The Santos Basin in Brazil is a hot area of oil and gas exploration in recent years, and its subsalt lacustrine mudstones are the main source rock of the basin. However, there is a lack of studies on the source rocks of the subsalt Picarras and Itapema formations, which is not conducive to the accurate evaluation of the source rock characteristics. Based on logging data of 51 wells and geochemical data of 16 wells, this paper makes detailed evaluations of the organic matter abundance, type, maturity, and distribution characteristics of source rocks of the subsalt Picarras Formation and Itapema Formation in the Santos Basin. The results show that the characteristics of source rocks of the Itapema and Picarras formations are similar, both of which have a high abundance of organic matter. The types of organic matter are mainly type I and II1, and the maturities are in the low-maturity to the high-maturity stage, which meets the standard of good source rocks. The total organic carbon content of the source rocks of the Picarras Formation ranges from 0.4 to 4.0%, much lower than that of the source rocks of the Itapema Formation, 0.8-5.6%. In addition, the hydrogen index average value of the source rocks of the Itapema Formation is 712.8 mg/g TOC, higher than that of the Picarras Formation, 697.5 mg/g TOC, both revealing a great hydrocarbon potential. The quality of source rocks of the Itapema Formation is better than that of the Picarras Formation. The two sets of source rocks have great hydrocarbon generation potential and are mainly developed in the eastern and western sags of the central depression. Therefore, the surrounding uplift areas will be the target for further oil and gas exploration.
The Santos Basin in Brazil is a hot area of oil and gas exploration in recent years, and its subsalt lacustrine mudstones are the main source rock of the basin. However, there is a lack of studies on the source rocks of the subsalt Picarras and Itapema formations, which is not conducive to the accurate evaluation of the source rock characteristics. Based on logging data of 51 wells and geochemical data of 16 wells, this paper makes detailed evaluations of the organic matter abundance, type, maturity, and distribution characteristics of source rocks of the subsalt Picarras Formation and Itapema Formation in the Santos Basin. The results show that the characteristics of source rocks of the Itapema and Picarras formations are similar, both of which have a high abundance of organic matter. The types of organic matter are mainly type I and II1, and the maturities are in the low-maturity to the high-maturity stage, which meets the standard of good source rocks. The total organic carbon content of the source rocks of the Picarras Formation ranges from 0.4 to 4.0%, much lower than that of the source rocks of the Itapema Formation, 0.8-5.6%. In addition, the hydrogen index average value of the source rocks of the Itapema Formation is 712.8 mg/g TOC, higher than that of the Picarras Formation, 697.5 mg/g TOC, both revealing a great hydrocarbon potential. The quality of source rocks of the Itapema Formation is better than that of the Picarras Formation. The two sets of source rocks have great hydrocarbon generation potential and are mainly developed in the eastern and western sags of the central depression. Therefore, the surrounding uplift areas will be the target for further oil and gas exploration.
Since Tissot et al. proposed
the theory of late oil generation
of kerogen thermal degradation in the 20th century,[1,2] research
on source rocks has been a significant work for geologists to analyze
the oil and gas exploration prospects in basins and zones. Oil and
gas are generated and discharged from source rocks, and after migration
and accumulation, the oil and gas can become valuable resources for
human development and utilization. The source rocks play an important
role during the oil and gas exploration.[3−5] Especially with the improvement
of oil and gas exploration, it is increasingly difficult to increase
the reserve and production. Therefore, the characteristics and evaluation
of source rocks have become the top priority of oil and gas exploration.[6,7] The geochemical characteristics of source rocks mainly focus on
the abundance, type, and maturity of organic matters. Macroscopically,
it is also necessary to evaluate the thicknesses distribution of source
rocks.[8−10]Global and gas exploration has experienced
a development stage
from shallow to deep and from land to sea. In the present day, the
world has entered a new stage of oil and gas exploration and development
in deep water. In recent 10 years, the proportion of newly discovered
passive continental margin basins has reached 65% in global oil and
