GEOLOGICAL SURVEY CIRCULAR 730

Geologic Appraisal of the 

Petroleum Potential of 

Offshore Southern 

California: The 

Borderland Compared to 

Onshore Coastal Basins
Geologic Appraisal of the 

Petroleum Potential of 

Offshore Southern 

California: The 

Borderland Compared to 

Onshore Coastal Basins

By James C. Taylor

GEOLOGICAL SURVEY CIRCULAR 730

1976
United States Department of the Interior

THOMAS S. KLEPPE, Secretary

Geological Survey

V. E. McKelvey, Director

Library of Congress Cataloging in Publication Data

Taylor, James Carlton, 1924-

Geological appraisal of the petroleum potential of offshore southern California.

(Geological Survey circular ; 730)

Includes bibliographical references.

1. Petroleum in submerged lands California, Southern. 2. Petroleum Geology California, Southern. 3. Gas, Natural, in submerged lands California, Southern. 4. Gas 

Natural Geology California, Southern. I. Title. II. Series: United States. Geological Survey. Circular ; 730.

QE75.C5 no. 730 [TN872.C2] 553'.28'097949 76-608074

Free on application to Branch of Distribution, U.S. Geological Survey 

1200 South Eads Street, Arlington, Va. 22202
CONTENTS

Abstract ______________________

Introduction _________________________

Acknowledgments ___________________

Geologic setting of the southern California region 

Oil and gas in onshore California basins ____ 

Oil and gas in Califomia coastal basins ______

Distribution of petroleum in coastal basins ___ 

Field size ___________._________

Age ________________

Reservoir rock type _______________

Oil and gas geology southern California borderland ___________________________

Oil and gas seeps ____________________

Offshore wells ____________________

Page

1

2

2

2

4

5

5

5

10

11

12

13

15

Oil and gas geology southern California 

borderland Continued

Sediment thicknesses _ .

Potential petroleum source rocks __-__.

Organic maturity ___ ____ __.

Organic maturity of Paleogene and 

Neogene samples _______ _ _.

Potential petroleum reservoir rocks _ _. 

Paleogene age ___________ _ _.

Neogene age . 

Potential petroleum traps _ ___________

Petroleum resource estimates _ - _ . 

Conclusions ______________ _ _ ____.

References cited __________ ___ __ _.

Page

15

19

21

24

26

26

26

28

30

32

33

ILLUSTRATIONS

Page

FIGURE 1. Index map of continental borderland of southern California showing inner and outer basin 

areas _______________________________________ __ -_ ______ __

2. Cumulative production and estimated recovery of oil and gas from known fields in onshore 

and offshore basins of California __________________________ _ ___ _ --

3. Histogram of cumulative production by age and basin for basins west of the San Andreas 

fault _________________________________________________-__ 

4. Size distribution of fields larger than 20 million barrels in basins west of San Andreas fault

5. Areas of the borderland under less than 200 m water __________-_________ __ ___

6. Core holes and stratigraphic tests drilled on the borderland prior to the Supreme Court's 

ruling in January 1966 on the State-Federal boundary _______________________ _

7. Organic carbon content (weight percent) of dart outcrop samples of Eocene and Oligocene 

age and inferred limits of Paleogene sediments ______________________ _____

8. Organic carbon content (weight percent) of Miocene dart cores ____________________ _

9. Organic carbon content (weight percent) in Holocene sediments from basin floors, outer 

slopes, and ocean floor _________________________________ ______________

10. Source rock analysis chart with organic carbon content plotted against hydrocarbon for Eocene-Oligocene and Miocene samples _________________ ________________ ____

11. Original and interpreted northeast-southwest seismic profile across Tanner Bank, showing 

paleontologically dated samples _____________________ ____________ _ _____

7

9

14

16

18

22

23

24

29

TABLES

TABLE 1. 59 largest fields in coastal basins west of San Andreas fault _____________________ __

2. Distribution of petroleum by stratigraphic age for coastal basins west of the San Andreas 

fault _____________________________________________________

Page

10

III
Page

TABLE 3. Summary of organic chemistry on dart samples by stratigraphic age, southern California

borderland _____________________________________________________________ -__ __ 20

4. Estimated undiscovered recoverable resources, southern California borderland _____________ 31

5. Major fields: Los Angeles basin _______________________________________________ __ 39

6. Major fields: Ventura basin ___________________________________ _________________ 39

7. Major fields: Santa Maria basin ___________________________ ______ _ __ 40

8. Major fields: Cuyama basin ____________________-_--_-_-__-_---_-------- ____________ 40

9. Major fields: Salinas and central coastal ______-__- - --- ----- - _- 40

10. Organic geochemistry of dart samples from the southern California borderland and Miocene outcrop samples from the southwestern Santa Ynez Mountains ______________ - 41

1.1. Organic geochemistry of Eocene outcrop samples, San Nicolas Island _- 43

DEFINITIONS

Reserve terminology varies between agencies. Data 

on reserves of oil and gas have been obtained from the 

American Petroleum Institute (API) and their terms 

(API, 1975, p. 14-17) in italics are compared to those 

of the U.S. Department of Interior (Miller and others, 

1975, p. 8-9).

Measured (proved) reserves of crude oil "are the 

estimated quantities of all liquids statistically defined 

as crude oil, which geological and engineering data 

demonstrate with reasonable certainty to be recoverable 

in future years from known reservoirs under existing 

economic and operating conditions" (API, 1975, p. 17).

Indicated (indicated additional) reserves are those 

"additional recoveries in known reservoirs (in excess 

of proved reserves) which engineering knowledge and 

judgment indicate will be economically available by application of fluid injection (or other improved recovery 

techniques), whether or not such program is currently 

installed" API, 1975, p. 14, 22).

Ultimate recovery represents the "sum of cumulative 

production to date plus the current estimate of proved

reserves" (API, 1975, p. 17). This term is not used by 

U.S. Department of Interior.

Demonstrated reserves are "the sum of measured and 

indicated reserves" (Miller and others, 1975, p. 9).

Inferred reserves are "reserves in addition to demonstrated reserves eventually to be added to known fields 

through extensions, revisions, and new pays" (Miller and 

others. 1975, p. 9). The API has no equivalent term.

Resources are the "concentrations of naturally occurring solid, liquid, or gaseous materials in or on the 

Earth's crust in such form that economic extractions of 

a commodity is currently or potentially feasible" (Miller and others, 1975, p. 8).

Undiscovered resources (undiscovered reserves) are 

"quantities of a resource estimated to exist outside of 

known fields on the basis of broad geologic knowledge 

and theory" (Miller and others, 1975, p. 8).

Identified resources are the "specific accumulations 

of economic resources whose location, quality, and quantity are estimated from geologic evidence supported in 

part by engineering measurements" (Miller and others, 

1975, p. 8).

IV
Geologic Appraisal of the Petroleum Potential of

Offshore Southern California: The Borderland

Compared to Onshore Coastal Basins

By James C. Taylor

ABSTRACT

Offshore southern California is part of a much larger 

Pacific continental margin, and the two areas have a 

similar geologic history at least as far back as middle 

Tertiary time. Assessment of the petroleum potential 

of the offshore Southern California borderland is accomplished by examining the adjacent highly explored 

productive coastal basins in the tectonically unstable 

area west of the San Andreas fault. Known oil and gas 

accumulations in this region can be characterized as 

follows: 88 percent comes from the Los Angeles and 

Ventura basins; 87 percent has been found in late Miocene and younger strata and only 0.2 percent has been 

found in Eocene strata; 80 percent has been found in 

thick deposits of deep-water turbidite reservoirs; and 

5 percent has been found in fractured Miocene siliceous shale reservoirs. The percentage of siliceous shale 

reservoirs will increase as a result of recent discoveries 

in this rock type in the Santa Barbara Channel. Of the 

212 known fields only 5 are giants (greater than 500 

million barrels), and these fields account for 52 percent of all past production from the region. Most fields 

are faulted anticlines, and the largest fields have the 

highest oil recoveries per acre.

Geologic knowledge of the offshore is limited by the 

availability of data. Data have been obtained from 

geophysical surveys, analyses of bedrock samples from 

the sea floor, and extrapolations of data from the 

mainland and offshore islands. Several factors have a 

negative effect on the assessment of the petroleum potential of the southern California borderland. They are:

1. The Neogene section is relatively thin, and the 

Paleogene section is thin and has a limited distribution.

2. Over large areas, Miocene sediments apparently 

rest directly on basement.

3. Along much of the Santa Rosa-Cortes Ridge, sediments are uplifted and truncated, exposing 

Paleogene rocks.

4. Organic content in Paleogene sediments is believed 

too low to generate large amounts of petroleum.

5. Source rocks are immature, even in sediments as 

old as Eocene.

6. Burial and thermal history are insufficient for the 

generaton of hydrocarbons over much of the 

borderland area.

7. Documented oil and gas seeps are unknown seaward of the Channel Islands.

8. Limited exploratory drilling nearshore, the best 

prospective area, has not been favorable.

9. Adequate or thick reservoirs of deep-water turbidite origin are not evident.

These negative factors are partly offset by the following positive factors:

1. Miocene sediments are excellent potential source 

rocks.

2. Asphaltic oil in rocks of Monterey-type lithology 

may be generated at lower than normal temperatures.

3. Shallow-water sands of reservoir quality possibly 

are present in the uppermost Paleogene and 

lowermost Neogene section.

4. Potential structural traps may be analogous to 

major structural producing trends onshore.

5. Fractured shale reservoirs may be present along 

flanks of major banks and ridges.

6. Buried and unsampled Paleogene and Late Cretaceous sediments may be better source rocks than 

those sampled and measured.

The southern California borderland, although a part 

of a locally rich petroliferous region, has no known 

basins with geologic histories or characteristics similar 

to the Los Angeles and Ventura basins. Some offshore 

basins are similar to less endowed basins in terms of 

petroleum potential such as the Santa Maria and Salinas 

basins. Areas with the best petroleum potential may be 

in deep water (greater than 500 m). Some of the past 

high estimates of the petroleum potential may have 

been overstated; the existing geologic data tend to substantiate low estimates of 0.6 to 5.8 billion barrels of 

oil and 0.6 to 5.8 trillion ft3 of gas for the southern 

California borderland at the 5 and 95 percent probability level.
INTRODUCTION

Public concern about the availability of adequate energy resources has led to reevaluatioHs 

of the remaining petroleum reserves and the 

potential but as yet undiscovered petroleum resources of the United States (Miller and others, 

1975). The continental shelves are believed to 

hold large quantities of undiscovered oil and 

gas resources. After executive action in January 1974 calling for the increased exploration 

of the Federal outer continental shelf areas, the 

southern California borderland was nominated 

as the first of these frontier areas to be leased. 

The area lies adjacent to the Los Angeles basin, 

one of the richest oil basins in the world, and is 

immediately south of the productive Ventura 

basin. Also in the region numerous offshore 

fields had been discovered in the 3-mile offshore 

zone of California State waters. The first offshore development was in 1896 when wells were 

drilled from wooden piers in the Summerland 

field. Additional discoveries in State waters occurred after the first California tideland leasing 

act in 1921 and continued as other similar acts 

were passed in 1938, 1955, and 1957 (Frame, 

1960, p. 6-9). Several additional discoveries 

have been made after Federal leasing in February J968 in the Santa Barbara Channel, an offshore extension of the Ventura basin (Wilson, 

1975).

This is one of several U.S. Geological Survey 

reports based on continuing study of the geology of the borderland (Vedder, Wagner, and 

Schoellhamer, 1969; Vedder and others, 1974, 

1976; Campbell and others, 1975; Sasnett and 

others, unpub. data; Junger and Wagner, unpub. data; Howell, 1975; Roberts, 1975; Greene 

and others, 1975; Greene, Silver, and von 

Huene, 1975; Wolf, 1975; Wagner, 1975; Vedder, 1975; Moore and Beyer, 1975; Moore and 

McCulloch, 1975). This report is a synthesis of 

geologic knowledge as it pertains to an appraisal of the petroleum potential of this area. The 

area to be evaluated (fig. 1) is approximately 

equal to that studied by Vedder and others 

(1974) and includes that part of the borderland 

that lies seaward from the shoreline to the base 

of the continental slope and between 34° N latitude west of Mugu Canyon and 32°N latitude 

west of the U.S.-Mexico boundary. This area 

covers more than 21,600 mi2 and has been divided into an inner basin and an outer basin 

area.

ACKNOWLEDGMENTS

Special appreciation is expressed to George 

Claypool for his expertise and services on the 

organic chemical analyses, to R. E. Arnal and 

J. D. Bukry for paleontological determinations, 

to R. M. Egbert and M. L. Randall for assistance in the statistical tabulations of production. 

I am especially grateful to J. G. Vedder and 

E. W. Scott for contributing their knowledge of 

the area, and to B. M. Miller and G. L. Dolton 

of the USGS Resource Appraisal Group and to 

R. F. Mast, for their interest and many helpful 

suggestions.

GEOLOGIC SETTING OF THE SOUTHERN 

CALIFORNIA REGION

The borderland has been referred to as the 

offshore continuation of the California mainland (Emery, 1960; Parker, 1971). Consequently, this study of its petroleum potential 

draws heavily on comparisons of the borderland with presumed analogous onshore basins 

where the petroleum exploration has been intense, the geology is much better known, the 

factors governing accumulations of oil and gas 

are generally agreed upon, and probably all of 

the giant oil fields (greater than 500 million 

barrels) have already been discovered. A synopsis of the distribution and characteristics of 

major accumulations onshore and the factors 

controlling their occurrence is a natural starting point for assessing the offshore potential.

Classification of basins by tectonic setting 

has been recently reviewed by Halbouty (Halbouty and others, 1970). The productive basins 

in California all occur on intermediate-type 

crust at the borders of present or former continental plates, and the San Andreas fault separates the Sacramento and San Joaquin basins 

of the Great Valley from the coastal basins to 

the west (fig. 2). The Tertiary tectonic history 

of these two areas is sufficiently different to 

justify excluding the Great Valley as a valid 

analog to the borderland. Major deformation 

occurred mainly on the west side of the San 

Joaquin Valley where wrenching along the San 

Andreas fault produced oblique and en enchelon
BATHYMETRIC CONTOURS IX METRES 

0 9 10 20 90 40 KILOHITRtt

0 9 n 19 20 NWITIML MILES

® Columnar uetionthown on ih«it4, 

U.S.6.S. MF.624, 1974

PUENTE 

HILLS j,

POINT/:. 1 .'.; 1.:. 

ARGUELLO/.', 1 .'.:'. . ': . SANTA V NEZ

FIGURE 1. Index map of continental borderland of southern California showing inner and outer basin areas.
anticlines and local intense folding, thrust faulting, and local unconformities. This structural 

style (Wilcox and others, 1973), which reflects 

the movements along the San Andreas fault, 

decreases eastward into the center of the San 

Joaquin basin. The Sierra Nevada granitic 

block and its continuation under much of the 

Great Valley had a pronounced stabilizing effect 

on the overlying sediments deposited during 

Tertiary time. In contrast, the entire area west 

of the San Andreas fault was intensely deformed, and each of the resulting Tertiary 

basins had its own unique tectonic and depositional history.

The Late Cretaceous and Cenozoic history of 

the onshore area west of the San Andreas can 

be divided into two intervals: from Late Cretaceous to the end of Paleogene time, and from 

early Miocene time to the present. The earlier 

interval began with local sedimentation in Late 

Cretaceous time after extensive erosion of the 

basement complex. Remnants of these Cretaceous sediments are now best exposed in the 

northern Transverse Ranges, the Santa Monica 

Mountains, and on the flanks of the Peninsular 

Ranges, which extend from the Los Angeles 

region south into Baja California. Extensive 

subsidence and deposition occurred during 

Paleogene time. Deep-water Eocene sediments 

were deposited over much of what is now the 

western Transverse Ranges, the Santa Barbara 

Channel, and the San Diego area and farther 

north in the Coast Ranges south of San Francisco. They also occur in the northern Channel 

Islands and San Nicolas Island. After gradual 

filling of these marine basins, regional uplift, 

erosion, and continental deposition occurred in 

Oligocene time and locally extended into early 

Miocene time.

The second interval began in early Miocene 

time with the deposition of shallow-water sands 

of the Vaqueros Formation during the beginning of a major marine transgression. The 

transgressive sands were overlain by the most 

widespread accumulation of deep-water sihale 

in all the Pacific west coast. These rocks include the early to middle Miocene Rincon Shale, 1 

the Miocene Monterey Formation, and late Miocene shales represented by the Sisquoc, Puente,

1 The Oligocene-Miocene boundary is in dispute, but for this 

paper it is considered to occur within the Zemorrian Stage. Consequently, the Vaqueros and Rincon Formations are considered no 

older than early Miocene.

