M A R C H 3, 18 4 9

U.S. DEPARTMENT OF THE INTERIOR

Petroleum Geology of the 

State of Washington

By Samuel Y. Johnson, Marilyn E. Tennyson,

William S. Lingley, Jr. and Ben E. Law

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1582

UNITED STATES GOVERNMENT PRINTING OFFICE, WASHINGTON : 1997
For sale by U.S. Geological Survey, Information Services

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Any use of trade, product, or firm names in this publication is for descriptive purposes only and

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Library of Congress Cataloging-in-Publication Data

U.S. DEPARTMENT OF THE INTERIOR

BRUCE BABBITT, Secretary

U.S. GEOLOGICAL SURVEY

Gordon P. Eaton, Director

Petroleum geology of the State of Washington / by Samuel Y. Johnson.

p. cm. — (U.S. Geoloigcal Survey professional paper ; 1582)

Includes bibliographical references.

1. Petroleum—Geology—Washington. I. Johnson, Samuel Y. II. Series. 

TN782.W2P48 1998

553.2′8′09797—dc21 97–23966

CIP
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III

CONTENTS

Abstract ........................................................................................................................... 1

Introduction..................................................................................................................... 1

Acknowledgments........................................................................................................... 2

Regional Geology of Washington................................................................................... 2

Conventional Petroleum Plays ........................................................................................ 4

[Numbers in parentheses are play numbers in Gautier and others, 1995]

Bellingham Basin Gas (401) ................................................................................... 5

Southeastern Puget Lowland Gas (402).................................................................. 8

Puget Lowland Deep Gas (403) .............................................................................. 11

Tofino-Fuca Basin Gas (404).................................................................................. 14

Western Washington Melange (405) ...................................................................... 15

Southwest Washington Miocene Sandstone (406).................................................. 18

Cowlitz-Spencer Gas (407)..................................................................................... 20

Northwestern Columbia Plateau Gas (501)............................................................. 22

Continuous-Type Petroleum Accumulations .................................................................. 28 

[Numbers in parentheses are play numbers in Gautier and others, 1995]

Coal-Bed Gas Plays ................................................................................................ 28

Western Washington—Bellingham Basin (450)............................................. 29

Western Washington—Western Cascade Mountains (451)............................ 29

Western Washington—Southern Puget Lowlands (452) ................................ 31

Basin-Centered Gas Accumulation Plays ............................................................... 31

Williamette–Puget Sound Basin-Centered Gas (412)..................................... 32

Columbia Basin—Basin-Centered Gas Play (503)......................................... 32

Discussion ....................................................................................................................... 33

Conclusions..................................................................................................................... 35

References Cited ............................................................................................................. 35

FIGURES

1. Schematic geologic map of Washington .................................................................................................................. 3

2. Correlation chart showing stratigraphy in petroleum-play areas.............................................................................. 4

 3–4. Maps of Washington showing:

 3. Locations and boundaries of conventional petroleum plays................................................................................ 5

 4. Locations and boundaries of unconventional petroleum plays............................................................................ 6

5–12. Schematic maps showing:

5. Bellingham Basin Gas play (401)........................................................................................................................ 7

6. Southeastern Puget Lowland Gas play (402)....................................................................................................... 10

7. Puget Lowland Deep Gas play (403)................................................................................................................... 12

8. Tofino-Fuca Basin Gas play (404) ....................................................................................................................... 14

9. Western Washington Melange play (405)............................................................................................................ 16

10. Southwest Washington Miocene Sandstone play (406)....................................................................................... 19

11. Washington portion of Cowlitz-Spencer Gas play (407)..................................................................................... 21

12. Northwestern Columbia Plateau Gas play (501) ................................................................................................. 24
IV CONTENTS

TABLES

1. Conventional oil and gas plays in Washington ............................................................................................................. 8

2. Conventional oil and gas in Washington ...................................................................................................................... 9

3. Summary of information on wells with total depth greater than 5,500 ft drilled in the 

Northwestern Columbia Plateau Gas play (501) .......................................................................................................... 26

4. Coal-bed gas in Washington ......................................................................................................................................... 30

5. Gas resources in continuous-type plays (excluding coal-bed gas plays)...................................................................... 34

6. Conventional oil and gas resources .............................................................................................................................. 35
1

 Petroleum Geology of the State of Washington

By Samuel Y. Johnson,1 Marilyn E. Tennyson,2

William S. Lingley, Jr.,3 and Ben E. Law4

ABSTRACT

Washington is a petroleum exploration frontier, but

there is no current petroleum production in the State. Several

possible petroleum systems may be present, hosted by sedimentary rocks deposited in Eocene strike-slip basins and late

Eocene and younger intra-arc, fore-arc, and trench basins.

Eight conventional petroleum plays, three coal-bed gas

plays, and two continuous-type gas plays are delineated in

order to analyze and assess the resource potential. In these

plays, the potential for significant petroleum accumulations

appears greatest in the Columbia Plateau region of eastern

Washington. Potential accumulations in western Washington are smaller but could have local economic significance.

On a regional scale, the absence of high-quality source rocks

is probably the most important factor limiting development

of large accumulations, although development of suitable

reservoirs and an inability to map traps also limits the potential of some plays.

INTRODUCTION

There is no current oil and gas production in Washington. However, the region has been considered a petroleum

frontier since 1900 when the State’s first wildcat well was

drilled in Snohomish County (McFarland, 1983). The State

has experienced several phases of petroleum exploration

during this century, generated largely by the presence of

voluminous deltaic and marine sedimentary rocks, numerous

oil and gas shows and seeps, and the development of the

nearby Mist gas field in northwest Oregon (Niem and others,

1994). As part of an ongoing effort to understand and predict

the petroleum resources of the United States that includes the

recent National Assessment of Oil and Gas Resources

(Gautier and others, 1995), the U.S. Geological Survey, in

cooperation with the Washington Department of Natural

Resources, recently recognized several hypothetical, conventional, and unconventional petroleum plays (Johnson and

Tennyson, 1995). The play areas occupy diverse geologic

settings within the complex geologic framework of the

Pacific Northwest convergent continental margin. The purpose of this report is to more fully describe, illustrate, and reference the geologic setting and petroleum geology of these

plays and to briefly summarize resource estimates of the U.S.

Geological Survey’s 1995 National Petroleum Assessment.

The play number designations used in that assessment are

included in this report.

For eight hypothetical conventional petroleum plays in

the State of Washington, we estimate a mean undiscovered

petroleum resource of 586 BCF (billion ft3) of gas and 19.3

MMB (millions of barrels) of oil. Mean estimated potential

gas-reserve additions from three hypothetical coal-bed gas

plays are 697.3 BCF. The mean undiscovered petroleum

resource estimated for one hypothetical basin-centered gas

play (Columbia Basin—Basin-Centered Gas play, 503) is

12.2 TCF (trillion ft3) of gas and 122.0 MMB of natural gas

liquids. A second basin-centered gas play (Willamette–Puget

Sound Basin-Centered Gas play, 412) is described but not

assessed because of insufficient information. Because petroleum is not currently produced in Washington and there is an

enormous volume of untested sedimentary rock, there are

fewer constraints on petroleum assessments than for developed regions and States. The play identification and analysis

presented in this report provides a geologic database, framework, and references from which further discussion and evaluation of assessments can proceed.

All of the plays we have identified share a common set

of geologic parameters. Most potential source and reservoir

strata are Paleogene siliciclastic rocks. The source rocks

range from carbonaceous shales and siltstones, having 0.5 to

4 percent total organic carbon, to methane-rich coals. Kero1U.S. Geological Survey, Mail Stop 966, Box 25046, Denver Federal

Center, Denver, CO 80225. 2U.S. Geological Survey, Mail Stop 940, Box 25046, Denver Federal

Center, Denver, CO 80225. 3Washington Department of Natural Resources, P.O. Box 47007,

Olympia, WA, 98504–7007. 4U.S. Geological Survey, Mail Stop 971, Box 25046, Denver Federal

Center, Denver, CO 80225.
2 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

gens are mostly type III gas prone, but minor amounts of

type-II oil- and gas-prone material have been observed in

some plays. Numerous gas shows and seeps together with

stripper oil and gas production indicate that effective source

rocks are present. Reservoir rocks are mostly Eocene moderate- to low-porosity feldspathic to sublithic sandstones, typically 20 to 60 ft (6.1 to 18.3 m) thick, with permeabilities

ranging from a few tenths to a few tens of millidarcies. Wireline logs indicate that many wells have penetrated multiple

potential reservoirs and considerable impermeable mudstone; therefore inadequate seal is not considered an impediment to exploration. Thermal maturity typically decreases

westward and eastward from low-grade metamorphic rocks

that crop out along the crest of the Cascade Range and in the

core of the Olympic Mountains (fig. 1). Geothermal gradients along the Puget trough have apparently remained at a

low 15°C/km since the middle Eocene. Potential fault traps

and faulted anticlinal traps are abundant throughout Washington, but structural complexity coupled with various

data-collection problems have stymied most efforts to map

prospect-scale structures with reflection seismology. All

plays described can be considered as frontier exploration. As

of 1995, the average drilling density in Washington was

among the lowest in the United States, with about 1 well per

1,000 mi2 (2,600 km2).

ACKNOWLEDGMENTS

The authors benefited from stimulating discussions with

numerous colleagues, including John Armentrout, Dave

Cox, Bob Deacon, Gordon Dolton, Frank Donis, Lanny Fisk,

Don Gautier, Joel Guttormsen, Peter Hales, Paul Hammond,

John Hanau, Paul Hurst, Tom Ise, Robert Kerr, Terry Mitchell, Peter Mustard, Alan Niem, Wendy Niem, Vito Nuccio,

Steve Palmer, Steve Pappajohn, Dave Pauli, Weldon Rau,

James Schmoker, George Sharp, Parke Snavely, Jr., Dal

Stanley, Richard Stanley, and Timothy Walsh. Katharine

Varnes, T.S. Dyman, and Richard Stanley provided constructive reviews.

REGIONAL GEOLOGY OF 

WASHINGTON

Washington (fig. 1) occupies a complex geologic setting along the western continental margin of North America.

Much of the State is underlain by a diverse pre-Tertiary basement of metamorphic, igneous, and sedimentary rock that

comprise several distinct crustal terranes that generally have

allochthonous and (or) exotic origins (e.g., Tabor, 1994).

Final stages of accretion of these terranes occurred by Late

Cretaceous or Paleogene time, after which the rocks formed

the framework of the Washington continental margin. These

rocks are widely exposed in northeastern Washington and the

North Cascade Range. In southeastern Washington, this

basement complex is covered by the Miocene Columbia

River Basalt Group. In the Cascade Range, pre-Tertiary

rocks plunge south below Tertiary Cascade volcanic rocks

about 28 mi (46 km) southeast of Mount Rainier. The westernmost exposures of pre-Tertiary basement rocks occur in

the San Juan Islands and along the west flank of the Cascade

Range. For the most part, these pre-Tertiary rocks are

thought of as economic basement for petroleum exploration

in Washington.

The pre-Tertiary basement experienced significant

Eocene transtensional and extensional deformation, manifested by detachment faulting and diffuse volcanism in

northeastern Washington (e.g., Harms and Price, 1992), and

strike-slip faulting and formation of rapidly subsiding sedimentary basins in the area of the present Cascade Range and

western Columbia Plateau (Johnson, 1985). Thick sequences

of Paleocene to lower Oligocene fluvial to shallow-marine

sandstone and interbedded mudstone and coal are widespread throughout Washington (fig. 2). For example, Eocene

nonmarine sedimentary rocks exceed 20,000 ft (6,000 m) in

thickness in the northwest-trending Chiwaukum graben

(Gresens and others, 1981; Chumstick basin of Evans, 1994)

on the east flank of the Cascades and in the Bellingham basin

of northwest Washington (Johnson, 1984a). The thick Paleogene sedimentary sequences in these basins may be host to

petroleum. Four hypothetical conventional gas plays (fig. 3),

three hypothetical coal-bed gas plays (fig. 4), and a hypothetical basin-centered gas accumulation play (fig. 4) that

involve these rocks are described below.

The Paleogene sedimentary rocks in the Cascade

Range–Columbia Plateau region are partly covered by

younger volcanic rocks. Cascade arc volcanism began in the

late Eocene and, although discontinuous in both space and

time, has persisted until the present. In contrast, the thick (as

much as 15,000 ft; 4,572 m) Miocene Columbia River Basalt

Group, which covers southeastern Washington, was erupted

from feeder dikes in easternmost Washington and Oregon

and adjacent Idaho in a relatively short period between about

16.5 and 6.5 Ma (Walsh and others, 1987; Reidel and others,

1989).

Pre-Tertiary basement in Washington is bounded on the

west-southwest by a complex structural zone in the Puget

Lowland (Johnson and others, 1996). West of this zone, the

western Puget Lowland, Coast Range, and Olympic Mountains of Washington are mainly underlain by lower and middle Eocene marine basalts of the Crescent Formation, now

widely believed to have formed in a continental-margin

rift-basin setting (Wells and others, 1984; Snavely, 1984,

1987; Babcock and others, 1992). In the late Paleogene and

Neogene, significant local tectonism and block rotation led

to partitioning of southwest Washington into discrete basins

and uplifts (Wells and Coe, 1985). One hypothetical gas play

(fig. 3; Cowlitz-Spencer Gas play, 407) involving middle to

upper Eocene marine to nonmarine rocks overlying the
REGIONAL GEOLOGY OF WASHINGTON 3







































  

















































  



   

































































    

   











 

















 







Peninsula

Olympic 

Coast

Range

Cascade Range

Columbia Plateau

Seattle

0

0 50 km

40 miles

49°

119° 118° 117° 122° 121°

46°

47°

48°

OREGON

CANADA

Pacific

Ocean

North

Cascade

Range

Pre-Tertiary rocks

Selected faults

Coast Range Eocene volcanic rocks

Undifferentiated Tertiary volcanic

and plutonic rocks

Miocene Columbia River Basalt Group

Quaternary deposits

Neogene sedimentary rocks

Paleogene sedimentary and minor 

metasedimentary rocks

Puget

Lowland

1

2

3

4

5

7

BB

SJI

T

G

C

CB

MR

EXPLANATION

6

Figure 1. Schematic geologic map of Washington, modified from Schuster (1992). Numbers refer to locations of stratigraphic columns

shown in figure 2. BB, Bellingham basin; C, Chumstick basin; SJI, San Juan Islands; MR, Mount Rainier; CB, Chehalis basin; G, Grays

Harbor basin; T, Tofino-Fuca basin.

Crescent Formation is located in the Chehalis and Nehalem

basin areas on the eastern flank of the Coast Range block in

southwest Washington. A hypothetical oil play involving

Miocene shallow-marine sandstones (fig. 3; Southwest

Washington Miocene Sandstone play, 406) occurs in the

Grays Harbor basin area on the western flank of the Coast

Range block in southwest Washington.

Throughout the Tertiary, the Coast Range block moved

northward relative to the pre-Tertiary framework to the east

along a complex dextral strike-slip fault zone on its eastern

margin (Johnson, 1984b, 1985; Johnson and others, 1994,

1996). This northward movement has been accommodated

on the north by south-directed thrusting on southern Vancouver Island (Clowes and others, 1987), by folding and faulting

in the northern Coast Range block (Brown and others, 1960;

Snavely, 1987; Snavely and others, 1993), and by subsidence of the Tofino-Fuca basin (Johnson and Yount, 1992).

Eocene to Miocene marine sedimentary rocks of the

Tofino-Fuca basin on the northern Olympic Peninsula are

host to one hypothetical gas play (fig. 3; Tofino-Fuca Basin

Gas play, 404), described below.

Subduction of oceanic crust and overlying marine sediment below the western margin of the Coast Range block has

occurred from the Eocene to the present. Underplated
4 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

?

?

?

?

?

?

?

?

? ? ? ?

?

?

cene

plate

local

Tiger

Mtn Fm

Epoch

0 Ma

10

20

30

40

50

60

Paleocene Eocene Oligocene Miocene

Pleist.

Plio1

Northwest

Columbia 

plateau

Bellingham

 Basin

Central Puget Lowland -

western Cascade Range

Southern

Puget 

Lowland

TofinoFuca

basin

SW Washington

Coast Range

upper structural

plate

Coastal

Washington -

lower

structural

2 3 45 6 7

Swauk

Formation

Chumstick

Teanaway Fm

Roslyn

Formation

Wenatchee 

Columbia

River

Group

Basalt

EllensburgFormation

local nonmarine

Formation

Formation

Chuckanut

Formation

Huntingdon

Formation

Boundary

 Bay

Formation

of Mustard

 and

Rouse (1994)

Raging River

Formation

ss of

Scow Bay

Puget

Group

Tukwila

Fm

Renton

Fm

Northcraft

Fm

Spiketon

Fm

Carbonado Fm

BlakeleyFormation

Ohanapecosh

Formation

local nonmarine deposits Blakely Harbor Formation

Crescent 

Formation

McIntosh

Formation

Cowlitz

Fm

Skookumchuck Fm

Lincoln

Creek

Formation

Astoria

Formation

 local 

nonmarine 

 deposits

Crescent 

Formation

Crescent 

Formation

McIntosh

Formation

Humptulips

Formation

 Lincoln

 Creek

Formation

Astoria

Formation

Montesano

Formation

local marine

 to deltaic

 deposits deposits deposits

Ozette

terrane

 Hoh rock

assemblage

Montesano

Formation

local marine

 deposits

Clallam

Formation

Twin

River

Group

Lyre

Formation

Aldwell

Formation

 nonmarine

and marine

Eastern WA Western Washington

sedimentary rocks varying in character from chaotic melange

to thick, laterally continuous sections, exposed by dramatic

late Miocene and younger uplift, crop out in the Olympic

Mountains and along the adjacent coastline to the west

(Tabor and Cady, 1978; Brandon and Calderwood, 1990;

Snavely and others, 1993; Lingley, 1995). These variably

deformed rocks are host to the hypothetical Western Washington Melange play (405) and may be sources for petroleum

in the Tofino-Fuca Basin Gas play (404) and the Southwest

Washington Miocene Sandstone play (406) (fig. 3).

