Abstract
Keywords
Introduction
Passive continental margin basins have been confirmed to have the most abundant oil and gas resources, 304 out of 877 giant oil and gas fields with 2P recoverable reserves of greater than 500 MMboe in the world are located in passive continental margin tectonic setting (Mann et al., 2003). Recently, the advancements in deepwater geological theories and exploration technologies have resulted in the significant increase in the oil and gas fields’ discoveries in deepwater passive continental margin basins. The typical example is the South Atlantic. Along its two coasts, 25 passive continental margin basins (Figure 1) have been explored, 80% basins are in deepwater setting； currently, a total of 111 giant oil and gas fields with recoverable reserve of 255,878 MMboe have been discovered along the South Atlantic Margins (Figure 1), accounting for more than 70% of the total discovered oil and gas equivalents in the passive continental margins all over the world. Several scholars have studied the tectonic evolution of hydrocarbon-bearing systems and the patterns of hydrocarbon accumulation along two coasts of the South Atlantic using analogy method (Blaich et al., 2011; Edwards and Santogrossi, 2000; Katz and Mello, 2000; Schiefelbein et al., 2000; Szatmari, 2000). However, most of these previous studies mainly focused on individual basins and the stratigraphy and reservoirs of two sides of the Atlantic conjugate margins were simply correlated based on limited seismic and drilling data. This paper systematically studies the formation and evolution of the prototype basins and their paleogeography in the conjugated passive continental margin basins along the coasts of the South Atlantic based on the plate tectonic evolution and paleogeographic reconstruction, basin filling styles in each segment are characterized using updated regional geology data, seismic reflection data, recent drilling data, and new oil and gas discoveries. The reservoir distribution in time and space is revealed in this region. Furthermore, the paper investigates the patterns of the hydrocarbon accumulation for the giant oil and gas fields and identifies the favorable plays in these basins in different parts of the South Atlantic conjugate passive continental margin basins. This is instrumental in understanding the petroleum geology on regional scale, geologic control on the oil and gas accumulation, and future petroleum exploration potentials in different areas in the South Atlantic conjugate continental margin basins.
The distribution of passive continental margin basins and giant oil and gas fields in the South Atlantic margins. The northern basin highlighted in white color represent the sag-type basin, the middle basins highlighted in brown color represent the salty rift-sag-type basin, and the south basins highlighted in pink color represent the rift-type basin. Adapted from Bradley (2008), Rüpke et al. (2010), and Torsvik et al. (2009).
Data and methods
The data of this paper consist of a large number of compiled published documents and geologic knowledge summary based on the data from many commercial databases and interpretation of latest available 2D seismic data. This paper firstly studied the paleogeography of different evolutionary stages and the basin filling characteristics of the South Atlantic prototype passive continental margin basins. According to characteristics of the prototype basin and the sedimentary filling of the main target formations, this article then classified the basin filling types for the different segments of the South Atlantic passive continental margin basins. Hydrocarbon accumulation and the play patterns in this region were lastly summarized according to the distribution of different types of source rocks and reservoirs and analysis of the petroleum system elements of the large discovered oil and gas fields.
Geologic setting
The South Atlantic conjugate passive continental margin basins from south to north include Falkland Plateau, Colorado, Punta Del Este, Santos, Campos, Potiguar, and Guyana basins in the west side and Outeniqua, Southwest African Coastal, Kwanza, Lower Congo, Gabon, and Liberia basins in the east side. These basins experienced multiple tectonic evolution stages from Mesozoic to Cenozoic. This region was located in the Gondwana continent in the pre-rift stage in Early Mesozoic. During the Early Cretaceous, affected by the Tristan plumes, rifting started to develop from south to north. Extension and stretching were also initiated from the southern end of the west Gondwana continent, forming the nearly N-S oriented rift basins. In the north, many nearly E-W oriented strike-slip faults were formed with strike-slip faulted basins. The strata of prototype basins can be divided into three segments: intracontinental rifting, transitional intercontinental rifting, and drifting passive continental margin stage. Intracontinental rift sequence is lacustrine filling in the Early Cretaceous Berriasian period, transitional intercontinental rift sequence is lacustrine and marine sediments filling in the Early Cretaceous Aptian, and the drifting passive continental margin stage is characterized by the marine sediment filling since the Early Cretaceous Albian.