Modelo, and Capistrano Formations. The Monterey typically includes large percentages of 

siliceous shale and diatomite as well as dolomitic, calcareous, and phosphatic shale. Early 

Miocene time also marked the beginning of extensive volcanism, increased tectonism with 

downwarpings of basins of more limited size 

than characterized the Paleogene, and renewed 

and continuing strike-slip movements on major 

faults, especially on the San Andreas fault 

(Clarke and Nilsen, 1973). During late Miocene 

and Pliocene time the Los Angeles and Ventura 

basins subsided rapidly, accumulating thick deposits of bathyal sediments derived from adjacent uplifted areas. Most of these Neogene 

basins approximate those that exist today but 

were modified by intense deformation during 

Pliocene and Pleistocene time. This second interval is still in progress; some of the basins 

are completely filled, others such as the Los 

Angeles, Ventura, and Santa Maria basins are 

nearly filled on their landward margins, and 

others are only partly filled, such as some on 

the borderland where present sedimentation is 

occurring at bathyal depths in excess of 1,000 m 

(3,280ft).

OIL AND GAS IN ONSHORE CALIFORNIA 

BASINS

The distribution of oil and gas in California 

basins on the basis of cumulative production 

plus demonstrated reserves 2 in known fields is 

shown in figure 2. The state's total oil production to January 1, 1975, has been 16,753 million 

barrels, and demonstrated reserves include 

measured reserves (3,557 million barrels) and 

indicated reserves (1,349 million barrels) for a 

current estimate of recoverable oil expected 

to total 21,659 million barrels (American Petroleum Institute, API, 1975). These estimates 

include only reserves from known fields; they 

do not include inferred reserves,2 reserves in 

discovered but as yet unproduced fields, future 

discoveries of new fields, or additional recoveries resulting from technological advances in 

recovery methods or significant changes in economic conditions.

To evaluate the distribution of petroleum in

2 For definition of terms see table of contents at beginning of 

report.
California basins and specifically the fields in 

the coastal basins, cumulative production figures to January 1, 1975, have been used rather 

than current estimates of total recovery or estimates of original-oil-in-place. Reserve figures 

which are necessary for estimating total recovery (that is, cumulative production plus measured reserves), are published only for entire 

state (API, 1975) and for those fields with recoveries expected to exceed 100 million barrels 

of oil (Oil and Gas Journal, 1975a). If measured reserves for all fields were available, a 

ranking of fields based on estimated recoveries 

would not be appreciably different from that 

based on cumulative production, nor would this 

data change the percentage of total recoverable 

oil attributed to the largest fields. Published 

figures show that the 42 largest fields in California (Oil and Gas Journal, 1975a) have reserves of 4,109 million barrels, or 84 percent of 

the 4,906 million barrels of reserves from all 

California fields. Original oil-in-place is reported (API, 1975, p. 29-32, p. 75) for the 

state, but there are no figures for individual 

fields in California.

Secondary recovery is increasingly important 

to current oil production in California, with 

portions of 102 fields undergoing water-flooding 

and 75 low-gravity fields being stimulated by 

steam and (or) hot water injection. Secondary 

recovery by steam now accounts for 34 percent 

of the present annual production in California 

(Conservation Committee of California Oil 

Producers, CCCOP, 1975, p. B). Most of the 

fields with low-gravity crude contributing to 

this percentage are in the San Joaquin Valley; 

the San Ardo field is the major contributor of 

the fields in the coastal region (CCCOP, 1975, 

table XXIII-B). The indicated additional reserves of 1.3 billion barrels of oil reported by 

the American Petroleum Institute reflect the 

importance of planned and future secondary 

recovery programs from known fields within 

the state.

OIL AND GAS IN CALIFORNIA COASTAL 

BASINS

Over one-half of the cumulative production 

(and estimated recovery) in California basins 

is attributed to the coastal basins west of the 

San Andreas fault (fig. 2). In the accompanying

tables on field and basin statistics, cumulative 

production plus demonstrated reserves are 

available only for the largest fields. Therefore, 

cumulative production has been used. Because 

our concern is how much energy might be derived from the borderland, produced gas has 

been converted to BOE (barrels of oil equivalent), assuming that 6,000 ft3 of gas has the 

approximate BTU value of one barrel of oil. 

This conversion allows an easy comparison between gas, oil, and oil and gas fields. The tables 

list both cumulative production of oil and oil 

plus BOE. For comparative purposes, the distribution of petroleum in the coastal basins is 

reviewed not only by basin but also by field 

size, stratigraphic age of the reservoir, the 

reservoir rock type, and the traps in which this 

oil and gas occurs. Offshore resources would be 

expected to be found in similar situations if offshore and onshore basins are truly analogous.

The amount of petroleum decreases in the 

coastal basins from south to north (figs. 2 and 

3). The Los Angeles basin has accounted for 37 

percent of the state's total production and 66 

percent of the total production of the coastal 

basins. The Ventura basin is next in size with 

22 percent of the total production from the 

coastal basins, followed by Santa Maria basin 

with 6 percent, Cuyama basin with 3 percent, 

and Salinas and other coastal basins with a total 

of 3 percent. The geology that affects this distribution needs to be understood; otherwise the 

proximity of the Los Angeles and Ventura 

basins with 88 percent of the petroleum may 

unduly influence the estimates of potential petroleum resources in the borderland.

DISTRIBUTION OF PETROLEUM IN 

COASTAL BASINS

FIELD SIZE

The magnitude of the estimated resource of 

any basin or frontier area such as the borderland will depend on discovery of major fields. 

Most of the total world discovered resources, 

including those in North America, are in giant 

fields (greater than 500 million barrels) 

(Moody and others, 1970). This distribution is 

also true for California basins (tables 5-9). 

Some major characteristics of the fields in the 

coastal basins west of the San Andreas fault
Basin

Cumulative production Estimated 

to January 1, 1975 x recovery 2 

(millions of barrels) 

Oil + BOB 3 Oil Oil + BOB 3

San Joaquin __._ --__-_ ____ 

Los Angeles ... __-__---_ 

Ventura __-_-----_--- _ ____ 

Sacramento ___________________

Santa Maria __________________

Cuyama __ __ ___ 

Salinas (and central coastal) __

Eel River . _ ____ __ 

State total ________._._ 

Coastal basins west of San 

Andreas fault .-. _.____

8,340

7,860

2,646

989

736

318

292

10

6,860

6,721

1,967

7

643

276

279

21,190

11,852

16,753

9,886

' 5 .« 11,297

9,398

4,927

4 1,327

Included

in

Ventura 

basin 5 

7 14

8 26,963 

5 - 8 14,325

SOUTHERN

CALIFORNIA

BORDERLAND

THIS REPORT

100 KILOMETRES

FIGURE 2. (See caption at top of facing page.) 

6
FIGURE 2. Cumulative production and estimated recovery2 of oil and gas3 from fields in onshore and offshore8 basins of California. Late Tertiary offshore 

basins in the Outer Continental Shelf (OCS) area 

north of the borderland are outlined.

1 Compiled from Conservation Committee of California Oil Producers (CCCOP, 1975).

2 Estimated recovery is sum of cumulative production plus estimated reserves compiled by American Petroleum Institute (API, 

1975). These include: estimated proved oil reserves plus indicated 

additional oil reserves (API, 1975, p. 14, 23), and estimated total 

proved reserves of natural gas (API, 1975, p. 102, 114) equated 

to barrels of oil equivalent (see 3), all from known reservoirs.

3 Gas equated to oil on approximate BTU energy equivalent, that 

is, 6,000 ft3 of gas equals one barrel of oil (BOE == barrel oil 

equivalent).

4 Nonassociated gas reserves (as BOE) allocated on past production (88 percent for Sacramento basin, 11 percent for San Joaquin 

basin, and 1 percent for Cuyama basin). *

3 Cuyama basin's remaining oil and associated gas reserves included in San Joaquin basin total.

6 Oil and associated gas from the Brentwood field included in 

total for San Joaquin basin.

7 Estimated remaining gas reserves, from California Div. Oil 

and Gas (1975, p. 132).

8 Reserves do not include discovered but as yet not produced 

offshore fields in Federal waters in the Santa Barbara Channel: 

Santa Ynez Unit; Santa Clara Unit; Pitas Point Unit.

87%

r 10,300

BASINS AND % 

OF PRODUCTION

LOS ANGELES 

VENTURA 

SANTA MARIA 

CUYAMA

SALINAS

66%

22%

6%

3%

3%

5.3%

4.7%

2.8%

0.2%

^600

-400

-200

LU 

O 

00

O 

CO_l

00

00

CD

g

Q 

O

tr 

o_

ID

O

EOC. OLIG. E.M. M.M. L.M.-P.

INCREASING AGE

FIGURE 3. Histogram of cumulative production by age and basin for basins west of the San Andreas fault. 

Cumulative production is to January 1, 1975, and is expressed in billions of barrels of oil plus BOE (gas to 

barrels of oil equivalent). See table 2 for values and references. EOC, Eocene time, OLIG, Oligocene; E.M., 

early Miocene time; L.M., late Miocene time; P, Pliocene time.

are listed in table 1. A cumulative curve (fig. 4) 

shows the dominance of the five giant fields 

which account for 52 percent of the total oil 

produced. The distribution of the fields on the 

plot is approximately log normal. Some fields

with continuous structures and reservoirs that 

have been considered as separate fields because 

of their discovery and (or) development history, are grouped as one field in this report; this 

includes the two largest fields shown on table 1.
TABLE 1. 59 largest fields in coastal basins west of San Andreas fault

[Ranked by cumulative production, showing current estimates of total recovery (where available) and main characteristics]

Field and basin: C, Cuyama; LA, Los Angeles; S, Salinas; SM, 

Santa Maria; V, Ventura'.

Cumulative production to 1-1-75: BOB barrels oil equivalent of 

gas at approximate BTU energy value, 6,000 ft3 gas = one 

barrel oil.

Current estimate of total recovery: From American Petroleum Institute estimates of remaining reserves for fields with "ultimate recoveries" greater than 100 million barrels oil (Oil and 

Gas Journal, 1975a).

Cumulative percent of basin total: Based on cumulative production of oil plus BOE to January 1, 1975.

Main reservoir type: DM sd, d^ep-marine sand; SM sd, shallowmarine sand; C sd, continental sand; F sh, fractured shale; 

cgl, conglomerate.

Trap type: A, anticline; D, dome; H, homocline; N, nose; F, 

fractured; S, stratigraphic variations, pinch-outs, permeability 

seals.

Barrels per acre recoveries: Based on cumulative production of 

oil plus BOE to January 1, 1975.

Cumulative 

production to 

1-1-75 

106 bbls

Field and basin

Torrance 2 _ _ _ _ _ _ _ __

Wilmintgon trend (LA) ______________

San Miguelito _ _ ._. _ _ _ _ _

Ventura-San Miguelito (V) _ __ ._ _

Honda (V) 1 _________ . ___ ______

Santa Fe Springs (LA) _ ___________

Brea-Olinda (LA) (includes 

Sansinena) . 

Inglewood (LA) ___ _ _ _ _. _______

Dominquez (LA) __ __ ... ____ __ _

San Ardo (S) _._ ___.________

Coyote West (LA) ________ ______

Cuyama South (C) _ _ _ __________

Seal Beach (LA) _ _________________

Montebello (LA) ____________________

Santa Maria Valley (SM) ____________

Richfield (LA) . ___ _ .-___.

Orcutt (SM) ________________________

Rincon (V) 1 ____ _ .. _ ________

Cat Canyon West (SM) ______________

South Mountain (V) (excludes 

Bridge Pool).

Elwood (V) 1 .. ___ . ._ __ .. ._

Coyote East (LA) _ ______ ______

Dos Cuadras (V) _ . _ __ ______

Beverlv Hills (LA) ___ ____ ______

Newhall Pot-ero (V) _ __ ____ _

Salt Lake (LA) __ ... _________ .

Saticov (V) (includes Bridge Pool) . 

Playa Del Rey (LA) ____________

Russell Ranch (C) ___ . .. __ ..

Carninteria offshore (V) 1 _ .. __ ...

Yorba Linda (LA) _________________

Whittier (LA) _. __ _ _. ..

Las Cienegras (LA) _. _.___

Lompoc (SM) __ _ . ______ _ ...

Newport West (LA) 1 ___.__ _.______

Cheviot Hills (LA) .. .. ____________

Montalvo West (V) 1 . _ _________

Placerita (V) _______________________

Del Valle (V)

Gato Ridge (SM) _________________

Summerland offshore (V) 1 __ _ .__

Cat Canyon East (SM) __ ..... _ ...

Oxnard (V) ___ . __ . __ . ________

Molino offshore (V) 1 . ._ ... .. __ .

Casmalia (SM) ___ .... _. .

Honor Rancho (V) _ . _ ___ ___

Shiells Canvon (V) ____ ___ __

Romona (V) _. _ __._._ _ .. _._

Bardsdale (V) __ .... _____ _____

Los Angeles City (LA) ______ . ____

Guadalupe (SM) . _ ...... ____ _

Potrero (LA) _____ .. ____________

See footnotes at end of table.

BOE

1,844 

203

2,092

1,124 

84

1.208

1,060 

1,054

0

741

469

336 

321 

286 

264 

243 

222

220

196 

194

173

153 

153

125

123 

118 

113

111 

104

83 

80 

76 

75

72 

69 

51 

50

49 

49 

47

46 

45 

42

42 

41 

40

38 

38 

38 

37 

35 

34

32 

30 

26 

25 

24 

24 

24

Oil

1,681 

45 

182

1,902

793

58

851

878 

924

0 

601

390

297 

258 

274 

232 

209 

188

185

159 

165

149

124 

137

93

90 

103

98

102 

79 

70 

49 

57 

63

65 

50 

45 

50

42 

42 

40

44 

23 

34

41 

25 

36

24 

38 

34 

0 

27 

32

26 

23 

20 

13 

22 

22 

14

Current 

estimate 

of total 

recovery 

108 bbls 

Oil

2,376 

39 

200

2,634

882 

3 65

947

899 

1,043

4 1,000 

611

415

321

268 

378 

250 

220 

200

190

186 

181

162

144 

5 185

<100 

104 

103

175 

109

:::::

Cumulative 

percent 

of 

basin 

total

2 58

17.7

27.9 

36.9 

45.8

45.8 

52.1

56.1

58.9 

61.6 

64.0 

66.2 

68.3 

70.2

72.1

73.8 

75.4

76.9

78.2 

79.5

80.6

81.6 

82.6 

83.6

84.5 

85.4 

86.1 

86.8 

87.4 

88.0

88.6 

89.2 

89.6 

90

90.4 

90.8 

91.2

91.6 

92.0 

92.4

92.8 

93.1 

93.4

93.7 

94.0 

94.3 

94.6 

94.9 

95.2

95.5 

95.8 

96.0 

96.2 

96.4 

96.6 

96.8

Provincial 

age 

of 

main 

reservoir

L. Mio. to 

E. Piio.

E. Plio.

L. Mio. 

E. Plio. 

L. Mio. 

E. Plio. 

M. Mio. 

L. Mio. to 

E. Plio. 

L. Mio. to 

E. Plio. 

E. Plio. 

E. Plio. 

L. Mio. 

E. Plio. 

E. Mio. 

L. Mio. to 

E. Plio. 

L. Mio. to 

E. Plio. 

L. Mio. 

L. Mio. to 

E. Plio. 

M. to L. 

Mio. 

L. Plio. 

M. toL. 

Mio. 

OliEr. to E. 

Mio. 

L. Mio. 

E. Mio. 

L. Mio. to 

E. Plio. 

E. Plio. 

L. Mio. 

L. Mio. 

E. Plio. 

L. Plio. 

L. M;o to 

E. Plio. 

E. M''o. 

M. Mio. 

E. Plio. 

E. Plio.

L. Mio. 

L. Mio. 

M. toL. 

Mio. 

L. Mio. 

L. Mio. 

Olisr./L. 

Plio. 

L. Plio. 

L. Mio. 

M. to L. 

Mio. 

E. Mio. 

E. Plio. 

Olig. 

E. Mio. 

L. Mio. 

M. toL. 

Mio. 

L. Mio. 

Olig. 

L. Mio. 

Olig. 

