ENERGYFILES MODELLING BASICS

CARIOCA/SUGAR LOAF - Brazil (offshore)

Confirms Tupi as having identified a huge play

The discoveries during 2007 of Carioca in BM-S-9 and Sugar Loaf in BM-S-8 within the Santos Basin, as well as other discoveries in the region, are very significant in that they confirm the potential of the sub-salt play originally identified in Tupi (BM-S-11) in 2006. Tupi pointed to the potential of the area for further oil and gas accumulations buried beneath a layer of salt and these wells confirm that potential.

The reason such a play has remained hidden for so long is this salt layer, which presents the dual challenge of imaging (since salt is relatively impervious to seismic energy) and drilling (since salt tends to wash out whilst drilling, creating zones of lost circulation) as well as the great water depth (over 2000m). In addition Petrobras has had its work cut out in the Campos Basin up to now. Modern technology, high oil prices and new foreign contractors are progressively overcoming, albeit at great cost, all these challenges.

The play will add large volumes to Brazil's reserves. However, as always, there are question marks. Firstly the press reports do not reveal how much of the volumes are gas, especially since the Santos Basin, has, up to now, been a gas-prone region. Also with just a few wells it is impossible to be sure of such large volumes. Proper analysis and application of SEC rules to the definition of proven plus probable reserves would likely limit volumes to less than 500 million barrels until additional successful wells are drilled.

What's more the complex geology and difficult surface conditions would mean many years (up to a decade) before such discoveries could be put into production, particularly in such a tight market for deep water equipment and personnel. Nevertheless the find is very significant to Brazil.

It has long been known that large resources of oil and gas are located beneath the salt basins of the world. Indeed many deep water fields in the Gulf of Mexico are already being exploited from such horizons. The play could perhaps eventually add 1 mm bbls per day by 2030 (if the reports are reasonably accurate) and delay the Brazilian peak date by a decade (to 2025).

However in a global sense the play is unlikely to affect the oil supply situation significantly over the coming decade. A net loss of over 500,000 barrels per day each year to the global market will probably be already occurring (and growing) by the time the first giant fields in the Santos Basin ramp up their output.

COLOMBIA SITTING ON BIG OIL RESERVES reported April 2008

Big oil reserves but big problems to extract them

It all depends on how you define reserves – actually how you define the 20 billion barrels proposed by Halliburton. If this huge volume includes all the heavy and extra-heavy oils that may ultimately be produced over the next 500 years or so then perhaps such numbers are realistic. However large reserves numbers relayed by ANH, Colombia’s national hydrocarbons agency, whose aim is to set out details of a Colombian licensing round, must be taken in context. Especially when the numbers are conflated with a target output hoped for over a period of just a decade. It takes many years to develop heavy oil reserves even in accessible areas.

Colombia has been producing modest volumes of heavy oil, defined as having an API gravity of 22 degrees or less, since at least 1945 and has been producing lighter oils since 1921. Output has been erratic, largely due to the remote and difficult location in which much of the oil is located, both geographically and geologically. A pronounced peak in output in 1999 was due to a combination of just three light oil fields (Cano Limon, Cusiana and Cupiaga in the Llanos Basin) all reaching maximum output at around the same time. No other light oil fields of this magnitude have ever been found, although over 200 smaller fields are also producing in the country.

Attached is a chart that provides one simple forecast for Colombian heavy and light oil production. Of course it assumes the most likely case that no new giant light oil fields will be located - perhaps that may be arguable. Also the years after 2020 are speculative, depending on many factors beyond just the geology of Colombia.

The chart does show how investment in many heavy oil developments will realistically lead to increased total oil output, albeit with exceptional growth in production through the next five years. However it will be very difficult to meet a volume close to the million barrels per day target hoped for by Ecopetrol for 2020 whilst light oil production continues to decline. Furthermore most of the new oil will be much heavier than that already being produced.

Perhaps a 740,000 bbls per day target for 2015, as reported by ANH elsewhere, is achievable with massive investment in drilling, but 1 million barrels per day by 2020 seems very unlikely. As a guide the volume of oil produced over the period from 2008 to 2050 in the chart corresponds to a little over 6 billion barrels; approximately equal to the entire volume of oil produced by Colombia in the 86 years since 1921.

Around 95% of UK oil production has come from the North Sea. A little oil is also produced from onshore and the Irish Sea off Wales and near to 10% of output now comes from the southern part of the Norwegian Sea, west of the Shetland Isles but in total the UK has seen declining output since 1999.

In February 2008 BP announced an oil discovery in Block 204/23, called South-West Foinaven. The name indicates its location, a few kms southwest of the Foinaven field, one of a cluster of fields 190 kms west of the Shetlands. Foinaven has been producing into a Floating, Production, Storage & Offloading (FPSO) system since 1997 and has produced approximately 250 million barrels so far. It peaked at over 100,000 bbls per day in 2002 (including the satellite East Foinaven) but is now in steep decline.