Basin evolution
The conjugate basins along the coasts of the South Atlantic were formed by the rifting of West Gondwana and the formation of the South Atlantic Ocean during Meso-Cenozoic period (Bally and Snelson, 1980; Bradley, 2008; Torsvik et al., 2009; Wegener, 1915). The prototype basins underwent early intracontinental rifting with lacustrine sediment filling (the Early Cretaceous Berriasian stage), transitional intercontinental rifting with lacustrine and marine sediments filling (the Early Cretaceous Aptian stage), and a drifting passive continental margin stage with marine sediment filling (since the Early Cretaceous Albian stage). These basins are generally filled with lacustrine sediments in Berriasian stage, lacustrine, lagoonal and marine sediments in Aptian to Albian stages, and marine sediments since Cenomanian from Cretaceous to Cenozoic (Figure 2). Controlled by the opening stage of the South Atlantic Ocean and the paleogeomorphic environment, the sedimentary environments can be subdivided into three segments from south to north by two major transform fault zones, the Rio Grande Fracture Zone and the Ascension Fracture Zone (Figure 2; Moulin et al., 2010).
Reconstruction of the prototype basins and paleogeography along the South Atlantic margins through time. The prototype basins underwent early intracontinental rifting with lacustrine sediment filling (the Early Cretaceous Berriasian stage), transitional intercontinental rifting with lacustrine and marine sediments filling (the Early Cretaceous Aptian stage) and a drifting passive continental margin stage with marine sediment filling (since the Early Cretaceous Albian stage).
Early Cretaceous Berriasian stage
In the Early Cretaceous Berriasian stage, the three segments along the two coasts are intracontinental rift basins dominated by continental depositional systems in the rifted stage and gradually transitioned to marine depositional systems from the southern end of the segment.
During the Early Cretaceous, extension and stretching initiated from the southern end of the west Gondwana continent, namely, the present west coast of South Africa. Affected by the Tristan plumes, rifting developed from south to north and was controlled by the nearly N-S oriented major faults; finally, a nearly N-S oriented long rift valley was formed, together with many nearly E-W oriented strike-slip faults, which isolated many secondary faulted depressions (Brownfield and Charpentier, 2006; Torsvik et al., 2009). The rift was filled with fluvial to lacustrine sediments. Drilling data and outcrops have confirmed the rifted strata were extensively developed in today's continental shelf and continental slope on both shores of the South Atlantic. Later, due to another intense extension during the Balmain stage, the southern part of the southern segment was then connected with the Indian Ocean and started to receive marine sediments, while the northern part was still receiving continental sediments, and the middle part subsided rapidly and deep-lacustrine mudstone sediments were accumulated in this segment. In the northern segment, the E-W extension was converted to the nearly E-W oriented São Paulo and Romanche transform faults and many narrow, deep, and small pull-apart rifted lacustrine basins developed (Rüpke et al., 2010).
Early Cretaceous Aptian stage
In the Early Cretaceous Aptian stage, the three segments on the two sides were transitional intercontinental rift basins. The southern segment was composed of clastic marine sediments. The middle segment was mainly characterized by the development of the lacustrine carbonates and salt (Strozyk et al., 2017; Thompson et al., 2015). The northern segment was dominated by clastic lacustrine rocks.
In the early to middle Aptian stage, with the narrow initial oceanic crust forming from south to north and massively incursion of seawater from the Indian Ocean to the south, a series of transgressive glutenite bodies formed (Torsvik et al., 2009), indicating the end of the early rift stage and the start of the continental rift period. Accompanied by intense magmatic activities, the Rio Grande Rise-Walvis Ridge volcanic highland near today’s middle segment formed in nearly an E-W direction, which provided a lateral barrier, and restricted the seawater circulation in the narrow nearly N-S oriented depression and formed a local lagoonal environment. In addition, due to the appearance of a narrow oceanic crust, the geothermal gradient clearly increased, the boundary fault blocks on both sides of the intercontinental rift tilted with thermal expansion. Without a sufficient supply of clastic rocks and with a location close to the equator, carbonate rocks developed with an extensive distribution (Torsvik et al., 2009). In the northern segment, controlled by the nearly E-W oriented trans-extensional fault belt, the rift system was relatively small and closed, with lacustrine clastic sediments. Connecting to the Indian Ocean, the southern segment had well circulated seawater and received shallow marine clastic sediments (Rüpke et al., 2010).
