EXPLORATION Niger delta deepwater region petroleum potential assessment

David Thomas
Thomas & Associates
Hastings, England

On behalf of the Nigerian Ministry of Petroleum and Natural Resources some 23,000 km of high quality 192 channel, 96 fold seismic, and associated gravity and magnetic data were acquired by TGSI-Mabon Geophysical Co. and made available to the industry in 1991.

These data were collected over all deepwater blocks in conjunction with the planned 1993 license round. Later, during 1993 and 1994 TGSI with Mabon Ltd. and Stratum Petroleum Services extended the program onto the shelf (7,000 km) and into the ultra deepwater areas (6,400 km), making possible modern studies of the entire offshore delta complex (Fig. 1)(28849 bytes).

In assessing the petroleum potential of an undrilled region, it is useful to refer to analogous basins or pro- vinces already with histories of hydrocarbon exploration and discovery. With this in mind, and using limited data from the already drilled areas of Nigeria offshore, the adjacent West Africa salt basin and Brazil in particular, an attempt is made to discuss the hydrocarbon habitat of the undrilled Niger delta deepwater offshore sedimentary sequences.

Deepwater morphology

Based on limited dip and strike direction seismic profiles in the deepwater offshore, the following morphological features can be recognized.

Similar to the massive growth fault and anticlinal structural features of the near-shore and land regions, the deepwater sedimentary folds appear to occur in competent beds above a possible decollement. The detachment from the underlying rocks is along a deformed zone occurring within a thick Upper Cretaceous-Tertiary shale section.

Domal uplifts, seemingly unrelated to the foldbelt, are interpreted on a number of seismic profiles as probably shale ridges. The uniform folding of most of the upper sedimentary section without any significant shale diapirism in the cores of the folds, suggests regional compression stresses acting in a general north-south direction. Involvement of beds as young as Pliocene and possibly Pleistocene indicates that folding and thrusting are very young and may be continuing today.

Decrease in fold amplitude and decrease in sediment ponding in the synclines in a seaward direction suggest that the zone of maximum deformation moved seaward through time.

At least two separate mechanisms adequately explain the tectonic styles of the Nigerian deepwater offshore (Fig. 2)(21240 bytes):

massive gravity sliding possibly triggered by regional uplift and supplemented by sediment loading at the head of the slide;
compression tectonic stresses originating within the deeper crust and transmitted into the fold area through deep thrust zones.

In both cases, detachment and deformation take place above a decollement or deformed zone located within mobile sub-strata (probably geopressured slope shales).

Fold description

Some folds have wavelengths of approximately 2-10+ km and exhibit no appreciable topographic relief on the sea floor. They are generally quite symmetrical, but in some places they show slight asymmetry in both a landward and seaward direction. The folds decrease in amplitude seaward and finally die out.

Towards the shore, an upper Tertiary (Miocene-Pliocene?) sedimentary se- quence fills in behind the high-amplitude folds (landward). These folds therefore act as barriers to sediments being transported down-slope. The sediments ponded behind the first high-amplitude fold form thick sedimentary depocenters extending in an arcuate form along the upper sedimentary wedge (slope). This sequence expands and fans out up-dip into large growth fault system familiar to the Niger delta petroleum province.

The folds appear to change amplitude, relief, and overall character rapidly; some folds apparently plunge and die out along strike. Based upon a best attempt at correlating some of the fold axes, the folds appear to trend in a general east-west direction in the south to northwest-southeast in the eastern deepwater offshore. This trend forms an en echelon pattern with the trend and direction of the shelf and slope, adjacent growth fault system, and young sedimentary depo-centers behind the folds.

The entire foldbelt contains numerous thrust faults that form an imbricate-type structural pattern. The faults dip mainly landward and tend to flatten at depth and die out within the reflectionless zones of probably Upper Cretaceous-Paleogene age. Most of the faults cut up through the cores of the anticlines, although some occur in the synclines. The faults are very steep in the axes of the tighter folds and are much less steep in the seaward, gentler folds.

Seismic characteristics

The distal relationship of the present day deepwater region to the sedimentary discharge of the Niger delta has made, generally, these areas essentially deepwater marine sediments. This is also based upon seismic characteristics and is supported by relatively low seismic interval velocities (2-3 km/sec).

