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Sequence stratigraphic interpretation of parts of Anambra Basin, Nigeria using geophysical well logs and biostratigraphic data
Accepted Manuscript Sequence stratigraphic interpretation of parts of Anambra Basin, Nigeria using geophysical well logs and biostratigraphic data
E.K. Anakwuba, N.E. Ajaegwu, C.F. Ejeke, C.U. Onyekwelu, A.I. Chinwuko PII:
S1464-343X(17)30491-0
DOI:
10.1016/j.jafrearsci.2017.12.018
Reference:
AES 3099
To appear in:
Journal of African Earth Sciences
Received Date:
31 March 2017
Revised Date:
16 December 2017
Accepted Date:
18 December 2017
Please cite this article as: E.K. Anakwuba, N.E. Ajaegwu, C.F. Ejeke, C.U. Onyekwelu, A.I. Chinwuko, Sequence stratigraphic interpretation of parts of Anambra Basin, Nigeria using geophysical well logs and biostratigraphic data, Journal of African Earth Sciences (2017), doi: 10.1016/j.jafrearsci.2017.12.018
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GRAPHICAL ABSTRACT
Fig. 16: Sequence stratigraphic framework of the wells showing reservoir continuity and formation tops within the interpreted system tracts
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Sequence Stratigraphic Interpretation of parts of Anambra Basin, Nigeria Using Geophysical Well Logs and Biostratigraphic Data lAnakwuba,
E. K., lAjaegwu, N. E., lEjeke, C. F. 2Onyekwelu, C. U. and 3Chinwuko, A. I.
1Department
of Geological Sciences, Nnamdi Azikiwe University Awka, Nigeria 2Sunlink Petroleum Limited, Nigeria; 3Department of Geological Sciences, Federal University Gusau, Nigeria
E-mails: [email protected], [email protected], [email protected], , [email protected], and [email protected]
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Abstract
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The Anambra basin constitutes the southeastern lower portion of the Benue Trough, which is a large structural depression that is divided into lower, middle and upper parts; and is one of the least studied inland sedimentary basins in Nigeria. Sequence stratigraphic interpretation had been carried out in parts of the Anambra Basin using data from three wells (Alo-1 Igbariam-1 and Ajire-1). Geophysical well logs and biostratigraphic data were integrated in order to identify key bounding surfaces, subdivide the sediment packages, correlate sand continuity and interpret the environment of deposition in the fields. Biostratigraphic interpretation, using foraminifera and plankton population and diversity, reveals five maximum flooding surfaces (MFS) in the fields. Five sequence boundaries (SB) were also identified using the well log analysis. Four 3rd order genetic sequences bounded by maximum flooding surfaces (MFS-1 to MFS-6) were identified in the areas; four complete sequences and one incomplete sequence were identified in both Alo-1 and Igbariam-1 wells while Ajire1 has an no complete sequence. The identified system tracts delineated comprises Lowstand Systems Tracts (progradational to aggradational to retrogradational packages), Transgressive Systems Tracts (retrogradational packages) and Highstand Systems Tracts (aggradational to progradational packages) in each well. The sand continuity across the fields reveal sands S1 to S5 where S1 is present in Ajire-1 well and Igbariam-1 well but not in Alo-1 well. The sands S4 to S5 run across the three fields at different depths. The formations penetrated by the wells starting from the base are; Nkporo Formation (Campanian), Mamu Formation (Late Campanian to Early Maastrichtian), Ajali Sandstone (Maastrichtian), Nsukka Formation (Late Maastrichtian to Early Palaeocene), Imo Formation (Palaeocene) and Nanka Sand (Eocene). The environments of deposition revealed are from coastal to bathyal. The sands of lowstand system tract and highstand system tract found in Ajali, Nsukka, Nkporo and Imo (Ebenebe Sandstone) Formations show good continuity and as such good reservoir qualities while the shales of the transgressive system tracts which includes the Imo Formation, Mamu, and Nkporo Formations where most of the maximum flooding surfaces were delineated, can serve as seals to the numerous reservoir units. Combinations of the reservoir sands of the lowstand system tract and highstand system tract and the shale units of the transgressive system tract can form good stratigraphic traps for hydrocarbon and hence should be hydrocarbon exploration targets.
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1.0 Introduction
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1.1 Background of the study
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There are seven sedimentary basins in Nigeria and Anambra Basin is one of the major in-land sedimentary basins. According to Akande and Ertmann (1998), the Anambra basin is part of the Benue Trough that is divided into lower, middle and upper parts; and whose genesis is related to the opening of the South Atlantic Ocean. Benkhelil (1989) discovered that the Benue Trough started during the geological period of the Lower Cretaceous in conjunction with the Atlantic Ocean opening. Thus, the Anambra Basin contains postdeformational Campanian - Maastrichtian to Eocene strata. The Anambra Basin is a synclinal structure consisting of more than 5,000 m thick of Upper Cretaceous to Recent sediments representing the third phase of marine sedimentation in the Benue Trough (Ladipo, 1988; Akande and Erdtmann, 1998) and covers an area of about 40,000 km2. Anambra Basin is the structural link between the Benue Trough and the Tertiary Niger Delta Basin which contains a large oil and gas reserve.
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Most sequence stratigraphic works done on the Anambra Basin were based on outcrop studies. Although, Nwajide (2013) interpreted some of the wells in the Anambra Basin, the sequence stratigraphic framework of the penetrated wells has not been constructed. The sequence stratigraphic framework would be however critical in understanding the hydrocarbon play-system within the basin. This shortcoming also impacted negatively on the understanding of the reservoir continuity as seen in the wells in the Anambra Basin. The reservoir continuity helps us to know the distribution of reservoirs across the wells/field/basin as the case may be. It is against this background that this study focuses on the integration of well logs and biostratigraphic data to interpret the sequence stratigraphy and reservoir continuity of the Igbariam-1, Alo-1 and Ajire-1 wells in the Anambra Basin.
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This is achieved using well logs and biostratigraphic data to interpret sequence stratigraphic surfaces of the study area, the environments of deposition, correlation of the wells, and the identification of reservoir continuity (Vail, 1987; Vail and Wornardt, 1991). Greater emphasis on interpretation of well logs and biostratigraphic information increases the resolution for prediction of reservoirs, seals and source rocks in the basin.
Oil and gas account for up to 95% of the Nigeria’s foreign earnings and has remained the major support of its economy since its discovery in commercial quantities in 1956. Nigeria’s oil and gas reserve estimates stand at about 34 billion barrels of oil and 170 trillion cubic feet of gas (Tuttle et al., 1999; Obaje et al., 2004). Several exploratory wells have been drilled by oil companies in the basin and three of these are Igbariam-1, Alo-1 and Ajire-1. Lack of detailed geologic information about the basin frustrates the efforts of explorers.
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1.2 Regional Geologic Setting
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The Anambra Basin constitutes the southeastern lower portion of the Benue Trough, which forms part of the Cretaceous structural depression and later rift basins that forms in West Africa. The Anambra basin represents about one tenth of the Benue Trough and is the least 2
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studied inland basin in Nigeria. It underlies the whole of Anambra State and parts of Abia, Enugu, Imo, Delta, Edo and Kogi States. The Anambra basin lies within longitudes 7o 00′E to 8o 00′E and latitudes 6o 30′N to 7o 30′N (Fig.1). It is located in the southern part of the regionally extensive Northeast -Southwest trending Benue Trough. Igbariam is located in Awka North, Anambra East local Government area along 6⁰24′ 0.0″N and 6⁰ 56′ 0″E. Alo is located along 6⁰ 05′N and 6⁰ 57′E. Alo is located 20 km north of Igbariam while Ajire is located 23 km west of Igbariam (Fig. 1).
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Fig.1: Locations of Existing Wells in the Anambra Basin (After Ekine & Onuoha, 2008).
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Nevertheless, the tectonic displacement of the axis of the Benin-Abakaliki Trough created three successive basins: the Anambra Basin, the Afikpo Syncline and the Niger Delta Basin (Murat, 1972).
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1.3 Outline stratigraphy of the Anambra Basin The stratigraphic succession of the Anambra Basin comprises of the Campanian to Maastrichtian Enugu/Nkporo/Owelli Formations (Fig. 2). The formations of the Campanian Nkporo Group reflect a shallow marine shelf. Extensive coastal swamps developed behind the poorly developed foreshores and shorefaces now known as the Enugu Shale. The Campanian was a period of short marine transgression and regression, thereby resulting in a regressive phase during the Maastrichtian which deposited the flood plain sediments and deltaic foresets of Mamu Formation that known as the Lower Coal Measures. Mamu Formation is overlain by the Ajali Formation (Obi, 2000) and followed by Nsukka Formation, a fluvio-deltaic sediment (Obi, 2000; Reyment, 1965; Obi et al., 2001). Obi et al., (2001) used sedimentological evidence to suggest that the Nsukka Formation represents a 3
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phase of fluvio-deltaic sedimentation. The Nsukka Formation (Paleocene) marks the onset of another transgression. The Imo Shales reflects shallow-marine shelf conditions in which foreshore and shoreface sands are occasionally preserved. The Imo Formation consists of blue-grey clays and shales and black shales with bands of calcareous sandstone, marl, and limestone (Reyment, 1965). Similarly, the Fika Shale which is a member of the Gongola SubBasin of Benue Trough consists of bluish-greenish carbonaceous with greatly fissile shales and rare limestones preserved (Petters and Ekweozor, 1982). Furthermore, the Cretaceous Ostracods biostratigraphy and foraminiferal biostratigraphy (Reyment, 1965), and microfauna recovered from the basal limestone unit (Adegoke et al., 1980) indicate a Paleocene age for the formation. The Eocene Ameki Group marks the return to regressive conditions.
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Fig. 2: Geological sketch map of the Anambra basin (Igwe et al, 2013).
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2.0 Data and Methodology
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2.1 Available Data
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The data available are the biostratigraphic and well log data from three different wells. The data is obtained through drilled boreholes or wells. The biostratigraphic data contains information on plankton and foraminifera populations and diversities, biozones, as well as depth. The biozone records obtained from the wells were the palynological and foraminiferal zones referred to as the P- and F- Zones. Five different pollen zones (P-Zones) and three fauna zones (F-Zones) recognized were P420, P370, P330, P200, and P100, and F3700 and F3500, and F1700 respectively. The logs available are the gamma ray log, sonic log, 4
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resistivity log, spontaneous potential log, density log, neutron log, and caliper log. Table 1 shows the logs availability for this project.
