This paper presents the potential depositional framework of sandstones and unconsolidated sand reservoirs, seals, and traps in the western part of the coastal swamp depobelt of the Niger Delta Basin, Nigeria, through integration of sequence stratigraphy and seismic imaging. The integration of well logs and biostratigraphic (foraminifera and palynological) data with three-dimensional seismic volume established the sequence stratigraphic framework, which has improved our understanding of the impact of sea-level changes in the distribution of sand facies. Four third-order seismic depositional sequences (sequences 1–4) of Serravallian deposits were identified based on the Vail stratigraphic concept. Depositional processes, structures, thickness, and seismic signatures vary in each sequence. Sequence 1, dominated by mud and very fine-grained sand facies, represents the outer shelf–shelf margin setting and has experienced shale tectonics (ductile deformation). Sequences 2 and 3 consist of alternating sand–shale facies and have experienced gravitational tectonics. Although sequence 2 represents middle shelf–inner shelf setting, sequence 3 represents inner shelf–transitional setting. Sequence 4 consists of thick fluvial–coastal plain sand facies and represents deltaic plain or continental sediments. These deposits reflect postgravitational tectonics. Within the third-order sequences are fourth-order sequences that recorded the interaction between small-scale transgressive–regressive cycles and depositional tectonics. The potential reservoirs within these sequences are stacked channel sandstones, shoreface sandstones, and heteroliths. The juxtaposition of the potential reservoirs against transgressive shales provides potential seals and traps. Structural interpretation shows synthetic and antithetic faults. In addition, event maps at various ages document structural closures that indicate the existence of possible hydrocarbon leads and prospects.
The Niger Delta Basin is characterized by extensional and anticlinal fault structures developed through syndepositional extensional tectonics. These structures play a pivotal role in the accumulation of petroleum in the Niger Delta Basin (Evamy et al., 1984; Doust and Omotsola, 1989; Beka and Oti, 1995; Stacher, 1995;). Most explorationists have solely or partially depended on these syndepositional structures as indicator elements in search of petroleum pools in this region. Cadena and Slatt (2013) claim that pure structural play concepts would not improve exploration opportunities but its integration with sequence stratigraphy and sedimentology.
The coastal swamp depobelt is a prolific petroleum subprovince of the Cenozoic Niger Delta Basin (Figure 1A), where petroleum exploration activities have been going on for the past five decades. The study cuts across seven fields that are pseudonyms because of proprietary reasons. Three fields exist along the depositional dip: Tovo (TV), Ogheneovo, and Iroro, and five fields exist along the strike direction: Emebradu, Ekpetiudi, Imoni, TV, and Eboh (TV field is seen here as the principal field, because it is situated along both depositional dip and strike of the study area) (Figure 1B). Large hydrocarbon production has been recorded from various fields in the coastal swamp depobelt. However, the selected fields are yet to be exploited effectively because of wide spacing of drilled wells. In addition, the deeper section of this region is yet to be penetrated and explored because of the complexity of imaging of this stratigraphic–structural section. This complexity poses a greater challenge to the identification of stratigraphic events and elements during exploration. To overcome this challenge, a combination of depositional and structural (conventional) play concept approach is essential. The key objectives of this work are the following: (1) examine the impact of sea-level changes and syndepositional tectonics on the sequence stratigraphic framework and sand distribution; and (2) predict depositional elements from seismic data which will allow the identification of potential reservoirs, seals, and traps in the study area. The usage of sequence stratigraphic analysis for prediction of depositional features is intended to reduce the uncertainty associated with prospects identification in this study.
Figure 1. Location and regional geological setting of the Niger Delta. Inset map of Nigeria shows the location of the Niger Delta. Location of XY cross section for Figure 2 is marked. (A) Schematic map of the Niger Delta depobelt nomenclature showing the area of study (red box) located in the western costal swamp depobelt (modified from Evamy et al., 1984; Saugy and Eyer, 2003). Each depobelt is delimited by major bounding faults. (B) Area of coverage seismic survey (A–G) within the red box marked with well locations and general structures of the area of study, western coastal swamp depobelt, Niger Delta, Nigeria. EB = Eboh; EM = Emebradu; EP = Ekpetiudi; IM = Imoni; IR = Iroro; OG = Ogheneovo; TV = Tovo.
The Niger Delta Basin is a prograding depositional complex lying within the Cenozoic succession of southern Nigeria. The basin is situated in the Gulf of Guinea and extends throughout the Niger Delta province (Klett et al., 1997). It is located between longitudes 3°E and 9°E and latitudes 4°N and 6°N (Figure 1). From the Eocene to the present day, the delta has prograded southwestward, forming depobelts representing the most active portion of the delta at each stage of its development (Doust and Omatsola, 1989).
The evolution of the Niger Delta Basin is linked to the opening of the Gulf of Guinea that is related to the opening of the South Atlantic (Burke et al., 1971). It is formed at the site of a rift triple junction and the subsequent separation of the South American and African continents in the Late Jurassic and continued into the Cretaceous (Short and Stauble, 1967; Burke et al., 1971). Short and Stauble (1967) reported three depositional cycles in southern Nigeria. The first is the marine incursion in the middle Cretaceous, which terminated with a mild folding phase in the Santonian. The second is the growth of a proto–Niger Delta during the Late Cretaceous that ended in a major Paleocene marine transgression (Whiteman, 1982). The third consists of continuous growth of the main Niger Delta from the late Paleocene to Holocene (Short and Stauble, 1967; Evamy et al., 1984). The later depositional cycle is generally affirmed to form the Cenozoic Niger Delta within southern Nigeria. The main sediment supply has been transported by an extensive drainage system, the Niger–Benue System through the Anambra Basin north of Onitsha and the less-important Cross River System through the Afikpo Basin (Short and Stauble, 1967; Etu-Efeotor, 1997) (Figure 1A).
