Introduction

Deepwater turbidite systems serve as chronostratigraphic archives of continental margin evolution and represent primary targets for hydrocarbon exploration in deepwater passive margin settings (Berg 1982; Anderson et al. 2000; Dribus 2014; Kelly and Doust 2016). The stratigraphic architecture and spatial distribution of these gravity-driven sedimentary bodies are governed by a complex interplay of tectonic subsidence, sediment supply, structural inheritance, and relative sea-level fluctuations (Shanmugam 2021). In frontier basins, as the basins in Brazilian Equatorial Margin (BEM), where direct well calibration is scarce, the identification of turbidites relies heavily on characteristic seismic facies, such as subhorizontal and subparallel reflector sets exhibiting low frequency, high amplitude, lens-shaped and strong lateral continuity (Armentrout et al. 1991; Normark et al. 1993). Beyond delineating the fundamental elements of a petroleum system, evaluating the potential presence and migration pathways of hydrocarbons is essential to accurately define prospective targets.

Within the structural framework of the South Atlantic, the economic viability of hydrocarbon accumulations in deepwater turbidite complexes has been definitively established. Major discoveries in the Brazilian eastern margin (e.g., Campos and Santos basins) and the equatorial African margins (Ivory Coast and Ghana) underscore this potential (Mendonça et al. 2003; Bastos and Prates 2017; Zalán et al. 2024). For instance, the Roncador field in the Campos Basin holds estimated reserves of 9 billion barrels, with Late Cretaceous and Paleogene turbidite plays constituting the largest oil-producing reservoirs chronostratigraphically above the Brazilian pre-salt section (Mendonça et al. 2003; Bastos and Prates 2017). Furthermore, the Guyana-Suriname Basin, located along the northwestern equatorial margin of South America, hosts recoverable reserves exceeding 8 billion barrels in Late Cretaceous turbidites (Wong and Geuns 2019). The tectono-depositional contexts of these BEM conjugate margins correlate closely not only in their stratigraphic architecture but also in key petroleum system elements, including source rock distribution, burial history, and trapping mechanisms (Bryant et al. 2012; Alleyne et al. 2018). Consequently, these deposits are presented as regional-scale analogues to the turbidite systems identified in the BEM by this study.

The central sector of the BEM, encompassing the Pará-Maranhão, Barreirinhas, and Ceará basins, is conjugate to the basins of the Gulf of Guinea and is currently regarded as a high-potential frontier for hydrocarbon exploration (Brownfield and Charpentier 2006; Pellegrini and Severiano Ribeiro 2018). Although previous regional assessments have posited an active petroleum system with established generation and migration pathways across the BEM (Delabrida et al. 2026), the detailed spatial configuration of deepwater turbidite complexes and the diagnostic evaluation of associated fluid-flow phenomena remain under-constrained. A challenge in appraising these deepwater systems utilizing sparse 2D seismic is the reliable differentiation of fluid-related amplitude anomalies, such as gas chimneys and direct hydrocarbon indicators (DHIs), from lithological contrasts or seismic processing artifacts. Therefore, the delineation of potential fluid escape structures must be strictly regarded as a mechanism for mitigating geological uncertainty, rather than as unequivocal evidence of hydrocarbon accumulations.

In the present study, a comprehensive 2D seismic dataset and well logs were analyzed with the aim of identifying and mapping deepwater turbidite systems and correlated DHIs in the central sector of the BEM. Classical seismic attributes (e.g., energy, instantaneous amplitude and frequency, pseudorelief, etc.), in addition to a special frequency attribute, were applied to the seismic profiles to enhance the seismic responses of the turbidite bodies and DHIs. Based on the seismic detection criteria for turbidite sequences (e.g., Berg 1982; Mitchum 1985; Tinterri et al. 2020; Fisher et al. 2021), these features were characterized by subhorizontal and subparallel reflector sets exhibiting low frequency, high amplitude, and strong lateral continuity.

To advance beyond purely descriptive seismic mapping, this study investigates the hypothesis that deepwater gravity flows in the central sector of the BEM were structurally confined and preferentially routed along slope-parallel structural corridors, and that the associated spatial distribution of amplitude and frequency anomalies reflects localized fluid-migration pathways rather than seismic processing artifacts. Accordingly, our study seeks to elucidate the principal structural and stratigraphic controls governing the spatial distribution, transport direction, and thickness variations of deepwater turbidite reservoirs within this frontier exploration sector. Furthermore, a multi-attribute seismic analysis is employed to discriminate interpreted seismic expressions of fluid migration, including paleo-pockmarks, gas chimneys, flat spots, and bright spots, from non-fluid-related seismic artifacts. This integrated approach provides a more robust assessment of geological uncertainty and risk, while enhancing the characterization and interpretation of potential hydrocarbon-bearing systems within the study area.

An important contribution of this study is the application of a novel suite of seismic attributes designed to enhance frequency components associated with turbidites and DHIs, improving the visualization of reservoir bodies and their enclosing shale units. Ultimately, by demonstrating consistency with successful hydrocarbon plays identified along the conjugate Equatorial Margins, this research highlights new exploration opportunities in the central BEM, characterized by reduced exploratory risk and significant economic potential.

Geological setting

Tectonostratigraphic framework

The BEM represents an oblique transform passive continental margin and was generated during the fragmentation of the supercontinent Gondwana and the opening of the Equatorial Atlantic in the Lower Cretaceous (145.0–100.5 Ma) (Matos 2000; de Castro et al. 2024; Cohen et al. 2025). Continental rupture and oceanic accretion were controlled by a right-stepping system of ENE–WSW oriented dextral strike-slip movements along extensive oceanic fracture zones, separating the Equatorial Atlantic margins in pairs of transform and divergent margin segments (Fig. 1) (Tavares et al. 2020; Scarselli et al. 2020; de Castro et al. 2022). The entire BEM was also affected by chains of submarine seamounts and exhibits a complex lithospheric structure characterized by a narrow and abrupt Ocean-Continent Transition (OCT). This transition is marked by significant lithospheric thinning, and the presence of high-angle transform faults that juxtapose thick continental blocks against younger, thinner oceanic crust (Matos 2000). The central sector of the BEM comprises the Pará-Maranhão Basin (divergent to oblique margin segment) and the Barreirinhas and West Ceará basins (transform margin segment), whose tectonic boundaries are the St. Paul (north) and Romanche (south) oceanic fracture zones.