L. Mio. 

E. Plio. 

L. Mio.

Main 

reservoir 

type

DMsd

DMsd 

DMsd 

DMsd

Fsh 

DMsd

DMsd

DMsd 

DMsd 

SMsd 

DMsd 

SM sd 

DMsd

DMsd

Fsh 

DMsd

Fsh

DMsd 

Fsh

Csd

DMsd 

SMsd 

DMsd

DMsd 

DMsd 

DMsd 

DMsd 

DMsd 

DMsd

SMsd 

DMsd 

DMsd 

DMsd, 

cgl 

DMsd 

DM sd 

Fsh

DMsd 

DMsd 

Csd/ 

DMsd 

DMsd 

DMsd 

Fsh

SMsd 

SMsd 

Csd 

SMsd 

DMsd 

Fsh

DMsd 

Csd 

DMsd 

Csd 

DMsd 

SMsd 

DMsd

Trap 

type

FA

FA

FA 

FA

A 

D

FA. FH, 

FN. S 

FA 

FA 

A 

FA 

FA, FH 

FA

A. FN

FH, S 

A

FA, FD

FA, S 

FA

FA

FA 

A 

FA

FA 

FA 

FA 

FA. FH 

FH 

A

FH, FA

FN 

FA 

FH

A, FH 

FA 

FA

FA

FA, FS 

FA

FH 

FH, FA

FA

FA 

FH, S 

FH 

FA 

FA 

FA

FA, S 

FA 

FA 

FA 

FA 

FH 

FA, FH

Maximum 

productive 

acres

14,500 

760 

7,273

22,533

3,480 

500

3.980

1,815 

6.290

1,480 

2,430

1,215 

1,670 

4,490 

1,125 

2.560 

870

1,600

7,630 

1,600

4,730

2,110 

2,980

3,210

725 

1,050 

1,505

1,200 

1,310 

1,490 

1.165 

640 

600

1.550 

1,100 

215

855

1,080 

970 

2,290

1,328 

820 

1,860

760 

660 

740

830 

3,470 

1,860 

1,130 

1,640 

2,690

720 

1,045 

590 

590 

780 

1,840 

365

Bbls 

per 

acre 

recoveries

127,172 

59,211 

27,911 

92,842

322,989 

168,000 

303,518 

584,022 

167,568

500,676 

193,416

276,543 

192,216 

63,697 

234,667 

94,922 

255,172

137,500

25,653 

120,976

36,515

72,720 

45,831

38,920

169,577 

112,135 

75,056

92.245 

79,621 

55,958 

68945 

118,936 

124,627

46.437 

62.766 

235.851 

58,782

45.823 

50.300 

20,630

34,286 

55.284 

23,015

55,500 

61,800 

53,830

45,984 

10,984 

20,205 

32,507 

21,074 

12,706

44,669 

29,016 

43,561 

42,639 

31,403 

13,204 

64,942
TABLE 1. 59 largest fields in coastal basins west of San Andreas fault Continued

Cumulative 

production to Current 

. . __ estimate 

i iTiJi °f total

108 bblS TP«n»>rv

Field and basin

Capitan (V) . ___ ___ ____ .

Torrev Canyon (V) __ __ .. .

Zaca Creek (SM) . ______ _

Total 60 fields _______ .

Other 153 fields ______ .

Total all fields _______ .

Oil +

BOE

___ 23

___ 22

.. __ 22

22

. ___ 21

___ 11,551

. ___ 301

. __ 11,852

10° bbls

Oil Oil

21 ___

on

19

1 S

20 .....

9,657 .....

229 .....

9,886 ° 12,153

Cumulative 

percent 

of

basin

total

97 0

O7 9

97 4

97 6

97.8

2.2

100

Provincial 

age 

of 

main

reservoir

Olig. E.

Mio.

Olig.

Olig./E.

Mio.

Olig.

M. toL.

Mio.

Main 

reservoir

type

SMsd

Csd

Csd/

SMsd

Csd

Fsh

Maximum 

producTrap

type

FA

FH, FA, FS

FD

FD

FH

tive

acres

330

2,030

330

260

490

Bbls 

per 

acre

recoveries

69,973

10,791

66,167

83,700

42,649

1 All or part of field in offshore.

2 From National Petroleum Council (McCaslin, 1975).

3 No data; calculated as percent of cumulative production.

4 Undeveloped major field in Santa Ynez Unit. Reserves estimated at 94,000,000 bbls by American Petroleum Institute (Oil and Gas 

Journal, April 31, 1975); 1-3 billion for Santa Ynez Unit (Oil and Gas Journal, January 27, 1975); and 3 billion for Santa Ynez Unit 

by National Petroleum Council (McCaslin, 1975).

5 Remaining reserves of 48 million barrels includes those for Cat Canyon East.

8 Estimated "ultimate recovery" based on cumulative oil production to January 1, 1975 plus API estimates (1975) of oil reserves plus 

indicated additional reserves from known oil fields.

Most of the production from the 18 largest 

fields (greater than 100 million BOE) has come 

from the Los Angeles basin.

Thorough exploration in California has probably found all of the giant fields that exist onshore. The remaining undiscovered oil onshore

100-i

75-

z

UJ

o ft:

UJ

o. 

ui

5 

ID 

o

50-

25-

ooooooo *

50 100 500 1000 5OOO 

CUMULATIVE PRODUCTION IO6 BBLS, OIL + BOE

1 -^

10

1

30

1

40

2500

-2000

-1500

cn

UJ

o:

CD

U. 

O

-I O

^ m

-1000 o

20 30 40 50 

FIELDS, IN DECREASING SIZE

60

- 500

- 100

0 

212

H O O -'

13 

o 

o ft:

5 

13 

O

FIGURE 4. Size distribution of fields larger than 20 million barrels in basins west of the San Andreas fault. Fields 

are plotted in order of decreasing size and by cumulative percent of the total production in these basins. The 

insert shows the cumulative distribution on logarithmic scale. Note that the plot follows a, linear trend indicating a log normal distribution. Field size is based on cumulative production to January 1, 1975. Barrels 

are expressed as barrels of oil plus gas as barrels of equivalent oil (see text).
is not expected to significantly vary the field 

size distribution and will not appreciably increase the current estimates of 21,659 million 

barrels of recoverable oil. This conclusion is 

supported by the low discovery rate of new 

fields in the coastal basins over the past few 

decades and the current estimated recoveries 

from those new fields (American Petroleum Institute, 1975). In the last 20 years new reserves 

have accounted for 1.2 billion barrels of oil plus 

BOE, which amount to only 8.3 percent of the 

estimated recoverable reserves in the coastal 

basins. This is true despite the fact that most 

of these discoveries came from areas not previously available for exploration; the state lands 

in the Santa Barbara Channel; the urbanized 

areas of Los Angeles (McFarland and Greutert, 

1971) ; and San Pedro Bay (exclusive of Wilmington, which was discovered in 1932). The 

analogous coastal basins now account for 56 

percent of California's total cumulative production, but this percentage should increase as production increases from newly discovered but as 

yet unproduced fields in the Santa Barbara 

Channel, such as the Santa Ynez Unit, where 

reserves are estimated as high as 3 billion barrels (McCaslin, 1975, p. 232), and the newly 

discovered Santa Clara Unit.

AGE

The concentration of oil in the late Miocene 

and younger reservoirs in California basins has 

often been noted. Table 2 shows the distribution 

of petroleum production by chronostratigraphic

age in the coastal basins west of the San Andreas fault.

A histogram (fig. 3) reemphasizes the high 

percentage attributed to these late Miocene and 

younger reservoirs; 87 percent or 10,307 million barrels (oil + BOE). Oil reserves decrease 

markedly with the age of the reservoir, and the 

Eocene reservoirs have only 0.2 percent of the 

total (approximately 19 million barrels), which 

is concentrated in the eastern Ventura basin. 

The Oligocene reservoirs (2.8 percent or 329 

million barrels), occur in fields in the Ventura 

basin; most oil (303 million barrels) is found 

in fields on the south flank of the basin onshore 

and a smaller concentration (26 million barrels) occurs along the northern, coast of the 

Santa Barbara Channel, mainly in the Elwood 

and Capitan fields. Early Miocene reservoirs 

(4.7 percent or 555 million BOE) are found 

almost entirely in two areas, the fields along 

the north side of the Santa Barbara Channel 

(253 million barrels) and those in the Cuyama 

basin (282 million barrels). Most of the middle 

Miocene production (5.4 percent or 642 million 

barrels) comes from fractured siliceous shale 

in the Santa Maria basin, (with minor production from fractured shale in the Los Angeles 

basin) and from sandstone reservoirs in the 

eastern Ventura basin. Very little sand was deposited during this period of widespread marine 

transgression, but some is found locally adjacent to the few elevated areas that remained 

positive during this period. Recent discoveries 

in the Santa Ynez Unit will increase the perTABLE 2. Distribtition of petroleum by stratigraphic age for coastal basins west of the San Andreas fault

[Based on cumulative production to January 1, 1975, in million of barrels, oil plus BOE gas]

Basin Eocene Oligocene

early 

Miocene

middle 

Miocene

late 

Miocene

Total

Los Angeles 1 _ _ __ ____

Santa Barbara 3 __

Cuyama 5 ___________

Salinas 5 _ _ _ _

Total __ __ _____

Percentage of total __ _ _

0

19

18

1

0

0

0

19

0.2

0

329

303

9fi

0

0

0

329

2.8

0

259

6

253

14

282

0

555

4.7

20

68

65

3

555

0

2

642

5.4

7,840

1,971

1,805

166

170

36

290

10,307

87.0

7,860

2,646

736

318

292

11,852

100

1 Percentages from Gardett (1971, p. 303).

2 Percentages derived from ultimate recoverable reserves (Nagle and Parker, 1971).

3 Percentages and age designation derived from Conservation Committee of California Oil Producers (1975) and California 

Division of Oil and Gas (1974).

4 Percentages from Crawford (1971).

5 Age designation from California Division of Oil and Gas (1974).

10
centage of production from these middle Miocene reservoirs, for fractured shale is the main 

reservoir in the Hondo field, the largest field in 

this unit (U.S. Geological Survey, 1974).

Considering the tectonic activity that occurred during middle and late Miocene time, the 

distribution of pre-middle Miocene reservoirs 

may have a marked bearing on potential size 

and location of reservoirs of similar age in the 

borderland. These reservoirs are almost entirely within the Ventura and Cuyama basins; the 

greatest amount of oil and gas has been discovered in the widespread Vaqueros Formation 

and lesser amounts in the Sespe and Alegria 

Formations. Both reservoirs occur on the perimeter of what is considered the thickest Eocene 

section west of the San Andreas fault, at least 

5,340 m (17,500 ft) thick (Dickinson, 1969). 

The Paleocene(?) and Eocene rocks in the 

Sierra Madre Mountains may exceed 7,600 m 

(25,000 ft) in thickness (Vedxler, 1968). Although the U.S. Geol. Survey has done no 

source-rock studies in these areas, the wellindurated dark-gray to gray-black shales that 

are common in the Cozy Dell Shale and Juncal 

Formation could be possible source rocks for 

the oil in the pre-middle Miocene reservoirs. 

Bailey (1947) recognized that Eocene rocks 

might be the source for oil in the nonmarine 

Sespe Formation, and this interpretation is also 

reasonable for the entire sequence of Eocene, 

Oligocene, and early Miocene reservoirs.

The widespread early Miocene sandstone 

reservoirs of the Vaqueros Formation were 

blanketed by thick marine shale, an excellent 

cap rock for any newly generated oil. Increased 

tectonism toward the end of middle Miocene 

time undoubtedly produced structural traps. 

The present structural traps containing Oligocene and lower Miocene petroleum may be 

modifications of these earlier Miocene structures, or some may be only recently formed. 

Because of the continuity of the Vaqueros reservoir sands and the thick cap rock, widespread 

remigrations may have occurred as older structures were modified, lost their volume of 

closure, and spilled oil that may have migrated 

to other structural traps at positions around 

the margin of the basin.

Another striking feature of these reservoirs 

is the ^cluster of dry gas fields in the western

Santa Barbara Channel, the La Goleta, Naples, 

Molino, Gaviota, and Caliente fields. These have 

produced 62 million BOE. Dry gas is not common in these coastal basins, and it might be 

late-generated gas (Pussey, 1973; Hunt, 1974) 

from the nearby deeply buried Eocene (and 

Upper Cretaceous?) section. In some recent reconstructions of Paleogene paleogeography, the 

Transverse Ranges and the Cuyama block were 

little affected by the breakup and major lateral 

adjustments attributed to other areas in central 

and southern California (Howell, 1975; Clarke 

and Nilsen, 1973; Nilsen and Clarke, 1975). 

Such adjustments, even though debatable in 

magnitude, timing, and direction, are generally 

conceded to have occurred, and existing oil and 

gas fields may have been destroyed in areas 

more affected by this tectonism.

RESERVOIR ROCK TYPE

Reservoir rocks in the coastal basins consist 

of marine deep-water and shallow-water sands, 

nonmarine alluvial and deltaic sands, and fractured siliceous shale. Fragmented schist basement is a minor producer but is insignificant as 

a contributor to total petroleum discovered onshore and is therefore not a primary objective 

in the borderland. These rocks can be generally 

grouped by stratigraphic age. Deep-water sands 

are predominant in the late Miocene and younger reservoirs. They are almost totally restricted 

to the Los Angeles and Ventura basins where 

the late Miocene to Pliocene basin subsidence 

was great, allowing a thick buildup of these 

thin-bedded, generally fair-sorted sands. Total 

stratigraphic thickness of reservoirs approaches 2,000 m (6,500 ft) in the Ventura and 

Santa Fe Springs fields. With reservoir sands 

typically accounting for up to 40 percent of the 

productive stratigraphic interval, net productive sand commonly exceeds 1,000 m (3,280 ft) 

in thickness. These extremely thick net-pay 

intervals have yielded some of the highest barrels per acre recoveries onshore (table 1). This 

reservoir rock probably accounts for about 80 

percent of the total oil in the coastal basins 

(table 2 and fig. 4).

The best reservoir rocks are shallow-water, 

high-energy sandstone, the most productive of 

which was deposited during the early Miocene

11
transgression. These rocks account for more 

than 10 percent of the total production in the 

coastal basins. The Vaqueros Formation, widespread in the western Ventura basin and extending northeasterly into the Cuyama basin, is 

productive in these two areas but is nonproductive in the southeastern Los Angeles basin 

where the underlying Eocene rocks are relatively thin. This reservoir has yielded over 500 million barrels (oil + BOE), and the two largest 

fields, Cuyama South (more than 120 m (400 

ft) thick) and Elwood (more than 90 m (300 

ft) thick) have accounted for nearly 75 percent 

of the production from the Vaqueros Formation. Similar shallow-water sands of late Miocene age occur in the Salinas Valley in the San 

Ardo field (Baldwin, 1971), a near giant in an 

otherwise sparsely productive basin. Early Pliocene shallow to possible outer neritic sands of 

the Sisquoc Formation are productive over the 

northern part of the Santa Maria Basin (Crawford, 1971). Many of the reservoirs in the Sisquoc Formation have low-gravity crude oil and 

are being developed by intense steam soaking. 

Although this is successful on land, present 

methods would probably be uneconomic in the 

offshore.

Fractured shale reservoirs commonly are 

overlooked as a viable and worthy prospect for 

exploration, yet they are the third most important reservoir rock in the coastal basins. 

More than 5 percent of the oil produced in the 

coastal basins occurs in these rocks. The main 

reservoir in the recently discovered Hondo field 

in the Santa Barbara Channel is the massive 

chert section of the Monterey Formation in 

which the estimated recoverable reserves may 

exceed 1 billion barrels. In the Santa Maria 

basin, the Monterey Formation has yielded 75 

percent (540 million BOE to January 1, 1975) 

of the oil produced in that basin (Crawford, 

1971). This unit is the main reservoir of the 

Orcutt (172 million BOE), Santa Maria Valley 

(Monterey production estimated at more than 

140 million BOE), West Cat Canyon (137 million BOE), Lompoc (47 million BOE), Gato 

Ridge (40 million BOE), and Casmalia fields 

(34 million BOE), which are north of the borderland. Production from fractured shale is of 

minor importance in the Los Angeles basin 

fields (about 20 million BOE, table 2), where it

has been restricted to fields in the southwestern 

part of the basin. The largest production in this 

basin will probably come from the recent development of the black shale unit of the "237" 

zone at Wilmington (Truex, 1972).

Petroleum in nonmarine clastic reservoirs is 

concentrated in the Oligocene Sespe Formation 

of the Ventura basin (Nagle and Parker, 

1971) ; production from the South Mountain 

field (125 million BOE) is nearly four times 

larger than the next group of fields. Reservoirs 

are scattered westward along the Santa Barbara coast where the nonmarine Sespe grades 

laterally into marine sands of the Alegria and 

Gaviota Formations (Curran and others, 1971). 

Other nonmarine deposits that contain oil are of 

late Pliocene and Pleistocene age and occur 

around the margins of nearly filled marine 

basins, especially in the Ventura and Los Angeles basins. These are scattered accumulations of 

small volume, but collectively they account for 

several percent of the oil in the coastal basins.