CONVENTIONAL PETROLEUM PLAYS

For the U.S. Geological Survey 1995 National Assessment of United States Oil and Gas Resources (Gautier and

others, 1995), a conventional petroleum play was defined as

“a set of known or postulated oil and (or) gas accumulations

sharing similar geologic, geographic, and temporal

properties such as source rock, migration pathway, timing,

trapping mechanism, and hydrocarbon type” (U.S. Geological Survey National Oil and Gas Resource Assessment

Team, 1995, p. 6). Play attributes are the geologic characteristics that describe principal properties of and necessary conditions for the occurrence of oil and (or) gas accumulations

of a minimum size. Minimum accumulation sizes estimated

and evaluated quantitatively for the National Assessment are

1 MMBO (million barrels of oil) and 6 BCFG (billion cubic

feet of gas). Assessments of undiscovered fields smaller than

these minimum accumulations were made separately. For

each conventional play defined, there is a discussion of

source rocks, reservoir, timing and migration of hydrocarbons, traps and seals, exploration status, and evaluation of

resource potential. The exploration status describes historical

drilling activity and known industry interest as of 1995.

Evaluation of conventional resource potential is based

on probabilities of play attributes, including charge, reservoir, and trap. Charge describes the occurrence of conditions

Figure 2. Correlation chart showing stratigraphy in petroleum-play areas. Shaded areas show intervals of nondeposition and (or) erosion.

References for columns include: (1) Tabor and others (1982, 1984), Taylor and others (1988), Evans and Johnson (1989); (2) Johnson

(1984a), Mustard and Rouse (1994); (3) Frizzell and others (1983), Frizzell and Easterbrook (1983), Johnson and others (1994); (4) Snavely

and others (1958), Rau and others (1983); (5) Rau and Armentrout (1983), Rau (1986), Moothart (1992); (6) Rau (1973), Palmer and Lingley

(1989), Snavely and others (1993); (7) Snavely and Lander (1983).
CONVENTIONAL PETROLEUM PLAYS 5

Bellingham Basin

Gas play (401)

Tofino-Fuca Basin

Gas play (404)

Northwestern Columbia

Plateau Gas play (501)

Puget Lowland 

Deep Gas play Western (403) Washington

Melange 

play (405)

Southeastern Puget

Lowland Gas play (402)

Southwest 

Washington

Miocene

Sandstone

 play (406)

 CowlitzSpencer Gas

play (407) - 

Washington

portion only

 

49°

117°

47°

123° 120°

100 km

50 miles

of hydrocarbon generation and migration adequate to cause

an accumulation of the minimum size. Charge includes consideration of the existence of source rocks that contain sufficient organic matter of the appropriate composition,

appropriate temperature and duration of heating to generate

and expel sufficient quantities of oil and (or) gas, and timing

of expulsion of oil and gas from source rocks appropriate for

filling available traps. Reservoir considers the occurrence of

reservoir rocks of sufficient quantity and quality to permit

the containment of oil and (or) gas in volumes sufficient for

an accumulation of the minimum size. Trap considers the

occurrence of those structures, pinch-outs, permeability

changes, and similar features necessary for the entrapment of

oil and (or) gas in at least one accumulation of the minimum

size. Included in this attribute are seals sufficient for entrapping hydrocarbons and capable of holding oil and gas accumulations during appropriate ranges of geologic time. The

play probability represents the product of the probabilities

(expressed as a decimal fraction) of the three play attributes

(charge, reservoir, and trap) and represents the chance that

oil or natural gas accumulations of the minimum size exist

within the particular play. Only plays with play probabilities

of greater than 0.1 were quantitatively evaluated.

After first determining an acceptable (≥ 0.1) play probability, estimates were made of the minimum, median, and

maximum number of undiscovered accumulations in the

area of each play. These estimates were based on the size of

the play area, our interpretation of the geology of the play,

and analogs from other fields, plays, and provinces. We also

estimated the size distribution of accumulations in the play.

These estimates are based on either a geologically similar

analog or on equations for in-place hydrocarbons (e.g., Dolton and others, 1987) that involve several different parameters and assumed values that are listed for each play.

BELLINGHAM BASIN GAS PLAY (401)

Introduction.—This hypothetical conventional gas play

is located in the Bellingham basin of the northern Puget

Lowland of Washington (figs. 1, 3, 5). The Bellingham basin

is a lowland that forms the southern part of a larger topographic depression that extends northwest into Canada. Initial subsidence in the Georgia basin is recorded by marine

and lesser nonmarine conglomerate, sandstone, siltstone,

and shale of the Upper Cretaceous Nanaimo Group (Mustard, 1994). A second phase of basin subsidence is recorded

by nonmarine sandstone, mudstone, and coal of the Paleocene(?) to Eocene Chuckanut and the upper Eocene Huntingdon Formations (fig. 2) (Johnson, 1984a; Mustard and

Rouse, 1994), which rests unconformably on the Nanaimo

Group or on pre-Tertiary crystalline or metamorphic basement. The modern Georgia and Bellingham basins formed in

the Neogene following a significant middle Tertiary contractional deformation event (Johnson, 1984a; England and

Calon, 1991). The modern Bellingham basin contains a dominantly continental sedimentary sequence of Miocene to

Quaternary sediments, including the Boundary Bay formation of Mustard and Rouse (1994), Pleistocene glacial and

interglacial sediments, and fluvial-deltaic deposits of the

Fraser and Nooksack rivers.

Figure 3. Map of Washington showing locations and boundaries of conventioal petroleum plays.
6 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

Western Washington -

Bellingham Basin play (450)

49°

117°

47°

123° 120°

100 km

50 miles

Western Washington -

Western Cascade

Mountains play (451) Western Washington - 

Southern Puget Lowlands

play (452)

Columbia Basin - 

Basin-Centered Gas

 play (503)

The Bellingham Basin Gas play (401) is bounded to the

south by uplifted, folded strata of the Eocene Chuckanut Formation and to the east by an uplift of pre-Tertiary basement

rocks on Sumas Mountain. To the southwest, the play

extends into the Strait of Georgia and is bounded by pre-Tertiary rocks of the San Juan Islands. To the north (both

onshore and offshore), the play extends into Canada. Only

the portion of the play in the United States is evaluated in this

report.

The petroleum exploration premise for this play is that

gas has been generated from organic-rich nonmarine rocks of

the Eocene Chuckanut Formation, or less likely from Upper

Cretaceous marine strata of the Nanaimo Group, and

migrated into reservoirs in Chuckanut fluvial sandstone bodies. Structural traps for reservoirs might include large folds

or smaller fault blocks, and interbedded fine-grained rocks

would provide seals.

Reservoirs.—Potential reservoirs in the Bellingham

Basin Gas play (401) are the lower and middle Eocene fluvial

and distributary channel sandstone bodies of the Chuckanut

Formation (Johnson, 1982, 1984c). Sandstone bodies range

in thickness to as much as 200 ft (60 m), are commonly conglomeratic, and typically include thin (< 1 ft; 30 cm) discontinuous lenses of mudstone. Sandstone bodies are bounded

by fine-grained strata (mudstone to very fine grained sandstone) of fluvial overbank origin. In samples from the Birch

Bay No. 1 well, porosity decreased with depth from 26

percent at 1,000 ft (305 m) to less than 10 percent at 6,000 ft

(1,829 m) (Hurst, 1991). Permeable reservoir rocks may be

present below about 4,500 ft (1,372 m) locally, but not across

the entire play. Measured permeabilities range from less than

1 mD to 58 mD (P.D. Hurst, Canadian Hunter Exploration,

Ltd., written commun., 1992). Sandstones are arkosic arenites (Johnson, 1982, 1984a) and the decreases in reservoir

qualities with depth are attributed to compaction and degradation of feldspar and lithic fragments. Porosity values from

20 outcrop samples of Chuckanut Formation sandstone range

from 0.8 to 12.7 percent (mean = 7.01 percent); permeability

values for the same sample suite ranges from 0.002 to 2.89

mD (mean = 0.326 mD) (J.M. Armentrout, Mobil Oil Company, written commun., 1982).

Source rocks.—The character of source rocks in the

Upper Cretaceous Nanaimo Group is considered poor (Bustin, 1990; Bustin and England, 1990; Mustard, 1994). Nonmarine carbonaceous shale and coal beds of the lower

Tertiary Chuckanut and Huntingdon Formations have moderate gas generative potential although these rocks are submature in many parts of the basin. In the Birch Bay No. 1

well (addendum to McFarland, 1983), for example, coals and

shales above a depth of 6,000 ft (1,829 m) are reported to

have both type-III and -IIB kerogens (Lingley and von der

Dick, 1991), and several beds in this interval contain more

than 6 percent total organic carbon (Hurst, 1991). Rocks

below 6,000 ft depth (1,829 m) in the Birch Bay No. 1 well

Figure 4. Map of Washington showing locations and boundaries of unconventional petroleum plays.
CONVENTIONAL PETROLEUM PLAYS 7































   



     





6,042'

5,576'

10,892'

5,202'

7,977'

7,858'

7,365'

9,126'

6,229'

6,008'

5,458'

6,180'

Ro = 0.53, 7,600'

Ro = 0.55, 4,000'

Ro = 0.45, 5,275'

Ro ~0.55, 4,200

Ro = 0.55, 1,709'

Ro = 0.74

UNITED STATES

Strait of Georgia

49°



Pre-Tertiary rocks

Chuckanut Formation

Quaternary deposits

Wells with total

depth > 1,500' (feet) 

Bellingham

basin

Bellingham

Fold axis

Fault

Play boundary

5,000 acres

10 km

14,789' CANADA

Gas seep

Sumas

Mountain

123°

San Juan Islands

EXPLANATION

.

.

. .

.

.

.

.

.

. 

have type-III kerogens and low TOC (total organic carbon)

values.

Vitrinite reflectance values of about 0.5 to 0.6 percent

have been reported from depths of 1,700 to 7,600 ft (518 to

2,316 m) in the basin (fig. 5). Reflectance in Chuckanut Formation outcrops on the south flank of the Bellingham basin

is 0.74 percent (fig. 5) (Walsh and Lingley, 1991).

Gases escaping from old well casings (about 5 mi

northwest of Bellingham; fig. 5) have a high methane and

nitrogen content (McFarland, 1983) and a mainly thermogenic origin (Hurst, 1991). One abandoned well is presently venting about 10 MCFGPD (thousand cubic feet of gas

per day) because it cannot be effectively plugged.

Timing and migration of hydrocarbons.—Maximum

burial occurred in the late middle to early late Eocene, prior

to late Eocene folding and associated uplift (Johnson,

1984a). Thus, the large anticlines in the basin that are potential hydrocarbon traps formed during and slightly later than

peak hydrocarbon generation and migration.

Traps and seals.—Large anticlines that are probably

subsurface extensions of folds exposed on the southeastern

basin flank (fig. 5) form the most viable hydrocarbon traps.

Hurst (1991) calculated 5,000 acres (20.2 km2) of structural

closure on the anticline penetrated by the Birch Bay No. 1

well. Surface trends suggest there should be three or four

comparable anticlines east of the Birch Bay structure in the

basin subsurface. The basin is also cut by numerous

high-angle faults (Johnson, 1982; Mustard, 1994), and small

structural traps adjacent to these faults are also possible.

Interbedded fine-grained nonmarine rocks are the likely

seals; the lenticularity of these units is responsible for some

uncertainty in trap viability. 

Exploration status.—Approximately 19 wells with

total depth greater than 1,500 ft (457 m) have been drilled in

the United States part of this play since 1914. Of these, only

seven wells had total depth greater than 5,000 ft (1,524 m),

and 9,126 ft (2,782 m) is the deepest penetration. In Canada,

approximately eight additional wells deeper than 5,000 ft

(1,524 m) have been drilled, and maximum penetration is

14,789 ft (4,508 m). Most recently (between 1988 and 1991),

three wells with total depths ranging from 4,422 to 9,126 ft

(1,348 to 2,782 m) were drilled in the United States.

Non-commercial gas shows were reported from several

sandstone bodies and from coal beds in these wells. Future

Figure 5. Schematic map showing Bellingham Basin Gas play (401). Petroleum wells in the United States are listed

in McFarland (1983) or in addendum to McFarland available through the Washington Division of Geology and Earth

Resources. Petroleum wells in Canada are listed in Mustard and Rouse (1994). Thermal maturity data (Ro = mean

vitrinite reflectance) is from Hurst (1991, and written commun. 1992) and Walsh and Lingley (1991); values are from

surface samples unless footage from adjacent petroleum well is listed. Geology greatly simplified after Johnson

(1982) and Brandon and others (1988).
8 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

exploration in the Bellingham basin may concentrate on a

potential coal-bed methane resource (see below) or on development of gas storage facilities similar to that currently operating in the Chehalis basin (Wurden and Ford, 1976).

Pipelines bringing gas to the Pacific Northwest urban corridor from Alberta, Canada, extend through the Bellingham

basin, so local infrastructure is highly favorable for development of a gas resource. 

Evaluation of resource potential.—This play has been

poorly to moderately explored. There is only minor information about rocks at depths greater than 5,000 ft (1,524 m).

Based on existing knowledge, the best objectives for a conventional gas play are at depths of less than 5,000 ft (1,524

m), where source and reservoir rocks are each of marginal

quality. For the recent U.S. Geological Survey 1995 National

Petroleum Assessment (Gautier and others, 1995), Johnson

and Tennyson (1995) assessed the probability of suitable

charge, reservoir rock, and trap at 0.5, 0.5, and 0.8, respectively, yielding an overall play probability of 0.2 for a gas

accumulation larger than 6 BCF (table 1). The median number of undiscovered gas accumulations larger than 6 BCF

was estimated to be 5. The size of the largest accumulation

expected at a 5 percent probability was estimated to be 155

BCF using the following simulation parameters and the

methodology of Dolton and others (1987): Area of closure =

5,000 acres (20.2 km2); depth = 10,000 ft (3,048 m); reservoir thickness = 75 ft (23 m); effective porosity = 10 percent;

trap fill = 0.8; recovery factor = 0.5; water saturation = 0.27.

The mean undiscovered resource in the Bellingham Basin

Gas play was estimated to be 30 BCF (table 2).

SOUTHEASTERN PUGET LOWLAND 

GAS PLAY (402)

Introduction.—This hypothetical conventional gas play

is located in the southeastern Puget Lowland and the western

flank of the Cascade Range of Washington (figs. 1, 3, 6).

This region experienced transtensional deformation and

rapid subsidence during the Eocene when coal-bearing rocks

of the Puget Group and correlative strata were deposited

(Johnson, 1985). From the Oligocene to the Holocene,

transpressive deformation of basinal strata resulted in numerous faults and broad to tight folds (Gard, 1968; Vine, 1969;

Stanley and others, 1996). This structural complexity has

made precise correlation of coal-beds and other stratigraphic

markers across the play area difficult. 

The play extends north from the Morton area to the

Tiger Mountain area and is about 18 to 30 mi (30 to 55 km)

wide. The play is bounded to the east by either uplifts of

pre-Tertiary rocks, or by a depositional contact where

Eocene sedimentary rocks dip below a thick cover of Eocene

and younger volcanic rocks. To the northwest, the play is

bounded by the approximate facies contact between upper

middle to upper Eocene nonmarine rocks (potential reservoir

rocks within the play) and marine rocks (west of the play). To

the west, the play boundary approximates the location of a

poorly defined, north-trending boundary that separates a

thicker, mainly nonmarine, more deformed, upper middle to

upper Eocene sequence to the east from a thinner, mixed

marine-nonmarine, less deformed, upper middle to upper

Eocene sequence to the west. 

The exploration premise is that gas has been generated

from Eocene nonmarine carbonaceous shale and coal or

marine mudstone and has migrated into reservoirs in Eocene

fluvial and shallow marine sandstones of the Puget Group.

Structural traps for reservoirs might include anticlines and

fault blocks; interbedded and overlying fine-grained sedimentary rocks and (or) volcanic rocks would provide seals. 

Reservoirs.—Middle to upper Eocene fluvial- and distributary-channel sandstone bodies of the undifferentiated

Puget Group, the Tiger Mountain Formation, the Renton Formation, the Carbonado Formation, and the Spiketon Formation (fig. 2) are the target reservoirs for this gas play. These

Table 1. Conventional oil and gas plays in Washington.

[Summary and comparison of estimated probabilities for charge, reservoir, and trap; overall play probability; median number of petroleum accumulations

larger than 1 MMBO (oil) or 6 BCF (gas); and size of the largest accumulation expected at a 0.05 probability]

Probability Median number of Largest

Play name and number Charge Reservoir Trap Overall accumulations accumulation

Bellingham Basin Gas (401) 0.5 0.5 0.8 0.2 5 155 BCF

Southeastern Puget Lowland Gas (402) 0.9 1.0 0.75 0.68 10 125 BCF

Puget Lowland Deep Gas (403) 0.75 0.2 0.75 0.11 5 125 BCF

Tofino-Fuca Basin Gas (404) 1.0 0.5 0.4 0.2 7 30 BCF

Western Washington Melange (405) 1.0 1.0 0.5 0.5 10 13 MMBO

Southwest Washington Miocene Sandstone (406) 1.0 1.0 0.15 0.15 2 14 MMBO

Cowlitz-Spencer Gas (407) 1.0 1.0 1.0 1.0 10* 150 BCF

Northwestern Columbia Plateau Gas (501) 1.0 0.6 1.0 0.6 10 1,000 BCF

*The median number of accumulations shown is for the entire play area, which includes parts of southwest Washington and northwest

Oregon. We estimate a median of four undiscovered gas accumulations for the Washington portion of the play (see text for discussion).
CONVENTIONAL PETROLEUM PLAYS 9

sandstone bodies range in thickness from 10 ft (3 m) to more

than 200 ft (61 m) and are bounded by fine-grained

flood-plain deposits (Vine, 1969; Johnson and Stanley,

1995). Sandstone reservoirs might be present at depths of as

much as 10,000 ft (3,048 m).

Sandstone is typically arkosic (e.g., Buckovic, 1978;

Frizzell, 1978; Johnson and Stanley, 1995). Petrographic

and meager porosity-permeability data suggest that sandstones are “tight” in the eastern part of the play where rocks

have been subjected to higher geothermal gradients; loss of

porosity reflects compaction and alteration of lithic fragments and feldspar. Porosity and permeability increase in the

western part of the play. Near Black Diamond, porosities

from two cores (depth range of 1,840 to 6,000 ft (561 to

1,829 m)) range from 6 to 37 percent and permeability

ranges from 1 mD to 2 darcies (unpub. industry data). 

Exploration drilling has indicated locally high reservoir

pressures (possibly artesian); the “Flaming Geyser” well

(total depth of 1,411 ft; 430 m), drilled as a coal test in 1911

in the Green River district, was abandoned because of gas

(flares as high as 30 ft; 9.1 m) and water flows. This well

continues to flow traces of gas.

