North Falkland Basin
Introduction — Structure— Source Rock — Reservoirs — The oil and gas fields — Play Types — Data
The main north-south orientated North Falkland Basin graben system is about 50 km wide at its northern end, about 30km wide near its southern margin, and located just 36 km or so north of the Islands. It is about 230 km long as presently mapped, but possibly extends 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, below about 2700m sub-sea, and has expelled over 60 billion barrels of oil.
At least one other older and deeper, gas-rich petroleum system has also been encountered in the basin; this mid Jurassic/early Cretaceous fluvio-lacustrine interval, beneath the pervasive lacustrine source rock, is possibly the source of the gas found in several wells in the basin.
Six wells were drilled in the basin during 1998, and a further 17, including 8 appraisal wells of the Sea Lion discovery, were drilled in the basin during the second drilling campaign between 2010 and 2012. The 2015 Eirik Raude Campaign is currently underway, with three wells drilled (one in EFB), one in progress and one anticipated. Discoveries made in the basin to date include:
- The Sea Lion oilfield on the eastern margin of the basin
- Casper (gas and oil), associated with Sea Lion as a satellite discovery
- Casper South (gas and oil), associated with Sea Lion as a satellite discovery
- Beverley (gas), associated with Sea Lion as a satellite discovery
- The Liz field (wet gas/condensate and dry gas at a deeper level) on the western flank of the basin.
- Zebedee, (oil and gas) to the south of the Sea Lion field
- Isobel Deep (oil) south of Sea Lion field but the well was suspended before reaching total target depth
Significant numbers of play concepts and different targets remain to be tested in the basin, which is at the most of which is still in the earliest stages of exploration. The Sea Lion field is currently undergoing consideration for Field Development, with Premier Oil aiming for project sanction in 2016.
The North Falkland Basin comprises two main structural elements: a N-S trending set of grabens, and a set of subsidiary basins to the west and south of the main grabens which are also controlled by N-S trending extensional faults but are 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 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.
Tectono-stratigraphic units
Eight widely correlatable tectono-stratigraphic units [see Richards and Hillier (2000) link below] are recognised in the basin. The eight tectono-stratigraphic units recognised are:
- a post-uplift sag unit - Palaeocene to Recent
- a late post-rift interval - Albian to early Paleaocene
- a middle post-rift interval - Aptian to Albian
- an early post-rift interval - Valanginian to Aptian
- a transitional unit - Berriasian to Valanginian
- a late syn-rift interval - Tithonian to Berriasian
- an early syn-rift interval - mid Jurassic to Tithonian
- a pre-rift sequence - Devonian
Source Rock
A world-class, Lower Cretaceous lacustrine source rock was discovered in the 1998 drilling campaign.
The Tithonian–Aptian lacustrine part of the source rock is over 1000m thick.
It forms part of a source-seal couplet.
It is mature below 2700m below sea level, but the immature layer above forms a regional seal.
Another, deeper petroleum system has also been identified, probably with a mid Jurassic to Tithonian source rock.
The source rocks have been characterised in detail by Richards and Hillier, 2000.
The North Falkland Basin is hot, with a geothermal gradient of 44°C/km.
Modelling the timing of oil generation is imprecise. Peak heat flow may have been either from about 150 to 125 MA (during Jurassic to Valanginian rifting) to around 90 MA (during the post-rift phase), when the crustal temperature in the region may have increased due to opening of the South Atlantic.
A model based on a peak heat flow of around 80 mW/m2 at 90 MA closely matches the observed VR, temperature and geochemical data observed in the released 1998 wells.
This model indicates that oil generation took place from the main early post-rift source rock during the late Cretaceous, between 70 and 100 MA.
At a depth of around 3000m below sea level, over 50% of the organic material will have been converted to oil. Modelling based on an earlier heat-flow peak (around 125 MA) produces peak oil generation around present day but with only about 2% conversion of organic matter, which is not consistent with the maturation analyses.