Fig. 1
Fig. 1
Full size image

Schematic plate reconstruction of the Equatorial Atlantic opening during the Upper Cretaceous (~ 85 Ma), highlighting the segmentation of the continental margin into divergent-oblique and transform segments, controlled by oceanic fracture zones (modified from Brownfield and Charpentier 2006; Dailly et al. 2013)

The sedimentary infill of the BEM central sector is composed of three sedimentary supersequences, as described by Trosdtorf et al. (2007). The first intracratonic supersequence is represented by the Paleozoic syneclise of the Parnaíba Basin and includes thick packages of Devonian (419–359 Ma) sandstones and shales (Canindé Group – Itaim, Pimenteiras and Cabeças formations) (Fig. 2). The overlying rift supersequence is composed of two rift sequences intercalated with a sag sedimentation unit between them. The basal sequence of sandstones and shales (Rift II Sequence – Inominado Formation) was deposited in the marine portion of the Barreirinhas basin during the Aptian (121.4–113 Ma). During the sag phase, the second sequence is represented by the lithological association of calcilutites and lagoonal shales (Pre-Rift III Sequence – Codó Formation), also dating from the Aptian (Fig. 2). The top unit is called the Canárias Group (Rift III Sequence) and corresponds to dark shales (Arpoador and Tutóia formations), turbidite sandstones (Bom Gosto Formation) and gray sandstones (Barro Duro Formation) (Fig. 2). These formations were deposited in the fan delta and filled an early marine rift basin in the Albian (113–100.5 Ma). The carbonates of the Caju Group, consisting of the Bonfim and Preguiças formations (Fig. 2), occur both in the Rift III sequence and in the drift section (Fig. 2).

Finally, the Drift Supersequence is composed of carbonate and siliciclastic units associated with successive transgressive‒regressive cycles from the Neo-Albian period to the recent (Fig. 2). The deepest sequences were deposited in a neritic environment of high and low energy that extended from the Neo-Albian to the Cenomanian (Caju Group). During the Turonian to Oligocene (94–23 Ma), the sedimentary environment was a shelf-slope basin that controlled the sedimentation of thick sequences of shale deepwater facies with associated turbidite sandstones. The turbidite units are included in the Travosas Formation (Humberto de Campos Group) (Feijó 1994). A large carbonate platform has been formed since the Miocene (23 Ma) to the present (Fig. 2), being partially covered with the retreat of the coastline and deposition of terrigenous sediments (Trosdtorf et al. 2007).

Fig. 2
Fig. 2
Full size image

Stratigraphic chart of the central sector of the Brazilian Equatorial Margin (BEM), illustrating the tectono-depositional stages and their four petroleum systems and migration paths (modified from Trosdtorf et al. 2007; Carmo 2018; Cohen et al. 2025)

Petroleum system and direct hydrocarbons indicators (DHIs)

The petroleum system of the offshore Barreirinhas Basin consists of three sequences of source rocks (Fig. 2): (a) shales of lagoonal origin and anoxic evaporitic environment of the Aptian (Codó Formation) (Trosdtorf et al. 2007). Geochemical studies reveal total organic carbon (TOC) contents ranging from 3% to 24% (Ferreira 2013); (b) shales deposited in a low-energy neritic environment of the Cenomanian (Preguiças Formation) (Feijó 1994; Trosdtorf et al. 2007). Their TOC contents are in the order of 4% to 6%, and these shales have the greatest potential for hydrocarbon generation (Carmo 2018); and (c) other source rocks include the Cenomanian–Turonian marine shales (Travosas Formation), deposited in anoxic environments (Ferreira 2013). Geochemical analyses of this formation in the Pará-Maranhão Basin reveal TOC content of 0.5 to 1.7%, type II kerogen, and the potential for oil and gas generation (Fabianovicz 2013). These source rocks formed 4 petroleum systems in the offshore Barreirinhas Basin: Codó-Bom Gosto (1), Codó-Tutóia (2), Preguiças-Travosas (3), and Travosas–Travosas (4) (Fig. 2).

The reservoir layers present in the BEM central sector include marine Albian sandstones (Bom Gosto and Tutóia Formations) and deepwater turbidite complexes (Travosas Formation) (Fig. 2). The latter originated from shelf-to-deep marine environments, had porosities of up to 20% and occurred from the Late Cretaceous to the Paleogene (Trosdtorf et al. 2007; Fabianovicz 2013). The role of seal rocks is shown by the thick package of intercalated marine shales of the Canárias Group and the Travosas Formation (Ferreira 2013). Deepwater sandstone and turbidite bodies are interspersed in these shales across the BEM central sector. These shale layers have low permo-porosities and represent the main barrier to prevent the upward migration of hydrocarbons through turbidites to shallower layers (Alleyne et al. 2018). Another important factor for the stratigraphic trapping and accumulation of hydrocarbons in the turbidite bodies is their pinch-out against the Late Cretaceous erosional unconformity. A similar structural and stratigraphic trap geometry with sand pinch-out onlap progressively onto laterally confining deepwater slope were largely observed in West African basins including the Jubilee field (Dailly et al. 2013; Kelly and Doust 2016).

In the Pará-Maranhão and Barreirinhas basins, the migration of hydrocarbons may have occurred along normal faults (Pellegrini and Severiano Ribeiro 2018). These structures are the main flow corridors connecting the source rocks to the turbidite reservoirs, from the rift layers to the drift sequence, sometimes reaching the ocean floor. Several of these faults are seated deep in the acoustic basement, acting as potential pathways for the transport of interstitial fluids from the source units throughout the entire sedimentary package until they could eventually reach the overlying reservoir sequences and even the ocean floor. The set of faults that reach the Upper Cretaceous unconformities connect the source rocks from the Preguiças and Travosas formations to the turbidite reservoirs (Fig. 2) (Milani et al. 2000; Carmo 2018). Unconformity surfaces also act as important pathways for the secondary migration of oil (Jiang et al. 2016) and may have transported hydrocarbons that arrived through normal faults into the turbidite complexes.