OIL AND GAS GEOLOGY-SOUTHERN 

CALIFORNIA BORDERLAND

The many factors that influence oil occurrence have been recently reviewed by Haun 

(1975). Only those factors pertinent to the borderland are discussed in this report.

The borderland has been divided both geographically and geologically. The inner basin 

area (fig. 1) includes basins that are extensions 

of those onshore, such as Santa Monica and San 

Pedro basins and the San Diego trough. The 

outer basin area is seaward of the northwesttrending ridge system that includes Santa Catalina Island and extends to the base of the continental slope.

The physiography of the borderland has been 

described by Shepard and Emery (1941), 

Emery (1960), Moore (1969), and Vedder and 

others (1974). Variation in water depth (more 

than 1,000 m (3,280 ft) in many basins) has a 

large influence on the potential recoverable 

petroleum resources. Sea floor relief has also 

restricted the type and location of geologic 

data; most dart sampling has been in water 

depths less than 1,000 m, and the current highresolution seismic systems used by the U.S. 

Geol. Survey have a maximum operating depth

12
of about 500 m (1,640 ft). Proposed Federal 

Lease Sale No. 35 is scheduled for the shallower 

areas where the depths are generally less than 

500 m; the lease sales in the deeper waters are 

not scheduled until June 1977.

Estimates by the U.S. Geol. Survey of the undiscovered but recoverable petroleum resources 

in OCS areas (Miller and others, 1975) show 

values for those areas less than 200 m deep 

(656 ft). This depth was chosen because it is 

the approximate break in slope for the continental shelf throughout much of the world, and 

because industry can develop and produce fields 

to these depths with present techniques and 

within a few years after discovery. The deepest existing platform or sea floor completion is 

in 139 m (455 ft) of water in the North Sea, 

although a platform is being constructed for 

267 m (875 ft) of water for the Santa Ynez 

Unit in the western Santa Barbara Channel and 

two platforms 372 m (1,200 ft) high are planned and awaiting construction in the Gulf of 

Mexico (McNabb, 1975, p. 19).

Of the more than 21,000 mi2 in the borderland, only about 2,306 mi 2 (11 percent) is shallower than 200 m (660 ft) (fig. 5) ; this is 

equally divided between waters owned by the 

State of California and the Federal Government. Of the Federal waters, more than 70 percent (849 mi2 ) is in the outer basin area and 30 

percent is in the inner basin area; 50 percent of 

the State area is along the mainland coast. The 

latter area is already productive in San Pedro 

Bay and Santa Monica Bay and is considered 

the area in less than 200 metres water depth 

with the highest potential for additional 

reserves.

OIL AND GAS SEEPS

Oil and gas seeps, as well as outcrops of 

asphalt-impregnated sands, have been used 

since the early days of oil exploration as indicators for underground accumulations. This is 

especially true in California oil basins where 

extensive seeps led to early oil field discoveries 

before the turn of the century. Offshore seeps 

in southern California waters have been documented (Wilkinson, 1971, 1972; Fischer and 

Stevenson, 1973), but these are almost all restricted to the Santa Barbara Channel, extensions of the Los Angeles basin into Santa Monica Bay, and Huntington Beach in the San Pedro 

basin. Several inactive seeps have been reported 

elsewhere in the Santa Monica basin, such as 

off the west tip of Santa Catalina Island, off 

Point Dume, and in the San Pedro Channel.

The absence of documented visible seeps seaward of the Channel Islands cannot be attributed to lack of observation. These waters 

have been traveled extensively over the last 40 

to 50 years by numerous oceanographic institutions, as well as by fisherman, yachtsmen, and 

more recently oil explorations. In a large part 

of this area, the Miocene and older rocks have 

been folded, uplifted, and eroded. Although no 

major earthquakes greater than magnitude 6 

have been recorded, a compilation of events 

greater than magnitude 4 for the 40 years between 1932 and 1972 shows that the area is 

seismically active (Hileman and others, 1973). 

Study of high-resolution seismic records by the 

U.S. Geol. Survey has revealed offsets on the 

sea floor, further attesting to the recency of 

tectonic activity (Greene and others, 1975). 

Faults with large displacements are also apparent from interpretation of deep-penetration 

geophysical records, from juxtaposition of dissimilar rocks and rocks of different ages, and 

to a lesser degree from the geomorphology of 

the province. These geologic features are similar to the onshore areas where seeps occur. As a 

possible indicator of petroliferous basins in the 

outer basins, the lack of visible seeps is disappointing but in no way eliminates the area as 

being potential. The U.S. Geol. Survey has not 

used the more sensitive and interpretative techniques employed by industry, such as fluorescence spectroscopy and gas chromatography of 

ocean waters and (or) bottom samples.

Bottom sampling by dredging and dart coring has recovered only one dredge haul containing hydrocarbons. In this haul 15- to 30-cm 

slabs of breccia consisting of clasts of late(?) 

Miocene calcareous and siliceous mudstone and 

volcanic rocks contain tar in the interstitial 

pores. This dredge site (KSB 21E in Vedder 

and others, 1974) is located 13 nautical miles 

west of Santa Catalina Island on the steep 

slope facing northeasterly into the Santa Monica basin. Considering the small volume of ma13
SEABED AREAS 

WATER DEPTHS 

State 1

Federal 1

Total 2

S_] P

SAN

MONICA 

262

(172+90)

SANTA-ROSA 

413

(195 + 216)

SANTA 

BARBARA

95 

(36 + 59)

SAN

PEDRO

229

1129+100)

SAN NICOLAS 

363

(131 +252)

SANTA 

CATALINA

103 

(99 + 4)

CORTES-[TAN

300 

(O + 300)

FORTYMILE 

6

(0 + 6)

SIXTYMILE , 

6 V /

FIGURE 5. Areas of the borderland under less than 200 m water. Each area is totaled in square miles (statute) 

theses. The seabed area along the mainland coast is divided into three areas at Point Vicente and Dana P

proposed lease area for OCS Sale No. 35 (Bureau of Land Management, 1975).
terial retrieved from bottom sampling, the apparent absence of tar-saturated sediments is 

not considered as significant as the absence of 

oil and gas seeps.

OFFSHORE WELLS

One of the factors used in evaluating the oil 

potential in a frontier area are the "favorable 

results from, and significance of any exploratory drilling" (Weeks, 1975). Several wells 

have been drilled on the Channel Islands, 12 on 

Santa-Rosa and 4 on Santa Cruz (Hunger, 

1974). The only known reference to oil shows 

is by Redwine (1955) in Signal-Honolulu well 

Tecolote No. 1, where "some 20 feet of the basal 

Sespe were oil-stained, including about one foot 

of good permeable oil sand containing 45 degree 

gravity oil." Elsewhere on the borderland, at 

least 77 core holes and stratigraphic tests were 

drilled in Federal waters (fig. 6) under permits 

issued by the California State Lands Commission prior to the Supreme Court's ruling January 31, 1966, on the State-Federal boundary in 

the offshore waters. The deeper tests were concentrated in San Pedro Bay, and a few were 

in Santa Monica basin and elsewhere throughout the borderland. According to Hunger 

(1974), 28 core holes penetrated more than 305 

m (1,000 ft) below the sea floor, and 7 exceeded 1,525 m (5,000 ft). In State waters at 

least 22 wells were drilled deeper than 1,525 m 

(5,000ft) (fig. 6).

Since 1966, almost all well activity in offshore 

California has been concentrated outside of the 

borderland, predominately in the Santa Barbara Channel before and after the OCS lease 

sale there on February 6, 1968, and to a lesser 

degree in central and northern California with 

the OCS sale there in 1963. On the borderland 

several deep stratigraphic tests were drilled in 

State waters in 1969 by industry groups, namely off Point Loma, Oceanside, and in Santa Monica Bay. Several industry groups had also 

drilled over 175 shallow core holes up to 229 m 

(750 ft) deep between 1968 and 1975 in the 

outer basin area, both in and out of the proposed No. 35 sale area, and some were in water depths exceeding 305 m (1,000 ft). These 

were drilled under existing rules of the Interior 

Department administered by the U.S. Geological Survey. In September 1975, a deep stratigraphic test was spudded off a structure on the 

southeast flank of Cortes Bank (fig. 6; Lambert 

zone 6, x = 1,152,375, y = 108,700). This proposed 3,660-m (12,000-ft) stratigraphic test is 

one of several such tests drilled or to be drilled 

on the outer continental shelf of the United 

States to obtain geologic information for evaluation by both the government and the oil industry prior to lease sale. Geologic permits for the 

drilling of these wells are issued by the U.S. 

Geol. Survey under regulations of the Department of the Interior.

Data from these wells are proprietary, but it 

is known that many of the deeper wells, especially in San Pedro Bay (fig. 6), were drilled 

on presumably favorable structures, some penetrated at least part of the prospective section, 

and some had oil and (or) gas shows; it is questionable, however, whether any discovered economic accumulations. If additional information 

shows that these wells were located on the most 

favorable structures, were sufficiently deep, and 

did not penetrate commercial accumulations of 

petroleum, a large part of the area with highest 

potential in the inner basin region must be 

downgraded.

SEDIMENT THICKNESSES

A primary concern for frontier areas is 

whether the basins have adequate thicknesses 

of sediments for petroleum accumulations. A 

contour map on the basement surface and an 

isopach of both postbasement and Pliocene and 

(or) upper Miocene strata were published by 

Parker (1971) but were based on limited data. 

More recent studies (Vedder and others, 1974; 

Junger and Wagner, unpub. data) have combined seismic profiles with age-dated bottom 

samples for interpreting the thickness of late 

Tertiary sediments throughout the borderland. 

Cross sections, an isopach map of post-Miocene 

sediments, and a preliminary geologic map as 

well as sampling on the outer ridges are given 

in Vedder and others (1974). Two subsequent 

cruises in 1974 and 1975 by the U.S. Geol. Survey have supplemented and added control in 

certain areas but have not substantially 

changed the structural or stratigraphic interpretations as previously published, except in

15
BATHYMETRIC CONTOURS IN METRES 

0 5 10 20 30 4O KILOMETRES

 

0 S 10 IS 20 NAUTICAL MILES

S

SIGNAL-HONOLULU 

TECOLOTE NO. 1

SEISMIC PROFILE 

FIGURE II

ESCI OCS-CAL 75-70 NO. I

State 3 

Naut. Mi 

Limit

SANTA MONICA BAY

121* 120' 119

118*

FIGURE 6. Core holes and stratigraphic tests drilled on the borderland prior to the Supreme Court's rulin

State-Federal boundary.
the San Diego Trough where new interpretations have substantially reduced the thickness 

of post-Miocene sediments. However, previous 

estimates on the velocities used for calculating 

these thicknesses have been reduced because of 

the shallow burial and low compaction evidenced by these post-Oligocene sediments. Consequently, some of the thicknesses published in 

Vedder and others (1974) are probably excessive by as much as 20 to 25 percent.

The distribution of known Cretaceous sedimentary rocks onshore and in the borderland 

recently has been reviewed (Vedder and others, 

1974). Samples of this age have been identified 

in sea floor outcrops in only three areas along 

the San Diego shelf, west of San Nicolas Island, 

and on the north edge of the unnamed ridge 

west of Cortes Bank. The sample from the unnamed ridge has not been previously reported 

(GSCD 60; 32°47.5' N, 119°40.9' W; Lambert 

zone 6, £ = 945,441, y = 244,805). Rocks of this 

age are presumably present just west and southwest of San Miguel Island. Cretaceous sediments are believed to be absent over much of 

the outer basin area west of the Patton Ridge, 

and in a broad belt extending southeastward 

from Santa Cruz Island including Santa Catalina and San Clemente Islands, Thirtymile, 

Fortymile, and Sixtymile Banks. Their presence 

under the Santa Rosa-Cortes Ridge adjacent to 

Santa Cruz and San Nicolas Basins is unknown, 

but on the basis of seismic records and modeling of gravity data (Sasnett and others, unpub. 

data), they are thought to be thin, except in the 

northwesternmost part of the ridge. Rocks of 

Cretaceous age have been excluded from this 

evaluation both as a possible source or as reservoir rocks until there is more evidence concerning their presence and character that would 

substantially differ from that obtained onshore 

where they have had a negligible productive 

history.

The Paleogene outcrop and subcrop areas are 

depicted as a broad belt (fig. 7) that wedges 

out to the east and probably to the south. Except for some questionable Oligocene sediments, 

rocks of this age have not been identified in the 

western third of the borderland. A thickness of 

2,150 m (7,050 ft) of Paleogene sediments is 

exposed on the Channel Islands, which includes 

366 m (1,200 ft) of continental beds (Sespe

type). Another 1,070+ m (3,500+ ft) of deep 

marine strata of Eocene age was measured on 

San Nicolas Island, but neither the base nor top 

is exposed (Vedder and Norris, 1963). The 

actual thickness in the borderland must be inferred, and gravity modeling (Beyer and others, 1975; Sasnett and others, unpub. data) for 

Bouguer corrections supports the inference already made from weak seismic control that this 

section, excluding dense Late Cretaceous and 

possibly early Tertiary rocks, does not exceed 

3,350 m (11,000 ft) anywhere along the Santa 

Rosa-Cortes Ridge or in the adjacent basins. 

To the north of the borderland in the northcentral Ventura basin, total Eocene and Oligocene sections have been variously reported to 

be as thick as 7,600 m (25,000 ft) (Vedder and 

others, 1974, map sheet 4; Curran and others, 

1971). Thicknesses in the borderland are therefore one-third to one-half of those maximum 

thicknesses recorded onshore, a major factor in 

evaluating the potential of the Paleogene rocks.

Neogene sedimentary rocks vary widely in 

thickness; they are absent or present only as a 

veneer on many banks and are thickest beneath 

the floors of the major basins. Over much of the 

area west of the Santa Rosa-Cortes Ridge, Neogene sediments are believed to lie directly on 

metamorphic basement. The same is true for the 

area to the southeast, from Sixtymile Bank 

northward over Thirtymile Bank to Santa Catalina Island, and they are believed to extend 

from Fortymile Bank to San Clemente Island 

and thence to the east end of Santa Cruz Island. 

On many ridges and banks, the base of the Neogene is traceable on seismic records from the 

contact on Paleogene rocks at the crests into 

the flanks and the subsurface sections in the 

main basins (fig. 11). In the outer basin area, 

thicknesses to 2,000 m (6,500 ft) over as much 

as 50 mi2 may occur at the north end of San 

Nicolas basin and perhaps in the east-central 

Santa Cruz basin. In contrast, in the Los Angeles basin such thicknesses cover 500 mi2 , and 

thicknesses greater than 6,100 m (20,000 ft) 

are inferred to cover 250 mi2 .

Compared to the onshore coastal basins, the 

thin section of Neogene strata in the outer basin 

area (and perhaps a large part of the inner 

basin area as well) is unlike the Los Angeles 

and Ventura basins in which sedimentary rocks

17
00

PALEOG

IS.'"'"'i OUTCROP 

r^?~l MARINE 

730-MTt THICKNE

 ED6ELIN

0.3 SAMPLES 

CARBON, 

REFEREN

BATHYMETRIC CO

FIGURE 7. Organic carbon content (weight percent) of dart and outcrop samples of Eocene and Oligocene age 

ments. The outcrop area is shaded and the subcrop beneath the borderland area is hachured. References a

strata: 1, Curran and others (1971) (table 1); 2, Vedder (1968); 3, Weaver and Doerner (1969, p. 38, 4

Howell (1975, fig. 4); 6, Vedder and Norris (1963); 7, Yerkes and others (1965, pi. 1) (includes some ea

marine section); 8, Kennedy and More (1971); 9, Vedder and others (1974, sheet 5).
of similar age have produced 83 percent of the 

total petroleum in the coastal basins (table 2). 

It is similar, however, to the Santa Maria and 

Salinas coastal basins (from which 1,011 million BOE has been produced), and those basins 

should perhaps be used as analogs for making 

assessments of the petroleum potential of the 

borderland.

In the inner basin area, Paleogene strata are 

absent except offshore from San Diego (fig. 7). 

Post-Miocene sedimentary rocks are thickest 

between Palos Verdes Hills and Santa Catalina 

Island (2,200 m; 7,200 ft) and in the western 

Santa Monica basin south of Mugu Canyon 

(3,000 m; 9,800 ft). However, Junger and 

Wagner (unpub. data) believe the Miocene 

sedimentary section is thin to absent beneath 

these thickest post-Miocene areas of deposition.

