The document discusses the petroleum system of the Camamu-Almada basin in northeastern Brazil, utilizing 1-D and 2-D modeling to analyze its geological evolution and potential for oil exploration. It highlights the primary sources of oil generation linked to lacustrine source rocks and the influence of low-permeability shales on petroleum migration. Additionally, the report emphasizes the importance of quantitative basin modeling in evaluating the risks and effectiveness of petroleum exploration in this region.

1. Gonçalves, F. T. T., R. P. Bedregal, L. F. C. Coutinho, and M. R. Mello, 2000,
Petroleum system of the Camamu–Almada Basin: a quantitative modeling
approach, in M. R. Mello and B. J. Katz, eds., Petroleum systems of South
Atlantic margins: AAPG Memoir 73, p. 257–271.
Chapter 19
Petroleum System of the Camamu–Almada
Basin: A Quantitative Modeling Approach
Abstract
The Camamu–Almada Basin, located in northeastern Brazil, is part of the rift system that formed
during the Early Cretaceous break-up of South America and Africa. Previous studies have characterized
the occurrence of a single petroleum system in this basin, the Morro do Barro(!), which encompasses a
Neocomian synrift lacustrine source rock and turbiditic reservoirs of the same age. 1-D and 2-D tectonic,
thermal, and geochemical modeling was applied to better understand the evolutionary history of the
petroleum system, as well as to provide a basis for better assessment of the exploration risk and petroleum
potential of the Camamu–Alamada Basin.
The hydrocarbon generation modeling indicates that most of the oil was generated by the end of the
rift phase (Barremian–Aptian). Present kerogen transformation ratios range from 10–20% nearby the conti-
nent (west) to 100% in the deeper areas (east). Fluid-flow modeling showed that the presence of a thick
section of low-permeability shales above the source rocks favored the downward migration of petroleum
to the sandstones of the Sergi Formation. Petroleum migration through normal faults, which juxtaposed
source rocks of the Morro do Barro Formation to sandstones of the Sergi Formation, also played a major
role in the filling of these carrier beds. Secondary migration extended considerably into the postrift phase.
INTRODUCTION
Over the past few years, application of the petroleum
system concept (Magoon, 1988) has provided a new ratio-
nale to approach petroleum research, to formulate plays
and prospects, and to evaluate the related exploration
risk. A petroleum system includes all the essential
elements (source rock, reservoir rock, seal rock, and over-
burden) and processes (trap formation, generation,
migration, and accumulation) that are needed for a petro-
leum accumulation to exist (Magoon and Dow, 1994).
A petroleum system also requires the timely conver-
gence of these elements and processes and a positive
mass balance between hydrocarbon charge and losses
through migration. Nevertheless, most petroleum system
studies emphasize only the qualitative aspects of the
system, such as describing present-day source rock matu-
rity and distribution, assessing reservoir quality and
occurrence, or performing geochemical characterization
of hydrocarbons. The application of quantitative basin
modeling techniques allows a better understanding of the
spatial and temporal relationships between the elements
and processes of petroleum systems, as well as assessing
the hydrocarbon mass balance. These are critical factors
when evaluating the risk associated with prospects.
The Camamu–Almada Basin, located in northeastern
Brazil (Figure 1), is part of the rift system that formed
during the Early Cretaceous break-up of South America
and Africa. With an area of about 12,000 km2 (10,000 km2
of that below sea level), this basin contains some small
gas accumulations in the onshore area and two oil fields
in the offshore (platform) area. The basin infill comprises
a thick (up to 10,000 m) succession of prerift, rift and
postrift strata. A previous study (Mello et al., 1995) has
characterized the occurrence of a single petroleum system
in the Camamu–Almada Basin: the Morro do Barro(!)
257
F. T. T. Gonçalves
R. P. Bedregal
Petrobrás R & D Center/Cenpes
Rio de Janeiro, Brazil
L. F. C. Coutinho
Petrobrás E & P Department
Salvador, Brazil
M. R. Mello
Petrobrás R & D Center/Cenpes
Rio de Janeiro, Brazil

2. Gonzaga, F. G., F. T. T. Gonçalves, and L. F. C. Coutinho, 2000, Petroleum geol-
ogy of the Amazonas Basin, Brazil: modeling of hydrocarbon generation and
migration, in M. R. Mello and B. J. Katz, eds., Petroleum systems of South
Atlantic margins: AAPG Memoir 73, p. 159–178.
Chapter 13
Petroleum Geology of the Amazonas Basin,
Brazil: Modeling of Hydrocarbon Generation
and Migration
Abstract
The Amazonas Basin is a 500,000-km2 intracratonic basin in northern Brazil. The ~6000-m lithologic
section encloses mainly Paleozoic sedimentary rocks intruded by Triassic–Jurassic diabase dikes and sills,
and subsequently buried by Cretaceous–Tertiary rocks. Geochemical and geologic data point to the Upper
Devonian marine black shales from Barreirinha Formation as the main hydrocarbon source rocks.
Data from 11 selected wells were used to perform thermo-mechanical modeling. Backstripping and
stratigraphic analyses indicate four extensional events: Ordovician–Early Devonian, Devonian–Early
Carboniferous, Middle Carboniferous–Permian, and Cretaceous–Tertiary. The tectonic subsidence curve
of each well was compared to theoretical subsidence curves to define the extensional factors and deter-
mine the heat flow history. The integration of 1-D basin modeling with geologic and geochemical data
suggests that the Barreirinha Formation source rock started to generate petroleum during the Late
Carboniferous. Modeling of primary migration indicates that the main phase of oil expulsion began when
the source rock attained a transformation ratio of ~50% and a maturation level of 0.80% Ro. The main
phase of petroleum generation and expulsion occurred from Late Carboniferous to Permian time and was
completed by the Early Triassic. Any later tectonic event remobilized those hydrocarbons previously
trapped.
Preliminary volumetric calculations indicate that up to 1 trillion bbl of oil equivalent were expelled
from the source rock. Because of the long distances of both vertical and horizontal migration, it is believed
that an important amount of the expelled hydrocarbon was dispersed along migration pathways.Asignif-
icant part could also have been remobilized and lost during Cretaceous uplift of the basin margins.
INTRODUCTION
The Amazonas Basin is a 500,000-km2 intracratonic
basin located in northern Brazil within the Amazon rain
forest. It is separated from the Marajó Basin by the
Gurupá arch on the east and from the Solimões Basin by
the Purus arch on the west (Figure 1).Although geochem-
ical data suggest a significant hydrocarbon source poten-
tial, no commercial petroleum accumulations have yet
been discovered. The basin’s sedimentary fill is about
6 km thick and consists mainly of Paleozoic rocks
(Ordovician–Permian) intruded by Triassic–Jurassic
diabase dikes and sills, and subsequently buried by
Cretaceous–Tertiary rocks (Figure 2).
This chapter describes the main results of a multidisci-
plinary survey carried out using seismic and well data in
addition to oil, gas, and rock samples. Geochemical meth-
ods included elemental and visual kerogen analysis,
Rock-Eval pyrolysis, gas chromatography, and mass
spectrometry. Also, numerical modeling was performed
using 1-D software (BaSS/Petrobras for thermo-mechan-
ical modeling and Genex/Institut Français du Pétrole for
geochemical modeling). The integration of geologic and
geochemical data with modeling results allowed charac-
159
F. G. Gonzaga
Petrobrás E&P
Rio de Janeiro, Brazil
F. T. T. Gonçalves
Petrobrás CENPES
Rio de Janeiro, Brazil
L. F. C. Coutinho
Petrobrás E&P
Salvador, Brazil