The Nature of Gas Hydrates on the Nigerian Continental Slope
Abstract
Gas hydrates have been collected in 6-meter piston cores during surface geochemical
exploration (SGE) surveys in the deep and ultra deepwaters of Nigeria in 1991, 1996,
and 1998. To date, gas hydrates have been collected in ~21 cores out of the >800
core collections on the Nigerian margin. This represents a 2.5% recovery ratio of gas
hydrated cores on this margin at sites that are potential conduits for the upward
migration of hydrocarbons (i.e., core locations are sited based on 2-D and 3-D
seismic over faults, mounds, acoustic wipe-outs, etc.). Unlike the northern Gulf of
Mexico where the authors have retrieved a significant percentage of thermogenic
hydrates in piston cores, all the gas hydrate collections offshore Nigeria to date have
been primarily biogenic in nature (methane >99% of the hydrocarbon gases;d 13C
generally light, -60 to –117 0/00). A few of these gas hydrated sites do contain a mixed
thermogenic gas component (ethane to butane gases up to a few hundred ppm of total
hydrocarbon gas), but even at these sites the primary gas in the hydrates is methane.
There is migration of liquid hydrocarbons to shallow sediments that is common on the
Nigerian continental margin. For example, a SGE coring survey on the Nigerian ultra
deep water continental margin in 1996 collected 10 cores out of 130 with visible liquid
hydrocarbons within portions of the 4.0 to 5.0 meters of sediment generally retrieved
by the piston cores. However, in many cases there is little gas associated with these
sites and the collection of gas hydrated cores is generally independent of the
macroseepage of liquid hydrocarbon core sites. Bottom Simulating Reflectors (BSRs)
are often associated with the marcoseepage core sites in Nigeria. BSRs are common
Annals of the New York Academy of Sciences, Third International Conference of Gas
Hydrates, Park City, Utah, July 18-22, 1999
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on the seismic records of the Nigerian continental slope. The subbottom depth of the
BSRs range between ~200 to ~500 meters and are often associated with various
geological structures such as faults. When gas hydrates are collected in cores they
often consist of disseminated nodules of a few centimeters in diameter within the mud
matrix a few meters subbottom or are massive (5 to 10+ cm thick) and come up as the
bottom of the core. The depth of the BSRs are generally similar or at shallow depths
than the calculated base of the methane hydrate stability zone using known bottom
water temperatures and thermal gradients for the region. The average heat flow for
the Nigerian continental margin is 58.2 mW/m2 with a range from 18.8 to 123 m/Wm2.
Introduction
Although gas hydrates have been known to exist in upper continental shelf
sediments for many years (1,2), they have not been commonly collected. The global
distribution of gas hydrates has been deduced primarily from bottom simulating
reflectors (BSRs) and the occasional collection, generally hundreds of meters deep in
the subsurface in deep-sea drilling (i.e., DSDP and ODP) cores. Brooks and coworkers
(3-8) have documented the occurrence of gas hydrates in shallow subsurface
marine sediments overlying several of the hydrocarbon generative basins throughout
the world (i.e., Gulf of Mexico, northern California and offshore Nigeria). The gas
hydrates have generally been collected from the upper 5 meters of piston cores taken
in water depths greater than 400 m. These gas hydrates occur in close proximity to
faults and other conduits for gas migration. In the Gulf of Mexico, biogenic and
thermogenic hydrates have been observed from submersibles to outcrop at the seafloor
(7, 9). The observations of gas hydrates at the seafloor in water depths near their
upper stability zone suggests that slight changes in bottom water temperature or
pressure could cause the hydrates to disassociate and thereby dramatically increase the
release of gas to the ocean surface. It is not clear to what degree shallow hydrates act
as barriers to the seepage of gas from the seafloor because bubbling gas seeps are
common in areas containing extensive shallow hydrates (5, 10).
Nigerian Margin Geological Setting
The Niger Delta occupies the central region of West Africa’s Gulf of Guinea.
With a land area of some 75,000 km2 it forms the largest delta system in Africa (11).
The delta owes its size to the focus provided by the Benue arm of the Niger Triple
Junction for sediment delivery from interior Africa to the Atlantic Ocean. The modern
delta began its growth in the late Eocene (12, 13). Since that time the delta top, as
defined by the 200 meter isobath, has prograded south and south-westwards from the
Cretaceous shelf-edge hinge line some 300 km across previously deepwater settings.
The distal edge of the delta lies some 80 to 170 km further seawards. The continental
slope forms the intermediate region and has been the focus of SGE cores containing
the hydrates reported here.