The viability of active petroleum systems and potential deepwater reservoirs is demonstrated by the Pecem Field discovery in the Ceará Basin, in which three deepwater wells penetrated a turbidite reservoir with an estimated hydrocarbon column of 290 m (Opdyke and Balabekov 2018). Furthermore, the application of a relative Vp/Vs overlay on rotated full stack 3D seismic data of this field proved highly effective in delineating the turbidite reservoir.

In the basins of the conjugate margins of South America and Africa, gas chimneys are recognized as important indicators of the migration of hydrocarbons to reservoirs (Aminzadeh et al. 2001; Connolly et al. 2002; Nemcok et al. 2016; Goulart et al. 2019). Recently, Delabrida et al. (2026) recognized the presence of gas chimneys and fluid migration pathways across the BEM. Despite this, the historical under-reporting of such features in the central sector during conventional seismic interpretations is primarily attributed to standard seismic processing workflows. Often, these workflows apply aggressive coherence and smoothing filters designed to enhance lateral reflector continuity, which can inadvertently mask or degrade the chaotic vertical signatures naturally caused by fluid escape structures (Goulart et al. 2019). Conversely, the frequency attributes applied in this study, particularly the LFE attribute, enhance the preservation of low-frequency anomalies, optimizing the detection of these vertical features that typically elude standard seismic evaluations.

However, in the present study, we identified seismic patterns typical of these leakage structures and describe them in Sect.  4. Given the lack of information from 3D seismic surveys and deepwater exploratory wells, we compared our seismic interpretations with well-studied and validated plays in the conjugate basins of West Africa and NW South America.

Another essential aspect of an active petroleum system is the thermal evolution of the basin that directly influences hydrocarbon generation. Recently, Fonseca et al. (2025) indicated in Barreirinhas Basin a current favorable thermal condition for oil generation (82–132 °C), occurring between depths of 1.5 to 4.75 km. Temperatures exceeding 132 °C were measured in exploratory wells at depths greater than 3.55 km, which favor gas generation. Deepwater domains are highlighted as areas with the greatest potential for thermal maturation of hydrocarbons, representing priority targets for future exploration.

Materials and methods

Seismic data and well logs correlation

The present study covers an area of approximately 45,000 km² in the central oceanic region of the BEM, encompassing the Barreirinhas Basin and its limits with the Pará-Maranhão Basin to the west, and the Ceará Basin to the east (Figs. 1 and 3). To investigate the spatial distribution of turbidite complexes and potential fluid migration pathways, the analyzed dataset comprised over 5,450 km of 2D seismic lines (Fig. 3), with recording times ranging from 8 to 16 s (TWT). These seismic data, provided by the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP), were previously stacked and migrated using conventional pre-stack time migration (PSTM) processing.

To establish chronostratigraphic control, we analyzed ten exploratory wells drilled across the study area (Fig. 3). These wells reached total depths ranging from approximately 3,000 to over 5,000 m, penetrating the main post-rift and drift sequences. Notably, none of these wells reached the crystalline basement. The available geophysical logs, including gamma ray (GR), resistivity, density (RHOB), and sonic (DT) profiles, were essential for characterizing the lithological units and their physical properties. A robust correlation between the lithostratigraphic unit tops identified in the wells and the seismic reflectors was achieved using synthetic seismograms. Well-to-seismic ties, alongside seismostratigraphic and structural interpretations, were performed using Petrel software (versions 2023–2025). The dimensions of the turbidite complexes (e.g., 360, 450, and 400 km²) and their thicknesses were estimated by tracking the top and base reflections across the available sparse 2D grid. We acknowledge that this inherently carries an uncertainty factor due to lateral interpolation across widely spaced lines. However, the resolution of the results is consistent with the regional scale of the present study and was considered in our interpretations and discussions.

Fig. 3
Fig. 3
Full size image

Bathymetric map of the central sector of the Brazilian Equatorial Margin (BEM), showing the three turbidite complexes (A, B and C) and the distribution of 2D seismic lines used for mapping turbidite complexes in both divergent-oblique margin segments (Pará-Maranhão/Barreirinhas basins) and transform margin segments (Barreirinhas/Ceará basins). FZ – Fracture Zone. Yellow segments indicate seismic profiles presented in Figs. 4, 5, 6, 7, 8 and 9. The base bathymetric map corresponds to the Global Bathymetry and Topography at 15 Arc Sec: + model (Tozer et al. 2019)

Seismic attributes

Seismic attributes are defined as all measured, computed, or implied quantities obtained from seismic data (Taner 1999). In this study, we applied three special seismic frequency attributes to enhance the typical seismic responses of turbidite bodies and the structural features associated with hydrocarbon migration and accumulation. These frequency-derived attributes are Low-Frequency Enhancement (LFE), High-Frequency Enhancement (HFE), and Low-High-Frequency Enhancement (LHFE).

Seismic frequency attributes extrapolate the frequency spectrum of the seismic signal from the Hilbert Transform. Following the methodology described by Goulart et al. (2019), the complex seismic trace was calculated in the Hilbert transform, extrapolating harmonic and subharmonic frequencies based on a linear extrapolation of straight lines on the flanks of the first derivative reflectance spectrum. The original seismic data, centered between 10 and 40 Hz, was expanded down to 0 Hz for the LFE and up to 70 Hz for the HFE, while strictly preserving the signal phase and amplitude ratios.

The LFE attribute amplifies low frequencies, facilitating the mapping of potential gas chimneys, which typically exhibit their highest relative amplitudes in this frequency range (Goulart and de Castro 2021). Subvertical leakage structures are often masked in conventionally processed seismic data due to aggressive coherence filters, thus, LFE optimizes the visualization of these chaotic, low-amplitude seismic facies (Aminzadeh et al. 2001; Goulart et al. 2019; Goulart and de Castro 2021; Azadbakht et al. 2024). Conversely, the HFE attribute enhances high frequencies to increase vertical resolution, better delineating structural terminations, turbidite pinch-outs, and flat spots (Bhandari and Cividin 2008). Finally, the LHFE attribute combines both spectra to improve the joint identification of turbidites, faults, and migration conduits, providing greater reliability in seismic interpretation.