gas exploration, with emphasis on the Gulf of Mexico, Santos, Kwanza,
Senegal, and Arab basins. The Santos Basin is a typical passive continental
margin petroleum-bearing basin in Southeast Brazil,[11,12] with excellent petroleum geological conditions and numerous oil
and gas discoveries. By the end of 2016, 38 oil and gas fields have
been discovered in the subsalt strata of the basin, with a total proved
recoverable reserves of about 30 billion barrels, accounting for 94%
of the Santos Basin.[13] Since 2006, several
giant oil and gas fields such as Lula, Jupiter, Sapinhoa, Franco,
and Libra have been continuously discovered in the field of lacustrine
carbonates of the subsalt strata in the deep-water area of the Santos
Basin, revealing that the subsalt strata of the basin have rich oil
and gas resources and great exploration potential.[14−16]Predecessors
have made some understandings of the research of source
rocks.[13,17−21] Scholars generally believe that there are two sets
of source rocks in the Santos Basin. One is the lacustrine source
rocks of the Early Cretaceous Barremian–Aptian Stage Guaratiba
Group in the subsalt rift period, and the other is the marine source
rocks of the Late Cretaceous Cenomanian–Turonian Stage Itajai-Acu
Formation in the postsalt drift period. It is confirmed that the Guaratiba
Group lacustrine mudstones, including the Picarras Formation and Itapema
Formation deposited in the subsalt rift period, are the main source
rocks of the basin.[13,17,19,21] The lacustrine source rocks of the Guaratiba
Group in the subsalt strata are characterized by high organic matter
abundance, good types, and great hydrocarbon generation potential,
in which the total organic carbon content (TOC) is between 1.0 and
15.9%, and the average value is 5.12%. The hydrogen index (HI) ranges
from 500 to 1084 mg/g, with an average of 755 mg/g. The average value
of hydrocarbon generation potential (S1 + S2) is 42 mg/g, the kerogen type is
type I, and the source rocks are widely distributed throughout the
basin.[13,19,21]Previous
geochemical evaluations of the presalt source rocks in
the Santos Basin were mostly concentrated in the Guaratiba Group.
However, there are two set of dark mudstones developed in this group
that show differences in the scale and quality due to the different
depositional environments, have not been carefully investigated. These
are Picarras and Itapema Formations, respectively. These differences
cannot be reflected by the overall evaluation of the Guaratiba Group,
which restricts the evaluations of petroleum potential and favorable
zones. In addition, there is a lack of geochemical data in the previous
research. Some studies use the geochemical data of source rocks in
the rift period of the adjacent Campos Basin for analogy research,[22] and other studies use the data of only one well
for the whole basin research,[23] leading
to great controversy on the research results. Therefore, based on
the logging data of 51 wells and the geochemical data of 16 wells,
combined with the seismic data and sedimentary facies, this paper
systematically studies the organic matter abundance, type, maturity,
and distribution of the source rocks of the subsalt Picarras Formation
and Itapema Formation in the Santos Basin and reveals the characteristics
and center of the source rocks. The research results are of great
significance to the further evaluation and exploration of oil and
gas resources in the Santos Basin.
Geological Settings
The Santos Basin
is a typical passive continental margin basin
located in the southeast sea area of Brazil, adjacent to the Campos
Basin in the north and the Pelotas Basin in the south. It covers an
area of about 32.7 × 104 km2 and a water
depth of 0–3200 m (Figure ).[11,24] The presalt lacustrine carbonate
in the Santos Basin is rich in oil and gas resources and is considered
a hotspot of exploration in the world.[19−25] The subsalt structure of the basin is generally NE–SW trending.
From west to east, the Santos Basin is composed of the western uplift
belt, the central depression belt, the eastern uplift belt, and the
continent–ocean transition belt.[19,26]
Figure 1
Structural
unit division and position of the Santos Basin.
Structural
unit division and position of the Santos Basin.The tectonic evolution of the Santos Basin is related
to the disintegration
of the Gondwana continent and the expansion of the Atlantic Ocean
since the Mesozoic.[26,27] It experienced three stages of
tectonic evolution as follows. (a) The rift period from the deposits
of the Picarras Formation to the Barra Velha Formation; (b) the transition
period from the deposits of the Ariri Formation; and (c) the drift
period from the deposits of the Guaruja Formation to the present day.
