History of exploration

Academic seismic and drilling (1950 - 1974)

1. 1950s - seismic refraction profiles shot across the Falklands area by the Lamont-Doherty Geological Observatory.
2. 1970s - a range of mostly academic studies, culminating in the three DSDP boreholes on the Maurice Ewing Bank; these boreholes proved the existence of potential oil source rocks in the area.

Speculative seismic data (1977 - 2001)

1. 1977-78 - two speculative, regional seismic surveys shot by Western Geophysical and GSI - some 21,652 km of data.
2. 1993 and 1994 - Geco-Prakla and Spectrum acquired regional reconnaissance speculative seismic data both south and north of the Islands respectively, with a combined total of 15,558 km.
3. 1995 - Spectrum acquired infill speculative seismic data over their original reconnaissance grid to the north of the Islands; this infill survey comprises 3,650 km of data with a five kilometre spacing between lines.
4. 1997 - Spectrum acquired a grid of seismic data over the Special Co-operation Area, infilling the original regional reconnaissance grid laid down by Geco-Prakla. These data were reprocessed by Spectrum in 2000, and provide excellent quality data over the SCA region.
   Note: the Special Co-operation Area agreement, established in 1996, has been rescinded by Argentina. Acreage on each side of the line designating the western edge of the Falkland Islands Designated Exploration Area that was formerly covered by the SCA agreement has therefore now reverted to the control of the relevant national jurisdiction.
5. 2001 - Lundin Oil acquired 1,250 km of seismic data over the unlicensed area immediately north of Tranches A and B in the North Falkland Basin in lieu of a well in Tranche F, but are available for purchase (from Talisman Energy) by companies interested in applying for licences in that area under the open-door licensing policy being pursued by the Government. 

 

 

 

 

 

Argentine wells (1980 - 1994)

1. Exxon, YPF and Oxy drilled 17 wells were drilled in Argentine waters of the Malvinas Basin
2. The geology of these wells has been summarised by Galeazzi (1998).
3. Five wells had encouraging shows of oil and gas in an under-charged Lower Cretaceous reservoir.
4. The Calamar x-1 well flowed about 3,200 barrels of 37° API oil per day.
5. A well drilled in late 1994 in the San Julian Basin to the northwest of the Islands is reported to have had oil shows within a 300 m thick reservoir interval.

Falklands Production Licences - North Falkland Basin

1. 1996 - seven Production Licences were awarded (to 14 companies) in the North Falkland Basin as a result of a competitive bidding round. The licences covered 48 blocks (some 12,800 square kilometres).
2. 1999 onwards – several phases of relinquishment and operator changes to original licence areas in North Falkland Basin.
   • November 2004 – two new licences covering 16 blocks in the southernmost part of the North Falkland Basin awarded to Rockhopper Exploration.
   • April 2005 - two new licences covering 6 blocks in the northern part of the North Falkland Basin awarded to Rockhopper Exploration. These 6 blocks were previously licensed to Shell and Agip.
   • August 2008 - a new licence covering 2.25 blocks in the southern part of the North Falkland Basin awarded to Desire Petroleum in association with Arcadia Petroleum.
   • Current North Falkland Basin operators are Desire Petroleum, Argos Resources and Rockhopper Exploration. Rockhopper also partner Desire in two of their licences, and Arcadia partner Desire in parts of three of their licences.