The Cenozoic Niger Delta subsurface is subdivided into three diachronous lithostratigraphic formations consisting of overpressured marine shale of the Akata Formation; sand–shale alternating fluvio–deltaic, paralic Agbada Formation; and the continental, coast plain sand, Benin Formation (Figure 2). The Niger Delta is composed of an estimated 8535 m (∼28,000 ft) of sediments in the central part of the Delta (Avbovbo, 1978). These three sedimentary units span across the whole delta, and each range in age from early Paleogene to Quaternary (Figure 2). The three formations occur in five offlapping siliciclastic sedimentation cycles that prograde southwestward over the oceanic crust into the Gulf of Guinea (Tuttle et al., 1999) (Figures 1A, 2). These offlapping siliciclastic sedimentation cycles are commonly referred to as depobelts, and each range in average width of 35 to 70 km (22–44 mi) (Figure 1A). They are defined by synsedimentary faulting that occurred in response to variable rates of subsidence and sediment supply (Doust and Omatsola, 1989). In order of progradational sedimentation, structural complexity tends to increase basinward (Figures 1A, 2).
Figure 2. Schematic section across the Niger Delta tectonic stratigraphic oil province. Boundaries of depobelts are shown with three diachronous lithostratigraphic formations, and associated structures are indicated (modified from Saugy and Eyer, 2003). Note the study depobelt and the line location shown in Figure 1A. TVDSS = true vertical depth subsea.
The structural development of the Cenozoic Niger Delta is related to sediment movement under the influence of gravity. These structures are formed because of diastrophism contemporaneous with rapid sand deposition, burial, and compaction along the delta edge, initiated by the deformation of the underlying sediments at depth, probably because of the interstitial fluid pressure (Merki, 1972; Evamy et al., 1984; Doust and Omatsola, 1989). The delta is a bit disturbed at the surface, but the subsurface is affected by large scale synsedimentary structures such as growth faults, rollover anticlines, and diapirs (Etu-Efeotor, 1997). Their distribution is related to growth stages of the delta (Short and Stauble, 1967).
The Cenozoic Niger Delta possesses a combination of excellent petroleum system components. Previous studies in the basin have shown that marine shale intervals of the Agbada and the upper part of the marine shales of the Akata Formations are the petroleum system potential source rock (Ejedawe et al., 1984; Doust and Omatsola, 1989; Stacher, 1995). The distribution of petroleum is likely to be related to heterogeneity of source rock type (greater contribution from paralic sequences in the west) and/or segregation because of remigration (Doust and Omatsola, 1989; Tuttle et al., 1999). Hydrocarbons in the Niger Delta are produced from sandstone and unconsolidated sand reservoirs of the Agbada Formation (Tuttle et al., 1999).
Hydrocarbon accumulation in the Niger Delta is found mainly in rollover anticlines in front of growth faults and in traps against faults without full closure in all directions (Short and Stauble, 1967). Halbouty (1972) established that on the flanks of the delta, major erosional events in the early to middle Miocene formed canyons that are now clay filled. The primary seal rock in the Niger Delta is the interbedded shale within the Agbada Formation. Clay fills form the top seals for some important offshore fields (Doust and Omatsola, 1989).
Data and Methodology
The data sets were provided by Shell Petroleum Development Company (SPDC) in Nigeria. Well logs such as gamma ray, resistivity, neutron, density, and sonic were available from 30 wells. The data set also included biostratigraphic information from key wells with an updated Niger Delta chronostratigraphic chart. Low-frequency (20–40 Hz), prestack-depth migration, noise-filtered, three-dimensional (3-D) seismic volume was available for stratigraphic and structural analysis of the study area. The quality of the 3-D seismic data are generally fair to good down to approximately 3 s. The 3-D seismic data were processed to zero phase reflectivity. Reprocessing was done using prestack imaging technique to resolve structural uncertainties.
Figure 3. Velocity model obtained from integration of 11 wells check-shot data. Derived interface velocity (Vo) and derived constant (K) were used in time–depth conversion of surfaces generated in this study. TWT = two-way traveltime; Vint = interval velocity.
Well logs and biostratigraphic and seismic data were integrated and correlated using the updated Shell Companies in Nigeria (1997) biozonation chart of the Niger Delta Basin. Based on this work, sequence boundaries (SB), maximum flooding surfaces (MFS), transgressive surface of erosion (TSE), and depositional systems were delineated. Well logs and biostratigraphic data analysis were used to establish depositional sequences. The identified chronostratigraphic surfaces within the sequences were tied to the well control through one-dimensional synthetic seismogram. The well logs were calibrated with the seismic data to provide geological constraints for the interpreted seismic surface, and the key chronostratigraphic surfaces were correlated regionally. The analysis of the seismic lines and the established depositional sequences revealed four mappable, third-order seismic sequences based on the stratigraphic concept by Vail et al. (1977), which uses unconformities as SB. The established third-order sequences were divided into fourth-order sequences that were then used to subdivided the systems tract into genetically related sedimentary units within the potential reservoirs that became more predictable. Depositional facies were predicted based on log signatures that are described as electrofacies. Facies is used here for predicted lithotype with specific log and seismic characteristics. Individual sand top and base were correlated across wells and mapped on seismic to obtain top and base structural time maps.
Time–depth conversion of interpreted surfaces was performed using VoK derivatives (where Vo = interface velocity and K = derived constant) obtained from the integration of check-shot data of key wells as inputs in Microsoft Excel from which the velocity model was derived (Figure 3). The velocity model was uploaded into Petrel software as a velocity–time function, which is approximately equivalent to depth (D)
where e = mathematical exponential, TWT = two-way traveltime, and Vint = interval velocity (Figure 3). The velocity–time function was used to convert time–depth structural maps in Petrel software.
