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).
1522 The Petroleum System of Talara Basin
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
1524 The Petroleum System of Talara Basin
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
1526 The Petroleum System of Talara Basin
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
T Muerto 2 Outcrop Muerto 0.19 0.00 0.05 0.19 432 26 100 0.26 0.00 0
T Muerto 3 Outcrop Muerto 0.32 0.02 0.32 0.25 437 100 78 1.28 0.06 6
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.
1528 The Petroleum System of Talara Basin
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
Figu
re5
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1530 The Petroleum System of Talara Basin
Figu
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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.
1532 The Petroleum System of Talara Basin
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.
1534 The Petroleum System of Talara Basin
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.
1536 The Petroleum System of Talara Basin
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.
1538 The Petroleum System of Talara Basin
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.
1540 The Petroleum System of Talara Basin
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.
1542 The Petroleum System of Talara Basin
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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