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2.2 Methodology
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Biostratigraphic and well log analyses were used in the interpretation of the subsurface sequence stratigraphy of the area of interest in the Anambra Basin. The well log suites were displayed at consistent scales to enhance log trends and aid recognition of facies stacking patterns and parasequences. The stacking patterns were analyzed using the gamma ray logs (Fig. 3). Parasequence stacks (vertical occurrences of repeated cycles of coarsening or fining upwards sequences), gave rise to progradational, retrogradational, or aggradational parasequence sets (Fig. 3). This enabled the delineation of the sequences in the system tract such as the high systems tract, lowstand systems tract and the transgressive systems tract.
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Gamma ray log signatures (fining and coarsening upward trends) in combination with the biofacies data, which was calibrated and depth matched with corresponding wireline logs, helped in determining lithofacies and depositional environments of the different rock units as seen in the field. Bell shaped log patterns on gamma ray logs indicates increasing clay contents up section or fining upward trends or an upward increase in gamma ray value, is a typical feature of fluvial channel deposits (Fig. 3). Funnel-shaped log patterns indicating decreasing clay contents up section or a coarsening upward trend, clearly showed deltaic progradation. Cylindrical (blocky or boxcar) log motif was delineated as thick uniformly graded coarse grained sand-stone unit, are probably deposits of braided channel, tidal channel or subaqueous slump deposits. Serrated log motif suggested intercalation of thin shales in a sandstone body, typically of fluvial, marine and tidal processes.
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Fig. 3: Gamma ray responses to variations in grain size and likely environment of deposition (Emery, 1996; Cant, 2002).
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More so, the Maximum Flooding Surfaces (MFSs) were identified in the wells using plots of pollen and foraminiferal abundant and diversity in Petrel. The MFSs were identified at depths with relative high abundance and diversity of pollen and forams and high gamma ray count 5
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(Fig. 4). MFSs are horizons of maximum transgression within a sequence (Van Wagoner et al. 1990). The sequence boundaries were also identified on the well logs using the gamma ray logs (Fig. 4). On the well logs, sequence boundaries were marked at the end of the highstand systems tract (HST) at the base of the thickest sand. The lowstand systems tract (LST) were identified at the proceeding sea level rise within the aggradational stacking pattern above the sequence boundary. The transgressive systems tracts (TST) were marked at the retrogradational stacking pattern with the sea level rise which terminated with the maximum flooding surfaces (MFS).
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Well correlation was achieved using interpreted surfaces (SBs and MFSs) of same geologic age and pattern defined within the study area. Marine flooding surfaces were the best markers on which the well correlation was based (Beka and Oti, 1995). This helps to determine lateral continuity or discontinuity of facies as well as aids reservoir continuity studies in the field.
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Fig. 4: Sequence stratigraphic model showing key stratigraphic surfaces and various systems tracts (Van Wagoner et al., 1988)
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3.0 Results and Discussion 3.1 Stratigraphic Surfaces 3.1.1 Maximum Flooding Surface (MFS) In Alo-1 and Igbariam-1wells MFS-1 was identified at 6,800 ft. and 8,498 ft. respectively (Fig. 5 & Fig. 6). In Alo-1 well, it occurred within the P200 biozone. The surface is clearly situated in a shale zone as seen in the log and is marked by high plankton and foraminifers’ population and diversity. MFS-2 at 5,300 ft. and 7,900 ft. respectively (Fig. 5 & 6) occurred in Alo-1 well within P200 biozones. There is an obvious reduction in planktonic population and diversity in Alo-1 well compared to Igbariam-1 well. MFS-3 was identified at 4,550 ft. and 7,200 ft. respectively (Fig. 5 & 6). The population and diversity of planktons and forams in Alo-1 well is seen to be higher than that in Igbariam-1 well. In Ajire-1 well, MFS’s 1, 2, and 3 were not recognized. This is because a younger formation was deposited in Ajire as a result the following maximum flooding surfaces was not penetrated by the well. MFS-4 was recognized in Alo-1 and Igbariam-1 wells at 3,750 ft. and 4,850 ft. respectively but was not identified in Ajire-1 well (Fig. 5 & 6). MFS-5 was identified in Alo -1 and Igbariam-1 wells at 1,100 ft., and 1,650 ft. respectively and both were defined within the F3500 biozone. MFS5 was not recognized in Ajire-1 well (Fig. 5 & 6). MFS-6 was recognized in only Ajire-1 well at 4,200 ft. occurring within the F3500 and P200 biozones. This key bounding surface was not seen in Alo-1 and Igbariam-1 wells (Fig. 4). 3.1.2 Sequence Boundaries (SB) SB-1 is the oldest sequence boundary identified in Alo-1 and Igbariam-1 wells at 7,250 ft., and 10,000 ft. respectively, and within the P200 and F1700 biozones respectively. This surface represents a subaerial erosional surface identified before the MFS-1 (Figs. 5 & 6). The sequence boundaries in this project are overlain by relatively sharp-based sand units identified as incised valley fills. The sand unit overlying SB-1 in Igbariam-1well is thicker than in Alo-1well due to local erosion of the sands at the onset of rising sea level and beginning of a retrogradational facies that starts with initial deposit erosion: the transgressive surface of erosion (TSE). SB-2 is identified in Alo-1 and Igbariam-1 wells at 5,700 ft. and 8,300 ft. respectively and within P200 biozone for the Alo-1 well. It occurs within a zone with appreciable faunal diversity (Figs. 5 & 6). SB-3 and SB-4 are identified at depths of 4,950 and 4,150 ft.s for Alo-1 well and 7,700 and 5,600 ft.s for Igbariam-1 well respectively. The sands overlying SB-4 down-dip at Igbariam-1well is thicker than that of Alo-1 well (Figs. 5 & 6). SB-5 is identified in the three wells (Figs. 5, 5 & 7). In Alo-1 well at 3,600 ft., Igbariam-1 well at 4,600 ft. and Ajire-1 well at 7,700 ft. In Ajire-1 well, SB-5 is found within the P100 biozone (Fig. 7).
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Fig. 5: Stratigraphic surfaces identified in Alo-1well.
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Fig 6: Bounding surfaces in Igbariam-1well
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Fig. 7: Stratigraphic surfaces identified in Ajire-1 well. 9
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3.1.3 Systems Tracts and Depositional Facies.
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Four complete genetic sequences and one incomplete sequence were recognized in both Alo1 and Igbariam-1 wells. The genetic sequences were identified using Galloway method (MFS – SB - MFS). The accompanying systems tracts were interpreted and mapped across the three wells, based on identified log motifs and the spatial distribution of the recognized stratigraphic surfaces (MFSs and SBs). First and fourth sequences formed the oldest and youngest depositional sequences respectively.
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3.1.3.1 Alo-1 Well
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Alo-1 well is composed of four complete sequences and one incomplete sequence (Fig. 8). It has five maximum flooding surfaces and five sequence boundaries. The formations found contained in it from total depth are; Nkporo, Mamu, Ajali, Nsukka and Imo Formations (Fig. 9).
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A sequence boundary SB-1 was identified and picked at the depth of 7,150 ft. It makes for the incomplete sequence. This incomplete sequence was interpreted in the Nkporo Shale in an environment ranging from coastal deltaic to bathyal. It was also interpreted in the P200 zone (Fig. 9).
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The first sequence is capped by MFS-1 at a depth of 6,800 ft. It is a complete sequence, mainly shaly and is about 1,500 ft. thick (Fig. 9). Environment of deposition is from the middle neritic to the bathyal and consists of sand and shale intercalations but mainly shales. The first sequence is bounded below and above by MFS-1 in Nkporo Shale and Mamu Formation and MFS-2 respectively. It is a complete sequence made of an HST and a TST (Fig. 9). In this sequence, fauna and plankton are present although there is not much plankton.
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The second sequence is about 2,297 ft. thick and bounded below and above by MFS-2 at the depth of 5,350 ft. and MFS-3 at 4,530 ft. respectively in Mamu Formation (Fig. 9). It is a complete sequence comprising shales and sandy-shale. The system tracts in this sequence are the HST, LST and the TST. There is high fauna diversity and population, high plankton diversity but low to absent plankton population. The environment of deposition ranges from middle neritic to bathyal.
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The third sequence is about 510 ft. thick and bounded below and above by MFS-3 at 4,530 ft. and MFS-4 at 4,020 ft. respectively (Fig 9). The Mamu Formation continues in this sequence. It is a complete sequence too comprising sandy- shale deposits. The environment of deposition ranges from inner neritic to bathyal. The system tracts identified in this sequence are the HST, LST and TST. High presence of foraminifers’ population and diversity with high plankton diversity was interpreted. The population of plankton is low.
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The fourth sequence is 3,010 ft. thick and bounded below and above by MFS-4 at 4,020 ft. and MFS-5 at 1,010 ft. respectively (Fig. 9). The sequence boundary SB-5 marks the entry into Ajali Formation. It is a complete sequence composed of thick sand resulting in a LST with little shale present. The system tracts in this sequence are the LST, HST, and TST. The gamma ray log shows the presence of tidal channel and incised valley fill in the Ajali 10
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Formation. Moving to the top, thick shale is present suggesting a change in environment which is the Nsukka Formation. It is composed of mainly shale with an intercalation of sand. In this sequence, there is very high fauna population and diversity with high plankton diversity in some places but low or absent plankton population. The Imo Formation overlies the Nsukka Formation. It is found above MFS-5 in the Alo-1 well.
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Fig. 8: Formations and systems tracts contained in Alo-1well.
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Fig. 9: A, Nkporo Shale. B, Mamu Formation, and C, Ajali Sandstone showing incised valley and tidal channels contained in it with the Nsukka and Imo Formation.
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Table 2: Summary of the Stratigraphy of Alo-1well. Depth (ft.)