Correspondingly, three sets of giant thick sedimentary sequences were
developed, namely the continental giant sequences of the Guaratiba
Group in the rift period, the evaporative salt giant sequences of
the Ariri Formation in the transition period, and the marine giant
sequences of the passive continental margin carbonates, deep-sea mudstones,
and deep-sea turbidite sandstones in the drift period (Figure ).[16,27,28] From the bottom to the top, the basin mainly
develops four sets of reservoirs: the lacustrine limestone of the
Cretaceous Guaratiba Group, the shallow-sea sandstone, carbonate of
the Florianopolis Group, the turbidite sandstones of Santos Group,
and the turbidite sandstones of the Paleogene–Neogene Marambala
Group.[13−15,27] Oil and gas are mainly
enriched in the limestone reservoir of the subsalt Guaratiba Group.
Two sets of source rocks are mainly developed in the basin, one is
the lacustrine source rocks of the Lower Cretaceous Barremian–Aptian
Stage Guaratiba Group in the subsalt rift period, and the other is
the marine source rocks of the Upper Cretaceous Cenomanian–Turonian
Stage Itajai-Acu Formation in the postsalt drift period.[13,17,21] In recent years, the discoveries
of a large amount of oil and gas have confirmed that the lacustrine
mudstones of the Guaratiba Group deposited in the subsalt rift period
are the main source rock of the basin.[17,20,29,30] The lacustrine source
rocks of the Guaratiba Group consist of the Picarras Formation and
the Itapema Formation source rocks. The Picarras Formation was formed
in the middle rift period of the Early Cretaceous Barremian stage,
developing deep lacustrine marl, mudstones, and argillaceous limestone.
The Itapema Formation was formed in the late rift period of the Barremian–Early
Aptian stage, and the lacustrine mudstones, marl, and shell limestone
were developed (Figure ).[13,17]
For the first time, based
on a large collection of geochemical
parameters, logging data of 51 wells and the geochemical data of 16
wells,[9,17,21,31−33] the geochemical characteristics
of source rocks of different strata of wells were evaluated from three
aspects: organic matter abundance, type, and maturity. Then, based
on the logging data, the thicknesses of dark mudstones of 40 wells
in the Itapema Formation and 12 wells in the Picarras Formation, the
ratio of the dark mudstone thickness to the formation thickness were
counted. Next, combined with the seismic interpretation results and
sedimentary facies,[34] the thicknesses were
analyzed according to the law of dark mudstones developed in deep
and semideep lacustrine facies. Then, based on the TOC of 15 wells
in the Itapema Formation and 5 wells in the Picarras Formation, combined
with the lithofacies paleogeography characteristics and the thickness
of the dark mudstones, the horizontal distribution diagrams of TOC
of the two formations of the subsalt source rocks were compiled. Taking
TOC ≥0.40% as the standard of effective source rock in logging
data,[33] the horizontal distribution diagrams
of the thickness of the two formations of the subsalt source rocks
were drawn. Finally, the hydrocarbon generation potential and favorable
areas for development in the Santos Basin were clarified.
Results
Organic Matter Abundance
Organic
matter abundance is commonly used to represent the relative content
of organic matter in source rocks, which is an important basis for
measuring and evaluating the hydrocarbon generation potential of source
rocks.[9,35,36] In this paper,
the organic matter abundance of the subsalt Itapema Formation and
Picarras Formation source rocks in the Santos Basin were evaluated
by the industry standard for the evaluation of organic matter abundance
in continental source rocks issued by the China National Petroleum
Corporation in 1995. The evaluation indexes mainly include the TOC,
chloroform bitumen “A” content, total hydrocarbon content
(HC), and hydrocarbon generation potential (S1 + S2) (Table ).
Table 1
Evaluation Indexes of the Organic
Matter Abundance of the Continental Source Rocks (SY/T 5735-1995)a
TOC—total organic carbon
content; HC—hydrocarbon content; S1 + S2—hydrocarbon generation potential.The TOC of the Itapema Formation source rock ranges
from 0.40 to
7.32%, with an average of 1.38%; the chloroform bitumen “A”
content varies from 0.38 to 0.69%, with an average of 0.52%; the HC
ranges from 139.3 to 1791.4 μg/g, with an average of 677.4 μg/g;
the S1 + S2 is between 1.09 and 50.20 mg/g, with an average of 12.50 mg/g, which
meets the standard of good source rock (Table ).
