BASIN AND PETROLEUM SYSTEM MODELING OF …...7 LIST OF FIGURES Figure 1: Map shows location and...

BASIN AND PETROLEUM SYSTEM MODELING OF THE SUR AND

NORTHERN OFFSHORE SANTA MARIA AREAS, OFFSHORE CENTRAL

CALIFORNIA

A THESIS

SUBMITTED TO THE DEPARTMENT OF GEOLOGICAL AND

ENVIRONMENTAL SCIENCES AT LELAND STANFORD JR. UNIVERSITY

IN PARTIAL FULFILLMENT OF THE REQUIREMENTS

FOR THE DEGREE OF MASTER OF SCIENCE

Keisha Alana Durant

December 2011

3

ABSTRACT

The Sur basin (also called the Partington basin) is an undrilled, asymmetrical

basin offshore central California. It is the northwestern extension of the offshore Santa

Maria basin, and therefore shares similar stratigraphy and tectonic history. Although

some successful petroleum discoveries have occurred in the southern offshore Santa

Maria area, the Sur basin and northern offshore Santa Maria areas have never been

commercially explored. Peters and others (2008) collected tarball and seep samples from

the central California coast and suggested that some may have originated from seeps

within the Sur and northern offshore Santa Maria areas. In this study, we used three-

dimensional (3D) basin and petroleum system modeling to evaluate whether a mobile

petroleum charge exists in these areas. A 3D geologic model of the Sur and northern

Santa Maria areas was constructed by converting travel time isopach maps to depth via

well data available in the nearby southern offshore Santa Maria area. Because Type IIS

kerogen generated significant amounts of heavy sulfur-rich crude oil in the southern

offshore Santa Maria area, Type IIS kerogen kinetics was used to simulate petroleum

generation from the Miocene Monterey Formation in the 3D basin model. The Monterey

Formation was split into the lower calcareous-siliceous, the carbonaceous marl and the

clayey-siliceous members. Other stratigraphic inputs for the model included the Lower

Foxen, the Upper Foxen, the Lower Sisquoc and the Upper Foxen Formations. The

model results suggest that the Miocene Monterey Formation source rock is thermally

mature and generated volumetrically significant accumulations of low-maturity

petroleum in minor anticlines sealed by the mudstone of the Sisquoc Formation or by the

4

clayey-siliceous member of the Monterey Formation. The model results also suggest the

potential for unconventional shale oil opportunities.

ACKNOWLEDGEMENTS

I would like to thank my advisors Stephan Graham and Mike Moldowan for their

direction, encouragement and assistance. Even when there were complications with my

project, they were always optimistic and supportive. I would also like to thank the other

faculty affiliates of the BPSM consortium at Stanford University, Allegra Hosford

Scheirer, Kenneth Peters, Leslie Magoon and Tapan Mukerji for their contributions to

this work by providing helpful discussions and constant support and guidance throughout

this process. Thank you for sticking with me, even with the frustrations along the way.

Carolyn Lampe and Oliver Schenk, thank you so much for answering my endless

software and basin modeling questions. You were both so very helpful and were always

quick to respond to my queries. I learnt so much from you both and I am so grateful.

I would like to especially thank Blair Burgreen and Tess Menotti for their support.

I have wonderful memories of us starting our journey together, taking the same classes,

keeping each other company at the office late at night. You made it so much fun and

your encouragement was greatly appreciated. I would also like to acknowledge some of

my other colleagues at Stanford for their useful discussion and support: Glen Sharman,

Julie Fosdick, Katie Maier, Theresa Schwartz, Matt Malkowski, Larisa Masalimova, Lisa

Stright, Lizzy Trower, Meng He, Danica Dralus, Zane Jobe, Anne Bernhardt, Jon Rotzien

and Liz Cassel.

5

I am also appreciative of the help that I obtained from Tom Lorenson, Ray Sliter

and Margaret Keller at the USGS. You were all extremely helpful with quickly fulfilling

data requests and technical knowledge and I could not have completed this project

without your help. I would like to thank David McCulloch, Sara Foland and Dan

Schwartz for useful discussions and offering as much information about the study area as

they could.

I am also thankful to the industry affiliates of the BPSM consortium at Stanford,

Aera Energy, BP, Chevron, Occidental Petroleum, JOGMEC, Petrobras, Saudi Aramco,

Hess and Schlumberger for financial assistance for my Masters research.

I would like to thank my husband Ryan for his support. He spent many nights up

late with me, keeping me company while I worked, and making sure that I was well taken

care off, even when I neglected to take care of myself. I would not have made it through

without him. To my loving family, my mummy Annette, my daddy Hamilton, my sister

Kervelle and my brother, Keiron, thank you so much for all the support, encouragement

and prayers throughout my academic career.

Finally, I would like to thank my Lord and Savior Jesus Christ for giving me this

opportunity and giving me the wisdom and grace to finish this project.

6

TABLE OF CONTENTS

ABSTRACT ........................................................................................................................ 3 ACKNOWLEDGEMENTS ................................................................................................ 4 LIST OF FIGURES ............................................................................................................ 7 INTRODUCTION .............................................................................................................. 9 GEOLOGIC SETTING .................................................................................................... 11

Structure and Tectonics ................................................................................................. 12 Stratigraphy ................................................................................................................... 13

Basement Rocks and Volcanics ................................................................................ 14 Monterey Formation ................................................................................................. 14 The Sisquoc Formation ............................................................................................. 15 The Foxen Formation ................................................................................................ 16 Correlation of stratigraphy between the offshore Santa Maria basin and the Sur Basin ......................................................................................................................... 17

Petroleum Geology of the southern offshore Santa Maria Area ................................... 17 METHODS ....................................................................................................................... 19

3-D Model Input Parameters ......................................................................................... 19 Chronostratigraphic Units ......................................................................................... 19 Paleo-water Depth ..................................................................................................... 22 Heat Flow Analysis: Basal Heat Flow and Sediment-Water Interface Temperature 22 Calibration ................................................................................................................. 23

RESULTS AND DISCUSSION ....................................................................................... 25 3-D Model Output ......................................................................................................... 25

Predicted Petroleum Potential ................................................................................... 25 Modeled Thermal Maturity and Expulsion Timing .................................................. 27 Monterey3 member – lower calcareous-siliceous member ...................................... 27 Monterey2 member - the middle carbonaceous marl member ................................. 28 Monterey1 Member - the upper clayey-siliceous member ....................................... 29

CONCLUSION ................................................................................................................. 30 FIGURES AND TABLES ................................................................................................ 32 APPENDIX ....................................................................................................................... 52 REFERENCES ................................................................................................................. 54

7

LIST OF FIGURES

Figure 1: Map shows location and geological setting of the Sur basin and the offshore Santa Maria basin modified after McClellan et al. (1991) and Sorlien et al. (1995). Study area is outlined by red dashed line. Faults are solid red lines. Basin outlines are solid blue lines. .......................................................................................................................... 32 Figure 2: Map shows locations of data available for this study. Purple lines are seismic lines used by Pankow (1997), yellow circles are wells drilled in the offshore Santa Maria Basin, green triangles are tarball and seep samples collected near the Sur and northern offshore Santa Maria areas for the Peters et al. (2008) study. .......................................... 33 Figure 3: Stratigraphic column of the offshore Santa Maria basin modified after Hoskins and Griffiths (1970) .......................................................................................................... 34 Figure 4: Isopach map (meters) of the Monterey Formation in the Sur and northern Offshore Santa Maria areas using data from Pankow (1997). .......................................... 35 Figure 5: Calculated fractional conversions based on an assumed heating rate of 1°C/m.y. for 29 worldwide petroleum source rocks that contain mainly type II kerogen (Peters et al., 2006) ........................................................................................................................... 36 Figure 6: Isopach map (meters) of the Lower Foxen Formation in the Sur and northern Offshore Santa Maria areas using data from Pankow (1997). .......................................... 37 Figure 7: Migrated seismic reflection lines A-3. The section shown is from the northern offshore Santa Maria area. 1=Upper Foxen; 2=Lower Foxen; 3=Upper Sisquoc; 4=Lower Sisquoc; 5=Monterey. Vertical axis is plotted in two-way travel time. ........... 38 Figure 8: Paleobathymetry curve for the COST well (OCS-CAL 78-164-1) modified from McCrory et al. (1995). ...................................................................................................... 39 Figure 9: Paleobathymetric curve from the P-496-1 well modified after McCory et al 1995. .................................................................................................................................. 40 Figure 10: Petromod Auto-SWIT tool showing Global mean surface temperature as a function of latitude and time, based on Wrygrala (1989). ................................................ 41 Figure 11: Sterane mass chromatograms (m/z 217) for one of the tarball samples collected near the Sur and northern offshore Santa Maria areas. ..................................... 42 Figure 12: Approximate ranges of biomarker maturity parameters are shown versus vitrinite reflectance and a generalized oil-generation curve from Peters et al. (2005). .... 43