Seismic interpretation of selected deepwater seismic profiles in conjunction with a morphological appreciation of the region suggest the development of shelf-fed turbidite systems (Table 1)(9397 bytes).

Basic elements required for the development of a shelf-fed turbidite system are:

the presence of a delta that constructs a relatively thick, wide shelf sedimentary unit that constitutes the main source of sediment for the deepwater turbidite system.
tectonic modification of the shelf declivity, leading to shelf sediment failure, and
the relative fall of sea level position, which determines the timing of submarine shelf erosion and reworking.

The main characteristics of the shelf-fed turbidite system are as follows:

The process involved is predominantly sub aqueous. Sediments previously de- posited on the platform are eroded and reworked in a shallow, high energy shelf environment and re-transported to the basin floor.
Multiple source points are active simultaneously. Depending on the availability of the shelf sediments, the multiple source points feed numerous sedimentary lobes on the basin floor, which coalesce laterally to form relatively thin, widespread, blanket-like aprons.
Basin-floor sedimentary facies are more sand rich and cleaner than their source deposits on the shelf. The turbidity currents generated on the shelf environment lose some or most of their suspended fine particles during their journey in unconfined flow regime to the basin floor.

Shelf-fed turbidites

Sand rich turbidites are by far the most important reservoir rocks of the Campos basin off Brazil. They account for 83% of its estimated total in-place oil resource and range from Upper Cretaceous to Miocene.

Oligocene and Miocene sandstones are the principal reservoirs of giant Marlim and Albacora fields, which hold more than 60% of the basins discovered oil reserves. These sandstones were deposited in a deepwater environment and occur dominantly as tabular bodies with good lateral continuity. They range from 30 m to more than 100 m in thickness, cover an area exceeding 6,000 sq km, consist of more than 95% massive and slightly friable sand, and display excellent porosity and permeability, reaching locally almost 30% and up to 5 darcies.

In summary, the shelf-fed turbidite system model will apply to sedimentary basins that contain three requisite elements:

Availability of sand-rich shelf sediments;
Development of tectonic pulse causing mass flows;
Relative sea-level lowering.

Subaerial exposition of the platform is not required; the most important sediment remobilization and transportation processes are predominantly sub-aqueous in the shallow, high energy shelf environment. Tectonic steepening of the earlier shelf platform is likely to develop in those basins having a thick mobile shale substrate.

Other northern Brazil margins with productive turbidite sand reservoirs include the Potiguar (Maastrichtian sands, e.g. Agulha field); Cumuruxitiba (Eocene-Turonian sands); and the DEspirito Santo (Oligocene-Turonian, e.g. Cedro field).

The Niger delta region is ideal for shelf-fed turbidite development.

Source rocks

To assess the source rock potential of the deepwater offshore, it would be opportune to review the oil source generation and correlation of West African and Brazilian offshore basins.1

Recent biomarker data studies show similarity among groups of oils and source facies and suggest an origin from seven types of hypoxic-anoxic environments ranging in age from Lower Neocomian to Eocene/Oligocene. The seven types are lacustrine freshwater, lacustrine brackish-saline water, marine hypersaline, marine carbonate, marine restricted (highly anoxic), siliciclastic marine deltaic, and carbonatic marine deltaic.

Hydrocarbons in the Brazilian marginal basins arise mainly from the Lower Cretaceous lacustrine freshwater/saline environments (pre-Aptian source rocks of the synrift stage), while the West African counterparts show major contributions from marine sequences (Upper Cretaceous and Tertiary source rocks).

In the Nigeria deepwater region, basement is composed of oceanic crust, thus no hydrocarbons generated from favorable non-marine synrift sequences are available for entrapment.

Marine deltaic.

Oils from this group have only been recovered in the Niger delta basin and, for example, the Para-Maranhao basin of the northern Brazil margin. They are correlated with Lower Tertiary marl and dark-grey shale source rocks deposited in marine deltaic environments varying from carbonate-dominated in Brazil (Limoeiro formation) to a siliciclastic-dominated in West Africa (Agbada and Akata formations, Niger delta). The oils are pooled in reservoirs ranging in age from Eocene to Miocene.