Table 2
Evaluation of the Organic Matter Abundance
of the Subsalt Source Rocks in the Santos Basin
horizon
TOC (%)
chloroform bitumen “A” (%)
HC (μg/g)
S1 + S2 (mg/g)
HI (mg/g TOC)
evaluation
Itapema Formation
0.4–7.32/1.38(71)
0.38–0.69/0.52(3)
139.3–1791.4/677.4(14)
1.09–50.2/12.5(61)
409.5–994.0/712.8(23)
good source
rock
Picarras Formation
0.71–4.76/2.14(19)
0.24–0.28/0.26(2)
235.0–895.5/565.2(2)
2.7–66.3/19.0(24)
292.1–986.0/697.5(13)
good source
rock
The TOC of the Picarras Formation source rock ranges
from 0.71
to 4.76%, with an average of 2.14%; the chloroform bitumen “A”
content is 0.24–0.28%, with an average of 0.26%; the HC ranges
from 235.0 to 895.5 μg/g, with an average of 565.2 μg/g;
the S1 + S2 varies from 2.70 to 66.30 mg/g, with an average of 19.00 mg/g, reaching
the standard of good source rock (Table ).Comparing the organic matter abundance
of the two formations of
source rocks, the source rocks of the Itapema Formation and Picarras
Formation all meet the good source rock standard, which is consistent
with the previous research results that regard them as a whole.[13,19−21] However, the organic matter abundance characteristics
of the two formations of source rocks also have certain differences.
The organic matter abundance of the Itapema Formation shows a higher
heterogeneity than that of the Picarras Formation, which has a greater
impact on the interval. Moreover, the HI can also reveal the hydrocarbon
potential. The HI of the source rocks of the Picarras Formation is
292.1–986.0 mg/g TOC, with an average of 697.5 mg/g TOC, lower
than that of the Itapema Formation, 292.1–986.0 mg/g TOC, with
an average of 712.8 mg/g TOC. The source rocks of the Itapema Formation
have a higher hydrocarbon potential (Table ).
Organic Matter Type
The organic matter
type is an important indicator to measure the quality of organic matter
in source rocks. It determines the hydrocarbon generation potential
of organic matter in source rocks and the nature of generated hydrocarbons
(oil or gas) and directly affects the petroleum perspective of a sedimentary
basin.[6,31] In this paper, chloroform bitumen “A”
and the family compositions (saturated hydrocarbon content, saturated
hydrocarbon/aromatics value, and nonhydrocarbon + asphaltene content),
rock pyrolysis parameters (HI, S1 + S2, HI–Tmax, and HI–OI diagram), and kerogen carbon isotope value (δ13C) are used to evaluate the organic matter types of the subsalt
source rocks (Table ).
Table 3
Evaluation Indexes of the Organic
Matter Type of the Continental Source Rocks (SY/T 5735-1995)a
II
evaluation indexes
I
II1
II2
III
chloroform bitumen “A” and the family compositions
saturated hydrocarbon
content (%)
40–60
30–40
20–30
<20
saturated hydrocarbon/aromatics value
>3.0
1.6–3.0
1.0–1.6
<1.0
nonhydrocarbon + asphaltene content
(%)
20–40
40–60
60–70
70–80
rock pyrolysis parameters
HI (mg/g)
>700
350–700
150–350
<150
S1 + S2 (mg/g)
>20
6–20
2–6
<2
δ13C (‰)
<–28.0
-28.0 to −26.5
−26.5 to −25.0
>−25.0
HI—hydrogen index; δ13C—kerogen carbon isotope.
HI—hydrogen index; δ13C—kerogen carbon isotope.From the HI–Tmax and HI–OI
diagrams, it can be seen that the organic matter type of the Itapema
Formation source rock is mainly type I, followed by type II1 (Figures and 4). In addition, the kerogen carbon isotope has become
the most effective parameter to determine the organic matter type
due to little change in the thermal evolution process (generally 1–2‰,
with the maximum value not exceeding 3‰).[33] The δ13C of the Itapema Formation source
rock varies from −32.87 to −22.72‰, mainly with
light carbon isotope characteristics, indicating that the organic
matter type is mainly type I, followed by type II1 (Figure ). Besides, the indicators
of chloroform bitumen “A” and its family compositions
and rock pyrolysis parameters show that the saturated hydrocarbon
content of the Itapema Formation source rock is 38.55–59.80%,
the saturated hydrocarbon/aromatics value is 2.37–9.80, the
nonhydrocarbon + asphaltene content is 23.58–28.49%, the HI
is 287.5–998.0 mg/g, and the S1 + S2 is 2.78–50.20 mg/g (Figure ). It is comprehensively
determined that the organic matter type of the Itapema Formation source
rock is mainly type I and type II1.