8

Figure 13: Shows accumulations (green) predicted in the 3-D model within the Sur and northern offshore Santa Maria Areas. The model predicts 31 accumulations containing 28.76 million barrels of oil (MMbbl). ............................................................................... 44 Figure 14: NW-SE cross-section through the 3-D model shows anticlinal closures that trap oil in the Monterey2 Reservoir, and locations of 1-D extractions for the Sur and northern Offshore Santa Maria areas at region of maximum overburden (NOSMPseudo and SurPseudo). ................................................................................................................ 45 Figure 15: Burial history at region of maximum overburden in the Sur area ................... 46 Figure 16: Burial history at region of maximum overburden in the northern offshore Santa Maria area ............................................................................................................... 47 Figure 17: Map of modeled present-day transformation ratio for the Monterey Formation in the Sur and northern offshore Santa Maria areas .......................................................... 48 Figure 18: Map of modeled present-day thermal maturity expressed as vitrinite reflectance in the Sur and northern offshore Santa Maria areas. Vitrinite reflectance was calculated using the "Easy%Ro" method of Sweeney and Burnham (1990). ................... 49

9

INTRODUCTION

The Sur basin (informally called the Partington basin) is an asymmetric, structural

basin offshore of the southern part of the central California margin (Figure 1). The Sur

basin is the northwestern extension of the offshore Santa Maria basin, and therefore

shares some of its stratigraphy, geologic history and tectonic history (McClellan et al.,

1991). Although the southern offshore Santa Maria area has had some successful

petroleum discoveries, the Sur and northern offshore Santa Maria areas have never been

commercially explored (McClellan et al., 1991). Various seismic data sets have been

collected, but a lack of wells in these two areas has made it impossible to validate

interpretations with true depth information from wells. As a result, the Sur and northern

offshore Santa Maria areas have not been well studied and very little has been written

about the region.

In 2008, Peters et al. used biomarker and stable carbon isotope ratios to study the

source rocks of 388 samples of produced crude oil, seep oil, and tarballs along coastal

California. More than 10 of these samples were tarballs collected near the Sur and

northern offshore Santa Maria areas (Figure 2) and were classified as Tribe 3 samples.

Peters et al. (2008b) suggested that these samples may have originated from seeps within

the Sur and northern offshore Santa Maria areas, however, because these tarballs are

carried by ocean currents, their origin is uncertain. In this study, we use basin and

petroleum system modeling to evaluate whether a mobile petroleum charge exists in the

Sur and northern Offshore Santa Maria areas. One model scenario will be presented, of

many that are possible.

10

This study is the first to evaluate the history of petroleum generation within the

Sur and offshore northern Santa Maria areas. In recent years, basin modeling has become

an important tool in the study of the burial and thermal history of sedimentary basins and

has been increasingly used to help evaluate the risk and cost of hydrocarbon exploration,

particularly in frontier areas like the Sur and northern offshore Santa Maria areas (Burrus

et al., 1996; Peters et al., 2008a; Lampe et al., 2006; Baur et al., 2009; Baur et al., 2010;

Rodriguez and Littke, 2001). In this study, 3-D basin and petroleum system modeling is

used to better constrain the petroleum system within the Sur and northern Santa Maria

areas.

Because there are no outcrop samples or well data available from the Sur and

northern offshore Santa Maria areas, rock units, the ages of unconformities and the

timing of geologic events have been inferred indirectly from evidence in neighboring

basins through correlation with seismic data available in these offshore areas. The study

area was defined based on the coverage of interpreted seismic data from Pankow (1997),

the only publicly available document solely dedicated to the study of the Sur and northern

offshore Santa Maria areas (Figure 1).

In summary, the objectives of this study are to 1) evaluate whether a mobile

petroleum charge exists in the Sur and northern Offshore Santa Maria areas and 2)

understand in a wider context how basin and petroleum system modeling can be used to

aid exploration in frontier basins.

11

GEOLOGIC SETTING

The Sur basin is located between 36°15'38"N and 35°31'46"N latitude, and

122°7'33"W and 121°30'50"W longitude (Figure 1). It is bounded to the south by the San

Martin structural discontinuity and to the northeast by a nearshore fault, which is the

central California segment of the San Gregorio-Hosgri fault (McCulloch, 1987). The

basin has an area of ~1800 km2 and consists of ~3 to 4 km of upper Tertiary strata, which

has been down-dropped against the elevated basement of the Mesozoic Franciscan

Complex due to vertical separation along the nearshore fault. The nearshore fault bends

to the northeast which causes another separation along the basin from the structurally

high Sur platform to the northeast (McCulloch, 1987). The sea floor meets the basement

of the Sur basin along its western edge where it shallows (McCulloch, 1987). The San

Martin structural discontinuity separates undeformed basement of the Sur basin from the

irregular basement of the offshore Santa Maria basin (McCulloch, 1987).

The offshore Santa Maria basin is located parallel to the coast between 35°48'3"N

and 34°24'59"N latitude, and 121°26'25"W and 120°54'16"W longitude (Figure 1). This

elongate, structural basin is bounded to the southwest by the Santa Lucia Bank fault and

to the northeast by the Hosgri fault (McCulloch, 1987). It has an approximate area of

5100 km2 and consists of a thick section of upper Tertiary sediments to the southwest,

which has been down-dropped along the Hosgri fault against the elevated basement of the

Franciscan Complex to the northeast (McCulloch, 1987). The offshore Santa Maria basin

shallows towards the San Martin structural discontinuity in the northwest (McCulloch,

1987).

12

Structure and Tectonics

The present-day California margin was formed primarily by Mesozoic to Tertiary

orthogonal subduction of the Farallon Plate, approach of the Farallon-Pacific plate and

initiation of dextral slip in a developing transform boundary between two triple junctions

formed during the late Oligocene (Atwater, 1970). Basement rock of the Franciscan

Complex accumulated by tectonic accretion on top of downgoing oceanic crust during

subduction (Miller, 1993). Transform motion most likely occurred along offshore strike-

slip faults at first, but then moved onshore to the San Andreas fault by the early Miocene

(Graham and Dickinson, 1978). A diffuse zone of deformation formed as the transform

boundary lengthened during early Miocene time, in which crustal blocks rotated and

formed basins like the offshore Santa Maria basin and the Sur basin (Atwater, 1989).

Pankow (1997) presented evidence that the offshore Santa Maria basin and the

Sur basin express different structural styles, and proposed that the two basins have

different strain accommodating mechanisms. The Sur basin has no evidence for major

structural inversion like that seen in the offshore Santa Maria and experienced

significantly less shortening than the offshore Santa Maria basin (Pankow, 1997).

McCulloch (1987) also cited evidence for this difference in structural style between the

two basins in the Neogene structures along the San Martin structural discontinuity which

separates the two basins.

