geochemical characteristics of oil and source rocks and

AUTHORS

Andrea Fildani � Department of Geologicaland Environmental Sciences, Stanford University,Stanford, California; present address: ChevronEnergy Technology Company, 6001 BollingerCanyon Rd., San Ramon, California 94583;[email protected]

Andrea Fildani is a research geologist for theQuantitative Stratigraphy Team in San Ramon. Hereceived his Laurea in geology from the Universityof Rome ‘‘La Sapienza’’ and his Ph.D. in geologicalsciences from Stanford University. His researchinterests are in sequence stratigraphy, seismicstratigraphy, marine geology, and basin analysis.Andrea is currently working on deep-water depo-sitional systems reservoir characterization.

Andrew D. Hanson � Department of Geo-science, University of Nevada Las Vegas, 4505South Maryland Parkway, Las Vegas, Nevada89154-4010; [email protected]

Andrew Hanson received his Ph.D. in geologicalscience from Stanford University in 1999. He thenworked for Texaco’s deep-water Nigeria explora-tion team as an exploration geoscientist. Hansonis an assistant professor at the University of Ne-vada, Las Vegas, where his research focuses onChina oil and source rock geochemistry, hydro-carbon migration issues associated with salt struc-tures in the La Popa basin of Mexico, and exten-sional basins of central and southern Nevada.

Zhengzheng Chen � Department of Geologicaland Environmental Sciences, Stanford University,Stanford, California; present address: ConocoPhil-lips, 600 N. Dairy Ashford, Permian 3024, Houston,Texas, 77079; [email protected]

Zhengzheng Chen joined Upstream Technology ofConocoPhillips in 2005. Currently, her work fo-cuses on reservoir geochemistry in heavy-oil fieldsin Venezuela and Alaska. She received her Ph.D.in organic geochemistry from Stanford Universityin 2004. Her thesis topics cover biomarker iso-topes, characterizing biodegradation using biomark-er acids, and petroleum systems in Saudi Arabia.

J. Michael Moldowan � Department of Geo-logical and Environmental Sciences, StanfordUniversity, Stanford, California 94305;[email protected]

J. Michael Moldowan attained a Ph.D. in chemistryfrom the University of Michigan. After a postdoc-toral fellowship at Stanford University, he joinedChevron in 1974, where he developed fundamentaland applied technology related to petroleum

Geochemical characteristicsof oil and source rocks andimplications for petroleumsystems, Talara basin,northwest PeruAndrea Fildani, Andrew D. Hanson, Zhengzheng Chen,J. Michael Moldowan, Stephan A. Graham, andPedro Raul Arriola

ABSTRACT

In the first comprehensive study of the Talara basin petroleum sys-

tem of onshore and offshore northwest Peru, we test oil–source

rock correlation through molecular biomarker analysis of oil samples

from wells scattered throughout the basin, as well as purported

source rocks. The new data presented in this manuscript suggest

that the oils constitute one oil family, and that the source rock was

a predominant marine clay deposited in an oxic to suboxic envi-

ronment. Substantial relative amounts of oleanane in each oil sample

indicate a notable input of terrestrial organic matter deposited in

a mixed marine and terrestrial environment (probably deltaic). The

high ratio of 24-norcholestanes to 27-norcholestanes and C25 high-

ly branched isoprenoid (HBI) alkanes suggests a significant up-

welling component in the source rock depositional environment.

In addition, the high oleanane indices (oleanane/hopane) of the

oils are not paralleled in any alternative source rock candidate in

this study. The values are as expected for Tertiary source rocks

and are at levels that exceed any reported Cretaceous or older source

rock or oil. This result, in concert with high nordiacholestane ratios,

norcholestane ratios, and HBI concentrations, indicates a Tertiary

age source rock.

Possible source rocks were selected and analyzed from different

outcrops and wells and compared with the oils. A negative correla-

tion suggests that Upper Cretaceous intervals of limestone, marl, and

black shale previously believed to be important source rocks can be

discounted as an important contributor to Talara basin oils. Instead,

the new data suggest a Tertiary source rock (Eocene–Oligocene[?])

AAPG Bulletin, v. 89, no. 11 (November 2005), pp. 1519– 1545 1519

Copyright #2005. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received September 11, 2004; provisional acceptance February 1, 2005; revised manuscriptreceived June 2, 2005; final acceptance June 30, 2005.DOI:10.1306/06300504094

comparable to that of the Progreso basin. However, no such source

rock strata have yet been identified within the Talara basin. Certain

Upper Cretaceous samples with good source potential could sup-

port another petroleum system not yet identified in the coastal areas

of Peru.

INTRODUCTION

The presence of petroleum in coastal northwest Peru has been

known for centuries. Original inhabitants used oil from natural

seeps for various purposes, and early Spanish colonists extracted

and refined tar from the La Brea seep south of the city of Talara

and used pitch to caulk their ships and to waterproof utensils. The

first well in the basin was drilled in 1874, making Talara one of the

first producing petroleum basins of South America (Travis, 1953).

Cumulative production from the basin exceeds 1.68 billion bbl of

oil and 1.95 tcf of gas from 42 oil and gas fields (Higley, 2004)

(Figure 1). The U.S. Geological Survey estimated that mean recov-

erable oil, gas, and natural gas liquid resources from undiscovered

fields in the basin sum up to 1.71 billion bbl of oil, 4.79 tcf of

gas, and 255 million bbl of natural gas liquids (Higley, 2004). This

estimate is based on a combined Cretaceous–Tertiary source rock

contribution. Gonzalez and Alarcon (2002), assuming only a Cre-

taceous shale as the hydrocarbon source rock, calculated a total vol-

ume of generated hydrocarbons of 2.75 � 105 MMBO and 2.25 �104 tcf of gas and total trapped oil and gas of 2.48 � 105 MMBO and

2.03 � 103 tcf of gas. Their estimate of total volume of recoverable

hydrocarbons from the Talara basin province, including current

production, is 3.72 billion bbl of oil and 9.344 tcf of gas. Most

importantly, Gonzales and Alarcon (2002) estimated the volume

of remaining recoverable hydrocarbons (excluding current pro-

duction) to be 2.22 billion bbl of oil and 5.844 tcf of gas.

Despite the variable resource estimates based on different

source rocks, agreement exists among authors that the mature

Talara basin has been, and will continue to be, a significant petro-

leum province in the world energy panorama. Only in very recent

years have secondary recovery programs been started in this basin,

which is still largely on primary production (Gutierrez and Arriola

Ipenza, 2002), whereas the offshore of the basin is largely unex-

plored. For this reason, a more comprehensive study of the petro-

leum system(s) of the Talara basin is crucial. The most compelling

problem about the Talara basin petroleum system is that very little

is known about the source rock component. The supposed source

rock intervals have been sparsely drilled and sampled, and no

biomarker-focused analytical work has yet been published.

Although petroleum systems include source, reservoir, and

trap, the presence of a source rock is the most important factor

governing the accumulation of hydrocarbons (Dahl et al., 1994).

However, even after a cumulative production of 1.68 billion bbl of

oil, the source rocks have not been rigorously documented, and

biomarkers. Since 1993, Michael has been a pro-fessor (research) in Stanford University’s Depart-ment of Geological and Environmental Sciences.He has published more than 90 articles in scientificjournal and four books.

Stephan A. Graham � Department of Geologi-cal and Environmental Sciences, Stanford Uni-versity, Stanford, California 94305;[email protected]

Steve Graham is a professor in the School of EarthSciences, Stanford University. He teaches coursesin sedimentary geology, seismic interpretation,sedimentary basin analysis, and petroleum reser-voir characterization. His current research projectsinclude studies of sedimentary basins in easternAsia, South America, and western United States,as well as studies of the sedimentology and strati-graphic architecture of deep-water deposits.

Pedro Raul Arriola � Petrobras Energia S.A.,Amador Merino Reyna 285 5tj piso San Isidro,Peru; [email protected]

Pedro Arriola graduated in 1997 with a degreein geological engineering from the San AntonioAbad University of Cusco, Peru. From 1999 to 2002,he worked for Perez Companc del Peru S.A. as adevelopment geologist. Pedro is currently workingfor Petrobras Energıa Peru as a petroleum geologistinvolved in reservoir studies in the Talara basin.

ACKNOWLEDGEMENTS

The authors thank Perez Companc del Peru (nowPetrobras Energia S.A.) for support throughoutfieldwork, for access to data, and for oil samples.In particular, Peter (Pedro) McGregor, GerardoPozo, Juan Leyva, and Fabian Gutierrez were in-strumental in the oil-samples acquisition. AngelaM. Hessler and Gerardo Pozo helped in the field.We thank Jacob Waldbauer, Michael Hren, andPage Chamberlain from the Stable Isotope Bio-geochemistry Laboratories at Stanford Universityfor helping us in d13C analyses. David Zinniker,Fred Fago, and all the technicians at the OrganicGeochemistry Laboratories were very helpful andsupportive throughout the project development.J. M. Moldowan is thankful to the Molecular Or-ganic Geochemistry Industrial Affiliates programfor laboratory support. We also thank DebraHigley for providing access to an early versionof her work. A. Fildani thanks the StanfordProject on Deep-Water Depositional Systems forsupport throughout this project. This manuscriptbenefited of reviews and comments from B. J.Katz, M. A. Smith, and AAPG Bulletin editor E. A.Mancini.

