Petroleum Review's Oil & Gas Fields Megaprojects - October Update In Full

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19 Oct 2005
View all related to Natural Gas | Oil | Resource Depletion

Prices set firm, despite massive new capacity

Over the last two years Petroleum Review has regularly updated its listing of the upcoming so-called "megaprojects". The aim of the listing is to attempt to answer the question as to whether sufficient oil is being developed to meet likely requirements going forward, writes Chris Skrebowski.

This latest update "based on public sources of information" identifies a total of 16.65mn b/d of new capacity due onstream by 2010. This, in turn, is made up of 6.34mn b/d of incremental Opec capacity and 10.31mn b/d of non-Opec capacity additions (see p2 for basis of tabulation). This is directly comparable with the 16.5mn b/d identified by the consultant CERA in its recent report. However, CERA's happy conclusion that potentially price depressing excess supply was about to emerge does not appear to take project slippage and depletion fully into account and, therefore, appears highly optimistic.

Experience shows that between 10% and 20% of projects slip from one year to the next. As no company intends this to happen and there is no way it can be anticipated, the only way to deal with it is to continuously update the database. A recent example of this phenomenon is the BP-operated Thunder Horse project, where, following storm damage to the platform, startup has moved from late 2005 to 1H2006. Project slippage does not mean that the capacity is lost, but merely postponed. This, however, will reduce the actual capacity increments each year going forward. The exact magnitude cannot be determined in advance - although 10% to 20% would be a reasonable rule of thumb.

Depletion modelling

Depletion is relatively difficult to model, but must be taken into account when determining future capacity additions. It is possible, and useful, to identify three sub-categories, or types, of depletion.

Type I depletion - is the normal loss of capacity in an oil field as production from wells in one field run down and are offset by new wells or increased production from other existing wells in the field. There is only limited public data available, apart from the North Sea, where decline rates of between 5% and 15% are reported and are typical of the main decline phase. The North Sea also shows that a proportion of the region's fields are able to finally stabilise production at about 10% of peak flows. There have also been reports (not fully corroborated) of 7% declines in Iranian fields and 6% declines in Saudi fields. Offshore fields, which, because of their economics require high flow rates and much more rapid and intensive development, tend to have the most rapid decline rates - often as much as 15%/y. Companies really only suffer the impact of Type 1 depletion when a field is fully drilled up and there is no possibility of offsetting the declines.

However, with the consultant IHS Energy now reporting to various conferences that 90% of known reserves are in production, more and more fields around the world are moving into their decline phase. One estimate is that as much as 70% of the world's producing oil fields are now in decline.

Type II depletion - is when a company, or country, can offset field declines in one part of the country with expansion in another part. Because public data is collected on a national basis, there is only limited data available on Type II depletion - although its magnitude is likely to be the same as for Type I.

Type III depletion - is when a country produces less oil in a year than it did in the previous year. This can be identified quite readily from public production databases (see Petroleum Review, August 2004 and August 2005). Type III depletion will increase as additional countries move into decline, but will reduce as the volumes produced by the countries in decline decreases. In 2003, Type III depletion was running at around 1.1mn b/d, but in 2004 it fell back to around 900,000 b/d (significant revisions to production data tend to confuse the picture). Over the next few years a number of countries are likely to move into decline - Denmark, China, Malaysia, Mexico, Brunei and India are the obvious candidates and account for over 12% of global production - so a reasonable working assumption is that Type III depletion will increase, although with something of a saw-tooth profile. Recent statements by oil companies (Petroleum Review, August 2005) have tended to indicate that overall depletion (Types I, II and III) is running at between 4% and 6%. Analysis of recent company production (see p24) tends to confirm that using a 5% figure is a reasonable approximation. Demand growth is subject to quite rapid swings, but appears to average around 2%/y. By combining these various pieces of information, it is possible to determine whether the market will tighten or weaken and whether "peak oil" is a likely outcome in the period to 2010 (see Table 2).