In the late Aptian stage, as evaporation continued, evaporites developed in the basins in the middle segment (Torsvik et al., 2009). The evaporites are composed of salt and anhydrite rocks, dominated by salt, which covers a total area up to 1 million km2 and are over 4000-m thick at a maximum (Kukla et al., 2018). Due to the limited development of the pull-apart rift in the basins in the northern segment, the lacustrine clastic sediments remained dominant, without seawater incursion from the south. The basins on the coasts of the southern segment remained marine environment with clastic sediments.
Early Cretaceous Albian stage
Since the Early Cretaceous Albian stage, the three segments on the two margins developed passive continental margin basins during the drift period, all of which received marine sediments, but the sedimentary thicknesses vary (Rüpke et al., 2010). From the early Albian stage, the seafloor with oceanic crust continued to expand, driving lithosphere movement toward both coasts and forming a fully opened ocean. The oceanic crust on both sides tended to become colder and subsided symmetrically from the two coasts to the mid-ocean ridge, and finally, in the continental crust and continent to ocean zone, passive continental margin sedimentary wedges formed in this drift stage. At that time, a large amount of transgressive seawater ended the deposition of evaporites. With the rise and fall of global sea level, from the bottom to the top, the drift period underwent a major transgression and regression cycle, resulting in a lower transgressive system and an upper regressive system.
The transgressive system (Albian to Maastrichtian) consisted of early shallow to late deep marine sediments. The southern segment was dominated by marine clastic sediments. The middle segment was deposited with shallow carbonate rocks early and clastic sediments lately. The South American plate moved southward while it moves westward along the transform fault, which makes the northern segment connected with the northern mid-Atlantic Ocean. The marine clastic sediments were deposited in the northern segment during this period. Maximum marine flooding occurred from the Cenomanian stage to the Turonian stage, which resulted in the forming of organic-rich black shale in an anoxic environment in the middle and northern segments. It is worth mentioning that the gravity-flow fans occur mostly in the northern segment. Controlled by the high-angle transform faults, the passive continental margins in the northern segment had a narrow shelf and steep continental slope, and lots of sand was transported to the shelf edge by rivers. The flood and earthquake triggered the sands to slide down the steeper slope and formed gravity-flow (mostly turbidite) sedimentary systems. The slope was eroded vertically and laterally, often creating parallel submarine canyons or recharge channels on the shelves and upper slopes. Once the speed of these gravity current was slowed down, sediments were settled out to form submarine fan groups and other gravity flow sedimentary systems on the lower slope and continental rise (abyssal plain).
Since the Paleocene, the fall of global sea level and sufficient sediment sources from two sides of the margins result in the prograding deltas and deepwater gravity-flow (mainly turbidite) sedimentary systems (Figure 2). The examples are constructive large-scale Niger, Foz do Amazonas and Pelotas deltas.
Differences in basin configuration style from southern segment to northern segment
A comprehensive comparison of basin configuration style is based on the interpretation of seismic and geologic data that shows different structures in the southern, middle, and northern segments. The dominant systems of the prototype phase divide the basins into three types: rift-type basins in the southern segment, salty rift-sag-type basins in the middle segment, and sag-type basins in the northern segment (Figure 1). The geothermal gradients of the rift and the sag systems (including the delta system) are approximately 4.0°C/100 m and 3.0°C/100 m on average, respectively (Wen et al., 2016). If their thicknesses are more than 3000 and 4000 m, respectively, the lower source rocks have entered the stage of peak hydrocarbon generation and expulsion, which provides the resource for forming giant oil and gas fields. Therefore, these two thicknesses are regarded as the general standards for the superior prototype phase. These two thickness standards will change slightly in basins with different paleogeothermal gradients and organic matter types.