Formation
Age
1,025 – 95 2,050 - 1,025
Imo Nsukka
3,600 - 2,050 5,700 - 3,600
Ajali Mamu
8,682 – 5,700
Nkporo Shale
Late Paleocene (Thanatian) Late Maastrichtian - Early Paleocene (Danian) Maastrichtian Late Campanian – Early Maastrichtian Campanian
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3.1.3.2 Igbariam-1 well
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The Igbariam-1 well encountered four sequences and one incomplete sequence (Fig. 10). Below the first interpreted sequence, at about 9,750 ft., is the first identified sequence boundary (SB-1) which is part of an incomplete sequence (Fig. 11). The environment of deposition of the incomplete sequence is from inner neritic shale to bathyal showing heterolithic turbidites interpreted to be the Nkporo Group deposited in an HST. Fauna diversity is present in this incomplete sequence.
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The first sequence identified in Igbariam-1 well is bounded above and below by MFS-2 and MFS-1 respectively. It is 598 ft. thick (Fig. 11). At 8,300 ft., SB-2 marks the beginning of the Mamu formation. It is mainly composed of marine shales with some sandstone deposits. This sequence was deposited from outer neritic to bathyal indicating the presence of shoreface 12
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sands and stacked turbidites of proximal lobes facies (Fig. 11). The system tracts here are the HST and TST but no LST. Fauna population and diversity is high. Plankton is absent. This sequence terminates at 7,900 ft.
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The second sequence which is a complete sequence is bounded below and above by MFS-2 and MFS-3 respectively (Fig. 11). It is about 700 ft. thick and is made up of a thick TST comprising of transgressive facies, and an HST comprising of sand and shale intercalations. The Mamu Formation continues in this sequence. This sequence was deposited from coastal deltaic to bathyal indicating tidal channel and coal deposits. Fauna population and diversity is higher here than the first sequence but still no plankton present. This sequence terminates at 7,200 ft.
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The third sequence is a complete one bounded above and below by MFS-4 and MFS-3 respectively (Fig. 12). It is 2,350 ft thick and consists of HST, TST and LST. The system tracts are complete in this sequence. This is still the Mamu Formation and this sequence was deposited in an environment ranging from coastal deltaic to bathyal indicating the presence of coal deposits in this formation. As the depth decreases, so does the population and diversity of fauna. The plankton population and diversity is nil. This sequence terminates at 4,850 ft.
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The fourth sequence, also a complete one is bounded below and above by MFS-4 and MFS-5 respectively (Fig. 11 and 12). It is 3,200 ft. thick and composed of HST, TST and LST. The system tracts are complete. From the depth of 4,850 ft. to 4,600 ft. is the Mamu formation terminating at 4,600 ft. (SB-5) (Fig. 12). The Ajali Formation begins at this depth in this sequence and is composed of an LST indicating an environment of deposition ranging from inner neritic to bathyal. In this environment, there are amalgamated coarse turbiditic and sandy channel fill facies. The fauna population and diversity increases with decrease in depth. The plankton population and diversity is absent here. The Ajali Formation terminates at 3,250 ft. marking the beginning of the Nsukka Formation (Fig. 12).
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The Nsukka Formation is composed of shales with sandstones and has an HST and TST system tracts contained in it (Fig. 12). This formation as seen on the log is 1,600 ft. thick. The environment of deposition ranges from shallow inner neritic to proximal fan. In this environment, there is high fauna and plankton population and diversity. It terminates at 1,650 ft. where the Imo Formation began. The sand lenses as seen on the gamma ray log is the Ebenebe Sandstone. This Sandstone was deposited in an environment ranging from inner neritic (fluvio-marine) to bathyal (Table 3). The fauna and plankton population and diversity are high up to the depth of 1,500 ft. where the fauna population and diversity reduces drastically while the plankton population reduces to nil.
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Fig. 10: Formations and systems tracts contained in Igbariam-1well.
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Fig. 11: A, reveals Nkporo Group and Owelli Sandstone with the interfingering Asata Shale in B. Facies like the tidal channels and submarine fan lobes were identified in Owelli Sandstone. C, is the Mamu formation with shoreface sands and stacked turbidites facies and coal deposits.
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Fig 12: E, Continuation of the Mamu Formation of Igbariam-1. F, Ajali Formation, Nsukka and Imo Formations. The Ebenebe Sand was identified in Imo Formation.
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Table 3: Summary of the stratigraphy of Igbariam-1 well. Depth (ft.) Formation Age 1,650 – 500 Imo Palaeocene 3,250 – 1,650 Nsukka Late Maastrichtian Palaeocene (Danian) 4,600 – 3,250 Ajali Maastrichtian 8,300 – 4,600 Mamu Late Campanian Maastrichtian 9,750 – 9,000 Owelli Sandstone Campanian 10,788 – 8,300 Nkporo Group Campanian
– –
Early Early
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3.1.3.3 Ajire-1 well
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The Ajire-1well has no complete sequence throughout its depth (Fig. 13). Only SB-5 and MFS-6 was identified in this well. Mostly LSTs and TSTs were identified along with three HSTs throughout the depth of the well. In this well, the fauna and plankton population and diversity are really high starting from the total depth drilled. The formations encountered in this well are the Mamu, Ajali, Nsukka, Imo Formations and Nanka Sand. SB-5 is at 7,700 ft. lying in Mamu Formation while MFS-6 is at 4,200 ft. in Imo Formation.
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From the base, at the depth of 8,300 ft. the Mamu Formation begins showing sand deposits shale deposits (Fig. 14A). The environment of deposition ranges from middle neritic to bathyal. The only system tract identified here is the highstand system tract (HST).The Mamu Formation ends at 7,700 ft. In this formation, there is high fauna population and diversity with high plankton diversity but low plankton population. 15
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Above the Mamu Formation, the Ajali Formation was encountered in the well to a depth of about 6,400 ft. (Fig. 14A). The environment of deposition ranges from middle neritic to bathyal and was deposited in TSTs and LSTs. It is made up of intercalations of sand and shale, while the identified facies includes heterolithic levee deposits. The fauna and plankton population and diversity in the Ajali Formation are high especially the fauna diversity.
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Fig. 13: Depositional facies of Ajire-1 showing component Formations.
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Fig. 14: A, Mamu Formation and Ajali Formation with heterolithic levee deposits as its facies. B, Nsukka Formation and Imo Formation with Ebenebe Sandstone. C, Nanka Sand of Ajire-1 well.
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Above the Ajali Formation, the Nsukka Formation was identified. It was deposited within the coastal deltaic to bathyal environments and composed of shale and sand. It was deposited in an HST and TST (Fig.14A). The fauna and plankton population and diversity are high. It terminated at 5,555 ft.
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Above the Nsukka Formation, the Imo Formation was encountered and was deposited in an environment ranging from coastal deltaic to bathyal (Fig. 14B and C). The identified facies here are shaly sand, sand and shale. The system tracts identified in this formation are TST and LST. The fauna and plankton population and diversity are high up to the depth of 4,255 ft. where it reduces drastically. From the depth to the top, the fauna diversity remains high with little presence of the others. It terminates at 4,150 ft.
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In the Ajire-1 well, above the Imo Formation is the Nanka Sand of the Ameki Group (Table 4). The Nanka Sand continues to the start depth which is 500 ft. The environment of deposition ranges from coastal deltaic to bathyal. The facies identified here are sand and sandy shale. The system tracts identified are the LST, HST and TST. Fauna and plankton population and diversity become high at 2,555 ft. and reduce significantly at 1,900 ft.
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Table 4: Summary of the stratigraphy of Ajire-1 well. Depth(ft.) Formation 4,150- 500 5,555 – 4,150 6,400 – 5,555
Nanka Sand Imo Nsukka
7,700 – 6,400 8,300 – 7,700
Ajali Mamu
Age Eocene Paleocene (Thanatian) Late Maastrichtian – Early Paleocene (Danian) Maastrichtian Late Campanian – Early Maastrichtian
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3.2 Sequence Stratigraphic Correlation Not all the key bounding surfaces (MFS and SB) could be correlated across the three wells. MFS-1 to MFS-5 could only be correlated across Alo-1 and Igbariam-1 wells at different depths. Sequence boundaries SB-1 to SB-4 could only be correlated across Alo-1 and Igbariam-1 wells. Both Alo-1 and Igbariam-1 well have four complete sequences and one incomplete sequence. Ajire-1 well has only an incomplete sequence.
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The correlation across the three wells (Fig.15) revealed the Nkporo Group (Nkporo Shale and Owelli Sandstone), Mamu, Ajali, Nsukka and Imo Formations in Alo-1 and Igbariam-1 wells. However, while the Owelli Sandstone was identified in Igbariam-1 well, the Nkporo Shale was identified in Alo-1 well and thus the two wells correlate well. Also, the Ajire-1 well correlates well with the other two wells from the Mamu to Imo Formations (Fig. 15).
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Fig. 15: Sequence stratigraphic surfaces correlation across the three wells.
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3.3 Reservoir Continuity
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A reservoirs’ area of coverage is often indicated by the lateral continuity of sand bodies and this is critical to robust hydrocarbon volume calculation. Identified sand bodies across the three wells were classified stratigraphically as S1 to S5 (Fig.15).
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Sands S1 was found to be in Alo-1 and Igbariam-1 wells. In Alo-1 well, it was interpreted within the depth of 7,000 ft. to 7,500 ft. within a TST. Below this sand is SB-1 and after a few ft. is MFS-1. In Igbariam-1 well, it was interpreted to start from SB-1 at 10,000 ft. to 9,000 ft. This sand is very thick compared to that in Alo-1 well. This sand occurred in an LST and was identified as the Owelli Sandstone where the tidal channel fills, the submarine fan lobe and the Asata Shale was interpreted.
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Sands S2 was found in both Alo-1 and Igbariam-1 wells. In Alo-1 well, it was interpreted within 5,650 ft. to 5,050 ft. SB-2 marks the existence of S2 and this sand was found in a TST. It is a part of the Mamu Formation. In Igbariam-1 well, it was interpreted within 8,600 ft. to 18
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7,500 ft. and is thicker compared to that in Alo-1 well. It occurred in the three system tractsHST, TST and LST. It is also a part of the Mamu Formation.
