RESERVOIR CHARACTERIZATION AS A CONSEQUENCE OF THE DEPOSITIONAL ENVIRONMENT IN THE OKWUTE FIELD, ONSHORE NIGER DELTA [301509]

RESERVOIR CHARACTERIZATION AS A [anonimizat] 3D [anonimizat], lithofacies, [anonimizat], Niger delta. [anonimizat], paleobathymetric, lithologic and wireline (GR and Resistivity) log data which resulted in the delineation of a Maximum Flooding Surface (MFS) candidate at 8900ft (10.4 Ma) and associated Sequence Boundary (SB) at 7100ft (?10.35 Ma) and 10,450ft (10.6 Ma). [anonimizat]-marine to ?[anonimizat]. [anonimizat]. [anonimizat], frequency and reflection configuration aid in identifying the trapping system and the sealing mechanism within the field as interpreted from the Okwute Field data.

CHAPTER 1

Introduction

Background

The geology of Nigeria is divided into two: The basement complex and the sedimentary basins. There are Seven Sedimentary basins in Nigeria of which the Niger Delta is a major one covering an area of approximately 75,000 km2 essentially in the southern Nigeria and the Gulf of Guinea (fig. 1), offshore Nigeria. The Niger Delta consists of regressive sequence whose maximum thickness is about 12 km in the central part (Short and Stauble, 1967). It is one of the most prominent basins in West Africa and the largest delta in Africa (Reijers et al, 1997). The Niger Delta is rated the 12[anonimizat]. Production of crude oil in Nigeria from the prolific Niger Delta basin has reached reserves exceeding 34 billion barrels of oil and 93 trillion cubic feet of gas (Tuttle et al, 1999). As a [anonimizat]. [anonimizat]. [anonimizat]. [anonimizat].

Sequence stratigraphy concepts have been used in the Niger Delta and found effective in studying siliclastic successions such as the Niger Delta petroleum province. Formation and sedimentation in the Niger Delta have been greatly influenced by tectonics and sea level changes (Osetoba and Ojo, 2014).

Stacher (1995) produced chronostratigraphic and sequence stratigraphic framework for the Niger Delta. Also, Ejadawe et al (2004) used 2D seismic to examine the regional sequence stratigraphy and sand fairways as controls on hydrocarbon occurrence in the Niger Delta. Ozumba et al. (2005) re-evaluated Opuama channel using sequence stratigrpahy. Optimization of the Usari field was achieved by the use of sequence stratigraphic analyses (Ajayi et al., 2006). Giwa et al, (2005) and Durogbitan and Gwarthorpe, (2008) emphasized the importance of sequence stratigraphy in petroleum exploration in the Niger delta. The present study combines a three-dimensional seismic image with well log data to analyse the stratigraphic successions within the Okwute field and develop a sequence stratigraphic framework for the field.

Figure 1: Geological map of the Niger Delta and surroundings (Reijers, 2011).

The history of the formation of the Tertiary Niger Delta (Akata-Agbada) petroleum system is summarized in the events chart (fig. 2). Rocks within the petroleum system are from Paleocene to Recent in age. Most of the petroleum is sourced from the Akata Formation, with smaller amounts generated from the mature shale beds in the lower Agbada Formation. Deposition of overburden rock began in the Middle Eocene and continues to the present. Units include the Agbada and Benin Formations to the north with a transition to the Akata Formation in the deep-water portion of the basin where the Agbada and Benin Formations thin and disappear seaward (Tuttle et al, 1999).

Petroleum generation within the delta began in the Eocene and continues today (Tuttle et al, 1999). Generation occurred from north to south as progressively younger depobelts entered the oil window. Reservoirs for the discovered petroleum are sandstones throughout the Agbada Formation. Reservoirs for undiscovered petroleum below currently producing intervals and in the distal portions of the delta system may include turbidite sands within the Akata (Tuttle et al, 1999). Trap and seal formation is related to gravity tectonics within the delta. Structural traps have been the most favourable exploration target, however, stratigraphic traps are likely to become more important targets in distal and deeper portions of the delta (Tuttle et al, 1999).

Figure 2: Events chart for the Niger Delta (Akata/Agbada) Petroleum System (Tuttle et al, 1999).

Geological setting of the Study Area

The geological setting of the study area discussed in this work is as recorded in the work of Reijers, 2011. The evolution of the delta is controlled by pre- and synsedimentary tectonics as described by Evamy et al. (1978), Ejedawe (1981), Knox & Omatsola (1987) and Stacher (1995). The delta growth is summarised below. The shape of the Cretaceous coast line (fig. 1; see also Reijers et al., 1997) gradually changed with the growth of the Niger Delta (Figs 4, 5). A bulge developed due to delta growth. This changing coastline interacted with the palaeo-circulation pattern and controlled the extent of incursions of the sea (Reijers et al, 1997). Other factors that controlled the growth of the delta are climatic variations and the proximity and nature of sediment source areas (Reijers, 2011).

During the Middle-Late Eocene, sediment was deposited (fig. 4A) west of the inverted Cretaceous Abakaliki High and south of the Anambra Basin in what became the ’northern depobelt of the Niger Delta’ (figs 1, 4, 5). The first coarse clastic deposits have been dated on the basis of microfloral units (Evamy et al., 1978) (fig. 3; Table 1) as Early Eocene (Reijers, 2011). Tradewinds generated longshore currents with two cells converging along the western estuarine coast sector (Burke, 1972; Berggren & Hollister, 1974, Reijers et al., 1997) (fig. 4A). Studies by Weber & Daukuro (1975), Ejedawe (1981) and Ejedawe et al. (1984) clarified that the embryonic delta subsided during the Late Eocene to Middle Oligocene <700 m/Ma and prograded approx. 2 km/Ma along three depositional axes that fed irregular, early delta lobes (fig. 4) that eventually coalesced. Thick sandy sediment accumulations thus formed in the active ’Greater Ughelli depobelt’ (Reijers, 2011).

During the Late Oligocene to Middle Miocene, the delta subsidence remained steady at some 700 m/Ma but delta progradation increased to 8–15 km/Ma. Incision of the Opuama Channel (figs 3, 4B, 5A) in the western sector of the delta occurred at this time (Patters, 1984; Knox & Omatsola, 1987, Reijers, 2011).

Table 1. Nature of 3rd-order composite sequences and their parasequence sets in the Niger Delta

Figure 3: Stratigraphic data sheet (west and east halves combined) of the Niger Delta. (After Reijers, 2011).

Figure 3 cont.: Stratigraphic data sheet (west and east halves combined) of the Niger Delta. (After Reijers, 2011).

From the Middle Miocene onward, the delta prograded over a landward dipping oceanic lithosphere. The ‘Escalator Regression Model’ of Knox & Omatsola (1987) shows the average delta subsidence rates and progradation figures used here. During the Miocene, the average progradation was some 1000 m/Ma. Depocentres in the eastern sector of the delta merged laterally and the enlarged delta front prograded pulse-wise, occasionally advancing at rates of 16–22 km/Ma (figs 3, 4B, 5). The coastline, now convex, broke up the longshore current into two divergent drift cells. During the Middle-Late Miocene, a rising hinterland supplied substantial amounts of sediment that accumulated in the active Central Swamp and in the northern sector of the Coastal Swamp. Progradation maintained at a steady rate of 13–17 km/Ma (fig. 3) and stabilised in the Late Miocene-Pliocene when the Coastal Swamp and offshore depobelts became active. In the eastern delta, sedimentation was interrupted by cutting-and-filling events (Burke, 1972; Petters, 1984), resulting in the Agbada, Elekelewu, Soku and Afam ’channels’ (figs 3, 5B). During the Pliocene, catastrophic gravity events, possibly related to contemporaneous activity along the Cameroon volcanic line, formed the Qua Iboe Channel in the south-eastern offshore area.

Figure 4: Palaeo-drainage trend and advancing coastline of the Niger Delta (modified after Edjedawe, 1981; Edjedawe et al., 1984). A – Position at start of sequence 3 (Orogho-shale transgression); B – Position at start of sequence 5 (Alabamina–1 shale transgression).

Figure 5: Palaeo-drainage trend and advancing coastline of the Niger Delta (modified after Edjedawe, 1981; Edjedawe et al., 1984). A – Position at start of sequence 9 (Dodo-shale transgression); B – Position at start of sequence 11 (Bolivina–46 shale transgression).

The details of the geology of the Niger Delta basin would be discussed in details in Chapter 2 (literature review) of this work.

Study Objectives

Identification of key stratigraphic surfaces, depositional sequences and delineation of the different systems tracts and determination of dominant trapping mechanisms in the study area.

Systems tracts that serve as hydrocarbon reservoirs will be identified and environment of deposition determined.

Scope of Work

The study area is located onshore Niger Delta, Nigeria which is on the continental margin of the Gulf of Guinea in Equatorial West Africa.

The sedimentary succession in the field has been analysed using sequence stratigraphic principles vis a vis; 3D seismic, biostratigraphic and well log data for well to well correlation to evaluate the lithology, stratigraphy – facies and depositional environments so as to determine the hydrocarbon reservoirs of the Okwute field, Niger delta

These research focuses on the interpretation of depositional processes within the Niger Delta clastic wedge using Seismic, Biostratigraphic and well log data from Okuwte field. Well log and seismic data were loaded into Petrel™ 2014 version.

