There is no harm in doubt and skepticism, for it is through these that new discoveries are made.
Richard Feynman
US educator & physicist (1918 - 1988)
In this article I consider the hope for hydrocarbons in the Falkland Island basins, and ponder why they have remained undrilled since 1998.
The statement “I’ll drink all the oil that’s found in ……….” has (allegedly) been applied to Saudi Arabia, Libya and the North Sea by such BP eminences as Norman Falcon, Sir Peter Kent and Peter Walmesley. Aside from the rather arrogant note struck by saying this before a significant number of wells have been drilled (and having met Norman Falcon when he was in his 80’s, I’d say he was one of the least arrogant people I’ve ever met), overall it would be nonsense to suggest anybody “knows” that the Falkland Island basins will or will not work; that there are “known” to be 60 billion barrels there; that the Majors are ‘risk-averse’; or for that matter that I’m ‘against’ the Falkland Island basins!
It’s certainly true that there were a number of firmly held views around – in the Majors and elsewhere – during the 1990’s. A sample would be:
• The geologists – “there’s no (world class) source rock in the South Atlantic basins (Namibia, South Africa, the Falkland Islands, Argentina).”
• The engineers – “the Falkland basins are remote, hostile, deep water (south of the FI): we can’t develop any discoveries.”
• Commercial guys – “they are thousands of miles from anywhere and the economics just don’t work at these oil prices.”
Even by the end of the 1990’s, when the North Falkland basin had been drilled, the prevailing view would have been something like “there’s maybe a 30% chance of the Northern basin becoming a hydrocarbon province and probably less than a 20% chance for the southern ones. We have better places to explore!” However, any notion that the Majors (especially) are somehow risk-averse and will wait to follow the small players on success is just nonsense: when I was at BP a plank of our exploration strategy was always to be #1 or #2 in a hydrocarbon province and the Majors as a whole tried to do this in for example Gulf of Mexico Deep Water, Angola Deep Water, Sakhalin, Trinidad, Nile Delta etc. A particularly difficult presentation to senior management would be to explain why we’d arrived ‘late’ in a basin’s opening!!
New exploration provinces have become very difficult to find over the last 5 years or so and all of the Majors and many of the bigger Independents have teams of geoscientists (and engineers) looking at basins around the planet, whether remote, hostile or with complex geology – look at Sakhalin or the new Ultra-Deep-Water “Lower Tertiary” play in the Gulf of Mexico, for example. These teams have real “Know How” and work from Plate Tectonics through regional geology to figuring out whether oil or gas in the pores of reservoirs can be detected directly using seismic technology. So, it’s my opinion that the key reason for the Majors continuing to “walk on by” the Falkland’s basins is that they have a fundamentally unfavourable view of the regional geology and that seeing one or more of the Majors farm-in would be a clear signal that there is a credible, different, regional story.
Also, a significant question will be where, if anywhere, might the “province-opening” giant discovery be made? Just as:
• The North Sea was opened up by the discovery of West Sole (for gas) and Brent and Forties (for oil)
• Alaska………..by the discovery of Prudhoe Bay
• Angola Deep Water………..by the discovery of the Girassol/Dalia/Rosa/Lirio complex,
a “new frontier” like the Falkland Islands would need such a discovery. If a “giant” discovery was made there say in 2009, it might get fully developed by 2015: smaller discoveries should then follow on behind, in the queue.
What can we say about the regional geology of, and the opportunity for giant fields in, the Falkland basins?
The North Falkland basin
The North Falkland basin (NFB) is a failed rift, formed during the break-up of the ancient land-mass of Godwana, during Jurassic to Cretaceous times. Thus, overlying Devonian basement (the “pre-rift”), there is a predominantly non-marine Jurassic to Lower Cretaceous fill (the “syn-rift”), overlain in turn by a marine sequence (the “post-rift”) of Upper Cretaceous to Recent age. The geometry of the basin is illustrated by the EW seismic line shown here as Exhibit 1.