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Sands S3 was interpreted in both Alo-1 and Igbariam-1 wells within 5,000 ft. to 4,300 ft. and 6,300 ft. to 5,800 ft. respectively. Both sands are in the Mamu Formation. In Igbariam-1 well, coal deposits and tidal channel sands were interpreted. In Alo-1 well, it was deposited in both an LST and TST while in Igbariam-1 well, it deposited in an HST. The sands in Alo-1 well are thicker than that in Igbariam-1well.
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Sands S4 was interpreted across the three wells. In Alo-1well, it is within 4,200 ft. to 3,600 ft. and still interpret as the Mamu formation, capped by SB-5. It was deposited within a TST and HST. In Igbariam-1 well, it is within 5,100 ft. to 4,150 ft. and is interpreted as the Mamu formation. It occurs within an HST, TST and LST. In Ajire-1 well, it is within 8,300 ft. to 8,200 ft. and is considered a part of the Mamu Formation. It occurs within an HST.
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Sands S5 was correlated across the three wells and interpreted as the Ajali Formation. In Alo1 well, it was deposited within an LST from 3,600 ft. to 2,050 ft. and tidal channels and incised valley was interpreted in it. In Igbariam-1 well, it was deposited within an LST from 4,600 ft. to 3,250 ft. and turbiditic channel fills was interpreted in it. In Ajire-1 well, it was deposited in both an LST and heterolithic levee deposits were interpreted here.
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Fig 16: Sequence stratigraphic framework of the wells showing reservoir continuity and formation tops within the interpreted system tracts.
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4.0 Conclusions
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Key bounding surfaces in the three wells have been identified along with the system tracts, environments of deposition and reservoirs. Four complete sequences and one incomplete sequence were interpreted in both Alo-1 and Igbariam-1 wells. Ajire-1 well has no complete sequence. Five maximum flooding surfaces (MFS-1 to MFS-5) were interpreted in both Alo1 and Igbariam-1 wells while only MFS-6 was interpreted in Ajire-1 well. Four sequence 19
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boundaries (SB-1 to SB-4) were interpreted in both Alo-1 and Igbariam-1 wells and SB-5 was interpreted only in Ajire-1 well.
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The integrated results aided in identifying the play elements that contain the reservoirs. Five reservoir sands were identified and marked. They were interpreted at different depths in Nkporo, Owelli, Mamu and Ajali Formations, representing TSTs, LSTs and HSTs. Sands S1 to S3 were interpreted across Alo-1 and Igbariam-1 wells while S4 and S5 were interpreted across the three wells.
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Sand S1 was interpreted within a TST in a middle neritic environment and is capped by shale deposited within an HST and is 250 ft. thick in Alo-1 well while in Igbariam-1 well, it was interpreted to be deposited in an LST as heterolithic turbidites in shallow marine to bathyal environments, capped by shale within a TST and is 1,000 ft. thick. The shales of the TST and HST will serve as a good seals for the sands.
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Sand S2 was interpreted to be deposited within a TST in a coastal deltaic to bathyal environments and is capped by shale deposited in an HST which is 300 ft. thick in Alo-1 well while in Igbariam-1 well, it was interpreted to be deposited within a TST, HST, and LST as channels and submarine fan lobes in a coastal deltaic to bathyal environments and is capped by shale deposited in a TST. This sand is 650 ft. thick. The shales of the TST and HST will serve as good seals.
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Sands S3 was deposited within an LST in an outer neritic to bathyal environments and is capped by shale deposited in an HST which is 550 ft. thick in Alo-1 well while in Igbariam-1 well, it was interpreted to be deposited in an HST which was found to be associated with coal deposits interpreted in the shales interbedded in the sand in a coastal deltaic to bathyal environments which is capped with the shales of an HST. The sand in the HST is 250 ft. thick. The shales of the HSTs in both wells will serve as seals.
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Sand S4 was deposited within an HST in a middle neritic environment and is capped by shale deposited in a TST and is 50 ft. thick in Alo-1 well while in Igbariam-1 well, it was interpreted to be deposited in an LST associated with stacked turbidites of proximal lobes and shoreface sands in an outer neritic to bathyal environments. This LST is capped by shales of the TST and is 350 ft. thick. The shales of the TSTs in both wells will serve as good seals. In Ajire-1 well, it was interpreted to be deposited within an HST in a bathyal environment and is capped by shales of an HST.
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Sands S5 was interpreted to be deposited within an LST which was associated with tidal channels and incised valleys in middle neritic to bathyal environments. This sand is 1,650 ft. thick and is capped by shales within a TST in Alo-1 well while in Igbariam-1 well, it was interpreted in an LST as amalgamated coarse turbiditic sandy channel fills in a coastal deltaic to bathyal environments. This sand is capped by shales of a TST and is 1,300 ft. thick. In Ajire-1 well, it was interpreted to be deposited in an LST as heterolithic levee deposits in coastal to bathyal environments. This sand is 1,300 ft. thick and is capped by shale within an HST.
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5.0 Recommendation
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The sands of LST and HST revealed in Ajali, Mamu, Nkporo and Imo (Ebenebe Sand Member) Formations show good continuity and as such, good reservoir qualities, while the shales of the TSTs which include the Imo Formation, Mamu, and Nkporo Formations can serve as seals to the numerous reservoir units.
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Acknowledgements
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Special thanks go to the Management of Department of Petroleum Resources (DPR), PortHarcourt, Nigeria, for approving the permission to use the data set for this study. We remain grateful to the staff of the Departmental of Geological Sciences, Nnamdi Azikiwe University, Awka, Nigeria for granting access to their work stations as well as their technical inputs.
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References
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Adegoke , O.S., Ako, B.D., and Enu, E.I., 1980. Geotechnical investigations of the Ondo State bituminous sands. Vol. 1., Geology and reserve estimate. Rept. Geological Consulting Unit, Dept. of Geology, University of Ife, pp 257.
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Akande, S. O. and Erdtmann, B. D., 1998. Burial metamorphism (thermal maturation) in Cretaceous sediments of the Southern Benue Trough and Anambra Basin, Nigeria. American Association of Petroleum Geologists Bulletin, 82: 1191-1206.
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Beka, F.T., and Oti, M.N.; 1995. The distal offshore Niger delta: frontier prospects of a mature petroleum provice, in Oti, M.N., and Postma, G., (Eds.), Geology of Deltas: Rotterdam, A.A. Balkema, pp. 237-241.
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Benkhelil, J., 1989. The origin and evolution of the Cretaceous Benue Trough (Nigeria). Journal of African Earth Sciences, 8: 251-282.
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Cant, D. J., 2002. Subsurface facies analysis. Geology Survey of Canada, Alberta 1, pp.27-44
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Emery, D., Myers, K.J., 1996. Sequence Stratigraphy. Oxford, U.K., Blackwell, 297 p.
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Igwe, O., Okechukwu, N., and Adepehin, E. J., 2013. Assesment of Asbestos Waste Dumpsite in Enugu Metropolis, South-Easthern Nigeria: Implications for Environmental Concern. Nigeria Journal of Education, Health and Technology Research (NJEHETR), 4(4): 146-158.
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Ladipo, K. O., 1988. Paleogeog raphy, sedimentation and tectonics of the Upper Cretaceous Anambra Basin, south-eastern Nigeria. Journal of African Earth Sciences, 7: 865-871. Murat, R. C., 1972. Stratigraphy and Paleogeography of the Cretaceous and lower Tertiary in Southern Nigeria in: Dessauvagie, T. F. J. (Ed.) Nwajide, C. S., 2013, Geology of Nigeria’s Sedimentary Basins. CSS Bookshop Limited Lagos, 365p. 21
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Obaje, N. G., Wehner, H., Scheeder, G., Abubakar, M. B., Jauro, A., 2004. Hydrocarbon prospectivity of Nigeria’s inland basins: From the view point of organic geochemistry and organic petrology. American Association of Petroleum Geologists Bulletin, 8(3): 325-353. Obi, G. C., 2000, Depositional model for the Campanian‑Maastrichtian Anambra Basin, Southern Nigeria. Ph.D. Thesis, University of Nigeria, Nsukka, Nigeria. Obi, G. C., Okogbue, C. O. and Nwajide, C. S., 2001, Evolution of the Enugu Cuesta: A tectonically driven erosional process. Global Journal Pure Applied Sciences, 7(2): 321-330. Petters, S. W., and Ekweozor, C. M., 1982. Petroleum Geology of Benue Trough and Southeastern Chad Basin. AAPG Bulletin, 66 (8): 1141-1149. Reyment, R. A., 1965, Aspects of the Geology of Nigeria: The Stratigraphy of the Cretaceous and Cenozoic Deposits. Ibadan University Press, 145p. Tuttle, M.L.W., Charpentier, R.R. and Brownfield, M.E., 1999. The Niger delta petroleum system: Niger delta province, Nigeria, Cameroon, and Equatorial Guinea, Africa: USGS Open-file report 99-50-H. Vail, P.R., 1987. Seismic stratigraphy interpretation procedure, in A.W. Bally, eds., Atlas of seismic stratigraphy, volume 1: AAPG Studies in Geology, 27: 1-10.
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Vail, P.R., and Wornardt, W., 1991. An integrated approach to exploration and development in the 90s: Well-log seismic sequence stratigraphy analysis. Transactions of the Gulf Coast Association of Geological Societies, 41: 630-650.
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Van Wagoner, J.C., Posamentier, H.W., Mitchum, R.M., Vail, P.R., Sarg, J.F., Loutit, T.S., and Hardenbol, J., 1988. An overview of sequence stratigraphy and key definitions, in C. W. Wilgus et al., eds., Sea level changes: An integrated approach: Society of Economic Paleontologists and Mineralogists Special Publication, 42: 39–45.
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Van Wagoner, J.C., Mitchum Jr., R.M., Campion, K.M., and Rahmanian, V.D., 1990. Siliciclastic sequence stratigraphy in well logs, core, and outcrops: concepts for highresolution correlation of time and facies. American Association of Petroleum Geologists Methods in Exploration Series 7, 55p.