CHAPTER 2

Literature Review

2.1 Introduction

The Niger Delta is situated in the Gulf of Guinea (fig. 6) and extends throughout the Niger Delta Province as defined by Klett et al, (1997). From the Eocene to the present, the delta has prograded southwestward, forming depobelts that represent the most active portion of the delta at each stage of its development (Doust and Omatsola, 1990). These depobelts form one of the largest regressive deltas in the world with an area of some 300,000 km2 (Kulke, 1995), a sediment volume of 500,000 km3 (Hospers, 1965), and a sediment thickness of over 10 km in the basin depocenter (Kaplan et al, 1994).

The Niger Delta Province contains only one identified petroleum system (Kulke, 1995; Ekweozor and Daukoru, 1994; Tuttle et al, 1999). This system is referred to here as the Tertiary Niger Delta (Akata –Agbada) Petroleum System. Akata-Agbada follows the petroleum system naming convention of Magoon and Dow (1994) where the petroleum system source rock is given first followed by the reservoir rock containing the largest volume of hydrocarbons. The maximum extent of the petroleum system coincides with the boundaries of the province (fig. 6). The minimum extent of the system is defined by the areal extent of fields and contains known resources (cumulative production plus proved reserves) of 34.5 billion barrels of oil (BBO) and 93.8 trillion cubic feet of gas (TCFG) (14.9 billion barrels of oil equivalent, BBOE) (Petroconsultants, 1996a). Reijers et al (1997) report natural gas reserves at 260 TCFG (46.3 BBOE). This is a near 2.5-fold increase that likely reflects the underreporting of gas in The Petroconsultant’s Inc.’s database. Currently, most of this petroleum is in fields that are onshore or on the continental shelf in waters less than 200 meters deep (fig. 6), and occurs primarily in large, relatively simple structures. A few giant fields do occur in the delta, the largest contains just over 1.0 BBO (Petroconsultants, Inc., 1996a).

Among the provinces ranked in the U.S. Geological Survey's World Energy Assessment (Klett et al, 1997), the Niger Delta province is the twelfth richest in petroleum resources, with 2.2% of the world’s discovered oil and 1.4% of the world’s discovered gas (Petroconsultants, Inc. 1996a).

In 1908, the German Nigerian Bitumen Corporation drilled the first wells in the vicinity of the tar seep deposits in the northern portion of the delta (Frost, 1997). However, significant oil shows were not found in Tertiary rocks until the early 1950’s. Shell-British Petroleum brought the first well on stream in 1958 at 5,100 barrels per day. From 1958 until the Biafran War in 1967, exploration and production increased in Nigeria. The war curtailed both activities until its end in 1970, when world oil prices were rising and Nigeria again could benefit economically from its petroleum resources in the Niger Delta. In 1971, Nigeria joined the Organization of the Petroleum Exporting Countries (OPEC) with a total production of 703 million barrels of oil (MMBO) per annum.

Figure 6: Index map of Nigeria and Cameroon. Map of the Niger Delta showing Province outline (maximum petroleum system); bounding structural features; minimum petroleum system as defined by oil and gas field centre points; 200, 2000, 3000, and 4000m bathymetric contours; and 2 and 4km sediment thickness. (Tuttle et al, 1999).

In 1997, production rose to 810 MMBO (Energy Information Administration, 1998a). Thirty-one percent of this production (251 MMBO) was exported to the United States, making Nigeria the fifth largest supplier of U.S. oil. Despite the political uncertainty in Nigeria today, the country’s sustainable production capacity is expected to increase over current production–they have agreed, however, to reduce their production by 225,000 barrels/day in 1998. Petroleum exploration is also expanding, especially in deeper water offshore, with the Nigerian government currently planning to offer six additional lease blocks in water up to 3000 m deep. Considering both oil and gas, the overall success ratio for exploration drilling is as high as 45% (Kulke, 1995; figs. 7A and 7B).

Figure 7: Crossplots for cumulative number of (A) oil fields and (B) Gas fields versus cumulative number of total new-field wildcat wells in the Niger Delta Province. (Tuttle et al, 1999).

Exploration of the small portions of the Niger Delta in Cameroon and Equatorial Guinea began much later than in Nigeria. Recoverable oil and gas (produced plus proved reserves) are much smaller than in Nigeria. In 1997, 96% of the Niger Delta recoverable petroleum was in Nigeria, 3.5% in Cameroon, and 0.5% in Equatorial Guinea (Petroconsultants, Inc., 1996a).

2.2 Province Geology

The onshore portion of the Niger Delta Province is delineated by the geology of southern Nigeria and southwestern Cameroon (fig. 6). The northern boundary is the Benin flank–an east-northeast trending hinge line south of the West Africa basement massif. The northeastern boundary is defined by outcrops of the Cretaceous on the Abakaliki High and further east-south-east by the Calabar flank–a hinge line bordering the adjacent Precambrian. The offshore boundary of the province is defined by the Cameroon volcanic line to the east, the eastern boundary of the Dahomey basin (the eastern-most West African transform-fault passive margin) to the west, and the two-kilometre sediment thickness contour or the 4000-metre bathymetric contour in areas where sediment thickness is greater than two kilometres to the south and southwest. The province covers 300,000 km2 and includes the geologic extent of the Tertiary Niger Delta (Akata-Agbada) Petroleum System.

2.2.1 Tectonics

The tectonic framework of the continental margin along the West Coast of equatorial Africa is controlled by Cretaceous fracture zones expressed as trenches and ridges in the deep Atlantic. The fracture zone ridges subdivide the margin into individual basins, and, in Nigeria, form the boundary faults of the Cretaceous Benue-Abakaliki trough, which cuts far into the West African shield. The trough represents a failed arm of a rift triple junction associated with the opening of the South Atlantic. In this region, rifting started in the Late Jurassic and persisted into the Middle Cretaceous (Lehner and De Ruiter, 1977). In the region of the Niger Delta, rifting diminished altogether in the Late Cretaceous. Figure 8 shows the gross paleogeography of the region as well as the relative position of the African and South American plates since rifting began.

Figure 8: Paleogeography showing the opening of the South Atlantic, and development of the region around Niger Delta. A. Cretaceous Paleogeography (130.0 to 69.4 Ma). B. Cenozoic paleogeography (50.3 Ma to present). Plots generated with PGIS software. (Tuttle et al, 1999).

After rifting ceased, gravity tectonism became the primary deformational process. Shale mobility induced internal deformation and occurred in response to two processes (Kulke, 1995). First, shale diapirs formed from loading of poorly compacted, over-pressured, prodelta and delta-slope clays (Akata Fm.) by the higher density delta-front sands (Agbada Fm.). Second, slope instability occurred due to a lack of lateral, basinward, support for the under-compacted delta-slope clays (Akata Fm.) (Fig. 9). For any given depobelt, gravity tectonics were completed before deposition of the Benin Formation and are expressed in complex structures, including shale diapirs, roll-over anticlines, collapsed growth fault crests, back-to-back features, and steeply dipping, closely spaced flank faults (Evamy et al, 1978; Xiao and Suppe, 1992). These faults mostly offset different parts of the Agbada Formation and flatten into detachment planes near the top of the Akata Formation.

Figure 9: Schematic of a seismic section from the Niger Delta continental slope/ rise showing the results of internal gravity tectonics on sediments at the distal portion of the depobelt. The Late Cretaceous-Early Tertiary section has a low-velocity gradient, probably marine shales, whereas the Late Tertiary has a normal-velocity gradient, suggesting a much sandier facies. Modified from Lehner and De Ruiter, 1977; Doust and Omatsola, 1990; Tuttle et al, 1999.

2.2.2 Lithology

The Cretaceous section has not been penetrated beneath the Niger Delta Basin, the youngest and southernmost sub-basin in the Benue-Abakaliki trough (Reijers et al, 1997). Lithologies of Cretaceous rocks deposited in what is now the Niger Delta basin can only be extrapolated from the exposed Cretaceous section in the next basin to the northeast–the Anambra basin (fig. 10). From the Campanian through the Paleocene, the shoreline was concave into the Anambra basin (Hospers, 1965) (see fig. 8a and fig. 8b), resulting in convergent longshore drift cells that produced tide-dominated deltaic sedimentation during transgressions and river-dominated sedimentation during regressions (Reijers et al, 1997). Shallow marine clastics were deposited farther offshore and, in the Anambra basin, are represented by the Albian-Cenomanian Asu River shale, Cenomanian-Santonian Eze-Uku and Awgu shales, and Campanian /Maastrichtian Nkporo shale, among others (fig. 10, fig 11a, and fig 11b) (Nwachukwu, 1972; Reijers et al, 1997). The distribution of Late Cretaceous shale beneath the Niger Delta is unknown.

Figure 10: Stratigraphic section of the Anambra Basin from the Late Cretaceous through the Eocene and time equivalent formations in the Niger Delta (Tuttle et al, 1999). Modified from Reijers et al, 1997.

Figure 11: Diagrammatic east-west (A-A’) cross section and southwest-northeast (B-B’) cross section through the Niger Delta Region. Isopachs (km) in location map are total sediment thickness (Kaplan et al, 1994). Stippled pattern in A-A’, continental basement (Tuttle et al, 1999). Cross section A-A’ and B-B’ modified from Whiteman (1982).

In the Paleocene, a major transgression (referred to as the Sokoto transgression by Reijers et al, 1997) began with the Imo shale being deposited in the Anambra Basin to the northeast and the Akata shale in the Niger Delta Basin area to the southwest (fig. 10). In the Eocene, the coastline shape became convexly curvilinear, the longshore drift cells switched to divergent, and sedimentation changed to being wave-dominated (Reijers et al, 1997). At this time, deposition of paralic sediments began in the Niger Delta Basin proper and, as the sediments prograded south, the coastline became progressively more convex seaward. Today, delta sedimentation is still wave-dominated and longshore drift cells divergent (Burke, 1972).