Although no volumetric measurements were 

made on the post-Paleogene sedimentary rocks, 

these interpretations of thicknesses from recent seismic data supplemented by age-dated 

dart cores are clearly far less than previously 

inferred by Parker (1971), whose cross sections show fairly constant thicknesses of up to 

3,050 m (10,000 ft) over Cortes Bank, in San 

Nicolas, Catalina, and Santa Cruz basins, and 

3,660 m (12,000 ft) in the Santa Monica basin.

POTENTIAL PETROLEUM SOURCE ROCKS

Over the last few decades, organic geochemistry has contributed greatly to our understanding of petroleum generation. There is a general 

consensus on the kind and quantity of organic 

matter required for a sediment to be a potential, 

source rock, and it is becoming possible to measure the degree of metamorphism of organic 

material during the interval from its initial 

burial in sediments to its final stage of graphite 

(and the release of C02 ). More is now known of 

the interrelation between the two main variables in this transformation, namely temperature and time, and many recent studies have 

typed crude oils and traced these back to their 

probable original source rock.

As a frontier basin, the borderland has a 

number of parameters favorable for such studies. The study of Tertiary sediments from sea 

floor ^samples is possible because of uplift and 

erosion after late Tertiary tectonism (Vedder 

and others, 1974). Much work has been done

on analogous and adjacent basins onshore, both 

from outcrops and wells (Philippi, 1965). Because the inner basin area of the borderland is 

adjacent to onshore basins and is productive 

along the coast, our efforts have been concentrated more on the Tertiary sediments seaward 

of the islands and on the islands themselves.

Selected fine-grained siltstone and mudstone 

from dart cores and island outcrops, which previously had been paleontologically dated, were 

analyzed for total organic carbon content, extractable hydrocarbons, and characteristics of 

those hydrocarbons. The results are listed in 

tables 10 and 11, and a summary of the results 

is shown in table 3. In order to be considered 

potential petroleum source rocks, argillaceous 

sediments should contain a minimum content of 

indigenous organic matter. The lower limit of 

organic richness for productive basins has been 

empirically set at 0.4 percent organic carbon 

(Ronov, 1958; Williams, 1974) and about 100 

parts per million extractable heavy hydrocarbons (Philippi, 1957; Baker, 1972). The potential of shale as a source rock is, in general, directly proportional to its organic richness; 

therefore, sediments that contain more than 5 

percent organic carbon and 500 parts per million hydrocarbons can be considered to be excellent potential source rocks.

Samples from Eocene outcrops on San Nicolas Island (table 3) give results consistent with 

dart cores of similar age from the sea floor 

(fig. 7). The mean value of the organic carbon 

from these 54 samples is 0.35 percent, indicating that few of the samples have sufficient organic matter to be considered potential source 

rocks. Dart cores of Oligocene or Eocene rocks 

usually can be distinguished from those of Miocene age immediately upon removal from the 

dart barrel. Fossiliferous silty mudstone of preMiocene age is stiff, in some samples semibrittle, in comparison to soft, plastic Miocene mudstone. They are lighter gray, commonly bluish 

gray, compared with the dark-gray to brownishblack hues typical of the Miocene rocks. Darker colors ordinarily have been correlated with 

organic richness, and this has been supported 

by the analytical data.

Eocene sandstone beds on San Nicolas, on the 

basis of sedimentary structures, were deposited

19
TABLE 3. Summary of organic chemistry on dart samples1 by stratigraphic age, southern Cali

[Samples are listed in tables 10 and 11 j

Organic carbon

to

o

Sample age

Late Cretaceous _ _ _

Eocene to Oligocene 1 _ _ _

Early Miocene _____

Early or middle Miocene _ _

Middle Miocene ______________

Middle or late Miocene _ __

Late Miocene _ _

Late Miocene or early Pliocene- _ 

Holocene _ _ _ _

Mean 

( weight 

percent)

0.2 

.35 

3.2 

4.8 

4.9 

5.6 

6.8 

5.9 

1.0

Number 

of 

samples

1

54 

6 

11 

26 

12 

20 

3 

1

Standard 

deviation

0~35 

1.5 

2.8 

2.2 

2.9 

2.1 

1.1

Mean 

(ppm)

~233

437 

1,399 

829

1,447 

"229

Bitumen

Number 

of 

samples

"3 

3 

2 

11

10 

"l

Total H

Standard 

deviation

255 

251 

518

486

1~755

Mean 

(ppm)

"26 

98 

458 

182

122

"58

Number 

of 

samples

3 

3

11

10 

"l

1 Eocene includes 44 outcrop samples from San Nicolas Island.
by southwestward directed mass gravity flow 

(Cole, 1975) into a bathyal environment 

(Weaver and others, 1969). The interbedded 

fine-grained siltstone and mudstone are poor 

source rocks, and the low organic content could 

be explained by several factors: (1) an oceanographic environment that was not conducive to 

a rich organic life, perhaps lacking nearby 

nutrient-rich upwelling currents; (2) an open 

ocean environment with aerobic bottom conditions that destroyed much of the organic matter; or (3) a rate of deposition that was either 

too slow, so that organic matter could be destroyed, or too rapid, so that organic matter was 

diluted by terrigenous sediments. Our sampling 

of this entire part of the early Tertiary section 

may be biased as our samples are concentrated 

on the San Nicolas platform, and sediments of 

similar age may exist, even including Late Cretaceous, that were deposited under conditions 

more favorable for organic growth and (or) 

preservation of such organic material. Eocene 

rocks are well exposed on the Channel Islands 

and San Nicolas Island and have high sandshale ratios and many conglomerate beds; much 

of the section is believed to have been deposited 

in a subsea fan environment. The basinward 

extension of these fans, where shale percentages would be higher, have probably not been 

sampled, and organic richness may be greater 

in these now-buried areas. However, the poor 

potential quality as measured is consistent with 

the low amount of hydrocarbons found in the 

onshore Paleogene sediments (348 million BOE, 

table 2) or the added oil in the Vaqueros Formation presumed to have been generated from 

the Paleogene (an additional 541 million BOE, 

table 2).;

Within the Neogene section, the Miocene and 

in particular the middle to late Miocene shales 

have long been considered one of the most likely sources of the prolific oil production in the 

onshore coastal basins (Barbat, 1958; Philippi, 

1965). Widespread sea-floor sampling of similar strata (fig. 8) supports previous interpretations on the extent of the Miocene seas and 

further indicates that good to excellent potential source rocks are present throughout the 

borderland (table 3 and tables 10 and 11). 

These samples also show a progressive increase 

in organic content from 3.2 percent in the early

Miocene to .6.8 percent in the late Miocene, with 

no apparent spatial preference throughout the 

outer basin area. Few Pliocene dart cores were 

obtained, and none have as yet been analyzed. If 

all other geologic factors were similar, the borderland should be as richly petroliferous as the 

onshore basins.

The Tertiary paleogeography and environmental conditions that controlled the organic 

content in the sediments are poorly known. 

However, the organic-rich Miocene sediments 

have an organic content not greatly different 

from the sediments now being deposited in the 

present basin floors (fig. 9). Emery (1960) 

states that the nearshore basin sediments have 

lower values than the offshore basins, and even 

lower values were obtained on the slope and 

very low values on the deep sea floor. "The peak 

concentration of organic matter at intermediate 

distance from the mainland is attributed to a 

very rapid rate of deposition of detrital sediments nearshore, resulting in the dilution or 

masking of organic matter there, and to a very 

slow rate of deposition far from shore, resulting 

in extensive oxidation of organic matter before 

it can become protected by burial. Thus the 

highest concentration occurs under optimum 

conditions of neither too rapid nor too slow a 

rate of deposition of detrital sediments" (Emery, 1960, p. 228). Recent sampling by the U.S. 

Geol. Survey gives low values (about 1 percent 

organic carbon) in the Holocene sediments on 

Cortes and Tanner Banks. Additional studies of 

other banks and ridges are continuing. If low 

values are found on the ridges, in contrast to 

higher values in the basins, this distribution of 

organic content might be used to infer paleobathymetry in Miocene samples of the same age.

ORGANIC MATURITY

Numerous methods have been proposed for 

determining the progressive transformation or 

metamorphism of organic matter into oil and 

gas (Bray and Evans, 1965; Philippi, 1965; 

Staplin, 1969; Gutjahr, 1966; Hood and others, 

1975). The methods adopted by the U.S. Geol. 

Survey consist of quantitative and qualitative 

analyses of the insoluble and the extractable 

organic matter. The generation and the expulsion of petroleum from its source are relatively

21
to 

to

FIGURE 8. Organic carbon content (weight percent) of Miocene dart cores. A summary of the samples is 

listed in tables 10 and 11.
to

oo

BATHYMETRIC CONTOURS IN METRES

0 » 10 80 »0 40 KILOMITMt

2.7 NO NAME BASIN

FIGURE 9. Organic carbon content (weight percent) in Holocene sediments from basin floors, outer slopes, and ocean floor (after 

Emery, 1960). Emery's data, as organic matter, converted to organic carbon (weight percent) by dividing by 1.7.
inefficient processes, and most of the organic 

matter remains in the rock, either as insoluble 

organic carbon or as soluble hydrocarbons. As 

petroleum is generated, the ratio of hydrocarbons to organic carbon increases to a point 

where HC/C ratios greater than 1 percent (fig. 

10) suggest mature potential source rocks. 

Other indicators of the stage of organic transformation are the characteristics of odd-even 

carbon number ratios of normal paraffins, the 

proportion of nonhydrocarbons in the extract, 

the ratio of saturated hydrocarbons to aromatics, and the elemental composition and depth 

of color of the remaining kerogen. Sufficient 

analyses were made with consistent results to 

generalize on the maturity of the Paleogene and

Neogene samples from the borderland, which 

has significant implications on the assessment 

of the petroleum potential of the area.

ORGANIC MATURITY OF PALEOGENE AND 

NEOGENE SAMPLES

All samples analyzed have a low hydrocarbon 

content, and their HC/C ratios are all less than 

1 percent required for good to excellent potential source rocks (fig. 10). The Paleogene rocks 

differ in some ways from the Neogene ones; 

saturated/aromatic hydrocarbon ratios in Pale.- 

ogene rocks are greater than one, rather than 

less than one, and the HC/C ratios are slightly 

higher. Although these might suggest a higher 

temperature history and hence a greater ma-

.01 .02 .05 0.1 0.2 0.4 10 20 50 100

10,000

1,000

100

LEGEND:BORDERLAND SAMPLES

© EOC-OLIG. DART CORES 

 EOCENE OUTCROP

(SAN NICOLAS ISLAND) 

X MIOCENE DART CORES

AREA OF 

POOR OR NONSOURCE ROCK

AREA OF 

0000 m 

POSSIBLE 

SOURCE 

ROCK

10000

iu ffi 0 >

x

uj

1,000 

UJ

o

<

o 

ce

o

§

100

UJO **;

< ^

* £

ui O

> DC

< 0

m

10

.01 0.1 0 " 0.4 I 2 5 10 20 50 100

I ©

POOR OR NON-SOURCE ROCK -»+*- POTENTIAL SOURCE ROCK 

ORGANIC CARBON WT. %

FIGURE 10. Source rock analysis chart with organic carbon content (weight percent) plotted against hydrocarbon (ppm) for Eocene-OHgocene and Miocene samples. Location of samples is shown on figures 7 and 8. The 

organic carbon content (weight percent) of additional samples is listed in tables 10 and 11.

24
turity, the chromatograms show a marked oddcarbon predominance, a characteristic of immaturity. It is likely that the Paleogene 

samples contain a different type of organic 

matter and may not have had a history of significantly deeper burial than the Miocene. Most 

Paleogene outcrop samples are judged immature and are interpreted not to have had a 

temperature history sufficiently high to generate petroleum.

Dart samples were obtained in areas of the 

borderland generally along banks and ridges in 

water depths less than 1,000 m. In most of these 

areas, the sediments have been slightly tilted 

and subsequently beveled. Seismic profiles indicate that the Miocene sediments were covered 

by only a minimal amount of younger sediments. Supporting evidence is in the fresh samples themselves; the Paleogene are semiconsolidated and stiff to semibrittle, whereas the Neocene are only slightly consolidated, soft, plastic, 

and moldable between the fingers. X-rays of 

Miocene diatoms show no conversion from opal 

to cristobalite, additional confirmation of shallow burial (Bramlette, 1946; Murata and Nakata, 1974). Since the close of Miocene time, 

some basins have continued to subside relative 

to the uplifted banks and ridges, and the top of 

the Miocene is inferred to be as deep as 10,000 

feet below sea level in several areas of the borderland (Vedder and others, 1974). Such subsidence and burial by as much as 7,000 feet of 

post-Miocene sediments have brought these excellent potential source rocks into a higher 

pressure and temperature regime than the 

sediments on the higher banks and ridges have 

experienced. By making various assumptions on 

the depth of burial, the paleogeothermal gradient, the conductivity of the sediments, effects of 

geologic time, and total overburden pressures, 

it is possible to postulate a temperature regime 

in the deeper parts of the present basins that is 

sufficient to generate hydrocarbons from these 

excellent potential Miocene source beds.

An early stage of organic diagenesis in a lower than normal thermal regime also may have 

occurred in these Miocene rocks. Six outcrop 

samples of the Monterey Formation from north 

of the Santa Barbara Channel between Point 

Conception and Gaviota were analyzed for comparison with Miocene dart core samples (table

10). George Claypool who analyzed these samples states (written commun., 1975) : 

The organic geochemical characteristics of the Monterey 

at these localities are intermediate between that of the 

submarine outcrop samples, and the deeply buried Miocene rocks of the Los Angeles and Ventura basins. The 

Monterey samples from onshore have the same range 

of organic carbon content as the dart core samples, but 

contain significant higher extractable hydrocarbon contents, with HC/C ratios of 1.5 percent and above. The 

composition of the extractable organic matter in the 

onshore Monterey is similar in many respects to that of 

the offshore Miocene dart core samples. Both have 

highly asphaltic extracts, and hydrocarbon fractions in 

which aromatics predominate over saturated hydrocarbons, and branched-cyclic saturates predominate over 

straight chain paraffins. These characteristics are consistent with thermal immaturity; however, it may be 

more of a genetic characteristic of the organic matter 

deposited with Miocene rocks in California. One sample 

in particular (Wood-3-1) is 13.4 percent soluble in hot 

chloroform. This rock is exceptionally rich; if fracturing or some other favorable circumstances permitted, a 

heavy asphaltic oil might be produced from the Monterey 

at this locality. The significance of this comparison is 

that Miocene rocks of the California borderland may 

contain organic matter of a composition which yields a 

heavy oil at an early stage of diagenesis. This idea has 

recently been proposed by Powell, Cook, and McKirdy 

(1975) for phosphate-rich rocks in general, and in particular for Mohnian age source sediments in the Los 

Angeles basin.

Less is known about the Paleogene rocks of 

the borderland. Where sampled, the organic 

material they contain is immature, but the sampling has been concentrated on the San Nicolas 

platform, an area which is now high and may 

never have been deeply buried. Strata of the 

same age in other parts of the borderland, especially beneath the Miocene rocks in the deeper 

Santa Cruz and San Nicolas basins, could have 

encountered sufficiently high temperatures to 

generate hydrocarbons. The effect of time on 

the generation of hydrocarbons (Hunt, 1974; 

Connan, 1974) would have required a slightly 

lower temperature for the Paleogene than for 

the Miocene. The borderland may have had a 

higher than normal paleogeothermal gradient. 

Widespread volcanism probably began over 

much of the borderland toward the end of the 

Saucesian Stage, roughly 16 m.y. ago. Presumably this episode was preceded by a general rise 

in the geothermal gradient. Hawkins and Divis 

(1975, p. 323-324) have suggested from chemical evidence that the Miocene volcanic rocks on 

San Clemente and Santa Catalina Islands are

25
the result of "mantle (plus sediment?) melting 

that may have been due to proximity of the 

paleo-East Pacific Rise rather than to an active 

subduction zone." Heat-flow measurements 

along the present East Pacific Rise are more 

than eight times normal, certainly sufficient to 

cause elevated temperatures in the overlying 

sedimentary column. Temperatures sufficient 

for generating hydrocarbons in the buried Eocene rocks seem plausible. The thickness of the 

buried Eocene section in these areas remains 

unknown, and the organic content of the sediments may be higher than that measured.

POTENTIAL PETROLEUM RESERVOIR ROCKS

PALEOGENE AGE

The inferred distribution of Paleogene sediments throughout the borderland is shown in 

figure 7. These rocks apparently are absent elsewhere, as there is ample evidence that Neogene 

sediments lie on basement rocks to the east, 

west, and northeast of this broad Paleogene belt 

(Vedder and others, 1974). It is unclear whether this belt approximates the Paleogene marine 

basin, whether subsequent uplift and erosion 

limited its distribution, or whether large-scale 

lateral faults have displaced blocks and modified 

the original shape of the basin, as recently proposed (Howell and others, 1975). It is apparent 

that the Paleogene rocks contain abundant 

sandstone. Alluvial, shallow-marine to deepmarine sandstone occurs in the San Diego area. 