Figure 4. Third-order sequence stratigraphic analysis: type well with biostratigraphic calibration of sequence stratigraphic surfaces and third-order sequence stratigraphic systems tract (S. Tract) for the study area based on stacking patterns and faunal population and diversity with shale interval (condensed section). Condensed sections correspond with time–stratigraphic correlation marker within the biozones (foraminifera zone [F-Zone] and palynological zones [P-Zone]) of the Niger Delta chronostratigraphic chart mapped as maximum flooding surfaces (MFS). Sequence boundary (SB) identified based on stacking pattern between MFSs and base of channel sandstone. Transgressive surface of erosion (TSE) interpreted based on minimum resistivity value and maximum density-neutron separations immediate above SB. Paleobathymetry (Paleoba.) delineation was based upon biostratigraphic data (foraminifera and palynological distribution). The analysis provided patterns for correlation to other wells and calibrated against correlation established from seismic reflection profiles. Note the seismic profile shown as Figure 8B. DEN = density log; DT = sonic log; F. Div = foraminifera diversity; F. Pop = foraminifera population; GR = gamma-ray log; HST = highstand systems tract; IN = inner neritic; INDET = indeterminate; LLD = resistivity log; LST = lowstand systems tract; MN = middle neritic; NEU = neutron log; ON = outer neritic; SHIN = shallow inner neritic; SSTVD = subsea true vertical depth; TST = transgressive systems tract; TV = Tovo.
To understand stratigraphic thickness and distribution of reservoirs with the study area, individual reservoir top and base structural depth maps, coupled with dip angle of the top surface, were used to generate sandstone thickness distribution maps in Petrel software.
RESULTS AND DISCUSSION
Well Correlation and Calibration of Depositional Sequences
The integration of type-well biostratigraphic calibration, TV-01 (Figure 4) and an established Niger Delta Basin chronostratigraphic chart (Figure 5), revealed four third-order stratigraphic sequences: sequence 1, sequence 2, sequence 3, and sequence 4 (Figure 6, 7). The main surfaces used in delineating these third-order stratigraphic sequences are MFS and SB. The cycle frequency of these sequences ranges from 1.00 to 1.85 m.y. The correlation panel along dip shows that the sequences thicken toward the basin, which reflects an increase in accommodation space caused by the syndepositional listric faulting (Figure 6, 8).
Figure 5. Niger Delta Basin chronostratigraphic chart (modified from Shell Companies in Nigeria, 2010). Integration of this chart and type logs from Figure 4 was used to identify correlation markers for the study interval. Chron = chronology; F-Zone = foraminifera zone; Geomag = geomagnetic; M = Miocene; N = Neogene; Nanno. = nannofossil; NN = nannofossil of Neogene; P-Zone = palynological zone; Palyn. = palynomorph; S-Zone = foraminifera subzone; SCiN = Shell Company in Nigeria; Seq. and SQ = sequence; Ser = Serrvalian; SL = sea level; SPDC = Shell Petroleum Development Company; T–R = transgressive–regressive sequence; TB = transgressive backstepping facies association; Tor = Tortonian.
The correlation surfaces (MFS) occur at or in close association with fossil population and diversity peaks, deposited during the most effective sea-level rise (Figure 4). This is the phase of a depositional sequence when the oceanic waters make their most landward incursion, and fossil-rich, shale-prone depositional environments are most widely distributed (Armentrout, 1996). In the Niger Delta Basin, these MFSs and condensed sections provide the most useful correlation horizons. They are identified by microfossil population and diversity peaks, intervals of high gamma-ray values, and on seismic by regional downlap surfaces (Galloway, 1989; Armentrout, 1991). Regional correlation, together with seismic imaging, provides an understanding on how sedimentary stacking patterns can be used to predict the distribution and development of reservoirs in undrilled areas (C. T. Williams et al., 1997).
Figure 6. Regional well correlation across line AA′. Correlation is flattened at a depth of 1219 m (4000 ft). The correlation indicates syndepositional listric faulting, which gives room for accommodation space along depositional dip toward the basin. Refer to regional map shown in Figure 1B for AA′ section location. F = fault; GR = gamma-ray log; HST = highstand systems tract; IR = Iroro; LST = lowstand systems tract; MFS = maximum flooding surface; OG = Ogheneovo; SB = sequence boundary; TSE = transgressive surface of erosion; TST = transgressive systems tract; TV = Tovo.
Sequence Stratigraphic Framework
Seismic sequence interpretation of composite seismic in line and cross line with well intersection for calibration also revealed clear evidence of four mappable, third-order seismic sequences that are consistent with those already delineated from wells (Figure 8). Each seismic sequence comprises a relatively conformable succession of strata bounded at its top and base by unconformities (Vail, 1987; Van Wagoner et al., 1988; Vail et al., 1991) (Figure 8). The wells in this study area did not penetrate down to 13.1 Ma SB (Figure 8).
Figure 7. Regional well correlation across southeast-northwest. Correlation flattened at depth 1219 m (4000 ft). The correlation reflects that the depositional strike rarely exhibits faulting. Refer to regional map shown in Figure 1B for section southeast-northwest location. EB = Eboh; EM = Emebradu; EP = Ekpetiudi; GR = gamma-ray log; HST = highstand systems tract; IM = Imoni; LST = lowstand systems tract; MFS = maximum flooding surface; SB = sequence boundary; TSE = transgressive surface of erosion; TST = transgressive systems tract; TV = Tovo.
Sequence 1 formed the deepest depositional sequence bounded at the base by 13.1 Ma SB (not penetrated by the drilled wells) and at the top by 12.1 Ma SB (Figure 6–8). This sequence consists of transgressive systems tract (TST) and highstand systems tract (HST) separated by the 12.8 Ma MFS. The 12.8 Ma MFS, which is a regional marker, is defined by Cassidulina 7 and the occurrence of the bioevent within the P788 and F900 biozones (Figure 4, Figure 5). The TST contained marine shale rich in faunal and condensed section that housed the 12.8 Ma MFS. The paleobathymetric data show that the TST composed of alternating sand–shale units was in the outer-margin shelf setting during a phase of relative sea-level rise. It is made up of higher-order retrogradational, aggradational, and progradational sandstone successions (Figure 4). The HST of the depositional sequence is deposited in the inner–middle shelf setting (Figure 4) and is mainly made up of deposits of progradational to aggradational stacking pattern sandstone units that were deposited during a phase of relative sea-level rise.