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ACCEPTED MANUSCRIPT HIGHLIGHT FROM Sequence Stratigraphic Interpretation of Parts of Anambra Basin Using Well Logs and Biostratigraphic Data
1. Biostratigraphic interpretation, using foraminifera and plankton population and 2.
3.
4.
5.
6. 7.
8.
diversity, reveals five maximum flooding surfaces (MFS) in the fields. Five sequence boundaries (SB) were also identified using the well log analysis. Four 3rd order genetic sequences bounded by maximum flooding surfaces (MFS-1 to MFS6) were identified in the areas; four complete sequences and one incomplete sequence were identified in both Alo-1 and Igbariam-1 wells while Ajire-1 has an incomplete sequence with no complete sequence. The identified system tracts delineated comprises Lowstand Systems Tracts (progradational to aggradational to retrogradational packages), Transgressive Systems Tracts (retrogradational packages) and Highstand Systems Tracts (aggradational to progradational packages) in each well. The sand continuity across the fields reveal sands S1 to S5 where S1 is present in Ajire-1 well and Igbariam-1 well but not in Alo-1 well. The sands S4 to S5 run across the three fields at different depths. The formations penetrated by the wells starting from the base are; Nkporo Formation (Campanian), Mamu Formation (Late Campanian to Early Maastrichtian), Ajali Sandstone (Maastrichtian), Nsukka Formation (Late Maastrichtian to Early Palaeocene), Imo Formation (Palaeocene) and Nanka Sand (Eocene). The environments of deposition revealed are from coastal to bathyal. The sands of lowstand system tract and highstand system tract found in Ajali, Nsukka, Nkporo and Imo (Ebenebe Sandstone) Formations show good continuity and as such good reservoir qualities while the shales of the transgressive system tracts which includes the Imo Formation, Mamu, and Nkporo Formations where most of the maximum flooding surfaces were delineated, can serve as seals to the numerous reservoir units. Combinations of the reservoir sands of the lowstand system tract and highstand system tract and the shale units of the transgressive system tract can form good stratigraphic traps for hydrocarbon and hence should be hydrocarbon exploration targets.
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Table 1: Data Availability for the Study WELLS
Ajire-1
Igbariam-1
Alo-1
Well Logs
Biostratigraphic data
Caliper
Gamma Ray
SP
Sonic
Resistivity
Density
Neutron
√
√
√
√
√
√
х
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
NB: √ shows available data; х shows unavailable data
E.K. Anakwuba, N.E. Ajaegwu, C.F. Ejeke, C.U. Onyekwelu, A.I. Chinwuko PII:
S1464-343X(17)30491-0
DOI:
10.1016/j.jafrearsci.2017.12.018
Reference:
AES 3099
To appear in:
Journal of African Earth Sciences
Received Date:
31 March 2017
Revised Date:
16 December 2017
Accepted Date:
18 December 2017
Please cite this article as: E.K. Anakwuba, N.E. Ajaegwu, C.F. Ejeke, C.U. Onyekwelu, A.I. Chinwuko, Sequence stratigraphic interpretation of parts of Anambra Basin, Nigeria using geophysical well logs and biostratigraphic data, Journal of African Earth Sciences (2017), doi: 10.1016/j.jafrearsci.2017.12.018
This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.
GRAPHICAL ABSTRACT
Fig. 16: Sequence stratigraphic framework of the wells showing reservoir continuity and formation tops within the interpreted system tracts
ACCEPTED MANUSCRIPT 1 2 3 4 5 6 7 8
Sequence Stratigraphic Interpretation of parts of Anambra Basin, Nigeria Using Geophysical Well Logs and Biostratigraphic Data lAnakwuba,
E. K., lAjaegwu, N. E., lEjeke, C. F. 2Onyekwelu, C. U. and 3Chinwuko, A. I.
1Department
of Geological Sciences, Nnamdi Azikiwe University Awka, Nigeria 2Sunlink Petroleum Limited, Nigeria; 3Department of Geological Sciences, Federal University Gusau, Nigeria
E-mails: [email protected], [email protected], [email protected], , [email protected], and [email protected]
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Abstract
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The Anambra basin constitutes the southeastern lower portion of the Benue Trough, which is a large structural depression that is divided into lower, middle and upper parts; and is one of the least studied inland sedimentary basins in Nigeria. Sequence stratigraphic interpretation had been carried out in parts of the Anambra Basin using data from three wells (Alo-1 Igbariam-1 and Ajire-1). Geophysical well logs and biostratigraphic data were integrated in order to identify key bounding surfaces, subdivide the sediment packages, correlate sand continuity and interpret the environment of deposition in the fields. Biostratigraphic interpretation, using foraminifera and plankton population and diversity, reveals five maximum flooding surfaces (MFS) in the fields. Five sequence boundaries (SB) were also identified using the well log analysis. Four 3rd order genetic sequences bounded by maximum flooding surfaces (MFS-1 to MFS-6) were identified in the areas; four complete sequences and one incomplete sequence were identified in both Alo-1 and Igbariam-1 wells while Ajire1 has an no complete sequence. The identified system tracts delineated comprises Lowstand Systems Tracts (progradational to aggradational to retrogradational packages), Transgressive Systems Tracts (retrogradational packages) and Highstand Systems Tracts (aggradational to progradational packages) in each well. The sand continuity across the fields reveal sands S1 to S5 where S1 is present in Ajire-1 well and Igbariam-1 well but not in Alo-1 well. The sands S4 to S5 run across the three fields at different depths. The formations penetrated by the wells starting from the base are; Nkporo Formation (Campanian), Mamu Formation (Late Campanian to Early Maastrichtian), Ajali Sandstone (Maastrichtian), Nsukka Formation (Late Maastrichtian to Early Palaeocene), Imo Formation (Palaeocene) and Nanka Sand (Eocene). The environments of deposition revealed are from coastal to bathyal. The sands of lowstand system tract and highstand system tract found in Ajali, Nsukka, Nkporo and Imo (Ebenebe Sandstone) Formations show good continuity and as such good reservoir qualities while the shales of the transgressive system tracts which includes the Imo Formation, Mamu, and Nkporo Formations where most of the maximum flooding surfaces were delineated, can serve as seals to the numerous reservoir units. Combinations of the reservoir sands of the lowstand system tract and highstand system tract and the shale units of the transgressive system tract can form good stratigraphic traps for hydrocarbon and hence should be hydrocarbon exploration targets.
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1.0 Introduction
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1.1 Background of the study
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There are seven sedimentary basins in Nigeria and Anambra Basin is one of the major in-land sedimentary basins. According to Akande and Ertmann (1998), the Anambra basin is part of the Benue Trough that is divided into lower, middle and upper parts; and whose genesis is related to the opening of the South Atlantic Ocean. Benkhelil (1989) discovered that the Benue Trough started during the geological period of the Lower Cretaceous in conjunction with the Atlantic Ocean opening. Thus, the Anambra Basin contains postdeformational Campanian - Maastrichtian to Eocene strata. The Anambra Basin is a synclinal structure consisting of more than 5,000 m thick of Upper Cretaceous to Recent sediments representing the third phase of marine sedimentation in the Benue Trough (Ladipo, 1988; Akande and Erdtmann, 1998) and covers an area of about 40,000 km2. Anambra Basin is the structural link between the Benue Trough and the Tertiary Niger Delta Basin which contains a large oil and gas reserve.
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Most sequence stratigraphic works done on the Anambra Basin were based on outcrop studies. Although, Nwajide (2013) interpreted some of the wells in the Anambra Basin, the sequence stratigraphic framework of the penetrated wells has not been constructed. The sequence stratigraphic framework would be however critical in understanding the hydrocarbon play-system within the basin. This shortcoming also impacted negatively on the understanding of the reservoir continuity as seen in the wells in the Anambra Basin. The reservoir continuity helps us to know the distribution of reservoirs across the wells/field/basin as the case may be. It is against this background that this study focuses on the integration of well logs and biostratigraphic data to interpret the sequence stratigraphy and reservoir continuity of the Igbariam-1, Alo-1 and Ajire-1 wells in the Anambra Basin.
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This is achieved using well logs and biostratigraphic data to interpret sequence stratigraphic surfaces of the study area, the environments of deposition, correlation of the wells, and the identification of reservoir continuity (Vail, 1987; Vail and Wornardt, 1991). Greater emphasis on interpretation of well logs and biostratigraphic information increases the resolution for prediction of reservoirs, seals and source rocks in the basin.
Oil and gas account for up to 95% of the Nigeria’s foreign earnings and has remained the major support of its economy since its discovery in commercial quantities in 1956. Nigeria’s oil and gas reserve estimates stand at about 34 billion barrels of oil and 170 trillion cubic feet of gas (Tuttle et al., 1999; Obaje et al., 2004). Several exploratory wells have been drilled by oil companies in the basin and three of these are Igbariam-1, Alo-1 and Ajire-1. Lack of detailed geologic information about the basin frustrates the efforts of explorers.
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1.2 Regional Geologic Setting
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The Anambra Basin constitutes the southeastern lower portion of the Benue Trough, which forms part of the Cretaceous structural depression and later rift basins that forms in West Africa. The Anambra basin represents about one tenth of the Benue Trough and is the least 2
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studied inland basin in Nigeria. It underlies the whole of Anambra State and parts of Abia, Enugu, Imo, Delta, Edo and Kogi States. The Anambra basin lies within longitudes 7o 00′E to 8o 00′E and latitudes 6o 30′N to 7o 30′N (Fig.1). It is located in the southern part of the regionally extensive Northeast -Southwest trending Benue Trough. Igbariam is located in Awka North, Anambra East local Government area along 6⁰24′ 0.0″N and 6⁰ 56′ 0″E. Alo is located along 6⁰ 05′N and 6⁰ 57′E. Alo is located 20 km north of Igbariam while Ajire is located 23 km west of Igbariam (Fig. 1).
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Fig.1: Locations of Existing Wells in the Anambra Basin (After Ekine & Onuoha, 2008).
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Nevertheless, the tectonic displacement of the axis of the Benin-Abakaliki Trough created three successive basins: the Anambra Basin, the Afikpo Syncline and the Niger Delta Basin (Murat, 1972).