Deep-marine sandstone deposited by massgravity flow currents (Cole, 1975) was deposited on San Nicolas Island, and sediments 

deposited in environments ranging from bathyal to neritic are found on the Channel Islands 

(Doerner, 1969; Weaver and Doerner, 1969). 

Sandstone and conglomerate beds make up over 

50 percent of the approximately 1,070+ m 

(3,500 ft) of Paleogene section on San Nicolas 

Island, and in other areas sandstone sections 

890 m (2,920 ft) thick have been measured, 

such as at Crook Point on San Miguel Island 

(Weaver and Doerner, 1969, p. 38). Throughout the Paleogene section there seems to be a 

sufficient quantity of coarse elastics for potential reservoirs. Compositionally, these sands 

have been derived from a predominantly continental terrane of siliceous plutonic rocks, 

quartz-rich metamorphic rocks containing muscovite and epidote, and resistant metavolcanic 

rocks with an equigranular matrix of quartz 

and feldspar. These abundant, commonly thick 

sandstones with stable constituents ordinarily 

are excellent reservoir sands if sorting has been 

sufficient to remove the finer silt and clay size 

components and if deep burial, cementation, or 

porosity-destroying diagenesis did not occur 

later. In outcrop, and where sampled on the sea 

floor, these sandstones generally have moderate 

porosity, and in the subsurface they should have 

porosities equal to or better than the Eocene 

sandstones' along the northern part of the Santa 

Barbara Channel, where maximum depth of 

burial has been much greater.

The fair reservoir quality of these sands 

would be improved with better sorting, which 

usually occurs in high-energy, shallow-water 

environments. Shallow-water sandstones have 

been noted in the Channel Islands and the San 

Diego area. To the north in the Santa Ynez 

Range and extending easterly into the Ventura 

basin, a gradual shallowing of the "Paleogene" 

basin in Oligocene time resulted in widespread 

shallow-water sands of the Alegria Formation 

and the nonmarine Sespe Formation. At the 

same time, a similar condition may have existed 

over much of the borderland or around its 

basinal margins. If it did exist, then good quality sands could be expected, and they might form 

the best potential reservoirs in the entire borderland. However, such sands have not been 

identified by the sampling or geophysical techniques available.

NEOGENE AGE

Miocene time began with a widespread marine transgression that deposited shallow-water 

sands of excellent reservoir quality over large 

parts of onshore southern California. In areas 

adjacent to the borderland, these sandstones are 

present in the Santa Barbara Channel eastward 

into the Ventura basin and, although absent in 

much of the Los Angeles basin, are present on 

the east side of that basin. Sandstones of early 

Miocene age occur on San Miguel and Santa 

Rosa Islands, are represented by coarse, nearsource breccias on Santa Cruz Island, are absent on Santa Catalina Island, and possibly are 

present beneath the middle Miocene volcanic

26
rocks of Santa Barbara and San Clemente 

Islands. On the sea floor, Miocene sedimentary 

rocks rest either on Paleogene sandstones and 

fine-grained clastic rocks or directly on basement rocks. Dart core samples identified as 

early or middle Miocene are chiefly siltstone, 

mudstone, and marlstone. Sandstone typical of 

the onshore Vaqueros Formation is inferred to 

be present at places but has not been positively 

identified; it may be represented by undatable 

Sandstone cores composed of well-sorted continental detritus, commonly containing broken 

fragments of neritic megafauna. Some of these 

sandstone samples also have clasts of intermediate to basic volcanic rocks, which are not found 

in the Paleogene sandstones but are common to 

the middle Miocene samples. Erosion and redeposition of Eocene sandstone and conglomerate during an early Neogene transgression 

could have resulted in widespread deposits of 

shallow-water, high-quality reseryoir sands, but 

until more is known of the late Paleogene and 

early Neogene history and until data from core 

holes and future drilling become available, such 

conclusions will remain conjectural.

Over 80 percent of the total production from 

the onshore coastal basins has come from thick, 

extensive, deep-water upper Miocene and Pliocene sands in the Los Angeles and Ventura 

basins. These two rapidly subsiding basins derived the bulk of their coarse clastic material 

from nearby uplifted areas. In the borderland, 

basin geometry appears to have been well defined by early Pliocene time, and it is unlikely 

that deep-water sands could have been transported across the onshore and adjacent basins 

(Santa Barbara Channel, Santa Monica and 

San Pedro basins) in quantities great enough 

for sand accumulations of sufficient thicknesses 

for potential reservoirs. Data from each of 

these nearshore areas suggest that the lower 

Pliocene section (and deep-water sands) thin 

toward the borderland, that is, south across the 

Santa Barbara Channel (U.S. Geological Survey, 1974), west in fields along the Santa Monica coast, and southwest from the southern Los 

Angeles basin (California Division of Oil and 

Gas, 1974).

Miocene deep-water sands might be present 

at various localities in the outer basins but cannot be predicted with present data. Highlands

existing during early and possibly into late 

Miocene time, such as "Catalinia" (Reed, 1951, 

p. 31) and those on Santa Cruz Island (McLean 

and others, 1975), did contribute coarse clastic 

material. However, these breccias, which crop 

cut on Santa Cruz Island and along the coast 

south of the Los Angeles basin, must be much 

better sorted in the subsurface to be potential 

reservoirs.

It is encouraging that possible analogous 

sandstone reservoirs occur in the Santa Barbara Channel in both the lower and middle Miocene sections. Basal Monterey sands of Miocene 

age are present in the Santa Ynez Unit where 

a "sandy zone" thickens from 53 m (175 ft) at 

the west (4 to 5 miles south of Point Conception) to 305 m (1,000 ft) 2G miles east in the 

Hondo field (U.S. Geological Survey, 1974, p. 

11-137, 138), where they are productive along 

with the overlying fractured shale of the same 

age (p. 11-163). A sandstone section of early 

Miocene age in the Rincon Formation is the 

main reservoir in the South Elwood offshore 

field (Dames and Moore, 1974; California Division of Oil and Gas, 1974) ; it is 47 m (155 ft) 

thick and occurs within a 305-m (1,000-ft)- 

thick section of deep-water marine shale. 

Twelve miles to the west in the Hondo field, 

probable equivalent sandstone beds occur as 

three separate units totaling around 33 net m 

(100 net ft) of sand (U.S. Geological Survey, 

1974, p. 11-163).

The presence of these early and middle Miocene sandstone units could not be predicted even 

though there is an almost continuous exposure 

of correlative strata in the upturned and eroded 

flank of the Santa Ynez Mountains only 6 miles 

to the north that extends eastward from Point 

Conception for over 60 miles. In addition, hundreds of wells have been drilled onshore along 

this trend and numerous onshore as well as offshore wells in State waters have penetrated this 

same shale section, and none are known to have 

cut these sands.

If such sands are found in the borderland, 

they may add significantly to the hydrocarbon 

potential. The Monterey sands in the Hondo 

field underlie the fractured Monterey siliceous 

shale reservoir, which is "anticipated to contribute the major portion of the ultimate Monterey oil recovery" (U.S. Geological Survey,

27
1974, p. 11-151). The sands are "unconsolidated, 

very fine to medium sized, quartz sand grains" 

(p. 11-153) with high porosities and permeabilities. Three tests in this reservoir indicate an 

initial daily rate estimated at 2,255 barrels of 

oil per day. Reserve estimates range from 94 

million barrels by the American Petroleum Institute (Oil and Gas Journal, 1975b) for the 

Hondo field to 3 billion barrels by the National 

Petroleum Council (McCaslin, 1975) for the 

Santa Ynez Unit of which Hondo is the largest 

field. The Rincon sandstone reservoir in the 

South Elwood field is much smaller, and the ultimate production is estimated at less than 10 

million barrels.

As reviewed in the onshore basins, the middle 

to late Miocene fractured siliceous shales are an 

important reservoir in areas such as Santa 

Maria basin and the newly discovered offshore 

fields in the Santa Ynez Unit of the Santa Barbara Channel. It seems reasonable, because of 

the widespread nature of the Miocene transgression over much of coastal California, that 

similar lithologies should exist and be potential 

reservoirs throughout the borderland. It is disappointing that dart cores of this age throughout the borderland are mainly fine-grained fossiliferous marlstone, mudstone, and siltstone 

that are not highly siliceous and do not appear 

comparable to the massive chert typical of the 

above proved reservoirs. This may be a sampling bias as a few chert lenses do occur in the 

diatomite sections on Santa Catalina and San 

Clemente Islands and diatoms are a common 

constituent in many Miocene dart cores. Volcanic detritus, especially glass shards, is common in some of the mudstone cores, but it is 

unlikely that diagenesis of these intermediate 

and basic volcanic sediments would transform 

them into dense cherts. It is conceivable that 

such sediments occur on the borderland, but 

they have not been identified. Structural reconstructions from seismic data suggest that during middle Miocene time the present basins 

were already subsiding more rapidly than the 

present ridges (at least the Santa Rosa-Cortes 

Ridge) (fig. 11). It is conceivable that more 

tuffaceous and siliceous sediments could have 

accumulated on the deeper flanks or in the 

basins.

An additional consideration is that onshore 

fractured shale reservoirs have difficult development problems. Erratic initial productive rates, 

common to many fields in the Santa Maria 

basin, are attributed to fracture porosity, resulting in many noneconomic wells. The overall 

moderate barrels-per-acre recoveries for these 

fields as noted in table 1, have been obtained as 

a result of close well spacing. Such close spacing 

would be prohibitively expensive in an offshore 

field. Declines in production commonly are steep 

for the first few years, after which they stabilize at low rates. This characteristic for an offshore field would result in a long life but high 

operating cost.

POTENTIAL PETROLEUM TRAPS

The structural style of the borderland has 

been reviewed by others (Moore, 1969; Vedder 

and others, 1974; Junger, 1975). Studies on 

specific folds and faults are limited to smaller 

areas that are generally adjacent to the coast 

or islands (Jennings, 1973; Ziony and others, 

1974; Campbell and others, 1975). Current U.S. 

Geol. Survey studies are in Santa Monica and 

San Pedro basins (Junger and Wagner, unpub 

data) and the shelf south of Santa Rosa Island 

and the Cortes and Tanner Banks (Greene, 

Clarke, and others, 1975).

Present knowledge indicates that fault patterns, types, ages, and displacements offshore 

are not significantly different from those onshore. Structural traps such as those associated 

with large-scale wrench faulting (Wilcox and 

others, 1973; Junger, 1975) are to be anticipated adjacent to such postulated strike-slip 

faults as the East Santa Cruz fault (Howell 

and others, 1974) and may result in the types of 

petroleum-bearing structures that have been so 

productive along the Newport-Inglewood trend 

of the Los Angeles basin (Harding, 1973).

Seismic profiles (Vedder and others, 1974, p. 

9-10)

suggest that the major folds on the outer part of the 

borderland are very broad and nearly symmetrical in 

contrast to typical structures in the Ventura and Los 

Angeles basins, where tight, steep-limbed, asymmetric, 

en echelon folds are commonplace. Acoustic profiling 

records recently made across the northern part of the 

Santa Rosa-Cortes Ridge confirm the presence of a 

large anticlinal structure that is steeper on its western

28
to

CO

< S 40° W

-ME CORTES BANK 

50 60

N40° E-

-TANNER BANK 

80 90

-SAN NICOLAS BASIN 

stratigraphic .frap.iv * - ' ' " ".--

^&»$t :W4;^te0^ii^»ii^ Eoc.-Olig. and volcanics*/ 'exposed on crest. Weak ' 

seismic reflectors. Struc- 

. turally complex ''.%*, .

.Onlqp of younger sediments^ \^£''^::^\

Zone of paleontologic 

control from dart cores 

in outcrop

Base of strong seismi 

Correlates to outcrop as 

base of Miocene

Vertical exaggeration 

approx. 6M

FIGURE 11. Original and interpreted northeast-southwest seismic profile across Tanner Bank, showing paleontologically dated samples. Profile record 

from -U.S. Geological Survey research vessel S.P. LEE cruise, November 1974, line 8, using 3-second sweep, 120 Kj sparker system (see fig. 6 

for location).
flank, but superimposed on it are numerous (smaller) 

discontinuous folds * * * Many topographic highs seem 

to reflect underlying anticlinal structure * * * Broad 

structural lows form both Santa Cruz * * * and San 

Nicolas Basins * * *, (but) both basins are flanked on 

their east and west margins by small northwest-trending low-amplitude folds that tend to die out basinward, 

although an upwarp is present in the central part of 

the San Nicolas Basin * * * Tight folds and faults complicate the structural pattern on the east and west ends 

of the (Santa Monica) Basin. San Pedro Basin is more 

complex and seems to have undergone two discrete 

phases of evolution in late Miocene time followed by 

post-Miocene downfaulting at the northwest end and 

folding throughout.

Anticlinal folding, both on a large and small 

scale, as well as a favorable structural jstyle 

associated with possible wrench faulting, shows 

that there are numerous structural prospects 

throughout the borderland. Many of the broad 

anticlinal structures that are in the shallower 

water depths in the outer basin area are eroded, 

exposing Paleogene strata along the crests (fig. 

11). Some of the largest productive structures 

in the onshore basins (such as Ventura-Rincon 

trend) are related to the extraordinary subsidence (more than 7,600 m; 25,000 ft) during 

late Neogene time and the rapid basin filling 

that was followed by post-late Pliocene deformation. Similar structures apparently are 

absent in the outer basins and do not seem to be 

well developed in the nearshore Santa Monica 

and San Pedro basins, a probable consequence 

of the much more subdued downwarping and 

only partial filling by post-Miocene sediments.

Prospective homoclinal traps with stratigraphic wedgeouts occur within the Miocene 

and younger section on many of the flanks of 

the major anticlinal ridges and banks where 

basinward thickening typically occurs. On the 

northeast flank of Tanner Bank the seismic 

character changes within the Miocene section, 

suggesting updip wedgeouts of a nonbedded section within a well-bedded sequence (fig. 11). 

The composition of the rocks that wedge out is 

unknown, as dart cores have recovered only 

Miocene mudstone updip on the erosional surface of the bank. The structural setting, age of 

sediments, and possible lithologic similarities 

are analogous to the Santa Maria Valley field 

in the Santa Maria basin.

Although much less can be interpreted seismically about the structures within the Paleogene rocks, the inferred structural complexity 

is greater than in Neogene rocks. Widespread 

Paleogene pinchouts are inferred in the deeper 

parts of the Santa Cruz and San Nicolas basins 

(fig. 7). These are believed to have formed by 

both eastward transgressive onlap and by truncation on the basis of surface mapping on Santa 

Cruz Island and interpretations of offshore 

seismic data (McLean and others, 1975; Junger, 

oral commun., 1975). This area is covered by 

thick marine Neogene shales, and there are 

obvious prospects where broad structures occur. 

Major obstacles to future production are the 

very deep water (about 1,000 m; 3,280 ft) and 

possible absence of source rocks to charge these 

potential reservoirs.

PETROLEUM RESOURCE ESTIMATES

Since 1971, there have been several published 

estimates of undiscovered petroleum resources 

in the borderland. These estimates are widely 

divergent, but direct comparisons are impossible because some are quoted as oil-in-place 

whereas others are given in terms of recoverable resources. They all cover different areas, 

and one is limited to areas of less than 200 m 

water depth. These estimates are reviewed here 

because they are being widely quoted, and they 

are not compatible with recently acquired geologic data.

Most estimates are based on the work of 

Parker (1971), who presented a well-documented report of the assumptions, methods, and 

data used to arrive at his estimate of 75 billion 

barrels of oil-in-place (exclusive of presently 

producing offshore fields) for the 18,500 mi2 

(11.8 million acres) of the borderland. In his 

opinion, the values are a "fair estimate if the 

thickness and extent of the Pliocene and upper 

Miocene strata are as shown on the maps and 

sections. However, these critical factors are 

based on scanty information and liberal interpretations" (p. 191). These strata are now 

known to be much thinner and of more limited 

area than inferred by Parker, and he was unaware that older sediments were widely exposed 

over much of the truncated Santa Rosa-Cortes 

Ridge. The immaturity of potential source rocks 

was not known, and the presence of adequate 

reservoir sands was given little discussion.

30
Parker's estimates were based largely on comparisons with the Los Angeles basin, a questionable premise in consideration of our present 

knowledge.