The Tertiary section of the Niger Delta is divided into three formations, representing prograding depositional facies that are distinguished mostly on the basis of sand-shale ratios. The type sections of these formations are described in Short and Stäuble (1967) and summarized in a variety of papers (e.g. Avbobvo, 1978; Doust and Omatola, 1990; Kulke, 1995). The Akata Formation at the base of the delta is of marine origin and is composed of thick shale sequences (potential source rock), turbidite sand (potential reservoirs in deep water), and minor amounts of clay and silt (fig. 10, fig. 11a, fig 11b, and fig. 12). Beginning in the Paleocene and through the Recent, the Akata Formation formed during lowstands when terrestrial organic matter and clays were transported to deep water areas characterized by low energy conditions and oxygen deficiency (Stacher, 1995). Little of the formation has been drilled; therefore, only a structural map of the top of the formation is available (fig. 13A). It is estimated that the formation is up to 7,000 meters thick (Doust and Omatsola, 1990). The formation underlies the entire delta, and is typically overpressured. Turbidity currents likely deposited deep sea fan sands within the upper Akata Formation during development of the delta (Burke, 1972).

Deposition of the overlying Agbada Formation, the major petroleum-bearing unit, began in the Eocene and continues into the Recent (fig. 10, fig. 11a, fig 11b, and fig. 12). The formation consists of paralic siliciclastics over 3700 meters thick (fig. 13B) and represents the actual deltaic portion of the sequence. The clastics accumulated in delta-front, delta-topset, and fluvio-deltaic environments. In the lower Agbada Formation, shale and sandstone beds were deposited in equal proportions, however, the upper portion is mostly sand with only minor shale interbeds. The Agbada Formation is overlain by the third formation, the Benin Formation, a continental latest Eocene to Recent deposit of alluvial and upper coastal plain sands that are up to 2000 m thick (Avbovbo, 1978).

Figure 12: Stratiigraphic column showing the three formations of the Niger Delta (Tuttle et al, 1999). Modified from Shannon and Naylor (1989) and Doust and Omatsola (1990).

Figure 13: A structural map of the top of Akata Formation (A) and thickness isopach contours of the Agbada Formation (B). Contours in 2000 foot intervals (Tuttle et al, 1999). Modified from Avbovbo (1978).

2.2.3 Depobelts

Deposition of the three formations occurred in each of the five offlapping siliciclastic sedimentation cycles that comprise the Niger Delta. These cycles (depobelts) are 30-60 kilometres wide, prograde southwestward 250 kilometres over oceanic crust into the Gulf of Guinea (Stacher, 1995), and are defined by synsedimentary faulting that occurred in response to variable rates of subsidence and sediment supply (Doust and Omatsola, 1990). Gravity field data from Hospers (1965) indicate that the Niger Delta is in near-isostatic equilibrium and represents a load accommodated by subsidence of the crust. The interplay of subsidence and supply rates resulted in deposition of discrete depobelts–when further crustal subsidence of the basin could no longer be accommodated, the focus of sediment deposition shifted seaward, forming a new depobelt (Doust and Omatsola, 1990). Each depobelt is a separate unit that corresponds to a break in regional dip of the delta and is bounded landward by growth faults and seaward by large counter-regional faults or the growth fault of the next seaward belt (Evamy et al, 1978; Doust and Omatsola, 1990). Five major depobelts are generally recognized, each with its own sedimentation, deformation, and petroleum history (fig. 14).

Figure 14: schematic showing how the coastline of the Niger Delta has prograded since 35 Ma. The delta has advanced seaward over 200 km and has broadened from a width of less than 300 km to a width of about 500 km. The shorelines approximate the Doust and Omatsola’s (1990) depobelts (Tuttle et al, 1999). Modified from Whiteman (1982).

Doust and Omatsola (1990) describe three depobelt provinces based on structure. The northern delta province, which overlies relatively shallow basement, has the oldest growth faults that are generally rotational, evenly spaced, and increase their steepness seaward. The central delta province has depobelts with well-defined structures such as successively deeper rollover crests that shift seaward for any given growth fault. Last, the distal delta province is the most structurally complex due to internal gravity tectonics on the modern continental slope.

2.3 Petroleum and its Occurrence

2.3.1 Distribution of Petroleum

Petroleum occurs throughout the Agbada Formation of the Niger Delta (fig. 6), however, several directional trends form an "oil-rich belt" having the largest field and lowest gas:oil ratio (Ejedawe, 1981; Evamy et al, 1978; Doust and Omatsola, 1990). The belt extends from the northwest offshore area to the southeast offshore and along a number of north-south trends in the area of Port Harcourt (fig. 15). It roughly corresponds to the transition between continental and oceanic crust, and is within the axis of maximum sedimentary thickness (see isopach map in fig. 11a). This hydrocarbon distribution was originally attributed to timing of trap formation relative to petroleum migration (earlier landward structures trapped earlier migrating oil). Evamy et al, (1978), however, showed that in many rollovers, movement on the structure-building fault and resulting growth continued and was relayed progressively southward into the younger part of the section by successive crestal faults, concluding that there was no relation between growth along a fault and distribution of petroleum. Ejedawe (1981) relates the position of the oil-rich areas within the belt to five delta lobes fed by four different rivers. He states that the two controlling factors are an increase in geothermal gradient relative to the minimum gradient in the delta centre and the generally greater age of sediments within the belt relative to those further seaward. Together these factors gave the sediments within the belt the highest "maturity per unit depth." Weber (1987) indicates that the oil-rich belt ("golden lane") coincides with a concentration of rollover structures across depobelts having short southern flanks and little paralic sequence to the south. Doust and Omatsola (1990) suggest that the distribution of petroleum is likely related to heterogeneity of source rock type (greater contribution from paralic sequences in the west) and/or segregation due to remigration. Haack et al, (1997) relate the position of the oil-rich belt to oil-prone marine source rocks deposited adjacent to the delta lobes (fig. 15), and suggest that the accumulation of these source rocks was controlled by pre-Tertiary structural sub-basins related to basement structures.

Outside of the "oil-rich belt" (central, easternmost, and northernmost parts of the delta), the gas:oil ratios (GOR) are high. The GOR within each depobelt increases seaward and along strike away from depositional centres. Causes for the distribution of GOR’s are speculative and include remigration induced by tilting during the latter history of deposition within the downdip portion of the depobelt, updip flushing of accumulations by gas generated at higher maturity, and/or heterogeneity of source rock type (Doust and Omatsola, 1990).

Stacher (1995), using sequence stratigraphy, developed a hydrocarbon habitat model for the Niger Delta (fig. 16). The model was constructed for the central portion of the delta, including some of the oil-rich belt, and relates deposition of the Akata Formation (the assumed source rock) and the sand/shale units in the Agbada Formation (the reservoirs and seals) to sea level. Pre-Miocene Akata shale was deposited in deep water during lowstands and is overlain by Miocene Agbada sequence system tracts. The Agbada Formation in the central portion of the delta fits a shallow ramp model with mainly highstand (hydrocarbon-bearing sands) and transgressive (sealing shale) system tracts–third order lowstand system tracts were not formed. Faulting in the Agbada Formation provided pathways for petroleum migration and formed structural traps that, together with stratigraphic traps, accumulated petroleum. The shale in the transgressive system tract provided an excellent seal above the sands as well as enhancing clay smearing within faults.

Figure 15: Schematic showing the location of lobes of the early Niger Delta, prolific oil centres, and shale prone areas (Tuttle et al, 1999). Modified from Ejedawe (1981) and Reijers et al 1997.

Figure 16: Sequence stratigraphic model for the central portion of the Niger Delta showing the relation of source rock, migration pathways and hydrocarbon traps related to growth faults. The main boundary fault separates megastructures which represent major breaks in the regional dip of the delta (Evamy et al, 1978, Tuttle et al, 1999). Modified from Stacher (1995).

2.3.2 Properties of Petroleum Fields

Most fields consist of a number of individual reservoirs that contain oil of varying composition with different gas/oil ratios. Gas caps are common. Many reservoirs are overpressured and primary production is mainly from gas expansion (Kulke, 1995). Common oil production problems include water coning, unconsolidated sands, wax deposition and high gas/oil ratios (see below), leading to ultimate recovery rates up to 30% (Kulke, 1995). The size and depth distribution of oil and gas fields is shown in Figure 17.

2.2.3 Properties of Oil and Gas

The physical and chemical properties of the oil in the Niger Delta are highly variable, even down to the reservoir level. Organic geochemical profiles for a nonbiodegraded and moderately biodegraded Niger Delta oil are summarized in Figure 18. The oil within the delta has a gravity range of 16-50° API, with the lighter oils having a greenish-brown color (Whiteman 1982). Fifty-six percent of Niger Delta oils have an API gravity between 30° and 40° (Thomas, 1995). Most oils fall within one of two groups. The first group are light paraffin based, waxy oils from deeper reservoirs (wax content up to 20%, but commonly around 5%; Kulke, 1995; Doust and Omatsola, 1990; high n-paraffin/naphthene of 0.86, fig. 18). The second group of oils are biodegraded and from shallow reservoirs. They have lower API gravity (average API of 26°; Kulke, 1995) and are naphthenic non-waxy oils (n–paraffin/naphthene = 0.37, fig. 18). Biodegradation and washing is extreme in some Pleistocene sands of the Agbada Formation, forming extra heavy oils (API 8-20°). Oils with less than 25° API account for only 15% of the Niger Delta reserves (Thomas, 1995). The concentration of sulfur in most oils is low, between 0.1 % and 0.3 % (Mbendi, 1996), with a few samples having concentrations as high as 0.6 % (Nwachukwu et al, 1995). A limited data set (Mbendi, 1996; Nwachuku et al, 1995) shows a negative correlation between API gravity and sulfur content, suggesting that sulfur content is likely related to oil degradation. This trend, however, is not seen in the data presented in Figure 18.