Falkland Production Licences - Southern Basins

1. 2001 – ten Production Licences awarded covering 232 blocks over the southern area to the Falklands Hydrocarbon Consortium (Falkland Oil and Gas Ltd and Hardman Resources), with Falkland Oil and Gas Ltd (FOGL) as operator.
2. 2003 – two licences and 37 blocks (90 blocks in total), relinquished by the Falklands Hydrocarbon Consortium (Falkland Oil and Gas Ltd and Hardman Resources) in the southern area as per licence conditions.
3. 2004 – Five licences awarded covering 80 blocks over the southern area to Borders and Southern Petroleum Ltd.
4. 2004 - A further seven licences, covering 195 blocks over 7 Quadrants in the Falkland Plateau Basin were awarded to Falkland Oil and Gas Ltd in December 2004. Unlike the other acreage held in the southern basins by FOGL, Hardman Resources do not partner them in these new licences.
5. 2005 - FOGL/Hardman relinquished a further 18 blocks as per their licence agreement.
6. July 2006 - FOGL relinquished 50% of their licence holding in their 2002 licences held in conjuction with Hardman Resources. This relinquishment was required by the Falkland Islands Government in exchange for changes to the agreed work programme.
7. The Government proactively extended Phase 1 terms of "Open Door" licences, principally to accommodate drilling in Phase 1. Phase 2 was also extended in order to facilitate longer-term planning.
8. September 2007 - FOGL were required by Government to relinquish PL030, followed by, in December 2007, 25% of the remainder of their 2004 licences. BHP Billiton farmed into all the FOGL acreage, and agreed to drill one well in the 2002 licences during Phase 1, one well in the 2004 licences during Phase 1, and one well in each set of licences during phase 2 if they opt to enter Phase 2.

The Falklands Offshore Sharing Agreement (FOSA)

1. FOSA was established before drilling in the North Falkland Basin, and disbanded in 1999.
2. FOSA comprised Shell, Amerada Hess, Lasmo and IPC and their respective partners.
3. FOSA undertook all of the logistics and support work to facilitate a multi-well drilling campaign in the North Falkland Basin.
4. FOSA was managed through a steering committee composed of each operating company.
5. Each company also took direct responsibility for one or more aspects of the FOSA agreement:
   • drilling services (managed by Amerada Hess);
   • the operations base and supplies (managed by Lasmo);
   • health and safety issues, aviation and site survey work (all managed by Shell);
   • environmental work (managed by Lasmo);
   • finance/tax (managed by Amerada and Lasmo).
6. FOSA managed the sharing of a single rig, supply base, aviation link, site survey facility and operations/logging staff.
7. FOSA resulted in savings of over £24m per company.
8. FOSA provided:
   • a larger pool of expertise than could be provided in-house;
   • greater flexibility than if each company were mounting a single or two well drilling operation;
   • a reduced manpower requirement;
   • a unified voice on many issues;
   • companies with enhanced bargaining power when dealing with suppliers;
   • a minimal operational/manpower impact on the community;
   • a huge amount of knowledge in terms of environmental protection and associated monitoring.

A hard copy of the FOSA exploration close-out report can be downloaded here.

Wells drilled in the 1998 drilling campaign in North Falkland Basin

Well Status Table

1. Six wells were drilled in the North Falkland Basin during 1998.
2. The six wells were drilled over an eight month period, using a shared rig on a back to back basis.
3. Technical challenges of drilling in Falklands waters were proved to be far less severe than anticipated.
4. Five of the six wells drilled had oil shows.
5. Most wells found oil within post-rift sandstones located immediately above the main source rock interval, but this reservoir was under-charged as it lies above the main regional source-seal couplet.
6. Live oil was recovered to surface from one of the Shell wells: the oil has an API gravity of 27°, and was from a thin sandstone at 3,000m.
7. Significant levels of gas were recorded in one Shell well from a deep petroleum system.
8. Sufficient was learnt about the basin and its petroleum systems to anticipate success in future operations.
9. Back to back drilling was the one major disadvantage of the FOSA sharing agreement described above:
   1. operators were sharing a single rig, with rental rate near the peak of the market, and there was no time available for analysis of well results before the next well had to be spudded;
   2. the problem was compounded by the fact that the drill sites had been chosen at least six months in advance;
   3. there was no chance to pick completely new locations, with new play concepts, based on the results of the wells as they were drilled;
   4. consequently, only a small number of play types were actually tested, and extensive post-drilling analysis (conducted slowly and with the benefit of hindsight) has identified several other play concepts that might have been better options for drilling.
10. New targets are located on better migration pathways that the targets tested in 1998.
11. The geology and petroleum potential of these wells has been summarised by Richards and Hillier (2000a and b).