1520 The Petroleum System of Talara Basin

different Upper Cretaceous intervals are cited as source

rocks by various authors (Zuniga-Rivero et al., 1999;

Arispe, 2001a; Gonzales and Alarcon, 2002). Thus,

many questions are still unanswered about the Talara

basin. Specific questions include the following. What

is the source rock? What was its depositional environ-

ment? What age is the source rock? How many petro-

leum systems are present in the basin? What are their

relationships?

Biomarkers are widely and successfully used in the

petroleum industry to identify groups of genetically

related oils, to correlate oils with source rocks, and to

describe the probable source rock depositional environ-

ments for migrated oil of uncertain origin (Moldowan

Figure 1. Generalized map with limitsof the Talara basin and major tectonicfeatures of northwest Peru. Limits of theTalara basin are shown in short dashes;the area of oil production is highlightedwith diagonal lines (modified fromMourier et al., 1988; Pillars de Zorritoslocation is from Kraemer et al., 1999).

Fildani et al. 1521

et al., 1985; Peters and Moldowan, 1993; Peters et al.,

2005). We analyzed 30 oils for biomarkers and screened

possible source rocks suggested by previous workers.

Our results permit the characterization of the Talara

oil–source rock depositional environments, exclude cer-

tain specific source rock candidates, and suggest the

possibility of previously unsuspected oil sources. Spe-

cifically, Talara oil biomarkers suggest a Cenozoic

source rock not yet identified in the basin, as well as

Upper Cretaceous source rock intervals of good po-

tential, possibly linked to a Cretaceous-based petro-

leum system as yet unrecognized and unexploited in

the coastal area of Peru.

GEOLOGICAL BACKGROUND

The Talara basin has been exploited for petroleum for

more than a century but it remains a frontier basin in

terms of its geological and tectonic setting. Although

this study does not deal with the complex tectonic

evolution of northwest Peru and the complicated basin

history of Talara, a short description of the basin evo-

lution sets the stage for the petroleum system. A more

detailed account of basin evolution and sedimentary

successions can be found in Fildani (2004).

The Talara basin sits astride the plate boundary

where the Chile–Peru trench and Ecuador trench are

dissected by a transform fault that continues inland as

the Dolores–Guayaquil megashear (Figure 1). The

megashear represents a fundamental break in the

crustal structure along the South American margin,

which influenced the sedimentary infill of northwest

coastal Peru (Figure 1). The basement of western Ecua-

dor, west of the megashear, is hypothesized to be Cre-

taceous oceanic crust (Shepherd and Moberly, 1981),

whereas the area south and east of the megashear is

composed of metamorphic and granitic rocks. The Ta-

lara basin mainly overlies crust with continental affini-

ties (Lonsdale, 1978). Different tectonic models have

been proposed for the coastal area of Ecuador and north-

west Peru, reflecting the fact that the post-Paleozoic

tectonic history of the area was complicated and not

simply related to subduction (Shepherd and Moberly,

1981). One of the manifestations of activity along the

Dolores–Guayaquil megashear was the formation of

the Gulf of Guayaquil (Progreso basin) north of the

study area (Figure 1).

The boundaries of the Talara basin are poorly de-

fined. It is impossible to describe the Talara basin

without considering interaction with at least two other

basins, the Progreso basin to the north and the Lan-

cones basin to the east (Figure 1). In particular, the

geographic boundaries of the basin are unclear. For

example, the southern end of the basin is poorly known,

and the offshore (western) margin is largely unexplored.

The onshore (eastern) margin is bounded by Paleozoic

basement exposed in two areas: the Amotape Moun-

tains and the Silla de Paita (Figure 1). The Amotape

Mountains extend at a 60j angle from the Andes and,

along with the Tamarindo high, separate the Talara

basin from the Lancones basin (Valencia and Uyen,

2002) (Figure 1). The southern limit of the onshore

basin is the Paita high (Silla de Paita) (Figure 1), but

no evident barriers are present in the offshore portion.

The basin is bounded to the north by the Dolores–

Guayaquil megashear and the Pillars de Zorritos, a

subsurface granitic high penetrated by wells (Figure 1)

(Kraemer et al., 1999; Higley, 2004). The petroleum-

bearing Progreso basin developed in the late Oligo-

cene and is filled by at least 6000 m (19,600 ft) of

sediment (Kraemer et al., 1999).

The Talara basin covers at least 15,000 km2

(5800 mi2), less than half of which is onshore (Fil-

dani, 2004). The onshore sedimentary deposits range

from Cretaceous to Eocene in age and consist of clastic

fill that is in excess of 9000 m (29,500 ft) thickness

(Carozzi and Palomino, 1993). In most of the forearc

regions, tectonically driven subsidence in the mid-

dle Eocene permitted the accumulation of shallowing-

upward marine sequences resting unconformably on

Paleocene, Cretaceous, or older rocks (Ballesteros et al.,

1988; Jaillard et al., 1995). Middle–late Eocene strata

of the Talara basin record a more complex story with

a deepening trend and deposition of deep-water sys-

tems. Periodic extension since the early Tertiary with

subsidence controlled by normal faulting was partially

related to subduction erosion (sensu Von Heune and

Scholl, 1991; Fildani, 2004). The Talara basin sub-

sided abruptly and was filled during the Paleocene–

Eocene by siliciclastic material of multiple origins,

predominantly from the east and the northeast (Fildani,

2004). Limited carbonate facies are restricted to parts

of the Cretaceous and Pliocene–Pleistocene sections

(Marsaglia and Carozzi, 1991; Carozzi and Palomino,

1993). Normal faulting affected the basin exten-

sively during and after deposition of the basin fill.

The deformation was prevalently postdeposition, and

the estimated total vertical displacement of base-

ment is up to 10 km (6 mi) (Shepherd and Moberly,

1981).


The oldest formation in the region, the Amotape

Formation (Figure 2), is exposed in the Amotape Moun-

tains and consists of Paleozoic (Devonian to Permian)

low-grade metamorphic rocks (Shepherd and Moberly,

1981). Mesozoic rocks are not well exposed in any part

of the basin; the few known outcrops are difficult to

access, and descriptions of these strata in the literature

are incomplete. The Cretaceous Pananga and Muerto

formations rest unconformably on the Amotape For-

mation and consist of limestone and bituminous marl.

The outcrops of the Pananga and Muerto formations

were visited and sampled (4j24036.400S, 80j5704.100W).

The Muerto Formation is overlain by a series of Cre-

taceous and Paleocene siliciclastic units (Figure 2). Vari-

ous authors have suggested that shale and limestone

of the Cretaceous are the petroleum source rocks for

the Talara basin (mostly Muerto bituminous marl and

the Redondo black shale) (Zuniga-Rivero et al., 1999;

Arispe, 2001a; Gonzales and Alarcon, 2002).

The Eocene strata are characterized by alternating

marine shale, sandstone, and conglomerate deposited

almost continuously during the early Tertiary. Most

Figure 2. Simplified stratigraphic col-umn with producing horizons (courtesyof Petrobras Energia P.A.) and potentialsource rock intervals sampled for thisstudy.

Fildani et al. 1523

of the Eocene sandstone intervals are producing reser-

voir horizons and are illustrated on the simplified strati-

graphic column of Figure 2 (Petrobras Energia S.A.,

2001, personal communication; Higley, 2004).

The coastline is marked by a series of raised Pleis-

tocene marine terraces (tablazos) (DeVries, 1988). These

tablazos, composed of transgressive limestone and co-

quina beds, cover about 60% of the onshore basin and

have been a limitation for seismic exploration. Note

that there have been no studies of the pre-Cenozoic

setting of the basin with regard to its relationship to the

petroleum system(s).

PREVIOUS WORK ON PETROLEUM SOURCEROCK AND OIL COMPOSITION

Published data on the Talara basin petroleum system

are sparse and proprietary data sets are not easily ac-

cessible. Recently, the U.S. Geological Survey pub-

lished an open-file report making available publicly,

for the first time, a large database of oil analyses from

the area (Higley, 2004).

Pindell and Tabbutt (1995) indicated that five main

Mesozoic–Cenozoic settings exist for source rock de-

position and preservation in the Andean basins of

South America. One of those five settings is within the

coastal environments of western South America, spe-

cifically forearc basins. They noted that upwelling and

attendant suboxic conditions concentrated organic mat-

ter in the marine shale and cited the Upper Cretaceous

Redondo Formation as one such rock unit that was de-

posited in this setting (Figure 2).