Figure 3
HI–Tmax diagram of the subsalt
source rocks in the Santos Basin. HI—hydrogen index; Tmax—rock pyrolysis peak temperature.
Figure 4
HI–OI diagram of the subsalt source rocks in the
Santos
Basin. HI—hydrogen index; OI—oxygen index.
Figure 5
δ13C, HI, S1 + S2 diagrams of the subsalt source
rocks in the
Santos Basin. δ13C—kerogen carbon isotope;
HI—hydrogen index; S1 + S2—hydrocarbon generation potential.
HI–Tmax diagram of the subsalt
source rocks in the Santos Basin. HI—hydrogen index; Tmax—rock pyrolysis peak temperature.HI–OI diagram of the subsalt source rocks in the
Santos
Basin. HI—hydrogen index; OI—oxygen index.δ13C, HI, S1 + S2 diagrams of the subsalt source
rocks in the
Santos Basin. δ13C—kerogen carbon isotope;
HI—hydrogen index; S1 + S2—hydrocarbon generation potential.The diagrams of HI–Tmax and
HI–OI show that the organic matter type of the Picarras Formation
source rock is mainly type I (Figures and 4). The δ13C of the Picarras Formation source rock ranges from −31.7
to −18.5‰, and the distribution range is wider than
that of the Itapema Formation, indicating that the organic matter
type is mainly type I and type II1 (Figure ). In addition, the data of chloroform bitumen
“A” and its family compositions in the Picarras Formation
source rock are relatively lacking and have only one sample data from
one well. The saturated hydrocarbon content is 43.02%, the saturated
hydrocarbon/aromatics value is 4.0, and the nonhydrocarbon + asphaltene
content is 46.23%. Moreover, the rock pyrolysis parameter HI ranges
from 292.1 to 927.0 mg/g, and S1 + S2 varies from 2.7 to 66.3 mg/g (Figure ). It is comprehensively determined
that the organic matter type of the Picarras Formation source rock
is mainly type I and type II1, followed by type II2.Compared with the organic matter types of the two
formations of
source rocks, the organic matter types of the Itapema Formation and
Picarras Formation are mainly type I and type II1, which
is consistent with the previous research results taking them as a
whole.[13,19,21]
Organic Matter Maturity
The maturity
of source rocks represents the thermal evolution degree of the transformation
of organic matter to oil and gas, which determines the quantity and
resource potential of oil and gas generated by organic matter.[9,37] In this paper, the vitrinite reflectance (Ro), TAI value, rock pyrolysis peak temperature (Tmax), and biomarker C29-sterane the 20S/(20S
+ 20R) value are mainly used to determine the organic matter maturity
of the subsalt source rocks (Table ).
Table 4
Evaluation Indexes of the Organic
Matter Maturity of the Continental Source Rocks (SY/T 5735-1995)a
Ro—vitrinite
reflectance; Tmax—rock pyrolysis
peak temperature.The deposition time of the Itapema Formation is earlier
than that
of the Barra Velha Formation, and there is no excessive tectonic movement
during this period.[13,27,38] Therefore, it can be inferred that the Ro of the Itapema Formation source rock should be higher than that
of the Barra Velha Formation. The average value of Ro of the Barra Velha Formation is 0.60%, and the TAI is
between 2.6 and 2.7, indicating that it is in the low-mature stage
(Table ). Thus, it
is speculated that the thermal evolution of the Itapema Formation
should not be lower than the low-mature stage. In addition, the Tmax of the Itapema Formation source rock ranges
from 471.0 to 466.0 °C, and the C29-sterane 20S/(20S
+ 20R) is between 0.21 and 0.59. It is comprehensively determined
that the Itapema Formation source rock is in the low-mature to the
high-mature stage.
