Productive interval

1140

011

500

1160

011

700

1180

0

Compensated Densilog-CompensatedNeutron-Gamma Ray Log

Gulf Oil1-24-1C Ogre

se nw 24-139n-93w

-9650

-9600

-9500

-9550

-9450

-9400

-9400

-9350

-9300

-9250

-9200

-9150

-9500

-9450

-9400

-9350

-9300 -9250

-9200

Taylor Field Area

-9248

-9322

-9336

-9453 TA

-9550 TA

-9362 TA

Taylor Field - Winnipeg PoolR 93 W R 92 W

T140 N

T139N

T138N


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).

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

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.


Formation: Ordovician Winnipeg and Cambrian Deadwood

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

Average Depth: 13,900 feet

Porosity: 12-18% depending upon interval



Average net pay: 40-50 feet


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.

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

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).

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

CI=50 ft

Pre - Red River Gas PlayCONVENTIONAL PLAY TYPE 8 index


Source Rock(Upper and Lower Bakken Shales)

West

Nesson Axis

Charles Formation

Bakken Formation "Maturity"

?

Interbedded Salt, Anhydrite and generallydense "tight" Dolomite and Limestone:Charles Formation

Light-colored generally porous Limestone and Dolomite-oolitic, pelletal and skelletal i.p.: Mission Canyon andNisku Fms.

Dark-colored generally dense "tight" Shaley Limestone-Siliceous (tr iangle), i.p.: Lodgepole Formation

Black organic-rich Shale: Upper andLower Bakken Shale Members

Calcareous-dolomitic Siltstone: MiddleBakken Siltstone Member

Grey-green-red Dolomite, Shale, andSiltstone: Three Forks Formation

Migration Flow Direction

Hydrocarbon Accumulation

"Maturity"

Overpressure Cell

Fractures

Poor Porosity

Good Porosity

East

Jurassic

Big Snowy Group

Madison Group (L-M Miss.)

Devonian

Mission Canyon Fm.

Triassic

Jurassic

Lodgepole

Nisku Fm.

?

?

?

CanadaUnited States

200

200

225

225

250

175 150

125

100

Mon

tana

-8468

-8477

-8404

-8483

-8450

-8362

-8475-8450

-8425

-8400

-8375

-8350

Antelope Field - Sanish PoolR 94 W

T

153

N

T151N

Borehole CompensatedSonic Log

William C. Kirkwod42-8 Melby

se ne 8-152n-94w

CaliperGR6.0 16.0

0.0 100.0DT

SPHI Limestone

40.0096.00

-0.1006.300

GR

caliper

DT

Ø

10500

10600

10700

Bakken Shale interval

NorthDakotaSouthDakota

CANADA

USA

-5500

Oil and/or Gas Production

Contour Interval 500 Feet

-2000 -2000

-3000

-4000

-5000W

eldon

Fau

lt

Rockton-Froid

Fault Zone

-9000

-800

0-7

000

-600

0-5

000

South Limit of Bakken

Formation

-400

0-3

000

-200

0

-100

0

-2000-1000

Wyo

min

gM

ont.

-500

0

-5500

-6000

-500

0

-4000-3000

Bakken Fairway/Sanish Sand PlayFort Berthold ReservationNorth Dakota

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).

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

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

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

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).

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.


Formation: Bakken shale/Sanish sandstone interval

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


Porosity: 7.4 average

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



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)

UNCONVENTIONAL PLAY TYPE 9

Organic-rich rocks have generatedhydrocarbons-matrix porosity isoil saturated.

ResistivityControl Point(Induction or Laterolog)

Approximate Limit Of Bakken Formation(Modified from Sandberg, 1962)

Mature "High" Resistivity Bakken Shale

Immature"Low-Resistivity"Bakken ShaleOrganic-rich rockshave not yet generatedhydrocarbons - matrixporosity is watersaturated.

North Dakota

South Dakota



United States

Mexico Cuba

Canada

Alaska Greenland



0

NonMarine

Rocks

NorthDakota

SouthDakotaMontana

Wyoming

United States

Canada112 110108 106 104 102

49

48

47

46

45

44

Legend for Facies Map

non marine rocks

coastal sandstones

interbedded shelf sandstone and shalessiltstones and shales

chalk and limestone

Formations

Ser

ies

Sys

tem

Tert

iary

Pale

oce

ne

Fort Union Formation

Hell Creek Formation

Fox Hills Sandstone

Bearpaw Shale

Judith River Formation

Claggett Shale PierreShale

EagleSandstone Gammon

Shale

Niobrara Formation

Carlile Shale

Greenhorn Formation

Up

per

Cre

tace

ou

s

Lo

wer

Belle Fourche Shale

Mowry Shale

Muddy Sandstone

Skull Creek Shale

Fall River Sandstone

Kootenai Formation

Sunburst SS Mbr.