Figure 8. Seismic profile across the depositional-dip transect. (A) Uninterpreted section. (B) Interpreted seismic section that indicates the presence of distinct geometries in each sequence and fault-controlled sequence stratigraphic architecture in the study area. Gamma-ray wire-line log to seismic calibration is based on available check-shot data (Tovo [TV]–09). This was used to establish the chronostratigraphic surfaces and the systems tracts on the seismic. Refer to Figure 4 and 6 for sequence stratigraphic analysis and regional correlation respectively. HST = highstand systems tract; LST = lowland systems tract; MFS = maximum flooding surface; NW = northwest; SB = sequence boundary; SE = southeast; TSE = transgressive surface of erosion; TST = transgressive systems tract.
Sequence 2 is bounded at the top and base by 10.35 and 12.1 Ma SB, respectively (Figure 6–8). The depositional sequence consists of a thick incised valley-fill lowstand system tracts (LST) overlain by TST and HST, separated by correlative TSE-1 and 11.5 Ma MFS, respectively (Figure 6, 7). The LST is made up of aggradational sandstone units of varying thickness from well to well (Figure 6, 7). The incision of the shoreface sandstone marks the end of a fall in sea level (end of sequence 1), where accommodation was less than the volume of sediment supplied to the basin and the onset of sea-level rise. The TST and HST are separated by the 11.5 Ma MFS defined by the regional marker Serravalian 3, Dodo Shale, and the occurrence of the bioevent within the P770 and F9500 biozones (Figure 5). The TST contained marine shale rich in faunal and condensed section that housed the 11.5 Ma MFS. The paleobathymetry data show that the TST of this depositional sequence was deposited in the inner–middle shelf settings (Figure 4), which is largely made up of higher-order retrogradational, with minor progradational, sandstone units (Figure 6, 7).
Sequence 3 is bounded at the top and base by 8.5 and 10.35 Ma SB, respectively (Figure 6–8). The depositional sequence consists of LST overlain by thin TST that thickened toward the basin (Figure 6). The HST is separated by a correlative surface of a TSE-2 and 9.5 Ma MFS (a regional marker, Tortonian, Uvigerina, and the occurrence of the bioevent within P788 and F900 biozones) (Figure 5).
Sequence 4 overlay the 8.5 Ma SB, which defines the change from shallow marine to littoral and continental fluvial–coastal plain facies represented by the Agbada–Benin Formation lithostratigraphic boundary.
Depositional geometries such as onlap and truncation from seismic lines reveal clear evidence for SB, whereas downlaps were used to interpret MFS (Figure 8). An SB is established between prograding deltaic system and the lowstand delta; this is interpreted as a prograding deltaic system that was cut or incised by the lowstand delta. The MFS found to correspond with trough amplitude of high continuous reflection across the region, associated with downlap (Figure 8). The MFS is interpreted as a surface of deposition at the time the shoreline is at its maximum landward position (Posamentier and Allen, 1999), formed after an earlier retrogradation period that directly followed sea-level lowstands.
The MFS and condensed sections are also identified on seismic data by very strong regional continuous reflection regionally (Figure 8). Toward the base of the seismic sections, a regional continuous trough amplitude reflection with evidence of downlapping clinoforms is interpreted to be the 12.8 Ma MFS, which correlates with the interval of abundant Cassidulina characteristic of benthonic paleoecological bottom-water conditions setting (Figure 4, Figure 5). At the middle of the seismic sections, a regional, continuous, high-trough amplitude reflection interpreted to be the 11.5 Ma MFS (Figure 8) correlates with an interval of the Dodo Shale (Nonion 4) (Figure 4, 5). The top regional, continuous, high-trough amplitude reflection between 1.25 and 1.5 s on the seismic sections (Figure 8), correlates with an interval of abundant Uvigerina characteristic of rotaliid benthonic dweller that corresponds to the condensed section that housed the 9.5 Ma MFS (Figure 4, Figure 5).
Tectono-Sedimentary and -Stratigraphy
Observation on the representative seismic profile shows that the relatively steep basinward listric faulting and sequences thicken seaward. The correlation across the depositional dip indicates progressive extensional synsedimentary tectonics, which gives rise to characteristic down-the-basin curved fault planes with depth (Figure 8). This suggests that accommodation is controlled by structural deformational events supposed to eustasy as the absolute control, as reported by previous works (Lindsay et al., 1987; Vail et al., 1991; Devlin et al., 1993; Christie-Blick and Driscoll, 1995).
Lateral variation in sequence thickness along the depositional dip is strongly controlled by fault growth with remarkable index (Figure 8). Here, fault growth index is the ratio of the thickness of the downthrown block sequence to that of the corresponding upthrown block sequence (Whiteman, 1982). The sequence stratigraphic architecture shows strong cyclicity exhibited by the fault growth index of approximately equal to 1.5, transgressive–regressive sequences defined by MFS and SB relationships (Figure 8). This suggests that changes in sea level and sediment loading were the dominant controlling factors that interplayed as a viable mechanism to cyclically initiate growth faulting. Sea-level fall, increase in sediments influx, or a combination of the two mechanisms caused delta progradation onto mud-prone shelf (C. T. Williams et al., 1997). Sand influx and loading onto undercompacted muds reactivated growth-fault movement, which eventually gave room for an increase in accommodation space in the downthrown blocks (Figure 8). Long periods of reduced accommodation exposed the shelf to erosion, which extended basinward, following the regressing shoreline. This is in progress, with a high rate of influx of fluvial sediments that incised the shelf deposits and created the SB (Figure 8).
The less-faulted lower sequence designated as sequence 1, characterized by subparallel, parallel with chaotic reflections and variation in amplitude (Figure 8; Table 1), is interpreted to be channel–levee elements (Cadena and Slatt, 2013). It is predicted to consist predominantly of muds and very fine-grained sand facies within the shelf marginal–slope setting and deduced to be related to lithologically controlled event (Figure 8; Table 1). The clay and silt with less sand sequence provided a plastic with less-brittle deformation mechanism, described as shale tectonics, which gave rise to the highly basinward listric faulting observed in the section (Figure 8; Table 1).
