The North Falkland Basin comprises two main structural elements: a N-S trending graben, and a set of subsidiary basins to the west and south of the graben, also controlled by N-S trending extensional faults, but constrained by NW-SE oriented reactivated Palaeozoic thrust sheets.
The main North Falkland Graben is about 50 km wide at its northern end, and about 30 km wide near its southern margin, just 36 km or so north of the Islands; it is about 230 km long as presently mapped, but may extend further to the northeast.
The basin appears to be a structurally isolated feature set within a Devonian platform providing a potentially abundant provenance area for clean reservoir sandstones. Deposition appears to have been fluvio-lacustrine and lacustrine until late in the Cretaceous, when the southern Boreal Ocean appears to have inundated the area from the southeast.
The basin contains a late Jurassic to early Cretaceous lacustrine source rock of world-class quality. This source is mature in its lower parts, and has expelled over 1x10(11) barrels of oil, all of which are thought to be still trapped beneath the regional seal formed by the non-mature, uppermost part of the lacustrine interval. Live oil has been recovered to surface from sandstones within the mature lacustrine source interval.
At least one other petroleum system has also been encountered in the basin; this late Jurassic/early Cretaceous fluvio-lacustrine interval beneath the pervasive lacustrine source rock produced significant levels of wet gas in one well.
Only six wells have been drilled in the entire basin, and all of these are concentrated in a very small geographical area.
Furthermore, because of back to back drilling, all six wells tested the same play concept, which proved to be a good clean sand, but located immediately above a regional seal. None of the target positions were at locations where the seal is breached significantly, and therefore all were under-charged. Significant numbers of play concepts and different targets remain to be tested in the basin, which is at the very earliest stages of exploration. [Top]
The North Falkland Basin comprises a N-S trending graben and a set of subsidiary basins to the west of the graben, also controlled by N-S trending extensional faults, but constrained by NW-SE oriented reactivated Palaeozoic thrust sheets.
The North Falkland Graben is subdivided, in its northern part, into western and eastern depocentres, separated by a pervasive, N-S trending intra-grabenal high (parochially termed the Orca Ridge by some companies). The graben is about 50 km wide at its northern end, and about 230 km long as presently mapped.
The main extensional rifting phase was during the Jurassic to Valanginian, with rift sag occurring from the Valanginian through the remainder of the Cretaceous. There may have been local uplift in the early Cenozoic, related to indentation of the Scotia Plate to the south into the South American Plate.
A 3D model of the northern part of the North Falkland Basin reveals the relationship between en-echelon N-S graben-margin faults and the hard-linked relay ramps that offset the N-S faults along the trends of pre-existing NW-SE oriented Palaeozoic lineaments. The relay ramps, as well as offsetting the main N-S extensional faults, provide potentially excellent pathways to bring sand-rich, reservoir-quality sediments into the basin from the surrounding Devonian platform.
The NW-SE trending Palaeozoic lineaments that define the edges of the relay ramps possibly represent the location of relaxed thrust sheets that were re-activated during Jurassic east-west oriented extension. They are best imaged in the southern parts of the North Falkland Basin, where there is a substantially thinner late Mesozoic cover above older rift sequences. Here, the thrusts form surfaces that the younger, N-S oriented normal faults sole-out onto.
The basin contains a late Jurassic to early Cretaceous fluvio-lacustrine succession capped by late Cretaceous and Tertiary marine deposits.
The late Jurassic to early Cretaceous interval contains a lacustrine source rock of world-class quality.
This source has expelled over 1x10(11) barrels of oil.
At least one other petroleum system has also been encountered in the basin.
Only six wells have been drilled in the entire basin, and all of these are concentrated in a very small geographical area.
Eight widely correlatable tectono-stratigraphic units are now recognised in the basin. The boundaries of these tectono-stratigraphic units can be correlated with seismically-identified sequence boundaries and tied to the downhole logs in the six wells.