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1.3 Outline stratigraphy of the Anambra Basin The stratigraphic succession of the Anambra Basin comprises of the Campanian to Maastrichtian Enugu/Nkporo/Owelli Formations (Fig. 2). The formations of the Campanian Nkporo Group reflect a shallow marine shelf. Extensive coastal swamps developed behind the poorly developed foreshores and shorefaces now known as the Enugu Shale. The Campanian was a period of short marine transgression and regression, thereby resulting in a regressive phase during the Maastrichtian which deposited the flood plain sediments and deltaic foresets of Mamu Formation that known as the Lower Coal Measures. Mamu Formation is overlain by the Ajali Formation (Obi, 2000) and followed by Nsukka Formation, a fluvio-deltaic sediment (Obi, 2000; Reyment, 1965; Obi et al., 2001). Obi et al., (2001) used sedimentological evidence to suggest that the Nsukka Formation represents a 3
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phase of fluvio-deltaic sedimentation. The Nsukka Formation (Paleocene) marks the onset of another transgression. The Imo Shales reflects shallow-marine shelf conditions in which foreshore and shoreface sands are occasionally preserved. The Imo Formation consists of blue-grey clays and shales and black shales with bands of calcareous sandstone, marl, and limestone (Reyment, 1965). Similarly, the Fika Shale which is a member of the Gongola SubBasin of Benue Trough consists of bluish-greenish carbonaceous with greatly fissile shales and rare limestones preserved (Petters and Ekweozor, 1982). Furthermore, the Cretaceous Ostracods biostratigraphy and foraminiferal biostratigraphy (Reyment, 1965), and microfauna recovered from the basal limestone unit (Adegoke et al., 1980) indicate a Paleocene age for the formation. The Eocene Ameki Group marks the return to regressive conditions.
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Fig. 2: Geological sketch map of the Anambra basin (Igwe et al, 2013).
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2.0 Data and Methodology
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2.1 Available Data
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The data available are the biostratigraphic and well log data from three different wells. The data is obtained through drilled boreholes or wells. The biostratigraphic data contains information on plankton and foraminifera populations and diversities, biozones, as well as depth. The biozone records obtained from the wells were the palynological and foraminiferal zones referred to as the P- and F- Zones. Five different pollen zones (P-Zones) and three fauna zones (F-Zones) recognized were P420, P370, P330, P200, and P100, and F3700 and F3500, and F1700 respectively. The logs available are the gamma ray log, sonic log, 4
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resistivity log, spontaneous potential log, density log, neutron log, and caliper log. Table 1 shows the logs availability for this project.
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2.2 Methodology
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Biostratigraphic and well log analyses were used in the interpretation of the subsurface sequence stratigraphy of the area of interest in the Anambra Basin. The well log suites were displayed at consistent scales to enhance log trends and aid recognition of facies stacking patterns and parasequences. The stacking patterns were analyzed using the gamma ray logs (Fig. 3). Parasequence stacks (vertical occurrences of repeated cycles of coarsening or fining upwards sequences), gave rise to progradational, retrogradational, or aggradational parasequence sets (Fig. 3). This enabled the delineation of the sequences in the system tract such as the high systems tract, lowstand systems tract and the transgressive systems tract.
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Gamma ray log signatures (fining and coarsening upward trends) in combination with the biofacies data, which was calibrated and depth matched with corresponding wireline logs, helped in determining lithofacies and depositional environments of the different rock units as seen in the field. Bell shaped log patterns on gamma ray logs indicates increasing clay contents up section or fining upward trends or an upward increase in gamma ray value, is a typical feature of fluvial channel deposits (Fig. 3). Funnel-shaped log patterns indicating decreasing clay contents up section or a coarsening upward trend, clearly showed deltaic progradation. Cylindrical (blocky or boxcar) log motif was delineated as thick uniformly graded coarse grained sand-stone unit, are probably deposits of braided channel, tidal channel or subaqueous slump deposits. Serrated log motif suggested intercalation of thin shales in a sandstone body, typically of fluvial, marine and tidal processes.
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Fig. 3: Gamma ray responses to variations in grain size and likely environment of deposition (Emery, 1996; Cant, 2002).
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More so, the Maximum Flooding Surfaces (MFSs) were identified in the wells using plots of pollen and foraminiferal abundant and diversity in Petrel. The MFSs were identified at depths with relative high abundance and diversity of pollen and forams and high gamma ray count 5
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(Fig. 4). MFSs are horizons of maximum transgression within a sequence (Van Wagoner et al. 1990). The sequence boundaries were also identified on the well logs using the gamma ray logs (Fig. 4). On the well logs, sequence boundaries were marked at the end of the highstand systems tract (HST) at the base of the thickest sand. The lowstand systems tract (LST) were identified at the proceeding sea level rise within the aggradational stacking pattern above the sequence boundary. The transgressive systems tracts (TST) were marked at the retrogradational stacking pattern with the sea level rise which terminated with the maximum flooding surfaces (MFS).
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Well correlation was achieved using interpreted surfaces (SBs and MFSs) of same geologic age and pattern defined within the study area. Marine flooding surfaces were the best markers on which the well correlation was based (Beka and Oti, 1995). This helps to determine lateral continuity or discontinuity of facies as well as aids reservoir continuity studies in the field.
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Fig. 4: Sequence stratigraphic model showing key stratigraphic surfaces and various systems tracts (Van Wagoner et al., 1988)
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3.0 Results and Discussion 3.1 Stratigraphic Surfaces 3.1.1 Maximum Flooding Surface (MFS) In Alo-1 and Igbariam-1wells MFS-1 was identified at 6,800 ft. and 8,498 ft. respectively (Fig. 5 & Fig. 6). In Alo-1 well, it occurred within the P200 biozone. The surface is clearly situated in a shale zone as seen in the log and is marked by high plankton and foraminifers’ population and diversity. MFS-2 at 5,300 ft. and 7,900 ft. respectively (Fig. 5 & 6) occurred in Alo-1 well within P200 biozones. There is an obvious reduction in planktonic population and diversity in Alo-1 well compared to Igbariam-1 well. MFS-3 was identified at 4,550 ft. and 7,200 ft. respectively (Fig. 5 & 6). The population and diversity of planktons and forams in Alo-1 well is seen to be higher than that in Igbariam-1 well. In Ajire-1 well, MFS’s 1, 2, and 3 were not recognized. This is because a younger formation was deposited in Ajire as a result the following maximum flooding surfaces was not penetrated by the well. MFS-4 was recognized in Alo-1 and Igbariam-1 wells at 3,750 ft. and 4,850 ft. respectively but was not identified in Ajire-1 well (Fig. 5 & 6). MFS-5 was identified in Alo -1 and Igbariam-1 wells at 1,100 ft., and 1,650 ft. respectively and both were defined within the F3500 biozone. MFS5 was not recognized in Ajire-1 well (Fig. 5 & 6). MFS-6 was recognized in only Ajire-1 well at 4,200 ft. occurring within the F3500 and P200 biozones. This key bounding surface was not seen in Alo-1 and Igbariam-1 wells (Fig. 4). 3.1.2 Sequence Boundaries (SB) SB-1 is the oldest sequence boundary identified in Alo-1 and Igbariam-1 wells at 7,250 ft., and 10,000 ft. respectively, and within the P200 and F1700 biozones respectively. This surface represents a subaerial erosional surface identified before the MFS-1 (Figs. 5 & 6). The sequence boundaries in this project are overlain by relatively sharp-based sand units identified as incised valley fills. The sand unit overlying SB-1 in Igbariam-1well is thicker than in Alo-1well due to local erosion of the sands at the onset of rising sea level and beginning of a retrogradational facies that starts with initial deposit erosion: the transgressive surface of erosion (TSE). SB-2 is identified in Alo-1 and Igbariam-1 wells at 5,700 ft. and 8,300 ft. respectively and within P200 biozone for the Alo-1 well. It occurs within a zone with appreciable faunal diversity (Figs. 5 & 6). SB-3 and SB-4 are identified at depths of 4,950 and 4,150 ft.s for Alo-1 well and 7,700 and 5,600 ft.s for Igbariam-1 well respectively. The sands overlying SB-4 down-dip at Igbariam-1well is thicker than that of Alo-1 well (Figs. 5 & 6). SB-5 is identified in the three wells (Figs. 5, 5 & 7). In Alo-1 well at 3,600 ft., Igbariam-1 well at 4,600 ft. and Ajire-1 well at 7,700 ft. In Ajire-1 well, SB-5 is found within the P100 biozone (Fig. 7).
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Fig. 5: Stratigraphic surfaces identified in Alo-1well.
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Fig 6: Bounding surfaces in Igbariam-1well
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Fig. 7: Stratigraphic surfaces identified in Ajire-1 well. 9
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3.1.3 Systems Tracts and Depositional Facies.
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Four complete genetic sequences and one incomplete sequence were recognized in both Alo1 and Igbariam-1 wells. The genetic sequences were identified using Galloway method (MFS – SB - MFS). The accompanying systems tracts were interpreted and mapped across the three wells, based on identified log motifs and the spatial distribution of the recognized stratigraphic surfaces (MFSs and SBs). First and fourth sequences formed the oldest and youngest depositional sequences respectively.
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3.1.3.1 Alo-1 Well
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Alo-1 well is composed of four complete sequences and one incomplete sequence (Fig. 8). It has five maximum flooding surfaces and five sequence boundaries. The formations found contained in it from total depth are; Nkporo, Mamu, Ajali, Nsukka and Imo Formations (Fig. 9).
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A sequence boundary SB-1 was identified and picked at the depth of 7,150 ft. It makes for the incomplete sequence. This incomplete sequence was interpreted in the Nkporo Shale in an environment ranging from coastal deltaic to bathyal. It was also interpreted in the P200 zone (Fig. 9).
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The first sequence is capped by MFS-1 at a depth of 6,800 ft. It is a complete sequence, mainly shaly and is about 1,500 ft. thick (Fig. 9). Environment of deposition is from the middle neritic to the bathyal and consists of sand and shale intercalations but mainly shales. The first sequence is bounded below and above by MFS-1 in Nkporo Shale and Mamu Formation and MFS-2 respectively. It is a complete sequence made of an HST and a TST (Fig. 9). In this sequence, fauna and plankton are present although there is not much plankton.