This southwest trending discontinuity joins the Santa Lucia Bank fault and then

trends towards Cape San Martin to the north. McCulloch (1987) suggested that the fault

and the discontinuity lie along the observed change in the basement rocks between the

two basins, and that they both coincide with a magnetic anomaly pattern change. On the

13

offshore Santa Maria basin side of the discontinuity, the basement is deformed with en

echelon structures, whereas, the basement of the Sur basin along the discontinuity are

undeformed, relatively smooth and dip towards the shore. McCulloch (1987) further

proposed that different structural histories between basement in these two basins may

indicate independent movement between basement blocks.

Stratigraphy

The stratigraphy of the central and southern offshore Santa Maria basin (Figure 1)

has been recorded from several exploratory wells in previous studies (Clark et al.,

1991,Hoskins and Griffiths, 1971). Using a combination of lithologic and

biostratigraphic data from ~50 wells in the central and southern offshore Santa Maria

basin, Clark et al. (1991) proposed a chronostratigraphic framework for the OCS P-406-1

well that can be used for correlation to other parts of the basin. In addition, Hoskins and

Griffiths (1971) prepared a generalized basin-wide stratigraphic column proposing

possible on-shore equivalents, which was then correlated to a synthetic seismogram of

the Oceano P-060-1 well by Miller (1999). Detailed stratigraphic studies from the deep

stratigraphic test well COST 164 #1, located between the offshore Santa Maria basin and

the Santa Barbara Channel, have also been published (Cook, 1979, Isaacs et al.,

1983,Isaacs et al., 1989). The stratigraphic framework outlined for the offshore Santa

Maria basin in previous work is critical to understanding the stratigraphy in the Sur and

northern offshore Santa Maria basins, in which no wells have been drilled. Therefore,

rock units and their ages, the age of unconformities, and the timing of geologic events

14

must be inferred indirectly from evidence in neighboring basins through correlation with

seismic data available in the Sur and northern Santa Maria basins.

Basement Rocks and Volcanics

The offshore Santa Maria basin contains Miocene volcanic rocks, which

unconformably overlie the Mesozoic rocks of the Franciscan Complex (Figure 3). These

volcanic rocks are thought to be the equivalent of the Obispo Formation of the onshore

Santa Maria basin (Clark et al., 1991). In some parts of the basin, rocks directly

overlying the volcanic sequence show evidence of possible correlation with the mudstone

and dolostone of the Point Sal Formation of the onshore and southern offshore Santa

Maria basins (Miller et al., 1999). However, the Oceano P-060-1 well penetrated

siliceous shale and chert of the Monterey Formation which immediately overlie the

volcanic sediments (McCulloch, 1987).

Monterey Formation

The Miocene Monterey Formation is present throughout the offshore Santa Maria

basin and is divided into the lower calcareous-siliceous member, the carbonaceous marl

member, the upper calcareous-siliceous to transitional marl-siliceous member, and the

clayey-siliceous member (Isaacs, 2001). The Monterey Formation generally thickens

from west to east in both the Sur and northern offshore Santa Maria areas (Pankow, 1997).

The Monterey Formation thickens more rapidly towards the east in the Sur area than in

the northern offshore Santa Maria area, thins over the San Martin structural discontinuity,

15

and thickens in the center of the southernmost portion of the northern offshore Santa

Maria area (Pankow, 1997).

The Monterey Formation, which contains sulfur-rich Type IIS kerogen, has

generated significant amounts of heavy, sulfur-rich crude oil in the southern offshore

Santa Maria area (Baskin and Peters, 1992, Orr, 1986). Analytical studies carried out by

Baskin and Peters (1992) of oils derived from the Monterey source rock suggested that

type IIS kerogen tends to generate earlier than other typical marine Type II kerogen. This

is because type IIS kerogens have high Sulphur/Carbon atomic ratios which result in

lower activation energies for petroleum generation and low corresponding frequency

factors. This is demonstrated in Figure 5 (Peters et al., 2006), which shows how different

Type II kerogens respond to increasing burial temperature. The figure shows that Type

IIS kerogen from the Monterey Formation in the Santa Maria basin (Sample #6) reacts

faster than other Type II kerogens.

The Sisquoc Formation

The upper Miocene to lower Pliocene Sisquoc Formation, which consists of

claystone, siliceous mudstone, siltstone and smaller amounts of thin limestone, dolomite

and chert, conformably overlies the Monterey Formation with a lithologically gradational

contact (Clark et al., 1991). The Sisquoc Formation is divided into the Upper and Lower

Sisquoc by an unconformity at the boundary between the Miocene and Pliocene. This

Miocene-Pliocene boundary unconformity is dated at 5.3 Ma and can be traced

throughout most of the offshore Santa Maria basin (Clark et al., 1991). The Upper

Sisquoc Formation is unconformably overlain by the Foxen Formation at the early-late

16

Pliocene boundary (Clark et al., 1991). This early-late Pliocene boundary can be mapped

throughout the basin, although, not as clearly as the Miocene-Pliocene unconformity

(Clark et al., 1991). The interpreted seismic sections of Pankow (1997) show that the

Upper Sisquoc is absent throughout the Sur basin and thins over a basement high at the

San Martin structural discontinuity. However, in the northern offshore Santa Maria basin,

the Upper Sisquoc Formation thins away from the thick central portion of the basin

toward the eastern and western margins (Pankow, 1997). The Lower Sisquoc has a

general west to east thickening sediment pattern in both the Sur and northern offshore

Santa Maria areas and thins over basement high at the San Martin structural discontinuity.

Similar to the Monterey Formation, the Lower Sisquoc Formation thickens to the center

of the southern portion of the northern offshore Santa Maria area (Pankow, 1997).

The Foxen Formation

The lithology of the Foxen Formation comprises poorly consolidated clay with

small amounts of sandstone, siltstone and limestone (Clark et al., 1991). Upper

Pliocene/Pleistocene and Pleistocene/Holocene sequences equivalent to the Paso Robles

Formation recognized in the onshore Santa Maria basin are not identifiable in most areas

in the offshore Santa Maria basin because the contact is lithologically gradational and

therefore unidentifiable in seismic data (Clark et al., 1991). Most offshore wells are

drilled on structural highs where the Pleistocene sediments are thin; therefore the contact

is also unidentifiable in well data (Clark et al., 1991). Pankow (1997) split the Foxen

Formation into upper and lower units. In the Sur area, the Upper and Lower Foxen

Formations generally thicken to the east, whereas, in the northern offshore Santa Maria

17

area, the thickest portion of both the Upper and Lower Formations is in the central

portion of the basin (Figure 6). The Upper and Lower Foxen Formations thin towards the

eastern and western margins of the northern Santa Maria area (Pankow, 1997).

Correlation of stratigraphy between the offshore Santa Maria basin and the Sur Basin

Pankow (1997) correlated seismic reflection profiles in the Sur and northern

offshore Santa Maria areas with the work of Hoskins and Griffiths (1971) and Clark et al.

(1991) in the central and southern offshore Santa Maria basin. Pankow (1997) correlated

the Monterey, Lower and Upper Sisquoc, and Foxen Formations across the Sur and

offshore Santa Maria basins. However, the Upper Sisquoc is very thin or absent in most

of the Sur area. Although the San Martin structural discontinuity prevented direct

correlation from the offshore Santa Maria basin to the Sur basin, correlations were made

by comparison of sequence thickness and reflection characteristics (Pankow, 1997). Two

seismic reflection data sets were used for stratigraphic correlation from the offshore Santa

Maria to the Sur basin (Pankow, 1997). The first data set was collected in 1975 using

airgun sources and a 48 channel recording system, whereas the second dataset was

recorded in 1974 using Aquapulse sources and a 62 channel recording system (Figure 7).