Source rocks.—There are two possible source rocks for

this hypothetical gas play. Organic matter for both potential

source rocks is mostly type III and gas prone, although Lingley and von der Dick (1991) also report type-II organic matter from these rocks: Source 1—Upper middle to upper

Eocene carbonaceous shale and coal of the undifferentiated

Puget Group, and the Tiger Mountain, Renton, Carbonado,

and Spiketon Formations (fig. 2). Coal desorbtion data indicate that coals have generated significant gas (Walsh and

Lingley, 1991). Surface outcrops and samples from shallow

wells (< 2,000 ft (610 m)) have mean vitrinite reflectance

ranging from about 0.35 to 2.0 percent (Walsh and Lingley,

1991; Johnson and Stanley, 1995, unpub. U.S. Geological

Survey data). Thermal maturity generally increases to the

east and in close proximity to intrusives (Walsh and Lingley,

1991; Esposito and Whitney, 1995; Johnson and Stanley,

1995). Source 2—Lower to middle Eocene marine mudstones. These rocks are exposed only on Tiger Mountain,

east of Seattle, where they are assigned to the Raging River

Formation (Vine, 1969; Johnson and O’Connor, 1994) , but

they are inferred to underlie a significant portion of the

southeastern Puget Lowland (Stanley and others, 1992,

1994; Johnson and Stanley, 1995). The source-rock properties of the Raging River Formation are described above. 

Timing and migration of hydrocarbons.—As with the

Puget Lowland Deep Gas play (403; see below), maximum

burial occurred in the late Eocene to Oligocene, prior to Oligocene and Neogene folding and associated uplift. Much of

this folding and uplift was controlled by movement on local

faults or fault networks and is not associated with a regional

contractional event (Johnson and others, 1994; Stanley and

others, 1996). Regional heat flow became elevated in the

Oligocene and Miocene with the onset of Cascade Range

volcanism in the Oligocene and early Miocene. Thus, maximum heating and thermal maturation may locally postdate

maximum burial. Because of ongoing deformation, structural traps in the play area have probably formed before, during, and after peak hydrocarbon generation. 

Walsh and Lingley (1991) used a variety of maturation

data to show that the central Puget trough (west part of play)

has had unusually low geothermal gradients since the middle

Eocene. They note that gradients increase eastward to the

Cascade crest, defining a fairway of conditions favoring

peak gas generation at moderate depths that trends north

along the western foothills of the Cascade Range.

Traps.—Anticlines and fault blocks such as those

that occur in the Morton or Carbon River anticlines or

near Black Diamond (Gard, 1968; Vine, 1969; Johnson

and Stanley, 1995; Stanley and others, 1996) form the

most viable hydrocarbon traps. Interbedded fine-grained

Table 2. Conventional oil and gas in Washington.

[Estimates of undiscovered technically recoverable resources by play (Johnson and Tennyson, 1995; Tennyson, 1995). Fractile values (F95, F5) are not additive. F95 represents a 19 in 20 chance and F5 represents a 1 in 20 chance of the occurrence of at least the amount tabulated]

Crude oil (million barrels) Gas (billion cubic feet)

Play name and number F95 F5 Mean F95 F5 Mean

Bellingham Basin Gas (401) 0.00 0.00 0.00 0.00 229.20 30.00

Southeastern Puget Lowland Gas (402) 0.00 0.00 0.00 0.00 615.20 163.20

Puget Lowland Deep Gas (403) 0.00 0.00 0.00 0.00 139.00 26.80

Tofino-Fuca Basin Gas (404) 0.00 0.00 0.00 0.00 108.60 15.00

Western Washington Melange (405) 0.00 89.20 18.20 0.00 0.00 0.00

Southwest Washington Miocene Sandstone (406) 0.00 7.60 1.10 0.00 0.00 0.00

Cowlitz-Spencer Gas (407) 0.00 0.00 0.00 115.89*

Northwestern Columbia Plateau Gas (501) 0.00 0.00 0.00 0.00 1,119.70 235.10

TOTAL 19.30 585.99

*The Cowlitz-Spencer Gas play (407) includes parts of Oregon and Washington; however, only the estimated resource for the Washington portion of the play is shown on this table. The resource was allocated between the States based on our evaluation of the geologic

framework and petroleum geology.
10 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

Quaternary





Sedimentary 

volcanic

deposits

rocks, mainly

Eocene

Tertiary

2,000 10 km

Play boundary

acres

Wells with total

depth > 3,000' (feet)

 











































  





















































































































   











   

M

Cascade Range

Ro = 1.18 to 4.01

0 to 1,600 ft

6,800'

Ro = 0.60, 6,800'

7,270

BD

= 6 to 19%,

2,000 to 6,000'

Ro

max TD = 6,023'

n = 7,

Ro < 37%

5,069

Ro = 0.64, 4,890'

oil shows

12,920'

Ro = 1.24, 12,900'

, oil show

7,562'

Ro = 0.81, 7,170'

8,271'

Ro = 0.61

Ro = 0.60,

4,080'

Ro = 0.40 to 1.69

0 to 1,800'

47°

122°30'

Ro = 0.70 - 1.20, 0'

Ro = 0.66, 3,980'

Ro = 0.42 to 1.10

0.76, 9,220'

Ro = 0.59, 1,240'

9,291'

5,721'

rocks

Fold axis

Fault

PS

TM

2,551'

S

W

T

CR

EXPLANATION
CONVENTIONAL PETROLEUM PLAYS 11

rocks (fluvial overbank deposits) and Oligocene and

younger volcanic rocks provide possible seals. Traps

might be present at depths ranging from the near surface

to 10,000 ft (3,050 m). The area is structurally complex

and includes many faults and folds that may have been

active from the Neogene to the Quaternary and may

have compromised the integrity of traps and seals.

Exploration status.—Approximately 30 wells with

total depths greater than 3,000 ft (914 m) have been drilled

in the play area, including one well with a total depth of

12,920 ft, (3,938 m) drilled in 1963, and 10 with total depths

between 5,000 and 10,000 ft (1,524 and 3,048 m) (McFarland, 1982). In the early 1980’s, AMOCO drilled 11 stratigraphic test wells in the area of this play, with a maximum

total depth of 2,780 ft (847 m). Three other wells with depths

ranging from 4,872 ft (1,485 m) to 8,271 ft (2,521 m) were

drilled between 1983 and 1989 (addendum to McFarland,

1983). 

Evaluation of resource potential.—The Southeastern

Puget Lowland Gas play (402) has been poorly explored (fig.

6). In the most favorable exploration scenario, gas generated

from source rocks in the eastern, more thermally mature part

of this play, has migrated westward to the best reservoir

rocks in the western part of the play. The history of Neogene

tectonism and uplift may limit both longer distance migration and the integrity of traps. The structural complexity

along with highly variable surface geology makes acquisition and interpretation of seismic reflection profiles difficult.

If traps for gas are present, these traps are probably small

(6–20 BCF). 

For the recent U.S. Geological Survey 1995 National

Petroleum Assessment (Gautier and others, 1995), Johnson

and Tennyson (1995) assessed the probability of suitable

charge, reservoir rock, and trap at 0.9, 1.0, and 0.75, respectively, yielding an overall probability of 0.68 for a gas accumulation larger than 6 BCF (table 1). The median number of

undiscovered gas accumulations larger than 6 BCF was estimated to be 10. The size of the largest accumulation

expected at a 5 percent probability was estimated to be 125

BCF using the following simulation parameters and the

methodology of Dolton and others (1987): Area of closure =

2,000 acres (8.1 km2); depth = 10,000 ft (3,048 m); reservoir

thickness = 75 ft (23 m); effective porosity = 10 percent; trap

fill = 0.8; recovery factor = 0.5; water saturation = 0.27. The

mean undiscovered resource in the Southeastern Puget Lowland gas play was estimated to be 163.2 BCF (table 2).

PUGET LOWLAND DEEP GAS PLAY (403)

Introduction.—This hypothetical conventional gas play

is located in the southeastern Puget Lowland and the western

flank of the Cascade Range of Washington (figs. 1, 3, 7). The

play extends north from near the town of Morton to northern

Whidbey Island and is about 25 to 30 mi (40 to 50 km) wide.

A progradational sequence of Eocene deep marine to nonmarine sedimentary rocks, including the Raging River Formation, the sandstone of Scow Bay, and the lower Puget Group

(fig. 2), forms the potential petroleum system of this play

(Ise, 1985). The play is bounded to the east and north by

uplifts of pre-Tertiary rocks, or by a depositional contact

where Eocene sedimentary rocks dip below a thick cover of

Eocene and younger volcanic rocks (Washington Public

Power Supply, 1981; Walsh and others, 1987; Whetten and

others, 1988). Structural uplifts cored by Eocene marine

basalt of the Crescent Formation bound the play to the northwest. The southwest boundary of the play lies a few kilometers west of an early to early middle Eocene facies change

where thick sequences of marine strata to the east are

inferred to interfinger with marine basalt to the west

(Johnson and Stanley, 1995). Along the axis of the Puget

Lowland, the Eocene section is overlain by heterogeneous

Oligocene to Quaternary strata of variable thickness. Quaternary depocenters include the Seattle, Everett, and Tacoma

basins. The play area experienced transtensional deformation and rapid subsidence during the Eocene (Johnson,

1985). From the Oligocene to the present, contractional and

transpressive deformation of basinal strata resulted in

numerous faults and broad to tight folds (Gard, 1968; Vine,

1969; Johnson and others, 1994; Stanley and others, 1996). 

The exploration premise of this play is that gas has been

generated from deeply buried Eocene marine mudstone and

has migrated into overlying interbedded shelf or deep-water

sandstone reservoirs. Structural traps for reservoirs might

include anticlines and fault blocks, and interbedded

fine-grained rocks and (or) volcanic rocks would provide

seals. 

Reservoirs.—Potential reservoirs for the Puget Lowland Deep Gas play (403) include lower to middle

Eocene marine sandstone of the Raging River Formation

(Johnson and O’Connor, 1994) and unnamed deeply buried correlative units. Sandstone in the Raging River Formation is lithic rich, and samples from outcrops and one

core have minimal porosity or permeability (Johnson and

O’Connor, 1994). Outcrop and subsurface data are

Figure 6 (facing page). Schematic map showing Southeastern

Puget Lowland Gas play (402). Petroleum wells are listed in McFarland (1983) or in addendum to McFarland available through the

Washington Division of Geology and Earth Resources. Thermal

maturity data (Ro = mean vitrinite reflectance) is from Walsh and

Lingley (1991), Johnson and O’Connor (1994), Johnson and Stanley (1995), or the data are previously unpublished; values are from

surface samples unless footage from adjacent petroleum well is listed. BD, Black Diamond; CR, Carbon River anticline; M, Morton;

PS, Puget Sound; S, Seattle; T, Tacoma; TM, Tiger Mountain; W,

Wilkeson. Geology simplified after Walsh and others (1987) and

Washington Public Power Supply (1991).
12 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

































































 





 









Quaternary

Sedimentary

volcanic

Pre-Tertiary

deposits

rocks, mainly Eocene

rocks

rocks

Tertiary

2,000 20 km

Play boundary

acres

Wells with total

depth > 3,000'(feet)











     

SJF

PS









WI

M

T

S

E

TM

SB

9,675'

Ro = 0.60, 9,600'

11,002

8,648'

6,693'

EB 5,959'

7,417' 5,408'

Ro = 0.45, 7,250'

7,353'

0.76, 9,220'

Ro = 0.59, 1,240'

9,291'

6,800'

Ro = 0.60, 6,800'

Ro = 1.18 to 4.01,

0' to 1,600'

7,270'

BD

TB

Cascade Range

MR

7,562'

Ro = 0.81, 7,170'

12,920'

Ro = 1.24, 12,900'

max TD = 6,023'

n = 7

8,271

47°

48°

123°

Ro = 0.40 to 1.69

0 to 1,800'

Ro = 0.24 to 0.61

200 to 3,100'

5,721'

Ro = 0.40 to 0.60

1,600 to 4,100'

Ro = 0.66, 3,980'

5,069

Ro = 0.64, 4,890'

Ro = 0.70 - 1.20

CR

EXPLANATION












CONVENTIONAL PETROLEUM PLAYS 13

insufficient to evaluate sandstone thickness and geometry. There are no available data on correlative deeply buried units in the play area; however, based on regional

paleogeographic patterns (e.g., Buckovic, 1978; Johnson,

1985; Johnson and Stanley, 1995), sandstone of both

arkosic and lithic composition should be present in these

units.

Source rocks.—Source rocks are inferred to be lower to

middle Eocene marine mudstones (Johnson and O’Connor,

1994). These rocks are exposed only on Tiger Mountain, east

of Seattle, where they are assigned to the Raging River Formation, but they are inferred to underlie a significant portion

of the Puget Lowland (Johnson and Stanley, 1995). At Tiger

Mountain, mean vitrinite reflectance of surface samples varies from 1.18 to 4.01 percent, and is 1.96 percent at 1,633 ft

(498 m) in one well (Johnson and O’Connor, 1994). Tmax

(the temperature at which maximum yield of hydrocarbons

occurs during Rock-Eval pyrolysis of organic matter) ranges

from about 509°C to 542°C in samples from outcrop and the

shallow subsurface—too high for reliable evaluation of

petroleum source rocks (Peters, 1986). Total organic carbon

in these samples is as high as 0.8 to 1.1 percent. This remnant

organic mater is an indication that rocks may have once been

more organic rich and capable of generating hydrocarbons

(Daly and Edman, 1987). 

Timing and migration of hydrocarbons.—Maximum

burial in most of the play occurred during the late Eocene to

early Oligocene, prior to Oligocene and Miocene contractional and transpressive deformation, folding, and associated

uplift. Regional heat flow became elevated in the Oligocene

and Miocene with the onset of Cascades volcanism in the

Oligocene and early Miocene. Thus, maximum heating and

thermal maturation may postdate maximum burial. Structural traps in the play area probably formed during and

slightly later than peak hydrocarbon generation (Walsh and

Lingley, 1991). 

Strata in the deeper parts of the Seattle and Everett

basins (fig. 7) are presently at maximum burial (Johnson and

others, 1994, 1996) and probable maximum thermal

maturation. Structural traps within and on the margins of

these basins thus predate peak hydrocarbon generation from

basinal strata. 

Traps and seals.—Anticlines and fault blocks form the

most viable hydrocarbon traps. Anticlines include large

structures such as the Kingston arch on the northern flank of

the Seattle basin (Johnson and others, 1994) and complex,

smaller scale structures such as those in the Morton, Carbon

River, and Black Diamond areas in the western Cascade

Range foothills (Gard, 1968; Vine, 1969; Johnson and Stanley, 1995; Stanley and others, 1996). Interbedded and overlying fine-grained Eocene rocks (marine and nonmarine) and

Oligocene and younger volcanic rocks provide possible

seals. Traps might be present at depths ranging from 10,000

to 25,000 ft (3,048 to 7,620 m). The area includes many

faults and folds that have been active through the Neogene

and Quaternary and may have compromised the integrity of

reservoirs and traps.

Exploration status.—Only two wells have penetrated

the top of the prospective section (10,000 ft; 3,048 m) in this

play. Approximately 40 wells with total depths greater than

3,000 ft (914 m) have been drilled in the play area, and 17

have total depths between 5,000 and 10,000 ft (1,524 and

3,048 m) (McFarland, 1983). In the last 10 years, activity in

the play area has emphasized a possible shallow coal-bed

methane resource (Choate and others, 1984; Pappajohn and

Mitchell, 1991; Walsh and Lingley, 1991; Johnson and Tennyson, 1995). The U.S. Department of Energy recently supported acquisition of a large seismic database for the purpose

of delineating a large conductive anomaly in the Cascade

foothills that probably represents the Eocene marine rocks

that are the inferred source and reservoir for this play (Stanley and others, 1992; Krehbiel, 1993; Zihlman, 1993;

Johnson and Stanley, 1995). 

Evaluation of resource potential.—The viability of the

Puget Lowland Deep Gas play (403) is dependent on the

hypothesis that (1) marine source rocks underlie a large part

of the Puget Lowland, (2) an adequate thickness of reservoir

rocks may be present, (3) potential reservoir sandstone has a

favorable diagenetic history, (4) there has been a favorable

migration history, and (5) traps and seals have retained their

viability in a structurally complex setting. Given the uncertainties associated with each factor, this play is considered

high risk. For the recent U.S. Geological Survey 1995

National Petroleum Assessment (Gautier and others, 1995),

Johnson and Tennyson (1995) assessed the probability of

suitable charge, reservoir, and trap at 0.75, 0.2, and 0.75,

respectively, yielding an overall play probability of 0.11 for

a gas accumulation larger than 6 BCF (table 1). The median

number of undiscovered gas accumulations larger than 6

BCF was estimated to be 5. The size of the largest accumulation expected at a 5 percent probability was estimated to be

125 BCF using the following simulation parameters and the

methodology of Dolton and others (1987): Area of closure =

Figure 7 (facing page). Schematic map showing Puget Lowland

Deep Gas play (403). Petroleum wells are listed in McFarland

(1983) or in addendum to McFarland available through the Washington Division of Geology and Earth Resources. Thermal maturity

data (Ro = mean vitrinite reflectance) is from Walsh and Lingley

(1991), Johnson and O’Connor (1994), Johnson and Stanley

(1995), or was previously unpublished; values are from surface

samples unless footage from adjacent petroleum well is listed. BD,

Black Diamond; CR, Carbon River area; E, Everett; EB, Everett basin; M, Morton; MR, Mount Rainier; PS, Puget Sound; S, Seattle;

SB, Seattle basin; SJF, Strait of Juan de Fuca; T, Tacoma; TB,

Tacoma basin; TM, Tiger Mountain; WI, Whidbey Island. Geology

simplified after Walsh and others (1987) and Washington Public

Power Supply (1991).
14 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

  





  







48°

124°









 











  Wells with total

depth > 3,000' (feet)

20 km

Pre-Tertiary rocks Fold axis

Fault

2,000 

acres

Play boundary

Tertiary broken

 formation

Sedimentary rocks interbedded

with Crescent Formation

Eocene Crescent Formation

mainly basalt

Tertiary sedimentary rocks

and Quaternary deposits



Canada

United States

Vancouver

Strait of Juan de Fuca

Island

Pacific Ocean

Gas

seep

3,009',

6,218',

7,158'

Olympic Peninsula

DBF

EXPLANATION



























 





7,493'

3,490',

3,619'

8,519'

6,571'

8,462'

Ro = 0.5, TD

Ro = 0.42 to 0.61



Ro = PA

0.58 to 1.60

Ro =

0.33 to 1.29

2,000 acres (8.1 km2); depth = 10,000 ft (3,048 m); reservoir

thickness = 75 ft (23 m); effective porosity = 15 percent; trap

fill = 0.8; recovery factor = 0.5; water saturation = 0.27. The

mean undiscovered resource in the Puget Lowland Deep Gas

play was estimated to be 26.8 BCF (table 2).