Rift-type basins in the southern segment
The southern rift-type passive continental margin basin shows a lower rift and upper sag structure, typically with a thicker underlying rift system (generally more than 3000 m in the depocenter) and a thin overlying sag system (generally less than 4000 m in the depocenter; Figure 3). Seismic data confirmed that the southern basins, except for the Pelotas Basin with a large-scale delta, are all rift-type basins (Figure 1). The underlying rift system is extensively developed, and the tensional faults control the structural pattern with alternate horsts and grabens. Drilling data revealed volcanic rocks in the lower part and continental, alluvial fan, and lacustrine sedimentary systems in the upper part of the rift (Conti et al., 2017, Contreras et al., 2010; Franke et al., 2007) as well as a significant seaward dipping reflectors phenomenon. The overlying sag system shows a clear wedge feature, where faults are less developed, and contacts the underlying strata with a regional angular unconformity. The bottom contains a group of continuous strong reflections, tens of meters to a hundred meters thick, composed of conglomerate deposits during the intercontinental rift period. The lower part of the sag system displays weak-amplitude to blank seismic reflections and is composed of deepwater fine-grained sediments during the transgression. The middle and upper strata display multiple sets of small-scale wedge-shape seismic reflections from the slope to the abyssal plain and are composed of small-scale delta and gravity-flow sedimentary systems.
Seismic reflection showing the rift-type passive continental margin basins in the southern segment of the South Atlantic. The W-E oriented AA′ seismic section is located in the Argentina Colorado basin and W-E oriented BB′ seismic section is located in the South Africa Southwest African Coast basin. The location of these two seismic sections is shown in Figure 1.
Salty rift-sag-type basins in the middle segment
The salty rift-sag-type basins have an underlying rift system similar to that of the rift-type basins in the southern segment, but a different overlying sag system. The upper sag system has distinct characteristics: (1) the whole overlying sag system is thick, more than 5000 m in the depocenter; (2) in the lower transitional member, lagoon carbonate, and evaporate developed from bottom to top (Chaboureau et al., 2013). The former is mainly distributed in today's Santos, Campos, Kwanzaa, and Lower Congo basins, more than 1000 m at the thickest location. The latter is widely distributed in all the basins in the middle segment, covering an area of 1 million km2 and becoming thicker toward the ocean, including over 4000 m at the thickest location; and (3) the salt structure is developed and the strong post-salt Cenozoic wedge/lenticular reflection structures represent a deepwater sedimentary system of many stages at a larger scale. This is consistent with the fall of the global sea level at that time (Figure 4).
Seismic reflection showing the salty-rift-sag-type passive margin basins in the middle segment of the South Atlantic margins. W-E oriented CC′ seismic section is located in the Brazil Santos basin, W-E oriented DD′ seismic section is located in the Congo Low Congo basin. The location of these seismic sections is shown in Figure 1.
Sag-type basins with thick post-rift sediments in the northern segment
The unique structure of the sag-type passive continental margin basins in the northern segment (Figure 5) is characterized by the following features: (1) the rift system is small comparing to the post-rift system and only occurs in limited basins, such as the Saira Basin, which is because the early rift was a narrow strike-slip pull-apart rift basin controlled by steep faults; (2) the sag system is thick (>5000 m) and the gravity-flow sand bodies are well developed since the sediments can be easily transported down from the narrow shelf and steep slope. Additionally, the Niger and Foz do Amazonas water systems developed delta basins, to be described later.
Seismic reflection showing the sag-type passive margin basins in the northern segment of the South Atlantic margins. S-N oriented EE′ seismic section is located in the Guyana Guyana basin and S-N oriented FF′ seismic section is located in the Cote d`Ivoire Cote d`Ivoire basin. The location of these seismic sections is shown in Figure 1.
Hydrocarbon accumulation and distribution of giant oil and gas fields
Based on differences in the basin evolution and configuration styles and sedimentary systems of the three types of basins in the three segments and the characteristics of the discovered giant oil and gas fields, the hydrocarbon accumulation and distribution patterns of the giant oil and gas fields were investigated for the basins in the three segments.