The eight tectono-stratigraphic units recognised are:
Modelling by Zilinski (2002), based on a pseudowell located in Tranche D of the North Falkland Basin also predicts significant oil generation. (Click on links for images)
Reservoir properties in several wells are tabulated below, using the tectono-stratigraphic subdivisions of Richards and Hillier (2000).
Deposition during the early and late syn-rift period (?mid Jurassic to Tithonian/Berriasian) was predominantly fluvial and fluvio-lacustrine, with some tuffaceous input, particularly in shallow water areas over structural highs. The basin appears to have been isolated from the developing South Atlantic Ocean during the Jurassic.
In the northernmost part of the North Falkland Basin, the early syn-rift was fluvially dominated.
In the northernmost part of the North Falkland Basin, the late syn-rift was lacustrine dominated, with more minor fluvial input.
Lateral fans probably shed coarse clastic detritus of reservoir quality into the basin from the surrounding Devonian platform during both episodes of the syn-rift phase.
Fluvial channels will have been concentrated in the depositional lows towards the bounding basin fault.
Neither the lateral fans nor the main axes of fluvial sedimentation have been drilled to date.
Both sets of undrilled reservoirs constitute prime targets for the next drilling campaign, particularly since they lie on anticipated good migration pathways lateral to the source/seal couplet.
The thickest late syn-rift reservoir interval in Well 14/5-1A has a net thickness of 125 m, with porosities ranging from 27.8 to 30.4%, and Sw values as low as 51%.
Well 14/10-1 also encountered two thin, late syn-rift reservoirs. The lower of these had a net thickness of 1.2 m; the upper had a net thickness of 2.4 m. Both of these sandstones had log-derived Sw values as low as 36%. Well 14/9-1 also encountered potential reservoir within the late syn-rift sequence, with porosities of up to 30% and water saturations as low as 70%, but sampling using a wireline formation tester was unsuccessful, suggesting that the sandstones were tight.
In a 2001 paper, Richardson and Underhill suggested that the syn-rift succession would have little reservoir potential due to a high incidence of tuffaceous material.
Deposition during the early post-rift period (Valanginian to early Aptian) was predominantly deltaic. There is no direct evidence of a link to the southern ocean at this time.
A large axial delta prograded from north to south into the basin, in several interrupted phases of progradation. Several other, smaller deltas also prograded laterally into the basin, each developing during a presumed different phase of relative basin margin uplift. Deltaic sandstones (where drilled in the centre of the basin) have porosities up to 28% and net:gross ratios of up to 0.7.
Significantly thicker, more proximal, and possibly better quality axial-deltaic reservoir sandstones are imaged on seismic from the unlicensed area north of the wells in the North Falkland Basin.
A lowering of lake levels in the latest part of this time period resulted in a significant basinwards shift of facies, and the development of an attached lowstand fan in front of the delta
Although some sandstones were encountered where this lowstand fan was drilled in the centre of the basin, it is thought that the main sand channels bypassed the site of the Shell well (14/10-1) that tested the lowstand system.
The sand-rich channels that bypassed the well location on the lowstand fan may have carried coarse clastic sediment either to the margins of the structural high to the south, or to a ponding position in the centre of the basin, to the south of the main cluster of wells drilled in 1998.
Early post-rift sandstones developed encased within the source-seal couplet of the thick lacusrine claystone may form target intervals at several of the new play types still to be tested in the basin.
Early post-rift sandstones were encountered only in Well 14/5-1A, where they form part of the axial, southerly prograding delta deposits in the eastern depocentre. A sandstone-dominated interval identified within the delta foresets contained 38 m of net sandstone reservoir, with up to 28% porosity and 974 mD permeability, but 89% water saturation.
Deposition during the middle post-rift period (Aptian to Albian) was essentially fluvially dominated.