TOFINO-FUCA BASIN GAS PLAY (404)

Introduction.—This hypothetical conventional gas play

is located in the Tofino-Fuca basin on the northern Olympic

Peninsula of Washington (figs. 1, 3, 8). This basin occupies

a modern topographic lowland that extends from southern

Vancouver Island to the Olympic Mountains and includes the

Strait of Juan de Fuca. Initial subsidence in the basin was of

middle Eocene age and probably driven by thermal subsidence of the volcanic Crescent Formation basement. Johnson

and others (1996) inferred that late Eocene and younger subsidence was forced by contractional deformation associated

with northward tectonic transport of the Washington Coast

Range province. 

The Tofino-Fuca Basin Gas play (404) is bounded on

the south by basement outcrops of the volcanic Crescent Formation, to the north by the international boundary with Canada in the Strait of Juan de Fuca, and to the west by the 3-mi

limit of State waters in the Pacific Ocean. To the east, the

play is bounded by the north-trending Discovery Bay fault

zone, which disrupts and partially truncates the stratigraphic

sequence. 

The exploration premise for the Tofino-Fuca Basin Gas

play (404) is that gas has been generated from either Eocene

strata buried in the deepest part of the basin or from Eocene

melange and (or) broken formation in a structural plate

underlying the basin. Once generated, this gas has migrated

either up-dip from deep basinal sources or up basement fault

zones into Eocene or Oligocene turbidite sandstone reservoirs. Traps are most likely stratigraphic in character (for

example, buried pinch-outs of turbidite sandstone beds), but

small fault traps are also possible. 

Reservoirs.—Upper middle Eocene to Oligocene turbidite sandstone beds of the Twin River Group, including the

Figure 8. Schematic map showing Tofino-Fuca Basin Gas play (404). Petroleum wells are listed in McFarland (1983) or

in addendum to McFarland available through the Washington Division of Geology and Earth Resources. Geology (including selectively displayed faults and folds) is based on Tabor and Cady (1978). Thermal maturity data (Ro = mean vitrinite

reflectance) and location of gas seeps is from Snavely and Kvenvolden (1989) and Niem and Snavely (1991); values for

vitrinite reflectance are from surface samples unless footage from adjacent petroleum well is listed. DBF, Discovery Bay

fault; PA, Port Angeles.
CONVENTIONAL PETROLEUM PLAYS 15

Hoko River, Makah, and Pysht Formations, are the target

reservoirs (Snavely and others, 1980; Niem and Snavely,

1991). Individual sandstone beds range up to about 40 ft (12

m) in thickness and form composite units that are as thick as

400 ft (122 m). Many sandstone beds and composite units

are bounded vertically and laterally by marine mudstones.

The proportion and thickness of sandstone beds within the

Twin River Group decreases to the east within the play area.

Sandstone is lithic-arkosic to quartzo-feldspathic in composition. Meager data suggest that porosity and permeability in

the best potential reservoir rocks may be as high as 20.4 to

24.6 percent and 2 to 657 mD, respectively (Niem and Snavely, 1991). Reservoir rocks are inferred to dip northward

into a basin-axis syncline, where they are buried as deeply as

17,000 ft (5,182 m) (Snavely, 1983; Niem and Snavely,

1991).

Source rocks.—There are two possible source rocks for

this play: Source 1—Eocene marine mudstone located

down-dip in the deepest part of the basin is the first possible

source. Total organic carbon in this interval (from surface

exposures and one well) ranges from 0.3 and 1.2 percent

(Snavely and others, 1980; Niem and Snavely, 1991). The

composition of organic matter plots in a nondiagnostic area

on Van Krevelen diagrams near the convergence of type-III

and type-II fields (Niem and Snavely, 1991). Sparse vitrinite

reflectance data for surface and well samples (as deep as

8,400 ft (2560 m)) ranges from about 0.4 to 0.5 percent.

However these rocks are buried as deeply as 25,000 ft (7,620

m) to the north in the deepest part of the basin (Snavely,

1983; Niem and Snavely, 1991) where higher levels of thermal maturity are expected. Source 2—Marine mudstone in

Eocene melange and (or) broken formations that occur in a

structural plate beneath the Tofino-Fuca basin (Snavely and

Kvenvolden, 1989) is the second possible petroleum source

rock for this play. These rocks crop out south of the

Tofino-Fuca Basin Gas play in the Olympic Mountains (fig.

8). Total organic carbon in these rocks is typically 0.4 to 0.9

percent. Organic matter is mostly type III and gas prone. Vitrinite reflectance of surface samples typically ranges from

about 0.35 to 1.6 percent (Palmer and Lingley, 1989; Snavely and Kvenvolden, 1989). 

There are at least two seeps of thermogenic gas in the

area of the play (fig. 8), indicating that source rocks have

reached maturity and generated hydrocarbons. One seep was

crudely gauged at a flow rate of 20 MCFGPD of methane

(Lingley, 1986). 

Timing and migration of hydrocarbons.—Folding in

the Tofino-Fuca basin and uplift of the Olympic Mountains

began in the middle Miocene (Brown and others, 1960;

Tabor and Cady, 1978; Brandon and Calderwood, 1990;

Snavely and others, 1993). Peak migration of gas probably

occurred immediately before this deformation, during maximum burial of both the coherent strata in the Tofino-Fuca

basin and the melange and (or) broken formation in the structurally lower thrust plate. 

Traps.—Possible stratigraphic traps include buried

pinch-outs of turbidite channel and lobe sandstone beds.

However, many of these potential reservoir bodies have been

breached by erosion on the south flank of the basin in the

play area. Obvious locations of structural traps are few and

small and might occur along faults. Marine mudstone interbedded with the turbidite sandstone forms the potential seals. 

Exploration status.—Nine exploration wells with total

depths greater than 2,740 ft (835 m) were drilled in the area

of the Tofino-Fuca Basin Gas play (404) between 1948 and

1986. The two most recent wells include the 1986 Twin

River Oil and Gas State No. 1-30 well (total depth = 6,571 ft

(2,003 m)) and the 1982 Fairview Oil and Gas No. 1 well

(total depth = 7,158 ft (2,182 m)) (McFarland, 1983; Lingley, 1986). Neither well encountered significant hydrocarbon shows, and there is no known exploration in this play at

the present. 

Evaluation of resource potential.—The Tofino-Fuca

Basin Gas play (404) has been poorly explored. There is only

minor available geological and geophysical information

about rocks at depths greater than 5,000 ft (1,524 m). The

presence of thermogenic gas seeps clearly indicates a viable

source rock for the play. The presence of suitable reservoirs

and traps is less certain, downgrading the overall play potential. For the recent U.S. Geological Survey 1995 National

Petroleum Assessment (Gautier and others, 1995), Johnson

and Tennyson (1995) assessed the probability of suitable

charge, reservoir rock, and trap at 1.0, 0.5, and 0.4, respectively, yielding an overall play probability of 0.2 for a gas

accumulation larger than 6 BCF (table 1). The median number of undiscovered gas accumulations larger than 6 BCF

was estimated to be 7. The size of the largest accumulation

expected at a 5 percent probability was estimated to be 30

BCF using the following simulation parameters and the

methodology of Dolton and others (1987): Area of closure =

700 acres (2.8 km2); depth = 10,000 ft (3,048 m); reservoir

thickness = 40 ft (12 m); effective porosity = 15 percent; trap

fill = 0.8; recovery factor = 0.7; water saturation = 0.27. The

mean undiscovered resource in the Tofino-Fuca Basin Gas

play was estimated to be 15 BCF (table 2).

WESTERN WASHINGTON 

MELANGE PLAY (405)

Introduction.—This conventional oil play is located

along most of the Pacific Coast of Washington (figs. 1, 8, 9).

The entire petroleum system is inferred to occur within the

Eocene to upper middle Miocene stratified sedimentary rock

and melange or broken formation of the Ozette terrane (Snavely and others, 1993) and the Hoh rock assemblage of Rau

(1973). Strata within these units were mostly deposited in

bathyal marine environments on Pacific basin plates, then

accreted to the leading edge of the North American plate

along a subduction zone. The exploration premise is that
16 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON



47°

48°

124°30'



           





























Strait of Juan de Fuca

Pacific

Ocean





Eocene to Miocene broken formation,

low-grade metasedimentary rock

Eocene to Miocene broken formation

and overlying Pliocene to Holocene

deposits

Eocene Crescent Formation and

overlying Eocene to Holocene strata

Wells with total

depth > 3,000' (feet)

 Thrust fault, barbs on

 upper plate

4,000 

acres

Play boundary Oil or gas

seep

30 km

Ro =

0.95 to 1.60 Ro = 0.58 to 0.95

Ro = 0.33 to 1.29

Ro =

0.79 to

1.18

3,095'

4,403'

6,210',gs

gs = Gas show

os = Oil show

6,880' Ro =

0.49 to

0.87

Ro =

0.96 to

2.05

3,010'

4,925'

Ro =

0.87 to

1.98

5,988'

4,927'

WB

7,500'

GH

3,453' 3,120'

5,073'

 Olympic

Mountains

5,015' 5,722',gs

5,600'

EXPLANATION

n = 7, max.

TD = 6,500'

os, gs

4,130'

4,035'

n = 17, os, gs

max. TD = 9,344'

Ocean City area

Ro = 0.53, 5,100'

3,805'
CONVENTIONAL PETROLEUM PLAYS 17

petroleum generated from organic-rich mudstones in the

melange and (or) broken formation has migrated into sandstone reservoirs in coherent structural blocks within the

melange. 

This play is bounded to the north and southeast by a

system of thrust faults that juxtaposes lower-plate melange

and broken formation with upper-plate Eocene marine volcanic rocks of the Crescent Formation and overlying Tertiary

strata. In the Olympic Mountains, the eastern limit of the

play approximates the location where induration and

low-grade metamorphism of the Ozette and Hoh units

become pervasive. To the west, the play extends to the 3-mi

limit of State waters.

Reservoirs.—Deep-marine channel sandstone beds

within coherent structural blocks in the Ozette terrane and

the Hoh rock assemblage are the inferred reservoir rocks.

Based on log analysis of wells from the Ocean City area,

Palmer and Lingley (1989) suggest that sandstone units

range from 10 to 100 ft (3 to 30 m) in thickness, with a mean

of about 34 ft (10 m). Composite sandstone units in outcrop

are as thick as 140 ft (42 m) (Lingley, 1995). Thicker sandstone units, mainly distributary channel deposits of limited

areal extent, probably include fine-grained interbeds or

drapes and are heterogeneous. Most sandstone units have

porosities less than 25 percent and permeabilities less than

100 mD (Palmer and Lingley, 1989). 

Source rocks.—Marine mudstone in the Eocene to

upper middle Miocene Ozette terrane and Hoh rock assemblage is inferred to be a widely distributed petroleum source

rock. The distribution of source rocks within these units is

impossible to determine because of internal structural complexity; however, melange-like rocks extend down to the top

of the down-going Juan de Fuca plate (about 50,000–60,000

ft; 15,000 to 18,000 m), and abundant source rock is

expected. Surface and well samples have relatively low total

organic carbon (typically 0.5 to 1.0 percent) and type-III

organic matter (Snavely and Kvenvolden, 1989). Although

gas is the expected hydrocarbon type, drilling records report

numerous oil shows. These shows and oil seeps are present

along an 84-mi-long (135 km), north-trending fairway

within the play. Approximately 12,000 barrels of oil were

produced from the Hoh rock assemblage in one well in the

Ocean City area (fig. 9) from 1957 to 1961 (McFarland,

1983; Palmer and Lingley, 1989). Thus, oil-prone source

rocks must be present at depth. Both oil and gas seeps occur

within the play area (fig. 9). Thermal maturity in possible

source rocks exposed at the surface or penetrated in wells

(fig. 9) varies significantly, probably in response to internal

structural disruption. In the Ocean City area, rocks at depths

of as much as 6,000 ft (1,829 m) have typical mean vitrinite

reflectance of 0.5 percent. However, in outcrops about 15.5

mi (25 km) to the north, mean vitrinite reflectance in correlative rocks is generally between 1.0 and 1.5 percent. Surface

vitrinite reflectance in the northern part of the play varies

from 0.33 to 2.05 percent (Snavely and Kvenvolden, 1989)

(fig. 9).

Timing and migration of hydrocarbons.—Migration in

this complex setting has probably occurred continuously

from the Oligocene to the present, as marine sedimentary

rocks of Eocene and younger age were progressively underplated beneath the continental margin. Upward and westward migration of hydrocarbons along faults within the

Ozette and Hoh units seems likely (Snavely and Kvenvolden, 1989; Palmer and Lingley, 1989). 

Traps.—There is almost certainly a variety of trap types

within the structurally complex Ozette and Hoh units, associated with fault blocks, anticlines, mudstone diapirs, and

stratigraphic pinch-outs or unconformities. Given the structural complexity of these units, individual traps are probably

small (less than 1,000 acres (4 km2). Fine-grained rocks

within the Ozette and Hoh units provide the seal. The

expected uniformity in depositional and structural style

across the play area suggests that traps are equally likely in

any part of the play. Similarly, the traps might occur at

depths ranging from about 2,000 ft to about 23,000 ft (610 to

7,010 m), the depth at which gas should disappear given geothermal gradients of about 1.5°F/100 ft (26°C/km).

Exploration status.—There is no known ongoing

exploration in this play. About 80 exploration wells have

been drilled in the play area since the early 1900’s, with 43

having total depths greater than 3,000 ft. This exploration

occurred in several discrete phases described in Palmer and

Lingley (1989). The last major exploration push in this play

ended in the late 1960’s following drilling by Shell and Pan

American on the adjacent continental shelf. 

Evaluation of resource potential.—The Western Washington Melange play (405) has limited potential given current technology. Reservoir quality and the integrity of traps

are considered the major limiting factors. Because of the

complex structural style and poor outcrop quality, exploration is extremely difficult. Moreover, the small anticipated

size of traps and reservoirs may discourage explorationists.

For the recent U.S. Geological Survey 1995 National

Petroleum Assessment (Gautier and others, 1995), Johnson

and Tennyson (1995) assessed the probability of suitable

charge, reservoir rock, and trap for an oil accumulation at

1.0, 1.0, and 0.5, respectively, yielding an overall play probability of 0.5 for an accumulation larger than 1 MMBO

(table 1). The median number of undiscovered oil

Figure 9 (facing page). Schematic map showing Western Washington Melange play (405). Petroleum wells are listed in McFarland (1983) or in addendum to McFarland available through the

Washington Division of Geology and Earth Resources. Geology is

based on Tabor and Cady (1978) and Walsh and others (1987).

Thermal maturity data (Ro = mean vitrinite reflectance) and locations of seeps are from Snavely and Kvenvolden (1989) and Palmer

and Lingley (1989); values for vitrinite reflectance are from surface

samples unless footage from adjacent petroleum well are listed.

GH, Grays Harbor. WB, Willapa Bay.
18 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

accumulations larger than 1 MMBO was estimated to be 10.

The size of the largest accumulation expected at a 5 percent

probability was estimated to be 13 MMBO using the following simulation parameters and the methodology of Dolton

and others (1987): Area of closure = 1,000 acres (4 km2);

reservoir thickness = 75 ft (23 m); effective porosity = 15

percent; trap fill = 0.8; recovery factor = 0.24; water saturation = 0.27. The mean undiscovered oil resource was estimated to be 18.2 MMB (table 2).

Johnson and Tennyson (1995) assessed the probability

of suitable charge, reservoir rock, and trap for a gas accumulation at 1.0, 1.0, and 0.1, respectively, yielding an overall

play probability of 0.1 for a gas deposit larger than 6 BCF.

Given this low play probability, the mean undiscovered gas

resource was not estimated. 

SOUTHWEST WASHINGTON MIOCENE 

SANDSTONE PLAY (406)

Introduction.—This hypothetical conventional oil play

is located in the parts of the Grays Harbor basin area of

southwest Washington (figs. 1, 3, 10) where Miocene shallow-marine sedimentary rocks have been deposited and preserved. The play has an irregular shape and is bounded by the

upwarped margins of the Grays Harbor basin to the north,

south, and east. To the west, the play extends to the 3-mi

limit of State waters. 

Eocene and Oligocene subsidence of the Grays Harbor

basin was probably generated by thermal subsidence of the

underlying volcanic basement, the lower to middle Eocene

Crescent Formation (Johnson and Yount, 1992). Neogene

subsidence was apparently forced by a variety of tectonic

processes involving contractional shortening, strike-slip

faulting, and rotation (Wells and Coe, 1985). The play area

includes a major north-trending, east-dipping thrust fault

(fig. 10) that represents a middle Tertiary plate boundary.

West of this boundary, Miocene shallow-marine rocks of the

Montesano Formation were deposited on the lower structural

plate consisting of Eocene to Miocene stratified rock and

melange of the Ozette terrane (Snavely and others, 1993) and

Hoh rock assemblage (Rau, 1973). East of this boundary, the

Astoria and Montesano Formations were deposited on an

upper structural plate consisting of Crescent Formation basement overlain by a stratigraphically coherent, generally

shoaling upward, sequence of Eocene to Miocene sedimentary rocks. 

The exploration premise of this hypothetical play is that

oil and gas generated from organic-rich mudstone in Eocene

to upper middle Miocene melange and broken formation of

the lower structural plate described above has migrated

upward into porous and permeable shallow-marine sandstone of the Miocene Montesano and (or) Astoria Formations. Structural traps for reservoirs could include small

anticlines and fault blocks. Where present, overlying

fine-grained rocks might provide viable seals. 

Reservoirs.—Miocene shallow marine and deltaic

sandstone of the Astoria and lower Montesano Formations in

the eastern part of play, and the Montesano Formation in the

western part of play, are the target reservoirs. In the Ocean

City area (fig. 10) in the west-central part of the play, Palmer

and Lingley (1989) describe a remarkable 600 ft (183 m) of

sandstone in the Montesano Formation that averages 28 percent porosity and 1 darcy of permeability. In the eastern part

of the play, several 100-ft-thick (30 m) sandstone beds occur

in both the Astoria and Montesano Formations (Bigelow,

1987). The proportion of sandstone in both the Montesano

and Astoria Formations generally decreases to the west.

Sandstone units are typically bounded by marine mudstone.

Target reservoir sandstone units occur at depths of about

1,000 to 3,200 ft (305 to 975 m). 