Giant structural-stratigraphic oil and gas fields in the southern rift-type basins
The southern rift-type passive margin basins developed a giant structural-stratigraphic oil and gas field in the rift stage (Figure 6). In this type of basins, the sedimentary systems that developed in the sag stage are less than 4000-m thick, and the geothermal gradient is low (generally less than 3.0°C/100 m). The marine shale has not entered the stage of peak hydrocarbon generation and expulsion and are not effective source rocks, but this marine shale can only act as a regional caprock. The rift system has a high geothermal gradient (average 4.0°C/100 m) and has an overlying sag system. The northern Barremian lacustrine shale and the southern marine shale in the rift system have entered the stage of peak hydrocarbon generation and expulsion, providing an effective hydrocarbon source for the formation of giant oil and gas fields. Currently, the giant offshore KUDU gas field in Southwest Africa has proven that the source rock is the Barremian lacustrine shale (Mello et al., 2012) with an average TOC of 10%, a hydrogen index up to 600 HC/gTOC, and a hydrocarbon potential from 9–11 to a maximum of 57 mg HC/g. Both the Logigo and the Sea Lion gas fields in the North Falkland Basin off the coast of South America have Barremian marine shale as source rock. These source rocks entered hydrocarbon-generating windows at the end of the Paleogene (Bushnell et al., 2000). The hydrocarbon migrated vertically along faults to the gravity-flow or transgressive sandstones at the top of the rift system and finally accumulated as giant structural-stratigraphic plays such as Kudu and Sea Lion.
The sedimentary filling and hydrocarbon accumulation model show the distribution of reservoir giant oil and gas fields in the rift-type passive margin basins in the southern segment of the South Atlantic margins. Kudu giant gas field is located in this segment and its discovered plays are structural-stratigraphic and mainly distributed in the rift system. Adapted from Mello et al. (2012).
Giant oil and gas fields producing from pre-salt carbonate rock and post-salt gravity-flow fan sandstone in the middle salty rift-sag-type basins
The salty rift-sag-type basins in the middle segment contain giant oil and gas fields producing from pre-salt lacustrine carbonate and post-salt marine gravity-flow fan sandstone reservoirs (Figure 7). A total of 47 giant oil and gas fields have been discovered, of which 26 are located in the Santos, Campos and Espirito Santo Basins off the east coast of Brazil, and 21 in the Lower Congo, Kwanzaa and Gabon Basins. The underlying carbonate rocks are primary reservoirs in the pre-salt fields, and the gravity-flow sandstones provide primary reservoirs in the post-salt fields.
The schematic diagram shows the hydrocarbon accumulation of giant oil and gas fields in the salty rift-sag-type passive margin basins in the middle segment of the South Atlantic margins. The deeper pink halite and pink salt divided the strata into two parts and the discovered plays are classified into two types. One type is pre-salt carbonate play distributed in the rift system, and the other is post-salt turbidite sands distributed in the sag system. Adapted from Mello et al. (2012).
The formation conditions of the giant pre-salt oil and gas fields are very similar. This is because the basins on the two conjugate margins were in a similar environment ranging from a narrow and closed intracontinental rift lake basin to an intercontinental lagoon in one basin. The main source rocks are lacustrine shales formed during the intracontinental rift stage (Beglinger et al., 2012). In the Campos Basin, the source rocks were proven to be Lagoa Feia black lacustrine calcareous shales deposited during the Early Cretaceous rifting period (Guardado et al., 2000), with type I kerogen, a TOC from 2% to 6%, a hydrogen index as high as 900 mgHC/gTOC, and a hydrocarbon potential of more than 10 mg HC/g. The shales were well developed in many grabens in the two conjugate margins, generally with thickness of 100–400 m (Harris, 2000). The 1D modeling study reveals the critical moments for the maturation of source rocks in South Atlantic basins, e.g. Campos basin span from Early to Late Cretaceous (Marcano et al., 2013). The source rocks reached peak oil generation at approximately the Miocene, and most are still in the oil window under the influence of heat insulation by overlying thick salt rock. If salt windows were undeveloped, hydrocarbon would migrate vertically through the rift system and then laterally along the transgressive unconformity to the overlying Aptian carbonate rocks and accumulate in the anticlinal structural traps. These anticlines are usually paleo-highs between rifts or isolated carbonate platforms on horsts, where two types of high-quality reservoirs were developed, ostracod and microbial carbonates. Currently, nine giant oil and gas fields are located in the Santos Basin and three in the Campos Basin offshore Brazil, and three in the Kwanzaa Basin in West Africa have been found to produce from the pre-salt carbonate reservoirs. Additionally, there was another field discovered in the Gabon Basin. The regional caprocks are very thick (100–2500 m) and widely distributed salt rocks (approximately 1 million km2) directly overlie the carbonate or conglomeratic sandstone.