The only cores cut in the 1998 exploration wells tested the lower parts of the Middle post-rift section. These were from the Hess well 14/9-1, located on the crest of the pervasive high that seaparates the western and eastern depocentres in the North Falkland Basin. Core examination suggests that the depositional environment was initially a marginal lake setting with small streams and widespread but thin, unconfined overbank flows. The environment became more dominantly fluvial through time, although swamp and marginal lake conditions may have persisted in places.
These reservoir rocks lie immediately above the main source interval, and were the main exploration target in all six of the wells drilled in 1998. They are present in all of the wells. In Well 14/5-1A, the sandstones have a net thickness of nearly 23 m, with a net to gross ratio of 0.56 and a porosity range of 19.6 to 25.4%. Furthermore, 79 m of net sandstone in this interval were encountered in Well 14/10-1, while over 133 m of net sandstone were found in Well 14/24-1.
Oils recovered to surface or spun out of cores in the North Falkland Basin wells appear to have been derived from two distinct levels within the overall late syn-rift to early post-rift lacustrine source-rock interval.
Gas shows observed during drilling ranged from part of one percent, to in excess of 32% in the early syn-rift sequence in Shell well 14/5-1A (from some of the thin sandstones recorded within a unit containing about 120 m of net sandstone). Gas types were often confined to C1, sometimes with minor amounts of C2 and C3, although high levels of C2 to C5 were recorded at times. Gas shows in the stratigraphically higher sandstones are generally less voluminous, with, for example, up to 2900 ppm C1 and only traces of C2 recorded from the middle post-rift sandstones in Amerada well 14/9-2. Gas shows directly from syn-rift and early post-rift lacustrine claystones are up to 12.06% (in Shell well 14/10-1), with a complete range of C1 through C5 gases recorded.
DHIs are rarely observed in the North Falkland Basin, presumably in large part due to the age of the rocks (predominantly Jurassic/Cretaceous). However, some flat spots have been imaged on seismic sections in the southern parts of the North Falkland Basin.
Surface evidence of seeps as recognised by Synthetic Aperture Radar (SAR) studies are also rare, presumably because over much of the North Falkland Basin the regional source-seal couplet is very effective, and prevents leaking of hydrocarbons to surface. This source-seal couplet is only rarely breached by major faults that reach to or near surface.
However, in the northernmost parts of the North Falkland Basin (in the open acreage north of the drilled area) there are several examples of DHIs and SAR seeps. These SAR seeps are present above disturbed sea bed zones, possibly representing pock marks caused by gas escape.
Some amplitude and AVO anomalies have also been observed in the area just a few kilometres north of the Amerada wells that were drilled in 1998. These features include amplitude and AVO anomalies over mapped structures
A variety of play types were planned to be targeted by the 1998 drilling campaign, but post-well analyses indicate that only three play types were actually partially tested. There are more untested than partially-tested plays remaining in the basin: a small selection of both are reviewed below.
Only Amerada well 14/9-1 tested this play within closure on the crest of the Intra-Graben High. The Tithonian to Berriasian, late syn-rift unit had log-derived porosities up to 30%. Although permeabilities appear to be poor at the 14/9-1 well location, the prospectivity of the syn-rift succession cannot be ruled out elsewhere, especially where early good poro-perm characteristics have been maintained by early oil migration before the destructive process of later diagenesis.
Two thin sandstone beds (3 and 5 m thick) were also penetrated in the late syn-rift sequence by Shell well 14/10-1, in a palaeo-lake centre setting, where sandstones would be expected to be thin and of poor quality compared to lake-margin settings. These two sandstones were not within closure at the level they were encountered, and therefore were not fully oil charged. However, both the sandstones had oil shows, and porosities of about 19%; one flowed live oil (27°API) to surface.
The syn-rift play has been only partially tested, and may merit further drilling at other locations.
All six wells encountered reservoir quality sandstones within the Aptian to Albian middle post-rift unit that directly overlies the main source-seal couplet, and five of them had oil shows. These sandstones are up to 133 m thick in wells, with porosities up to 25.4%.
