GEO ExPro

The North Falkland Basin

What have we learned from this summer’s exploration drilling activity around the Falkland Isles?
This article appeared in Vol. 7, No. 5 - 2010

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The Jasons are a group of remote islands, to the far north-west of West Falkland, composed of Palaeozoic sandstones, with interbedded siltstones and mudstones. Photo: Eileen Davies, FITB This year six wells have been completed or are drilling around the Falkland Islands, with one announced discovery, Sea Lion, having found significant in-place volumes of waxy crude oil. The published evidence tends to suggest that proof of a major discovery that would open the Falkland basins as a major petroleum province is still awaited.

The Falkland Islands are a self-governing British Overseas Territory - an easy place to do business according to the Falkland Island Government (FIG)’s web-site.
 

Plenty to offer!

A simple summary of the regional geology around the Falklands. There are several under-explored and undrilled basins in the Falklands. Image: Falkland Islands Government According to the Falkland Islands Government, there are many reasons to attract exploration companies to the Islands. It is a petroleum province in its infancy with several under-explored and undrilled basins. There is evidence of a world-class source rock, several working petroleum systems have been proven and there are numerous undrilled targets thought to contain more than 200 MM bbo. Yet until this year only six wells have been drilled to date in Falkland Islands waters, all in a very small area and all testing the same play.

In addition, the FIG point out that they have top quartile fiscal terms with easy data access and there are many new licences and farm-ins available.

The Falkland Islands are surrounded by four major sedimentary basins: the Falkland Plateau Basin to the east, the South Falkland Basin to the south, the Malvinas Basin to the west, and the North Falkland Basin to the north. The basins underwent complex rifting from the Triassic through Valanginian, during fragmentation of Gondwanaland, before being subjected to Cretaceous thermal sag and Cenozoic uplift coincident with Andean compression and the development of overthrusting along the plate boundary to the south.

New exploration campaign

Until recently only a very limited area had been tested – the red dots show the position of the 6 wells drilled in the late 1990’s. Image courtesy of Falkland Islands Government This summer has seen a renewal of exploration drilling activity around the Falkland Isles, the first since the six wells were drilled back-to-back in the North Falklands Basin in 1998.

This summer’s wells targeted the Liz/Beth, Rachel Sea Lion and Ernest prospects in the North Falkland Basin (NFB) and Toroa in the South Falklands Basin, with only Sea Lion, about 225 kms north of the Islands, being announced as a significant discovery. The shared rig returned to Sea Lion to drill an appraisal well which encountered 53m net pay of a medium grade (26.4-29.2 API gravity) crude which flowed at sustained rates in excess of 2,000 bopd (with a maximum of 2,304).

What can we say about what has been learned so far?

Despite brave words about it being early days in the exploration campaign, much having been learned and so on, the success rate is disappointing in comparison with other recent campaigns in the South Atlantic such as those in Angola, Ghana and the Brazil sub-salt, where profound understanding of petroleum systems and extensive 3D seismic data have been exploited to deliver success rates in excess of 50 or even 75%.

A working petroleum system?

Schematic west – to East cross section through drilled section of North Falklands Basin. Image: modified from Falkland Islands Government In reality, this year’s Toroa dry hole to the south of the Falkland Islands has added little to our knowledge of the South Falkland and Falkland Plateau Basins although it is noteworthy that BHP Billiton has now completely withdrawn from its partnership in the area.

Focussing therefore on the NFB, like many of the world’s petroliferous sedimentary basins, it originated in a rifting episode, actually a failed axis of opening of the South Atlantic, and subsequently passed through a syn-rift to post-rift evolution.

In detail, the oldest rocks recorded are Devonian. The overlying succession comprises: a fluvio-lacustrine, early syn-rift interval of possibly mid-Jurassic to Tithonian age; a late syn-rift fluvio-lacustrine interval of Tithonian to Berriasian age; a rift-sag transitional unit of Berriasian to Valanginian age; an early post-rift lacustrine unit of Valanginian to early Aptian age; a middle post-rift, transgressive unit of Aptian to Albian age; a late post-rift, terrestrial to marine unit of Albian to early Palaeocene age; and a postuplift thermal subsidence unit of Palaeocene to Recent age.

Much of the sediment appears to have been derived from volcanic and/or metamorphic terranes, probably located to the north or north-west of the basin. As well as the volcanic material which occurs in the ground mass and as lithoclasts in many of the units, some volcaniclastic rocks and minor amounts of ashfall tuffs are observed, particularly within the late syn-rift succession.

Analagous Basins


Gypsy Cove, just 6 km from the main town, Stanley, is an area of outstanding beauty, flanked by a beach of beautiful white sand and rich in wildlife. Photo: FITB Cross section showing Doust and Sumner’s summary of the four main petroleum system types (PSTs) recognized in South East Asia. 1: Early Syn-Rift Lacustrine Petroleum System (Oil prone); 2: Late Syn-Rift Transgressive Deltaic Petroleum System (Oil/Gas prone); 3: Early Post-Rift Marine Petroleum System (Gas/Oil prone); 4: Late Post-Rift Regressive Deltaic Petroleum System (oil/Gas prone). Image: Doust and Sumner: Petroleum Geoscience Volume 13, 2007 There are many broadly analagous basins around the world, notably in South East Asia, in Rajasthan and in the rifts and lakes of East Africa.