In the post-salt oil and gas fields on the two conjugate margins, the reservoirs are primary gravity flow fan sandstone and a small amount of carbonate rocks. The cap rocks are all transgressive shales, but the source rocks are not exactly the same. As the post-salt strata in the depression stage on the two margins belonged to two separate basins and were affected by the different sediment supplies, the depositional thicknesses varied greatly between the different basins of the two margins and even the different units in the same basin, thus affecting the distribution of effective source rocks. In the drift stage, wedge-shaped sags developed, and the zone below the slope break was deposited in the thickest units, generally more than 4000 m. The Cenomanian-Turonian transgressive shale in the lower section has type II kerogen and a TOC of 2–5%, with a maximum of 10%, and it experienced peak hydrocarbon generation and expulsion (Harris, 2000), which provides the hydrocarbon source for giant oil and gas fields. In the Lower Congo Basin, with abundant sediment source transported by the Congo River, sediments were deposited up to a maximum of 6000 m since the Oligocene. Besides the lower Cenomanian-Turonian marine shale, the local Oligocene marine shales in the upper section also entered the hydrocarbon generation threshold, with primary type II kerogen and a TOC of up to 14.4%, and providing high-quality source rock conditions. However, thin systems deposited during the sag period may also provide good conditions for the development of giant oil and gas fields. In the Campos Basin, for example, due to later strong activities of the mobile salt, hydrocarbons migrated upward to the marine gravity-flow sandstone deposited during the drift period through salt windows. The hydrocarbon might migrate a long or short distance in the vertical direction, the shortest to the post-salt Lower Cretaceous strata (the Albian stage), and the longest to the Miocene strata. Since salt tectonics occurred before and after the formation of gravity flow sandstones, two types of traps were formed: stratigraphic traps of submarine fan above salt and composite traps with lithological pinch-out and fault components. Since the gravity flow sandstones were formed in many stages and the faults affected the migration and sealing conditions, a giant oil–gas field usually has multiple oil–water contacts and the relationship between oil and water is extremely complicated.
Giant oil and gas fields producing from gravity-flow fan in the northern sag-type basins
The sag-type basins in the northern segment developed giant oil and gas fields with reservoirs of marine gravity-flow fan or turbidite sandstone formed in drift stage (Figure 8). The lower pull-apart rift is narrow, deep and distributed over a limited area. The upper sag system formed during the drift period is very thick (greater than 5000 m) and mainly consists of clastic sediments, and the gravity flow sandstones are widely developed.
The schematic diagram showing the hydrocarbon accumulation of giant oil and gas fields in the sag-type passive margin basins in the northern segment of the South Atlantic margins. Controlled by the tectonic evolution and narrow shelf, the thick sediments are filled in the sag system and the discovered plays are distributed in the turbidite sands in the sag system.