A comparison between conventionally processed (PSTM) seismic data and the LFE, HFE, and LHFE attribute responses is illustrated in Fig. 4. High-amplitude reflectors associated with turbidites are highlighted by the LFE attribute (Fig. 4B), while overall reflector continuity and fault zone discontinuities are enhanced by the HFE and LHFE attributes, respectively (Fig. 4C and D).

Fig. 4
Fig. 4
Full size image

Segment of seismic Sects.  239–250 (location in Fig. 3), crossing the Turbidite Complex B (TC-B) with conventional PSTM seismic processing (A) and special frequency attributes: Low Frequency Enhancement (LFE) (B), High Frequency Enhancement (HFE) (C), and Low and High Frequency Enhancement (LHFE) (D). Seismic interpretation with the LHFE attribute is shown in (E) and (F). Units: U3 – Maastrichtian, U4 – Oligocene and U5 – Pleistocene

Seismic characterization of direct hydrocarbon indicators

DHIs are a class of anomalous seismic responses that serve as proxies for hydrocarbon migration and accumulation. Bright, dim, and flat spots, alongside localized phase changes, are seismic amplitude anomalies commonly indicative of fluid accumulations (Guo et al. 2015; Monigle et al. 2025). Gas chimneys are characterized by vertical or sub-vertical chaotic seismic zones with low amplitude and low trace-to-trace similarity (Meldahl et al. 2001; Connolly et al. 2002) and can reach significant lateral dimensions, occasionally extending beyond 5 km in width (Azadbakht et al. 2024).

However, when interpreting sparse 2D seismic data, large chaotic zones must be approached with caution to mitigate misinterpretation. Potential gas chimneys must be carefully discriminated from seismic artifacts, such as acoustic wipe-outs (shadow zones) generated by shallow high-impedance anomalies or structural complexities. In this study, the interpretation of DHIs as inferred migration pathways was strictly conditioned by structural framing (e.g., fault roots) and attribute validation. Other related seepage features mapped include Hydrocarbon-related Diagenetic Zones (HRDZs) and paleo-pockmarks (O’Brien and Woods 1995; Cartwright et al. 2007; Cartwright and Santamarina 2015). HRDZs were recognized as zones of anomalously high amplitudes overlying gas chimneys, while paleo-pockmarks were identified as V- or U-shaped depressions with onlap fill and similarly formed above gas chimneys.

Seismic well correlation

Based on the well-to-seismic ties established in Sect.  3.1, correlation panels between wells on the continental shelf and the deepwater domain illustrate the interplay between the main sedimentary sequences and the interpreted seismic units (Fig. 5). Six regional seismic horizons were interpreted, representing the primary chronostratigraphic intervals of the Pará-Maranhão and Barreirinhas basins. From bottom to top, these correspond to the Moho discontinuity, the acoustic basement, the Albian top, the Maastrichtian top, the Oligocene unconformity, and the current seafloor (Fig. 6).

The Moho is identified beneath the slope and abyssal plain as a high-reflectivity zone at approximately 9.0 s (TWT), deepening landward. The acoustic basement (U1 in Figs. 2 and 6) comprises Precambrian crystalline rocks and pre-rift sequences, characterized by chaotic patterns and discontinuous, high-amplitude reflectors. The overlying rift sequence (U2) is marked by a strong top reflector and internal low reflectivity. The drift sequences (U3 to U5) exhibit sub-horizontal, continuous reflectors, which are frequently deformed by gravitational tectonics.

Normal faults deeply rooted in the acoustic basement compose an intricate series of asymmetric grabens and horsts (Fig. 6), reflecting structural patterns dominated by oblique strike-slip tectonics across the Barreirinhas transform margin segment (de Castro et al. 2022). The structural scenario also encompasses tilted blocks, chaotic reflection zones associated with transtensional regimes, and reverse faults related to transpressional episodes along the Romanche Fracture Zone (Montenegro et al. 2021). Furthermore, extensional-compressional gravitational systems (Fig. 5) developed as post-breakup sedimentary layers mobilized over detachment surfaces of overpressured shales (Cruz et al. 2009). In the outer slope and deepwater domains, this gravitational system is floored by Cenomanian-Turonian shales that form the primary detachment zones (Krueger et al. 2012), as calibrated by well 02 (Fig. 5).

Fig. 5
Fig. 5
Full size image

Correlation panel among the six wells in continental shelf and deepwater, showing interpreted seismic units U2 – Break-up, U3 – Maastrichtian, U4 – Oligocene and U5 – Pleistocene. Location in Fig. 3. The geological ages (in Ma) adopted in this study follow the International Chronostratigraphic Chart (Cohen et al. 2025)

Fig. 6
Fig. 6
Full size image

Seismic profile 258–7481 with the LFE attribute (location in Fig. 3), presented in its uninterpreted (A) and interpreted (B) versions. The interpretation highlights a linked gravitational system, the turbidite complex TC-A pinching out over the Maastrichtian horizon, which was identified in well 1 (1-MAS-20-MA). Units: U1 – Basement, U2 – Break-up, U3 – Maastrichtian, U4 – Oligocene and U5 – Pleistocene

Results

In the Pará-Maranhão and Barreirinhas basins, the turbidite bodies form elongated sedimentary sequences with average lengths of ~ 23 km and thicknesses ranging from 110 to 230 m. These bodies are hosted within sets of low-amplitude, discontinuous reflectors, interpreted as deepwater prodelta or submarine canyon shale deposits. The distinct high-amplitude seismic response of the turbidite reflectors is primarily attributed to the strong acoustic impedance contrast between the turbidite sandstones, particularly if gas occupies the pore space, and the surrounding compacted, low-porosity shales. Occasionally, these turbidite bodies are partially truncated by normal faults at their landward termination and are observed overlying potential gas chimneys (Figs. 4 and 7). In the strike direction, submarine channels filled with high-amplitude reflectors were identified (Fig. 7C and D). These channels likely acted as primary pathways for turbidity currents, facilitating the accumulation of siliciclastic sediments in the deltaic fronts and ultimately forming the turbidite complexes.