In 2004, effectively all the world's spare capacity was used up in meeting unexpectedly rapid demand growth. It is not at all clear if the world's oil companies can provide an incremental 3mn-plus b/d from all the small, untabulated projects and infill drilling going forward year after year. The world has now reached the point where the volumes lost to depletion are much larger than the levels of likely new demand. This means total increments requred (new demand plus depletion) are running at around 7%/y, while the largest supply increments in 2006 and 2007 are contributing 3.6% and 3.5%.
It would seem most unlikely that small projects and infill drilling could account for the remaining required 3.5%. The inescapable conclusion is that oil prices will have to remain high enough to destroy demand, bringing supply and demand back into balance.

Table 1: Future oil field projects with a peak production capacity of over 75,000 b/d
Project Location Operator Oil Peak Flows (b/d) Gas Peak Flows (mn cf/d) Reserves (mn b) Partners and shareholdings
Onstream 2005
Opec countries
Bab North East Abu Dhabi onshore ADCO +90 (2005) ADCO 100%
Bonga Nigeria OML 118 Shell 225 170 600 Shell 55%, ExxonMobil 20%, Total 12.5%, Agip 12.5%
DarkhovinPh1 Iran Eni/Naftiran 55   Eni 60% (on behalf of NIOC), Naftiran Intertrade (NICO) 40%
Northern fields incr. Kuwait KOC +300  
Nowruz expansion Iran expansion Shell +90     Shell buy-back from NIOC
Soroush expansion Iran expansion Shell +100   Shell buy-back from NIOC
Non-Opec countries
ACG magastructure Ph1 Azerbaijan BP +300 (2006) 6,000+ BP 34.14%, Unocal 10.28%, Socar 10%, Inpex 10%, Statoil 8.56%, ExxonMobil 8%
(Azeri-Chirag-Guneshli) (Central Azeri)       TPAO 6.75%, Devon 5.62%, Itochu 3.92%, Delta Hess 2.72%
Adar Yale fields Sudan CNPC 250 (2006)      
Angostura Ph1 Trinidad BHP Billiton 60 (2005) 300 BHP Billiton 45%, Total 30%, Talisman Energy 25%
Barracuda (25ºAPI) Brazil (Campos) Petrobras 150 (2005) 770 Petrobras 100%
Baobab Ivory Coast CNR 65 (2006) 25 CNR 57.61%, Svenska Petroleum 27.39%, Petroci Overseas 10%, Petroci Holdings 5%
Caratinga (24º API) Brazil (Campos) Petrobras 150 (2005) 330 Petrobras 100%
Clair South West of Shetland BP 60 (2006) 15 250 BP 28.6%, ConocoPhillips 24%, Chevron 19.4%, Shell 18.7%, Amerada 9.3%
Kizomba B Angola ExxonMobil 250 (2005) 1,000 ExxonMobil 40%, BP 26.66%, Eni 20%, Statoil 13.33%
Kristin Norway Statoil 126 (cond) 530 220 (cond) ExxonMobil 11%?
Mad Dog Gulf of Mexico BP 80 40 250 boe BP 60.5%, BHP Billiton 23.9%, Unocal 15.6%
Mutineer-Exeter (Cnvr Basin) NW Australia Santos 85 (2006) 3 61 Santos 33.3977%, Kufpec 33.4023%, Nippon Oil 25.0%, Woodside 8.20%
Prirazlomnoye Russia Siberia Gazprom/Statoil 155 (2010) 610 Gazprom ?, Rosneft?
Sakhalin I (Chayvo field) Russian Far East ExxonMobil 250 (2006) 1,000 2,300 Exxon NG 30%, Sakhalin O&G 30%, ONGC Videsh 20%,SakhMNG 11.5%, RB-Astra 8.5%
Salym fields Khanty-Mansiisk Shell/Evikhon 120 (2009) 800 Salym Petroleum Development NV (SPD): Shell 50%, OAO Evikhon 50%
Sanha(cond),  
Bomboco(crude) Angola Chevron 100 boe (2007)   Sonangol 41%, Chevron 39.2%, Total 10%, Eni 9.8%
White Rose Eastern Canada Husky Oil 90 (2006) 230 Husky Oil 72.5%, Petro-Canada 27.5%

 