Oils derived from terrestrial organic matter such as those in the Niger Delta have high pristane:phytane ratios (fig. 18). If the oils are derived from terrestrial organic matter younger than mid-Cretaceous, then the oleanane:C30-hopane ratios are high as well (fig. 18).

Concentrations of Ni and V in Niger Delta oils are less than 100 and V/(V+Ni) values range between 0.01 and 0.41 with an average of 0.12 ppm (Nwachukwu et al, 1995), consistent with values in oils derived from Type III organic matter (Lewan and Maynard, 1982). Concentrations of sulfur and V/(V+Ni) in Niger Delta oil, place the Niger Delta source rocks in Lewan’s (1984) Regime II with respect to source-rock depositional conditions. These trace-metal data, together with the organic geochemistry and physical properties of the oil indicate that the Niger Delta source rocks contain predominately terrestrial organic matter. The organic matter was deposited in suboxic-anoxic bottom waters where vanadyl and nickel availability for bonding was hindered in part by formation of hydroxides and complexing with metastable sulfide ions, respectively. Preservation of the organic matter would be quite good under these conditions.

The associated gas in the Niger Delta is thermal in origin (13C values of -36 to 40‰; Doust and Omatsola, 1990), with low CO2 and N2 concentrations. Hydrogen sulfide is not a problem associated with Niger Delta gas; however, relatively high mercury concentrations have been observed. Currently, 75% of the gas produced from the Niger Delta is flared, 10% is reinjected to maintain reservoir pressure, and only 15% marketed. (Energy Information Administration, 1998b).

Figure 17: Histograms showing the distribution of size and average reservoir depths in (A) oil fields and (B) gas fields (Tuttle et al, 1999).

Figure 18: Geochemical data for a non-biodegraded oil (A) and a partially biodegraded oil (B) from the Niger Delta. Data include whole crude gas chromatograms, charts showing relative proportions of bulk composition and a variety of physical and chemical analyses and ratios (Tuttle et al, 1999).

2.4 Source Rock

2.4.1 Source Rock Identification

There has been much discussion about the source rock for petroleum in the Niger Delta (e.g. Evamy et al, 1978; Ekweozor et al, 1979; Ekweozor and Okoye, 1980; Lambert-Aikhionbare and Ibe, 1984; Bustin, 1988; Doust and Omatsola, 1990). Possibilities include variable contributions from the marine interbedded shale in the Agbada Formation and the marine Akata shale, and a Cretaceous shale (Weber and Daukoru, 1975; Evamy et al, 1978; Ejedawe et al, 1979; Ekweozor and Okoye, 1980; Ekweozor and Daukoru, 1984; Lambert-Aikhionbare and Ibe, 1984; Doust and Omatsola, 1990; Stacher, 1995; Frost, 1977; Haack et al, 1997, Tuttle et al, 1999).

2.4.2 Agbada-Akata

The Agbada Formation has intervals that contain organic-carbon contents sufficient to be considered good source rocks (see data in Ekweozor and Okoye, 1980; Nwachukwu and Chukwura, 1986). The intervals, however, rarely reach thickness sufficient to produce a world-class oil province and are immature in various parts of the delta (Evamy et al, 1978; Stacher, 1995). The Akata shale is present in large volumes beneath the Agbada Formation (fig. 13A) and is at least volumetrically sufficient to generate enough oil for a world class oil province such as the Niger Delta (Tuttle et al, 1999).

Based on organic-matter content and type, Evamy et al (1978) proposed that both the marine shale (Akata Fm.) and the shale interbedded with paralic sandstone (lower Agbada Fm.) were the source rocks for the Niger Delta oils.

Ekweozor et al (1979) used ab-hopanes and oleananes to fingerprint crude with respect to their source–the shale of the paralic Agbada Formation on the eastern side of the delta and the Akata marine-paralic source on the western side of the delta. Ekweozor and Okoye (1980) further constrained this hypothesis using geochemical maturity indicators, including vitrinite reflectance data that showed rocks younger than the deeply buried lower parts of the paralic sequence to be immature. Lambert-Aikhionbare and Ibe (1984) argued that the migration efficiency from the over-pressured Akata shale would be less than 12%, indicating that little fluid would have been released from the formation. They derived a different thermal maturity profile, showing that the shale within the Agbada Formation is mature enough to generate hydrocarbons. [See discussion about expulsion from abnormally pressured source rocks in the section on Petroleum Generation, Migration and Accumulation.]

Ejedawe et al, (1984) use maturation models to conclude that in the central part of the delta, the Agbada shale sources the oil while the Akata shale sources the gas. In other parts of the delta, they believe that both shales source the oil. Doust and Omatsola (1990) conclude that the source organic matter is in the deltaic offlap sequences and in the sediments of the lower coastal plain. Their hypothesis implies that both the Agbada and Akata Formations likely have disseminated source rock levels, but the bulk will be in the Agbada Formation. In deep water, they favour delta slope and deep turbidite fans of the Akata Formation as source rocks. The organic matter in these environments still maintains a terrestrial signature, however, it may be enriched in amorphous, hydrogen-rich matter from bacterial degradation. Stacher (1995) proposes that the Akata Formation is the only source rock volumetrically significant and whose depth of burial is consistent with the depth of the oil window.

2.4.3 Cretaceous Shale

Some have proposed that marine Cretaceous shale beneath the Niger Delta is a viable source rock (e.g. pre-Albian super source rock; Frost, 1997). This Cretaceous section has never been drilled beneath the delta due to its great depth; therefore, no data exist on its source-rock potential. Migration of oil from the Cretaceous into the reservoirs in the Agbada Formation would have required an intricate fault/fracture network as the Akata shale reaches a thickness greater than 6,000 meters. No data exist to support such a network. The chemical composition of the oils provides conflicting evidence for the hypothesis of a Cretaceous source rock, especially for an Early Cretaceous one. Nwachukwu et al, (1995) report low V : V + Ni ratios in Niger Delta crude (0.12), a ratio quite smaller than the ratio in Cretaceous oils in onshore seeps in the northern portion of the province (0.46; Oluwole et al, 1985 as cited in Kulke, 1995). The V + Ni ratios for Miocene oils reported in 1998 by Geomark Research Inc. (fig. 18), however, are similar to those in the Cretaceous oils. Significant oleanane is found in Niger Delta crude. This compound is related to angiosperms, which only became wide spread in the Late Cretaceous-Tertiary. Haack et al (1997) use the northern Gulf of Mexico Basin model of older rocks sourcing oils in deeper water to suggest that oil in hypothetical deep-water plays of the Niger Delta may be sourced, in part, by Upper Cretaceous rocks. As these oils are in hypothetical plays, no geochemical data are available yet to test such a hypothesis in the Niger Delta.

2.4.4 Source Rock Chemical Characteristics

Bustin (1988), in a detailed source-rock study on side-wall core and cuttings from the Agbada-Akata transition or uppermost Akata Formation, concluded that there are no rich source rocks in the delta. With respect to oil potential, Bustin claims that the poor source-rock quality has been more than compensated by their great volume, excellent migration pathways, and excellent drainage. The oil potential is further enhanced by permeable interbedded sandstone and rapid hydrocarbon generation resulting from high sedimentation rates. The total organic-carbon (TOC) content of sandstone, siltstone, and shale in his study is essentially the same (average of 1.4 to 1.6% TOC). The content, however, seems to vary with age of the strata—a trend of decreasing content with decreasing age (average of 2.2% in the late Eocene compared to 0.9% in Pliocene strata). Bustin’s Eocene TOC average compares well with the averages of 2.5% and 2.3% obtained for Agbada-Akata shales in two wells (Udo and Ekweozor, 1988). Ekeweozor and Okoye (1980) report TOC values from 0.4 to 14.4% in both the onshore and offshore paralic sediments. Nwachukwu and Chukwura (1986) report values as high as 5.2% in paralic shales from the western part of the delta. The higher TOC contents are limited to thin beds and are only easily recognized in conventional cores (Doust and Omatsola, 1990).

The organic matter consists of mixed maceral components (85-98% vitrinite with some liptinites and amorphous organic matter) (Bustin, 1988). There is no evidence of algal matter and the shales are low in sulfur (.02 to .1 %). Hydrogen indices (HI) are quite low and generally range from 160 to less than 50 mg HC/g TOC. Ekweozor and Daukoru (1994) believe that Bustin’s average of 90 mg HC/g TOC underestimates the true source-rock potential because of matrix effects on whole-rock pyrolysis of deltaic rocks. Udo et al, (1988) report HI values of 232 for immature kerogen isolates from Agbada-Akata shales. HI values over 400 have been measured (U.S. Geological Survey, unpublished proprietary data).

Pristane/phytane in extracts range between 2 and 4 (Bustin, 1988). Bustin found that both HI values and pristane/phytane change with stratigraphic position similarly to TOC contents (lower values in younger strata). He attributes these stratigraphic trends in organic-matter to increased dilution as sedimentation rates increased and possibly an increase in oxidizing conditions of the depositional environment.

