Introduction
Agbami Field is located 220 miles south-east of Lagos and 70 miles offshore
Nigeria, in the central Niger Delta. The field discovered in late 1998 is about
150Km west of Akpo field and 200Km SE of Bonga field straddling concession blocks OPL216 and 217 in approximately 4500 meters of water in the Gulf of
Guinea (ChevronTexaco, 2003b). Agbami field is Nigeria’s biggest field and one of the 10 largest discoveries of the 1990s with peak production estimated at
200,000 barrels of oil a day by 2007 and capital investments projected at $3.5 to
$4 billion (Appelbaum, 2000).
The Agbami structure is a 30Km long northwest/southeast trending doubly plunging thrust-faulted, detachment-fold anticline covering an area of 45,000 acres (Appelbaum, 2002 and ChevronTexaco, 2003a). The structure is characterized by crestal extensional faulting of the Pleistocene to upper Miocene sequences over middle Miocene to Paleocene strata that were thrust-faulted and later uplifted by a shale-cored detachment fold (Shirley, 2002). The field is in a lower slope environment outboard of the modern shelf slope break in a Mioceneto-recent depobelt where structure is dominated by detachment folds, shale ridges and toe thrust anticlines induced by upslope extensional growth faulting on the outer shelf margin (Shirley, 2002). The pay intervals consist of two principal zones namely; primary reservoirs (17 million year old sands containing about
80% of the reserves) made up of slope channel, slope fan, and basin floor fan facies and shallower productive secondary reservoirs (13MY/14MY/16MY sands containing 20% of the reserves) comprised of channel and levee-overbank facies
(Grimes et al, 2004).
History
Licensing
Famfa Oil Limited was awarded the leasehold rights to OPL 216 in August 1993 and signed a farm-in agreement with Star Deepwater Petroleum Limited (a wholly owned ChevronTexaco subsidiary) in 1996 wherein Star was designated as technical advisor for the block. I n 1998, 20% of Star’s interest in the block was

assigned to Petroleo Brasileiro Nigeria Limited (ChevronTexaco, 2001). In March of 2000, the Nigerian Government elected to acquire an interest in OPL 216, obtaining a portion of Famfa’s interest. The OPL 217 contractor working interest partners are Statoil (54%) and Texaco Nigeria Outer Shelf (46%) pursuant to a
Production Sharing Contract (PSC) with the Nigeria National Petroleum
Company (ChevronTexaco, 2001, 2003 & 2005).
To minimize cycle time to first oil, preliminary facility design/engineering was carried out concurrently during the field appraisal phase. The project gained sanction approvals in late 2003 and early 2004, and major facility construction contracts (including the construction of a $1.1 billion FPSO to Daewoo Shipping and Marine Engineering) in 2004 and 2005 with first production expected in 2007
(ChevronTexaco, 2001 & 2005).
Exploration
An insight into the tectono-stratigraphic evolution of Agbami field (and the deepwater Niger Delta as a whole) obtained from available regional 2D multi-client seismic data is shown in Fig………………..
3D seismic data was acquired over the 617,000-acre OPL Block 216 after exploration right was granted in late 1996. Acquisition, processing and interpretation of the seismic data were done using Texaco's 3D visualization technology (Appelbaum, 2002).
The discovery well Agbami-1, completed in January 2000, encountered 420 net feet of pay, in multiple oil zones from 8,200ft to the total depth of 12,400ft
(Appelbaum, 2002). The well penetrated stacked reservoir sands saturated with oil, ranging in overall column thickness from 400 to over 1,000ft. The quality of the oil from these zones is 35-45 degree API gravity, with very low sulphur content. Preliminary data indicates the reservoirs contain several hundred million barrels of recoverable oil (Appelbaum, 2002). The well spudded on 15 July 1998 in 4,700ft of water was the deepest water-depth well in Nigeria at that time
(Appelbaum, 2002 and SPG, 2006).
Drilling and Appraisal

The Agbami-2 appraisal well drilled in 2000 in 4,800ft of water, to a total depth of
15,683ft which confirmed that the structure had potential recoverable reserves in excess of one billion barrels of oil equivalent (Appelbaum, 2002). Appelbaum
(2002) also suggests that the well encountered 534ft of pay in five separate oilbearing zones, one of which flowed at a maximum rate of 10,000bopd and wellhead pressure of 2,200psi. Surface equipment limitations prevented the achievement of a higher flow rate. Oil from the reservoir is light, sweet crude (45 degree API gravity) with no contaminants (SPG, 2006). The well test surpassed expectations and, together with other technical data, suggested that the Agbami discovery likely ranks among the largest single finds to date in deepwater West
Africa (Appelbaum, 2002). Statoil drilled the Ekoli 1 well into the same structure in adjacent Block OPL217 around the same time (Grimes et al, 2004).
Before development plans could be considered, however, an additional four-well appraisal program was completed in August 2001, which confirmed earlier reserve figures and provided additional valuable information on the field. The drilling program defined the productive limits of the field and established reservoir continuity (ChevronTexaco, 2001). The results will help form the basis of a development plan incorporating conceptual facilities design, reserves, production rates and well count, while experience gained during the drilling of the appraisal wells will optimize well design for development drilling (Appelbaum, 2002).
Field Stratigraphy
The stratigraphy of the Niger Delta is divided into three diachronous units of
Eocene to Recent age that form a major regressive cycle (See Figure). The reservoir section penetrated by the Agbami Field appraisal wells comprises four distinct stratigraphic units that range from Lower Miocene (Burdigalian) to Middle
Miocene (Serravalian) and falls entirely within the marine, sand and shale lithostratigraphic unit of the Akata Formation (Short and Stauble 1967 and
Avbovbo 1978).
Oligocene and earliest Miocene sediments deposited over the Akata shale
Formation were middle to lower bathyal shales and basin floor fans with broad areal distribution. Isochron and isopach mapping indicates a major lower