High-density distribution of antithetic and synthetic faults in sequences 2 and 3 is characterized by subparallel, discontinuous-to-chaotic reflection and subparallel to parallel, continuous, low-to-high-amplitude reflection, respectively (Figure 8; Table 1). They are formed within the middle–inner shelf setting and represent a delta with increasing complexity as a result of depositional loading triggered by depositional or gravitational tectonics. Generally, stimulated lithologically by alternating sand–shale shelf facies sequences, rendering a mechanical stratigraphy that gave rise to the crestal faulting (Figure 8; Table 1). The stratigraphic and structural relationship of the upper sequences with sand-prone depositional settings are deduced to be related to high-rate sediments influx and more sedimentation at the distal to the proximal, with less accommodation with a resultant creation of the K-faulting (a special type of closely spaced multiplicity flank faults with relative narrow blocks) during this phase (Figure 8).
The uppermost sequence, sequence 4, with no faulting represents a postgravitational or posttectonic depositional sequence that is predominantly fluvial–coastal plain sand facies (Figure 8). This sequence is associated with moderate to high parallel reflection (Figure 8; Table 1) that corresponds with relative thick sandstone and siltstone facies (Escalante, 2005). Truncation of the underlying sequence is observed before transgression onlaps and establishes a base level for fluvial–coastal plain sand progradation, which marks the boundary between the Benin–Agbada Formations (Figure 8).
Figure 9. Type-log showing fourth-order cycles sand packages at different stratigraphic level broken into small-scale transgressive-regressive (fourth-order) cycles with tops, flooding surface (FS) that corresponds to minimum resistivity value and maximum density-neutron separation. The FS-n/TSE-n used here as names of different sandstone units, where n is numeric. DEN = density log; DT = sonic log; F. Div = foraminifera diversity; F. Pop = foraminifera population; F-Zone = foraminifera zone; GR = gamma-ray log; HST = highstand systems tract; IN = inner neritic; INDET = indeterminate; LLD = resistivity log; MFS = maximum flooding surface; NEU = neutron log; ON = outer neritic; P-Zone = palynological zone; Paleoba. = paleobathymetry; S. Tract = systems tract; SB = sequence boundary; SHIN = shallow inner neritic; SSTVD = subsea true vertical depth; Transg–Reg = transgressive–regressive; TSE = transgressive surface of erosion.
Fourth-Order Sequence and Reservoir Sandstones
Within the framework of the third-order systems tracts, the sand-shale stacking patterns relationships further revealed the existence of multiple higher cyclicity events that are interpreted as fourth-order sequences (Figure 9). Higher-order sequences of the prograding deltaic systems are mainly recognized by coarsening-upward log motif; retrograding deltaic systems recognized by fining-upward log motif that overlies a shallower water facies; and aggradational deltaic system (lowstand deposit), associated with clinoforms to subparallel to parallel and truncated seismic reflections, respectively. Individual higher-order sequences in the third-order depositional systems were recognized by a coarsening-upward log motif interpreted as shoreface sandstone, followed by a fining-upward log interpreted as channel sandstone facies (Zeng et al., 2007). The fining-upward and blocky log motif is predicted as stacked channels associated with relative lowstand, aggradational stacking pattern. The individual reservoir sandstone top which corresponds to flooding surfaces (FS) was delineated using minimum resistivity and neutron-density logs separation (Figure 9). Based on electrofacies, three major potential reservoir types were predicted in the study area; these include stacked channel sandstone, shoreface sandstone, and heterolith facies (Table 2). The stacked channel sandstone facies are related to the channel-fill deposits. Stacked channel sandstone are reservoirs thicker than 14 m (45 ft) and possibly represent composite bodies or series of channel sandstones (Doust and Omatsola, 1989). Generally, the reservoir sandstone units in the study area are appreciably thicker than 23 m (75 ft) (Figure 10–13). Based on reservoir geometry and quality, the most important reservoir types in the Niger Delta coastal swamp are point bars of distributary channels and coastal barrier bars intermittently cut by sand-filled channels (Kulke, 1995). In this work, they were easily identified on seismic data because of their appreciable thickness and incision on lower sequence, which is characterized by high-amplitude chaotic reflection (Figures 14A, 15. The heterolithic facies is related to levee deposits composed of alternating sandstone–siltstone–shale interbeds and associated with semicontinuous reflectivity of moderate amplitude. The shoreface sandstone facies are widely distributed across the area of study but difficult to identify on seismic because of their relatively reduced thickness. Identification of these facies was based on their association with other depositional features: occurrence below channel incisions and downlapping onto underlying surfaces, which corresponds to seismic packages with lenticular shape with moderate amplitude reflection (Figure 14).
Figure 10. Stratigraphic cross section of the FS-15 reservoir sand along depositional dip and strike (northwest-southeast) in Tovo (TV) principal field. The correlations are flattened on the reservoir top. This elucidates the reservoir distribution, architecture, and facies succession. Note the positions of the wells on the reservoir thickness map (Figure 13A). Chan. Sst = channel sandstone; FS = flooding surface; GR = gamma-ray log; LSF = lower shoreface; Marine S = marine shale; MFS = maximum flooding surface; NEU/NEU_COR/NEUT = neutron log; RT = resistivity log; SB = sequence boundary; SSTVD = subsea true vertical depth; TSE = transgressive surface of erosion; USF = upper shoreface.
Seismic reflection characteristics and reservoir facies relationships with sandstone thickness distribution map of individual fourth-order sequence revealed the impact of sea-level changes on the channel sandstone and shelf deposits distribution (Figure 13, 16). Sand FS-15, FS-14, and TSE-1, which correspond with fourth-order sequences, were selected for reservoir studies in this work based on their sea-level fluctuation characteristic indicators (Figure 9), such as stacking patterns, facies homogeneity, reflection patterns, depositional incisions, and/or erosional surfaces.