Fig. 7
Fig. 7
Full size image

Seismic profiles 258–7481 (A and B) with the LFE attribute and 258–7172 (C and D), crossing the Turbidite Complex A (TC-A) (location in Fig. 3). The turbidites are anchored on the Maastrichtian unconformity, exhibiting amplitude anomalies (bright spots) and being affected by normal faults, which seemingly connect the source rocks from the rift sequence to the overlying turbidite bodies. Units: U3 – Maastrichtian, U4 – Oligocene and U5 – Pleistocene

Three major turbidite complexes were mapped across the outer slope and abyssal plain of the BEM central sector (Fig. 3), based on the standard seismic signature of analogous sedimentary units identified in productive deepwater fields worldwide (e.g., Normark et al. 1993; Kelly and Doust 2016). Generally, these turbidite bodies rest upon a prominent Upper Cretaceous (Maastrichtian) stratigraphic unconformity and are spatially associated with sparse normal fault systems, vertical seismic masking (interpreted as gas chimneys), and paleo-pockmarks. Paleo-pockmarks manifest as sub-rounded to rounded depressions along the Maastrichtian unconformity, filled by overlying drift sequences of unit U4 (Fig. 7, see detailed zoom in Supplementary Figs. S1). Their origin is widely linked to localized fluid expulsion through gas chimneys, which excavates depressions in the ancient seafloor (e.g., Sun et al. 2011; Velayatham et al. 2018).

These seismic features, occurring in spatial and structural alignment, reveal strong analogies with established hydrocarbon plays in producing basins along the South American and African equatorial margins, suggesting the potential for an active migration system within this sedimentary succession. The spatial extent of the turbidite complexes was estimated by mapping the turbidite seismic facies across the 2D grid and interpolating these areas onto the geological map (Fig. 3). The three identified turbidite complexes, designated TC-A, TC-B, and TC-C, are detailed below.

Turbidite complex A (TC-A)

Systematic seismic interpretation reveals that Turbidite Complex A (TC-A) occupies an approximately rectangular area on the continental rise of the Pará-Maranhão Basin (Fig. 3). TC-A comprises a major turbidite body with a maximum total thickness of 390 m (Fig. 6), internally subdivided into two ~ 110 m thick sand-prone layers separated by a 160 m thick shale sequence. The complex extends ~ 20 km in the dip direction (NE-SW) and ~ 18 km in the strike direction (NW-SE), encompassing an area of approximately 360 km². TC-A is hosted within unit U4 at a burial depth of ~ 3,860 m, under a water column of 2,850 m, and is sealed by 1,010 m of overlying strata (Figs. 6 and 7). The complex gently deepens seaward towards the abyssal plain, with its upper boundary occasionally coinciding with the top of unit U4.

In the dip direction, TC-A exhibits an up-slope onlap against the Maastrichtian unconformity, where the turbidite facies thin and pinch out against the northeastern edge of the submarine fan’s inner lobe (Figs. 6 and 7A, and 7B). Conversely, in the strike direction, the turbiditic sequence infills paleo-channels within the fan architecture (Fig. 7C and D). Deep-seated normal faults were mapped in the proximal portions of the turbidite system; these structures root into the acoustic basement and propagate through the sedimentary succession, likely linking deeper potential hydrocarbon source rocks to the overlying Maastrichtian unconformity (Figs. 6 and 7).

A broad, vertical, low-amplitude seismic zone characterized by chaotic internal reflections is observed up-dip (towards the structural crest) of the turbidite bodies and is bounded to the NE by a deep-seated normal fault. This localized loss of lateral reflector coherence is interpreted as a potential gas chimney, a critical DHI that may represent a focused fluid migration conduit charging the turbidite complex. In this framework, the deep faults act as preferential pathways for upward hydrocarbon migration. The observed gas chimneys associated with this complex span seismic times from 4.5 to ~ 7.0 s (TWT), crossing the entire drift sequence (Fig. 7A and B). Furthermore, localized amplitude anomalies (bright spots) within the turbidites may indicate hydrocarbon entrapment, which would increase the acoustic impedance contrast between fluid-bearing sands and the surrounding lithologies. In several instances, these gas chimneys terminate upwards in crater-like depressions along the Maastrichtian unconformity (Fig. 6A and B). These features are interpreted as paleo-pockmarks caused by ancient fluid leakage. The postulation of oil-bearing turbidite complexes in the central BEM sector and the associated exploration risks will be critically discussed in Sect.  5.

Turbidite complex B (TC-B)

TC-B is situated in the central portion of the deepwater Barreirinhas Basin, extending an average of 30 km in the NE-SW direction and 15 to 30 km in the NW-SE direction, covering a roughly ellipsoidal area of ~ 450 km² (Fig. 3). TC-B comprises three primary turbidite bodies with thicknesses ranging from 350 to 500 m, internally characterized by intercalations of sandstones and shales (Figs. 4 and 8). These bodies are deposited along the outer slope and continental rise at estimated burial depths between 2,500 and 6,200 m, deepening oceanward to 7,500 m.

In the dip direction, TC-B is characterized by stacked high-amplitude reflectors (Figs. 4 and 8). The deepest turbidite is anchored on the Maastrichtian unconformity, whereas the shallower bodies are positioned near the top of the U4 sequence and within the U5 sequence. Low-amplitude reflection zones are interpreted as interbedded shale layers. The proximal sector of these turbidites is heavily controlled by deep-rooted normal faults and flanked by vertical chaotic zones interpreted as gas chimneys, propagating upwards from the continental rise to the outer slope. An additional cluster of gas chimneys occurs closer to the shelf break, affecting the uppermost sequences near the seafloor. Crater-like structures at the top of these shallow gas chimneys likely represent ancient pockmarks subsequently buried by younger sedimentation (Fig. 8, see detailed zoom in Supplementary Fig. S2). This sector of the basin was heavily influenced by strike-slip tectonics along the Romanche Fracture Zone, controlling the continental shelf breakup (Fig. 3). This intense strike-slip deformation produced a large chaotic reflection zone near the shelf break, SW of TC-B, which extends from the outer slope into the abyssal plain (Fig. 8A and B).