2.4.5 Source Rock Potential

Demaison and Huizinga (1994) have estimated the average source potential index (SPI) for the Niger Delta at 14 t HC/m2. Given that the Niger Delta is a vertically drained system (drainage area small), the SPI value is in the upper portion of the medium range of worldwide values. SPI is calculated as follows:

SPI (in metric tons HC/m2) = h(S1+S2)r/1000

Where h is thickness of source rock in meters, S1+S2 is the average genetic potential in kilograms of HC per metric ton of rock, and r is the rock density in metric tons per cubic meter (Demaison and Huizinga, 1994). Using a genetic potential of 7.5 kg/t (median of U.S. Geological Survey unpublished proprietary Niger Delta data) and assuming a density of 2.26 g/cm3 (Michael Lewan, U.S. Geological Survey, written communication, 1999), the thickness of source rocks required by the above equation is 825 meters. This is much larger than the 100 to 300 metre thickness calculated using material balance equations (Michael Lewan, U.S. Geological Survey, written communication, 1999). One hundred to 300 meters of mature source rock could be easily accommodated in the mature, lower portion of the Agbada Formation and the uppermost Akata Formation.

We agree with researchers (Evamy et al, 1978 among others) who believe that both formations are source rocks for the Niger Delta oil. The two formations are just different facies within the same depositional system and likely contain similar organic matter. Each formation contributes variably to the hydrocarbons generated, depending on the location within the delta and the depth of burial. Based on proposed migration pathways, oil composition, and a variety of other factors, we tend to favour a source-rock thickness on the order of 100 to 300 meters rather than 825 meters. A 100 to 300 metre thickness implies that, if correct, the SPI value for the Niger Delta estimated by Demaison and Huizinga (1994) is too high.

2.5 Reservoir Rock

Petroleum in the Niger Delta is produced from sandstone and unconsolidated sands predominantly in the Agbada Formation. Characteristics of the reservoirs in the Agbada Formation are controlled by depositional environment and by depth of burial. Known reservoir rocks are Eocene to Pliocene in age, and are often stacked, ranging in thickness from less than 15 meters to 10% having greater than 45 metres thickness (Evamy et al, 1978). The thicker reservoirs likely represent composite bodies of stacked channels (Doust and Omatsola, 1990). Based on reservoir geometry and quality, Kulke (1995) describes the most important reservoir types as point bars of distributary channels and coastal barrier bars intermittently cut by sand-filled channels. Edwards and Santogrossi (1990) describe the primary Niger Delta reservoirs as Miocene paralic sandstones with 40% porosity, 2 Darcy permeability, and a thickness of 100 meters. The lateral variation in reservoir thickness is strongly controlled by growth faults; the reservoir thickens towards the fault within the down-thrown block (Weber and Daukoru, 1975). The grain size of the reservoir sandstone is highly variable with fluvial sandstones tending to be coarser than their delta front counterparts; point bars fine upward, and barrier bars tend to have the best grain sorting. Much of this sandstone is nearly unconsolidated, some with a minor component of argillo-silicic cement (Kulke, 1995). Porosity only slowly decreases with depth because of the young age of the sediment and the coolness of the delta complex (see geothermal gradient data below).

In the outer portion of the delta complex, deep-sea channel sands, low-stand sand bodies, and proximal turbidites create potential reservoirs (Beka and Oti, 1995). Burke (1972) describes three deep-water fans that have likely been active through much of the delta’s history (fig. 19). The fans are smaller than those associated with other large deltas because much of the sand of the Niger-Benue system is deposited on top of the delta, and buried along with the proximal parts of the fans as the position of the successive depobelts moves seaward (Burke, 1972). The distribution, thickness, shaliness, and porosity/permeability characteristics of these fans are poorly understood (Kulke, 1995).

Figure 19: Physiographic sketch of the deep marine sediments in the Gulf of Guinea off the Niger Delta. Modified from Burke (1972) and Reijers et al, (1997). (Tuttle et al, 1999).

Tectono-stratigraphy computer experiments show that local fault movement along the slope edge controls thickness and lithofacies of potential reservoir sands downdip (Smith-Rouch et al, 1996). The slope-edge fault simulation from these experiments is shown in Figure 20. Smith-Rouch (written communication, 1998) states that "by extrapolating the results to other areas along the shelf margin, new potential reservoirs are identified."

2.6 Traps and Seals

Most known traps in Niger Delta fields are structural although stratigraphic traps are not uncommon (fig. 21). The structural traps developed during synsedimentary deformation of the Agbada paralic sequence (Evamy et al, 1978; Stacher, 1995). As discussed earlier, structural complexity increases from the north (earlier formed depobelts) to the south (later formed depobelts) in response to increasing instability of the under-compacted, over-pressured shale. Doust and Omatsola (1990) describe a variety of structural trapping elements, including those associated with simple rollover structures, clay filled channels, structures with multiple growth faults, structures with antithetic faults, and collapsed crest structures.

On the flanks of the delta, stratigraphic traps are likely as important as structural traps (Beka and Oti, 1995). In this region, pockets of sandstone occur between diapiric structures. Towards the delta toe (base of distal slope), this alternating sequence of sandstone and shale gradually grades to essentially sandstone.

The primary seal rock in the Niger Delta is the interbedded shale within the Agbada Formation. The shale provides three types of seals—clay smears along faults, interbedded sealing units against which reservoir sands are juxtaposed due to faulting, and vertical seals (Doust and Omatsola, 1990). On the flanks of the delta, major erosional events of early to middle Miocene age formed canyons that are now clay-filled (fig. 12). These clays form the top seals for some important offshore fields (Doust and Omatsola, 1990).

Figure 20: Slope-Edge Normal Fault Simulation (2 Ma – present) for the Niger Delta. Bright Intervals are Sands (Tuttle et al, 1999).

Figure 21. Niger Delta oil field structures and associated trap types (Tuttle et al, 1999). Modified from Doust and Omatsola (1990) and Stacher (1995).

2.7 Petroleum Generation and Migration

Evamy et al (1978) set the top of the present-day oil window in the Niger Delta at the 240°F (115° C) isotherm. In the northwestern portion of the delta, the oil window (active source-rock interval) lies in the upper Akata Formation and the lower Agbada Formation as shown in Figure 22. To the southeast, the top of the oil window is stratigraphically lower (up to 4000’ below the upper Akata/lower Agbada sequence; Evamy et al, 1978). Some researchers (Nwachukwu and Chukwura, 1986; Doust and Omatsola, 1990; Stacher, 1995) attribute the distribution of the top of the oil window to the thickness and sand/shale ratios of the overburden rock (Benin Fm. and variable proportions of the Agbada Fm.). The sandy continental sediment (Benin Fm.) has the lowest thermal gradient (1.3 to 1.8°C/100 m); the paralic Agbada Formation has an intermediate gradient (2.7°C/100 m); and the marine, over-pressured Akata Formation has the highest (5.5°C/100 m) (Ejedawe et al, 1984). Therefore, within any depobelt, the depth to any temperature is dependent on the gross distribution of sand and shale. If sand/shale ratios were the only variable, the distal offshore subsurface temperatures would be elevated because sand percentages are lower. To the contrary, the depth of the hydrocarbon kitchen is expected to be deeper than in the delta proper, because the depth of oil generation is a combination of factors (temperature, time, and deformation related to tectonic effects) (Beka and Oti, 1995).

Figure 22: Subsurface depth to top of Niger Delta oil kitchen showing where only the Akata Formation is in the oil window and where a portion of the lower Agbada is in the oil window. Contours are in feet (Tuttle et al, 1999). Modified from Evamy et al (1978).

Figure 23 shows a burial history chart for the Oben-1 well in the northern portion of the delta (see fig. 22 for well location). In the late Eocene, the Akata/Agbada formational boundary in the vicinity of this well entered the oil window at approximately 0.6 Ro (Stacher, 1995). Evamy and other (1978) argue that generation and migration processes occurred sequentially in each depobelt and only after the entire belt was structurally deformed, implying that deformation in the Northern Belt would have been completed in the Late Eocene.7 The Akata/Agbada formational boundary in this region is currently at a depth of about 4,300 m, with the upper Akata Formation in the wet gas/condensation generating zone (vitrinite reflectance value >1.2; Tissot and Welte, 1984). The lowermost part of the Agbada Formation here entered the oil window sometime in the Late Oligocene.

The Northern Belt’s Ajalomi-1 well about 25 km to the south of Oben-1 shows the Akata source rock first entering the oil window in the Oligocene after reservoir rock deposition (see Figure 19, p. 266 in Stacher, 1995). Stacher assumes migration overlaps in time with the burial and structure development of overlying reservoir sequences and occurs primarily across and up faults (see fig. 16). Migration pathways were short as evidenced from the wax content, API gravity, and the chemistry of oils (Short and Stäuble, 1967; Reed, 1969).

Migration from mature, over-pressured shales in the more distal portion of the delta may be similar to that described from over-pressured shales in the Gulf of Mexico. Hunt (1990) relates episodic expulsion of petroleum from abnormally pressured, mature source rocks to fracturing and resealing of the top seal of the over-pressured interval. In rapidly sinking basins, such as the Gulf of Mexico, the fracturing/resealing cycle occurs in intervals of thousands of years. This type cyclic expulsion is certainly plausible in the Niger Delta basin where the Akata Formation is over-pressured. Beka and Oti (1995) predict a bias towards lighter hydrocarbons (gas and condensate) from the over-pressured shale as a result of down-slope dilution of organic matter as well as differentiation associated with expulsion from over-pressured sources.

Figure 23: Burial history chart for the norther portion of the Niger Delta (Akata/Agbada) petroleum system. Data from Oben-1 well in Norther Depobelt (see fig. 22 for location). Modified from Ekweozor and Daukoru (1994). (Tuttle et al, 1999).