Montesano Formation sandstone is lithic arenite (Bigelow, 1987) and typically has porosities greater than 20 percent and permeabilities ranging from 2 to 2,000 mD (Palmer

and Lingley, 1989). There are no available porosity and permeability data for the Astoria Formation in this play, but

Astoria sandstone outcrops are friable, and values similar to

those of the Montesano Formation are inferred. 

Source rocks.—Eocene to upper middle Miocene

marine mudstone of the Ozette terrane and Hoh rock assemblage is the inferred hydrocarbon source rock. The thickness

of source-rock units is impossible to determine because of

internal structural complexity within these units. However,

melange-like rocks are inferred to extend down to the top of

the down-going Juan de Fuca plate, about 50,000 to 60,000

ft (15,000 to 18,000 m) deep. Surface and well samples have

relatively low total organic carbon (typically 0.5 to 1.0 percent) and generally type-III organic matter (Snavely and

Kvenvolden, 1989). Although gas is the expected hydrocarbon type, drilling records report numerous oil shows, and

approximately 12,000 barrels of oil were produced from the

Hoh rock assemblage in one well between 1957 and 1961

(McFarland, 1983; Palmer and Lingley, 1989). Thus,

oil-prone source rocks are expected at depth. Thermal maturity in possible source rocks varies significantly, probably in

response to structural disruption. In the Ocean City area,

rocks at depths of as much as 6,000 ft (1,830 m) have typical

mean vitrinite reflectance of 0.6 percent; however, mean vitrinite reflectance in correlative outcrops about 15 mi (25 km)

to the north is generally between 1.0 and 1.5 percent (Snavely and Kvenvolden, 1989). 

Timing and migration of hydrocarbons.—Migration

has occurred from the late Miocene (after deposition of the

reservoir rocks) to the present. Westward and upward migration along thrust faults within the Ozette and Hoh

source-rock units seems likely (Snavely and Kvenvolden,

1989). In the western part of the area, Ozette and Hoh source

rocks are overlain by reservoir sandstone units, and there is
CONVENTIONAL PETROLEUM PLAYS 19















































































































































































































124°

47°

GH

WB





Wells in play area with

total depth > 3,000' (feet)

Pliocene to Quaternary deposits

Miocene Astoria and Montesano

Formations

Eocene and Oligocene

sedimentary rocks

Eocene Crescent Formation,

mainly basalt Play boundary

1,000

acres

Fault Fold axis

25 km

4,989'

3,015'

3,946'

6,855'

Ro = 0.47, 4,600'

6,608'

6,928'

7,005'

6,725'

3,000'

3,950'

3,663'

3,737'

12,293' 4,699'

4,248'

3,910'

n = 4, max.

TD = 3,452'

4,927'

Pacific Ocean

5,093'

5,038'

4,600'

3,240'

3,120'

3,453'

4,200'

Ro = 0.57, 2,280'

n = 5, max. TD = 5,000'

n = 14, max. TD = 9,344'

Ro = 0.53, 5,100'

Ocean City area

 Thrust fault, barbs on upper plate

EXPLANATION

Figure 10. Schematic map showing Southwest Washington Miocene Sandstone play (406). Petroleum wells are listed in

McFarland (1983) or in addendum to McFarland available through the Washington Division of Geology and Earth Resources. Geology (including selectively displayed faults and folds) is based on Walsh and others (1987). Thermal maturity data

(Ro = mean vitrinite reflectance) is from Snavely and Kvenvolden (1989) and Palmer and Lingley (1989); values for vitrinite

reflectance are from surface samples unless footage from adjacent petroleum well is listed. GH, Grays Harbor. WB, Willapa

Bay.
20 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

a direct migration pathway from inferred source to reservoir.

In the eastern part of the play area, petroleum sourced from

lower-plate melange and broken formation must migrate

through a thick Eocene to Oligocene section of volcanic and

sedimentary rocks in order to reach Miocene sandstone reservoirs. 

Traps.—Small anticlinal traps that are either associated

with thrust or strike-slip faults or with mudstone diapirs in

the underlying melange and broken formation are the most

likely traps (Palmer and Lingley, 1989). Stratigraphic

pinch-outs of Montesano Formation sandstone beds are less

likely traps. Upper Miocene to Pliocene marine mudstones

(in the upper part of and above the Montesano Formation)

form possible seals. Closure on anticlinal traps cannot be

demonstrated with available data and, if present, is probably

no more than 1,000 acres (4 km2). 

Exploration status.—There is no known ongoing exploration in the area of this play. About 70 wildcat wells have

been drilled in the area of this play since 1901 during several

discrete exploration phases (McFarland, 1983; Palmer and

Lingley, 1989). The deepest and most recent well, the

Amoco-Weyerhaeuser No. 1-29, was abandoned in 1985 at a

total depth of 12,293 ft (3,747 m). 

Evaluation of resource potential.—The Southwest

Washington Miocene Sandstone play (406) has limited

potential. Most oil and gas shows and the only hydrocarbon

production in this geographic area have come from the

underlying melange. There is clearly source and reservoir

rock for this play, and evidence from borehole shows and

drill-stem tests indicate that there has been some petroleum

migration through potential sandstone reservoir units

(Palmer and Lingley, 1989). Overlying seals have been

breached in parts of the play (especially the western part),

and trap and seal integrity is regarded as the principal limiting factor for petroleum accumulation. 

For the recent U.S. Geological Survey 1995 National

Assessment of United States Oil and Gas Resources (Gautier

and others, 1995), Johnson and Tennyson (1995) assessed

the probability of suitable charge, reservoir rock, and trap for

an oil accumulation at 1.0, 1.0, and 0.15, respectively, yielding an overall play probability of 0.15 for a deposit larger

than 1 MMB (table 1). The median number of undiscovered

oil accumulations larger than 1 MMBO was estimated to be

2. The size of the largest accumulation expected at a 5 percent probability was estimated to be 14 MMBO using the following simulation parameters and the methodology of

Dolton and others (1987): Area of closure = 1,000 acres (4

km2); reservoir thickness = 40 ft (12 m); effective porosity =

25 percent; trap fill = 0.8; recovery factor = 0.30; water saturation = 0.27. The mean undiscovered oil resource in the

Southwest Washington Miocene Sandstone play was estimated to be 1.1 MMB (table 2).

Johnson and Tennyson (1995) assessed the probability

of suitable charge, reservoir rock, and trap for a gas accumulation at 1.0, 1.0, and 0.1, respectively, yielding an overall

play probability of 0.1 for a gas deposit larger than 6 BCF.

Given this low play probability, the mean undiscovered gas

resource was not estimated. 

COWLITZ-SPENCER GAS PLAY (407)

Introduction.—In Washington, this play is located in

the southern Puget Lowland and the southwestern Coast

Range of Washington (figs. 1, 3, 11). Johnson and Tennyson

(1995) show the play extending south into Oregon where it

includes the Mist gas field (approximately 70 BCF; Bruer,

1980; Armentrout and Suek, 1985; Niem and others, 1994;

H.J. Meyer, Oregon Natural Gas Co., oral commun., 1995);

however, only the Washington portion of the play is considered in this report. The play has an irregular shape and

includes portions of the Chehalis, Grays Harbor, Nehalem,

and Astoria basins. Uplifts of Tertiary volcanic rocks, including the Black Hills, Willapa Hills, the Doty Hills, and highlands east of Centralia and Longview, locally define play

boundaries (fig. 11). For the purposes of this report, the play

is bounded on the south by the Oregon-Washington State

boundary, on the east by volcanic rocks of the Cascade

Range or tightly folded and faulted Eocene strata in the Cascade Range foothills, and on the northwest and west by a

facies change that results in the disappearance of the Eocene

reservoir rock. 

Eocene strata that form the potential petroleum system

were deposited on a basement of lower to lower middle

Eocene basalt of the Crescent Formation. These strata are cut

by reverse, thrust, normal, and strike-slip faults with displacements as large as a few kilometers (Snavely and others,

1958; Wells, 1981; Wells and Coe, 1985). Beds typically

have gentle dips but locally have steep dips adjacent to faults.

Deformation generally decreases from east to west. 

Using the Mist gas field (Bruer, 1980; Armentrout and

Suek, 1985) as an analog, the exploration premise for this

play is that gas generated from Eocene marine shale or nonmarine carbonaceous shale and coal has migrated into reservoirs in overlying or interbedded Eocene fluvial,

shallow-marine, or submarine-fan sandstone. Structural traps

for reservoirs are mainly fault blocks, but might include

small anticlines. Stratigraphic traps are also possible but

have not been documented. Interbedded fine-grained rocks

and (or) overlying marine mudstone form the seals. 

Reservoirs.—Middle to upper Eocene fluvial, deltaic,

shallow-marine, and submarine-fan arkosic sandstone of the

Cowlitz, Skookumchuck, and McIntosh Formations are the

potential reservoir rocks. Analysis of outcrops and geophysical borehole logs indicates that the sandstone bodies that are

potential reservoirs within these formations are as thick as

about 170 ft (52 m) (Henricksen, 1956; Snavely and others,

1958; Wurden and Ford, 1976; Flores and Johnson, 1995).

Sandstone is predominantly arkosic. Skookumchuck Formation sandstone in the Jackson Prairie gas storage wells in the
CONVENTIONAL PETROLEUM PLAYS 21



































































Tertiary volcanic

rocks

Tertiary sedimentary

rocks and Quaternary

deposits 2,000

20 km

Play boundary

acres

Wells with total

Fault

depth > 3,000' (feet)

Fold

axis Oregon

Washington

Mist gas

field

3,500'

Ro = 0.23

6,650' 4.484'

6,143'

10,820'

8,446'

10,708'

Jackson Prairie

gas storage

Ro = 0.41, P = 28 to 40%,

K < 8,500 mD, 2,540 '

max. TD = 8,015' Ro = 0.64, 7,000'

3,110' 6,500'

9,455' 3,720'

3,037'

4,010'

4,330'

3,015' Ro = 0.35

4,034'

6,855'

6,608'

GH

WB

Pacific Ocean

BHU

DHU

WHU

GHB

CB

NB

AB

PL

46°

30'

124°

L

C













NH

5,272'

Ro = 0.47, 4,600'

6,908'

3,946'

Ro = 0.48,

P = 10 to 20%,

K = 0.4 to 6.2 mD

CR

NA

EXPLANATION

Chehalis basin has porosities of 30 to 40 percent at depths of

1,500 to 3,000 ft (457 to 914 m) and permeabilities as high

as several darcies (Wurden and Ford, 1976). These values

are comparable to those reported from the Mist field of

northwest Oregon, where Cowlitz Formation reservoir rocks

have porosities of 25 to 36 percent and permeabilities of 100

mD to several darcies (Armentrout and Suek, 1985; Niem

and others, 1994). 

Deep-marine sandstone of the McIntosh Formation in

the western part of the play has reported porosities of 10 to

Figure 11. Schematic map showing Washington portion of Cowlitz-Spencer Gas play (407). Geology (including selectively

displayed faults and folds) is based on Walsh and others (1987) and Walker and MacLeod (1991). Petroleum wells in Washington

are listed in McFarland (1983) or in addendum to McFarland available through the Washington Division of Geology and Earth

Resources. Thermal maturity data (Ro = mean vitrinite reflectance), porosity (P), and permeability (K, in millidarcies) is from

Wurden and Ford (1976), Walsh and Lingley (1991), Moothart (1992), or previously unpublished data; values are from surface

samples unless footage from adjacent petroleum well is listed. AB, Astoria basin; BHU, Black Hills uplift; C, Centralia; CB, Chehalis basin; CR, Columbia River; DHU, Doty Hills uplift; GH, Grays Harbor; GHB, Grays Harbor basin; L, Longview; NA, Nehalem arch; NB, Nehalem basin, NH, uplands underlain by Northcraft Formation, PL, Puget Lowland; WB, Willapa Bay, WHU,

Willapa Hills uplift.
22 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

22 percent, but measured permeabilities are less than 6.2 mD

(Moothart, 1992). Porosity in these rocks is commonly

occluded by smectite and chlorite rim cements, zeolites, and

sparry calcite. Some secondary porosity results from dissolution of feldspar and lithic fragments (Moothart, 1992).

Source rocks.—Middle to upper Eocene marine shale

and (or) shallow-marine to deltaic coal and carbonaceous

shale of the McIntosh, Skookumchuck, and Cowlitz Formations are the inferred source rock (Snavely and others, 1958;

Armentrout and Suek, 1985; Moothart, 1992; Niem and others, 1994; Flores and Johnson, 1995). Organic matter in these

rocks is terrestrial and gas prone. Cumulative thickness of

Eocene coal beds in the eastern part of the area is more than

80 ft (24 m). Coal beds sampled at the surface and in the subsurface down to about 10,000 ft (3,048 m) are of lignite to

subbituminous rank; mean vitrinite reflectance is generally

between 0.3 and 0.6 percent but can be slightly higher (fig.

11) (Walsh and Lingley, 1991). In the western part of the

play, the mean vitrinite reflectance of marine mudstone at the

surface and in the shallow subsurface (less than 5,000 ft;

(1,524 m)) is generally 0.4 to 0.5 percent, and total organic

carbon ranges from 0.5 to 1.25 percent (Moothart, 1992).

Enhanced maturation may have occurred adjacent to Eocene

and younger intrusive centers that occur within or on the

margins of the play area (e.g., Esposito and Whitney, 1995). 

There is also significant potential source rock in this

play that does not crop out and has been penetrated by only a

few boreholes in the deeper parts of basins. For example,

unpublished proprietary seismic data reveal the presence of a

thick section of marine strata at depths of 6,500 to 16,400 ft

(1,981 to 4,999 m) below the Chehalis basin (fig. 11) (Krehbiel, 1993; Johnson and Stanley, 1995). 

Timing and migration of hydrocarbons.—Maximum

burial and inferred generation and migration of hydrocarbons

occurred in the early to middle Miocene, following deposition of the Oligocene Lincoln Creek Formation (fig. 2). 

Traps.—The structural style of this play is illustrated by

the Mist field of the northern Oregon Coast Range, where gas

is produced from pools (about 1 to 8 BCF) in multiple, small,

fault-block traps (Bruer, 1980; Bruer and others, 1984;

Armentrout and Suek, 1985; Niem and others, 1992, 1994).

Entrapment could also occur in gentle anticlines or along

stratigraphic pinch-outs of nearshore or deltaic sandstone

bodies. There has been ongoing tectonism in the area of this

play since the Eocene; thus, fault-block traps might have

formed before, during, or after peak hydrocarbon generation.

Overlying fine-grained marine siltstones of the Keasey and

Lincoln Creek Formations provide an efficient seal. Traps

associated with good reservoir rocks probably occur between

about 1,000 and 7,000 ft (305 and 2,134 m). 

Exploration status.—Despite the presence of the nearby

Mist field in northwest Oregon, there has been only marginal

exploration interest in the southwest Washington part of this

play. About 20 wells with depths greater than 3,000 ft (914

m) have been drilled in the approximately 1,900-mi2 (5,000

km2) area (McFarland, 1983). Most of these wells were

drilled in the late 1950’s or early 1960’s, after which there

has been little exploration activity. The 1960’s wave of

exploration resulted in development and numerous subsequent expansions of the natural gas storage facility at Jackson

Prairie (operated by Washington Natural Gas) in the Chehalis basin (fig. 11) (Wurden and Ford, 1976).

Evaluation of resource potential.—In the Cowlitz-Spencer Gas play (407), the relatively low maturity of

source rocks is probably the largest factor limiting development of significant gas accumulations. In the Washington

part of the play, there also does not appear to be an analog for

the Nehalem arch, the regional structural feature considered

most responsible for petroleum migration into the Mist gas

field (Armentrout and Suek, 1985; Niem and others, 1994).

However, the smaller scale structural style at Mist (numerous

small fault blocks and fault-block traps) typifies the entire

play area. Given this structural style, there should be a few

small gas accumulations in Washington. Because the Washington portion of this play has been poorly explored, considerable drilling may be needed before a clear strategy for

finding these small traps is developed. 

For the recent U.S. Geological Survey 1995 National

Petroleum Assessment (Gautier and others, 1995), Johnson

and Tennyson (1995) assessed the probability (in the entire

play area) of suitable charge, reservoir rock, and trap at 1.0,

1.0, and 1.0, respectively, yielding an overall probability of

1.0 for a gas accumulation larger than 6 BCF (table 1). Using

the Mist gas field as an analog, the size of the largest accumulation expected in the entire play at a 5 percent probability

was estimated to be 150 BCF. We feel this overall probability

also applies to the restricted Washington portion of the play.

Based on our evaluation of the geologic framework and

petroleum geology of this play, we estimate a median of four

undiscovered gas accumulations larger than 6 BCF for the

Washington portion of the play (10 for the entire play) and

estimate the mean undiscovered resource for the Washington

portion of this play to be 116 BCF (table 2). 

NORTHWESTERN COLUMBIA PLATEAU 

GAS PLAY (501)

Introduction.—This hypothetical gas play (fig. 12) is

located in south-central Washington within one or more nonmarine Paleogene transtensional and (or) extensional basins

(Gresens, 1982; Johnson, 1985; Taylor and others, 1988;

Catchings and Mooney, 1988; Evans, 1994; Jarchow and

others, 1994) that were buried during the Miocene by flood

basalts of the Columbia River Basalt Group. The area of the

play is defined by the inferred sub-basalt extent of these

Paleogene fluvial and lacustrine sedimentary rocks, which

consist of arkosic sandstone, mudstone, conglomerate, and

minor coal interbedded with volcanic and volcaniclastic

rocks. The thickness of the prospective section ranges from
CONVENTIONAL PETROLEUM PLAYS 23

about 4,000 to 20,000 ft (1,219 to 6,096 m) or more, based

on thicknesses of exposed sequences at the northwest margin

of the play. The northeastern boundary of the play lies

between wells to the northeast in which the Paleogene

sequence is absent and wells to the southwest where it is

present; the boundary approximately coincides with a major

crustal boundary postulated by Reidel and others (1994) that

roughly follows the projection of the Entiat fault (fig. 12),

the northeastern margin of the exposed Paleogene sequence.

The southwest boundary of the play is the approximate

southeastward projection of southeast-trending splays of the

Straight Creek fault zone (Tabor and others, 1984). The

northern margin of the play is placed at the northern limit of

continuous exposures of the Columbia River Basalt Group.

The southern boundary of the play is placed along the

Columbia River. The play is about 125 mi (201 km) long and

60 mi (97 km) wide. 