Table 5
Evaluation of the Organic Matter Maturity
of the Subsalt Source Rocks in the Santos Basin
well
stratum
top depth (m)
bottom depth (m)
Ro (%)
TAI
evaluation
W-1
Barra Velha Formation
5052
5055
0.60
2.6–2.7
low-mature stage
5109
5112
0.60
2.6–2.7
5226
5229
0.64
2.6–2.7
W-2
Picarras Formation
5576.6
1.05
high-mature stage
The average value of Ro of the Picarras
Formation is 1.05% (Table ), the Tmax ranges from 425.0
to 438.0 °C, and the C29-sterane 20S/(20S + 20R) varies
from 0.25 to 0.56, indicating that the Picarras Formation source rock
is in the low-mature to the high-mature stage.The maturities
of source rocks of the Itapema Formation and Picarras
Formation are in the low-mature to the high-mature stage, and the
maturity evolution spans are large. In addition, the samples are mainly
from the uplift area in the Santos Basin. The burial depth in the
depression area where the source rocks are developed is significantly
larger than that in the uplift area, and the maturity of the source
rocks in the depression area should be higher.
Horizontal Distribution Characteristics of
Dark Mudstones
The dark mudstones of the two formations are
mainly distributed in the western and eastern sags of the central
depression belt, but the thicknesses are different. The thickness
of the dark mudstones of the Itapema Formation is larger than that
of the Picarras Formation (Figures and 7). The dark mudstones
of the Picarras Formation were deposited in the early rift period
and mainly developed in the semideep lacustrine environment.[13,17,21] The scale of the lacustrine basin
was relatively small, and the thickness of the dark mudstones ranged
from 60 to 300 m. The maximum thickness of the dark mudstones reached
200 m in the western sag and 300 m in the eastern sag (Figure ). With the continuous continental
rifting, the scale of the lacustrine basin was further expanded. The
dark mudstones of the Itapema Formation were mainly developed in the
semideep and deep lacustrine environment.[13,17,21] The thickness of the dark mudstones varied
from 90 to 390 m, and the maximum thickness of the dark mudstones
reached 360 m in the western sag and 390 m in the eastern sag (Figure ).
Figure 6
Dark mudstone thickness
of the Picarras Formation in the Santos
Basin.
Figure 7
Dark mudstone thickness of the Itapema Formation in the
Santos
Basin.
Dark mudstone thickness
of the Picarras Formation in the Santos
Basin.Dark mudstone thickness of the Itapema Formation in the
Santos
Basin.
Horizontal Distribution Characteristics of
Source Rocks
The TOC of the Picarras Formation source rock
ranges from 0.4 to 4.0%, and the maximum content reaches 3.6% in the
western sag and 4.0% in the eastern sag of the central depression
belt (Figure ). Also,
the TOC of the Itapema Formation source rock varies from 0.8 to 5.6%,
and the maximum content reaches 4.4% in the western sag and 5.6% in
the eastern sag of the central depression belt (Figure ).
Figure 8
TOC of the Picarras Formation in the Santos
Basin. TOC—total
organic carbon content.
Figure 9
TOC of the Itapema Formation in the Santos Basin. TOC—total
organic carbon content.
TOC of the Picarras Formation in the Santos
Basin. TOC—total
organic carbon content.TOC of the Itapema Formation in the Santos Basin. TOC—total
organic carbon content.The thickness of the Picarras Formation source
rock ranges from
30 to 220 m, the thickest is in the eastern sag of the central depression
belt, with a maximum of 220 m, and the thickness in the western sag
reaches 160 m (Figure ). The thickness of the Itapema Formation source rock varies from
30 to 270 m, the thickest is in the eastern sag of the central depression
belt, with a maximum of 270 m, and the thickness in the western sag
reaches 210 m (Figure ).
Figure 10
Source rock thickness of the Picarras Formation in the Santos Basin.
Figure 11
Source rock thickness of the Itapema Formation in the
Santos Basin.
Source rock thickness of the Picarras Formation in the Santos Basin.Source rock thickness of the Itapema Formation in the
Santos Basin.