Petroleum Geology of the southern offshore Santa Maria Area

The southern offshore Santa Maria area has been relatively well studied in

comparison to the Sur and northern offshore Santa Maria areas. The Point Arguello and

Point Pedernales fields located in the southern offshore Santa Maria area were discovered

in 1981 and 1982 respectively (Crain et al., 1985, Tennyson and Isaacs, 2001). The Point

18

Pedernales oil field is located about 5 miles west of Point Pedernales and had cumulative

production through 2000 of 64 million barrels (MMbbl) of oil and 19 billion cubic feet

(bcf) of gas (County of Santa Barbara, 2005).The Point Arguello field is located about 8

miles from the coast between the western border of the Santa Barbara Channel and the

southern border of the offshore Santa Maria basin (Crain et al., 1987) and had cumulative

production through 2000 of 146 MMbbl of oil and 71 bcf of gas (County of Santa

Barbara, 2005).

Biomarker and carbon isotope studies within the southern offshore Santa Maria

area have revealed that the Monterey Formation is the primary source rock in the

southern offshore Santa Maria area (Crain et al., 1987, Mero et al., 1991). TOC values

for the source rock of 1-3% have been reported in various studies (Isaacs et al., 1989,

Telnaes et al., 2001). Analytical studies by Orr (1986) have designated the kerogens of

the Monterey Formation in the southern Offshore Santa Maria as type II-S oil prone

sulphur-rich organic matter.

The Monterey Formation is also the primary reservoir rock in the southern

offshore Santa Maria area (Crain et al., 1987). Fractured siliceous mudstone and chert of

the Monterey Formation are believed to be the main reservoirs of the offshore Santa

Maria area (Tennyson and Isaacs, 2001, Mero et al., 1991). Most of the oil in the

southern offshore Santa Maria area is trapped by faulted anticlinal traps (Tennyson and

Isaacs, 2001). The faults also act as seals in some areas (Mero et al., 1991). The

mudstone of the Sisquoc Formation, as well as unfractured or clay-rich Monterey

intervals, act as additional seals within the southern offshore Santa Maria area (Tennyson,

2001).

19

METHODS

3-D Model Input Parameters

Chronostratigraphic Units

The only data available as stratigraphic inputs for the 3-D model were isopach

maps in two-way travel time of the Upper and Lower Foxen, Upper and Lower Sisquoc,

and Monterey Formations created in the Pankow (1997) study (Figure 4, Figure 6).

Attempts to recover the original data for further interpretation were unsuccessful;

therefore the level of structural and stratigraphic complexity that could be incorporated

into the model is limited. Nevertheless, the correlations of Pankow (1997) are plausible,

and the isopach maps have sufficient character with respect to sediment thickening and

thinning, particularly within the Monterey Formation, to suggest that stratal thickness

was controlled by growing syn-sedimentary structures, as is common in other Neogene

basins of California (e.g., the San Joaquin basin; (Webb, 1981).

Seafloor depths are derived from a 90-m resolution grid file generated from

coastal relief data provided by NOAA. Utilizing NOAA's graphical user interface, we

output a seafloor grid from the US Coastal Relief Model Grids database within an area

bounded by 125° to 120 ° W longitude and 35° to 40 ° N latitude. The 3 arc-second (90

meter) grid was exported as ASCII text, and was used to grid the longitude-latitude-depth

data with GMT software. The seafloor grid was then sampled at each longitude and

latitude contained within the two-way travel time files for each model layer.

The two-way travel time isopach maps were scanned and imported into ArcGIS

where they were georeferenced and digitized as polyline shapefiles. The maps were then

imported into Petrel® and converted to gridded surfaces. Each gridded surface was

20

82000 x 6450 m and had a grid increment of 130 x165 nodes. The isopach maps were

converted from two-way travel time to depth. Due to a lack of wells and the

unavailability of the original seismic data, little or no velocity control was available in the

study area. Therefore, time to depth conversion was done using data retrieved by Sorlien

et al. (1999) from wells in the southern offshore Santa Maria area. Sorlien et al. (1999)

calculated the approximate depth and travel time to formation tops by subtracting the

distance between the reference level in the well, and the sea surface, and then converting

this depth value to time using velocity analysis from processing, supplementing these

calculations with check-shot surveys and transit times from four wells. The data from

this previous study was used to calculate the interval velocities for each layer using the

equation !!!!!!!!!! ∗!

, where z = depth (meters) and t = two-way travel time (seconds).

Once the interval velocities were calculated, surface calculations were carried out in

Petrel to convert the isopach time surfaces to isopach depth surfaces using the equation

!"#$%&� !"#$ !"#$%&' ÷ 2 ÷ 1000 ∗ !"#$%&'( !"#$%&'( (!)). The depth converted

surfaces were hung on the seafloor and the stratigraphic tops of those surfaces were

calculated using the built-in surface calculator in Petrel®. Depth surfaces were then

imported into PetroMod®, the basin modeling software used in this study.

In PetroMod®, each chronostratigraphic unit was assigned a lithology or mixture

of lithologies using data from several sources (Clark et al., 1991, Cook, 1979, Isaacs et al.,

1983) to account for lithology variations in each unit. For each lithology, PetroMod®

automatically assigns default physical and thermal rock properties, which include thermal

conductivity, radiogenic heat, heat capacity, mechanical compaction, chemical

compaction, permeability, seal properties and fracturing. Age constraints obtained from

21

previous studies (Clark et al., 1991, McCrory et al., 1995) were used to assign beginning

and ending ages of deposition for each chronostratigraphic unit (Table 1). The Monterey

Formation was split into three units in order to better represent the lithologies associated

with each of its members. The upper calcareous-siliceous to transitional marl-siliceous

member of the Monterey Formation was combined with the carbonaceous marl member

and the clayey-siliceous member in equal proportions. Because the different members of

the Monterey Formation have not previously been distinguished in the Sur and northern

offshore Santa Maria areas, for discussion purposes we have designated the lower

calcareous-siliceous member, the middle carbonaceous member, and the upper clayey-

siliceous member as the Monterey3, Monterey2 and Monterey1 members, respectively.

For modeling purposes, a carrier bed must be assigned as a PetroCharge layer in

PetroMod®. However, the complex fractured lithologies most likely present in the study

area are difficult to model without more detailed data than was available for this study.

Permeability and capillary entry pressure, the main controls on fluid flow, typically have

higher values in fractured rock than in a porous rock like sandstone (Carolyn Lampe,

personal communication, 2011) making fractured rock ideal carriers or reservoirs.

Therefore, in order to simulate an ideal carrier, a 5 meter thick sandstone carrier bed was

inserted at the top of the lower calcareous-siliceous member of the Monterey Formation

in lieu of a fractured network. For discussion purposes, this layer will be identified as the

Monterey2 Reservoir.

22

Paleo-water Depth

In lieu of well data from the study area, the paleobathymetric curve of (McCrory

et al., 1995) for the Cost Well OCS-CAL 78-164-1 and OCS-P 0496-1 well (Figures 8,

Figure 9), located in the southern offshore Santa Maria area, was used to estimate the

regional water depth during deposition of each chronostratigraphic unit. McCrory et al.

(1995) used benthic foraminifers with restricted paleoenvironmental ranges as proxies for

paleobathymetry following the procedures and assignments of (Ingle, 1980).

Heat Flow Analysis: Basal Heat Flow and Sediment-Water Interface Temperature

Boundary conditions need to be defined for heat flow analysis through geologic

time (Hantschel and Kauerauf, 2009). Temperature maps on the sediment surface and

basal heat flow maps are the main boundary conditions for heat flow analysis. The

sediment-water interface temperature for this model was obtained using the built-in

SWIT tool in PetroMod® (Figure 10). The SWIT tool estimates paleo-mean surface or

air temperatures and makes corrections for paleo-water depth based on the work of

(Wygrala, 1989). In order to derive paleo surface temperatures, an understanding of

paleo latitude and paleo-water depth changes with geologic time is crucial (Hantschel and

Kauerauf, 2009).

The basal heat flow can be estimated from crustal models or by systematically

adjusting the input surface heat-flow, and can be calibrated with thermal calibration

parameters (Peters et al., 2008a, Hantschel and Kauerauf, 2009). Surface heat flow is

obtained by calculating the product of the geothermal gradient, and the thermal

conductivity expressed in watts per meter-degrees Kelvin (W/m.K). These measurements

23

are obtained by measuring borehole temperatures and the thermal conductivity of the

rock penetrated by the borehole (Peters et al., 2008a). The heat flow is measured in

milliwatts per square meter (mW/m2).