Most of the data available for potential Talara

source rocks are based on total organic carbon (TOC)

and pyrolysis (Rock-Eval) and dispersed in proprietary

reports. Total organic carbon values above 1% indicate

good to very good source rocks, whereas those below

1% have poor to fair source potential (Peters, 1986).

Various authors postulated two separate formations as

hydrocarbon source rocks in the Talara basin: the ma-

rine shale of the Upper Cretaceous (Campanian) Re-

dondo Formation and the Lower Cretaceous (Albian)

Muerto Formation, composed of marl and limestone

(Figure 2) (Zuniga-Rivero et al., 1998a, b; Arispe,

2001a; Gonzales and Alarcon, 2002). Gonzales and

Alarcon (2002) proposed that the Cretaceous Re-

dondo Formation is the primary hydrocarbon source

rock in the basin and included the Cretaceous Muerto

Formation and upper Oligocene Heath Formation as

regionally significant potential source rocks. Although

the Heath Formation is not recognized in the Talara

area, Kraemer et al. (1999) indicated that the Heath

Formation is the primary source rock in the Progreso

basin province (Figure 1). The Heath Formation was

deposited in the late Oligocene or early Miocene in a

deltaic environment and has an average TOC of 1.6%

(Kraemer et al., 1999).

In contrast, Perupetro (1999) asserted that poten-

tial Tertiary hydrocarbon source rocks include shale of

the Eocene San Cristobal Formation (lower Eocene of

the Salina Group), the Chacra Group (lower Eocene

Echinocyamus and Clavel (Parinas) formations), the

lower Talara (middle Eocene), and the Chira–Heath

(upper Eocene–lower Oligocene) formations (Figure 2)

(reported by Higley, 2004). Tertiary sediments in the

deepest part of the basin are indicated as potential

source rocks (Zuniga-Rivero et al., 1998a). However,

Gonzales and Alarcon (2002) indicated that the Bal-

cones, as well as the Eocene Chira, Salina, and San

Cristobal formations and different intervals in the Pa-

leocene were poor source rocks based on TOC and

hydrocarbon indices (Rock-Eval).

The American International Petroleum Company

evaluated the TOC of 151 samples of Tertiary shale

collected from outcrops and well cuttings throughout

the basin without identifying a good potential source

rock interval (database reported by Higley, 2004).

Gonzales and Alarcon (2002) reported that the geo-

chemical analyses of 13 shale and limestone samples

ranging in age from Early Cretaceous (Albian) to Oli-

gocene showed TOC contents ranging from 1.1 to 1.3%.

Rodriguez and Alvarez (2001, personal communica-

tion), in an unpublished report for Perez Companc,

indicated that, based on the analysis (Rock-Eval and

TOC) of 135 samples from different wells through-

out the basin from the Cretaceous to the upper Eo-

cene, the Muerto Formation was the interval with the

best source rock potential. This conclusion was based

on high (>2%) TOC results. Unfortunately, we had no

access to cuttings from this interval in our study.

Previously published oil data from the Talara

basin province (reported by Higley, 2004) seem to

suggest one oil family. The oils have median values of

5.5 ppm for nickel (Ni) and 4.0 ppm for vanadium (V)

(Higley, 2004). Based on the vanadium and nickel con-

tent and d13C values, Higley (2004) concluded that

the Talara basin province oils were from source rocks

of similar origin, such as shale deposited in a marine

setting. Possible minor variations in oils were attributed

to local differences in the same depositional system or


from mixed nonmarine or marine-nonmarine shale that

contained a different ratio of nickel to vanadium (Higley,

2004). Mixing of oils from several source rocks may also

have influenced the Ni and V contents of these oils

(Higley, 2004). The oil samples reported by Higley

(2004) are primarily from Eocene reservoirs. One oil

sample listed is from a fractured interval from the Amo-

tape Formation in the southern part of the basin (Port-

achuelo field; Figure 3). This oil shows the same geo-

chemical characteristics and groups with the other oils,

indicating that a late charge of old and fractured res-

ervoirs is possible in this basin.

These incomplete, conflicting, and generally broad

prior studies (i.e., bulk geochemical analyses) demon-

strate that the identification of Talara basin’s petro-

leum source rock(s) remains open. To address this

problem, we proceeded in three steps: (1) we col-

lected all available published and unpublished data on

the Talara basin petroleum system; (2) we performed

oil biomarker analyses to define molecular characteris-

tics of 30 oil samples; and (3) we analyzed selected po-

tential source rocks to search for matches with our

oil database. As a result, we were able to eliminate a

series of previously postulated petroleum source rocks

and redirect the focus toward a completely different

scenario for deposition of the basin’s source strata,

opening new possibilities for exploration in the Talara

basin.

Figure 3. Map showingthe location of wells fromwhich oil samples ana-lyzed in this study werecollected; inset showsdetailed map with loca-tion of wells in Block X(courtesy of Pecom delPeru, now Petrobras delPeru).

Fildani et al. 1525

METHODS

This work is based on 30 oils and 6 source rock ex-

tracts collected during 2000 and 2001. To cover the

entire basin, we collected oils from different wells from

fields onshore and offshore (Figure 3). Oils were fil-

tered to clean up impurities (such as sediments) and

separated using short-column chromatography, and satu-

rate and aromatic fractions were separated by high-

pressure liquid chromatography (HPLC) (Peters and

Moldowan, 1993). Gas chromatography (GC), selected

ion-monitoring gas chromatrography–mass spectrome-

try (SIM-GCMS), and metastable reaction-monitoring

gas chromatography–mass spectrometry (MRM-GCMS)

were performed on oils and possible source rock ex-

tracts. The details of the implemented technical pro-

cedures are reported in Appendix 1.

DATA PRESENTATION AND ANALYSIS

Source Rock Geochemistry

Because the published data, which include mostly

nonbiomarker parameters, are not specific about wells

and areal distribution of samples, it is currently not

possible to identify favorable depositional environments

for potential source rocks or establish geochemical

correlations. Almost every shale interval in the Talara

basin has been indicated as a possible source of hy-

drocarbons (see list in Higley, 2004). The Cretaceous

section, with the Muerto Formation and the Redondo

Formation, contains the favorite candidates (Zuniga-

Rivero et al., 1998a, b; 1999; Arispe, 2001a; Gonzales

and Alarcon, 2002), but data presented to support

this inference are insufficient. The Muerto Formation

was also indicated as the source rock when Perupetro

advertised the bid round of 2000 (Perupetro, 1999;

Zuniga-Rivero et al., 1999; Arispe, 2001b).

We targeted the Muerto Formation and the Re-

dondo Formation to evaluate a match with the oils.

The Muerto Formation outcrop was examined and

sampled, together with the underlying Pananga For-

mation on the west side of the Amotape Mountains

(Figure 1). The 2–3-m (6.6–10-ft)-thick limestone

beds of the Pananga Formation comprising massive

limestone with scattered ammonites are not a likely

source. In contrast, the Muerto Formation is a thinly

bedded (10–20-cm; 4–8-in.), laminated marl with

intercalated dark shales. The intense sulfurous smell

from freshly broken rocks probably helped to advertise

this rock as the source rock of the northwest Peru ba-

sins (Zuniga-Rivero et al., 1999). We collected four sam-

ples from the Muerto Formation. Although the sam-

ples did not have elevated TOC values (Table 1), we

extracted and analyzed bitumens from one sample.

The Redondo Formation has been penetrated by

some wells in Block X, and Perez Companc (now Pe-

trobras Energia S.A.) made four cuttings available for

bitumen extraction. The cuttings come from two wells

situated close to each other (Perez Companc wells EA

5927 and EA 2278 herein named simply wells 5927 and

2278; Figure 3) and suggested the presence of pro-

mising source rocks (Table 1). The black shale sample

named ‘‘Redondo’’ in Table 1 was taken from an un-

specified core in the Upper Cretaceous interval.

To create a broader source rock screening, we also

sampled shale from different Eocene formations (Pozo,

Ostrea, Lobitos, and Mogollon Medio formations;

Table 1; Figure 2) that have been suggested as possible

source rocks by local geologists. To avoid the effects of

outcrop weathering, we used samples from borehole

cores and cuttings when available.

To complete our source rock collection, two Heath

Formation samples were taken from outcrops to the

north in an area that some workers consider part of the

Progreso basin (3j43.1440S, 80j41.6310W). The samples

were collected from two different cliff exposures com-

posed of shale and silty shale. They appear to be ther-

mally very immature, containing considerable organic

material (leaves and stem material) consistent with depo-

sition in a low-energy environment (possibly lagoonal).