Using Parker's estimates, the Western Oil 

and Gas Association (WOGA) (1974, p. 11) 

concluded that "based on typical California recoveries (recoverable) reserves within the borderland included in the call for nomination (7.5 

million acres) would be in the range of 6 to 19 

billion barrels, with a gas/oil ratio of 2,000 

cubic feet per barrel" with 14 billion barrels 

given as a reasonable estimate of potential production. After identification of the proposed 

lease sale area (from 7.5 million acres in the 

nomination area to 1.56 million acres in the sale 

area), WOGA recommended no changes in their 

estimate of 14 billion barrels, and the Bureau 

of Land Management used this figure as the 

high range of recoverable resources in their 

Draft Environmental Statement (1975, p. 3).

Hardoin (1975) of the California State 

Lands Commission estimated 80 billion barrels 

of oil-in-place for the entire borderland (12 

million acres). He used the 75 billion barrels 

from Parker (1971) and included an additional 

5 billion for the already discovered offshore 

fields (Venice, Torrance, Wilmington, Belmont 

offshore, Huntington Beach, and West Newport).

In 1974, the U.S. Geol. Survey made estimates 

for the Bureau of Land Management on the 

potential recoverable resources in each of the 

five main areas within the proposed lease area 

(1.56 million acres) which ranged from 1.6 to 

2.7 billion barrels of oil (and 2.4 to 4.8 trillion 

ft3 of gas) (Bureau of Land Management, 1975, 

p. 1). Miller and others (1975), using additional geologic data and further study, reviewed the 

remaining resources for the entire continental 

United States and Alaska and the adjacent OCS 

areas in water depths to 200 m (656 ft). In 

their report, values for the borderland were not 

separated from the rest of the OCS area of 

California. Table 4 shows their estimates for 

the area in water deeper than 200 m. These 

estimates, listed with the probabilities of 5 percent, 95 percent, and most likely as defined by 

Miller and others (1975), were made using 

many of the data discussed in the present reTABLE 4. Estimated undiscovered recoverable oil resources, southern California borderland

[Values in billions of barrels of oil (Miller and others, 1975) ]

Depth

( metres )

Area

(mi-)

Estimated

range l

(95-5

percent)

Statistical

mean

Inner basin area ._

Outer basin area ..

Total borderland -..___

0-200 

>200

0-200 

>200

940

3.840

4,780

1,566

16,183

17,749

22,529

0.4-2.0 

.2-2.0

1.01 

.81

0 -0.24 0.06 

0 -1.6 .4

1 The low value is the quantity associated with a 95 percent 

probability (19 in 20 chance) that there is at least this amount, 

and the higher value is at the 5 percent probability (1 in 20 

chance).

port. Subsequent data, such as the organic 

chemistry analyses, have generally reinforced 

previous inferences bearing on the petroleum 

assessment, but several1 additional generalizations can be made. In depths less than 200 m, 

the most favorable areas appear to be in the 

inner basin area along the coast in the Santa 

Monica and San Pedro Bays, even though considerable exploration has already been done 

there and elsewhere around the periphery of 

the Santa Monica and San Pedro basins. At 

these water depths in the outer basin area there 

is at least a 5 percent probability that no recoverable oil will be found.

In depths below 200 m, potential resources at 

the 5 percent probability level are probably 

greater than shown in table 4. However, the 

recovery of petroleum at these depths will be 

very expensive and dependent upon the existence of large accumulations. The more favorable areas in deeper waters are judged to be:

1. Where the middle Miocene is at maximum or 

near maximum depth of burial.

2. In structural and stratigraphic traps on the 

flanks of major uplifts such as Tanner 

Bank.

3. In the vicinity of suspected large-scale lateral faulting where structures may be similar to those along the Newport-Inglewood 

trend.

4. Where pre-Miocene sediments are thickest 

and most deeply buried, and where shale 

predominates and may be richer in organic matter than so far measured.

5. In inferred shallow-marine sands of Oligocene or early Miocene age, structurally 

positioned to receive oil generated either

31
from the younger organic-rich Miocene 

sediments or from questionably inferred 

source rocks of older age.

No revised estimates have been made on the 

basis of these new data, for they are beyond 

the scope of this paper. As indicated, new data 

affect interpretations and the resulting assessment of the petroleum potential, but as of now, 

such data are not sufficient to alter the existing 

estimates substantially.

CONCLUSIONS

The southern California borderland, with its 

structural and sedimentary basins, is a part of 

the much larger Pacific plate margin which includes all the onshore oil-producing basins west 

of the San Andreas fault. An assessment of the 

petroleum potential of this frontier area is 

aided by comparing it with the similar, wellexplored oil-producing region.

The cumulative production in California (to 

January 1, 1975) amounted to 21,190 million 

barrels of oil (plus gas as barrels of oil equivalent) , and the remaining demonstrated reserves 

(proved and indicated) from known fields are 

currently estimated to be 5,775 million barrels 

of oil (plus gas as BOE). Over half of this production (11,852 million barrels) has come from 

five coastal basins; Los Angeles, Ventura, Santa Maria, Cuyama, and Salinas. The petroleum 

is unevenly distributed between these basins, as 

well as by stratigraphic age of the reservoir, by 

field size, and reservoir rock type. Los Angeles 

and Ventura basins account for 88 percent of 

the total oil produced. Of the 212 fields in these 

coastal basins, 52 percent of the oil has come 

from the five largest fields, and 87 percent of 

production has come from late Miocene and 

younger reservoirs with only 0.2 percent from 

Eocene and Cretaceous rocks. Over 80 percent 

is in reservoirs of thick deep-marine sands, and 

major accumulations in the Los Angeles and 

Ventura basins typically have net sand thicknesses exceeding 328 m (1,000 ft). Shallowmarine sands of excellent reservoir quality 

make up 10 percent of the reservoirs, and these 

are concentrated in the Salinas, Cuyama, and 

western Ventura basins. A minor but little understood reservoir is the fractured shale of the 

Miocene Monterey Formation. Nearly 5 percent

of all production in these coastal basins (552 

million barrels) has come from this formation 

in the Santa Maria basin, but recent discoveries 

and planned production in the Santa Barbara 

Channel may markedly increase the percentage 

derived from this reservoir rock type.

In the 59 fields with production over 20 million barrels, the dominant trap type is the 

faulted anticline. Most of the fields larger than 

100 million barrels have recoveries exceeding 

100,000 barrels per acre, and two are as high as 

500,000 barrels per acre. Recoveries in fields 

smaller than 50 million barrels are generally 

less than 50,000 barrels per acre.

If large accumulations similar to those onshore are to be found offshore, they will be in 

deep basins filled or partly filled with late Tertiary sediments, in thick buildups of deep marine turbidites, and in anticlinal structures. The 

petroleum presumably will have moderate oil 

gravity sufficient to ensure high per well recoveries. Large dry gas fields are not expected to 

be present. Smaller oil accumulations can be expected from shallow-water sands, probably of 

Oligocene or early Miocene age, and from fractured shale of the widespread Miocene Monterey 

Formation.

Many of the major requirements necessary 

for these large accumulations of petroleum are 

missing in the offshore region. The total sedimentary section is thin, and many banks and 

ridges have been truncated to expose early Tertiary rocks. Miocene strata rest directly on 

basement in large areas offshore. Early Tertiary rocks are present along Santa Rosa-Cortes 

Ridge but are much thinner than correlative 

strata onshore to the northeast. Thick turbidite 

sands equivalent to those in the onshore producing Los Angeles and Ventura basins are not 

expected to be present in any of the basins seaward of Santa Catalina Island. In addition, the 

nearshore Santa Monica and San Pedro Bays, 

which are the most favorable prospective areas, 

have yielded discouraging results from previous 

stratigraphic tests. Organic geochemical analyses reveal that the strata of Miocene age are 

very good to excellent potential source rocks 

and are comparable to those onshore that are 

the source for the large volumes of oil in the 

middle Miocene and younger reservoirs. The

32
early Tertiary samples, however, have insufficient organic matter to be considered as potential source rocks. Sampling on the ridges and 

banks indicates little depth of burial for the 

entire Tertiary section. The organic matter is 

immature, indicating little burial and a thermal 

regime insufficient for the generation of petroleum. Although seeps are common onshore 

and in the Santa Barbara Channel, no documented oil or gas seeps have been reported seaward of the Channel Islands. Only 11 percent of 

the borderland is in water less than 200 m (660 

ft) deep, a factor that should be considered 

from a practical and economic standpoint.

The positive aspects for petroleum occurrence 

on the borderland include the high organic content of the Miocene section. In the more deeply 

buried areas of the borderland, these strata 

could be excellent source rocks, and there is 

some evidence that temperature histories need 

not be as high as previously deduced for the 

generation of asphaltic oil from this type of 

organic shale. Fractured shale reservoirs both 

in the deeper basins and on the down-flank margins of major uplifts are prospective areas for 

significant accumulations. Structural traps, although generally not having dips as steep as 

those onshore, are present throughout the borderland. Because the early Tertiary depositional history is as yet little understood, large areas 

of the borderland may contain shallow-water 

sands of excellent reservoir quality, particularly those laid down in Oligocene and early Miocene time prior to the major Miocene transgression. The distribution, thickness, and character 

of Late Cretaceous and Paleocene rocks are 

poorly known and are not considered. The areal 

distribution of dart cores that recovered Eocene 

sediments is limited, and this sampling bias may 

have overlooked potential Eocene or older 

source rocks that could have charged these inferred reservoirs.

Previous estimates on the petroleum potential are not compatible with all the known geologic facts. Although there are many gaps in 

our knowledge of this area, it is unlikely that 

additional geologic data will vary so greatly as 

to justify any marked increase in the estimates 

already published by the U.S. Geol. Survey 

(Miller and others, 1975). Additional data will,

however, more closely delineate prospective 

areas for possible exploratory drilling. The most 

favorable areas for significant accumulations 

are those in deep water.

REFERENCES CITXD

American Petroleum Institute, 1975, Reserves of crude 

oil, natural gas liquids, and natural gas in the United 

States and Canada and the United States productive 

capacity as of December 31, 1974: Am. Petroleum 

Inst, v. 29, May 1975, 254 p.

Bailey, T. L., 1947, Origin and migration of oil into 

Sespe redbeds, California: Am. Assoc. Petroleum 

Geologists Bull., v. 31, no. 11, p. 1913-1935.

Baker, C. R., 1972, Organic geochemistry and geological 

interpretations: Jour. Geol. Education, Oct. 1972, 

p. 221-234.

Baldwin, T. A., 1971, Petroleum potential of California 

central Coast Ranges, in Cram, I. H., ed., Future 

petroleum provinces of the United States their geology and potential: Am. Assoc. Petroleum Geologists 

Mem. 15, p. 309-315.

Barbat, W. F., 1958', The Los Angeles basin area, California, in Higgins, J. W., ed., A guide to the geology 

and oil fields of the Los Angeles and Ventura regions 

(California) : Am. Assoc. Petroleum Geologists and 

Soc. Econ. Paleontologists and Mineralogists, Pacific 

Sees., p. 37-49; in Weeks, L. G., ed., Habitat of oil 

 a symposium: Tulsa, Okla., Am. Assoc. Petroleum 

Geologists, p. 62-77.

Beyer, L. A., Sasnett, N. B., Pisciotto, K. A., 1975, Interpretation of gravity and magnetic surveys of the 

California continental borderland (abs.) : Am. Assoc. 

Petroleum Geologists Pacific Sec. Mtg., Long Beach, 

Aprl 23-26, 1975, p. 8.

Bramlette, M. N., 1946, The Monterey Formation of California and the origin of its siliceous rocks: U.S. Geol. 

Survey Prof. Paper 212, p. 567-560.

Bray, E. E., and Evans, E. D., 1965, Hydrocarbons in 

the non-reservoir rock source beds: Am. Assoc. 

Petroleum Geologists Bull., v. 49, p. 248-257.

Bureau of Land Management, 1975, Proposed 1975 outer 

continental shelf, oil and gas general lease sale, offshore southern California, OCS Sale No. 35: Draft 

Environmental Statement, Washington, D.C., U.S. 

Govt. Printing Office, DES 75-8, v. 1-4, variously

California Division of Oil and Gas, 1974, California oil 

and gas fields; south, central coastal and offshore 

California, v. 2: California Div. Oil and Gas Rept. 

TR 12.

 1975, 60th annual report of the State oil and gas 

supervisor: California Div. Oil and Gas Rept. PRO6, 

175 p.

Campbell, R. H., Wolf, S. C., Hunter, R. E., Wagner, 

H. C., Junger, A. and Vedder, J. G., 1975, Geologic 

map and sections, Santa Barbara Channel region, 

California: U.S. Geol. Survey open-file map 75-123.

33
Clarke, S. H., and Nilsen, T. H., 1973, Displacement of 

Eocene strata and implications for the history of 

offset along the San Andreas Fault, central and 

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34
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36
TABLES 5-11

TABLE 5. Major fields: Los Angeles basin 

[Ranked-by cumulative oil plus BOB1 to January 1, 1975]

Field

Long Beach

Dominquez

Coyete West

Seal Beach

Montebello

Torrance

Richfield _

Rosecrans

Coyote East

Total (14 fields)

Others (46 fields)

Total basin (60 fields)

Cumulative 

oil 

( thousands of 

barrels)

1,681,737

878,214

923,792

600,694

343,619

296,658

258,309

232,151

188,000

184,506

182,294

164,863

89,828

98,142

6,122,807

598,275

6,721,082

Cumulative 

oil + 

gas as 

BOE

1,843,544

1,060,29.7

1,053,719

740 971

413,538

336,409

321,239

264,438

221,735

oiq oqi

203,106

193,561

122,943

112,960

7,108,354

751,411

7,859,765

Percent 

of 

total

23.5

13.5

13.4

9.4

5.3

4.3

4.1

3.4

2.8

2.7

2.6

2.5

1.6

1.4

90.5

9.5

100.0

Cumulative 

percent 

of basin 

total

23.5

37

50.4

59.8

65.1

69.4

73.5

76.9

79.7

82.4

85.0

87.5

89.1

90.5

90.5

100.0

Maximum 

proved 

acreage

14,500

1,815

6,290

1,480

2,430

1,215

1,670

1,125

870

1,600

7,273

1,600

725

42,593

17,301

59,894

Bbls/ 

acre 

( cumulative 

oil + 

BOB)

127,141

584,185

167,523

500,656

170,180

276,880

192,359

234,056

254,868

127,434

27,926

120,976

169,577

75,056

1 BOE= Barrels oil equivalent of gas at 6,000 ft3 =l bbl oil (approx BTU equivalent).

- Wilmington field is treated separately here, but in table 1 the Wilmington trend includes Wilmington, Torrance, and Belmont 

offshore.

TABLE 6. Major fields: Vcntura basin

[Ranked by cumulative oil plus BOE to January 1, 1975]

Field

South Mountain (excludes 

Bridge Pool)

Elwood

Placerita

Montalvo West *

Del Valle 1 _ __ _

Summerland offshore

Oxnard

Molino Gas offshore 1

Castaic Junction

Honor Rancho

Shiells Canyon

Romona

Bardsdale

Total (20 fields) __

Total (92 fields)

Basin total (112 fields)

Cumulative 

oil 

( thousands 

of barrels)

851,286

123,526

93,261

103,277

102,248

69,874

56,822

50,369

44,874

41,048

34,169

24,903

94 21 Q

34,056

0

27,415

25,504

23,034

19,543

12,515

1,761,943

204,880

1,966,823

Cumulative 

oil + 

BOE 

(thousands) 

of barrels)

1,208,094

153,440

1 94 Q39

117,742

110,694

83,377

76,119

69,043

50,708

42,180

41,912

40,793

38,167

37,581

36,733

34,561

32,162

30,322

25,701

25,157

2,379,418

265,227

2,644,645

Percent 

of 

total

45.7

5.8

4.7

4.5

4 9

3.2

9 Q

2.6

1 Q

1.6

1.6

1.5

1.4

1.4

1.4

1.3

1 2

1.1

1.0

1.0

90.0

10.0

100

Cumulative 

percent 

of 

basin 

total

45.7

51.5

56.2

60.7

fi4 Q

68.1

71.0

73.6

75.5

78.7

77.1

80.2

81.6

83.0

84.4

85.7

86.9

88.0

89.0

90.0

90.0

100.0

Maximum 

proved 

acreage

3,980

2,110

3,210

1,050

1,200

1,490

640

1,100

215

760

1.860

660

830

1,860

1,130

1,640

720

1,045

590

590

Bbls/ 

acre 

( cumulative 

oil + 

BOE)

303,541

72,720

38,920

112,135

92,245

55,958

118,936

92,766

235,851

55,500

22,533

61.800

4^ 984

20,205

32,507

21,074

44,669

29,016

43,561

42,639

1 Gas fields or fields with dry-gas zones.

39
TABLE 7. Major fields: Santa Maria basin

[Ranked by cumulative oil plus BOE to January 1, 1975]

Field

Orcutt

Cat Canyon West _

Lompoc

Gato Ridge _ _

Casmalia

Total (7 fields)

Others (13 fields)

Basin total (20 fields)

Cumulative 

oil 

(thousands of 

barrels )

. __ 159,418

. __ 148,796

136,576

. __ 40,417

36,462

. _ 37,535

._ __ 31,584

. __ 590,788

51,991

__ 642,779

Cumulative 

oil + 

BOE 

( thousands of 

barrels )

195,732 

172,714 

152,841 

47,243 

39,834 

38,115 

34,179

680,658 

55,321

735,979

Percent 

of 

total

26.6 

23.5 

20.8 

6.4 

5.4 

5.2 

4.6

92.5 

7.5

100

Cumulative 

percent 

of 

total

26.6

50.1

70.9 

77.3 

82.7 

87.9 

92.5

92.5 

100

Maximum 

proved 

acreage

7.630 

4,730 

2,980 

2,290 

780 

3,470 

2,690

 

Bbls/ 

acre 

( cumulative 

oil + 

BOE)

25,653 

36,515 

51,289 

20,630 

50,830 

10,984 

12,706

TABLE 8. Major fields: Cuyama basin

[Ranked by cumulative oil plus BOE to January 1, 1975]

Field

Cuyama South

Russell Ranch

Total (2 fields) _

Others (3 fields)

Basin total (5 fields) .