In this study, a constant heat flow of 66 W/m.K through time was assigned based

on a previous1-D basin modeling study in the OCS 315-1 well, located in the southern

offshore Santa Maria area (Telnaes et al., 2001). Telnaes and others (2001) chose this

heat flow value to model the geothermal gradient reported in the Point Conception COST

164 well (45° C/km) by Cook and others (1979).

Calibration

Because no wells have been drilled in the Sur and northern offshore Santa Maria

areas, no data were available for calibration of the 3-D model presented in this study.

However, seep and tarball samples collected from the Sur area of coastal California

(Figure 2) from a study by Peters et al. (2008b) were used to estimate the thermal

maturity of the source rock. Peters et al. (2008b) used biomarker and stable carbon

isotope ratios to better understand the origin and distribution of tar and seep samples from

coastal California, and identified three tribes of 13C-rich oil samples that originate from

the thermally mature equivalents of the Monterey Formation. From the samples analyzed

in Peters et al. (2008b) we identified those that were closest to the Sur and northern

offshore Santa Maria areas and used the GC/MS results from the m/z 217 chromatogram

(Figure 11) to calculate C29 sterane 20S/(20S+20R), C29 sterane ββ/(ββ+αα), and C32

hopane 22S/(22S+22R) ratios. These biomarker ratios were used to bracket the thermal

maturity of the samples. Because the samples were collected along the coast near the Sur

24

and northern offshore Santa Maria basin, the assumption is that they were generated by

the Monterey source rock in these areas. These samples were identified as Tribe 3 by

Peters et al. (2008b), which contains five oil families. Tribe 3 samples were noted by

Peters et al. (2008b) to originate from a distal marine carbonate source rock of pelagic

origin with little or no higher plant input. Anoxic conditions dominated the deposition of

the source rock for the Tribe 3 samples.

Figure 12 shows approximate ranges of biomarker maturity parameters and

corresponding vitrinite reflectance (Peters et al., 2005) and was used to estimate the

equivalent vitrinite reflectance values and stages of oil generation for the samples. The

C32 hopane 22S/(22S+22R) ratios ranged from 0.55 to 0.62. C29 sterane 20S/(20S+20R)

ratios ranged from 0.33 to 0.41, and C29 sterane ββ/(ββ+αα) ratios ranged from 0.53 to

0.65. Therefore the samples have reached the early oil window (~0.6% Ro) based on the

C32 hopane ratio, but they have not reached the endpoint for either of the two sterane

isomerizations. Therefore, for calibration purposes the data indicates that oil generated

from the basal Monterey Formation in the Sur and northern Santa Maria areas has

reached only the early oil windows (Ro ~ 0.6-0.7%).

Source Rock Characteristics

Type IIS kerogen kinetics (Pepper and Corvi, 1995) was used to simulate thermal

cracking of kerogen in the Monterey Formation in this study. Type IIS kerogen kinetics

were chosen because crude oils in the southern offshore Santa Maria area near the Sur

and northern offshore Santa Maria areas are exceptionally rich in organic sulfur (8-14%)

(Orr, 1986). Original Total Organic Carbon (TOC) and Hydrogen Index (HI) values

25

were obtained from a previous study by (Peters et al., 2008b). The Monterey1,

Monterey2, and Monterey3 were assigned TOC values of 4.5, 9.9 and 5 wt. % and HI

values of 216, 360 and 406 mg HC/g TOC respectively.

Migration Methods for Simulation

Flowpath modeling was chosen as the migration method in the PetroMod® 3-D

simulator because it is an efficient method typically used when data is sparse as is this

case in this study (Hantschel and Kauerauf, 2009). Flowpath modeling assumes that

hydrocarbon migration occurs almost vertically in low permeability layers, with

generated hydrocarbons being injected into the next reservoir above after expulsion from

the source rock (Hantschel and Kauerauf, 2009). Hydrocarbon losses are roughly

proportionate to the rock thickness through which the hydrocarbons pass (Hantschel and

Kauerauf, 2009).

RESULTS AND DISCUSSION

3-D Model Output

Predicted Petroleum Potential

Figure 13 represents the output of the 3-D model generated from the total

stratigraphic volume defined by Pankow, the only data available from the Sur and

northern offshore Santa Maria areas. Points of accumulation on top of the Monterey2

Reservoir layer in this figure are shown for illustrative purposes and are not necessarily

indicative of real accumulations, but show the impact on stratigraphic architecture of

growing structures in the Miocene. The 3-D model is based on limited data, but in that

26

context, if a 2-D cross-section is extracted from the model in lieu of published well-

documented structure maps (Figure 14), the model yields minor anticlines which trap

petroleum, sealed by mudstone of the Sisquoc or by the clay-rich Monterey1 member

(Figure 14). The flow paths predicted by the model show that petroleum was primarily

generated from the Monterey3 source rock before migrating updip into the Monterey1

Sandstone. We recognize that this basin may contain extensively fractured Monterey

Formation, so another reservoir scenario not modeled here would be a fracture system in

the Monterey Formation analogous to the southern offshore Santa Maria area (Crain et al.,

1987; Mero et al., 1991). Yet another plausible reservoir scenario in this kind of deep-

water basin is off-structure turbidite Miocene sandstone traps analogous to the Stevens

sandstone in the San Joaquin basin (Webb, 1981). Although the model predicted that a

total of 76 Billion Barrels (BBO) of petroleum was generated by the Monterey source

rock, 66 BBO of petroleum was lost via top and side outflow, and 1 BBO was lost via

migration losses. The model predicted that the remaining 9 Billion Barrels of petroleum

has accumulated in the Monterey Formation source rock, indicating that there may be

shale oil potential in the Sur and northern offshore Santa Maria areas. Most importantly,

these model results demonstrate that there likely are moveable hydrocarbons in the Sur

and northern offshore Santa Maria areas and that they are probably volumetrically

significant. The 3-D model predicts 31 accumulations totaling approximately 29 million

barrels (MMbbls) of petroleum. Flash calculations done in PetroMod® to estimate

surface conditions of the oil in these accumulations predict an API of 32.

27

Modeled Thermal Maturity and Expulsion Timing

Monterey3 member – lower calcareous-siliceous member

In order to evaluate the thermal maturity and expulsion timing within the Sur and

northern offshore Santa Maria areas, 1D models were extracted at the region of maximum

overburden within each of the areas (Figure 15, Figure 16). The Monterey3 is more

thermally mature than the Monterey2 and Monterey1 members (Table 2, Figure 17,

Figure 18), and therefore most of the accumulations predicted by the model were

generated by the Monterey3 member. At the region of maximum overburden within the

Sur area, the Monterey3 begins oil expulsion at burial depths of 2.4 to 3.4 km

(@TR=10%). Initial oil expulsion in the Monterey3 occurred between 5 to 8 Ma with

vitrinite reflectance values ranging from 0.5 to 0.6% at initial oil expulsion. The base of

the Monterey3 member in the region of maximum overburden within the Sur area has a

present-day predicted vitrinite reflectance of 1.2 % and a present-day transformation ratio

of 86%. The Monterey3 reaches peak oil expulsion in the Sur area between 2 to 4 Ma at

depths of 4.2 to 5.1 km.

At the region of maximum overburden within the northern offshore Santa Maria

area, the Monterey3 begins oil expulsion at burial depths of 3.3 to 4.2 km. Initial oil

expulsion in the Monterey3 within the northern offshore Santa Maria occurs slightly later

than in the Sur area between 4 and 6 Ma with a vitrinite reflectance of 0.6 at initial oil

expulsion. The base of the Monterey3 member in the region of maximum overburden

within the northern offshore Santa Maria area has a present-day predicted vitrinite

reflectance of 0.8 % and a present-day transformation ratio of 56 %. The Monterey3

reaches peak oil expulsion in the northern offshore Santa Maria area at 1.2 Ma at depths

28

of 3.7 km to 4.0 km. The region of maximum overburden within the Sur area contains a

thicker section of the Monterey3 member with a higher thermal maturity than that of the

northern offshore Santa area.