Total organic carbon and Rock-Eval data indicate

that the samples collected from the Eocene section are

not favorable source rocks (Table 1). The best quality

Eocene samples contain type III kerogen and would

produce mostly dry gas (Figure 4) (Peters et al., 2005),

yet no evidence of dry gas accumulation in the ba-

sin has ever been reported (Gonzales and Alarcon,

2002). Cretaceous source rocks have good liquid po-

tential with promising values of TOC and Rock-Eval

(Table 1). However, TOC and Rock-Eval values indi-

cate low-quality source rock for the Muerto Formation

samples. The Muerto sample selected for biomarker

analyses yielded a high C29/C30 hopane ratio and a very

low diasterane/sterane value consistent with the ob-

served carbonate depositional environment (Table 2;

Figure 5). Cuttings from wells 5927 and 2278 are in-

terpreted as having been deposited in the continuous

and laterally extended interval of Redondo Formation

that is reported as a basinal blanketing shale. These


samples are good potential source rocks based on bulk

geochemical measures (Table 1), but the two samples

from well 2278 completely lack oleanane (Table 2;

Figure 5), a compound related to terrestrial input

(Moldowan et al., 1994). The sample from well 5927

has oleanane (Figure 5), and a 24-norcholestane ratio

and 24-nordiacholestane ratio (respectively, NCR and

NDR in Table 2). The values of NCR and NDR are

relatively high for this rock extract (well 5927, NCR =

0.67, NDR = 0.53; see Table 2) for an Upper Creta-

ceous source rock where values lower than 0.6 and

0.5, respectively, are expected (Holba et al., 1998a, b).

Shale samples from wells 5927 and 2278 are probably

from different intervals in the Redondo Formation.

Oil Geochemistry

We sampled oils from different fields to have the

largest possible coverage of the basin and a regional

view sufficient to identify possible geochemical trends

across the basin (Figure 3). Most of the wells produce

from multiple reservoirs, and the production is re-

ported as combined. Talara oils vary in their GC patterns

mostly because of their different degrees of biodeg-

radation (Figure 6). Oils of light biodegradation exhibit

full n-alkane (C15+) envelopes, whereas oils of severe

biodegradation (at least eight samples) are characterized

by a large unresolved complex mixture with neither

n-alkanes nor isoprenoids (Moldowan et al., 1992; Pe-

ters and Moldowan, 1993). Conventional biomarker

ratios are shown in Table 3 (steranes) and Table 4

(hopanes). Sterane and homohopane distributions are

similar for all the samples (Tables 3, 4). The oils have a

high C30 sterane index, suggesting a marine environ-

ment (Peters and Moldowan, 1993). The diasterane/

sterane ratio indicates a clay-rich environment (Hughes,

1984). The relative abundance C27-C28-C29 of regular

steranes of the oils exhibits small differences and does

not require different source rocks (Figure 7); the rather

uniform subequal abundances of the C27-C28-C29 ster-

anes are typical of a marine algal flora. The stair-step

Table 1. Total Organic Carbon and Rock-Eval Data for Possible Source Rocks of Talara Basin

SampleTOC and Rock-Eval Data* Interpretive Ratios**

Identification Wells Depth (ft) Formation TOC S1 S2 S3 T max HI OI S2/S3 PI S1/TOC

T Muerto 1 Outcrop Muerto 0.47 0.27 0.89 0.17 433 189 36 5.24 0.23 57



Well 2278 2278 7870–7880 Redondo 4.44 0.99 18.10 0.67 433 408 15 27.01 0.05 22

Well 2278 2278 7890–7910 Redondo 5.31 1.45 22.45 0.82 433 423 15 27.38 0.06 27

Well 5927 5927 8010 Redondo 2.82 0.37 9.40 0.53 433 333 19 17.74 0.04 13

Well 5927 5927 8060–8070 Redondo 1.61 0.10 2.88 0.31 433 179 19 9.29 0.03 6

Well 5927 5927 8080–8090 Redondo 1.95 0.11 3.35 0.33 435 172 17 10.15 0.03 6

Pozo 3265 Pozo 0.63 0.07 0.51 0.31 427 81 49 0.12 11

Ostrea 1 AA80 Ostrea 0.28 0.01 0.32 0.07 416 114 25 0.03 4

Ostrea 2 AX 11 Ostrea 2.41 0.09 1.41 0.48 430 59 20 0.06 4

Lobitos AA1768 Talara 0.45 0.01 0.39 0.08 439 87 18 0.03 2

Mogollon medio 1944 Mogollon 0.15 0.01 0.2 0.01 455 133 7 0.05 7

11/23/03 Redondo 1.31 0.17 2.51 0.27 435 192 21 0.06 13

11/8-6 Outcrop Heath 2.35 0.02 0.32 2.2 435 14 94 0.06 1

11/15-2 Outcrop Muerto 0.21 0 0.04 0.4 415 19 190 0.00 0

11/30-4 Outcrop Heath 0.34 0 0.05 0.35 383 15 103 0.00 0

*TOC = total organic carbon; S1, S2, S3 = Rock-Eval pyrolysis parameters that measure volatile organic compound (S1), organic compounds by cracking of kerogen(S2), and organic carbon dioxide (S3).

**HI = hydrogen index; OI = oxygen index; PI = production index (S1/(S1 + S2)). All parameters are described in Peters (1986).

Fildani et al. 1527

progression of C31 to C35 homohopanes is similar for

all the samples and indicates an oxic or suboxic source

depositional environment (Figures 8, 9 with oil Talara 1)

(Peters and Moldowan, 1991, 1993). Source rocks of

this type tend not to be prolifically productive and dis-

play relatively low to moderate TOC and HI values

(Peters and Moldowan, 1993). The almost total ab-

sence of C35 hopanes, normally associated with marine

carbonate and evaporite (Clark and Philp, 1989), ex-

cludes those lithologies from the source rock interval.

The C26 steranes (24-norcholestanes) and related

C26 diasteranes (24-nordiacholestane) are possibly de-

rived from a diatomaceous precursor (Holba et al.,

1998a). Their ratios to the nontaxon-specific C26 ster-

anes, 27-norcholestane and 27-nordiacholestane (NCR

and NDR, respectively; Holba et al., 1998a) are in the

high range of values reported for Tertiary source rocks.

The occurrence of diatomaceous intervals in the source

rock of the oil has been confirmed by the presence of

highly branched isoprenoid (HBI) alkanes detected in

the oil samples (mass/charge [m/z] 238; Table 5). Highly

branched isoprenoids are specifically related to rhizo-

solenid diatom evolution and their diffusion and diver-

sification after the late Turonian; the presence of large

amounts of HBI is an age indicator (Sinninghe Damste

et al., 2004). Diatom-rich upwelling-related deposits

are not well documented in the area, but evidence of

paleo-upwelling is reported for Eocene and Miocene

strata preserved along the Peruvian coast (Marty et al.,

1988; Dunbar et al., 1991) and from the modern Peru-

vian marine slope (Aplin et al., 1992). The modern Pe-

ruvian upwelling system is one of the most productive

areas of the oceans (Dunbar et al., 1991). The occur-

rence of diatomite and diatomaceous mudstone deposits

Figure 4. Hydrogen index–oxygen index (Van Krevelen)plot indicating hydrocarbon-generative potential of sourcerocks sampled for this study(Peters, 1986). Type I = highlyoil prone; type II = oil prone;type III = gas prone; type IV =gas prone to inert.


in the Chira Formation (late Eocene–early Oligocene)

of the Talara basin suggests that it was deposited in an

upwelling oceanic margin (Dunbar et al., 1991).

The oils of the Talara basin show high relative

amounts of oleanane (Figure 8). Elsewhere, oleanane

has been reported in Cretaceous and Tertiary source

rocks, where it is directly linked to flowering plants

(Moldowan et al., 1994). Oleanane can be used as a

terrestrial input indicator (vascular plants) as well as

an age indicator because its concentration can be rela-

tively high in the Tertiary. All the Talara oils analyzed

have oleanane in the m/z 191 traces (Figure 8), with an

oleanane index (the ratio between oleanane and C30

homohopane) ranging from 0.2 to 1.2 (Table 4). The

oleanane index suggests substantial higher plant input

(Moldowan et al., 1994). This character, coupled with

the subequal C27-C28-C29 sterane (algal) distribution,

suggests a combination of marine and terrestrial sources

typical of a distal deltaic environment.

In summary, the combination of high NDR and

NCR, HBI, and the presence of oleanane in high rela-

tive abundance (oleanane index > 0.2; Moldowan et al.,

1994) support the Tertiary-aged and mixed marine and

terrestrial input. In Talara oils, the moderate Pr/Ph ra-

tios (1.1–1.7; see Appendix 2), low diasterane/sterane

ratios (0.2–0.6, with the exception of AA9161 at 1.81),

and the poor preservation of C34-C35 homohopane dis-

tributions (Figure 9) suggest an oxic to suboxic depo-

sitional environment.