Project Location Operator Oil Peak Flows (b/d) Gas Peak Flows (mn cf/d) Reserves (mn b) Partners and shareholdings
Onstream 2006
Opec countries
Bu Hasa development Abu Dhabi ADCO 180   ADCO 100%
Darkhovin Ph2 Iran Eni/Naftiran +160   Eni 60% (on behalf of NIOC), Naftiran Intertrade (NICO) 40%
Erha Nigeria (OPL 209) ExxonMobil 165 500 ExxonMobil 56.25%, Shell 43.75%
Ghawar Haradh Ph3 Saudi onshore Saudi Aramco +300   Saudi Aramco 100%
NEAD project**** NE Abu Dhabi ADNOC +110   ADNOC 100%
Non-Opec countries
ACG megastructure Ph2 Azerbaijan BP +500 (2008) 6,000+ See under Ph1 in 2005
Albacora Leste Brazil Petrobras 180 (2006) 700mn boe Petrobras 90%, Repsol 10%
Atlantis Gulf of Mexico BP 150 675 boe BP 56%, BHP 44%
Benguela-Belize(BBLT1) Angola Chevron 100 (2007) 400 Chevron 31%, Agip 20%,Total 20%,Sonangol 20%,Galp 9% Buzzard UKCS Nexen 200 (200720/08) 550 Encana 43%, Intrepid Energy 30%, BG Group 22%, Edinburgh Oil & Gas 5%
Cachalote Brazil Petrobras   800
Chinguetti Ph1 Mauritania offshore Woodside 75 123 Woodside 53.85%, Hardman Res 21.6%, Roc Oil 3.69, Premier 9.23%, BG 11.63%
Dalia Angola Total 240 1,600 Total 40%, BP 16.67 %, Statoil 13.33%, ExxonMobil 20%
Enfield (+Laverda/Vincent) Australia NW Shelf Woodside 100 363 Woodside Petroleum 60%, Mitsui 40%
Golfinho Module I Brazil(Espirito Santo) Petrobras 100 (2007) 450 Petrobras 100%
Jubarte 1 Brazil (B60 Santos) Petrobras 60 (2005) 540 Petrobras 100%?
Roncador II Brazil Petrobras 145 (2008) 2,700 (tot) Petrobras 100%
Surmont(heavy oil by SAGD) Canada, N Alberta ConocoPhillips 100 (2012) ? ConocoPhillips 50%, Total 50%
Syncrude Ph3 Canada, Athabasca Canadian Oil Sands 100   Canadian Oil Sands 32%, Imperial Oil 25%, Petro-Canada 12%, Nexen ?%, others?%
Tengiz/Kololev expansion* Kazakhstan Chevron 298 to 450+ 100 7,000 Chevron 50%, ExxonMobil 25%, KazMunaiGaz 20%, LukArco 5%
Thunder Horse (inc North) Gulf of Mexico BP 250 (2008) 200 1,500 boe BP 75%, ExxonMobil 25%
Onstream 2007
Opec countries
Abu Hadriya/ Khursaniyah/Fadhili Saudi onshore Saudi Aramco +500 250 4,500; 500; 950 Saudi Aramco 100%
Azadegan (south part)*** onshore Iran Inspex 260 (2012) 2,500-3,000 Pedco 25%, Japanese interests 75% (Inspex, Japex,JNOC , Tomen)
Bonga South + Aparo Nigeria (OML 118) Shell and Chevron 250 1,000 Shell 55%, ExxonMobil 20%, Total 12.5%, Eni 12.5%
Corocoro Ph1 Venezuela offshore ConocoPhillips 75 450 ConocoPhillips 32.5%, PdVSA 35%, Eni 26%, Opic 6.5%
Non-Opec countries  
Golfinho Module II (28-40 API) Brazil (Espirito Santo) Petrobras 100 (2007/2008) 450 Petrobras 100%
Greater Plutonio (6 fields) Angola block 18 BP 240 800 BP 50%, Shell 50%
Kikeh Malaysia, off Sabah Murphy Oil 120 (2009) 530 Murphy 80%, Petronas Carigali 20%
Lobito-Tombuco (BBLT 2) Angola Chevron +100 (2008) 400+ Chevron 31%, Agip 20%,Total 20%,Sonangol 20%,Galp 9%