The Côte d’Ivoire Basin is used as an example to illustrate the characteristics of this kind of large oil and gas fields. Before 2007, there were 39 oil and gas fields discovered in the Côte d’Ivoire Basin, with small- and medium-sized reserves. However, with the increasing drilling depth, the scale of the oilfields was also found to be larger. In May 2007, Well M-1, in a maximum water depth of 1322 m, discovered the largest Jubilee oilfield (1166 MMbbl), where the Turonian composite gravity-flow sandstones are reservoirs with an effective thickness of 97.25 m, a single layer thickness of 2–36 m, and an average porosity of 22%. In May 2010, Well Teak-1, drilled in the northeastern high of the Jubilee oilfield, discovered a gravity-flow sandstone play with a total reservoir thickness of 71.7 m. The well drilled into Turonian gravity-flow fan reservoirs and Campanian gravity-flow sandstone reservoirs. In the drift stage, the deepwater marine system was deposited quickly and was very thick. The lower Cenomanian-Turonian marine shale deposited during the global ocean anoxic event has now entered the peak period of hydrocarbon generation and expulsion, and hydrocarbons can migrate to and accumulate in the stratigraphic gravity-flow sandstone traps with the marine shales as both source rock and cap rock, or migrate upwards through faults or unconformities to the shallow gravity-flow fan bodies. Seismic data showed that the entire sag system developed multistage skirt-shaped submarine fans from the bottom to the top in the base of the slope. Following the discovery of the largest Turonian Jubilee oilfield in the Tano Subbasin in 2007, more discoveries were made in the deepwater Upper Cretaceous gravity-flow fans in the Liberia Basin to the north and the Guyana Basin on the opposite margin. The deepwater Liza discovery in the Guyana Basin provides recoverable reserves of 12 × 108 bbl. All these have proven that the gravity-flow fans in the sag-type passive continental margin basins in the northern segment are the most favorable reservoirs.
Differences in the petroleum system and hydrocarbon accumulation in three types of basins
The hydrocarbon accumulation patterns were summarized according to the structural style, sedimentary fill architecture, and petroleum system elements in three types of basins in three segments. In the southern rift-type basins, the hydrocarbons are mainly accumulated in the rift system, the sandstones at the top of the rift system are the main reservoirs, with primary sources from the rift system and its overlying marine shale formed in the drift stage acts as high-quality regional caprock. For the salty rift-sag-type basins in the middle segment, the hydrocarbon systems are separated by the thick salt, in the pre-salt, the hydrocarbons sourced from the source rock in the rift system were trapped in the early transitional lagoon carbonate and sealed in the overlying salt; above the salt, the hydrocarbons are sourced from both the source rock in the rift system and its overlying post-salt marine shale in the sag system. These hydrocarbons are accumulated in the marine gravity-flow sandstones in the sag system. In the northern sag-type basins, the hydrocarbons sourced from the marine shale in the post-rift sag system are mainly accumulated in the gravity-flow reservoirs in the same sag sequence. The gravity fan reservoir is in a shirt shape at the base of slope.
Conclusions
The passive continental margin basins on the two margins of the South Atlantic are conjugate in nature, associated with the separation of South America and Africa and the opening of the South Atlantic Ocean. All the basins experienced early intracontinental rifting (the Early Cretaceous Berriasian stage, 129–125 Ma), transitional intercontinental rifting (the Early Cretaceous Aptian stage, 125–113 Ma), and drifting passive continental margin stage (since the Early Cretaceous Albian stage, 113 Ma). Based on the basin evolution, structural differences, sedimentary characteristics, and basin configuration styles, the basins in the South Atlantic margins can be divided into three types of passive continental margin basins in the three segments along the margins. The southern segment is characterized by the rift-type basins with well-developed rift systems. The middle segment consists of transitional salty rift-sag-type basins with both rift and sag systems developed. The northern segment contains sag-type basins with well-developed sag systems and less-developed rift. The structural and sedimentary filling differences in the three types of basins in three segments determine that the hydrocarbon accumulation patterns of the giant oil and gas fields are clearly different. In the southern rift-type basins, oil and gas are accumulated in giant structural-stratigraphic reservoirs at the top of the rift sequence. The primary sources are from the rift system and the caprock is from the upper marine shale formed in the drift stage. In the middle salty rift-sag-type basins, if salt windows were not developed, the hydrocarbons from the source rock in the rift system were sealed in the early transitional lagoon carbonate by the overlying salt; above the salt, the hydrocarbons are sourced from both the post-salt marine shale in the sag system and its underlying lacustrine source rock in the rift system. Some hydrocarbons generated from the rift source rocks are accumulated in the pre-salt carbonate in the rift sequence and some vertically migrated up via faults and then through the salt window, and finally accumulated in marine gravity-flow sandstones in the sag system. In the northern sag-type basins, the hydrocarbons sourced from the marine shale in the sag system directly charged the composite gravity-flow fan reservoirs distributed in a shirt shape at the base of slope and led to the giant oil and gas accumulations in the drift stage.