Discussion
The Santos Basin, Campos
Basin, and Espirito Santo Basin are located
on the southeastern coast of the Brazil and the western bank of the
South Atlantic. These three sedimentary basins can be called the Great
Campos Basin, which belongs to the passive continental margin basin
on the eastern coast of Brazil. They have similar tectonic sedimentary
backgrounds. The main source rocks are the lacustrine mudstones of
the Lower Cretaceous in the subsalt rift period.[39,40] Among them, the lacustrine mudstones of the Lower Cretaceous Lagoa
Feia Group in the Campos Basin have high organic matter abundance,
with TOC ranging from 0.7 to 8.0%, with an average of 2.4%. The S1 + S2 varies from
3.1 to 90.0 mg/g, with an average of 20.6 mg/g,[22] which meets the best source rock standard and is better
than the subsalt source rocks in the Santos Basin. The organic matter
types are mainly type I and type II1, which have the same
characteristics as the subsalt source rocks in the Santos Basin. The
maturity is in the immature to the low-mature stage,[22] which is lower than that of the Santos Basin. The thickness
of source rocks ranges from 200 to 300 m,[40] which is thicker than the subsalt source rocks in Santos Basin.
However, affected by the scale and structural pattern of the rift
basin, the distribution area of source rocks is much smaller than
that in Santos Basin.[22,40] Moreover, the lacustrine mudstones
of the Lower Cretaceous in the Espirito Santo Basin also have high
organic matter abundance, where the TOC is higher than 4.0%, and the
HI is generally higher than 400 mg/g. The organic matter types are
mainly type I and type II. The Ro ranges
from 0.6 to 1.4%, indicating that the maturity is in the low-mature
to the high-mature stage.[41,42] The distribution area
of source rocks is smaller than that of the Santos Basin and Campos
Basin.[22,34] On the whole, the subsalt source rocks of
the Itapema Formation and Picarras Formation in the Santos Basin have
a good quality, large thickness, and wide distribution area, indicating
that the source rocks have great hydrocarbon generation potential,
which is superior to the subsalt source rocks in the Campos Basin
and Espirito Santo Basin.In addition, the subsalt source rocks
in the Santos Basin are most
developed in the eastern and western sags of the central depression
belt. The maximum TOC in the eastern sag reaches 4.0% in the Picarras
Formation, 5.6% in the Itapema Formation, and the maximum thickness
of the source rocks reaches 220 m in the Picarras Formation and 270
m in the Itapema Formation. The maximum TOC in the western sag reaches
3.6% in the Picarras Formation and 4.4% in the Itapema Formation,
and the maximum thickness of the source rocks reaches 160 m in the
Picarras Formation and 210 m in the Itapema Formation. The eastern
sag and western sag of the central depression belt become the high-quality
hydrocarbon generation centers. Furthermore, the source control theory
emphasizes that the distribution of oil and gas fields is around the
hydrocarbon generation centers and is strictly controlled by them.
This theory is an important theory to guide petroleum exploration
in continental petroliferous basins. Therefore, the uplift areas around
the eastern sag and the western sag of the central depression belt
of the Santos basin are favorable areas for further oil and gas exploration.
Conclusions
The characteristics of source rocks
of the subsalt Itapema Formation and Picarras Formation in the Santos
Basin are similar while characterized by a high organic matter abundance.
Also, the organic matter types are mainly type I and II1. The maturities are in the low-mature to the high-mature stage.
The source rocks are widely developed on the plane and have a large
thickness. The source rocks meet the standard of good source rocks.
The TOC of the source rocks of the Picarras Formation ranges from
0.4 to 4.0%, much lower than that of the source rocks of the Itapema
Formation, 0.8–5.6%. Moreover, the HI average value of the
source rocks of the Itapema Formation is 712.8 mg/g TOC, higher than
that of the Picarras Formation, 697.5 mg/g TOC, both revealing a great
hydrocarbon potential. The quality of source rocks of the Itapema
Formation is better than that of the Picarras Formation.The subsalt source rocks in the Santos
Basin have a good quality, large thickness, and wide distribution
area and have a great hydrocarbon generation potential, which is superior
to the subsalt source rocks in the similar Campos Basin and Espirito
Santo Basin. The eastern sag and western sag of the central depression
belt are the high-quality hydrocarbon generation centers, which have
the material basis for the formation of large and medium-sized oil
and gas fields. The surrounding uplift areas are favorable areas for
further oil and gas exploration.
Figure 1
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Figure 4
Figure 5
Figure 6
Figure 7
Figure 8
Figure 9
Figure 10
Figure 11