For many such basins, the individual evolutionary stages have been identified and their characteristics summarized. Although often complex in detail, the sedimentary response and tectonic development of the various stages can be correlated with phases in tectonostratigraphic development. Equally, although the depositional environments and tectonic situation of the rift fill may change laterally, basic sedimentary sequence patterns and structural styles can normally be recognized. Characteristic hydrocarbon habitats can be related to these basic patterns, allowing regional-scale comparisons of petroleum systems and hydrocarbon plays between basins with similar geological histories.

This crucial use of ‘analogues’ helps identify common petroleum system types with related parameters, and the plays likely to be associated with them. This is of vital assistance in the evaluation of the petroleum potential of unexplored or under-explored rift basins, such as the North Falklands Basin.

For the NFB, the broad ideas discussed below originate from a regional review of the oil and gas potential of South East Asian Tertiary basins, carried out in Shell during the 1990’s and reported on by the eminent Shell geologist Harry Doust (Doust and Sumner, Petroleum Geoscience Vo.l 13, 2007). The main conclusions of this study were that petroleum prospectivity could be linked to the presence and relative development of a small number of petroleum system types, common to the South East Asian family of basins. As shown in the cross-section, the existence of a lacustrine source rock system in the ‘syn-rift’ is a crucial component of the working petroleum systems; this has been key to prognoses for the North Falklands Basin, as have the inference of rift margin and deltaic sands.

What is especially relevant is that these South East Asian petroleum systems are in the main thoroughly explored and have significant production histories, allowing us to ask two crucial questions: namely “what field sizes do such systems yield?”, and also “are there any special issues connected with them?”

Doust and Sumner suggest that fields producing from early “syn-rift” lithofacies are oil-rich but small, with average ultimate reserves of 25 MMboe and 60 Bcfg, while those producing from late “syn-rift” lithofacies are oil prone but with significant gas (2:1 ratio) and are of moderate size, with average ultimate reserves of 55 MMboe and 293 Bcfg.

The main conclusion relevant to the NFB is that whilst discoveries may well be made, fields bigger than 100 MMboe will be few and far between.

Potential problems with waxy crude

As anticipated,  lacustrine source rocks in the “syn-rift” setting of the NFB constitute a working petroleum system that has resulted in a petroleum accumulation at Sea Lion; as is normal for such sources, the resulting crude oil is waxy. Whilst it has been announced that the wax percentage is at the low end of a world-wide scale, and compares favourably with that of some oils that are successfully being produced, including those in SE Asia, the critical piece of data with respect to flow (or otherwise) – the pour point temperature – has not been revealed.

The difficulty with waxy crude is that it can have a tendency to turn solid en route from the reservoir to the processing facilities.. The technology to overcome this problem, including the injection of chemicals, lighter oils and the heating of flow/pipelines, exists and has led to successful production throughout SE Asia, for example, in Cairn’s Rajasthan operations. Deployment in a remote, hostile, cold water environment may be trickier, however; reduced flow rates and recovery factors and significantly increased development and operating costs should be anticipated.  

The Falkland’s fiscal terms are amongst the most generous in the world and basic economic analyses published by the companies involved in exploration of the NFB demonstrate that a discovery with 400 MMb recoverable reserves could be commercial, using an FPSO and regular offloading to a tanker, with an acceptable number of wells and per well flow rates in the range 7,000-10,000 bopd. But these are significantly higher rates both than those proven so far and those from the best currently under-development and producing analogue to the emerging NFB province, namely Cairn Energy’s operation in Rajasthan.
 

The Rajasthan analogue

Stanley view. Photo: FITB Let us consider this analogue province in a bit more detail. The gross initial-in-place volumes for Rajasthan are estimated in the range 4 to 6.5 Bboe, depending exactly how much is allowed for prospects; gross reserves translate to about 1,150 to 1,400 MMboe. The largest field is Mangala at circa 475 MMboe reserves (1,290 initial-in-place); the two next biggest are 150 and 66 MMboe respectively. Mangala oil has higher wax content (35% vs 18-21%) and viscosity (33cP vs 6.5-8.5cP) than the values reported from Sea Lion., with similar API gravity (29 vs 26.2-29.2) .

For 2010, full year average production from Mangala is estimated at just over 69,000 boepd, from about 60 wells; the balance between production and injection wells is unclear but it is not unreasonable to assume that average production is from 1,000 to 2,000 boepd. Cairn has successfully drilled and completed 6 Mangala horizontal wells which tested at an average production rate of more than 11,500 bopd and a hydro-fracced gas well which flowed at 20.9 MMcfpd. Dominated by Mangala, the initial targeted production plateau production is 175,000 bopd, with a plan to exceed 200,000 via chemical EOR schemes.

In summary, Rajasthan compares well with the South East Asian analogues discussed earlier. Cairn Energy’s developments require a large number of wells and use of well-known technologies; an individual sustained well rate of 2,000 bopd is at the upper end of current performance.

Thus for the NFB, the analogues tell us that the number of discoveries of a size that are likely to be commercial in the hostile waters to the north of the Falklands will be small and that assumed flow rates are significantly greater than those found in practice elsewhere. A key immediate question is whether the flow rates observed so far at Sea Lion are the result of equipment limitations or related to the waxy crude itself.

Dr. David Bamford has over 23 years exploration experience with BP where he was Chief Geophysicist from 1990 to 1995, General Manager for West Africa from 1995 to 1998, and acted as Vice President, Exploration, directing BP's global exploration programme, from 2001 to 2003. He has been a non executive Director of Tullow Oil since 2004 and writes regularly for a number of magazine and e-journals.

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