Fig. 8
Fig. 8
Full size image

Seismic profiles 258–7365 (A and B), 258–7112 (C) PST and (D and E) with the LFE attribute, crossing the Turbidite Complex B (TC-B) (location in Fig. 3), showing deep normal faults, gas chimney, and paleo-pockmarks associated with the turbidite bodies (bright spot). Units: U3 – Maastrichtian, U4 – Oligocene and U5 – Pleistocene

In the strike direction, two TC-B turbidite bodies display a diagnostic seismic pattern of high-amplitude reflectors (sand-prone units) intercalated with low-amplitude reflectors (shale-prone units), gently dipping to the SE above the Maastrichtian unconformity and atop the U4 sequence (Fig. 8C and D, and 8E). At the NW limit of the seismic section, near the toe-of-slope, the deepest turbidite body pinches out up-dip. At this termination, two sub-vertical low-amplitude zones suggest the presence of gas chimneys. The deeper gas chimney occurs on the northwestern edge of the turbidite body, at the base of unit U4 over the Maastrichtian unconformity. A few kilometers further northwest, a second gas chimney crosses unit U4 and part of U5, terminating at a strong reflector near the seafloor (Fig. 4). The combination of internal high seismic amplitude and gentle downward concavity are hallmark characteristics of paleo-pockmarks generated by fluid expulsion. The identification of these suspected fluid escape features further reinforces the hypothesis of viable migration routes that could feed hydrocarbons into the TC-B reservoirs.

Turbidite complex C (TC-C)

TC-C is located on the deepwater continental rise near the boundary between the Barreirinhas and Ceará basins, encompassing a semicircular area of ~ 400 km² with an average length of 20 km (Fig. 3). Similar to TC-B, TC-C consists of three main turbidite beds interspersed with shales, identified by sets of elongated, high-amplitude reflectors gently dipping oceanward (Fig. 9). TC-C is hosted entirely within unit U3, reaching a cumulative thickness of 600 m. Individually, each turbidite body measures 160 to 230 m in thickness, separated by up to 100 m of shale. Stratigraphically, TC-C is older than TC-A and TC-B (which are hosted in units U4 and U5). Notably, no prominent turbidite systems were observed in the shallower post-rift units in the eastern sector of the Barreirinhas Basin. TC-C sits at a burial depth of 5,485 m, under a water column of 2,475 m, and is sealed by 3,010 m of overlying strata.

The deepest turbidite body overlies unit U2 (Albian rift sequence), while the uppermost body is truncated by the Maastrichtian unconformity (Fig. 9). In the dip direction, the reflectors narrow landward, onlapping a prominent basement high (Fig. 9A and B). However, unlike the other mapped complexes, a distinct depositional pinch-out surface is not clearly resolved. The structural relationship between the turbidite bodies and the basement high is more evident in the strike direction, where the draped layers of unit U3 form an anticlinal structure, partially controlled by deep-rooted faults (Fig. 9C and D). The strike-oriented seismic sections exhibit several potential DHIs, including flat spots near the anticline hinges, gas chimneys cross-cutting units U3 and U4, and paleo-pockmarks at the base of unit U5, collectively suggesting a possible hydrocarbon migration system associated with TC-C.

Fig. 9
Fig. 9
Full size image

Seismic profiles 258–7201 (A and B) PSTM and 258–7160 (C and D) with the LFE attribute, crossing the Turbidite Complex C (TC-C) (location in Fig. 3), showing three turbidite bodies over a structural high of the acoustic basement. Direct hydrocarbon indicators (DHIs) such as flat spots, gas chimneys, and paleo-pockmarks are highlighted in D. Units: U1– Basement, U2 – Break-up, U3 – Maastrichtian, U4 – Oligocene and U5 – Pleistocene

Seismic signatures of potential fluid-escape features

In the analyzed 2D seismic profiles, prominent vertical to sub-vertical zones of acoustic masking and chaotic reflection patterns are systematically observed cross-cutting the deeper stratigraphic sequences (Figs. 4, 7 and 8, and 9). Some of these anomalous zones extend laterally for several kilometers, particularly near the shelf break and along the continental rise. In conventionally processed PSTM data, these zones are characterized by a pronounced ‘wipe-out’ effect, where the lateral continuity of background reflections is severely disrupted. When evaluated using spectral decomposition, these vertical chaotic zones consistently correlate with distinct Low-Frequency Enhancement (LFE) anomalies at their core, which are often flanked by High-Frequency Enhancement (HFE) anomalies.

Remarkably, these vertical acoustic disturbances are systematically rooted in deeper and structurally deformed horizons. They are frequently associated with deep-seated planar normal faults and typically propagate upwards to terminate at or near the base of the mapped turbidite complexes, namely TC-A, TC-B, and TC-C (Figs. 4, 7 and 8, and 9).

The upper terminations of these vertical chaotic zones coincide with localized and strong amplitude anomalies (bright spots) within the overlying turbidite bodies. Furthermore, these vertical zones frequently culminate in crater-like, U- or V-shaped depressions along the Maastrichtian unconformity and shallower horizons. These depressions are subsequently infilled by onlapping reflectors of the younger drift sequences, such as unit U4. Additionally, localized horizontal amplitude anomalies (flat spots) are observed within the structural hinge zones of the older turbidite bodies (e.g., TC-C, Fig. 9), presenting a distinct acoustic impedance contrast relative to the surrounding stratigraphic reflectors. As a group, these seismic facies and amplitude behaviors constitute the primary observational criteria used to evaluate potential fluid-flow phenomena within the central sector of the BEM, recently mapped by Delabrida et al. (2026), applying seismic attributes (instantaneous amplitude, pseudo-relief, similarity, and chaos) to 2D and 3D seismic data. Figure 10 summarizes the three turbidite systems in the BEM central sector, showing the main related fluid-escape features.