The non-marine rocks are described as ‘lacustrine’, deposited in a large lake into which flowed rivers forming sandy deltas and fans – the present day lakes of East Africa are thought to be similar in size and morphology: Jin Qiang et al. (2005) have recently described an interesting Tertiary analogue in the Dongying Depression of Eastern China. Lacustrine fine-grained claystones slowly filled the lake(s), from time-to-time in oxygen-free conditions resulting in a potential source rock with high organic carbon content.
As summarized by Duncan (2006), this lacustrine “syn-rift” package contains the basic components of a petroleum system, namely potential reservoirs and a potential soruce rock.
Exhibit 2 sketches the NFB play concepts, after Duncan (2006). The major potential is believed to lie in the “syn-rift”, in the untested flanks of the basin at the level of the (likely) mature source rock where there may be good reservoir development and the hydrocarbons (hopefully, oil) would have only a short distance to migrate from the mature source rock to these reservoirs.
There are many global analogues of the failed rift basin petroleum system hypothesized for the NFB, especially in Asia.
The eminent Shell geologist Harry Doust has recently reviewed (Doust and Sumner, 2007) the many examples from South East Asia. To make the analogue point firmly, Exhibit 3 shows Doust and Sumner’s summary of the four main petroleum system types (PSTs) recognized in South East Asia – note the similarities with the NFB cross-section of Exhibit 2.
What is especially interesting is that these South East Asian PSTs are in the main thoroughly explored and this allows us to ask a crucial question, namely “what field sizes do such PSTs yield?” Doust and Sumner summarize as follows:
1. Fields producing from early “syn-rift” lithofacies are oil-rich but small, with average ultimate reserves of 25 million barrels oil and 60 bcf gas.
2. Fields producing from late “syn-rift” lithofacies are oil prone but with significant gas (2:1 ratio) and of moderate size, with average ultimate reserves of 55 million barrels and 293 bcf of gas.
These numbers confirm one of the two key mythologies (well, prejudices would be another word!) regarding “syn-rift” PST exploration, namely that individual field sizes tend to be small-moderate. The other mythology is that typically a large number of exploration wells need to be drilled to discover a significant total resource: however, it’s possible that this is based on historic, inefficient exploration – for example due to an absence of modern (3D) seismic data – rather than being an inherent property of “syn-rift” PSTs.
To further examine these two points, let’s consider a specific “failed rift” analogue, the Balmer basin in Rajasthan, onshore in India, currently being explored by Cairn Energy, and similar to those described further to the South East by Doust and Sumner. Independent consultants have estimated that the Balmer basin has circa 2 billion barrels of oil in place. By early 2006, Cairn had drilled over 80 exploration and appraisal wells, testing the extremities of the basin; their “creaming curve” (cumulative recoverable reserve volumes versus time) is shown as Exhibit 4. Exhibit 5 shows various estimates of recoverable reserves by discovery.
What can be discerned from this data, in addition to a significant number of exploration and appraisal wells being needed, is that:
• there is an outside chance that the total recoverable reserve will reach one billion barrels, and
• there is one moderate field (Mangara); the rest are small.
In summary, such analogues tell us that failed rift, “syn-rift”, lacustrine petroleum systems deliver a moderate prize in terms of both ultimate recoverable reserves and individual field sizes: exploration effort is relatively intensive. They are perfectly valid, commercial, targets onshore, as Cairn Energy are proving in Rajasthan and indeed Tullow Oil are proving in the Albertine basin of Uganda.
However, offshore anywhere they are a tougher proposition: offshore in the remote, hostile environment of the NFB, they seem unlikely to offer province-opening discoveries. It is likely that some discoveries will be made in the NFB but also likely that they will at best wait their turn in a queue behind bigger discoveries made elsewhere.