Miocene sediment fairway across the crest of the Agbami structure, with the presence of basin floor fan sands likely (Shirley, 2002).
Regional paleoenvironmental and palinspastic reconstructions of the Agbami area support unconfined sheet-like basin floor fan deposition throughout the lower and part of the middle Miocene (Shirley, 2002).
Biostratigraphy and facies analyses of the Agbami 1 and 2 wells have confirmed bathyal environments within the middle Miocene slope channel, slope fan and basin floor fan facies (Shirley, 2002). As the shelf prograded outward, depositional loading induced structural folding, beginning about 12.5 million years ago. This has resulted in bathymetric features that channelized subsequent sedimentation, leading to channel-levee type deposition (Shirley, 2002).
Geophysics
The seismic reflections from the shallower, secondary reservoirs occur above the water bottom multiple and are of relatively good quality. Amplitude extractions of both near and far angle data match predicted AVA models making it possible to interpret stratigraphic and fluid changes from the seismic data at this level
(Grimes et al, 2004).
However, the seismic data from the deeper, main pay intervals in the 17MY interval suffer from significant multiple energy contamination (Grimes et al, 2004).
The energy from these multiples occurs at the same time as the main pay interval primary reflections over much of the field, seriously degrading the data, especially in the pre-stack domain (Grimes et al, 2004). Recent reprocessing efforts by ChevronTexaco using a Gaussian beam method for attenuation of the multiples have given good results that should allow better characterization of the reservoirs from seismic in future reservoir models (Grimes et al, 2004).
Also, reflectors from the inboard limb of the fold at the northwest end of the structure have diminished stacked amplitude responses and in general, the inboard limb is less well imaged than the outboard limb. Shallow toe thrusts north of the field appear to be masking far offset traces which would normally contribute to the expected high amplitude far angle reflections of oil bearing sands. To record higher angle traces in this area, and hence better map the sand

distribution, efforts are currently underway to re-acquire seismic data parallel to the thrust front (Grimes et al, 2004).
Trap
Agbami a 20-Mile Long Thrust-Faulted Anticline
The Agbami structure is in a lower slope environment outboard of the modern shelf slope break in a Miocene-to-recent depobelt where structure is dominated by detachment folds, shale ridges and toe thrust anticlines induced by upslope extensional growth faulting on the outer shelf margin.
Basinward, the zone of relatively minor structuration, is highly prospective (the
Agbami and Akpo fields are just two examples) and extends into the northern blocks of the JDZ.
Reservoir
The pay intervals at Agbami field consist of two principal zones. The primary reservoirs are in the 17 million year (MY) sands and contain about 80% of the reserves. These objectives include slope channel, slope fan, and basin floor fan facies that offer both stacked and isolated reservoir objectives. Secondary reservoirs are present in the 13MY/14MY/16MY sands. These shallower productive zones are comprised of channel and levee-overbank facies.
With the limited frequency content of the seismic data, stratigraphic information from seismic was restricted to the identification of thick, sandstone-prone fairways that were mapped throughout the field area as architectural elements in the reservoir model. Tying to the low frequency inversion data placed the seismic tops and bases of these architectural elements in the shales above and below the corresponding sandstone unit in the well logs. This architectural element interpretation forms the basis for well-to-well correlation, field volumetrics, and reservoir modeling.
A channelized sheet system was selected as the most likely depositional model for the 17MY reservoir based on the available seismic and well data. To fully capture the potential range of depositional systems and associated in-place

volumes and connectivities caused by variable net-to-gross and reservoir architecture, four end-member models were also created: isolated channel, isolated sheet, amalgamated channel, and amalgamated sheet.
Source
The source rock in the JDZ is considered to be the Akata shale. Additional source rock potential exists in lacustrine deposits of the pre-delta rift sequences.
Thermal modeling indicates that sediments situated in the northern sector of the
JDZ are within the maturity window.
Hydrocarbon reserves/Resources
Total field reserves are estimated at around one billion oil-equivalent barrels.
The successful four-well appraisal program confirmed that the Agbami structure has potential recoverable reserves of one billion barrels of oil equivalent. (Chevy ( c )
(
References
RESERVOIRS
Strat…
The uppermost unit, the Benin Fm, comprises continental/fluviatile and backswamp deposits up to 2500m thick. These are underlain by the Agbada Fm of paralic, brackish to marine, coastal and fluvio-marine deposits, organized into coarsening upwards ‘offlap’ cycles. The underlying Akata Fm, comprises up to
6500m of marine pro-delta clays. Shales of the Akata Fm are overpressured and

have deformed in response to delta progradation. These shales facilitate regional decollement for updip extension and downdip compression. Shales of the Akata
Fm constitute a world-class source rock. Deepwater turbidite sands also exist within this formation.