Monterey2 member - the middle carbonaceous marl member

The 3-D model predicts that the Monterey2 member is thermally immature

throughout the Sur area except within the region of maximum overburden. In the Sur

Area, petroleum generation from the Monterey2 member within the region of maximum

overburden begins at burial depths of 4.2 to 4.5 km and the Monterey2 has vitrinite

reflectance values of 0.5 to 0.6 at initial oil expulsion (TR= 10%). The base of the

Monterey2 member in the region of maximum overburden within the Sur area has a

present-day predicted vitrinite reflectance of 0.8 % and a present-day transformation ratio

of 34%. Therefore, the Monterey2 has not reached peak oil expulsion in the Sur area

(TR=50%).

At the region of maximum overburden within the northern offshore Santa Maria

area, the Monterey2 begins oil expulsion at burial depths of 2.8 to 3.0 km. Initial oil

expulsion in the Monterey2 within the northern offshore Santa Maria occurs later than in

the Sur area about 0.6 Ma with vitrinite reflectances of approximately 0.6 % at initial oil

expulsion. The base of the Monterey2 member in the region of maximum overburden

within the northern offshore Santa Maria area has a present-day predicted vitrinite

reflectance of 0.6 % and a present-day transformation ratio of 12%. Therefore the

Monterey2 has not reached peak oil expulsion in the northern offshore Santa Maria area

29

(TR=50%). The thickness of the Monterey2 member varies very little between the Sur

and northern offshore Santa Maria areas (Table 2).

Monterey1 Member - the upper clayey-siliceous member

The Monterey1 member is the least thermally mature source rock of the three

Monterey members. The Monterey1 is thermally immature throughout the Sur area

except within the region of maximum overburden. In the Sur area, petroleum generation

from the Monterey1 member within the region of maximum overburden begins at burial

depths of 3.1 to 3.3 km and the Monterey1 has vitrinite reflectance values of 0.5 to 0.6 at

initial oil expulsion. The base of the Monterey1 member in the region of maximum

overburden within the Sur area has a present-day predicted vitrinite reflectance of 0.6%

and a present-day transformation ratio of 13%. Therefore the Monterey1 has not reached

peak oil expulsion (TR=50%).

The Monterey1 member is thermally immature throughout the northern offshore

Santa Maria region and does not reach initial oil expulsion. The base of the Monterey1

member in the region of maximum overburden has present-day predicted vitrinite

reflectance of 0.6% and a present-day transformation ratio of 2.2%. The Monterey1

member in the Sur area is thicker than the Monterey1 member in the northern offshore

Santa Maria area (Table 2).

30

CONCLUSION

The 3-D model presented in this study demonstrates that there likely are moveable

hydrocarbons in the Sur and northern offshore Santa Maria areas and that they are

probably volumetrically significant. The model predicts 31 accumulations totaling

approximately 29 million barrels (MMbbls) of petroleum with an API of 32; this resource

estimate is artificial due necessary assumptions, but is indicative of the potential of the

basin. A lack of outcrop samples and well data from the Sur and northern offshore Santa

Maria areas imposed certain limitations on the 3-D model. Rock units, the ages of

unconformities and the timing of geologic events have been inferred indirectly from

evidence in neighboring basins through correlation with seismic data available in these

offshore areas. Furthermore, it was not possible to calibrate the model because there was

no vitrinite reflectance data available from wells. As a result, the heat flow could not be

well constrained. Despite these limitations, the model gives a reasonable first look at the

petroleum potential in the Sur and northern offshore Santa Maria areas. It illustrates that

the Monterey Formation is sufficiently mature thermally to generate petroleum, and

shows that basin modeling is a suitable tool for exploration in similar frontier basins with

little or no data available. The model suggests that minor anticlines might trap petroleum,

sealed by the mudstone of the Sisquoc or by the clay-rich Monterey1 member. The

petroleum was primarily generated from the Monterey3 source rock before migrating

updip into the Monterey1 Sandstone. Although only one reservoir scenario was

presented in this study, other possible reservoir scenarios include a fracture system in the

Monterey Formation and off-structure turbidite Miocene sandstone traps. The model also

31

predicts approximately 9 billion barrels (BBO) of petroleum has accumulated in the

Monterey Formation source rock, indicating that there may be shale oil potential in the

Sur and northern offshore Santa Maria areas.

The lower calcareous-siliceous Monterey3 member is the most thermally mature

member of the Monterey Formation and therefore generated most of the accumulations

predicted by the model. At the region of maximum overburden within the Sur area, the

Monterey3 reaches peak oil expulsion between 2 to 4 Ma at depths of 4.2 to 5.1 km and

has a present-day transformation ratio of 86%. The Monterey3 reaches peak oil

expulsion at 1.2 Ma at depths of 3.7 km to 4.0 km and has a present-day transformation

ratio of 56 % at the region of maximum overburden within the northern offshore Santa

Maria area. The Sur area contains a thicker section of the Monterey3 member with a

higher thermal maturity than that of the northern offshore Santa Maria area in the region

of maximum overburden.

32

FIGURES AND TABLES

Figure 1: Map shows location and geological setting of the Sur basin and the offshore Santa Maria basin modified after McClellan et al. (1991) and Sorlien et al. (1995). Study area is outlined by red dashed line. Faults are solid red lines. Basin outlines are solid blue lines.

33

Figure 2: Map shows locations of data available for this study. Purple lines are seismic lines used by Pankow (1997), yellow circles are wells drilled in the offshore Santa Maria Basin, green triangles are tarball and seep samples collected near the Sur and northern offshore Santa Maria areas for the Peters et al. (2008) study.

34

Figure 3: Stratigraphic column of the offshore Santa Maria basin modified after Hoskins and Griffiths (1970)

35

Figure 4: Isopach map (meters) of the Monterey Formation in the Sur and northern Offshore Santa Maria areas using data from Pankow (1997).

36

Figure 5: Calculated fractional conversions based on an assumed heating rate of 1°C/m.y. for 29 worldwide petroleum source rocks that contain mainly type II kerogen (Peters et al., 2006)

37

Figure 6: Isopach map (meters) of the Lower Foxen Formation in the Sur and northern Offshore Santa Maria areas using data from Pankow (1997).

38

Figure 7: Migrated seismic reflection lines A-3. The section shown is from the northern offshore Santa Maria area. 1=Upper Foxen; 2=Lower Foxen; 3=Upper Sisquoc; 4=Lower Sisquoc; 5=Monterey. Vertical axis is plotted in two-way travel time.

39

Figure 8: Paleobathymetry curve for the COST well (OCS-CAL 78-164-1) modified from McCrory et al. (1995).

40

Figure 9: Paleobathymetric curve from the P-496-1 well modified after McCory et al 1995.

41

Figure 10: Petromod Auto-SWIT tool showing Global mean surface temperature as a function of latitude and time, based on Wrygrala (1989).

42

Figure 11: Sterane mass chromatograms (m/z 217) for one of the tarball samples collected near the Sur and northern offshore Santa Maria areas.

43

Figure 12: Approximate ranges of biomarker maturity parameters are shown versus vitrinite reflectance and a generalized oil-generation curve from Peters et al. (2005).

44

Figure 13: Shows accumulations (green) predicted in the 3-D model within the Sur and northern offshore Santa Maria Areas. The model predicts 31 accumulations containing 28.76 million barrels of oil (MMbbl).

45

Figure 14: NW-SE cross-section through the 3-D model shows anticlinal closures that trap oil in the Monterey2 Reservoir, and locations of 1-D extractions for the Sur and northern Offshore Santa Maria areas at region of maximum overburden (NOSMPseudo and SurPseudo).