Figure 11. Stratigraphic cross section of the FS-14 reservoir sand along depositional dip and strike (northwest–southeast) in Tovo (TV) field. The correlations are flattened on the reservoir top. This elucidates the reservoir distribution, architecture, and facies succession. Note the positions of the wells on the reservoir thickness map (Figure 13B). Chan. Sst = channel sandstone; FS = flooding surface; GR = gamma-ray log; LSF = lower shoreface; Marine S = marine shale; MFS = maximum flooding surface; NEU/NEU_COR/NEUT = neutron log; RT = resistivity log; SB = sequence boundary; SSTVD = subsea true vertical depth; TSE = transgressive surface of erosion; USF = upper shoreface.
The FS-15 reservoir sand has near tabular geometry along strike is related to retrogradational sand deposits (Figure 13A). Predicted to have been actively influenced by marine processes when there was a relative increase in sea level and accommodation space was greater than sediment supply (Figure 16A). This allowed reservoir deposits to be composed of heterogeneous mixtures of lower and upper shoreface or radioactive sand, intrareservoir marine shale, and channel sandstone facies, predicted to be amalgamated channels sandstone (Figure 10, 16A; Table 2). The amalgamated channel sandstone, FS-15 reservoir, has an average thickness of 38 m (125 ft). It is located in the third-order sequence 2 and is overlain by a major marine shale of the 11.5 Ma MFS (Figure 9). It can be subdivided into two subunits by a laterally persistence intrareservoir marine shale of approximately 1- to 3-m (∼3–10-ft)-thick with FS (Figure 10). Low variations in log character associated with this intrareservoir shales suggest the latter does not constitute a barrier to fluid flow (Ogbe, 2018) (Figure 10). Both the basal and the upper sequences of the FS-15 sandstone are composed of shoreface radioactive sandstone and channel sandstone facies as the overlying deposit intermittently (Figure 10). This implies the sediment has been reworked and influenced by marine dominated processes. Marine shale within the upper subsequence occurs generally in the margins of channel sandstone facies (Figure 10), indicating the deposit was submerged by seawater (Figure 16A). Generally, the vertical facies relationships of this reservoir facies suggest an increase in water depth, either directly across a FS or a transgressive, upward-deepening succession bounded below by a wave ravinement surface (Swift, 1968). This can be observed on correlation panel where channel sandstone of this reservoir spans across the depositional strike and less in the depositional dip (Figure 6, 7, 15).
Figure 12. Stratigraphic cross section of the TSE-1 reservoir sand along depositional dip and strike (northwest–southeast) in Tovo (TV) field. The correlations are flattened on the reservoir top. This elucidates the reservoir distribution, architecture, and facies succession. Note the positions of the wells on the reservoir thickness map (Figure 13C). Chan. Sst = channel sandstone; FS = flooding surface; GR = gamma-ray log; LSF = lower shoreface; Marine S = marine shale; MFS = maximum flooding surface; NEU/NEU_COR/NEUT = neutron log; RT = resistivity log; SB = sequence boundary; SSTVD = subsea true vertical depth; TSE = transgressive surface of erosion; USF = upper shoreface.
Figure 13. Isopachous map of the individual sandstone facies with well locations and wet status. Refer to the stratigraphic cross sections of the reservoir sandstone bodies, shown in Figure 10–12. (A) Flood surface (FS)-15 sandstone thickness map reveals the reservoir is tabular in geometry. (B) The FS-14 sandstone thickness map reveals the reservoir is lobate in geometry. (C) Transgressive surface of erosion-1 sandstone thickness map reveals the reservoir is bulge in geometry. TV = Tovo.
In contrast, reservoir FS-14 sand unit with lobate geometry is related to progradational sand deposition (Figure 13B). Predicted to have been dominated by fluvial processes when there was a relative drop in sea level, it is characterized by deposits of shoreface that were incised by relatively thick stacked channel sandstone that is relatively homogeneous in facies across individual wells (Figures 11, 16B; Table 2). It is located in the third-order sequence 2 and is capped by a fourth-order marine shale that separates it from the FS-15 reservoir sand (Figure 9). The reservoir has an average thickness of 50 m (165 ft) and is characterized by intervening shales that are not generally persistent or correlatable across individual wells (Figure 11). The intervening shales are predicted not to be barriers during production and may reduce water coning. This is attributed to the reservoir fluid showing similar contacts across individual wells that contain hydrocarbon accumulations. The basal facies of the reservoir is mainly lower and upper shoreface sandstone facies with an average thickness of 8 to 14 m (26 to 46 ft) across the depositional dip and depositional strike transects, respectively, which shows a remarkable lateral continuity across the study area (Figure 11). The upper facies is dominated by channel sandstone facies with an average thickness of 41 m (135 ft) along the depositional dip and changes to channel heterolith facies laterally toward the basin (Figure 11). This suggests the sediment to be a coastal deposit that is strongly influenced by fluvial dominated processes (Figure 12B) (Ogbe, 2018). Across strike, the channel deposit thickness ranges from 12 to 24 m (40 to 80 ft), and it is poorly developed in the southeast of the TV field. This suggests less-fluvial processes or channel incision in the southeast of the TV field during the development of the reservoir. Generally, the FS-14 sand reservoir thickness and facies development vary laterally across the different fields and faults (Figure 6, 7, 15).
Figure 14. Well data correlation in Tovo (TV) field. (A) Reservoir top and base mapped on a seismic section with wells control along line Tovo -01, TV-02, TV-03, TV-06, and TV-09. This allows for reservoir structural maps interpretation used in generation of thickness distribution maps of the reservoirs, displayed in Figure 13. (B) Field dip structural cross section showing individual reservoir thickness with growth faults. (C) Structural depth surface maps of flooding surface (FS)-15, FS-14, and TSE-1 reservoir sandstone. MFS = maximum flooding surface; SB = sequence boundary; TSE = transgressive surface of erosion; TWT = two-way traveltime.