Biological marker maturity parameters indicate the thermal burial history of the source rocks of the African marginal basins was generally higher (i.e. greater burial depths and heat flow) than their Brazilian counterparts.

This is quite an important conclusion, as a main concern for source rock maturation in the Niger delta Tertiary section is the southern thinning of the sedimentary wedge (less overburden), and its resultant effect on hydrocarbon generation.

Although the Niger delta is one of the worlds main hydrocarbon producing areas, a definitive source rock based on accepted geochemical analytical parameters remains enigmatic and controversial. However the most effective source rocks are believed to be marine shales of the Akata formation and shales intercalated with the paralic sandstones of the Agbada formation.

Open marine.

The open marine oil type is confined exclusively, to date, to Gabon, in the equatorial West Africa margin. These oils correlate with the Upper Cretaceous (Cenomanian-Turonian) open marine black shale source rocks, with predominance of calcareous mudstone lithology (Azile and Anguille formations). The oils are commonly pooled in reservoirs ranging in age from Senonian to Tertiary.

The absence of this oil type, in the Brazilian basins is attributed to the lack of thermal maturity of the Cenomanian- Turonian organic-rich sediments that are widespread in most of the Brazilian marginal basins.

Although the Upper Cretaceous has not been penetrated in the Niger delta region due to depth of burial below the Tertiary delta complex, Cretaceous oil is recorded onshore: the surface oil seeps and tar sands of western Nigeria and Benin; positive shows of oil and gas in wells and at surface in the Anambra basin and Calabar flank and hinge line (eastern onshore Niger delta).

The possibility of good quality mature Upper Cretaceous source rocks in the Nigerian deepwater, based on a Gabon-type analogy, has to be positively considered.

Reservoir rocks

Due to an appreciation of distance from the sediment source, the main depositional regime is regarded to be marine shales with shelf-fed turbidites as principal reservoirs (Table 2)(8794 bytes).

Turbidites and submarine sands.

The variety in size, shape, sand/shale ratio, and location of submarine fans is the reason for a large range in their petroleum potential. For a long time, turbidites have been considered to be barely acceptable reservoir rocks. Their thin-bedded layered characteristics used to make a seismic approach to individual layers impossible, and well log correlations and fluid communication between wells often encountered serious difficulties, making these deposits somewhat less attractive. In addition, economics required that several reservoirs be found stratigraphically because one submarine fan sand may be too small.

A major question always involves the location of source beds, and, if hydrocarbons had to migrate from elsewhere, how the flow pattern relates to the depositional characteristics. In addition, there is the influence of diagenesis, making turbidites acceptable in a structural trap setting but uncomfortable to the explorationist for stratigraphic trap settings.

It is now realized that several submarine fans may be self-sourcing or sourced from nearby. Organic rich hemipelagic muds, as well as fine grained overbank deposits with acceptable TOCs, form a huge volume of low organic source rocks. In addition, the high accumulation rates of these overbank deposits should be regarded favorably for preservation of organic material.

Turbidites in post-rift sag basins are known from the Paleocene of the North Sea with compaction features and updip stratigraphic traps. Passive margins contain turbidite reservoirs in a variety of structural styles, such as the salt-diapiric and growth fault influenced basins of the U.S. Gulf Coast Neogene and Upper Cretaceous-Tertiary sequences of offshore Brazil. Reservoirs associated with shale diapirs are found in Tertiary strata of offshore East Malaysia and in the Canadian Beaufort Sea.

About 90% of the hydrocarbons produced in Southern California come from deepsea fans, such as in the Los Angeles and Ventura basins.

Submarine fans and turbidite systems are now accepted as major petroleum reservoirs in many sedimentary basins of the world. These reservoirs produce from a variety of structural, stratigraphic and combination traps.

Prograding sand wedges and slope fans.

In deepwater Nigeria mappable prograding sand wedges and slope fans have been seismicly identified and exhibit similar characteristics to sedimentary sequences in the Gulf of Mexico. Lowstand basin floor fans contain interpreted channel complexes characterized by chaotic bedding with small amplitude anomalies and rare, large channels that exhibit concave-up reflections.