The middle to late Miocene Columbia River Basalt

Group dominates the surface geology of the area. Geophysical data (Stanley, 1984; Catchings and Mooney, 1988; Jarchow and others, 1994) indicate that it is about 10,000 to

15,000 ft (3,280 to 4,572 m) thick in the south-central part of

the play; Orange and Berkman (1985) interpreted a basalt

thickness of almost 20,000 ft (6,096 m) on the basis of magnetotelluric data in the southern part of the play. Two exploration wells penetrated more than 10,000 ft (3,048 m) of the

Columbia River Basalt Group in the central part of the play,

and six other wells penetrated 5,000 to 8,000 ft (1,524 to

2,438 m) of this unit (table 3). 

The Columbia River Basalt Group unconformably

overlies thick, folded Paleogene strata on the northern margin of the play. Paleogene units include the lower Eocene

Swauk Formation (Tabor and others, 1982, 1984; Taylor and

others, 1988), the middle to upper Eocene Chumstick

(Evans, 1988, 1991, 1994) and Roslyn (Walker, 1980; Barnett, 1985) Formations, and the upper Eocene or lower Oligocene Wenatchee Formation (Gresens and others, 1981;

Gresens, 1983; Tabor and others, 1982; Hauptman, 1983)

(fig. 2). Exploratory drilling (fig. 2, table 3) and corroborative seismic and magnetotelluric surveys (Stanley, 1984; Jarchow and others, 1994; Lutter and others, 1994) have

confirmed that these strata extend beneath the basalt at least

30 mi (48 km) southeastward from the exposures at the

northwestern margin of the play. Predominantly arkosic

sandstone bodies within these nonmarine units are the potential reservoirs for the play. 

In the western part of the play, uppermost Oligocene to

Quaternary calc-alkaline volcanic rocks of the Cascade arc

overlie the Paleogene sequence and also overlie, interfinger

with, and underlie the Columbia River Basalt Group. These

strata have been also been encountered in some of the exploration wells below the Columbia River Basalt Group. Large,

dominantly east-west-trending folds and generally

north-verging reverse faults of the Miocene to Quaternary

Yakima fold belt deform the basalt, most notably in the

western part of the play. This play also includes a major

north-northwest-trending fold, the Hog Ranch–Naneum

Ridge anticline, that lies along the trend of the Leavenworth

fault and the southwest margin of the Chumstick basin. A

well drilled on this high encountered a reduced thickness of

basalt, and Campbell (1989) concluded that it was a

pre-basalt topographic high that limited eastward transport

of Cascade-derived volcaniclastic rocks.

The exploration premise for this play is that gas and gas

condensate was generated from coal or organic-rich fluvial

or lacustrine mudstone in Paleocene or Eocene nonmarine

strata beneath the basalt and migrated into Paleogene sandstone reservoirs. Traps are postulated to be either (1) Neogene structural traps typified by the large-amplitude

east-trending folds and reverse faults of the Columbia River

Basalt Group, (2) upper Eocene to Oligocene structural

traps, or (3) stratigraphic traps, caused by lateral facies

changes, variations in porosity and permeability, or stratigraphic truncations. Drilling density in this play is approximately one well per 2,800 mi2 (7,200 km2), making the

Columbia basin one of the least explored sedimentary basins

in the contiguous United States.

Reservoirs.—Potential reservoirs are Eocene or Oligocene arkosic fluvial sandstone beds of the nonmarine

Swauk, Chumstick, Roslyn, Manastash, and Wenatchee Formations and coeval units. These units are all exposed on the

northern and western margins of the play, where they are

interbedded with substantial thicknesses of volcanic rocks.

The drilled sub-basalt thickness (table 3; also Campbell and

Reidel, 1994) of these nonmarine strata in the northern and

central parts of the play ranges from less than 5,000 ft to

more than 11,000 ft (1,524 to 3,353 m). Sandstone bed thickness (based on log interpretation) averages 26 ft (7.9 m) and

is as thick as 81 ft (24.7 m). Lingley and Walsh (1986) suggested that these strata are likely to be only fair reservoir

rocks; their analysis of geophysical logs of several wells

indicated that porosity typically decreases downward within

sub-basalt strata from a mean of 18 percent at 6,000 ft (1,829

m) to a mean of 6 percent at 15,000 ft (4,572 m). 

The lower to middle Eocene Swauk Formation (Taylor

and others, 1988; Evans and Johnson, 1989) is exposed in the

Swauk basin between the Leavenworth and Straight Creek

fault systems. It is more than 15,744 ft (4,800 m) thick and

comprises several facies ranging from proximal fanglomerates to fine-grained lacustrine rocks. Taylor and others

(1988) described braided- and meandering-river sandstone

facies that could be present in the Swauk-equivalent section

beneath the Columbia River Basalt Group. These fluvial

deposits consist of medium- to coarse-grained, cross-bedded

sandstone with bed thicknesses up to about 32.8 ft (10 m) in

the meandering river facies and 230 ft (70 m) in the braided

river facies. The latter facies, however, is reported to have

significant amounts of laumontite and limited porosity (Taylor and others, 1988). V.A. Frizzell, Jr., (unpub. data, 1982)

reported porosity values between 3.1 and 5.3 percent and
24 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON



   









































   









Quaternary deposits

Exploration well 

showing 

total depth (feet)

Play boundary

Fold 

Fault

 13,190



Columbia River 

Basalt Group

Oligocene and Miocene

volcanic and plutonic rocks

Eocene volcanic rocks



Eocene sedimentary rocks

Pre-Tertiary rocks 

Monoclinal axis

WASHINGTON

OREGON

Columbia River

1,695

1,140

1,188

1,250

1,230

825

935

2,760

3,810

Yakima River

Y

525

47°

121° 120° 119°

46°

 930

4,903

E

W

LF

EF

SCF

Basalt Explorer

4,682

Moses Lake 1A

6,979

Quincy

13,190

4,575

1-29 Bissa

14,965

BN 23-35

12,584

BN 1-9

17,518

YM 1-33

16,199 HR - NR

4,615

2,000

RHGF

1,003

RSH-1

10,655 Darcell 1-10

8,556

P

CB

SB

40 km

EXPLANATION








CONVENTIONAL PETROLEUM PLAYS 25

permeabilities of 0.02 and 0.21 mD for four outcrop samples

of the Swauk Formation. Similarly, log-interpreted porosities

for strata interpreted as equivalent to the Swauk Formation

near the bottom of the Yakima Minerals 1-33 well (table 3)

at about 15,000 ft (4,572 m) were in the 5 to 8 percent range

(Lingley and Walsh, 1986).

The middle to upper Eocene Chumstick Formation is an

extremely thick sequence of fluvial and lacustrine rocks

(Evans and Johnson, 1989; Evans, 1991). Total stratigraphic

thickness is uncertain but has been estimated between about

19,000 ft (5,791 m) (Gresens and others, 1981) and 39,360 ft

(12,000 m) (Evans, 1991). Abundant channel-form sandstone beds form multistory sequences 33 to 100 ft (10 to 30

m) thick (Evans, 1991). Composite sandstone and conglomerate units in the Chumstick Formation are as thick as 300 ft

(91 m) or more (Evans, 1988). No systematic analyses of reservoir properties from outcrops of this sandstone facies have

been reported. V.A. Frizzell, Jr. (unpub.data, 1982) reported

low porosity and permeability from measurements on two

samples of Chumstick sandstone (1.2 percent and 0.02 mD;

6.8 percent and 0.8 mD), but it is unlikely that his samples

were taken from the most promising reservoir facies, and the

degree of weathering is unknown. Sandstone beds assigned

to the Chumstick Formation by Campbell and Banning

(1985) at depths between about 13,000 ft (3,962 m) and

16,000 ft (4,877 m) in the BN 1-9 well (table 3) have

log-derived porosities of only about 5 to 7 percent (Lingley

and Walsh, 1986). Drill-stem tests, however, had flows of 3.1

MMCFGPD (million cubic feet of gas per day) and 6 BCPD

(barrels of condensate per day) (Lingley and Walsh, 1986),

indicating that at least some sandstone beds in the sub-basalt

Chumstick have reservoir potential. 

The middle and upper Eocene Roslyn Formation

(Walker, 1980; Frizzell and others, 1984; Tabor and others,

1982, 1984; Barnett, 1985) crops out between the Leavenworth and Straight Creek fault system and is correlative with

the upper part of the Chumstick Formation. It consists of

about 8,200 ft (2,499 m) of fine- to coarse-grained, micaceous, partly zeolitized, poorly indurated, lithofeldspathic

sandstone; coal beds are interbedded with sandstone in the

upper part of the unit. Deposition took place in a southwest-flowing fluvial system (Barnett, 1985). Strata

interpreted as Roslyn Formation by Campbell and Banning

(1985) were encountered in the Yakima Minerals 1-33 and

1-29 Bissa wells (table 3) at depths of 9,776 ft (2,980 m) to

about 13,278 ft (4,047 m) and 4,570 (1,393 m) to about

13,610 ft (4,148 m), respectively. Lingley and Walsh (1986)

used well logs to infer porosities between 4 and 18 percent at

those depths. In the Yakima Minerals 1-33 well, an interval

at about 13,000 ft (3,962 m) near the bottom of the inferred

Roslyn tested 5,400 barrels of water per day and 570

MMCFGPD of gas, indicating adequate permeability.

The lower Oligocene Wenatchee Formation (Gresens

and others, 1981; Tabor and others, 1982; Hauptman, 1983)

is exposed discontinuously in several locations near

Wenatchee, lying unconformably on Eocene and older

strata. Campbell and Reidel's (1994) interpretation of drilling results indicated that it is present below the basalt in the

eastern part of the play in the Quincy and BN 1-9 wells (table

3). It consists of as much as 984 ft (300 m) of friable

coarse-grained quartz sandstone interbedded with tuffaceous

shales and paleosols. Hauptman (1983) interpreted the depositional setting as a generally west-flowing fluvial system

with both braided and meandering streams. The sandstone is

much less feldspathic than the other Paleogene units. Campbell and Reidel (1994) reported that a water well drilled in

1993 encountered about 60 ft (18 m) of Wenatchee Formation channel sandstone that produced several thousand gallons per minute of water at almost 100 psi pressure, along

with a little gas, suggesting that this unit could be an excellent gas reservoir. Sandstone interpreted as Wenatchee Formation (Campbell, 1989) between about 11,200 ft (3,414 m)

and 13,000 ft (3,962) in the BN 1-9 well (table 3) has porosities of about 9 to 17 percent, and drill-stem tests had flows

of 2.4 MMCFGPD and 134 barrels of water per day (Lingley

and Walsh, 1986).

Source rocks.—Potential source rocks are lacustrine

and fluvial shales in the Swauk and Chumstick Formations

and coal beds in the Roslyn Formation. Reported TOC (total

organic carbon) values from outcrops are 0 to 6 percent (0.03

to 1.10 percent in the Swauk Formation; 0.92 to 17.9 percent

in the Roslyn Formation; 0.13 to 5.97 percent in the Chumstick Formation (V.A., Frizzell, Jr., unpub. data)). Pyrolysis

data on cuttings samples from the Yakima Minerals 1-33 and

Bissa 1-29 wells indicates that each penetrated more than

1,200 ft (366 m) of section (including thin coal beds) that

averaged more than 2.5 percent TOC (Core Laboratories,

1987a, 1987b; Lingley and von der Dick, 1991). Organic

matter is mostly types III and IV but includes minor type II

(Peters, 1986), the probable source of the paraffinic condensate (37° to 52° API gravity) recovered during a drill-stem

test. 

Mean vitrinite reflectance values in exposed rocks on

the northern margin of the play were reported to range from

0.24 to 1.38 percent (0.82 to 1.29 percent in the Swauk

Figure 12 (facing page). Schematic map showing Northwestern

Columbia Plateau Gas play (501). Exploration wells compiled from

McFarland (1983), commercial Petroleum Information database

(Well History Control System), and Campbell and Reidel (1994).

CB, Chumstick basin; E, Ellensburg; EF, Entiat fault; HR-NR, Hog

Ranch-Naneum Ridge anticline; LF, Leavenworth fault zone; P,

Pasco; RHGF, Rattlesnake Hills gas field; SB, Swauk basin; SCF,

Straight Creek fault zone; W, Wenatchee, Y, Yakima; YM, Yakima

Minerals. Geology simplified from Walsh and others (1987), Stoffel and others (1991), and Tabor and others (1982, 1984).

CONVENTIONAL PETROLEUM PLAYS 27

Formation; 0.45 to 1.38 percent in the Roslyn Formation;

0.25 to 0.89 percent in the Chumstick Formation; V.A. Frizzell, Jr., unpub. data). Evans (1994) reported vitrinite reflectance values between 0.40 and 2.08 percent for surface

outcrops of the Chumstick Formation. Lingley and Walsh

(1986) reported vitrinite reflectance measurements from

subsurface coals sampled in four wells, including three that

penetrated basalt (table 3). In two of these wells, mean vitrinite reflectance values indicated only marginal maturity

(maximum values of about 0.6 to 0.7 percent), but for

sub-basalt sections in the other two wells, maximum values

range from 1.3 to 1.4 percent, suggesting that the coals could

have generated gas. 

Isotopic data demonstrate the presence of thermogenic

gas, probably derived from coals in sub-basalt strata, in

intra-basalt aquifers in the southern part of the play (Johnson

and others, 1993). Nineteen water wells located between

Yakima and Pasco have tested gas, and several have had

degassing equipment installed. 

Timing and migration of hydrocarbons.—Lopatin

modeling suggests that maturation of lower Eocene rocks

may have begun in the Oligocene, while maturation of middle Eocene and younger source rocks probably took place

during the Miocene during burial by 5,000 to 13,000 ft

(1,524 to 3,962 m) of the Columbia River Basalt Group

(Tennyson and Parrish, 1987). The presence of marginally

mature sedimentary interbeds in the lower part of the basalt

sequence (Lingley and Walsh, 1986; T. Walsh, Washington

Department of Natural Resources, oral commun., 1987) is

also consistent with Miocene maturation. Blackwell and others (1985) indicate that the geothermal gradient in the

Columbia basin now ranges from 28°C to 58°C/km, suggesting that the onset of peak gas generation could be presently

occurring at about 7,000 ft (2,134 m) in parts of the basin.

Traps.—The best potential structural traps appear to be

the large, Miocene and younger anticlines and fault-block

traps associated with deformation of the Columbia River

Basalt Group. Dipmeter data suggest that some pre-basalt

strata penetrated in the Yakima foldbelt wells conform with

structure mapped at the surface. However, some workers

(e.g., Saltus, 1993; Campbell and Reidel, 1994) have suggested that the youngest folds may not extend downward

into the pre-basalt sedimentary strata, and that sub-basalt

structural highs are not coincident with fold crests in basalt.

Eocene through early Miocene fold, fault, and stratigraphic

traps are also possible but cannot be readily located beneath

the thick basalt cover with present technology. The most

probable seals consist of shale interbeds in the fluvial

sequences or permeability barriers resulting from differences

in cementation or zeolitization.

Exploration status.—The only historical production for

this play was from the small Rattlesnake Hills gas field on

the east-southeast-trending Rattlesnake Hills anticline (fig.

12). The field was discovered during the drilling of a water

well in 1913, developed about 1930 after venting an

unknown amount of gas to the surface from open wells, and

abandoned in 1941. Total production was an estimated 1.3

BCFG (McFarland, 1979). Hammer (1934) reported gas

composition of 97.25 percent methane, 2.45 percent nitrogen, and 0.15 percent each oxygen and carbon dioxide. In

contrast, Wagner (1966) reported more than 80 percent

methane and about 10 percent nitrogen. Neither analysis

reported ethane or heavier hydrocarbons. The gas was

trapped in a faulted anticline between two vesicular zones in

basalt flows sealed by clay interbeds, at depths between 700

and 1,300 ft (213 to 396 m) (Hammer, 1934). The gas was

probably generated from coal within or below the basalt

(Johnson and others, 1993) or from a biogenic source

(Stevens and McKinley, 1995). In 1958, a deep test (Standard Oil Rattlesnake Hills No. 1) was drilled to 10,655 ft

(3,248 m) about 10 mi (16 km) west of the Rattlesnake Hills

gas field, but the well did not record any gas shows. The

rocks at the bottom of the well were volcanic and are

believed by S.P. Reidel (Washington State University, oral

commun., 1989) to belong the Columbia River Basalt

Group. 

Between 1980 and 1989, seven important test wells

were drilled in the northwestern Columbia basin to depths of

5,604 to 17,518 ft (1,708 to 5,339 m) (table 3). All were

located on the crests of large anticlines in Columbia River

Basalt Group, including one sited near the intersection of the

northwest-southeast-trending Hog Ranch–Naneum Ridge

anticline and the east-west-trending Frenchman Hills anticline. Most of the wells had gas shows, and drill-stem tests

were run in at least four of the wells. Notable test results

included 5.4 MMCFGPD and 6 BWPD in the Shell Oil

Company BN 1-9, and 570 MMCFGPD in the Yakima Minerals 1-33. The widespread occurrence of gas in these wells

indicates that gas accumulations are almost certainly present,

but the generally “tight” character of sub-basalt sandstones

appears to limit the chances for easily produced discoveries,

unless strategies for locating particularly good reservoir

facies can be developed.

Resource potential.—This play is considered to have a

high probability of at least a few, and possibly many, small

gas accumulations and a lower probability of large gas accumulations. Significant subcommercial flows of gas were

tested in several of the wells that penetrated the basalt, but it

has not been demonstrated that reservoir strata are of adequate quality, thickness, and lateral persistence to contain a

conventional gas accumulation larger than a few tens of

BCFG, despite the possible presence of traps big enough to

hold hundreds of BCFG. The thick basalt cover and associated difficulty this presents for exploration and the generally

poor character of potential reservoir sandstones are the primary discouraging factors for future exploration of this play.

For the recent U.S. Geological Survey 1995 National

Petroleum Assessment (Gautier and others, 1995), Tennyson

(1995) assessed the probabilities of suitable charge, reservoir

rock, and trap at 1.0, 0.6, and 1.0, respectively, yielding an
28 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

overall play probability of 0.6 for a gas accumulation larger

than 6 BCF (table 1). The size of the largest accumulation

expected at a 5 percent probability was estimated to be 1,000

BCF. This estimate is consistent with an analysis by Lingley

and Walsh (1986), who postulated accumulations with areas

of closure of 3,000 to 25,000 acres (12.1 to 101.2 km2),

depths of 5,000 to 14,000 ft (1,524 to 4,267 m), porosity of

6 to 18 percent, and a recovery factor of 60 percent, concluding that accumulations between 40 and 1,000 BCF were possible. The number of undiscovered accumulations greater

than 6 BCF was estimated to be between 1 and 100, with 10

accumulations assigned as the median. The mean undiscovered resource in the Northwestern Columbia Plateau Gas

play (501) was estimated to be 235 BCFG (table 2).