The Talara oils are of biodegradation degree 1–4,

according to Peters et al. (2005). The impact of bio-

degradation is most obvious in GC patterns of Talara

Table 2. Sterane and Hopane Values Calculated for Selected Source Rock Extracts

Sterane

Source Rocks Formations

C29 Steranes

(aaa20R/aaa20R +

aaa20S)

C29 Steranes

(abb/aaa +

abb)

Diasterane/

Sterane C27 (%) C28 (%) C29 (%)

C30

Index NDR NCR

Heath Formation 0.06 0.31 0.12 5 17 78 0.02

Redondo Formation 0.38 0.37 1.22 28 32 40 0.06 0.35 0.36

Muerto Formation 0.51 0.53 0.06 36 28 36 0.058 0 0.22

EA5927-8010 Redondo

Formation

0.26 0.39 0.65 32 28 40 0.086 0.53 0.67

EA2278-7879 Redondo

Formation

0.46 0.45 0.48 29 35 35 0.081 0.28 0.39

EA2278-7870 Redondo

Formation

0.47 0.41 0.40 32 34 34 0.077 0.28 0.41

Hopane

Source Rocks Formations Ts/(Ts + Tm)*

C32 22S/

(22S + 22R)

C30 hopane

ba/

(ab + ba) C29/C30

Tricyclic

Terpane/

17a Hopane

Oleanane

Index

Heath Formation

Redondo Formation 0.46 0.59 0.20 0.49 0 0.11

Muerto Formation 0.22 0.59 0.07 1.25 0 0

EA5927-8010 Redondo

Formation

0.41 0.56 0.10 0.49 0 0.14

EA2278-7890 Redondo

Formation

0.58 0.64 0.08 0.35 0 0

EA2278-7870 Redondo

Formation

0.57 0.67 0.06 0.36 0 0

*Ts = C27 18a(H)-trisnorhopane II; Tm = C27 17a(H)-trisnorhopane.

Fildani et al. 1529

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Fildani et al. 1531

oils but does not impact biomarker analysis results.

The sterane and hopane distributions do not change

systematically with degrees of biodegradation. From

GCMS analysis, we observed no destruction of steranes

and a consistent distribution of homohopane patterns

(Figures 8, 9). Although oleanane is more resistant to

biodegradation than C30 hopane (Peters et al., 2005,

p. 665), oils of severe biodegradation degree (with

pristane and phytane removed; i.e., EA878 trace in

Figure 6) do not exhibit a higher oleanane/hopane

ratio than oils of light biodegradation degree.

Variations in values of the biomarker parameters

suggest a source rock with local differences related to

facies variation of the source depositional environment.

For this reason, we mapped variations in biomarker

parameters to identify possible trends in the source

rock distribution (Figure 10). Lacking knowledge of

the deep structure of Talara basin and with various au-

thors ascribing dominant vertical migration pathways

in the basin (with minor lateral migration) (Sanz, 1988;

Higley, 2004), the oleanane index and NDR of the oils

were plotted and contoured (Figure 10). In a verti-

cally drained basin, such as probably the small, highly

faulted Talara basin, progressive lateral changes in

source rock quality can be inferred in the variation of

the geochemistry of migrated oils (Dahl et al., 1994).

The oleanane index and the NDR distribution show

interesting differences (Figure 10). Contouring reveals

higher values along a roughly north-south axis for

both parameters, flanked to the east and west by lower

Table 3. Sterane Values Calculated for the Talara Basin Oils

Oil Samples

C29 Steranes

(aaa20S/aaa20R +

aaa20S)

C29 Steranes

(abb/aaa + abb)

Diasterane/

Sterane C27 (%) C28 (%) C29 (%) C30 Index NDR* NCR*

Talara 1 0.56 0.58 0.44 0.27 0.34 0.39 0.031 0.55 0.68

Talara 2 0.54 0.57 0.33 29.28 34.52 36.20 0.032 0.53 0.66

Talara 4 0.53 0.58 0.31 30.74 34.55 34.71 0.032 0.51 0.66

Talara 6 0.56 0.59 0.32 31.47 35.08 33.46 0.030 0.53 0.66

Talara 7 0.52 0.55 0.21 33.09 33.30 33.60 0.032 0.52 0.66

Talara 10 0.54 0.58 0.31 31.35 34.94 33.71 0.030 0.48 0.63

Talara 14 0.57 0.60 0.34 30.50 34.50 35.00 0.030 0.53 0.67

Talara 15 0.51 0.55 0.25 30.18 34.84 34.99 0.033 0.52 0.66

Talara 17 0.54 0.58 0.28 30.00 34.00 36.00 0.030 0.48 0.66

Talara 20 0.53 0.60 0.33 26.89 36.42 36.69 0.030 0.50 0.66

Talara 21 0.56 0.59 0.32 31.40 33.00 35.60 0.032 0.51 0.66

Talara 26 0.58 0.58 0.49 28.54 35.66 35.80 0.038 0.52 0.65

Talara 30 0.53 0.59 0.30 30.00 35.00 35.00 0.033 0.52 0.67

AA 9174 0.58 0.59 0.47 31.00 33.00 36.00 0.032 0.53 0.68

EA 8054 0.59 0.60 0.48 31.00 33.00 36.00 0.033 0.50 0.68

EA 10519 0.57 0.59 0.40 31.00 34.00 35.00 0.032 0.53 0.71

EA8004 0.56 0.59 0.46 32.00 34.00 34.00 0.032 0.51 0.69

AA7874 0.59 0.58 0.40 28.49 33.27 38.24 0.030 0.56 0.72

EA9484 0.59 0.58 0.42 29.00 33.00 38.00 0.028 0.52 0.69

AA9161 0.62 0.58 1.47 24.00 35.00 41.00 0.057 0.54 0.65

EA878 0.54 0.60 0.42 31.00 35.00 34.00 0.029 0.57 0.69

AA5717 0.59 0.59 0.58 31.00 32.00 37.00 0.030 0.54 0.67

AA6982 0.56 0.58 0.43 29.00 35.00 36.00 0.031 0.56 0.70

EA7619 0.55 0.57 0.28 32.00 32.00 36.00 0.032 0.52 0.70

EA7931 0.57 0.60 0.43 32.00 35.00 34.00 0.030 0.52 0.70

AA2061 0.58 0.58 0.33 31.00 33.00 36.00 0.032 0.53 0.68

AA6592 0.58 0.60 0.49 33.00 31.00 36.00 0.027 0.50 0.69

EA1121 0.56 0.60 0.52 31.00 35.00 34.00 0.028 0.49 0.69

*NDR = nordiacholestane ratio; NCR = norcholestane ratio.


values. NDR shows a well-defined high in the center

of Block X, with the highest value reaching 0.57

(Figure 10). The oleanane index shows two highs:

one to the north and one to the south of Block X, with

lower values offshore to the west. The mapped highs of

the oleanane index and the NDR are almost compen-

satory; the high of the NDR parameter sits between the

highs of the oleanane index (Figure 10). The distribu-

tion of these parameters suggests a nonhomogenous

source rock with differences related to lateral facies

variation. The source depositional system was probably

deposited along a north-south trend, which closely

mimics the modern coastline. The areas of higher NDR

values suggest a more distal source facies possibly in-

volved with upwelling (more algal, colder water, more

nutrients), whereas the areas with a higher oleanane in-

dex may have had more terrestrial input (river mouth?).

Oils might be reflecting small differences in the source

rocks facies both stratigraphically and areally.

Maturity Indicators and Biodegradation Effects

The Ts/(Ts + Tm) ratio is both maturity and source

dependent and is not an effective parameter for ma-

turity in Talara oils. Possible organic facies changes

(as discussed above) dictate the changes in many bio-

marker parameters, such as Ts/(Ts + Tm) ratio, di-

asterane/sterane ratio, and oleanane/C30 hopane ratio

(Peters et al., 2005). The presence of C30 steranes, an

indicator for marine-source input (Moldowan et al.,

1990), and oleanane, an indicator for terrestrial input,

point to a mixed-source input from both marine and

terrestrial organisms. The influence of organic facies

Table 4. Hopane Values Calculated for Talara Oils

Oil

Samples

Ts/

(Ts + Tm)*

C32 22S/

(22S + 22R)