Should South West Foinaven be developed it will be with subsea wells tied back to the Foinaven FPSO, whose life may then be extended. BP intends to evaluate the discovery but mentions in its press release that 2 wells will be required to develop it. Foinaven itself required 22 production wells to achieve plateau output of 85,000 bbls per day and individually the best wells may have managed a maximum of 5,000 bbls per day. Assuming both the new subsea wells are producers (rather than water injectors) then peak production for South West Foinaven could reach 10,000 bbls per day and total reserves may optimistically be 40 million barrels.

Of course this makes many assumptions that only the operator could confirm. Certainly other small accumulations may lie nearby. The licence was awarded to BP and its partner Marathon in 2005 in the 23rd Offshore Licensing Round. "Discoveries like this are key to the future of the North Sea...BP is always looking for new opportunities to invest..." says Dave Blackwood, head of BP's North Sea business.

Quite right too - South West Foinaven is key. Strictly speaking the discovery is not in the North Sea but leaving that aside the modest size of the accumulation points to the future of the UK Continental Shelf - a future of decline supported by small satellite discoveries that reduce decline rates by a percent or two. Production from BP's field could briefly replace perhaps 5 to 10% of the UK's current decline. There certainly may be the odd substantial accumulation remaining (the last one was Buzzard discovered in 2001) but trumpeting relatively insignificant finds like South West Foinaven will be the significant norm.

Egyptian oil production peaked in 1993 at just under 950,000 barrels per day, mostly from the Gulf of Suez and the Western Desert. It has been declining by an average of 2.5% per year ever since. This is despite increasing condensate and natural gas liquids production from its newly developed offshore shallow and deep water gas fields located in the gas-prone Nile Delta. Gas production has grown very rapidly in recent years, almost all as a result of these Nile Delta discoveries and new finds are regularly announced. LNG exports from a plant at Damietta began at the end of 2004.

In January 2008 BP announced a gas discovery in this Nile Delta region, which it described as "significant". The Satis find, in the North El Burg Concession, is said by BP to "demonstrate the potential of the deeper reservoirs within the Nile Delta and will require further appraisal." There is little here to suggest that it is an exceptionally large find, and it will certainly require further wells before BP will contemplate announcing a reserves number. It is probably "significant" in that it has located a new deep gas play, which could itself be large, although this is hardly surprising in such a geological basin.

Satis appears to lie nearby to other developed and developing gas fields on the east of the delta but it will still be a challenge to develop with its Oligocene reservoir reported to lie at a depth of over 6,000 metres below sea level. It is defined as high pressure/high temperature (HP/HT) and will require expensive and specialised equipment to exploit. The Satis find certainly once again confirms the excellent gas potential of this region and there is little doubt that other deep reservoir accumulations will eventually be discovered on trend. However its impact, in an already important region for meeting future global LNG and pipeline gas demand, will likely be very long term.

It has been reported that the second well drilled by Petrobras in Block BM-S-11 in the Santos Basin (which lies offshore to the south of the Campos Basin where most of Brazil's oil and gas production originates) has identified between 5 and 8 billion barrels of light oil and natural gas that could be recovered from beneath water depths of over 2000 metres. This would make it the largest discovery since Kashagan in the Caspian Sea (which was first drilled in the year 2000) and, of course, the largest ever deep water discovery.

The discovery seems very significant and also points to the potential of the area for further oil and gas accumulations buried beneath a layer of salt. The reason such a play has remained hidden for so long is this salt layer, which presents the dual challenge of imaging (since salt is relatively impervious to seismic energy) and drilling (since salt tends to wash out whilst drilling, creating zones of lost circulation) as well as the great water depth. Modern technology and high oil prices are progressively overcoming, albeit at great cost, all these challenges. Further exploration may lead to further finds.

The play could add hugely to Brazil's reserves. However, as always, there are question marks. Firstly the press reports do not reveal how much of the volumes are gas, especially since the Santos Basin, has, up to now, been a gas-prone region. Also with just two wells it is impossible to be sure of such large volumes. Proper analysis and application of SEC rules to the definition of proven plus probable reserves would likely limit volumes to less than 500 million barrels until additional successful wells are drilled, and, depending on the quality of the reservoir, probably less than 100 million barrels. Furthermore the complex geology and difficult surface conditions would mean many years before such a discovery could be put into production, particularly in such a tight market for deep water equipment and personnel.

Nevertheless the find could still be significant to Brazil. It has long been known that large resources of oil and gas are located beneath the salt basins of the world (factored into yet-to-find volumes in all Energyfiles models). Indeed many fields in the Gulf of Mexico are already being exploited from such horizons. The Tupi filed alone could perhaps eventually add 500,000 bbls per day by 2030 (if the reports are near accurate) and delay the Brazilian peak date several years. However in a global sense Tupi is unlikely to affect the oil supply situation significantly over the coming decade. A net loss of over 500,000 barrels per day each year to the market will already be occurring (and growing) by the time Tupi reaches maximum capacity.

(all quotes from these reviews should be cited: "Dr Michael R. Smith, Chief Executive of Energyfiles, the oil and gas forecasting company")