CONTINUOUS-TYPE PETROLEUM 

ACCUMULATIONS

In this report, two kinds of continuous-type hydrocarbon accumulations are discussed, coal-bed gas accumulations and basin-centered gas accumulations. The

methodology used in the 1995 National Assessment of

United States Oil and Gas Resources for assessing these

deposits differs from that used for conventional hydrocarbon

accumulations. For detailed explanations, see Schmoker

(1995) for the overall treatment of continuous-type accumulations and Rice and others (1995) for the specific treatment

of coal-bed methane deposits. General characteristics of

basin-centered accumulations are described in Law (1995a,

1995b)

The methodology used for estimating the recoverable

gas in basin-centered gas accumulations (Schmoker, 1995) is

different from that used in conventional accumulations.

Within the stratigraphic interval and play area selected for

analysis, a cell size is chosen. The size of the cell is based on

the area expected to be drained by wells in the play area. The

total number of cells in a play equals the area of the play

(mi2) divided by the cell size (mi2). Because of uncertainties

involved in the determination of the play area and cell size,

these values are treated as a frequency distribution. The next

step in the methodology is to establish an estimate of the ultimate recovery (EUR) probability distribution for the play.

The EUR probability distribution is determined by selecting

productive wells that are thought to be representative of the

play. The EUR of those wells is then plotted as a probability

distribution. This data is then entered into a computational

probability program developed by Crovelli and Balay

(1995). The results of the computation program are presented as a probability distribution represented as minimum

(100th fractile), maximum (0th fractile), and median values

(50th fractile).

COAL-BED GAS PLAYS

During the past 25 years, coal-bed gas has been produced from more than 5,400 wells in the United States and

now accounts for about 6 percent of total national gas

reserves and 3 percent of gas production (Rice and others,

1995). Most of the reserves and production are from the San

Juan basin of Colorado, New Mexico, and Utah, and the

Black Warrior basin of Alabama and Mississippi. Most

aspects related to the occurrence and development of hydrocarbons from coal are discussed in Law and Rice (1993).

Because of the immense quantities of coal-bed gas that could

be included in resource appraisals, the U.S. Geological Survey 1995 National Assessment of Oil and Gas Resources

(Gautier and others, 1995) estimated only those resources

that were judged capable of being added to U.S. oil and gas

reserves during the next few decades (by approximately

2020).

Coal-bed gas plays in Washington were defined on the

basis of factors that control the occurrence and productivity

of coal-bed gas. These factors include but are not limited to

coal thickness, heterogeneity, depth, and composition of

coal, seals, gas content, gas composition, permeability, pressure regime, local and regional structural setting (including

folds, faults, joints, cleats), and hydrology. Hydrology is

important because water production and disposal are important economic and environmental factors in field development. In general, coal-bed gas plays for potential additions to

reserves extend from depths of 500 to 6,000 ft (152 to 1,829

m) below the surface. 

Rice and others (1995) describe in detail the methodology used to assess coal-bed gas plays. Briefly, this method

involves the following: (1) defining and describing the

coal-bed gas play based on geologic criteria (discussed

above); (2) compilation of available relevant geologic data

needed for geological/engineering, computational, and economic assessment; (3) subdivision of the specific play area

into cells that generally equal the coal-bed gas well spacing

authorized by State regulatory agencies and determining the

number of untested cells in the play; (4) estimating the success ratio (values of 0 to 1.0) of untested cells in the coal-bed

gas play that are anticipated to produce gas; (5) Determining

the probability distribution of estimated ultimate recoveries

(EUR) from wells in potentially productive untested cells,

and (6) Estimating the probability (values of 0 to 1.0) that

one or more of the untested cells in the play will produce at

least the minimum EUR estimated for cells within the play.

Many of these steps rely on development of analogs and reservoir simulations from the productive San Juan and Black

Warrior basins. Three coal-bed gas plays are identified in

Washington and are described below.
CONTINUOUS-TYPE PETROLEUM ACCUMULATIONS 29

WESTERN WASHINGTON—BELLINGHAM BASIN 

PLAY (450)

Introduction.—This coal-bed gas play occupies the

same area as the conventional Bellingham Basin Gas play

(401) (figs. 3, 4, 5), and the geologic setting of this area is

described above under that play. Coals of the Paleocene(?) to

Eocene Chuckanut Formation are the potential gas reservoirs

in this play.

Coal occurrence.—Coals of the Lake Whatcom zone

and Bellingham interval of the Chuckanut Formation (Beikman and others, 1961) are exposed on the southern margin of

the Bellingham basin and should continue in the subsurface

of the basin to the north (fig. 5). The Lake Whatcom zone

includes about five coal beds ranging in thickness from 2 to

9 ft (0.6 to 2.7 m) (Beikman and others, 1961). The Bellingham interval contains two beds with thicknesses of 14 ft (4.3

m) and 2 ft (0.6 m) (Beikman and others, 1961). One of these

two intervals is probably correlative with the King Mountain

interval, recognized in the basin subsurface (P.D. Hurst,

Canadian Hunter Exploration, Ltd., written commun., 1992).

The King Mountain coal zone contains five to eight coal

beds with a mean bed thickness of 5 ft (1.5 m) and no beds

thicker than 10 ft (3.0 m). The King Mountain coal interval

has been penetrated at depths ranging from 1,700 to 3,700 ft

(518 to 1,128 m), depending on the location and structural

position of the well. Conchoidal fractures were observed in

sidewall cores of these coals, a positive indicator of a permeable cleat system (P.D. Hurst, Canadian Hunter Exploration,

Ltd., written. commun., 1992). Otherwise, there is no information on joints and cleats. 

Coal maturity.—The mean vitrinite reflectance of coals

in the King Mountain interval ranges from 0.5 to 0.55 percent at depths of about 1,700 ft (518 m) (P.D. Hurst, Canadian Hunter Exploration, Ltd., written. commun., 1992).

Mean vitrinite reflectance in coal exposed on the south flank

of the basin is 0.74 percent (Walsh and Lingley, 1991). 

Coal resources.—Beikman and others (1961) estimated reserves of approximately 310 million short tons (281

million metric tons) for coal beds more than 14 inches (36

cm) thick at depths of less than 3,000 ft (914 m) in and on the

flanks of the Bellingham basin. Moen (1969) and Vonheeder

(1977) subsequently raised the estimate to 366 million short

tons (332 million metric tons), of which about 37 percent is

measured or indicated and about 63 percent inferred. There

are no active coal mines in or on the margins of the Bellingham basin. 

Coal-bed gas exploration.—No wells have been drilled

in the Bellingham basin that were designed primarily as

coal-bed gas tests using current drilling and completion practices, and only four wells provide relevant information for

coal-bed gas evaluation. Mud-gas responses indicate that

methane and lesser propane is being liberated from coals

(P.D. Hurst, Canadian Hunter Exploration, Ltd., written.

commun., 1992). The propane has been attributed to the

presence of type-IIB kerogen in the coals. There is meager

data on the desorbtion and permeability of the coals. In one

well, King Mountain coals desorbed gas at 100 ft3/short ton

of coal (3.4 cm3/g), suggesting low maturity consistent with

vitrinite reflectance data. Isotopic analyses of gas seeps from

old well casings indicate a thermal origin with some biogenic mixing for gases (Hurst, 1991). There is no available

data on water composition in subsurface coal beds. 

Evaluation of resource potential.—There has been no

significant exploration for coal-bed gas in the Bellingham

basin, with information about possible coals deeper than

5,000 ft (1,524 m) lacking. Available information suggests

that low coal rank, steep dips, and low permeability will be

the main factors limiting development of a viable coal-bed

gas resource. Using the meager available data from the Bellingham basin and an analog from underpressured discharge

coal-bed reservoirs of the San Juan basin, Johnson and Tennyson (1995) estimated an overall play probability of 0.7, a

mean of 280 untested cells, a success ratio of 0.5 for untested

cells, and a mean estimate of ultimate recovery for untested

cells of 413 MMCF gas. These estimates yield mean potential gas reserve additions for the entire play of 40.5 BCF

(table 4). 

WESTERN WASHINGTON—WESTERN CASCADE 

MOUNTAINS PLAY (451)

Introduction.—This coal-bed gas play occupies essentially the same region as the conventional Southeastern

Puget Lowland Gas play (402) (figs. 3, 4, 6); the geologic

setting of this region is described above under that play.

Coals of the undifferentiated Puget Group and the Tiger

Mountain, Renton, Carbonado, and Spiketon Formations

(fig. 2) are the potential coal-bed gas reservoirs in this play.

Coal occurrence.—Beikman and others (1961)

describe the stratigraphy of coal bearing strata at nine locations within this play: (1) Newcastle–Grand Ridge area; (2)

Renton area; (3) Tiger Mountain and Niblock areas; (4) Taylor area; (5) Green River district; (6) Wilkeson-Carbonado

coal field; (7) Spiketon area; (8) Fairfax-Montezuma and

Ashford areas; and (9) Eastern Lewis County. Each area is

characterized by its own nomenclature for coal seams. For

example, the Green River district includes at least 16 coal

beds assigned to the Franklin coal zone and the Kummer coal

zone. These Green River district coals occur in a section

about 6,300 ft (1,920 m) thick and have a cumulative minimum thickness of 73 to 90 ft (22 to 27 m) (Vine, 1969). The

Green River district probably represents the area with the

most coal in this play. In other areas, the coal-bearing section
30 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

commonly interfingers with and pinches out against volcanic

rocks (Gard, 1968; Vine, 1969). 

The lack of uniformity in stratigraphic and coal nomenclature across this play area reflects the difficulty in correlation of units and markers induced by structural complexity,

the lenticular nature of coal beds, and the presence of locally

interbedded volcanic rocks. Structural relief in the play area

is considerable. For example, the Franklin coal zone is being

strip-mined from the axis of an anticline about 1.2 mi (2 km)

north-northeast of Black Diamond (fig. 6). Nearby petroleum

exploration wells have encountered the same stratigraphic

level at depths of 5,000 ft (1,524 m) or more.

Coal maturity.—Mean vitrinite reflectance values in

surface and subsurface coals range from 0.35 to more than

2.0 percent in the play area, increasing eastward toward the

axis of the Cascade Range (Walsh and Lingley, 1991). Mean

vitrinite reflectance in the surface section near Black Diamond (fig. 6) range from 0.42 to 0.68 percent. Pappajohn and

Mitchell (1991) reported mean vitrinite reflectance values

from coal-bed gas exploration drilling near Wilkeson (fig. 6)

of 0.84 to 1.03 percent. In the eastern Lewis County area

(north of Morton), mean vitrinite reflectance values range

from 0.6 to 0.8 percent at the surface (as high as 2.21 percent

near intrusions), and from 0.96 to 1.69 percent in the upper

2,000 ft (610 m) of the subsurface. These rocks have been

uplifted and (or) deformed.

Coal resources.—Beikman and others (1961) estimated

reserves of approximately 1,230 million short tons (1,116

metric tons) for coal beds more than 14 inches (36 cm) thick

and at depths of less than 3,000 ft (914 m) in the area of this

play. Of this amount, about 33 percent is measured or indicated and 67 percent is inferred. These estimates are

probably conservative. There is one active coal mine in this

area, operated since 1986 by the Pacific Coast Coal Company near Black Diamond (fig. 6). Total production in the

John Henry No. 1 mine has exceeded 1 million short tons

(907,200 metric tons), and the current annual production has

grown to about 300,000 short tons (272,200 metric tons)

(Brownfield and others, 1994). Coal is being strip-mined

along the axis of a tight anticline.

Coal-bed gas exploration.—Since 1986, 15 wells that

can be broadly considered coal-bed gas wells have been

drilled in the area of this play. A few wells underwent

extended production testing, and good gas shows were

encountered in several wells (S. Pappajohn, Carbon Energy

International, oral commun., 1993). There is presently no

coal-bed gas production. 

Pappajohn and Mitchell (1991) report desorbtion values

ranging from 6.8 to 17.6 cm3/g for five coal beds penetrated

by drilling in the Wilkeson area (fig. 6). The history of methane-related underground mine accidents in the region and the

presence of gas bubbling to the surface through ponds in the

John Henry No. 1 mine are further indicators of gassy coals.

Steve Pappajohn (Carbon Energy International, oral commun., 1993) reports that there are well-developed cleats in

some of the coals encountered by drilling in this play area;

however, there is no available data on joints, cleats and coal

permeability. Pappajohn and Mitchell (1991, table 5) present

analytical data from water produced from coal seams in the

Wilkeson area that indicates the water meets State and Federal requirements for surface discharge. 

Evaluation of resource potential.—In the Western

Washington—Western Cascade Mountains play (451), available information suggests that structural complexity and (or)

Table 4. Coal-bed gas in Washington.

[Comparison of U.S. Geological Survey estimates of undiscovered technically recoverable coal-bed gas with that

of other selected States and geologic provinces. Information from Gautier and others (1995) and U.S. Geological

Survey National Oil and Gas Resource Assessment Team (1995, table 5). Fractile values (F95, F5) are not additive. F95 represents a 19 in 20 chance and F5 represents a 1 in 20 chance of the occurrence of at least the amount

tabulated]

Gas (trillion cubic feet)

Selected play, State, or geologic province F95 F5 Mean

estimate

Western Washington—Bellingham Basin (450) 0.00 0.09 0.04

Western Washington—Western Cascade Mountains (451) 0.00 0.93 0.54

Western Washington—Southern Puget Lowlands (452) 0.00 0.27 0.12

TOTAL, Washington 0.70

Piceance basin, Colorado 5.47 10.09 7.49

San Juan basin 5.76 9.67 7.53

Southwest Wyoming 0.83 7.66 3.89

Black Warrior basin, Alabama and Mississippi 1.49 3.43 2.30

North Appalachian basin, New York, 

Pennsylvania, Ohio, West Virginia 7.68 16.36 11.48

TOTAL ESTIMATE, lower 48 States* 42.89 57.63 49.91

*Total for lower 48 States is not a sum of the selected areas listed on this table.
CONTINUOUS-TYPE PETROLEUM ACCUMULATIONS 31

poor permeability may be the limitations on developing a

coal-bed gas resource. Much of the area is tightly folded and

cut by faults, making exploration difficult and limiting reservoir continuity. Drilling results have also indicated that gas

has locally escaped through steeply dipping coal beds that

have breached the surface (S. Pappajohn, Carbon Energy

International, oral commun., 1993). 

Using the available data from this play and an analog

from the Piceance Basin–Western Basin Margin play (2054),

Colorado, Johnson and Rice (1995) estimate an overall play

probability of 0.9, a mean of 1,072 untested cells, a success

ratio of 0.4 for untested cells, and a mean of the EUR distribution for untested cells of 1,401 MMCF gas. These estimates yield mean potential gas reserve additions for the

entire play of 541 BCF (table 4). This estimate is significantly less than previous estimates (Choate and others,

1984).

WESTERN WASHINGTON—SOUTHERN PUGET 

LOWLANDS PLAY (452)

Introduction.—This coal-bed gas play occupies the

same region as the eastern part (east of long 123°10'W.) of

the Washington portion of the conventional Cowlitz-Spencer Gas play (407) (figs. 3, 4, 11); the geologic setting of this

region is described above under that play. Coal of the Skookumchuck and Cowlitz Formations are the potential

coal-bed gas reservoirs (fig. 2) in this play. 

Coal occurrence.—Coals belong to the upper middle to

upper Eocene Skookumchuck Formation in the northern part

of play and to the Cowlitz Formation in the southern part of

the play. Thirteen coal beds with a cumulative thickness of

about 88 ft (27 m) have been recognized in a 2,600-ft-thick

(793 m) section of the Skookumchuck Formation (Snavely

and others, 1958). Approximately 70 ft (21.3 m) of coal in

seven beds has been recognized in a 500-ft section (152 m)

of the Cowlitz Formation on the southwest margin of the

Chehalis basin (P. Hales, Weyerhaeuser Corp., written commun., 1995). Several coal beds occur in the subsurface of the

Chehalis basin at depths as great as about 6,000 ft (1,829 m).

Wireline log analysis suggests that the cumulative thickness

of coal may be greatest in the Chehalis basin. 

Coal maturity.—Coals in this play range in rank from

lignite to subbituminous B (Beikman and others, 1961).

Mean vitrinite reflectance of surface coal in the Skookumchuck Formation in the Centralia area ranges from about

0.35 to 0.40 percent, and values from subsurface coal in the

Chehalis basin ranges from 0.4 to 0.7 percent (Walsh and

Lingley, 1991). Coal of the Cowlitz Formation in the southern part of the play is generally of lower grade with mean vitrinite reflectance values less than 0.4 percent.

Coal resources.—Beikman and others (1961) estimated reserves of approximately 3,810 million short tons

(3,456 million metric tons) for coal beds more than 14 inches

(36 cm) thick and depths of less than 3,000 ft (914 m) in the

area of this play. Of this amount, about 55 percent is measured and indicated and about 45 percent is inferred. The

play area includes the Centralia mine, from which approximately 100 million short tons (97 metric tons) have been produced since 1971. 

Coal-bed gas exploration.—No coal-bed gas wells

have been drilled in this play. The absence of exploration

interest here no doubt reflects the low thermal maturity of the

coals. 

Evaluation of resource potential.—The most favorable

aspect of the play is the great volume of relatively shallow

coal. The least favorable aspect of the play is the low thermal

maturity of the coal. Using stratigraphic and maturity data

and an analog from underpressured discharge coal-bed reservoirs of the San Juan basin, Johnson and Rice (1995) estimate an overall play probability of 0.6, a mean of 774

untested cells, a success ratio of 0.5 for untested cells, and a

mean ultimate recovery for untested cells of 500 MMCF of

gas. These estimates yield mean potential gas reserve additions for the entire play of 116 BCF (table 4). This estimate

is notably smaller than previous estimates of Choate and others (1984).

BASIN-CENTERED GAS 

ACCUMULATION PLAYS

Basin-centered gas accumulations, another type of continuous gas accumulation, also occur in many petroleum

provinces. These gas accumulations, unlike discrete conventional accumulations, are regionally pervasive and sometimes extend over thousands of square miles and through

thousands of feet of stratigraphic section. This resource presently accounts for approximately 10 percent of total gas production in the United States and is expected to play an even

more significant role in the energy requirements of the

nation in the future (National Petroleum Council, 1992). 