C30 Hopane

ba/(ab + ba) C29/C30

Tricyclic Terpane/

17a Hopane

Oleanane

Index

Talara 1 0.66 0.55 0.12 0.44 0.00 0.69

Talara 2 0.60 0.55 0.12 0.44 0.00 0.36

Talara 4 0.62 0.57 0.11 0.45 0.00 0.39

Talara 6 0.65 0.58 0.10 0.44 0.00 0.33

Talara 7 0.52 0.55 0.11 0.46 0.00 0.26

Talara 10 0.65 0.55 0.10 0.44 0.00 0.44

Talara 14 0.62 0.53 0.11 0.44 0.00 0.39

Talara 15 0.57 0.57 0.11 0.46 0.00 0.30

Talara 17 0.58 0.56 0.11 0.45 0.00 0.34

Talara 20 0.55 0.56 0.10 0.48 0.00 0.50

Talara 21 0.62 0.55 0.12 0.45 0.00 0.36

Talara 26 0.64 0.54 0.13 0.47 0.00 0.69

Talara 30 0.63 0.49 0.10 0.45 0.00 0.37

AA 9174 0.73 0.65 0.11 0.48 0.00 0.69

EA 8054 0.72 0.63 0.10 0.50 0.00 0.67

EA 10519 0.71 0.65 0.11 0.51 0.00 0.54

EA8004 0.70 0.63 0.11 0.51 0.00 0.62

AA7874 0.69 0.63 0.10 0.45 0.00 0.57

EA9484 0.75 0.67 0.09 0.39 0.00 0.64

AA9161 0.73 0.62 0.17 0.60 0.00 1.00

EA878 0.66 0.67 0.10 0.48 0.00 0.49

AA5717 0.73 0.67 0.09 0.49 0.00 0.76

AA6982 0.71 0.67 0.09 0.47 0.00 0.58

EA7619 0.63 0.67 0.09 0.43 0.00 0.33

EA7931 0.69 0.65 0.09 0.44 0.00 0.46

AA2061 0.68 0.65 0.08 0.43 0.00 0.40

AA6592 0.75 0.67 0.09 0.42 0.00 0.63

EA1121 0.82 0.67 0.12 0.41 0.00 1.02

*Ts = C27 18a(H)-trisnorhopane II; Tm = C27 17a(H)-trisnorhopane.

Fildani et al. 1533

change (marine vs. terrestrial) is supported by positive

correlations observed between oleanane/hopane ratios

with source-indicative parameters, such as diasterane/

sterane ratios and Ts/(Ts + Tm) ratios (Figure 11).

Parameters from C29 steranes, 20S/(20S + 20R), and

abb/(abb + aaa) ratios (averages about 0.55 and 0.58,

respectively; Table 3) are at or near their equilibrium

values (about 0.55 and 0.68, respectively; Seifert and

Moldowan, 1986). This suggests that the oils have been

generated from the source rock in a narrow maturity

range at or near the peak of the oil window.

Biodegradation (reviewed by Peters et al., 2005)

can alter biomarker ratios where one component of

the ratio is more susceptible to bacterial attack than

the other. Most of the studied oil shows a biodegra-

dation rank in the range 0–4 (ranging from intact

n-alkanes to complete n-alkane removal, but without

isoprenoid obliteration; Peters and Moldowan, 1993).

At these biodegradation levels, oil generally does not

show alteration of polycyclic biomarkers. When iso-

prenoids are virtually removed (rank 5), biomarker

alteration can become significant (ranks > 5). Oil is

sometimes observed to contain n-alkanes and/or iso-

prenoids and shows significant biomarker alteration.

These cases are commonly attributed to mixing in the

reservoir of multiple oil charges that have been de-

graded to different extents. Such cases have not been

observed in the Talara oils studied here. However,

several oils show complete loss of isoprenoids by gas

chromatography–flame ionization detector (GC-FID)

analysis (EA10519, EA8001, AA7874, EA9484,

AA9161, EA878, and AA6982), rank� 5. In these cases,

one might expect to observe samples that show some

biomarker biodegradation, although there appears to

be significant inertia between achieving total isopren-

oid biodegradation and effective biomarker alteration,

which results in many oils being stuck at biodegrada-

tion rank 5. No obvious hints of biomarker alteration

appear in any of these oils, except sample AA9161

(Figure 11). Oil AA9161 shows elevated oleanane/

hopane and diasteranes/steranes ratios consistent with

such alteration, and several of the other sterane parame-

ters (Table 3) are also deviant from the other oil samples,

suggesting alteration (Figure 11). Such alteration is evi-

dent because hopane and steranes are more labile toward

biodegradation than oleanane and diasteranes, respec-

tively, and these parameters are seen to respond accord-

ingly with increased values for this sample (Table 3).

OIL – SOURCE ROCK CORRELATION

Biomarker analyses of selected source rock extracts

from both subsurface and outcrop samples of the

Talara basin were compared to the oils in an attempt

to establish oil–source rock correlation. The biomarker

Figure 7. Ternary plot of regular ster-anes for Talara oils and selected sourcerocks. Percentages of C27-C28-C29 ster-anes are based on GCMS analysis of mass/charge (m/z) 217 peak areas of the satu-rates fraction. The ternary plot showssmall differences and the uniform sub-regular C27-C28-C29 sterane distributionand can be interpreted as being indicativeof a marine algal flora because of sub-equal C27-C28-C29 distribution.


Figure 8. Example GCMS mass chromatograms for two oils from the Talara basin showing m/z 191. Notice the large oleananepeaks and the lack of preservation of the higher homohopanes. These data indicate a Cretaceous or younger source rock that wasdeposited in an oxic-suboxic setting and are similar to data for oils derived from other known deltaic settings.

Fildani et al. 1535

parameters of the oils suggest a very specific depo-

sitional environment and age limitation for the source

rock: a Tertiary age source deposited in a clay-rich ma-

rine oxic to suboxic environment with terrestrial in-

put. We infer that the source rock was deposited in

the offshore part of a deltaic environment where local

variation and interfingering of marine and terrestrial

material occurred over short distances and through

time. Distal parts of deltaic systems tend to be clay

rich (Bhattacharya and Walker, 1992), and in an oceano-

graphic setting, such as what occurs along the Peruvian

coast, diatom blooms are seasonally favored by up-

welling, comparable to the modern Peruvian margin

(Aplin et al., 1992).

The Cretaceous shale and marl have good poten-

tial as source rocks (Figure 4) and, when plotted on a

C27-C28-C29 ternary diagram, show a good potential

correlation with the oils (especially samples from well

2278; Figure 7). However, the Muerto Formation sam-

ple yielded biomarker parameter values typical of a

carbonate environment (C29/C30 hopanes) not encoun-

tered in the oils; it lacks oleanane and contains very low

values of NCR and NDR. We therefore conclude that

the bituminous marly limestone facies of the Muerto

Formation sampled for this study is not the source rock

for oils in the Talara basin.

Samples from wells 5927 and 2278 are good source

rocks based on their bulk geochemical measures (Table 1),

but samples from well 2278 completely lack oleanane

(Figure 5). Additionally, NDR and NCR values are

consistent with those typically recorded for Upper Cre-

taceous oils (Holba et al., 1998a) and are thus also

not a match for the Talara oils. The sample from well

5927 has oleanane (Figure 5) and 24-norcholestane

with values of NCR and NDR relatively high for an

Upper Cretaceous source rock, where values lower

than 0.6 and 0.5, respectively, are expected (Holba

et al., 1998a, b). However, overall, the parameters for

sample well 5927 do not match well with the oils. This

sample initially appeared to be a possible candidate

Figure 9. Homohopane distribution(C31–C35) from Talara oil sample 1(representative for all oils) indicatesnonpreservation of the higher homo-hopanes, typical of suboxic bottomwater during deposition.

Table 5. HBI* Values for Selected Oils

Sample

Samples

weight (mg)

Concentration

(mg/mL)

Volume

(mL)

Spike**

(mg) ppm GCMS

HBI

area

HBI Standard

Area

HBI

(ppm)

STD (Standard) 0.01326 50 0.663 CZ223

AA2061 14.4 0.01326 200 2.655 184.41 CZ225 115,067 29,161 727.6662

AA9161 14.3 0.01326 200 2.652 185.45 CZ226 No HBI

EA1121 6 0.01326 100 1.326 221.00 CZ227 104,357 26,980 854.81457

EA7619 8.9 0.01326 100 1.326 148.99 CZ228 123,805 30,189 611.00248

Talara 1 1.3 0.01326 50 0.663 510.00 CZ229 105,594 26,414 2038.8029

Talara 10 1 0.01326 50 0.663 663.00 CZ230 33,119 23,611 929.9859

Talara 14 2.6 0.01326 50 0.663 255.00 CZ231 136,435 30,467 1141.9216

Talara 17 1.6 0.01326 50 0.663 414.38 CZ232 115,951 34,212 1404.396

Talara 20 0.7 0.01326 50 0.663 947.14 CZ233 51,489 28,284 1724.2059

*HBI standard concentration = 0.01333 mg/ml. Remaining HBI standard concentration = 0.01213.**Total spike solution used: 900.


as Talara’s oil source, a dark shale deposited along an

upwelling-related coastline, but the low oleanane and

the C27-C28-C29 sterane distribution indicate otherwise.

Comparison of the biomarker parameters from the two

wells (wells 5927 and 2278) suggests that the intervals

sampled are not correlative, or the potential source rock

interval has significant lateral variations (Figure 5).