Modelling of the (relatively lean) deeper potential source rocks of mid Jurassic to Berriasian age within the early syn-rift succession suggests:
- that they are currently post-mature
- have possibly been a source, mostly for gas
- they probably reached peak generation in the early Cretaceous
Most of the hydrocarbons were expelled by about 90 MA (in the Cenomanian to Turonian).
In excess of 60 billion barrels may have been generated from the main lacustrine source rock.
Onset VR values are:
- onset of oil generation at a VR of 0.76%
- peak generation at a VR of 0.9%.
Reservoirs
Most exploration wells drilled in the basin have encountered reservoir rocks of varying quality, depending on stratigraphic and basin location. Several oilfields located along the eastern flank of the basin have proven the presence of extremely good quality reservoir rocks. The reservoirs penetrated in the 1998 drilling campaign, and for which data have been released, are summarised by Richards and Hillier, 2000.
Syn-rift reservoir rocks (mid Jurassic to Berriasian)
Deposition during the early and late syn-rift period (mid Jurassic to Tithonian/Berriasian) was predominantly fluvial and fluvio-lacustrine, with some tuffaceous input locally. The basin was 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.
The thickest late syn-rift reservoir interval penetrated to date was in well 14/5-1A. Syn-rift reservoirs in this well had porosities ranging up to 30%.
In 2010 the first exploration well drilled in the basin since the 1998 campaign discovered gas condensate and dry gas at two levels within the syn-rift succession at the Liz field on the western flank of the basin. Desire Petroleum reported that earliest late syn-rift sandstones (the G4 sands in their terminology) contained wet gas/condensate in sandstones up to 70m thick, with porosities of about 12%, while early syn-rift volcaniclastic sandstones up to 112m thick, with porosities of about 22%, present in a discrete interval near the base of the early syn-rift succession (Stratigraphic Unit H in their terminology) contained dry gas.
Early post-rift reservoir rocks (Valanginian to early Aptian)
Deposition during the early post-rift period (Valanginian to early Aptian) included deltaic sediments that prograded into the lake basin from the north, a range of fans that prograded into the basin from the eastern and western margins of the basin, and the continued deposition of a thick succession of oil-prone lacustrine source rocks. There is no direct evidence of a link to the southern ocean at this time.
A lowering of lake levels during the early post-rift period resulted in a significant basinwards shift of facies, and the development of an attached lowstand fan in front of the southwards prograding axial delta as well as the deposition of several sand-rich fans shed off the eastern margin of the basin . These easterly derived fans form the Sea Lion and its associated satellite fields of Casper, Casper South and Beverley. Published values from confidential wells in these fan sands suggest that drilled net pay values are over 90m in places, with porosities of up to 25% or so, and permeabilities clustering in the range of 10 to 500 mD, with DST results suggesting that permeabilities in the flow-tested sands were approximately 200 to 300 mD.
The several oil and or gas discoveries made in the basin margin-derived fan sands during the 2010-12 drilling campaign are discussed in the section on North Falkland Basin oil and gas fields.
Many early post-rift sandstone targets developed encased within the source-seal couplet of the thick lacusrine claystone are still to be tested in the basin.
Middle post-rift reservoir rocks (Aptian to Albian)
Deposition during the middle post-rift period (Aptian to Albian) was essentially fluvially dominated.
Cores cut in the Hess 14/9-1 well in 1998 suggest 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 and reach a thickness of over 133 m in Well 14/24-1. These sandstones were specifically targeted in just two wells in the 2010-12 drilling campaign but were dry.
The oil and gas field and other hydrocarbon shows
Oil and gas discoveries have been made on both flanks of the basin, and oil and gas shows have been recorded from reservoirs drilled near the centre of the basin.