46

Figure 15: Burial history at region of maximum overburden in the Sur area

47

Figure 16: Burial history at region of maximum overburden in the northern offshore Santa Maria area

48

Figure 17: Map of modeled present-day transformation ratio for the Monterey Formation in the Sur and northern offshore Santa Maria areas

49

Figure 18: Map of modeled present-day thermal maturity expressed as vitrinite reflectance in the Sur and northern offshore Santa Maria areas. Vitrinite reflectance was calculated using the "Easy%Ro" method of Sweeney and Burnham (1990).

50

Table 1: Age and petroleum system element information for stratigraphic units of the 3-D model

Layer Depo. From (Ma)

Depo. To (Ma) Lithology PSE

Undivided Sediments 2.3 0 Shale (organic lean, silty) Overburden Rock

Upper Foxen 3.4 2.3 Shale (typical) Overburden Rock

Lower Foxen 3.8 3.4 Shale (organic lean, siliceous, typical) Overburden Rock

Upper Sisquoc 5.3 3.8 Shale (organic lean, siliceous, typical) Overburden Rock

Lower Sisquoc 6 5.3 Shale (typical) Overburden Rock

Monterey1* 9.05 6 Shale (organic lean, siliceous, 95% Opal-CT) Source Rock

Monterey2 Reservoir* 9.07 9.05 Sandstone (typical) Reservoir Rock

Monterey2* 11.75 9.07 Marl Source Rock Monterey3* 17.5 11.75 Dolomite (organic rich) Source Rock

Basement 70 17.5 BASEMENT Underburden Rock

* The Monterey Formation was split in three layers in PetroMod®, therefore ages of deposition for the

various members of the Monterey Formation were not assigned but calculated proportionately by

PetroMod®

51

Table 2: Comparison of thickness, original TOC, original HI, EASY%Ro and burial depth at present day with timing of initial oil expulsion (TR=10%) for the Monterey1, Monterey2 and Monterey3 source rocks in the northern offshore Santa Maria and Sur basins. TR = transformation ratio. Values are listed as generated by PetroMod® but 2nd decimal digits are not statistically significant.

*TR=50% (peak expulsion) between 2.03 to 4.37 Ma at depths of 4210-5144 m **TR does not reach TR=10% + TR=50% (peak expulsion) at 1.2 Ma at depths of 3736-4015 m

Sur basin

northern offshore Santa Maria basin

Monterey1 Monterey2 Monterey3* Monterey1** Monterey2 Monterey3+

Thickness 461 399 869 363 320 689

TOC 4.5 9.9 5 4.5 9.9 5

HI 216 360 406 216 360 406

Time of Initial

Expulsion Ma (@

TR=10%)

0.89 3.01 5.48-7.66 N/A 0.6 4.17-5.56

Depth of Initial

Expulsion m (@ TR =

10%)

3091-3275 4166-4505 2747-3416 N/A 2752-3026 3342-4156

EASY%Ro @ TR=10% .51-.62 .55-.64 .55-.64 N/A .57-.64 0.58

% TR at present day

(at base) 12.96 33.96 85.57 2.22 11.77 56.27

EASY%Ro @ present

day

(at base)

0.64 0.76 1.15 0.56 0.65 0.84

Burial Depth @

present day (at base) in

m

2957 3382 4244 2436 2762 3444

52

APPENDIX

Table 3: Approximate depth and traveltime to formation tops for wells from Sorlien et al. (1999) used in the time to depth conversion for this study

Well Horizon Depth in meters Two-way Travel time (s)

P-060 #1 (Oceano)

Seafloor 168 0.227 Top Sisquoc Formation 1027 1.221

Top Monterey Formation 1662 1.762

Top volcanic rocks 2142 2.035

Bottom of well 2434 2.142

413 #1

Seafloor 309 0.418

Top Sisquoc Formation 781 0.976 Top Monterey Formation 1163 1.416



496 #1

Seafloor 366 0.494

Top early Pliocene sediments 560 0.690

Top Sisquoc Formation 651 0.820 Top of Miocene sediments 743 0.922


Top lower part Monterey Formation 1145 1.360

Top Franciscan Complex 1383 1.482 Bottom of well 1815 1.660

424 #1

Seafloor 177 0.209




Top Franciscan Complex 1073 1.192 Bottom of well 1201 1.260

443 #1

Seafloor 271 0.366




Top Cretaceous sediments 1489 1.630 Top Franciscan Complex 2082 1.970


53

Table 3 (cont’d)

Well Horizon Depth in meters Two-way Travel time (s)

COST 164 #1

Seafloor 447 0.604 Sequence Boundary 855 1.100

Top lower Pliocene sediments 1208 1.470

Top Sisquoc Formation 1351 1.590

Top of Miocene sediments 1540? 1.750 Top Monterey Formation 1986 2.000


Top Cretaceous sediments 3018 2.650 446 #1 Early-late Pliocene unconf. 907 1.120



Top lower part Monterey Formation 1650 1.770 Top "Lospe" Formation 1670 1.780

Serpentine 1940 1.950


449 #2 Early-late Pliocene unconf. 1000 1.210 Top Sisquoc Formation 1170 1.370

Top of Miocene sediments 1430 1.600

Top Monterey Formation 1810 1.910 Top lower part Monterey Formation 2070 2.090


450 #2 Top Sisquoc Formation 1290 1.390

Top Monterey Formation 2330 2.180 Bottom of well 2784 2.410

456 #1 Top early Pliocene sediments 1230 1.420



Top lower part Monterey Formation 2370 2.200 Bottom of well (TVD) 2841 2.420

320 #2 Sandstone 1560 1.750

Top Sisquoc Formation 1784 1.900

Top of Miocene sediments 1910 2.030 Top lower part Monterey Formation 2250 2.223

54

REFERENCES

Atwater, T., 1989. Plate tectonic history of the Northeast Pacific and western North America, in Winterer, E.L., Hussong, D.M., Decker, R.W. (Eds.), The Eastern Pacific Ocean and Hawaii. Geol. Soc. Am., Denver, CO, United States (USA), United States (USA).

Atwater, T., 1970. Implications of plate tectonics for the Cenozoic tectonic evolution of western North America. Geological Society of America Bulletin 81, 3513-3535.

Baskin, D.K., Peters, K.E., 1992. Early generation characteristics of a sulfur-rich Monterey kerogen. AAPG Bull. 76, 1-13.

Baur, F., Di Benedetto, M., Fuchs, T., Lampe, C., Sciamanna, S., 2009. Integrating structural geology and petroleum systems modeling – A pilot project from Bolivia's fold and thrust belt. Mar. Pet. Geol. 26, 573-579.

Baur, F., Littke, R., Wielens, H., Lampe, C., Fuchs, T., 2010. Basin modeling meets rift analysis – A numerical modeling study from the Jeanne d'Arc basin, offshore Newfoundland, Canada. Mar. Pet. Geol. 27, 585-599.

Burrus, J., Osadetz, K., Wolf, S., Doligez, B., Visser, K., Dearborn, D., 1996. A two-dimensional regional basin model of Williston Basin hydrocarbon systems. AAPG Bulletin 80, 265-291.

Clark, D.H., Hall, N.T., Hamilton, D.H., Heck, R.G., Mooney, W.D.(., 1991. Structural analysis of late Neogene deformation in the central offshore Santa Maria Basin, California; Special section on EDGE and related seismic projects, onshore-offshore California [modified]. Journal of Geophysical Research 96, 6435-6457.

Cook, H.E., 1979. Geologic studies of Point Conception deep stratigraphic test well OCS-Cal 78-164 No. 1, outer continental shelf, southern California, United States. OF 79-1218, 148.

County of Santa Barbara, 2005. County of Santa Barbara Planning and Development, Energy Division. 2011.

Crain, W.E., Mero, W.E., Patterson, D., 1987. Geology of the Point Arguello Field. 6, 407-407-426.