CHAPTER 3

Materials and Methods

3.1 Data Set

Data for this project was provided by Chevron Nigeria Limited, which include 3D Seismic, Suite of logs for 6 wells; Gamma Ray (GR) logs, Resistivity logs as well as Biostratigraphic data. The base map showing the area extent of the seismic and the location of the wells can be seeing in figure 24.

3.1.1 Seismic Volume

The seismic volume is a SEGY file with six (6) wells drilled in the area where the seismic volume was acquired. For quality control, that is to see if the seismic acquisition was properly carried out and the resulting data well processed, a quick pan through the data was done at an interval of 5 lines in Petrel interpretation window. The seismic data has a recording time of 6000ms and is highly faulted with an antithetic and synthetic faults dipping basinward.

3.1.2 Gamma Ray (GR) Logs

Gamma Ray (GR) Logs is a lithology identifier. It measures the radioactive response of the formation which is a function of the clay mineral content and thus its grain size and depositional energy. A signal deflection to the right is indicative of shale (relatively due to radiation that emanates from naturally occurring Uranium, Thorium and Potassium), while a deflection to the left of the curve is indicative of sand.

Figure 24: Base Map of the Study Area Showing Seismic Lines Intersecting the Wells.

3.1.3 Resistivity Logs

This measures the bulk resistivity of a formation, which is a function of the porosity and pore fluid. Porous formation containing conductive fluid exhibits a low resistivity value, which makes it an excellent lithology indicator as well as suitable for correlating within shale successions.

3.1.4 Biostratigraphic Data

Biofacies data were calibrated and depth matched with corresponding wireline logs. Environmental and paleobathymetric interpretation that was given were achieved from population and diversity of benthonic and planktonic foraminifera.

Biozone records given were the Foraminifera and Nanofossil Zones referred as the P and N zones.

3.2 Methodology

Schlumberger Petrel 2014 was used for the interpretation of the 3D seismic and well log data sets used in this study. Petrel is a Windows based software application which covers a wide range of workflows from seismic interpretation to reservoir simulation. A project was created in Petrel for this study and available data were loaded and quality checked before interpretation began, which include faults mapping so as to determine the trapping mechanism in place in the field, also two wells (Okwute south-1x and Okwute-6) with biostratigraphic interpretation chart received in pdf format were available, these were correlated with the Gamma ray and resistivity well log data of six (6) wells namely: Okwute-01, Okwute-02, Okwute-03st, Okwute-04, Okwute-05, Okwute-06l received in .las format, the .las files were imported into the Petrel 2014 software in that format and the result of the correlation were recorded accordingly.

The interpretation of depositional settings in wells Okwute south-1x and Okwute-6 using sequence stratigraphy follows the standard interpretation procedure recommended by Mitchum et al (1993).

3.2.1 Identifying Key Stratigraphic Surfaces

Maximum Flooding Surface (MFS) was recognized on the wireline logs and biostratigraphic data as: the boundary between retrogradational parasequence sets and progradational parasequence sets; units of maximum shale peaks and well-developed shales (shaliness) visible on the Gamma Ray and Resistivity; a surface of maximum foraminifera abundance and diversity. Plots of faunal abundance and diversity curves alongside well logs enhanced the recognition of Maximum Flooding Surfaces (fig. 25).

Sequence Boundaries (SB) were recognised in areas of low faunal abundance and diversity or absence of known bio-events, which corresponds to low Gamma Ray, high Resistivity logs responses within the shallowing section. Candidate sequence boundaries were identified as the base of thickest and coarsest sand unit between two adjacent Maximum Flooding Surfaces, which naturally coincided with the shallowest environments associated with the least foraminfera abundance and diversity or complete absence of foraminfera (fig. 25).

The relative ages of the surfaces mapped in the wells; MFSs and SBs were dated with marker shales (P and N zones) and by correlation with the Niger Delta Chronostratigraphic Chart, Haq et al, (1988) also using biostratigraphic report of Adegoke et al, (1976).

3.2.2 Identifying System Tract and Depositional Sequences

Three (3) System Tracts (LST, TST, and HST) were recognized and mapped, with the aid of the depositional sequence model, Vail et al, 1977 (fig. 25).

The system tracts comprise of integration of depositional environments which form depositional sequences characterizing them. The depositional sequences are delineated using Gamma Ray Log Signatures or motif – fining and coarsening upward motif and biofacies data (fig. 26).

Bell shaped log motif on Gamma Ray Logs indicate increasing clay contents up section or fining upward trends, an upward increase in gamma ray value is a typical feature of fluvial channel deposits. Funnel shaped log motif indicate decreasing clay contents up section or a coarsening upward trend, a clear indication of a deltaic progradation. Cylindrical (blocky or boxcar) log motif delineate thick uniformly graded coarse grain sandstone unit, probably deposits of braided channel, tidal channel or subaqueous slump deposits. Serrated log motif suggests intercalation of thin shales in a sandstone body, typically of fluvial, marine and tidal processes, Kendall et al, (2005).

Figure 25: Geomorphology, cyclic sedimentation and an active fault in the Tertiary Niger Delta coastal zone (Reijers, 2011). Modified after Weber, 1971.

Figure 26: Gamma Ray Log Shapes and Depositional Settings (Adapted from Rider, 1999).

CHAPTER 4

Results and Interpretation

The results of Biostratigraphy (Foraminiferal micropaleontology, Palynology and Nannopaleontology), Sedimentology, Paleoenvironmental and Sequence stratigraphic analyses of ditch cutting samples obtained from Okwute-1 well, interval 6360ft – 12,900ft and Okwute-6 well, interval 5010ft – 13,290ft are presented in this report.

The zonation schemes of Blow (1969) incorporated in Bolli and Saunders (1985) of age diagnostic planktic taxa, as well as known age diagnostic benthic assemblage(s) in the Niger delta were utilized in age interpretation and definition of associated foraminiferal zones. Accordingly, two (2) microzones ?N15 and N14 have been delineated in this study.

The definition of palynological zones (P-Zone) followed the approach of Evamy, et al., (1978). Based on this, two (2) subzones P780 and P770 were delineated in the analyzed interval of the well.

The studied interval 6360ft – 12,900ft of the Okwute-1 well was completely barren of nannofossils hence no nanno-zone nor age was proposed for the well. This may be due to unfavorable preservation conditions of a localized nature, hence resulting in no preservation of nannofossils in the well. While in interval 5010ft – 13,290ft of the Okwute-6 well the definition of Nannopaleontological zones followed the approach of Martini, (1971); and resulted in the delineation of two (2) nannozones: NN9, as well as a composite NN8 – ?NN7 nannozone. These two nannozones are bounded above and below, by intervals virtually barren of nannofossils and therefore could not be assigned any nanno-zone.

Following the results of these analyses, the sediments of Okwute-1x and Okwute-6 well (interval 6,360ft – 12,900ft and 5,010ft – 13,290ft) were deposited as part of the Benin and Agbada Formations with the boundary between both Formations delineated at 7200ft and 7100ft respectively. Deposition of these units took place in Middle – Late Miocene times.

Sequence stratigraphic analysis and interpretations were based on the integration of biostratigraphic, paleobathymetric, sedimentological and wireline (GR and Resistivity) logs data; resulted in the delineation of one Maximum Flooding Surface (MFS) proposed at 9120ft (?10.4 Ma) for Okwute-1 well and 8900ft (?10.4 Ma) for Okwute-6 well. The associated Sequence Boundary (SB) was delineated at 7200ft, (?10.35 Ma) and 10,500ft (?10.6 Ma) in the Okwute-1 well and 7100 (?10.35 Ma) and 10,450ft (10.6 Ma) in the Okwute-6 well.

Dating of these key surfaces was achieved by correlation to the third order cycles chart of Haq, et al., (1988), as well as inferences from chronologically significant bio-events.

Paleoenvironmental interpretations were based on the integration of microfaunal, microfloral, paleobathymetric, lithologic and wireline (GR and Resistivity) logs data. The results indicate that the stratigraphic development of Okwute-1x well, took place in delta plain to prodelta environments within non-marine to middle neritic paleo-water depths and delta plain – distal delta front paleoenvironments within non-marine to ?middle shelf paleowater depths in the Okwute-6 well.

A synthesized stratigraphic summary of the analyzed interval of the well is presented overleaf, while the detailed stratigraphic summary is presented as enclosure 3, 4.

The correlation of Okwute-1 and Okwute-6 wells was attempted using the 10.4Ma MFS as well as the P780 / P770 boundary and is presented in a summarized correlation panel overleaf. The correlation shows that the Okwute –1 well is located down-dip of Okwute –6 well with a displacement of about 220ft, which may be indicative of faulting in the area during Late Middle Miocene times.

Stratigraphy

The two wells have a similar stratigraphy which is not arbitrary but essentially because of their occurrence in the same field and consequently, the same (Niger Delta) basin. Okwute-1 (interval 6360ft – 12,900ft) and Okwute-6 (interval 5010ft – 13,290ft) well penetrated the Benin and the Agbada Formations as observed from the lithologic and wireline log characteristics. The base of the Benin Formation was delineated at 7200ft in Okwute-1 and 7100ft in Okwute-6 using the resistivity log reading which showed an abrupt kick to the left, coinciding with the sequence boundary encountered at these depths. The Benin Formation is characterized by massive (medium – coarse grained) sands with minor shale intercalations, barren of microfauna; while the underlying Agbada Formation is characterized by the paralic development of sands, shales and silts within the analysed interval. These litho-units were deposited in non-marine to middle shelf paleo-water depths during Middle – Late Miocene times.