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The second sequence is about 2,297 ft. thick and bounded below and above by MFS-2 at the depth of 5,350 ft. and MFS-3 at 4,530 ft. respectively in Mamu Formation (Fig. 9). It is a complete sequence comprising shales and sandy-shale. The system tracts in this sequence are the HST, LST and the TST. There is high fauna diversity and population, high plankton diversity but low to absent plankton population. The environment of deposition ranges from middle neritic to bathyal.
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The third sequence is about 510 ft. thick and bounded below and above by MFS-3 at 4,530 ft. and MFS-4 at 4,020 ft. respectively (Fig 9). The Mamu Formation continues in this sequence. It is a complete sequence too comprising sandy- shale deposits. The environment of deposition ranges from inner neritic to bathyal. The system tracts identified in this sequence are the HST, LST and TST. High presence of foraminifers’ population and diversity with high plankton diversity was interpreted. The population of plankton is low.
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The fourth sequence is 3,010 ft. thick and bounded below and above by MFS-4 at 4,020 ft. and MFS-5 at 1,010 ft. respectively (Fig. 9). The sequence boundary SB-5 marks the entry into Ajali Formation. It is a complete sequence composed of thick sand resulting in a LST with little shale present. The system tracts in this sequence are the LST, HST, and TST. The gamma ray log shows the presence of tidal channel and incised valley fill in the Ajali 10
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Formation. Moving to the top, thick shale is present suggesting a change in environment which is the Nsukka Formation. It is composed of mainly shale with an intercalation of sand. In this sequence, there is very high fauna population and diversity with high plankton diversity in some places but low or absent plankton population. The Imo Formation overlies the Nsukka Formation. It is found above MFS-5 in the Alo-1 well.
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Fig. 8: Formations and systems tracts contained in Alo-1well.
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Fig. 9: A, Nkporo Shale. B, Mamu Formation, and C, Ajali Sandstone showing incised valley and tidal channels contained in it with the Nsukka and Imo Formation.
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Table 2: Summary of the Stratigraphy of Alo-1well. Depth (ft.)
Formation
Age
1,025 – 95 2,050 - 1,025
Imo Nsukka
3,600 - 2,050 5,700 - 3,600
Ajali Mamu
8,682 – 5,700
Nkporo Shale
Late Paleocene (Thanatian) Late Maastrichtian - Early Paleocene (Danian) Maastrichtian Late Campanian – Early Maastrichtian Campanian
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3.1.3.2 Igbariam-1 well
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The Igbariam-1 well encountered four sequences and one incomplete sequence (Fig. 10). Below the first interpreted sequence, at about 9,750 ft., is the first identified sequence boundary (SB-1) which is part of an incomplete sequence (Fig. 11). The environment of deposition of the incomplete sequence is from inner neritic shale to bathyal showing heterolithic turbidites interpreted to be the Nkporo Group deposited in an HST. Fauna diversity is present in this incomplete sequence.
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The first sequence identified in Igbariam-1 well is bounded above and below by MFS-2 and MFS-1 respectively. It is 598 ft. thick (Fig. 11). At 8,300 ft., SB-2 marks the beginning of the Mamu formation. It is mainly composed of marine shales with some sandstone deposits. This sequence was deposited from outer neritic to bathyal indicating the presence of shoreface 12
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sands and stacked turbidites of proximal lobes facies (Fig. 11). The system tracts here are the HST and TST but no LST. Fauna population and diversity is high. Plankton is absent. This sequence terminates at 7,900 ft.
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The second sequence which is a complete sequence is bounded below and above by MFS-2 and MFS-3 respectively (Fig. 11). It is about 700 ft. thick and is made up of a thick TST comprising of transgressive facies, and an HST comprising of sand and shale intercalations. The Mamu Formation continues in this sequence. This sequence was deposited from coastal deltaic to bathyal indicating tidal channel and coal deposits. Fauna population and diversity is higher here than the first sequence but still no plankton present. This sequence terminates at 7,200 ft.
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The third sequence is a complete one bounded above and below by MFS-4 and MFS-3 respectively (Fig. 12). It is 2,350 ft thick and consists of HST, TST and LST. The system tracts are complete in this sequence. This is still the Mamu Formation and this sequence was deposited in an environment ranging from coastal deltaic to bathyal indicating the presence of coal deposits in this formation. As the depth decreases, so does the population and diversity of fauna. The plankton population and diversity is nil. This sequence terminates at 4,850 ft.
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The fourth sequence, also a complete one is bounded below and above by MFS-4 and MFS-5 respectively (Fig. 11 and 12). It is 3,200 ft. thick and composed of HST, TST and LST. The system tracts are complete. From the depth of 4,850 ft. to 4,600 ft. is the Mamu formation terminating at 4,600 ft. (SB-5) (Fig. 12). The Ajali Formation begins at this depth in this sequence and is composed of an LST indicating an environment of deposition ranging from inner neritic to bathyal. In this environment, there are amalgamated coarse turbiditic and sandy channel fill facies. The fauna population and diversity increases with decrease in depth. The plankton population and diversity is absent here. The Ajali Formation terminates at 3,250 ft. marking the beginning of the Nsukka Formation (Fig. 12).
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The Nsukka Formation is composed of shales with sandstones and has an HST and TST system tracts contained in it (Fig. 12). This formation as seen on the log is 1,600 ft. thick. The environment of deposition ranges from shallow inner neritic to proximal fan. In this environment, there is high fauna and plankton population and diversity. It terminates at 1,650 ft. where the Imo Formation began. The sand lenses as seen on the gamma ray log is the Ebenebe Sandstone. This Sandstone was deposited in an environment ranging from inner neritic (fluvio-marine) to bathyal (Table 3). The fauna and plankton population and diversity are high up to the depth of 1,500 ft. where the fauna population and diversity reduces drastically while the plankton population reduces to nil.
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Fig. 10: Formations and systems tracts contained in Igbariam-1well.
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Fig. 11: A, reveals Nkporo Group and Owelli Sandstone with the interfingering Asata Shale in B. Facies like the tidal channels and submarine fan lobes were identified in Owelli Sandstone. C, is the Mamu formation with shoreface sands and stacked turbidites facies and coal deposits.
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Fig 12: E, Continuation of the Mamu Formation of Igbariam-1. F, Ajali Formation, Nsukka and Imo Formations. The Ebenebe Sand was identified in Imo Formation.
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Table 3: Summary of the stratigraphy of Igbariam-1 well. Depth (ft.) Formation Age 1,650 – 500 Imo Palaeocene 3,250 – 1,650 Nsukka Late Maastrichtian Palaeocene (Danian) 4,600 – 3,250 Ajali Maastrichtian 8,300 – 4,600 Mamu Late Campanian Maastrichtian 9,750 – 9,000 Owelli Sandstone Campanian 10,788 – 8,300 Nkporo Group Campanian
– –
Early Early
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3.1.3.3 Ajire-1 well
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The Ajire-1well has no complete sequence throughout its depth (Fig. 13). Only SB-5 and MFS-6 was identified in this well. Mostly LSTs and TSTs were identified along with three HSTs throughout the depth of the well. In this well, the fauna and plankton population and diversity are really high starting from the total depth drilled. The formations encountered in this well are the Mamu, Ajali, Nsukka, Imo Formations and Nanka Sand. SB-5 is at 7,700 ft. lying in Mamu Formation while MFS-6 is at 4,200 ft. in Imo Formation.
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From the base, at the depth of 8,300 ft. the Mamu Formation begins showing sand deposits shale deposits (Fig. 14A). The environment of deposition ranges from middle neritic to bathyal. The only system tract identified here is the highstand system tract (HST).The Mamu Formation ends at 7,700 ft. In this formation, there is high fauna population and diversity with high plankton diversity but low plankton population. 15
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Above the Mamu Formation, the Ajali Formation was encountered in the well to a depth of about 6,400 ft. (Fig. 14A). The environment of deposition ranges from middle neritic to bathyal and was deposited in TSTs and LSTs. It is made up of intercalations of sand and shale, while the identified facies includes heterolithic levee deposits. The fauna and plankton population and diversity in the Ajali Formation are high especially the fauna diversity.
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Fig. 13: Depositional facies of Ajire-1 showing component Formations.
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Fig. 14: A, Mamu Formation and Ajali Formation with heterolithic levee deposits as its facies. B, Nsukka Formation and Imo Formation with Ebenebe Sandstone. C, Nanka Sand of Ajire-1 well.
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Above the Ajali Formation, the Nsukka Formation was identified. It was deposited within the coastal deltaic to bathyal environments and composed of shale and sand. It was deposited in an HST and TST (Fig.14A). The fauna and plankton population and diversity are high. It terminated at 5,555 ft.
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Above the Nsukka Formation, the Imo Formation was encountered and was deposited in an environment ranging from coastal deltaic to bathyal (Fig. 14B and C). The identified facies here are shaly sand, sand and shale. The system tracts identified in this formation are TST and LST. The fauna and plankton population and diversity are high up to the depth of 4,255 ft. where it reduces drastically. From the depth to the top, the fauna diversity remains high with little presence of the others. It terminates at 4,150 ft.
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In the Ajire-1 well, above the Imo Formation is the Nanka Sand of the Ameki Group (Table 4). The Nanka Sand continues to the start depth which is 500 ft. The environment of deposition ranges from coastal deltaic to bathyal. The facies identified here are sand and sandy shale. The system tracts identified are the LST, HST and TST. Fauna and plankton population and diversity become high at 2,555 ft. and reduce significantly at 1,900 ft.
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Table 4: Summary of the stratigraphy of Ajire-1 well. Depth(ft.) Formation 4,150- 500 5,555 – 4,150 6,400 – 5,555
Nanka Sand Imo Nsukka
7,700 – 6,400 8,300 – 7,700
Ajali Mamu
Age Eocene Paleocene (Thanatian) Late Maastrichtian – Early Paleocene (Danian) Maastrichtian Late Campanian – Early Maastrichtian
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3.2 Sequence Stratigraphic Correlation Not all the key bounding surfaces (MFS and SB) could be correlated across the three wells. MFS-1 to MFS-5 could only be correlated across Alo-1 and Igbariam-1 wells at different depths. Sequence boundaries SB-1 to SB-4 could only be correlated across Alo-1 and Igbariam-1 wells. Both Alo-1 and Igbariam-1 well have four complete sequences and one incomplete sequence. Ajire-1 well has only an incomplete sequence.