Cut Bank SS Mbr.unconformity

Morrison Formation

Jura

ssic

Up

pe

r

unconformity

nonmarine rocks

coastalsandstones

calcareous rocks

marine siltstonesand shales

2800 2800

2600

2500

25002400

2300

2200

2200

Cheyenne Co.Sherman Co.

Wheeler

BenkelmanLow

2100

CherryCreek, East

St. Francis

2100

2000

2000

Armel

BeecherIsland

Vernon

2000

Low

Low

Col

orad

o

Kan

sas

R44W 43 42 41 40 39 38 R37W

T1S

2

3

4

5

Beecher IslandGas Zone

perforatedinterval

Resistivity

1.0 10 100 40 240 0153045

20

mv

Gamma Ray Porosity

SP

1450 1450

1550 1550

RILDRLL8

GammaRay Density

Porosity

NeutronPorosity

0510Core Permeability

(md)

CAOF 2100 MCFGPDNIO

BR

AR

A

Sm

oky

Hill

Mem

ber

PIE

RR

E

Sha

ron

Spr

ings

Mbr

.


burial > 3000'Ø could be<35%

burial between3000-4000'Ø could be30-35%

Lim

it

ofoccurre

nceof

Nio

brar

a F

m.

Area

ofburial

below4000'

3000'

NorthDakota

SouthDakota

Nebraska

Kansas

OklahomaNewMexico

Colorado

Wyoming

Montana

North Dakota

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).

Figure FB-16.4. Regional distribution of diagenetic and petrophysical facies of the Niobrara. Area within 3000 feet or less of burial should contain chalks with porosity greater than 35%. Areas between 3000 and 4000 feet of burial should average 30-35% porosity (after Rice and Shurr, 1980).

Figure FB-16.3. General correlation chart of Cretaceous rocks (after Rice and Shurr, 1980).

Figure FB-16.5. Structure map on top of the Niobrara Formation, northwestern Kansas showing a Niobrara gas field (in red). Contour interval is 100 feet. Hypothetical or unconventional play for Fort Berthold reservation (after Lockridge and Sholle, 1978).

Figure FB-16.6. Type logs for Niobrara producing well, Beecher Island area, Kansas Nebraska No. 1-32 Whombie, sec. 32, T2S, R43W (after Lockridge and Sholle, 1978).

PLAY TYPE 10

Niobrara Microbial Gas Play(Low - High Potential)

General Characteristics - Upper Cretaceous Niobrara is a chalk and calcareous shale that covers most of the western interior from Kansas and eastern Colorado into the Dakotas. It is assumed that a Niobrara gas play similar to the eastern Denver Basin (Beecher Island Field, Goodland Field) exists in the southern Williston basin. Niobrara production in the Denver Basin is considered a self-sourced, continuous extent gas field.Estimated thickness of the Niobrara would be greater than 100 feet, and depth of burial is less than 1000 feet. Area of subcrop or outcrop might affect gas generation. Areal extent of production might be as small as 25 square miles.

Figure FB-16.2. Map showing depth of burial of the Niobrara Formation. Across reservation area porosity could be <35% (after Rice and Shurr, 1980).

UNCONVENTIONAL PLAY TYPE 10Niobrara Microbial Gas Play



General ReferencesFort Berthold Reservation

Anderson, Robert C., 1995, The Oil and Gas Opportunity on Indian Lands-Exploration Policies and Procedures, Bureau of Indian Affairs, Division of Energy and Mineral Resources, General Publication G-95-3, 158 p.

Beeman, William R., et al., 1996, Digital Map Data, Text and Graphical Images in Support of the 1995 Assessment of United States Oil and Gas Resources, United States Geological Survey, Digital Data Series DDS-35, CD ROM.

Charpenteir, Ronald R., et al., 1996, Tubular Data, Text, and Graphical Images in Support of the 1995 National Assessment of United States Oil and Gas Resources, United States Geological Survey, Digital Data Series DDS-36, CD ROM.

Gautier, Donald L., et al., 1996, 1995 National Assessment of United States Oil and Gas Resources - Results, Methodology, and Supporting Data, United States Geological Survey Digital Data Series DDS-30 Release 2.

_______________., et al., 1995, 1995 National Assessment of United States Oil and Gas Resources, Overview of the 1995 National Assessment of Potential Additions to Technically Recoverable Resources of Oil and Gas - Onshore and State Waters of the United States, United States Geological Survey Circular 1118, 20 p.

Mallory, William Wyman, et al., 1972, Geologic Atlas of the Rocky Mountain Region, Rocky Mountain Association of Geologists ,331 p.

Peterson, James A. and MacCary, Lawrence M., 1987, "Regional Stratigraphy and General Petroleum Geology of the U.S. Portion of the Williston Basin and Adjacent Areas", Williston Basin: Anatomy of a Cratonic Oil Province, Rocky Mountain Association of Geologists, pp. 9-43.

Rice, Dudley D. and Shurr, George W., July 1980, "Shallow, Low-Permeability Reservoirs of the Northern Great Plains - Assessment of their Natural Gas Resources", American Association of Petroleum Geologists Bulletin, Volume 64/7, pp. 969-987.