One transgressive event is recognized; the peak proposed as MFS candidate, based on the relative abundance and diversity of microfauna and associated high gamma ray log value. The MFS delineated at 9120ft and 8900ft for Okwute-1 and Okwute-6 respectively and has been dated ?10.4 Ma by correlation to the third order cycles chart of Haq, et al, (1988).

Sequence Stratigraphy

Sequence stratigraphic analysis and interpretation of Okwute-1 & 6 wells, was achieved by the integration of biostratigraphic, lithologic and wireline (Gamma ray and Resistivity) log data.

The approach of Vail and Wornadt (1991) was adopted, while bearing in mind the pitfalls that are commonly associated with log facies analysis; cave-ins and missing/sampling intervals.

The Maximum Flooding Suface (MFS) was delineated based on the relative high abundance and diversity of (foraminifera) fossils, relative abundance of Zonocostites ramonae (Mangrove pollen) associated with high GR log value. The MFS provided the basis for the recognition of genetic depositional sequences. The proposed Sequence Boundaries (SB) on the other hand, were delineated based on faunal minima associated with low GR log value.

Dating of these key surfaces (MFS and SB) was achieved by correlation to the third order cycles chart of Haq, et al., (1988). The sequence stratigraphic summary is presented in tables 2 & 3.

Table 2: Sequence Stratigraphic Summary of Okwute-1 Well

Table 3: Sequence Stratigraphic Summary of Okwute-6 Well

Details of the interpreted systems tracts are presented below.

Systems Tract: Highstand Well: Okwute-1

Interval: 12,900ft – 10,500ft

The onset of this systems tract was not tested in the analyzed interval. The lithofacies are predominantly shales and sands with minor silts and sandstones, at the lower section whereas sands and silts characterize the upper section. This systems tract was deposited in the middle to inner/shallow neritic settings in a shallowing upward pattern, reflecting an overall progradational (coarsening upward) trend, typical of a highstand systems tract. Also, gradual reduction in both occurrences of mangrove pollen (Zonocostites ramonae) and marine indicators are observed within this interval.

This systems tract was terminated at 10,500ft, at a sequence boundary (SB) inferred on top of an aggrading sand body, coinciding with the low GR log value and faunal minima recorded at this depth. The SB is dated ?10.6 Ma by correlation to the third order cycles chart of Haq, et al., (1988).

Systems Tract: Highstand Well: Okwute-6

Intervals: 13,290ft – 10,450ft

The relative abundance and diversity of microfauna observed in the lower section of the interval is probably associated with the terminal phase of a preceding rise in sea level (the earliest phase of an HST). The deposition of these predominantly progradational/aggradational sands (with shale intercalations) took place in middle shelf to non-marine paleobathymetric settings. The log motif within the interval shows progradational (coarsening upward) units above and below; with an aggradational unit between them. The top of this systems tract (that is, the SB) was delineated at 10,450ft the base of an aggradational (blocky) sand body. This is probably the base of an incised valley fill.

The SB is dated 10.6 Ma by correlation to the global sea level cycles chart of Haq, et al., (1988). The LDO of Discoaster hamatus (10.7 Ma) inferred at 10,530ft lends credence to this age interpretation.

Systems Tract: Transgressive Well: Okwute-1

Interval: 10,500ft – 9120ft

Shales and sands (with minor silt) deposited in shallow inner/inner – middle shelf paleo-water depths with overall back-stepping (fining upward) pattern of log motifs, characterize this transgressive interval. Also indicative of this systems tract are high occurrences of mangrove elements and marine indicators within the analyzed interval.

The peak of this transgression (MFS) which terminated this systems tract was marked at 9120ft based on the high abundance and diversity of fauna associated with the high gamma ray log value at this depth. This MFS is dated ?10.4 Ma by correlation to third order cycles chart of Haq, et al., (1988).

Systems Tract: Transgressive Well: Okwute-6

Interval: 10,450ft – 8900ft

This transgressive phase is characterized by progradational through aggradational to retrogradational log motif patterns within the interval. The corresponding lithofacies (sands and shales) were deposited in non-marine to ?middle shelf paleo-water depths. The peak of transgression (MFS) was delineated at 8900ft based on GR log evidence (high GR log value). The nannofossil abundance and diversity peak at 8940ft and foraminiferal abundance and diversity peak at 9000ft were not very reliable because of the large barren intervals above these depths.

However, a supporting evidence is the Zonocostites ramonae peak within the upper most section of the interval. This MFS is probably the 10.4 Ma marker shale, as deduced from Haq, et al., (1988). The difference in depths between the delineated MFS and the associated nannofossil and foraminiferal peaks may be as a result of sampling intervals and/or cave-ins.

Systems Tract: Highstand Well: Okwute-1

Interval: 9120ft – 7200ft

The lower section of this regressive phase is characterized by sands, hemipelagic shales and silts. The percentage of shales decreases toward the upper section which is dominated by stacks of progradational, medium – coarse grained sands. The lithofacies are deposited in inner-middle neritic at the lower section and shoal upwards to shallow inner neritic paleo-water depth setting. Also, high percentage occurrence of Mangrove pollen (Zonocostites ramonae) and scanty marine indicators characterized the lower section of the analyzed interval.

This regressive phase terminated at the SB delineated at 7200ft on top of a prograding sand body, where resistivity log shows an abrupt kick to the left, with no faunal recovery. It is dated ?10.35 Ma by correlation to the third order cycles chart of Haq, et al., (1988).

Systems Tract: Highstand Well: Okwute-6

Interval: 8900ft – 7100ft

The log motif pattern within the interval shows that the lithofacies (predominantly sands with shales and silt intercalations) are progradational to aggradational, and were deposited in predominantly non-marine paleo-water depths; with minor marine incursions as depicted by the rare occurrences of marine (floral) indicator elements within the interval. The top (SB) of this systems tract was delineated at 7100ft; at the base of the overlying and more aggradational sand body. This SB is dated ?10.35 Ma by correlation to the third order cycles chart of Haq, et al., (1988).

Systems Tract: Lowstand (PGC) Well: Okwute-1

Interval: 7200ft – 6360ft

The preceding regressive event persisted within this interval with predominantly aggradational stacking pattern of non marine sand bodies. This is typical of the prograding complex of the lowstand systems tract. The sands are mostly medium – coarse grained, belonging to the Benin Formation and deposited probably in a fluvial setting. The top of this systems tract was not encountered in the analyzed interval of the well.

Systems Tract: Lowstand (PGC) Well: Okwute-6

Interval: 7100ft – 5010ft

The predominantly aggradational, medium-coarse grained sand units; intercalated by silts and shales were deposited in predominantly non-marine (with minor marine influence) paleowater depths. This is probably a prograding wedge complex unit of a Lowstand systems tract. The upper boundary of this depositional systems tract (i.e., transgressive surface) was not encountered in the analysed interval of the well.

Paleoenvironments

Paleoenvironmental interpretation of Okwute-1 and Okwute-6 wells (intervals 6360ft – 12,900ft and 5010ft – 13,290ft respectively) was carried out through the integration of foraminiferal, palynological, lithologic and wireline (GR/Resistivity) log data.

Foraminiferal data was most useful in the estimation of paleobathymetry by the use of relative abundance and diversity of the recovered foraminifera, as well as the occurrence of environmentally significant benthic taxa.

Palynological data on the other hand was useful in the delineation of various palyno-ecological communities encountered in the analysed interval of the well. These communities include Savanna (Charred gramineae cuticle and Monoporites annulatus); Fresh water swamp/Forest elements (Concentricytes circulus, Pediastrum sp., Botryococcus sp., Psilastephanocolporites laevigatus and Pachydermites diederixi), Mangrove swamp (Zonocostites ramonae and Psilatricolporites crassus); and marine indicators (Organic Walled Microplanktons – OWM).

The results indicate that sediments encountered in the analysed interval of Okwute-1 well were deposited in non-marine to middle shelf paleo-water depths within Foreshore to lower shorface paleoenvironmental setting, while for the Okwute-6 well deposition were in non-marine to ?middle shelf paleo-water depths within Foreshore to Upper shoreface paleoenvironmental settings.

The depositional environments and bathymetric ranges used in these interpretations are shown in figure 27.

Interval: 6360ft – 8850ft Well: Okwute-1

Paleobathymetry: Non-marine – shallow inner neritic

Paleoenvironment: Foreshore – upper shoreface

The upper interval (6360ft – 7470ft) and the lower interval (8250ft – 8790ft) are predominantly barren of foraminifera while the mid section (interval 7500ft – 8190ft) showed sparse occurrences of some benthic taxa such as Saccammina complanata, Nodosaria sp, Quinqueloculina seminulum and Bulimina sp, representing shallow inner marine deposition within a predominantly non-marine setting.

The palynological suite within this interval is characterized by sporadic occurrence of marine indicators, moderately high occurrences of mangrove elements, fresh water swamp/forest and savanna elements and extremely low occurrence of montane elements.

This interval consists of predominantly progradational/blocky sands and shales with minor silts. The medium to coarse grained sands described within this interval probably suggest deposition within channel complexes within a delta plain setting exposed to minor marine influence. Coal materials were observed within this interval.

Interval: 5010ft – 8050ft Well: Okwuke-6

Paleobathymetry: Non – marine – ?shallow inner shelf

Paleoenvironment: Foreshore – upper shoreface

This interval is completely barren of foraminifera; while the palyno-assemblage consists of moderately high percentage occurrence of Freshwater / Forest elements, moderately low – moderately high percentage occurrence of Savanna elements, very low – low percentage occurrence of Montane elements, moderately high – very high percentage occurrence of Mangrove elements; coupled with sporadic – moderately low occurrence of marine elements. This suggests minor marine influence in a predominantly non-marine setting.