These features suggest that the channel complexes contain significant amounts of clastic material. There is a well developed updip shallow-water facies of the slope fan that may well contain shoreface sands.

Large seismic amplitude anomalies in the lowstand prograding wedge suggest well developed sheet sands are present. These sands are in both shallow-water delta front facies and deep water turbidite facies.

Presence of traps

Structural

Examples from Nigeria offshore include:

Simple and complex rollover structures that are domal in geometry but marked anticlinal with depth. Common onshore and near offshore Niger Delta region.

Subsequent or contemporaneous movement of ductile shale and growth faults have produced large structural closures.

Synthetic untilted step-like fault blocks. These structures are asymmetric features limited by normal fault blocks, with strata and fault planes mainly inclined basinward, following the depositional dip of the affected sedimentary unit. Steep-dipping downthrown blocks to the basin gradually take the distal sedimentary facies deeper than the synchronous proximal facies.

On the basis of tectono-stratigraphic relationships, synthetic untilted step-fault blocks developed concomitantly with the sedimentation related to the descendant, vertical, differential movements, which gradually increased basinward. Occasionally, some intermediate block fell slower than adjacent blocks, and horst blocks would develop where relatively thin sedimentary sections were deposited.

Antithetic tilted step-fault blocks. These structures are asymmetric features, the strata are inclined opposite to the original depositional dip. The blocks are limited by antithetic faults, the planes of which dip basinward, opposite to the dip of the faulted strata. They were also concomitantly developed with the sedimentation.

Stratigraphic

Numerous stratigraphic horizons in the deepwater region possess a litho-stratigraphic component suitable for hydrocarbon entrapment. This type of trap is therefore very common.

Exploration

Current deepwater acre- age holding is shown in Fig. 3 (55596 bytes). All the concessions were awarded during 1993.

Acquisition of 2D and 3D seismic data is proceeding. Texaco acquired a 30% interest in Statoil/BP permits 213, 217, and 218, with Texaco funding a reported $80 million exploration budget over the next 5 years. Amoco 35% and Exxon 25% have taken farmouts on Agip permits 211 and 316, and Amoco has also acquired 50% of Mobils 221 permit.

Deepwater exploratory drilling began this year.

Fiscal regime and PSC

The main fiscal conditions for oil operations in Nigeria are contained in the Petroleum Profit Tax Act 1959, amended in 1967, 1970, 1973, and 1979. A model production sharing contract (PSC) was issued in 1990, and in March 1991 a revised model was issued, incorporating provisions of the 1991 Memorandum of Understanding (MOU).

The organization of the production sharing mechanism is fairly standard with the exception of items which are allowable for cost recovery. The complications in the PSC concern the implementation of the 1990 and 1991 MOU provisions. The MOU really forms the basis of negotiations with different oil companies having variations of royalty, tax holidays, and different treatments of tax offsets or credits.

Income tax, royalty, and capital investment credit were made depth dependent. For example, information available is that royalty is now levied according to the following system: in water depths of less than 200 m the rate is now 16.67%, falling to 12% for water depths of up to 500 m, 8% for water depths up to 800 m, and 4% for water depths up to 1,000 m. Royalty is zero over a 1,000 m water depth. Likewise in the deepest waters income tax and the capital investment credit rate are set at 50%.

The outlook

NNPC has been successful in attracting major oil companies into the deepwater, albeit with improved terms. Without further changes to the present PSC both in terms of the applicable rates and tax credits any developments must be considered at threshold profitability.

The prospects in the deepwater are by all accounts large and the production from any developments would be large. However development costs would also be large.

The majors who have chosen to explore these areas must be hoping to develop new and cheaper technologies to bring the fields on stream. At the same time they know that NNPC has been flexible in the past and may make additional benefits available to companies with insufficient profitability in development projects.

Acknowledgment

Thanks to TGS-Calibre for the use of Figs. 1 and 2 in this article.

Reference

Mello, M.R., et al., Brazilian and West African oils: generation, migration, accumulation and correlation, Proc. 13th World Petroleum Congress, Buenos Aires, Oct. 20, 1991, Vol. 2, pp. 153-164.