Figure 15. Well to seismic correlation across individual fields in the western coastal swamp depobelt. Gamma-ray (GR) wire-line log to seismic calibration is based on available check-shot data. (A) Composite seismic profile along depositional dip, which revealed the relationship between depositional facies and seismic reflection pattern: flooding surface (FS)-15 sand associated with subparallel to parallel reflection, FS-14 sand associated with clinoform to subparallel reflection, and transgressive surface of erosion (TSE) sand associated with chaotic reflection. Note the reflection pattern inserts in Figure 16. Reservoir tops also map on the section, indicating reservoir not extensive along depositional dip in the region. (B) Composite seismic profile along depositional strike with reservoir tops mapped on the section, indicating lateral extension along depositional strike in the region. EB = Eboh; EM = Emebradu; EP = Ekpetiudi; IM = Imoni; IR = Iroro; MFS = maximum flooding surface; OG = Ogheneovo; SB = sequence boundary; TV = Tovo; TWT = two-way traveltime.
Consequently, the TSE-1 reservoir sand is predicted to be formed during a phase when there was a drastic fall in sea level and accommodation was less than sediment influx. The reservoir has a bulge geometry that is related to aggradation with little or no marine influence (Figure 13C). Thus, a relatively much thicker homogeneous stacked channel sandstones overlying shoreface sandstone facies was developed (Figure 12, 13C, 16C). The reservoir has an average thickness of approximately 128 m (∼420 ft) and is characterized by relatively thin intervening shales that are not laterally persistent (Figure 12). It could be divided into two subsequences by the 12.1 Ma SB that is associated with a laterally persistent intrareservoir marine shale of up to approximately 3 m (∼10 ft) thick (Figure 12). The basal sequence of the TSE-1 reservoir formed the upper sand unit of the third-order sequence 1 that comprises a lower and upper shoreface sandstone facies of variable thickness ranging from approximately 12 to 31 m (∼40 to 100 ft) (Figure 12). The overlying reservoir succession formed the basal sandstone unit of the third-order sequence 2 and is the major reservoir that is dominated by incised channel-fill deposits with appreciable thickness. This indicates the transport of substantial sediment volumes with high erosion capacity on the shelf (Figure 12C). The intrareservoir shale between the shoreface and the channel deposits suggests incision and subsequent abandonment of deep channels that were not confined to the stratigraphic level at the top of the underlying sequence (Hampson et al., 2011). This idea is also supported by the presence of a relatively thin bed of radioactive sand overlying the SB in wells TV-02, TV-04, and TV-10 (Figure 12). This reservoir facies development is near constant across individual field and thickness varies across faults (Figure 13, 14). H. Williams et al. (1997) suggested the main phase of growth faulting was triggered by high rates of sedimentation near the river mouth with an increase in subsidence rates caused by spontaneous sediment loading. Shoreface deposits are better developed and distributed in the downthrown block where accommodation space is created.
Figure 16. Conceptual depositional model of predicted reservoir sand bodies geometry. Stacking patterns and distribution is based on seismic imaging, facies succession, and sandstone thickness distribution maps. In each panel, reservoir type log, dip-oriented cross section, and reservoir geometry are shown. (A) The flooding surface (FS)-15 reservoir facies succession have been developed at the phase of relative sea-level rise with less sediment supply into the basin. Sand distribution geometry is tabular associated with shoreface and amalgamated channel sandstones, characterized by subparallel–parallel reflection on seismic. (B) The FS-14 reservoir facies succession is predicted to have deposited at the phase of relative sea-level fall with high rate of influx of fluvial sediment into the basin. Lobate sandstone distribution geometry is associated with shoreface sandstone incised by channel-fill deposit, characterized by clinoform and subparallel reflection. (C) Transgressive surface of erosion (TSE)-1 reservoir facies succession, have been deposited at the phase when sedimentation greater than accommodation space with excessive supply of fluvial sediment into the basin. Lobate sandstone distribution geometry is associated with shoreface deposits stacked on by erosionally based multistory channel sandstones. It is characterized by chaotic reflection on the seismic section. GR = gamma-ray log; MFS = maximum flooding surface.
The relationship between sandstone thickness and faulting suggests that the reservoir sands were deposited when the major faults were active or triggered by sediment loading. This is attributed to the significant growth in thickness on the hanging-wall reservoirs with respect to footwall reservoirs. Insignificant growth on hanging wall in relation to footwall block of the minor faults (Figure 14B, C), which indicates the reservoir sediments were deposited before or when most of the associated synthetic and antithetic faults were inactive. It is expected in extensional settings that stratigraphic thickness is significantly greater along depositional dip toward the basin when its development is contemporary with active growth faulting (Figure 17). Lateral variation in reservoir thickness is highly dependent on growth faults, and the reservoir thickens toward the fault plane within the hanging-wall block (Weber Daukoru, 1975).
Figure 17. Block diagram of distribution of reservoir facies, geomorphology and trapping mechanism within the Cenozoic Niger Delta coastal zone (modified from Weber, 1971; Reijers, 2011). FS = flooding surface; HST = highstand systems tract; LST = lowland systems tract; MFS = maximum flooding surface; SB = sequence boundary; TSE = transgressive surface of erosion; TST = transgressive systems tract.
Implications for Petroleum Exploration
Potential reservoirs occur within anticlinal closures that coincide with sediment accommodation centers throughout the coastal swamp depobelt. Characteristically, the area is highly faulted, and reservoir units are inverted against growth-fault planes and juxtaposed against marine shale facies, thus offering good seal and trap potential (Figure 17). Petroleum accumulations are predicted to be trapped against these growth faults and within the series of antithetic faults downthrown in a northeast direction (Figures 8, 14). The antithetic faults provide the footwall traps for sequence 1 and reservoir of sequence 2, whereas the main synthetic faults could provide downthrown traps for the deeper potential reservoirs. The primary seal rock is the interbedded shales within the Agbada Formation (Figure 17). Doust and Omatsola (1989) noted that the shales provide three types of seals: clay smears along faults, interbedded sealing units that the reservoir sandstone are juxtaposed against because of faulting, and vertical seals. Bounding synthetic faults formed during the early phase of the growth faults, and the later-formed antithetic faults offer good hydrocarbon leads and possible prospects (Figure 18). The petroleum system source rocks in this area possibly include variable contributions from the marine interbedded shale of the Agbada Formation (Figure 17), the marine Akata Shale, and possible deeper Cretaceous shale that may exist at depth (Weber Daukoru, 1975; Lambert-Aikhionbare and Ibe, 1984; Doust and Omatsola, 1989; Stacher, 1995; Haack et al., 1997).