Willette, Donna C., et al., 1996, "Oil and Gas Atlas on Indian Lands", Indian Resources Building Partnerships, Sixth Annual Energy and Minerals Conference, Bureau of Indian Affairs, Division of Energy and Mineral Resources, 10 p.

Fort Berthold Reservation-Fields and Articles

Anderson, Robert C., 1995, "Fort Berthold Reservation-The Three Affiliated Tribes", The Oil and Gas Opportunity on Indian Lands-Exploration Policies and Procedures, Bureau of Indian Affairs, Division of Energy and Mineral Resources, General Publication G-95-3, pp. 29-42.

Burke, Randolph B. and Zakaria Lasemi, 1995, "A Preliminary Comparison of Waulsortian Mound Facies in the Williston and Illinois Basins", Seventh International Williston Basin Symposium, Montana Geological Society, Billings, Montana, pp. 115-128

Editors, North Dakota Geological Society, 1962, "Antelope Field-Sanish", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 21-22.

____________, 1962, "Antelope Field-Sanish", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 23-24.

____________, 1962, "Antelope Field-Duperow", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 25-26

____________, 1962, "Antelope Field-Interlake", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 27-28.

____________, 1962, "Antelope Field-Madison", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 21-22.

____________, 1962, "Bear Den-Madison", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 31-32

____________, "Bear Den-Devonian", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 33-34

____________, 1962, "Blue Buttes-Madison", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 49-52

____________, 1962, "Croff-Madison", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 77-78

____________, 1962, "Croff-Devonian", Oil and Gas Fields of North Dakota-A Symposium , North Dakota Geological Society, Bismark, North Dakota, pp. 79-80

Editors, Petroleum Information, 1984, Antelope Field-Sanish Pool - McKenzie County, North Dakota", Williston Basin Field Summaries, Petroleum Information.

____________, 1984, "Antelope Field-Devonian Pool-McKenzie County, North Dakota", Williston Basin Field Summaries, Petroleum Information.

____________, 1984, "Antelope Field-Silurian Pool-McKenzie County, North Dakota", Williston Basin Field Summaries, Petroleum Information.

____________, 1984, "Blue Buttes-Silurian Pool-McKenzie County, North Dakota", Williston Basin Field Summaries, Petroleum Information.

____________, 1984, "Blue Buttes-Red River Pool-McKenzie County, North Dakota", Williston Basin Field Summaries, Petroleum Information.

____________, 1984, "Dickinson Field Heath Pool-Stark County, North Dakota", Williston Basin Field Summaries, Petroleum Information.

____________, 1984, "Taylor Field-Winnipeg Pool-Stark County, North Dakota", Williston Basin Field Summaries, Petroleum Information.

Gordon, Ian R., 1995, (Abstract) "Stratigraphy and Structure of an Early Mississippian Waulsortian Bioherm in the Lodgepole Formation, Dickinson Field, North Dakota", Seventh International Williston Basin Symposium, Montana Geological Society, Billings, Montana, pp. 449.

Peterson, James A., 1996, "Williston Basin Province (031)", Tabular Data, Text, and Graphical Images In Support of the 1995 National Assessment of United States Oil and Gas Resources, United States Geological Survey, Digital Data Series DDS-36, CD ROM.

Shurr, George W., et al., 1995, "Tectonic Controls on the Lodgepole Play in Northern Stark County, North Dakota- Perspectives from Surface Studies", Seventh International Williston Basin Symposium, Montana Geological Society, Billings , Montana, pp. 203-208.

Sperr, J.T., et al., 1993, "Wabek and Plaza Fields: Carbonate Shoreline Traps in the Williston Basin of North Dakota", North Dakota Geologic Survey Field Study, No. 1, p. 24.

Webster, Mark and Thomas Van Arsdale; 1995, "Geochemical Microseep Survey of the Plaza and Wabek Productive trends, Mountrail and Ward Counties, North Dakota", Seventh International Williston Basin Symposium, Montana Geological Society, Billings, Montana, pp. 57-65.

Fort Berthold Reservation - Map References

Executive Reference Map 334, 1985 edition, Extended Area, Northern Rocky Mountains, Geomap Company.

Executive Reference Map 321, 1983 edition, Southern Williston Basin, Geomap Company.

Indian Land Areas, 1992, United States Department of the Interior-Bureau of Indian Affairs.

Clayton, Lee, et al., 1980, Geological Map of North Dakota Survey.

Darton, N.H., et al., 1951, Geologic Map of South Dakota, United States Geological Survey.

Ross, Clyde P., et al., 1958, Geological Map of Montana, Montana Bureau of Mines.

North DakotaREFERENCES index


Documents

Fort Berthold Reservation - US Department of Energy · PDF filepotential for undiscovered oil and gas reserves on the Fort Berthold Reservation. ... Table 1 summarizes the present