Crain, W.E., Mero, W.E., Patterson, D., 1985. Geology of the Point Arguello discovery. AAPG Bulletin 69, 537-545.

Graham, S.A., Dickinson, W.R., 1978. Evidence for 115 Kilometers of Right Slip on the San Gregorio-Hosgri Fault Trend. Science 199, 179-181.

55

Hantschel, T., Kauerauf, A.I., 2009. Fundamentals of Basin and Petroleum Systems Modeling. Springer, Dordrecht, Federal Republic of Germany (DEU), Federal Republic of Germany (DEU).

Hoskins, E.G., Griffiths, J.R., 1971. Hydrocarbon Potential of Northern and Central California Offshore; Future petroleum provinces of the United States; their geology and potential, Vol. 1. Memoir - American Association of Petroleum Geologists 15, 212-228.

Ingle, J.C.,Jr, 1980. Cenozoic paleobathymetry and depositional history of selected sequences within the southern California continental borderland; Studies in marine micropaleontology and paleoecology; a memorial volume to Orville L. Bandy. Special Publications - Cushman Foundation for Foraminiferal Research , 163-195.

Isaacs, C.M., Jackson, L.L., Stewart, K.C., Scott, Norman,I.,II, 1989. Analytical reproducibility and abundances of major oxides, total carbon, organic carbon, and sedimentary components of Miocene and early Pliocene cuttings from the Point Conception Deep Stratigraphic Test Well, OCS-CAL 78-164 No. 1, offshore Santa Maria Basin, Southern California. OF 87-0075, 28.

Isaacs, C.M., Keller, M.A., Gennai, V.A., Stewart, K.C., Taggart, J.E.,Jr, 1983. Preliminary evaluation of Miocene lithostratigraphy in the Point Conception COST well OCS-CAL 78-164 No. 1, off Southern California; Petroleum generation and occurrence in the Miocene Monterey Formation, California.

Isaacs, C.M., 2001. Depositional framework of the Monterey Formation, California, in Isaacs, C.M., Rullkoetter, J. (Eds.), The Monterey Formation; from Rocks to Molecules. Columbia University Press, New York, NY, United States (USA), United States (USA).

Lampe, C., Kornpihl, K., Sciamanna, S., Zapata, T., Zamora, G., Varadé, R., 2006. Petroleum systems modeling in tectonically complex areas — A 2D migration study from the Neuquen Basin, Argentina. J. Geochem. Explor. 89, 201-204.

McClellan, P.H., McCulloch, D.S., Bloch, R.B., 1991. Offshore Central California.

McCrory, P.A., Dumont, M.P., Barron, J.A., Geological Survey, 1995. Neogene Geohistory Analysis of Santa Maria Basin, California, and its Relationship to Transfer of Central California to the Pacific Plate. U.S. G.P.O. ;Denver, CO, Washington.

McCulloch, D.S., 1987. Regional Geology and Hydrocarbon Potential of Offshore Central California, in Scholl, D.W., Grantz, A., Vedder, J.G. (Eds.), Geology and Resource Potential of the Continental Margin of Western North America and Adjacent Ocean Basins-Beaufort Sea to Baja California. Circum-Pacific Council for Energy and Mineral Resources, Houston, TX, United States (USA), pp. 353-401.

56

Mero, W.E., Foster, N.H., Beaumont, E.A., 1991. Point Arguello Field; U.S.A., Santa Maria Basin, offshore California. AAPG Treatise of Petroleum Geology, Atlas of Oil and Gas Fields , 27-27-57.

Miller, K.C., Meltzer, A.S., Sorlien, C.C., Nicholson, C., Luyendyk, B.P., Miller, K.C., Meltzer, A.S., 1999. Structure and tectonics of the central offshore Santa Maria and Santa Lucia basins, California; results from the PG&E/EDGE seismic reflection survey; Miocene extension and post-Miocene transpression offshore of south-central California. Structure and tectonics of the central offshore Santa Maria and Santa Lucia basins, California; results from the PG&E/EDGE seismic reflection survey. U.S.Geological Survey Bulletin B 1995-Y,Z, Z1-Z12.

Miller, K.C., 1993. Crustal structure along the strike of the offshore Santa Maria basin, California. Tectonophysics 219, 57-69.

Orr, W.L., 1986. Kerogen/asphaltene/sulfur relationships in sulfur-rich Monterey oils. Org. Geochem. 10, 499-516.

Pankow, K.C., 1997. Neogene stratigraphy and tectonics of the offshore Sur and Santa Maria basins, California. University of California at Santa Cruz, Santa Cruz, CA.

Pepper, A.S., Corvi, P.J., 1995. Simple kinetic models of petroleum formation. Part I: oil and gas generation from kerogen. Mar. Pet. Geol. 12, 291-319.

Peters, K.E., Magoon, L.B., Lampe, C., Scheirer, A.H., Lillis, P.G., Gautier, D.L., 2008a. A Four Dimensional Petroleum Systems Model for the San Joaquin Basin Province, California, in Scheirer, A.H. (Ed.), Petroleum Systems and Geologic Assessment of Oil and Gas in the San Joaquin Basin Province, California. U.S. Geological Survey, Menlo Park, CA.

Peters, K.E., Hostettler, F.D., Lorenson, T.D., Rosenbauer, R.J., 2008b. Families of Miocene Monterey crude oil, seep, and tarball samples, coastal California. AAPG Bulletin 92, 1131-1152.

Peters, K.E., Moldowan, J.M., Peters, K.E., Walters, C.C., 2005. The Biomarker Guide 2. Biomarkers and Isotopes in Petroleum Exploration and Earth History. Cambridge Univ. Press, Cambridge [u.a.

Peters, K.E., Walters, C.C., Mankiewicz, P.J., 2006. Evaluation of kinetic uncertainty in numerical models of petroleum generation. AAPG Bull. 90, 387-403.

Rodriguez, J.F.R., Littke, R., 2001. Petroleum generation and accumulation in the Golfo San Jorge Basin, Argentina: a basin modeling study. Mar. Pet. Geol. 18, 995-1028.

57

Sorlien, C.C., Nicholson, C., Luyendyk, B.P., Sorlien, C.C., Nicholson, C., Luyendyk, B.P., Miller, K.C., Meltzer, A.S., 1999. Miocene extension and post-Miocene transpression offshore of south-central California; Miocene extension and post-Miocene transpression offshore of south-central California. Structure and tectonics of the central offshore Santa Maria and Santa Lucia basins, California; results from the PG&E/EDGE seismic reflection survey. U.S.Geological Survey Bulletin B 1995-Y,Z, Y1-Y38.

Telnaes, N., Requejo, A.G., Hanesand, T., Hermansen, D., Jarvie, D., 2001. Characterization of Source Rock Potential, Hydrocarbon Generation, and Maturity in Well OCS-315-1, Offshore Santa Maria Basin, California, in Isaacs, C.M., Rullkoetter, J. (Eds.), The Monterey Formation; from Rocks to Molecules. Columbia University Press, New York, NY, United States (USA), United States (USA).

Tennyson, M.E., Isaacs, C.M., 2001. Geologic setting and petroleum geology of Santa Maria and Santa Barbara Basins, coastal California, in Isaacs, C.M., Rullkoetter, J. (Eds.), The Monterey Formation; from Rocks to Molecules. Columbia University Press, New York, NY, United States (USA), United States (USA).

Webb, G.W., 1981. Stevens and earlier Miocene turbidite sandstones, southern San Joaquin Valley, California. AAPG Bulletin 65, 438-465.

Wygrala, B.P., 1989. Integrated study of an oil field in the southern Po Basin, Northern Italy = Integrierte Studie eines Erdölfeldes im südlichen Po-Becken, Norditalien. .

BASIN AND PETROLEUM SYSTEM MODELING OF …...7 LIST OF FIGURES Figure 1: Map shows location and...

Documents

Transcript of BASIN AND PETROLEUM SYSTEM MODELING OF …...7 LIST OF FIGURES Figure 1: Map shows location and...