Figure 18. Example of potential exploration play. (A) Seismic section across depositional dip showing wedge associated clinoforms and interpreted event, XY of possible hydrocarbon leads. Location of XY cross section for Figure 19 is marked. (B) Depositional model of predicted reservoir sands engaged by faults depended rollover anticlinal. Thick marine shales above and below sand bodies constitute the potential seals. A–D = predicted potential reservoir sand units; MFS = maximum flooding surface; SB = sequence boundary; XY = cross-line that marks event surface.
The established relationship between depositional features and seismic imaging unraveled exploration opportunities in the deeper section of the area of interest where stratistructural imaging is complex (Figure 14). The deeper section (sequence 1) representing the outer shelf–shelf margin is characterized by series of foreset and bottomset of clinoforms. These depositional features apparently form gigantic sedimentary wedge geometries (Figure 18A). This architectural unit is predicted to be composed of progradational shoreface sediments and highstand aggradational stacked channel sandstone succession with good reservoir potential (Figure 18B). These channelized sandstone units (designated as A, B, C, and D) are encased in marine shales, which are inferred to be the source rock feeding these channel sandstones (Figure 18B). Additionally, the closures on the downthrown block adjacent to the observed reservoir sandstone units are inverted against fault planes with low net-to-gross ratio and, therefore, offer good seal and trap potential. Based on the presence of these petroleum system elements, these channelized sandstone units are interpreted as possible exploration targets (red horizon in Figure 18A). The predicted sand C, which exhibits a better seismic image of clinoforms, is associated with a large fault–dependent rollover anticline structure. This structure has a high potential of engaging a large volume of sand in a three-way closure (Figure 19A), which offers good hydrocarbon leads and possible prospects within an estimated depth range of 4039 to 4953 m (∼13,250 to 16,250 ft) (Figure 19B). It shows spill point at 4343 m (14,250 ft) and a relief of 305 m (1000 ft) (Figure 19B). The amplitude extraction attribute map reveals strong amplitudes that are fairly conformable with the structures (Figure 19C). Amplitude-versus-offset modeling that can determine if the source of the amplitude anomaly is lithology or charge; fault sealing integrity and geometry associated with these predicted reservoirs need to be validated to derisk the possible exploration targets predicted before embarking on drilling.
Figure 19. Possible exploration target opportunity predicted based on depositional features and seismic imaging relationships. Refer to Figure 18. (A) Interpreted predicted sand C time structural surface (XY) map that revealed sand-rich reservoir unit with fault dependent rollover anticlinal closure associated with bounded faults. (B) Depth structural surface map of the interpreted surface that revealed hydrocarbon lead structural closure features such as the spill point, crest, and relief (highlighted in orange coloration). (C) Supported extract amplitude map that shows booming extractions that are fairly conformable with structures.
1. Four third-order seismic depositional sequences of Serravallian age were identified in the western coastal swamp depobelt of the Niger Delta, Nigeria. Sequence 1 was deposited in outer shelf–shelf margin environments and experienced shale tectonics (ductile deformation). Both sequence 2 and sequence 3 experienced gravitational tectonics and were deposited in middle shelf–inner shelf setting and inner shelf–transitional setting, respectively. Sequence 4 corresponds to continental sediments that represent postgravitational tectonics deposit.
2. Higher-order (fourth-order) depositional sequences were distinguished within each third-order sequence and subdivide the stratigraphic levels (systems tracts) into genetically related sandstone units that potential reservoir and distribution became more predictable within. In the study area, reservoir units are essentially shoreface deposits stacked by channel sandstone that have been influenced either by fluvial or marine processes.
3. Three types of fourth-order depositional sequences were recognized based on their sand-distribution patterns. Lowstand deposits display a bulge geometry. Transgressive deposits are represented by strike-oriented tabular sand geometry. Highstand deposits are characterized by dip-oriented lobate sand geometry.
4. Variability in thickness across depositional-dip transect and near uniform across strike transect within the different sequences suggests synchronism between sea-level fall and sedimentary processes in the initiation of depositional tectonism, whereas eustatic impact appears secondary in the western coastal swamp depobelt of the Niger Delta Basin, Nigeria.
5. Relative increase in HST thickness and growth across faults within the sequences suggests increase in accommodation space and sediments influx in the generation of the structural traps. Combination of depositional and structural play concept impacts the ability to image potential reservoirs, traps, and exploration prospect identification in the deeper section of the study area.
6. Seismic imaging revealed that the depositional facies are correlative with seismic facies that are environmentally controlled. The sandstone compartmentalization is largely depositionally controlled within the sandstone–shale–sandstone–shale shelf succession; thus, the stratigraphic framework and structural styles are important to the development of good hydrocarbon leads and prospects.
7. Presence and absence of hydrocarbon accumulations in reservoirs of the same stratigraphic unit penetrated by wells suggest that the reservoirs of the coastal swamp depobelt of the Niger Delta Basin are structurally and stratigraphically controlled.
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This work is part of the research work of the first author and was done while carrying out his research internship program at Shell Petroleum Development Company (SPDC) in Port Harcourt, Nigeria. Special thanks to SPDC for providing the data sets, facilities, and the enabling environment to carry out the research work. Special thanks are extended to Nick Hoggmascall and Kelly Maguire at SPDC Exploration and Geological Services Teams for their brilliant amiable supervision and knowledge shared in the course of the research program. Sincere appreciation also goes to the SPDC Exploration Team, especially the following individuals: Adelola Adesida, Afolabi Fatunmbi, Otuka Umahi, Owen Ovwigho Irifeta, Daniel A. Daniel, and Kate Iwe and Okiemute Amuboh of the Development Team who have provided the technical background to the research here presented. The authors express thanks to C. S. Nwajide for constructive review of the manuscript. The authors are very appreciative of AAPG Editor Barry J. Katz, Andreas F. Cadena, and three other anonymous reviewers for their insightful and constructive comments, which have greatly improved the quality of the manuscript.