The Sea Lion field: oil in the Sea Lion and associated satellite discoveries on the eastern side of the basin has an API of about 28°, with relatively low gas-oil ratios (<300 scf/Bbl in the east of the field to 450 scf/Bbl in the west of the field) and a wax content of about 18%. Two wells were flow tested in 2010: 14/10-2, the Sea Lion discovery well, flowed for 18 hours at a stabilised rate of 1,800 barrels of oil per day under natural conditions, and 14/10-5 flowed at a stabilised rate of about 5,500 barrels per day with the aid of vacuum-insulated tubing and electro-submersible pumps. The Sea Lion field appears to have slightly different fluid characteristics on each side of the structural, water-bearing low that divides the field into eastern and western sections. It appears, from current drilling knowledge, that there is a semi-regional gas-oil contact at approximately 2402m TVDSS, and an oil-water contact at approximately 2477m TVDSS.
Discoveries associated with the Sea Lion field: as well as the Sea Lion discovery, which Premier Oil and its partners are currently preparing for development, several other discoveries have been made on the eastern flank of the basin, including:
- Casper (gas and oil)
- Casper South (gas and oil)
- Beverley (gas)
Other discoveries: the Liz field (wet gas/condensate and dry gas at a deeper level) was discovered on the western flank of the basin. The Liz condensate has a Condensate to Gas Ratio of 95 Bbl/MMscf.
Shell identified strong gas shows in well 14/5-1 during drilling in 1998, but plugged and abandoned the well. It is characterised by the Falkland Islands Governemnt as a well with gas shows. Rockhopper (who subsequently acquired that acreage) reclassified the well as a gas discovery, which they call Johnson.
At least 2 petroleum systems have been identified in the drilled area of the North Falkland Basin:
- The oil appears to have been derived from the Tithonian to Aptian lacustrine source rocks.
- Wet and dry gas appear to have been derived from a deeper, fluvio-lacustrine source rock, but data is still being analysed.
- The deeper, gas-prone source rock may be in the oil window further south in the North Falkland Basin.
- A deep source appears also to have generated oil slicks observed on SARs in the area north of the wells.
The 2015 Zebedee discovery proves the presence of a further fan system to the south of Sea Lion and its previously discovered satellites. wireline logging indicated 25.3 metres of net oil pay in Zebedee, with 18.5 metres of net gas pay in Hector and an additional 2.6 metres of net oil pay in the F2 oil-bearing sand. Pressure data indicates that the gas gradient is offset from the gas gradient observed in the Beverley and Casper South reservoirs, which means Hector could be oil-bearing in a downdip location.
Only three play type groups have been targeted in the basin to date.
Syn-rift and early to middle post-rift sandstones on the crests of tilted fault blocks or in basin centre inversion highs were tested in 5 wells in the 1998 drilling campaign, with numerous oil and gas shows resulting in four of them. Two more similar targets, drilled during the 2010-12 campaign in more southerly locations within the North Falkland Basin (Desire well 25/5-1 and Rockhopper well 26/6-1) found no significant indications of hydrocarbons.
Lowstand fan sands shed off the front of the major axial delta that prograded into the basin from the north during the Valanginian to early Aptian, were targeted just once in the 1998 campaign, where Shell well 14/10-1 flowed live 27° API oil to surface. There are numerous similar stratigraphic traps still to be drilled in the basin, and the 14/10-1 results significantly de-risk the prospectivity of this play type. None of these sands were targeted during the 2010-12 drilling campaign.
Basin margin-derived sands, shed off both margins of the basin in the late syn-rift to early post-rift phases, have proved to be prolific sources of both oil and gas. Only a small selection of such fans have been drilled to date, and many more similar targets have been identified ready for drilling during the next campaign.
As well as untested examples of the play types described above, several completely untested play types remain to be drilled. These include:
- laterally derived delta sandstones along both basin margins.
- Basin margin sandstones developed during overstepping of the eastern rift shoulder.
- Closed high plays in acreage to the north of drilled areas.
There is now a wealth of exploration data available for the North Falkland Basin.
All proprietary seismic and well data over five years old, plus all spec data over ten years old is freely available, under certain conditions, to bona-fide oil companies interested in exploring in the area: contact This email address is being protected from spambots. You need JavaScript enabled to view it.. Data delivery will be made at our discretion.
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 (via the FIG contact above) or one of the existing licensees, at their discretion.