There is no single characteristic that uniquely defines a

basin-centered gas accumulation. However, the following

list of attributes facilitate identification: (1) the presence of

regionally extensive accumulations that occupy the more

central, deeper parts of basins, (2) the absence of down-dip

water contacts, (3) the presence of reservoirs that are abnormally over- or under-pressured relative to normal, hydrostatic pressures, (4) the abnormally pressured fluid phase is

gas, (5) gas reservoirs are overlain by a normally pressured

transition zone containing gas and water, (6) there is little or

no producible water in reservoirs, (7) reservoirs have low

permeability, commonly less than 0.1 mD, (8) gas is of thermogenic origin, (9) the source of gas is from interbedded and

(or) adjacent rocks, (10) the distance of gas migration from

the source rock is relatively short compared to migration distances that may occur in conventional accumulations, (11)

the top of the gas accumulation occurs at 0.7 to 1.0 percent
32 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

vitrinite reflectance, (12) structural and stratigraphic trapping aspects are of secondary importance, and (13) the “seal”

is a relative permeability barrier. Because it is unlikely that

all these characteristics can be identified in any single well,

the most important characteristics to recognize are abnormal

pressures, thermal maturity, and the abnormal pressure fluid

phase.

WILLAMETTE–PUGET SOUND 

BASIN-CENTERED GAS (412)

Introduction.—The Puget-Willamette Lowland

trough, located immediately west of the Cascade Range in

Washington and Oregon, contains several smaller basins

that include the Tualatin and Nehalem basins in Oregon

and the Chehalis, Tacoma, Seattle, and Everett basins in

Washington (figs. 1, 6, 7, 11) (Johnson and others, 1994,

1996; Niem and others, 1994). These forearc sub-basins

are filled with Eocene and younger sedimentary rocks that

were deposited in nonmarine to marine depositional systems and may be as thick as 30,000 ft (9,146 m). Only a

few wells have been drilled in this play area that are deep

enough to determine the presence of a basin-centered gas

accumulation (Law, 1995b). Subsurface data from two

wells (the Exxon GPE Federal Community No. 1 well

located in northwestern Oregon (Niem and others, 1994),

and the Phillips State No. 1 well located east of Tacoma in

the Puget Lowland (McFarland, 1983)) were drilled to

depths of 11,287 ft (3,441 m) and 12,920 ft (3,939 m),

respectively. The top of abnormally high reservoir pressure

occurs in these wells at depths of 8,000 to 9,600 ft (2,439

to 2,926 m), and the levels of thermal maturity at these

depths are about 0.8 percent mean vitrinite reflectance

(Walsh and Lingley, 1991; Stormberg, 1992). These relationships, in conjunction with the presence of interbedded

coal beds and low-permeability reservoirs, suggest the

presence of a basin-centered gas accumulation. The spatial

and areal distribution of basin-centered gas accumulations

in this hypothetical play cannot be determined with available data.

Reservoirs.—Sandstone reservoirs in this play occur in

Eocene and possibly older rocks. Borehole data indicate that

gas-bearing reservoirs occur in an interval that is at least

3,300 ft (1,006 m) thick. The bottom of the potential

basin-centered gas accumulation is not known because the

entire gas-bearing interval has not been penetrated. Eocene

sandstones that are likely to form reservoirs in Washington

are probably arkosic in composition (Buckovic, 1978; Frizzell, 1978; Johnson and Stanley, 1995). These sandstone

units contain significant proportions of lithic fragments and

mica that are likely to be altered and compacted during

diagenesis. No porosity or permeability data are available

from the reservoirs in the overpressured interval, but qualitative estimates are low. Limited data indicate that the top of

the overpressured, basin-centered gas accumulation ranges

from 8,000 to 9,600 ft (2,439 to 2,926 m). The bottom of the

reservoirs is at least 13,000 ft (3,963 m). 

Source rocks.—In the absence of source rock analyses,

the most likely sources of gas are the interbedded coal beds

and carbonaceous shales. The levels of thermal maturity at

the top of the gas accumulation in the Phillips State No. 1

well (Walsh and Lingley, 1991) are sufficiently high (mean

vitrinite reflectance = 0.8 percent) to generate gas from available organic matter. Published and unpublished source rock

analyses from various rock units in the Pacific Northwest

indicate that nearly all of the organic matter is a type-III kerogen and capable of generating mainly gas (Law and others,

1984; Sidle and Richers, 1985; Lingley and von der Dick,

1991). 

Timing and migration.—Because gas is generated

within, or in close proximity to reservoirs in basin-centered

gas accumulations, the temporal relationships between gas

generation, migration, and development of a trap are not

nearly as important as they are in conventional accumulations. It is uncertain when the reservoirs penetrated by the

Phillips State No. 1 and Exxon GPE Federal Community

wells were charged with gas. Present-day temperatures at

depths of 8,000–9,600 ft (2,439 to 2,926 m) are about 130°F

to 150°F (40°C to 51°C), too low to have achieved the

present level of thermal maturity at present depths. Therefore, this area has experienced higher temperatures in the

past.

Traps and seals.—See the discussion of the character of

traps and seals needed for basin-centered gas accumulations

in the introduction to this section.

Exploration status.—The Willamette–Puget Sound

Basin-Centered Gas play (412) has not been explored. Previous exploration activity in the play area has focused on traditional structural plays. Due to a lack of information, this play

was not quantitatively evaluated for the 1995 National

Assessment of Oil and Gas Resources (Gautier and others,

1995; Law, 1995b).

COLUMBIA BASIN—BASIN-CENTERED GAS PLAY (503)

Introduction.—This hypothetical play underlies the

widespread Miocene Columbia River Basalt Group in eastern Washington (Law, 1995a) (figs. 1, 4). The play area is

nearly the same as that for the conventional Northwestern

Columbia Plateau Gas play (501) (figs. 3, 12), and its geologic setting is described above under that play. The few

wells that have been drilled through the Columbia River

Basalt Group show that it has variable thickness that is commonly in excess of 5,000 ft (1,524 m). The sub-basalt rocks

consist mainly of lower Tertiary fluvial and lacustrine rocks

that were deposited in structurally complex basins; these

rocks have highly variable thicknesses (e.g., Taylor and others, 1988; Evans and Johnson, 1989; Evans, 1994).
DISCUSSION 33

Interpretations of subsurface data from six widely spaced

wells indicate the presence of a basin-centered gas accumulation. The well data show that the top of a thick, overpressured interval begins at depths ranging from 8,300 to 12,700

ft (2,530 to 3,872 m). Within the overpressured interval,

large amounts of gas have been recovered on drill-stem tests.

Although some water has also been recovered, most of the

zones recovered gas with no water. The areal and spatial

extent of the accumulation are imprecisely known because of

insufficient deep drilling.

Reservoirs.—The potential reservoirs consist of

Eocene arkosic fluvial sandstone bodies that are exposed on

the northern margin of the play and consist of the Swauk,

Chumstick, Roslyn, and Manastash Formations (Tabor and

others, 1982, 1984; Taylor and others, 1988; Evans, 1994).

The quality of these reservoirs is unknown. Surface exposures of the rocks on the play margins contain significant

proportions of lithic fragments and micas (Frizzell, 1978;

Taylor and others, 1988; Evans, 1994), and diagenetic alteration of these less-stable minerals is likely to produce low

permeability. Porosity values ranging from 6 to 15 percent

have been calculated from well logs (Lingley and Walsh,

1986). The thickness of the gas-bearing interval is at least

6,400 ft (1,951 m). The maximum thickness is unknown

because the gas-bearing interval has not been entirely penetrated by drilling. Based on analysis of well logs, the depth

of reservoirs within the play ranges from 8,300 (2,530 m) to

more than 17,000 ft (5,183 m). 

Source rocks.—The sources of gas are assumed to be

the Eocene coal beds and carbonaceous rocks that are interbedded with reservoir rocks. Regional source-rock studies in

Washington and Oregon indicate that nearly all organic matter in the region is a type-III kerogen, capable of generating

mainly gas with little liquids (Law and others, 1984; Sidle

and Richers, 1985; Core Laboratories, 1987a, 1987b). The

level of thermal maturity within the gas-bearing interval

ranges from 0.8 to more than 1.0 percent vitrinite reflectance

(Lingley and Walsh, 1986; Core Laboratories, 1987a,

1987b), sufficient to generate gas.

Timing and migration.—Because gas is generated

within or in close proximity to reservoirs in basin-centered

gas accumulations, the temporal relationships between gas

generation, migration, and development of a trap are not critical. It is not known when the reservoirs were charged with

gas. It appears as though present-day temperatures are in or

near equilibrium with measured levels of thermal maturity.

Maximum burial occurred in the late Miocene, following

eruption and deposition of the Columbia River Basalt Group. 

Traps and seals.—See the discussion of the character of

traps and seals needed for basin-centered gas accumulations

in the introduction to this section.

Exploration status.—The play is unexplored. There are

five wells that penetrate the gas accumulation; the last of

these was drilled in 1988. Several production tests have been

conducted, revealing gas flows at initial rates of as much as

3.1 MMCFD. Previous exploration activity in the play area

has focused on more conventional structural plays. There is

no indication that the region has been evaluated in the context of basin-centered gas accumulations.

Evaluation of resource potential.—Methodology

developed by Schmoker (1995) was used to estimate

resource potential of the Columbia Basin—Basin-Centered

Gas play (503). Because of the hypothetical nature of the

play, the Greater Green River Basin–Mesaverde play (3741),

Wyoming, was used as an analog. Cell sizes of 80 and 160

acres were chosen. The number of cells under the two scenarios were 51,096 and 25,548; success rations were 0.7 and

0.8, respectively. The mean EUR was 1,421 MMCFG. In

addition, the estimation of liquid hydrocarbons utilized a

ratio of 10 barrels per MMCFG. With this input data, the

mean estimate of potential reserve additions is 12,200.1

BCFG and 122.0 MMB of natural gas liquids (table 5) (Law,

1995b). 

DISCUSSION

Although Washington has no current petroleum production, the above play descriptions and associated resource

estimates (tables 1–2, 4–6) indicate the State includes many

possible petroleum systems with commercial potential.

Because there is no petroleum production in Washington,

there are fewer constraints on petroleum assessments than

for developed regions and States. We reiterate that this relative lack of constraints makes it likely that other petroleum

geologists may develop resource estimates somewhat different from ours.

The estimates of table 2 suggest that Washington has

mean undiscovered technically recoverable conventional oil

and gas resources of about 19 MMBO and 586 BCFG,

respectively. We infer that the most significant resources are

in the Northwestern Columbia Plateau Gas play (501), with

a mean assessed resource of 235.10 BCFG and a 5 percent

probability of 1.120 TCFG. Table 6 places Washington’s

estimated conventional oil and gas resources in perspective

through comparison to other selected States and geologic

provinces. Oregon, for example, has a similarly low inferred

resource base, whereas Alaska’s conventional oil and gas

resources are estimated to be more than two orders of magnitude larger. Mean estimates of Washington’s oil and gas

conventional resources are just 0.07 percent and 0.23 percent, respectively, of the estimate for the total onshore

United States (U.S. Geological Survey National Oil and Gas

Resource Assessment Team, 1995, table 1). 

Table 4 shows that estimates of Washington’s coal-bed

gas resources (700 BCFG) are relatively small compared to

those of the San Juan and Black Warrior basins (7.53 and

2.30 TCFG, respectively), where most national production

of coal-bed gas is now carried out. Washington’s estimated

coal-bed gas resource forms about 1.4 percent of the
34 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

estimated cumulative coal-bed resource for the onshore

lower 48 States (U.S. Geological Survey National Oil and

Gas Resource Assessment Team, 1995, table 5). 

Table 5 shows that the resource estimate for Washington’s Columbia Basin—Basin-Centered Gas play (503) is

relatively similar to that of the petroliferous San Juan and

Uinta-Piceance basins of the Rocky Mountain region, and

represents about 4 percent of the total estimate for continuous-type gas accumulations (exclusive of coal-bed gas plays)

in the onshore United States. Washington’s Columbia

Basin—Basin-Centered Gas play (503) resource is also estimated to be about 17 times larger than the State’s estimated

coal-bed gas resource (table 4) and 21 times larger than

Washington’s estimated conventional gas resource (tables 2,

6). Attanasi and others (1995, table 3) estimate that the

threshold gas price for development of the Columbia

Basin—Basin-Centered Gas play (503) resource is more than

$9 per MCF, which is significantly higher than the 1995 market price (about $1.50 per MCF) and also greater than the

estimated threshold price for a majority of other continuous-type gas plays recognized in the United States (Gautier

and others, 1995). In contrast, the economic analysis of Donnelly and others (1995) suggests that this unconventional gas

play may shortly become economic. 

Regardless of economics, the Columbia Plateau region

of eastern Washington holds the State’s greatest potential for

large fields that can have regional and national significance

in meeting energy demands. Plays in western Washington

will probably never provide a significant proportion of

national or regional petroleum requirements; however, given

the costs of transporting petroleum (including building and

supporting infrastructure), it is possible that western Washington’s petroleum resources can have local significance. For

example, daily production at the Mist field (about 60 BCFG)

in northwest Oregon (Bruer, 1980; Niem and others, 1994)

has been as high as 13 MMCF and provided as much as about

7 percent of Portland’s gas supplies. Future hydrocarbon

exploration in western Washington will no doubt concentrate

on resources that would be used locally within the Pacific

Northwest.

The lack of larger and richer petroleum systems in

Washington can be attributed to its geologic history. Considerable Cenozoic sedimentary rock is present, having formed

in a variety of strike-slip (Eocene) and forearc, intra-arc, and

trench basin (Oligocene and younger) settings. Several

strike-slip basins in California (such as the Los Angeles basin

(table 6)), Venezuela, and elsewhere are very petroliferous,

as are numerous forearc basins (such as the Sacramento basin

(table 6) or Alaska’s Cook Inlet)—so these basin types are

not by nature poor habitats for petroleum resources. 

Perhaps the most prominent limiting factor for Washington basins is the lack of good source rocks. In California’s

Neogene strike-slip basins, marine rocks of the Monterey

Formation were deposited in many environments restricted

from the influx of clastic sediments. In contrast, strata in

Washington’s Eocene strike-slip basins are predominantly

nonmarine, rich in clastic sediments, and deposited at high

sediment-accumulation rates (Johnson, 1985). These high

rates probably precluded the origin of good organic-rich

lacustrine facies, which provide the source beds for petroleum systems in other nonmarine basins (e.g., the

Uinta-Piceance basin, table 6). Marine rocks (Eocene and

younger) in the Grays Harbor and Tofino-Fuca basins of the

Coast Range are also generally clastic rich and organic poor,

again suggesting that sediment supply was a limiting factor

on the development of good regional source rocks. 

The quality of reservoir rocks is an additional limiting

factor to development of significant petroleum accumulations in Washington, although not as important as the relative

absence of good source rocks. Although many sandstone

Table 5. Gas resources in continuous-type plays (excluding coal-bed gas plays).

[Comparison of U.S. Geological Survey estimates of undiscovered technically recoverable gas resources for the

Columbia Basin—Basin-Centered Gas play (503) with that of continuous-type plays in selected geologic provinces. Information from Gautier and others (1995) and U.S. Geological Survey National Oil and Gas Resource Assessment Team (1995). Fractile values (F95, F5) are not additive. F95 represents a 19 in 20 chance and F5

represents a 1 in 20 chance of the occurrence of at least the amount tabulated]

Gas (trillion cubic feet)

Selected play or geologic province F95 F5 Mean

estimate

Columbia Basin—Basin-Centered Gas (503) 2.80 30.87 12.20

Uinta-Piceance basin (parts of Colorado and Utah) 11.55 23.38 16.74

San Juan basin, Colorado (parts of New Mexico, and Utah) 10.66 36.84 21.15

Southwestern Wyoming 55.95 213.51 119.30

Western Gulf (parts of Texas and Louisiana) 1.82 3.67 2.63

Appalachian basin (parts of New York, Pennsylvania, 

West Virginia, Ohio, Virginia, Kentucky, 

Tennessee, Georgia, Alabama) 43.12 83.66 61.21

TOTAL ESTIMATE, onshore United States* 219.36 416.55 308.08

*Total for onshore United States is not a sum of the selected areas listed on this table.
REFERENCES CITED 35

units lack significant porosity and permeability due to diagenetic alteration of abundant volcanic lithic debris (e.g., Galloway, 1974), there are also some excellent reservoirs, such

as the Eocene sandstone beds used for gas storage in the Chehalis basin (Wurden and Ford, 1976). The best sandstone

reservoirs are clearly the arkoses derived from crystalline

source terranes to the east. These arkosic sandstones predominate in Eocene rocks (Frizzell, 1978; Johnson, 1985),

which formed prior to latest Eocene initiation of the Cascade

volcanic arc. Arkosic sandstones are also present, but in less

abundance, in Neogene strata of southwest Washington (for

example, parts of the Astoria and Montesano Formations;

(fig. 2) sourced by the paleo-Columbia River drainage). 

Suitable traps and seals are present for most plays. The

most notable exception is the Western Washington Melange

play (405), in which tectonic processes associated with subduction have probably disrupted and caused breaching in

many potential reservoirs. Faulting along the west flank of

the Cascade Range may have also compromised the integrity

of sandstone and coal-bed reservoirs in the Southeastern

Puget Lowland Gas play (402), the Puget Lowland Deep Gas

play (403), and the Western Washington—Western Cascade

Mountains play (451).

CONCLUSIONS

Washington hosts numerous possible petroleum systems, but there is no current petroleum production in the

State. These possible petroleum systems are hosted by

sedimentary rocks deposited in Eocene strike-slip basins and

late Eocene and younger intra-arc, forearc, and trench

basins. Eight conventional petroleum plays, three coal-bed

gas plays, and two continuous-type gas plays can be delineated in order to analyze and assess the resource potential of

these possible petroleum systems. In these plays, the potential for significant petroleum accumulations is clearly greatest in the Columbia Plateau region of eastern Washington.

Potential accumulations in western Washington are smaller

but could have local economic significance. The absence of

suitable source rock is probably the most important factor

limiting development of large accumulations, although

development of suitable reservoirs, traps, and seals also limits some plays. Play analysis indicates that Washington’s

petroleum resources are small and unlikely to have a significant impact on meeting the Nation’s energy needs. Development of local petroleum resources, however, could be

important in serving local economies. 

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Crude oil Gas

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or geologic province Mean Mean 

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Oregon 0.00 0.32

Alaska 8.44 68.41

Sacramento basin, Calif. <0.01 3.32

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36 PETROLEUM GEOLOGY OF THE STATE OF WASHINGTON

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