Lithologically, the interval consists of medium – coarse grained sands associated with silts and shale intercalations. These lithofacies are characterized by blocky log motifs typical of channels deposited in a delta plain – proximal delta front setting.

Interval: 8850ft – 9630ft Well: Okwute-1

Paleobathymetry: Inner – middle neritic

Paleoenvironment: Upper shoreface

This interval is characterized by fluctuation in the paleo-water depth from inner – middle neritic realm. The upper section (8850ft – 9270ft) of this interval showed a regular and sometimes abundant occurrence of some benthic taxa such as Alveolophragmium crassum, Cyclammina sp, Lenticulina inornata and Quinqueloculina microcostata which probably indicate deposition in an inner – middle neritic setting. However, a drop in paleo-water depth to a predominantly inner shelf setting is depicted by the low recovery of faunal taxa between 9270ft – 9630ft.

The moderately low occurrences of marine indicators and montane elements, moderately high occurrence of savanna elements and the high occurrences of mangrove, fresh water swamp / forest elements constitute the palynological community in this interval.

The predominantly blocky sand with shale intercalation encountered in this interval depict channels/bar deposits in a delta front setting.

Interval: 8050ft – 8700ft Well: Okwute-6

Paleobathymetry: ?Non – marine

Paleoenvironment: Upper shoreface

The non-marine inference is based on the non-recovery of microfauna within this interval. However, the palynological assemblage suggests the deposition of the sediments within the interval in a predominantly upper shoreface setting. The assemblage consists of the low percentage occurrence of Montane elements, moderately high percentage occurrences of Savanna and Mangrove elements, the non-occurrence of Fresh water / Forest elements; coupled with moderately low percentage occurrence of marine indicator elements.

Aggradational, progradational and retrogradational log motifs characterize the sands (intercalated by shales and silts) in the interval; and suggest their deposition as channel / bar complexes in a delta plain – delta front setting.

Interval: 9630ft – 11070ft Well: Okwute-1

Paleobathymetry: Shallow inner neritic

Paleoenvironment: ?Lower shoreface

This interval is predominantly a shallow inner neritic setting with a deepening in paleo-water depth to inner neritic setting observed within the mid section (10,410ft – 10620ft) of the interval.

The occurrences of Alveolophragmium crassum, Spiroplectammina wrightii and Haplophragmoides compressa are observed within this interval.

The floral assemblage on the other hand consists of moderately high occurrence of marine indicators, high occurrence of fresh water swamp/forest elements and sporadic occurrence of montane elements.

The log motifs characterizing the shale and sand are retrogradational / progradational and suggest their deposition as probably channels/bar complexes in a delta front setting.

Interval: 8700ft – 9060ft Well: Okwute-6

Paleobathymetry: ?Non-marine – inner shelf

Paleoenvironment: Upper shoreface

The upper section (8700ft – 8820ft) is completely barren of microfauna; therefore, suggesting a non-marine deposition. The lower section on the other hand, is characterized by the occurrences of Alveolophragmium crassum, Epistominella vitrea, Florilus ex. gr. costiferum, Lenticulina inornata and Quinqueloculina vulgaris. This benthic assemblage is associated with an overall low planktic diversity within the interval.

Palynologically, the floral assemblage in this interval is similar to that of the preceding interval, and also suggests a predominantly upper shoreface deposition. Based on these evidences (faunal and floral), the deposition of the sediments of this interval probably took place in an inner-shelf setting with some non-marine influence.

The lithofacies (predominantly shale with silts and sands intercalations) are characterized by aggradational log signatures; suggesting their deposition as interdistributary bay deposits in a delta plain – delta front setting.

Interval: 11,070ft – 11,970ft Well: Okwute-1

Paleobathymetry: Inner neritic

Paleoenvironment: Upper shoreface

The foraminferal assemblage in this interval is made up of the occurrences of Textularia panamensis, Lenticulina inornata and Alveolophragmium crassum which indicate deposition in an inner neritic setting. However, a drop in paleo-water depth to a predominantly shallow inner neritic setting is depicted by the low recovery of faunal taxa between (11610ft – 11970ft).

Palynologically, this interval consists of moderately low occurrence of marine indicators, moderately high occurrences of mangrove and fresh water swamp / forest elements and absence of montane elements.

Lithologically, this interval consists predominantly of medium to coarse-grained sands and shales with minor silts, which are characterized by progradational log signatures suggestive of their deposition as channel and bar deposits within a proximal delta front setting.

Interval: 9060ft – 10,020ft Well: Okwute-6

Paleobathymetry: Shallow inner – inner shelf

Paleoenvironment: Upper shoreface

The sporadic occurrence of Eggerella scabra, Haplophragmoides sp, Lenticulina inornata and Florilus atlanticus is associated with an overall low planktic diversity. This points to a shallow inner shelf deposition with probable non-marine influence – depicted by an interval (9060ft – 9360ft) of non-recovery.

The palynofloral suite in this interval is made up of: moderate – high percentage occurrences of Savanna and Mangrove elements, low percentage occurrence of Montane elements, non-occurrence of Freshwater / Forest elements; in association with low percentage occurrence of marine indicator elements.

The sands and shale intercalations in this interval are characterized by blocky / aggradational log motifs; suggesting their deposition as channels / channel fills in a delta front setting.

Interval: 11,970ft – 12,900ft Well: Okwute-1

Paleobathymetry: Inner – middle neritic

Paleoenvironment: Upper – Lower shoreface

This interval is characterized by frequent fluctuation in the paleo-water depth from inner to middle neritic realm. Foraminiferal contents showed an increase in abundance and diversity when compared to the preceding interval.

The occurrences of significant benthic taxa such as Textularia panamensis, Lenticulina inornata, Florilus (ex. gr.) costiferum and Cibicorbis inflata are observed.

The palyno-ecological community in this interval is characterized by moderately high occurrence of marine, moderately low occurrences of mangrove, freshwater swamp/forest and savanna elements and extremely low occurrence of montane elements.

The interval is predominantly shale and fine to medium grained sands with minor silts and sandstone occurrences. The log signature of these litho-units are retrogradational and aggradational which depicts their deposition as probably bar complexes within a delta front to prodelta paleoenvironment.

Interval: 10,020ft – 10,680ft Well: Okwute-6

Paleobathymetry: Non-marine – shallow inner shelf

Paleoenvironment: Foreshore – upper shoreface

Intervals of non-recovery of microfauna are interlaced with few intervals of sporadic recovery of microfauna. The rare occurrences of Textularia panamensis, and a calcareous indeterminate species characterize this interval.

The palynofloral assemblage in this interval is similar to that of the preceding interval; and suggests a predominantly upper shoreface deposit. These evidences (microfaunal and microfloral) probably point to a proximal inner shelf setting with some non-marine influence.

The sands (and shale/silt intercalations) encountered in this interval are characterized by aggradational / retrogradational log motifs suggesting their deposition as a channel / point bar complex in a delta plain – proximal delta front setting.

Interval: 10,680ft – 12,690ft Well: Okwute-6

Paleobathymetry: Inner shelf

Paleoenvironment: Upper shoreface

The microfaunal assemblage consists of the infrequent occurrences of Alveolophragmium crassum, Ammobaculites strathearnensis, Reophax sp, Florilus ex. gr. costiferum, Epistominella vitrea, Lenticulina inornata, a calcareous indeterminate species and Quinqueloculina sp. Planktic diversity is very low. These occurrences are interlaced with intervals of non-recovery; pointing to occasional non-marine influence.

The palynological assemblage in this interval comprises: the low percentage occurrence of Montane elements, rare – moderately low percentage occurrence of Freshwater / Forest elements, moderately low – moderately high percentage occurrence of Savanna elements, moderately high – high percentage occurrence of Mangrove elements; in association with low percentage occurrence of Marine indicator elements. This points to a predominantly upper shoreface paleoenvironment.

The sands, shales and silts encountered in the interval are characterized by progradational, aggradational and retrogradational log motifs; suggesting their deposition as channel / bar (distributary and point bars) complexes in a delta plain – delta front setting.

Interval: 12,690ft – 13,290ft Well: Okwute-6

Paleobathymetry: Inner – ?middle shelf

Paleoenvironment: Foreshore – upper shoreface

The occurrences of Eggerella ex. gr. forestensis, Eggerella scabra, Ammobaculites sp, Haplophragmoides sp, Textularia sp, Textularia panamensis, Reophax sp, Alveolophragmium crassum, Epistominella vitrea, Florilus ex gr. costiferum, Quinqueloculina microcostata, Ammonia beccarii and Lenticulina inornata; are interlaced with barren intervals above and below suggesting deposition in a predominantly inner shelf setting with some non-marine incursions. However, the relatively moderate planktic diversity within the interval may point to occasional deepening to proximal middle shelf paleo-water depth.

The co-occurrence of extremely low Montane elements, moderately high Savanna elements, moderately low Mangrove elements, and low Marine indicator elements within this interval suggests a foreshore – upper shoreface paleoenvironment.

The sands and shales (with silt intercalations) found in this interval are characterized by progradational / aggradational log motifs; suggesting their deposition as distributary mouth bar / interdistributary bay deposits in a predominantly delta front setting.

The non-availability of GR log signatures from 13,100ft – 13,290ft precluded definite interpretations. However, interpretation in this interval was inferred based on lithologic descriptions (appendix 1).

CHAPTER 5

Summary and Conclusion

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Appendix I