We took additional analytical steps to isolate and

identify source units. Stable carbon isotopic compo-

sition is considered important in oil-to-oil correlation

and oil-source correlation, as in fact they can be used to

identify negative correlation (Peters et al., 2005). Two

considerations prompted us to collect stable carbon

isotopic data. First, stable carbon isotopic composition

of oils (d13C) shows a trend of 13C enrichment with

decreasing age that can be used to discriminate different

oils (Chung et al., 1992; Andrusevich et al., 1998).

Second, values of d13C for oils of the Talara basin hint

at an undefined source rock that is younger than the

Upper Cretaceous (Higley, 2004). We analyzed d13C

content of whole oil for nine samples from different

fields in our possession (Table 6). The analyses were

conducted at the Stable Isotope Biogeochemistry

Laboratories at Stanford University. Whole-oil d13C

(versus Peedee belemnite [PDB]) isotope measure-

ments of the nine oil samples yield a ratio near �21x(Table 6; error of ±0.2x), suggesting a similar source

rock for each of the sampled Talara fields. Four d13C

Figure 10. Distribution maps for oleanane index and NDR. Notice the compensatory aspect to their distributions, suggesting lateralfacies changes in the source rocks.

Fildani et al. 1537

values from proprietary data from Perez Companc

show ratios near �21.5x(Table 6).

Our d13C analyses of kerogen extracted from the

well 5927 sample yield an average value of �26.47x(Table 6). This average value derived from kerogen

differs significantly from the average value of d13C for

the Talara oils (�21x). The sampled interval in well

5927 is isotopically too light to be the source of Talara

oils. Age-discriminant biomarker parameters all suggest

that Talara oil is from a Tertiary source rock interval.

Figure 12 compares the parameter NCR with d13C to

reinforce the result of a Tertiary age for the oil. Fur-

thermore, comparing the obtained d13C values with

global values of carbon isotopes through time in crude

Figure 11. Correlation betweenTs/(Ts + Tm) ratios, oleanane/C30 hopane ratios, and diaster-ane/sterane ratio suggests thatorganic facies change is an in-fluential factor in the variation ofbiomarker parameters but notan issue for Talara oils. Divergentpoint in the upper right of eachgraph is sample AA9161, whichhas biodegraded biomarkers.


oils (Chung et al., 1992; Andrusevich et al., 1998), the

value for the kerogen extracted by sample well 5927 is

consistent with a Late Cretaceous system, whereas the

oils suggest a younger source rock (maybe Oligocene or

younger). The reason for the isotopic shift in the global

carbon budget that occurred in the late Tertiary is not

completely understood, but it is believed to be related

to a sudden, rapid drop in the concentration of atmo-

spheric CO2 (Chung et al., 1992). The heavy isotopic

values of the Talara oils further suggest a prevalent ma-

rine input. Terrestrial organic matter is isotopically in-

variant at about �25x(Chung et al., 1992). Although

the abundance of oleanane indicates that the source of

the oil received higher land plant material, the heavy

isotopic value of the oils suggests that marine algae

contributed the bulk of the organic matter to the source.

IMPLICATIONS OF A TERTIARY SOURCE ROCK

Talara basin oils present a dilemma with multiple per-

missible solutions inferable from the available data.

Major effort is required to improve our understand-

ing of the petroleum system of a basin that, even if

tectonically complicated, remains burdened by unsub-

stantiated concepts. Biomarker parameters and d13C

values indicate that where sampled, the Upper Creta-

ceous strata are not the main source for Talara oil.

Thus, our findings contrast with the presumption of

source rocks in the Upper Cretaceous (Zuniga-Rivero

et al., 1999; Arispe, 2001a; Gonzales and Alarcon,

2002; Valencia and Uyen, 2002). Published data show-

ing the enrichment in d13C in the oils were interpreted

as a clear signature of a Tertiary source rock (Higley,

2004), thus contradicting the conventional belief that

the source rock is Late Cretaceous in age. Furthermore,

our analysis of potential source rock samples from

the Eocene interval failed to reveal any new possible

source rocks, nor have any unpublished proprietary

reports (Perez Companc, 2001, personal communi-

cation) helped to unveil unreported sources.

All available data suggest that Talara oils were

generated from a younger source rock than previously

believed, a source rock that might not even be present

within the traditional boundaries of the Talara basin.

Peters et al. (2005), from a limited database (reporting

only few GCMS traces), suggested that the Heath For-

mation could be the source rock for both the Talara

basin and the Progreso basin. A published chromatogram

of a rock extract obtained from cuttings from the well

Piedra Redonda C-13X (Peters et al., 2005) is a good

match with the oils from the Talara basin (Figure 13).

The sample is described as being from the Heath

Formation, and the chromatogram shows oleanane and

a pattern of tetracyclic terpanes similar to the oils from

Talara (Figure 13). Furthermore, Higley (2004) re-

ported that geochemical characteristics of two oils from

the Progreso basin are a good match with the observed

values of the Talara oils and concluded that the Talara

and Progreso oils could be grouped in the same family,

probably from the same source rock interval. Although

further analyses (for both biomarker and isotopes) are

needed to unequivocally confirm this relationship, it

appears that the potential source rocks could lie within

the deltaic system of the Heath Formation or a similar

depositional system. The Piedra Redonda well is located

north of the Talara basin in an area reported as part of

the Progreso basin (Kraemer et al., 1999) (Figure 14).

Because Oligocene and Miocene strata have not been

drilled in the Talara basin and the Heath Formation is

only known to be present in outcrops north of Talara

basin, the upper Oligocene and early Miocene have been

overlooked as potential source rocks for oils in the

Talara basin. The presence of structural barriers (such

as the Pillars de Zorritos) and zones of intense faulting

Table 6. d13C Values for a Possible Source Rock and Oils

from Talara Basin

Formations Depth (ft) d13C (x)

Source RockWell 5927 Redondo 8020–8030 �26.142

Well 5927 Redondo 8040–8050 �26.332

Well 5927 Redondo 8040–8050 �26.95

OilsEA1121 �21.259

AA9161 �20.741

EA7619 �21.312

AA2061 �20.782

Talara 10 �20.711

Talara 17 �20.65

Talara 20 �22.056

Talara 1 �21.853

Talara 14 �21.483

Oils (from Pecom del Peru)Well 1531 Helico �21.1

Well 1659 Ostrea �21.7

Well 5167 Parinas �21

Well 5176 Bas. Salina �22.2

Fildani et al. 1539

between the Progreso and the Talara basins have been

considered obstacles for lateral migration. Unpublished

data from Perez Companc suggest that lateral migration

is unlikely, especially to the north near the Progreso

basin, where the Oligocene has been drilled with no oil

shows and where a series of dry wildcats were drilled

south of the Pillars de Zorritos (Figure 1) (G. Pozo, 2004,

personal communication). This evidence seemingly pre-

cludes the possibility of lateral migration of oil from the

upper Oligocene–lower Miocene Heath Formation,

which is present to the north, into Eocene Talara reser-

voirs, while leaving Oligocene reservoirs uncharged.

Alternatively, we suggest three possible scenarios

to account for Talara basin oil. For the first scenario,

we assume that the Heath Formation main deposi-

tional area was located (as described) in the Progreso

basin, north of Talara. In this case, the Oligocene Heath

Formation generated the oil that migrated to the

Eocene reservoirs of Talara before the structural bar-

riers became effective. In this scenario, lateral migra-

tion of almost 100 km (62 mi) must be postulated to

account for the charge of the Eocene reservoir intervals

(Figure 14). The absence of oil in Oligocene deposits in

the north could be explained by the absence of traps at

the time of migration (Figure 14), with the implication

of structural deformation after the late Oligocene.

Another scenario depends critically on Paleogene

extensional tectonism in the Talara basin (Fildani, 2004).

In this scenario, a Paleogene horst and graben setting

would favor the development of basinal marine-source

facies and a thick accumulation of sediment, which

could have been sufficient to foster oil maturation.

Sediments deposited in deep-water environments in the

late Eocene crop out along the modern Peruvian coast

(Fildani, 2004). The Oligocene sedimentary rocks to

the north are interpreted as having been deposited in

deltaic environments, and the depositional systems of

the Progreso basin are described as deltaic to shallow

Figure 12. Comparative diagram showing (A) 24-norcholestane (NCR) vs. geologic age with white field indicating the variation ofNCR with geologic age (modified from Holba et al., 1998a, b). (B) d13C variation through geologic time with fields being defined bydiagonal lines (modified from Chung et al., 1992), and different average values represented by solid line with dots, from Andrusevichet al., (1998). For both figures the stars indicate average values.


marine (Kraemer et al., 1999). We suggest that the

deposition of effective oil-source strata occurred off-

shore of the Talara basin in the late Eocene and Oli-

gocene. These strata would be the southern equivalent

of the Heath Formation. In this scenario, like the pre-

vious one, lateral migration of at least tens of kilo-

meters must be assumed to account for the charge of

the Eocene reservoir intervals. Both scenarios 1 and 2

contrast with the currently proposed but unproven

vertical migration mechanism for reservoir charge in

the Talara basin (Sanz, 1988; Higley, 2004).