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The correlation across the three wells (Fig.15) revealed the Nkporo Group (Nkporo Shale and Owelli Sandstone), Mamu, Ajali, Nsukka and Imo Formations in Alo-1 and Igbariam-1 wells. However, while the Owelli Sandstone was identified in Igbariam-1 well, the Nkporo Shale was identified in Alo-1 well and thus the two wells correlate well. Also, the Ajire-1 well correlates well with the other two wells from the Mamu to Imo Formations (Fig. 15).
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Fig. 15: Sequence stratigraphic surfaces correlation across the three wells.
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3.3 Reservoir Continuity
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A reservoirs’ area of coverage is often indicated by the lateral continuity of sand bodies and this is critical to robust hydrocarbon volume calculation. Identified sand bodies across the three wells were classified stratigraphically as S1 to S5 (Fig.15).
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Sands S1 was found to be in Alo-1 and Igbariam-1 wells. In Alo-1 well, it was interpreted within the depth of 7,000 ft. to 7,500 ft. within a TST. Below this sand is SB-1 and after a few ft. is MFS-1. In Igbariam-1 well, it was interpreted to start from SB-1 at 10,000 ft. to 9,000 ft. This sand is very thick compared to that in Alo-1 well. This sand occurred in an LST and was identified as the Owelli Sandstone where the tidal channel fills, the submarine fan lobe and the Asata Shale was interpreted.
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Sands S2 was found in both Alo-1 and Igbariam-1 wells. In Alo-1 well, it was interpreted within 5,650 ft. to 5,050 ft. SB-2 marks the existence of S2 and this sand was found in a TST. It is a part of the Mamu Formation. In Igbariam-1 well, it was interpreted within 8,600 ft. to 18
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7,500 ft. and is thicker compared to that in Alo-1 well. It occurred in the three system tractsHST, TST and LST. It is also a part of the Mamu Formation.
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Sands S3 was interpreted in both Alo-1 and Igbariam-1 wells within 5,000 ft. to 4,300 ft. and 6,300 ft. to 5,800 ft. respectively. Both sands are in the Mamu Formation. In Igbariam-1 well, coal deposits and tidal channel sands were interpreted. In Alo-1 well, it was deposited in both an LST and TST while in Igbariam-1 well, it deposited in an HST. The sands in Alo-1 well are thicker than that in Igbariam-1well.
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Sands S4 was interpreted across the three wells. In Alo-1well, it is within 4,200 ft. to 3,600 ft. and still interpret as the Mamu formation, capped by SB-5. It was deposited within a TST and HST. In Igbariam-1 well, it is within 5,100 ft. to 4,150 ft. and is interpreted as the Mamu formation. It occurs within an HST, TST and LST. In Ajire-1 well, it is within 8,300 ft. to 8,200 ft. and is considered a part of the Mamu Formation. It occurs within an HST.
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Sands S5 was correlated across the three wells and interpreted as the Ajali Formation. In Alo1 well, it was deposited within an LST from 3,600 ft. to 2,050 ft. and tidal channels and incised valley was interpreted in it. In Igbariam-1 well, it was deposited within an LST from 4,600 ft. to 3,250 ft. and turbiditic channel fills was interpreted in it. In Ajire-1 well, it was deposited in both an LST and heterolithic levee deposits were interpreted here.
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Fig 16: Sequence stratigraphic framework of the wells showing reservoir continuity and formation tops within the interpreted system tracts.
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4.0 Conclusions
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Key bounding surfaces in the three wells have been identified along with the system tracts, environments of deposition and reservoirs. Four complete sequences and one incomplete sequence were interpreted in both Alo-1 and Igbariam-1 wells. Ajire-1 well has no complete sequence. Five maximum flooding surfaces (MFS-1 to MFS-5) were interpreted in both Alo1 and Igbariam-1 wells while only MFS-6 was interpreted in Ajire-1 well. Four sequence 19
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boundaries (SB-1 to SB-4) were interpreted in both Alo-1 and Igbariam-1 wells and SB-5 was interpreted only in Ajire-1 well.
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The integrated results aided in identifying the play elements that contain the reservoirs. Five reservoir sands were identified and marked. They were interpreted at different depths in Nkporo, Owelli, Mamu and Ajali Formations, representing TSTs, LSTs and HSTs. Sands S1 to S3 were interpreted across Alo-1 and Igbariam-1 wells while S4 and S5 were interpreted across the three wells.
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Sand S1 was interpreted within a TST in a middle neritic environment and is capped by shale deposited within an HST and is 250 ft. thick in Alo-1 well while in Igbariam-1 well, it was interpreted to be deposited in an LST as heterolithic turbidites in shallow marine to bathyal environments, capped by shale within a TST and is 1,000 ft. thick. The shales of the TST and HST will serve as a good seals for the sands.
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Sand S2 was interpreted to be deposited within a TST in a coastal deltaic to bathyal environments and is capped by shale deposited in an HST which is 300 ft. thick in Alo-1 well while in Igbariam-1 well, it was interpreted to be deposited within a TST, HST, and LST as channels and submarine fan lobes in a coastal deltaic to bathyal environments and is capped by shale deposited in a TST. This sand is 650 ft. thick. The shales of the TST and HST will serve as good seals.
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Sands S3 was deposited within an LST in an outer neritic to bathyal environments and is capped by shale deposited in an HST which is 550 ft. thick in Alo-1 well while in Igbariam-1 well, it was interpreted to be deposited in an HST which was found to be associated with coal deposits interpreted in the shales interbedded in the sand in a coastal deltaic to bathyal environments which is capped with the shales of an HST. The sand in the HST is 250 ft. thick. The shales of the HSTs in both wells will serve as seals.
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Sand S4 was deposited within an HST in a middle neritic environment and is capped by shale deposited in a TST and is 50 ft. thick in Alo-1 well while in Igbariam-1 well, it was interpreted to be deposited in an LST associated with stacked turbidites of proximal lobes and shoreface sands in an outer neritic to bathyal environments. This LST is capped by shales of the TST and is 350 ft. thick. The shales of the TSTs in both wells will serve as good seals. In Ajire-1 well, it was interpreted to be deposited within an HST in a bathyal environment and is capped by shales of an HST.
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Sands S5 was interpreted to be deposited within an LST which was associated with tidal channels and incised valleys in middle neritic to bathyal environments. This sand is 1,650 ft. thick and is capped by shales within a TST in Alo-1 well while in Igbariam-1 well, it was interpreted in an LST as amalgamated coarse turbiditic sandy channel fills in a coastal deltaic to bathyal environments. This sand is capped by shales of a TST and is 1,300 ft. thick. In Ajire-1 well, it was interpreted to be deposited in an LST as heterolithic levee deposits in coastal to bathyal environments. This sand is 1,300 ft. thick and is capped by shale within an HST.
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5.0 Recommendation
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The sands of LST and HST revealed in Ajali, Mamu, Nkporo and Imo (Ebenebe Sand Member) Formations show good continuity and as such, good reservoir qualities, while the shales of the TSTs which include the Imo Formation, Mamu, and Nkporo Formations can serve as seals to the numerous reservoir units.
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Acknowledgements
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Special thanks go to the Management of Department of Petroleum Resources (DPR), PortHarcourt, Nigeria, for approving the permission to use the data set for this study. We remain grateful to the staff of the Departmental of Geological Sciences, Nnamdi Azikiwe University, Awka, Nigeria for granting access to their work stations as well as their technical inputs.
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ACCEPTED MANUSCRIPT HIGHLIGHT FROM Sequence Stratigraphic Interpretation of Parts of Anambra Basin Using Well Logs and Biostratigraphic Data
1. Biostratigraphic interpretation, using foraminifera and plankton population and 2.
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6. 7.
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diversity, reveals five maximum flooding surfaces (MFS) in the fields. Five sequence boundaries (SB) were also identified using the well log analysis. Four 3rd order genetic sequences bounded by maximum flooding surfaces (MFS-1 to MFS6) were identified in the areas; four complete sequences and one incomplete sequence were identified in both Alo-1 and Igbariam-1 wells while Ajire-1 has an incomplete sequence with no complete sequence. The identified system tracts delineated comprises Lowstand Systems Tracts (progradational to aggradational to retrogradational packages), Transgressive Systems Tracts (retrogradational packages) and Highstand Systems Tracts (aggradational to progradational packages) in each well. The sand continuity across the fields reveal sands S1 to S5 where S1 is present in Ajire-1 well and Igbariam-1 well but not in Alo-1 well. The sands S4 to S5 run across the three fields at different depths. The formations penetrated by the wells starting from the base are; Nkporo Formation (Campanian), Mamu Formation (Late Campanian to Early Maastrichtian), Ajali Sandstone (Maastrichtian), Nsukka Formation (Late Maastrichtian to Early Palaeocene), Imo Formation (Palaeocene) and Nanka Sand (Eocene). The environments of deposition revealed are from coastal to bathyal. The sands of lowstand system tract and highstand system tract found in Ajali, Nsukka, Nkporo and Imo (Ebenebe Sandstone) Formations show good continuity and as such good reservoir qualities while the shales of the transgressive system tracts which includes the Imo Formation, Mamu, and Nkporo Formations where most of the maximum flooding surfaces were delineated, can serve as seals to the numerous reservoir units. Combinations of the reservoir sands of the lowstand system tract and highstand system tract and the shale units of the transgressive system tract can form good stratigraphic traps for hydrocarbon and hence should be hydrocarbon exploration targets.
ACCEPTED MANUSCRIPT
Table 1: Data Availability for the Study WELLS
Ajire-1
Igbariam-1
Alo-1
Well Logs
Biostratigraphic data
Caliper
Gamma Ray
SP
Sonic
Resistivity
Density
Neutron
√
√
√
√
√
√
х
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√
NB: √ shows available data; х shows unavailable data