Cumulative 

oil 

(thousands of 

barrels )

_ 208,536

. _ 64,887

_ _ 273,423

2.868

_ 276,291

Cumulative 

oil + 

BOE 

f thousands of 

barrels )

243,273 

71,977

315,250 

3,183

318,433

Percent 

of 

total

76.4

22.6

99.0 

1.0

100.0

Cumulative 

of 

basin 

total

76.4 

99.0

99.0 

100.0

 Maximum 

proved 

acreage

2,560 

1,550

Bbs/ 

acre 

( cumulative 

oil + 

BOE

95,029 

46,437

TABLE 9. Major fields: Salinas and central coastal

[Ranked by cumulative oil plus BOE to January 1, 1975]

Field

Cumulative

oil

(thousands of 

barrels)

Cumulative 

oil + 

BOE 

(thousands of 

barrels)

Percent

of 

total

Cumulative

of

basin 

total

Maximum 

proved 

acreage

Bbls/ 

acre 

(cumulative 

oil + 

BOE)

San Ardo _____.

Others (14 fields)

Total __.

274,181

4,572

278,753

286,032

5,936

291,968

96.5 

3.5

96.5

100

100

4.490 63,704

40
TABLE 10. Organic geochemistry of dart samples from the southern California borderland and Miocene outcrop

samples from the southwestern Santa Ynes Mountains

[Analyses by U.S. Geological Survey Organic Geochemistry Laboratory, Lakewood, Colo. ]

Age and sample No.

Late Cretaceous

KZ 73-1-39 ____ .. ____ .

Early Eocene

LCB 111-10 __ . _____ __ .

LCB 110-8 _____ ______ .

Early-middle Eocene

LCB 110-10 ____________ .

KZ 73-1-22 . ... ... . __ .

KsB 697-13 .. __ ----..

Middle Eocene

KZ 73-1-20 . - _ .- __ . ...

KZ 73-1--36 .. ._ . . __ . _ .

LCB 110-5 _____ .- __ ._. .

LCB 110-1 - -. ..- . _

Late Eocene or Oligocene

LCB 130-8B . .... ......

Early Miocene

LCB 106-4 __ . ______ . __ .

LCB 111-1 __________ ...

LCB 133-6 . - __ _ . .....

LCB 106-19 __ . __ . __ ....

LCB 106-6 _ .... .. .

LCB 110-20 ______ , __ ....

Early or Middle Miocene

LCB 127-7 _______ __ . __ .

LCB 143-6 . __ ... .. .. .

LCB 120-2 ... ___________ .

KSB 908-2 .. ___ ____ ....

KSB 908-3

KSB 709A-6 _____ _____ .

LCB 105-12 .. _______ . __ . 

Middle Miocene

LCB 117-5B __ ______ ... 

LCB 128-1 ___ __ . __ .. . 

LCB 129-5B ..... ______ ... 

LCB 133-7 

SCSF 74AA-117 __ ... 

SCSF 74AA-121 .... 

SCSF 74AA-131 ... .... 

LCB 108-11 

LCB 109-4B . .. . 

LCB 135-3 . 

LCB 134-6 . .. _ . 

LCB 135-11 . . . _ . 

LCB 134-14 . .

LCB 3-3 ... __ . __ .

KSB 783-6 ..._.. .... 

KZ 73-3-4 

KZ 73-4-1

K7, 73-7-2 

KSB 907-1A ......... 

KSB 906-7 

KZ 73-9-10 

KZ 73-10-27 

LCB 123-4

Middle or late Miocene

LCB 112-1 ... __ .... 

SCSF 74AA-118 

KSB 783-8 

KZ 73-1-8 . .. 

KZ 73-7-1

KZ 73-6-10 .. . 

LCB 107A-5B 

K7, 73-9-3 . . 

KZ 73-9-16 .. 

LCB 116-PB 

LCB 116-5B 

LCB 106-18 .. . 

LCB 105-17 ... 

Late Miocene

LCB 123-1 _ . 

KSB 709A-8 

SCAL 75KD 286 10 

SCAL 75KD 474 " ...

LCB 106-1 _____ . __ ....

LCB 125-4 .....

LCB 126-12 __ ....

LCB 131-3 __ . .......

LCB 109-1 __ .. __ ...

carbon

percent)

0.2

.2

.5

. - 2.5

- - .2

<.l

.2

.2

.4

.5

.7

1.5

4.1

4.1

2.7

1.5

5.1

11.1

4.4

7.3

3.2

1.8

6.8

2.7

5.9

3.7

4.2

2.0

 3.2 

.6.9 

6.1 

6.5 

5.9 

4.7 

9.3 

6.4 

8.5 

6.7 

1.9 

3.9 

3.3

4.6

1.4 

1.7 

4.7 

3.2

3.1 

5.6 

6.1 

7.5 

5.3 

6.3 

0.5

3.5

11.2

8.2 

2.2 

3.2

6.5

5.4 

6.3 

5.7 

7.9 

1.7 

6.5

5.5 

7.0 

7,4 

12.0

6.1

6.3

6.3

9.3

2.3

Carcarbon

1 percent )-

5.0

2.4

.5

2.8

.6

1.0

2.6

1.5

.6

1.0

.5

8.1

1.6

.6

1.0

2.1

1.9

3.3

3.6

2.9

1.8

1.6

1.7

1.1

1.9

.4

3.5

.1

1.8 

6.5 

2.8 

1.3 

3.0 

4.0 

6.4 

1.1 

2.8 

2.7 

7.9 

7.3 

.8

4.5

2.2 

<.01 

3.4 

2.2

.6

!05 

2.7 

2.3 

.7 

2.0

5.1

3.2 

5.5 

1.4

1.8

7.3 

1.7 

6.1 

5.6 

3.2 

6.8 

2.4 

2.0

3.2 

5.4 

3.3 

5.3

3.5

7.2

7.7

6.4

8.2

3.5

Extractable hydrocarbons

Bitu-

(ppm) :i

62

526

111

184

441

685

1,765

1,033

352 

1,080 

551 

1,419 

1,452 

1,450 

1,617 

880 

953 

1,015 

207 

364 

351

1,374 

1,385

992 

2,123

883 

1,154

721

695

772

6,244

627

260

Total

(ppm) 4

8

65

6

50

101

142

576

340

52 

450 

116 

228 

200 

289 

433 

131 

190 

288 

63 

127 

54

571 

303

57 

56 

43 

54

185

207

347

0

164

119

S/A^>

2.67

1.14

1.0

.69

.35

.01

.13

.27

.04 

.36 

.29 

.04 

.27 

.08 

.02 

.01 

.14 

.02 

.26 

.05 

.06

....

....

....

.15 

.08

....

.48 

.60 

.27 

.30

.08

.25

.06

.20

percent B

0.40

.26

.09

.33

.25

.35

.52

.77

.16 

.65 

.19 

.35 

.34 

.61 

.47 

.20 

.22 

.43 

.33 

.33 

.16

...

...

...

.51 

.37

...

.10 

.08 

.06 

.04

.30

.33

.55

.32

.52

isoiaH/C*

1.20

1.30 

1. 1$ 

1.37

--.

...

...

1~30

...

...

1.18

1.32

Location a

X

904,687

906,279

931,689

929,349

951.U83

728,407

956,411

914,630

934,810

937,777

1,060,612

900,668

932,889

1,244,063

851,891

894,616

919,704

1,078,927

1,528,677

873,738

838,100

871,740

1,092,409

1,150,101

709,232

699,012

848,223

801,793 

1,085,266 

1.093,549 

1,241,643 

1,065,502 

1,057,617 

1,034,021 

1,103,577 

1,095,178 

1,337,926 

1,309,649 

1,315,337 

1.287,710

774,588

707,549 

889,957 

1.017,287 

1,068,556

1,062,962 

1,183,961 

1,182,699 

1,121,873 

1,323,239 

1,476,422 

978.459

797,531

902,125 

1,063,136 

884,535 

992,121 

1,184,163

1,173,951 

935,115 

1,348,578 

1,307,693 

789,797 

784,854 

853,316 

840-.702

989,053 

704,101 

1,118,588 

1,017,028

910.466

979.596

1,022,557

1,044,373

1,052,880

1,100,093

y

413,034

467,598

453,069

459,303

430,043

729,556

435,628

413,061

443,787

431,667

160,792

597,430

478,393

128,871

599,655

597,557

490,505

215,823

214,818

2li7,093

210,265

632,951

565,116

454,195

754,500

742,959

625.475

353,614 

183,406 

165,988 

127,062 

236,378 

227,512 

209,102 

509,148 

496,678 

20,150 

21,952 

34,418 

36,331

543,553

706,061 

577,686 

276,379 

268,414

262,757 

186,532 

538,333 

533,709 

201,483 

186,368 

200,393

652,121

432,699 

234,231 

577,876 

446,920 

186,704

507,567 

656,916 

206,722 

201.515 

377,707 

375,089 

599,503 

609,808

199,635 

748,697 

227,887 

263,057

596,386

337,137

281,661

159.743

137,830

488,784

See footnotes at end of table.

41
TABLE 10. Organic geochemistry of dart samples from the southern California borderland and Miocene outcrop 

samples from the southwestern Santa Ynez Mountains Continued

Age and sample No.

Late Miocene Continued 

SCSF 74AA-12S ____ . __ ..__

KZ 73-14-3 __ _- __ - --

KZ 73-14-14 __________ - 

LCB 141-5 _______ -. __ --_

KSB 709A-22 __________ _ _

LCB 105-21 ______ - ----._

Late Miocene or early Pliocene 

KZ 73-2-40 _______ ___ _ ______

KZ 73-3-44 _ _ _

KZ 73-9-28 _____ - _ _ .

Holocene 

SCAL 75KD 416 10 _ __ _

Miocene outcrops 1T Wood 3-1 -_. _ .

Gav 19 6A _ _ _ _ _

Aw? 6C-10B - _ . _

Bix 7-2A .

Wood 9-1

CarOrganic bonate 

carbon carbon 

(weight (weight 

percent) 1 percent)

5.9

10.0

6.3

5.6

7.5

9.4

6.7

5.1

6.2

4.6

6.5

1.0

9.2

3.1

6.4

1.9

6.5

1.0

5.8 

3.5 

5.4 

7.0 

7.6 

4.6 

4.4 

5.7 

.8 

4.6

7.5 

7.4 

4.7

4.3

8.5 

5.1 

1.3 

10.6

Extrac table hydrocarbons

Bitumen 

- (ppm) :!

724

229

134,100 

1,854 

5,214 

1,375 

9,982 

1,018

Total 

HC 

(ppm) 4

173

58

40,000 

461 

1,128 

647 

1,278 

159

S/A 5

.09

....

2.00

l'.15 

.15 

.56 

.1 

.22

isolaHC/C tion ' 

percent 0 H/C S

.29 1.30

 

.58 

43.5

1.5

1.76

3.41

2.0

1.59

Location °

X

1,042,031 

707,128 

996,675 

1,063,320 

1,173,951 

1,285,010 

1,254,088 

1,484,555 

677.432 

845,384

973.801 

963.601 

1,271,705

1,122,207

y

213,417 

705,717 

459,800 

262,807 

180,596 

335,814 

324,027 

161,989 

713,505 

600,414

350,548 

344,629 

190,728

92,169

1 Acid-insoluble carbon by combustion.

" Total carbon minus acid-insoluble carbon.

 '' Total chloroform-extractable organic matter.

4 Sum of organic extract eluted from silica-gel with (a) heptane and (b) benzene.

5 Ratio of saturated hydrocarbons (heptane eluate) to aromatic hydrocarbons (benzene eluate).

0 Ratio of total hydrocarbon to organic carbon in percent.

7 Nonextractable organic matter isolated by HC1-HF digestion, heavy liquid flotation, visual examination, elemental analysis for C, H, 

N.

s Atomic ratio of hydrogen to carbon in kerogen.

0 Lambert coordinates, California zone 6.

111 Samples frozen upon collection and kept frozen until analyzed.

11 Outcrop samples are from the Monterey Formation in the southwest Santa Ynez Moontains between Point Conception and Gaviota. 

Variable lithologies as follows: Wood-3-1, calcareous; shale; Gav-10-9, dolomite calcareous shale; Gav-19-6A, cristobalitic shale; Aug6C-10B, phosphatic dolomite; B5x-7-2A, quartz porcelanite; Wood-9-1, quartz chert.

42
TABLE 11. Organic geochemistry of Eocene outcrop samples, San Nicolas Island

[Analyses by Continental Oil Co.]

Unit

No.1

9ft

20 _ _ __ _ .

20 _ __ __ __

18 _ __

18 _____

18 _ _ __

18 _ 

18 _ _ __ _ .

18 __

16 _ ----- _ __.

16 ___ _______ _ -

16 __

16 _

16 _ _ _ _

14

12 _____ _

12 __ _

12 __

10 _______

8 __ __ _ _ .

6 _ _ ______

6 _ _ __

6

6 _- ______

6 -__ _ _ - - .

6 - - _ _ _ .

6 __ . - - -

6 _ _

6 _

6 _ _

6 ______

6

6 - -

6 __ _ _ _ .

6 _ _ 

6

6 _

6 _

6 _

6 _ _ _ __ _ _ _.

6 _ _

6 

6 _ _ _ __ _- .

6 _ _

Total samples 44

Mean value, organic content wt.

Standard deviation ____0.18

sample

No.

E

n

E-4

E-la

55-211

. _ 55-216

. _ 55-204

. . 55-196

_ _ 55-190

55-189

55-163

. _ 55-157

55-152

55-150

55-144

55-141

55-135

55-132

55-131

55-130

55-120

55-116

55-77

. __ 55-69

55-64

55-99

55-55

AX-5

. _ 55-45

55-36

AX-2

M-27

AX-1

. __ 55-25

55-21

55-18

55-12

_ __ M-16

M-13

M-ll

K-2

. _ M-7

M-5

. _ M-3

M-l

percent ____ 0.30

Organic

( weight

percent)

< !

< 1

.31

.73

.12

.22

.13

.12

.3

.26

.38

.48

.11

.12

.12

.40

.28

.24

.12

.11

.12

.13

.16

.12

.29

.38

.49

.37

.32

.45

.29

.36

.35

.36

.32

.63

.78

.56

.14

.43

.61

.50

.21

Extractable hydrocarbon

Total

(ppm)

91 ft

160

210

140

340

150

350

200

80

140

80

170

510

100

30

60

260

300

80

50

.100

180

60

160

90

110

180

230

160

90

180

70

80

110

110

90

300

600

350

520

180

240

310

140

HC

(ppm)

84

53

0

29

38

73

102

73

<80

28

20

44

90

24

<30

<60

32

39

<80

<50

30

60

<60

42

28

18

22

33

39

13

41

9

13

11

21

22

75

180

93

222

34

40

89

32

HC/C

>8.4

>5.3

.94

.52

6.1

4.6

5.6

<6.7

.93

.77

1.2

1.9

2.2

<2.5

<5.0

.80

1.4

<3.3

<4.2

2.7

5.0

4.6

2.6

2.3

.62

.58

.67

1.1

.41

.91

.31

.36

.31

.58

.69

1.2

2.3

1.7

15.9

.79

.66

1.8

1.5

Unit number shown in Vedder and Norris (1963, pi. 5).

43