The Southern and Eastern Falkland basins
The southern and eastern basins are undrilled, true Frontiers so there will be a variety of views on the regional geology, even within the same company!
Putting to one side the ‘exotic’ notion of there being an offshore extension of the Andean trend some 150 kms south of the Falkland Islands, suggesting an untested fold belt petroleum system, our main focus should be on the large-scale, wedge-like sedimentary features of prognosed mid-Cretaceous age that have been described from the Falkland Plateau and East Falkland basin east and south-east of the Islands e.g. Richards et al. (2006). Exhibit 6 shows an interpretation of these features as revealing potential basin slope and floor ‘fans’ with a sand provenance to the NW. One can tentatively envisage a petroleum system here, involving (probably channelised) reservoirs in these ‘fans’ and oil migrating from rich, marine, oil-prone Upper Jurassic source rocks similar to those found in the DSDP 330 well east of the Falkland Islands (aka well east – over 1000 kms away!). Unfortunately, however, the mid-Cretaceous wedges show effectively monoclinal dip, perhaps because there are no “active” shales or salt in the system, and so one has to appeal to stratigraphic trapping to envisage anything other than small accumulations.
Thus this system is more analogous to potential, but failed, passive margin petroleum systems such as the Amazon and Zambesi Fans rather than to successful ones such as those fed by the Congo (“active” salt) or the Niger (“active” shale) and should therefore be regarded as high risk.
The Conundrum!
For an experienced oil company contemplating entering the Falkland Islands basins, the region presents a conundrum in that:
• north of the Islands, there is some chance of discoveries but these may be too small individually and collectively to ‘open’ the region for production
• to the south and east of the Islands, the plays are either ‘exotic’ or high risk though the passive margin wedges perhaps offer larger prospects.
For many, the inclination will be to “walk on by” once again. At the recent Geological Society of London conference on the South Atlantic Basins (6-7 Nov 2007), it was noticeable that the session on the Falkland Islands was poorly attended – the British Geological Survey (BGS – the technical advisors to the Falkland Islands Government) and the current license holders were talking mainly to themselves, with little discussion of what it would actually take to deliver exploration success.
With respect to exploration methodologies, beyond conventional 3D seismic there is nowadays a menu of advanced geophysical techniques – for example 2C and 4C, Wide-Angle, Multi-Azimuth, CSEM; attribute extraction including AVO – which should be selected a la carte, and a host of lessons learned in West Africa (the Deep Waters of the Congo and Niger Deltas and the West Africa Transform Margin), both of which should be applied in the deliberate search for subtle, even stratigraphic, traps.
BHP Billiton have just farmed-in to the acreage to the south-east of the islands and, although they are best known as major mining company, they have a decent track record in the E & P business, with a couple of well-known oil & gas men on their Board – let’s see what they do!
An issue for the Falkland Islands Government (FIG)
I believe that a key issue is the lack of pace in assessing the actual oil & gas resources of the Falkland Islands, with exploration effectively becalmed since the 1998 NFB drilling campaign, and that this results from:
• the lack of involvement of the Majors, leaving activity in the hands of AIM-quoted companies, and
• the FIG’s lack of leverage.
This latter point is significant. Whilst a somewhat “hands-off” approach is suitable in mature or maturing provinces such as the US OCS, the UKCS or the NOCS (nowadays), active involvement of a national entity seems crucial to ‘forcing the pace’ in Frontier basins as, for example, in Angola and (historically) Norway. The FIG should consider the formation of a small national oil company, with its own technical, commercial and legal teams, to participate in the exploration and participation of the Islands’ resources.
References
Doust and Sumner: Petroleum Geoscience Volume 13, 2007.
Duncan: Falkland Islands Newsletter, May 2006.
Jin Qiang et al: Journal of Petroleum Geology, October 2005.
Richards et al: Journal of Petroleum Geology, July 2006.
Click for bigger images
Author:
David Bamford
Tuesday, January 08, 2008 14:50