Fig. 10
Fig. 10
Full size image

Seismic signatures of potential fluid-escape features in the turbidite complexes TC-A (A and D – Fig. 7B), TC-B (B and E – Fig. 8D), TC-C (C and F– Fig. 9C and D), location map of turbidite complexes (G). Units: U1– Basement, U2 – Break-up, U3 – Maastrichtian, U4 – Oligocene and U5 – Pleistocene

Discussion

Turbidite complexes architecture and controls

The seismic architecture of the mapped turbidite systems in the BEM central sector reflects mass-transport dynamics intrinsically linked to submarine canyon and prodelta depositional environments (Berg 1982; Normark et al. 1993). The prodeltaic seismic facies are characterized by low-amplitude and low-to-moderate continuity reflectors, corresponding to the dominant shale content (Berg 1982; Gasperi and Catuneanu 2014). In stark contrast, the turbidite bodies exhibit high seismic amplitudes and extensive lateral continuity, reaching several tens of kilometers (Figs. 4 and 7). This acoustic impedance contrast allows for the precise delineation of turbidite sequences encased within thick shale packages. Furthermore, these highly reflective packages typically occur on the outer slope and continental rise, up-dip onlapping seaward-dipping post-rift and drift stratigraphic unconformities. The spatial coexistence of these highly reflective zones with potential DHIs (bright and flat spots, gas chimneys, and paleo-pockmarks) strengthens the hypothesis of possible fluid migration systems associated with sandstone bodies.

Based on these seismostratigraphic criteria, three main turbidite complexes were identified across the Pará-Maranhão, Barreirinhas, and Ceará basins (Figs. 3, 4, 6, 7, 8, 9 and 10). Specifically, a well-preserved submarine channel system is observed in strike-oriented sections parallel to the shelf break, crossing TC-A (Fig. 7D). Two main channels, extending 18 to 24 km and filled with turbidite sequences up to 450 m thick, were excavated into the Maastrichtian unconformity. Based on this depositional geometry, TC-A and TC-B are interpreted as up-dip truncation turbidite plays against the Maastrichtian unconformity, structurally analogous to prolific turbidite reservoirs in Norwegian basins (Martinsen et al. 2005). In opposition, TC-C represents an older turbidite system deposited within the pre-Cenomanian drift sequence, heavily influenced by rift-phase structural inheritance (Fig. 9D). Located further east in the Ceará Basin (Fig. 3), TC-C exhibits structural traits remarkably similar to the Albian faulted-block and Cenomanian drape plays (3 and 5 in Fig. 11) identified in the African Equatorial Margin by Kelly and Doust (2016). We hypothesize that TC-C development was controlled by transform tectonics along the Romanche Fracture Zone prior to the Maastrichtian, a regime that did not concurrently affect the relatively younger, northwestward complexes (TC-A and TC-B). In fact, Delabrida et al. (2026) identified three main fluid migration systems in the central BEM, which encompass the turbidite complexes mapped in this study. According to them, the fluid migration systems in the Pará-Maranhão and Barreirinhas basins are controlled by gravitational tectonics, involving the TC-A and TC-B turbidite complexes. The fluid migration system in the western Ceará basin, which includes the TC-C turbidite complex, is clearly affected by strike-slip movements along E-W trending Romanche Fracture Zone.

Fig. 11
Fig. 11
Full size image

Schematic geological section of the petroleum system in the Cretaceous of Equatorial Africa. (modified from Kelly and Doust 2016).

Direct hydrocarbon indicators (DHI)

Recent regional assessments have highlighted the petroleum prospectivity of turbidite systems in the BEM (Pellegrini and Severiano Ribeiro 2018), drawing analogies to giant discoveries in the conjugate margins of Guyana-Suriname and Ivory Coast-Ghana (Kelly and Doust 2016; Alleyne et al. 2018). To ground these analogies, DHIs were systematically investigated in this study, particularly in the deepwater domains.

Vertical chaotic seismic zones with low amplitude and low trace-to-trace similarity, interpreted as gas chimneys, are the most prominent candidate DHIs observed in the central BEM (Figs. 4, 7, 8, 9 and 10). These sub-vertical features crosscut units U3 to U5 and are partially controlled by deep-seated basement faults. Structurally, genuine gas chimneys represent fractured or hydrothermally altered rock volumes where upward fluid migration creates highly permeable escape pathways, often indicative of an active petroleum system (Meldahl et al. 2001; Connolly et al. 2002; Delabrida et al. 2026).

However, interpreting wide vertical chaotic zones solely as gas chimneys in 2D seismic data carries inherent exploratory risks. It is imperative to critically consider alternative geological and geophysical mechanisms for these observed amplitude anomalies. Large-scale zones of low seismic coherence can frequently result from acoustic wipe-outs (chaotic zones) caused by signal scattering and attenuation beneath shallow, high-impedance anomalies, such as localized carbonate buildups, gas hydrate concentrations, or magmatic sills (Planke et al. 2005; Løseth et al. 2009; Burgess et al. 2013). Furthermore, extensive sub-vertical fault zones subjected to polyphase tectonic reactivation can create wide corridors of structural deformation that degrade seismic imaging, mimicking fluid-escape structures. Therefore, while high-amplitude anomalies (bright spots) and phase reversals may indicate fluid-related velocity changes or diagenetic cementation, their interpretation in this study serves primarily as a mechanism for geological risk reduction rather than definitive proof of commercial hydrocarbon accumulations (Aminzadeh et al. 2001; Heggland 2014; Goulart et al. 2019; Delabrida et al. 2026).

Despite these uncertainties, the spatial correlation of these potential gas chimneys with paleo-pockmarks reinforces the fluid migration hypothesis. Paleo-pockmarks, recognized as crater-like depressions formed by fluid expulsion on ancient seafloors and subsequently buried (e.g., Velayatham et al. 2018), are observed across the study area (Figs. 7, 8 and 9). Within the BEM, these features exhibit diameters of approximately 2 km (comparable in genesis, though smaller in scale, to the 5.5–9.5 km pockmarks in the South China Sea, as described by Sun et al. 2011). Similar coupled gas chimney-pockmark systems are widely documented in the Guyana-Suriname Basin (Fig. 12). A striking tectono-depositional analogue to our study area was drilled by the Jethro-1 well in the Guyana Basin, where an oil-rich Tertiary turbidite fan was discovered within a crater-shaped feature situated on the upper-slope (Wong and Geuns 2019). In the BEM, strong amplitude seismic anomalies (bright spots) embedded in several paleo-pockmarks (Figs. 7 and 8) provide secondary evidence of possible hydrocarbon entrapment. Additionally, flat spots, which are horizontal seismic reflectors representing horizontal fluid contacts (Guo et al. 2015; Delabrida et al. 2026), were identified within the antiform structural highs of TC-C (Fig. 9C), suggesting multiphase fluid accumulation in these older turbidite bodies.