A third alternative scenario retains the vertical mi-

gration model in charging the Eocene reservoirs by

emphasizing the function of compressional inversion

of the basin in the late Oligocene. Thrust faults are

present in outcrops in the Talara basin, and Serranne

(1987) reported phases of compressional tectonism

based on structural analysis. Eocene proximal facies in

the eastern part of the basin could have thrust over

equivalent distal offshore facies, as well as Oligocene

strata, during basin inversion. This last scenario has not

been tested by drilling, but it could be easily evaluated

with good-quality regional seismic reflection profiles,

which presently are not available for the area. We

cannot exclude a combination of different components

from these scenarios. Indeed, a strong possibility exists

that tectonism and structural architecture control mi-

gration paths of the Talara petroleum system. The

Figure 13. Comparison betweena representative oil from theTalara basin (Talara 1) and apublished rock extract from thePiedra Redonda well (from Peterset al., 2005). Tetracyclic terpanesand homohopanes are labeled;the stars indicate an unknowntetracyclic terpane common toall the oils of Talara and to thePiedra Redonda sample. Therock extract comes from an in-terval of the late Oligocene HeathFormation.

Fildani et al. 1541

mapped oil parameters of Figure 10 could be related to

slight facies changes in source rock characteristics be-

cause they are quite systematic in their distribution and

probably not coincidental. This implies the preserva-

tion of oil characteristics throughout migration with

only partial homogenization of oils. Thus, the areas of

effective source rock (kitchens) should be relatively

close, and only limited lateral migration is implied.

CONCLUSIONS

Biomarker parameters and the d13C signature of oil

samples from the Talara basin indicate that the oil was

generated from a Tertiary source rock probably depos-

ited in a marine upwelling setting (diatomaceous shale

intervals) with significant influx of terrestrial organic

matter. An interpretation of a deltaic environment

best explains the mix of marine and terrestrial com-

ponents, with a dominant marine component. Up-

welling influences are clearly indicated by HBI, a bio-

marker compound directly related to the diffusion and

diversification of diatoms. Biomarker attribute map-

ping shows that the upwelling deposits were located

in a more distal position in the deltaic system (prodelta

or offshore). Based on a comparison with published data,

we suggest that the Oligocene or younger shale de-

posits (such as the Heath Formation and/or its lateral

equivalent) in the Talara offshore are the main source

rocks for the oils of the Talara and Progreso basins. Al-

though the Upper Cretaceous strata of the Talara basin

contain potential petroleum source rock intervals, these

do not correlate with the biomarker signature of the

oils, and consequently, they are not the main source

Figure 14. Location map of all the oil samplesused in this study and for the Piedra Redondawell to the north where intervals of the HeathFormation were reached. The three differentpossible scenarios are described in the text.The arrows indicate possible migration pathsfor different scenarios.


intervals of Talara oils analyzed. Nevertheless, Upper

Cretaceous strata could provide the charge for an ad-

ditional petroleum system in northwest Peru yet to

be discovered.

APPENDIX 1: LABORATORY PROCEDURESAND TECHNIQUES

Sample Separation

About 30 g of rock sample were pulverized and transferred to a po-rous thimble (Whatman cellulose extraction thimble, single thick-ness, 33 mm [1.3 in.] internal diameter, 80 mm [3.1 in.] externallength, and 35 mm [1.4 in.] external diameter), which was placedinto a Soxtec extraction unit to extract soluble bitumen. A beakerfilled with extraction solvent (azeotropic mixture of toluene/methylene chloride at a volume ratio of 2:1 with a boiling pointof 63.8jC) was attached to the extractor and heated with an oilbath for 2 hr. Subsequently, the extract was transferred, solventevaporated, and weighed for cleanup and separation.

All rock extracts and oil samples were separated into saturatesand aromatic fractions at the Molecular Organic Geochemistry Labo-ratories at Stanford University using the method described by Petersand Moldowan (1993). In brief, oils and rock extracts are absorbedonto an alumina column. The saturate-aromatic cut is rinsed from thecolumn with methyl t-butyl ether/hexane (10:90 vol/vol). The cleaned-up saturate-aromatic fraction of the oil or rock extract is separatedusing a Waters model 590 HPLC pump equipped with a WhatmanPartisil 10 silica column (9.4 mm [0.37 in.] internal diameter� 50 cm[20 in.]). The eluent is divided into three fractions: saturates, aromatics,and polar compounds. Molecular sieves (high Si/Al ZSM-5 zeolite, sili-calite, with pore size of 6 A) were used to remove n-alkanes (paraffins)from saturates to increase the signals of more diagnostic biomarkers.

Instrumental Analysis

Gas Chromatography

Crude oils were analyzed using a Hewlett-Packard (HP) 5890 gaschromatograph equipped with flame ionization detector and a 24-m(78-ft) methyl silicone DB-1 column with 0.2 mm (0.008 in.)internal diameter and 0.33 mm phase thickness. Crude oils werediluted 40-fold with toluene, and 0.5 mL of the solution was injectedonto the column. The injector was set at 325jC in the splitlessmode. Hydrogen was used as the carrier gas with a head pressure of20 psi. The oven temperature was set to rise from 80 to 320jC at10jC/min and to hold at 320jC for 20 min.

Selected Ion-Monitoring Gas

Chromatography–Mass Spectrometry

Because of upgrades in instrumentation, two different instrumentswere used for samples collected in different years. Specifically, sam-ples collected in 2000 were analyzed with an SIM-GCMS, Trio I VGMasslab, whereas samples collected in 2001 were analyzed using anHP 5890 MSD. For the 2001 sample set, silicalited saturates wereanalyzed using HP 5890 Series II gas chromatograph connected to HP5972 Series mass selective detector. Silicalited saturate cuts werediluted 20-fold with hexane, and 0.5 mL of the solution was injected

with an HP 6890 autoinjector. The injector was set at 325jC in thesplitless mode. The carrier gas was helium at 1.0 mL/min with a headpressure of 15.7 psi at 190jC. The column was a 60-m (197-ft) HPDB-1 column with 0.25 mm (0.009 in.) internal diameter and 0.25mm phase thickness. The GC oven temperature started at 140jC,stayed at this temperature for 1 min, rose to 325jC at 3.5jC/min, andstayed at 325jC for 10 min.

For the 2000 sample set, SIM-GCMS was conducted on aTrioVG instrument. The silicalited saturate cuts were diluted 10-fold with hexane, and 0.1 mL of the sample was injected on the HP5890 Series II GC. The injector was set at 325jC in the splitless mode.The column was a 60-m (197-ft) HP DB-1 column with 0.25 mm(0.009 in.) internal diameter and 0.25 mm phase thickness. The ovenGC temperature started at 130jC, then rose to 320jC at 2jC/min,and stayed at 320jC for 20 min.

Metastable Reaction-Monitoring Gas

Chromatography–Mass Spectrometry

For the sample set collected in 2000, silicalited saturates wereanalyzed using an HP 5890 Series II gas chromatograph connectedto an AutoSpecQ mass spectrometry. The GC oven temperaturestarted at 140jC, stayed at this temperature for 1 min, then rose to326jC at 6jC/min, and stayed at 326jC for 15 min. Hydrogen wasthe carrier gas with a head pressure of 27 psi. The column was a 60-m(197-ft) J&W DB-1 column with 0.25 mm (0.009 in.) internal di-ameter and 0.25 mm phase thickness. The mass spectrometer wasset at EI+ ionization mode with a cycle time of 810 msec.

Samples collected in 2001 were analyzed on the sameinstrument, using a slightly different GC temperature program,which started at 150jC, then rose to 325jC at 2jC/min, and stayedat 325jC for 20 min.

APPENDIX 2: PRISTANE/PHYTANE RATIOS

Samples Pristane/Phytane

AA2061 1.27AA5717 1.65AA6592 1.58AA9174 1.68AFMuerto, (rock extract) 1.06AFRedond, (rock extract) 1.96EA1121 1.84EA2278-7870 1.58EA2278-7890 1.29EA5927-8010 0.17EA7619 1.45EA7931 1.53EA8054 1.29Talara 1, B/C 1.70Talara 2. B/C 1.68Talara 4, B/C 1.57Talara 7, B/C 1.52Talara 10, B/C 1.48Talara 14, B/C 1.64Talara 15, B/C 1.49Talara 17, B/C 1.38Talara 20, B/C 1.11Talara 21, B/C 1.48Talara 26, B/C 1.39Talara 30, B/C 1.53

Fildani et al. 1543

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geochemical characteristics of oil and source rocks and

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