The play has been only partially tested, and may merit further exploration, particularly if viable migration pathways can be mapped at some localities. Some such localities have been identified, particularly in association with faults that breach the underlying source–seal couplet.
Only Shell well 14/5-1A addressed the Valanginian to early Aptian, early post-rift axial delta play.
Thick sandstones are likely to occur at delta top and delta front level to the north of the 14/5-1A well location, and evidence from the limited amounts of seismic available from north of the drilled area suggests that the delta is indeed considerably better developed in its more proximal reaches.
Some possible channel features have been imaged cut into the front of the delta in the Eastern Depocentre. These channels themselves have significant potential, especially since they are encased in source rocks which may provide a straight forward migration pathway and therefore relatively easy charge. They may also have carried sand further out into the lacustrine basin, into presently undrilled acreage which is only sparsely covered by seismic data. However, these channels have not been drilled at any location.
The play has been only partially tested, and may merit further drilling at other locations.
Jurassic to earliest Cretaceous fan sandstones, deposited during the syn-rift phase, may be developed along the margins of the basin in situations analagous to the Brae complex in the South Viking Graben of the North Sea. Such sandstones would be stratigraphically subjacent to the mature, basal part of the main lacustrine source rock, and would therefore be likely to be charged with hydrocarbons.
Early Cretaceous deltaic bodies that prograded into the basin from marginal areas during the early post-rift phase may be sand-rich, and may also be closer to migration pathways, particularly those associated with the basin margin faults. They may therefore be more to likely to have been charged with hydrocarbons than sandstones within the axial north–south delta. They may be significantly more extensive than their presently known distribution.
Shoreline and/or transgressive sandstones of Aptian to Albian age may have been deposited along the margins of the basin during the initial overstepping of the flanks in the middle post-rift phase. Although such sandstones would be stratigraphically above the main mature part of the source rock succession, they might have been charged by fluid flow vertically up basin margin faults.
Mapping of the 2D seismic data elsewhere in the North Falkland Basin points to the presence of numerous closed highs in several discrete, deep sub-basins that extend to at least four seconds of two-way travel time (TWT). No definitive correlations have yet been established with the drilled areas, although it seems likely that the deeper parts of the section equate with the early syn-rift sediments penetrated in the Shell well 14/5-1A. These sediments were the source of gas in that well, although are capable of generating oil where less deeply buried.
There is now a wealth of exploration data available for the North Falkland Basin.
In addition to the spec seismic that covers much of the basin, there are several relatively tightly spaced proprietary surveys across much of the central parts of the basin.
There is also considerable marine grav-mag data and more limited aero-mag data over the basin.
Spec data over the North Falkland Basin are available for purchase from Spectrum Energy.
The data acquired for Lundin Oil over the open acreage to the north of existing licences is currently owned by Talisman Energy, and may be available from them on a spec basis.
All seismic data are available for viewing by bona-fide oil companies interested in exploring in the area:
All proprietory seismic data over five years old, plus all spec data over ten years old is freely available to bona-fide oil companies interested in exploring in the area, and may be supplied to companies (in SEG-Y or Landmark project format), at the sole discretion of the BGS.
Both Desire Petroleum and Argos Resources are able to supply geophysical data to interested parties upon completion of their individual confidentiality agreements.
Only six wells have been drilled in the North Falkland Basin, but these each have a full suite of logs and relevant interpretation reports on aspects such as biostratigraphy, petrology, geochemistry, etc.
More or less complete well data sets are available from Desire Petroleum and Argos Resources subject to completion of their individual confidentiality agreements.
BGS is able to supply complete data sets from all wells to bona-fide oil companies interested in exploring in the area; such data delivery will be made at the sole discretion of the BGS.
Offset engineering data, met-ocean data, general environmental data and any other materials of interest to bona-fide oil companies interested in exploring in the area, and which cannot be downloaded from this web site can be acquired from either BGS or one of the existing licensees, at their discretion.