Fig. 12
Fig. 12
Full size image

Comparison between the Turbidite Complex A (TC-A) in the eastern sector of the Barreirinhas (A) and a conceptual model of the Cretaceous faulted-block turbidite play of the Guiana-Suriname Basin (B) (modified from Kelly and Doust 2016).

Petroleum system

The structural and stratigraphic contexts of the turbidite complexes mapped in this study align robustly with the four petroleum systems proposed for the BEM central sector (Carmo 2018; Fig. 2). For the two oldest systems (1 and 2 in Fig. 2), associated with TC-C, hydrocarbons generated in Aptian sag-phase shales (Codó Fm) may have migrated vertically through fault networks into the Albian turbidite reservoirs (Bom Gosto Fm). In turn, the third system involves Albian/Cenomanian source rocks (Preguiças Fm) feeding the younger Maastrichtian-anchored turbidites of TC-A and TC-B (Figs. 4 and 7, and 8). Finally, intra-formational migration from Travosas Fm shales directly into encased turbidites constitutes the fourth system (Pellegrini and Severiano Ribeiro 2018).

This framework is highly analogous to the Gulf of Guinea and Guyana-Suriname provinces, where Upper Albian and Cenomanian source rocks dictate deepwater prospectivity. In these conjugate margins, source rock quality and thickness increase basinward (Brownfield and Charpentier 2006), and geochemical signatures indicate long-distance lateral migration into deepwater reservoirs (Schiefelbein et al. 2000; Dailly et al. 2013). The deepwater channel complexes mapped in the BEM (Fig. 7C and D) provided the necessary accommodation space for massive downslope deepwater clastic transport, resulting in potential reservoirs up to 45 km long and 600 m thick. Importantly, large structural depressions bounded by Lower Cretaceous faulted highs and subsequently filled by Upper Cretaceous turbidites are defining characteristics of both the Pará-Maranhão and Guyana-Suriname basins (Fig. 12A and B; Casey et al. 2015; Kelly and Doust 2016; Griffith 2018). Therefore, TC-A and TC-B represent combination structural-stratigraphic traps dynamically analogous to the Jubilee Field (Bryant et al. 2012; Dailly et al. 2013; Ferreira 2013).

Finally, the recent thermal characterization of the BEM central sector, conducted by Fonseca et al. (2025), confirms that the deepwater domains currently lie within the oil generation window. Corrected bottom-hole and drill-stem test temperatures, recorded within the 1.5 and 4.75 km depth range, vary from 82 °C to 132 °C, making it thermodynamically feasible for the underlying source rocks to actively feed the shallow turbidite systems (TC-A and TC-B). Although temperature calibrations below 5.1 km are lacking, the clear correlation of thermal regimes between the Pará-Maranhão and Barreirinhas basins and their prolific African counterparts (Brownfield and Charpentier 2006; MacGregor 2020) reinforces the frontier exploration potential of the BEM central sector.

Conclusions

The main findings of this study can be summarized as follows:

  • Application of Seismic Attributes: The application of specialized frequency-derived seismic attributes, particularly LFE and LHFE, significantly optimized the visualization and delineation of subtle seismic facies and features, improving the resolution of deepwater turbidite geometries, fault networks, and vertical fluid migration conduits. These seismic responses are poorly defined on standard PSTM seismic sections, which hindered their clear interpretation in previous studies of Brazil’s equatorial margin. Thus, it can be concluded that each seismic feature has a specific frequency range in which it appears in the seismic section with its best resolution, highlighting a promising avenue for numerous future studies applying spectral decomposition techniques.

  • Mapping of Turbidite Complexes: Based on the systematic interpretation of a regional 2D seismic dataset, well-log correlations, and advanced frequency-derived seismic attributes across the central sector of the BEM, this study successfully identified and mapped three major deepwater turbidite complexes designated as TC-A, TC-B, and TC-C within the Pará-Maranhão, Barreirinhas, and Ceará basins. These sand-bearing layers form elongated sedimentary sequences, spanning areas from 360 to 450 km² with cumulative thicknesses of up to 600 m, which are anchored by major regional unconformities such as the Albian and Maastrichtian surfaces and structurally constrained by normal faults deep-seated in the acoustic basement and gravitational detachment systems.

  • Direct Hydrocarbon Indicators (DHIs) and Fluid Migration: The integration of seismic amplitudes and attribute responses further revealed multiple potential DHIs, including bright spots, flat spots, gas chimneys, and buried paleo-pockmarks concentrated at the up-dip wedges of the turbidite bodies. These features suggest potential fluid migration networks that may connect Aptian–Albian and Cenomanian–Turonian source rocks to the overlying turbidite reservoirs. While chaotic low-coherence zones and amplitude anomalies suggest the presence of focused fluid flow and reservoir potential, their interpretation is framed primarily as an exercise in geological risk reduction, acknowledging alternative non-hydrocarbon mechanisms such as acoustic shadow zones or processing artifacts in sparse 2D grids, and underscoring that final confirmation requires targeted well calibration.

  • Regional Analogies and Prospectivity: Finally, the tectono-depositional architecture, trapping mechanisms, and petroleum system elements of the BEM central sector exhibit robust analogies to world-class producing oil fields along Equatorial Atlantic margins of NW South America (Guyana-Suriname Basin) and West Africa (Ivory Coast and Ghana), as well as the eastern Brazilian margin. All these correlations position the deepwater BEM as an exploratory frontier with high prospectivity, characterized by reduced geological risk and significant economic potential.