Annals of the New York Academy of Sciences, Third International Conference of Gas
Hydrates, Park City, Utah, July 18-22, 1999
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The Eocene and younger delta succession is divided into three younger units
moving seaward. These are, from the bottom upwards, the Akata Formation, the
Agbada Formation and the Benin Formation (13). The Akata Formation comprises
deep marine shales and, as was predicted more than twenty-five years ago, deepwater
sands (12). Shelf to paralic sediments define the Agbada Formation and the
uppermost unit, the Benin Formation, consists of primarily non-marine, delta top sands
and clays. Delta top loading has been sufficient to mobilize the Akata Formation clays
and the entire 10-12 km succession is being actively displaced oceanwards. The result
is a generally clearly defined frontal toe thrust (14) behind which are stacked clay
cored diapir belts associated with the lateral translation of the delta slope towards the
ocean. Doust and Omatsola (13) and more recently by Cohen and McClay (15)
provide a comprehensive account of the history of development of the delta in terms of
depobelts.
The modern anatomy of the delta is summarized on Fig. 1. Superimposed are
the oil producing region and some of the most significant of the deepwater discoveries.
Our own work based on piston-core recovered oils collected in 1996 and 1998,
together with comparisons with offshore and nearshore produced oils, indicates that
the predominant offshore source, at least to present exploration limits, is a mid-
Tertiary or younger marine claystone with strong deltaic influences (although
Cretaceous-sourced seeps are present locally). These oils and seeps group to form
GeoMark’s Tertiary Deltaic Oil Family (16) regarded as derived from the Akata
Formation. The mixed Type II/III source rocks which would supply these oils and the
accompanying gases have been described from the Akata Formation to the west of
Bioko Island in Equatorial Guinea (17). Mixed oil and gas prone kerogens are also
described from the Bonga discovery in OPL 212 and the Ngolo-1 well in OPL 219
(18). Little is known concerning the younger Cretaceous and older Tertiary source
rocks, although their presence is suspected beneath the slope given that source rocks of
this age are developed. Considering the prevalence of mature oil seepage to shallow
sediments and the large oil/gas discoveries occurring along the continental margin,
there are multiple possible sources of gas to the hydrate stability zone.
Sea Floor Gas Hydrate Collections
The initial hydrate discoveries in the Gulf of Mexico, offshore West Africa,
northern California and elsewhere have resulted from piston cores acquired for the
purpose of geochemical exploration. SGE studies are used to define the aerial
distribution of oil, condensate and gas seepage on the continental margin. These
studies high grade areas and prospects by defining areas of active oil migration and
charge through gas and high molecular weight hydrocarbon analysis methods. This
active migration acts to charge accompanying reservoirs in the same geological
system. From many such studies, especially in Tertiary delta systems in west Africa,
the Gulf of Mexico and elsewhere, we know that there is considerable macroseepage
of ‘live’ oil and gas into seafloor sediments throughout broad regions from the
shelf/slope break extending to the ultra deep waters (>1,500 m).
Annals of the New York Academy of Sciences, Third International Conference of Gas
Hydrates, Park City, Utah, July 18-22, 1999
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Core locations for SGE studies are chosen from both 2-D and 3-D seismic data
where there are possibly deep conduits (i.e., faults and fractures) for the upward
migration of hydrocarbons. The optimum targets are deep cutting faults that page link the
source succession to the seabed. These are best developed where there is ongoing
tectonism, for example in clay diapir or salt tectonic provinces. However, even in
tectonically quiet regions breaks are usually present, especially where the section is
thick and/or where there has been differential movement and reactivation across
basement features such the Benue and Charcot Fracture Zones in Nigeria. The ideal
faults are those associated with: (1) amplitude anomalies (“flags”) and/or BSRs, (2)
seabed constructional features such as carbonate accumulations and mud-gas mounds,
(3) gas vent pits, and (4) gas chimneys. Thus, the sites chosen for SGE studies are
very focused to optimise the chance for retrieving upward migrated gaseous and liquid
hydrocarbons.
Cores are acquired with a 900 kg piston corer with collapsible piston, 6-meter
of pipe and core liner. All cores are positioned with differential GPS positioning to a
precision of ±5 meters, generally within ±30 meters of preselected locations. Often
either precision bathymetric or subbottom (3.5 kHz or Chirp sonar) profiling is used to
further refine core positions in the field. Seismic data acquired by Mabon Limited was
used for both the 1996 and 1998 Nigerian programs discussed below. Core site
selection is enhanced where 3-D seismic and/or swath bathymetry are available.
Gas hydrates are recognized visually in many of the cores upon retrieval on
deck as most often white ice-like nodules or lenses in the core. They are also inferred
by large gas expansion pockets in some cores upon retrieval on the ship’s deck. If
large gas nodules are present, the hydrate is sometimes placed in a 23-cc Parr bomb to
collect the hydrate decomposition gas into a high pressure cylinder (8). In our SGE
studies, all the cores are sampled at three depths in the bottom half of the core for
headspace gas. Headspace gas analysis refers to the determination of interstitial light
hydrocarbon gases (C1-C5). The light hydrocarbon gases are not very soluble in water,
so they can be extracted from a sediment by a gas/water partitioning procedure (19).