Long Lake (tar sands) Canada, N Alberta Nexen 70   1,900 Nexen 50%, OPTI Canada 50%
Mangala and Aishwariya India, onshore Rajastan Cairn Energy 80-100   600 Cairn Energy 70%, ONGC 30%
Peng Lai Ph2 China, Bohai Bay PL19-3 ConocoPhillips 190 (2009)   800 CNOOC 51%, ConocoPhillips 49%
Polvo (BM-C-8) Brazil (Campos) Devon Energy 50   50mn b+ Devon Energy 60%, SK Corporation 40%
Roncador III Brazil Petrobras 145 (2008)   2,700 (tot) Petrobras 100%
Rosa (t'back to Girassol) Angola block 17 Total 250, net+40   300 Total 40%, Esso 20%, BP 16.67%, Statoil 13.33%, Norsk Hydro 10%
Sakhalin 2 Russian Far East Shell +120      
Vankorskoye 2 fields Russia Siberia Shell/TFE PSA 216   900  
Onstream 2008
Opec countries
Agbami Nigeria OPL 216, 217 Chevron 250 (2008)   800 Chevron 68.15%, Petrobras 13%, Statoil 18.85%
Akpo Nigeria OML 130 Elf Nigeria (Total) 225 boe   590 Total 24%, NNPC %, Petrobras %, Sapetro %
Banyu Urip (Cepu block) Indonesia offshore ExxonMobil 170 20 700 in block Under negotiation
Block 208 El Merk fields Algeria Anadarko 100      
Shaybah and Central fields expn Saudi onshore Saudi Aramco +300      
Non-Opec countries
ACG magastructure Ph3?? Azerbaijan BP +400 (2009)   5,400 See under Ph1 in 2005
Frade Brazil Chevron 110 (2007)   300 Chevron 42.5%, Petrobras, Nissho Iwai
Horizon Ph1 (tar sand) Canada CNR 110   3,300 CNR ???
Kashagan Ph1 Kazakh Caspian Agip (Eni) 450 (2009) 1,500 10,000 (tot) Eni/Total/ ExxonMobil/Shell 18.52% each, ConocoPhillips 9.26%, Inspex 8.33%,KMG 8.33%
Kizomba C (Mondo,Saxi,Batuq) Angola ExxonMobil 125   1,000 ExxonMobil 40%, BP 26.66%, Eni 20%, Statoil 13.33%
Marlim Leste Brazil (Campos) Petrobras 180 (2008) 6mn cm/d 150 Petrobras 100%
Marlim Sul III Brazil Petrobras 100   2,679 boe (tot) Petrobras 100%
Moho-Bilondo Congo(Haute Mer) Total 90     Total 53.5%, Chevron 31.5%, Societe Nationale de Petroles du Congo (SNPC) 15%
Su Tu Trang (White Lion)15-1 Vietnam, Cuu Long ConocoPhillips 100?   220 Petrovietnam 50%, ConocoPhillips 23.25%, KNOC 14.25%, SK Corp 9%, Geopetrol 3.5%
Shenzi Gulf of Mexico BHP Billiton 100     BHP Billiton ?%, BP ?%
Tahiti Gulf of Mexico Chevron 125 70 500mn boe Chevron 58%, Statoil 25%,Shell 17%
Onstream 2009
Opec countries
Al Shaheen expansion Qatar offshore Maersk Oil +210    
Corocoro Ph2 Venezuela offshore ConocoPhillips +45   450 ConocoPhillips 50%, PdVSA 24%, Eni 26%
Khurais Saudi onshore Saudi Aramco 1,200   3,000 Saudi Aramco 100%
Qatar GTL (Ph1) Qatar Qatar Shell Gas 70 (cond) 800   Qatar Petroleum?%, Shell ?%
Non-Opec countries
Karachaganak Ph3 & 4 Kazakhstan Eni and BG +200?   Eni 32.5%, British Gas 32.5%, Chevron 20%, Lukoil 15%
Marlim Sul III (FPSO P56) Brazil Petrobras 100  
Marlim Sul IV (Semi tba) Brazil Petrobras 100  
New Canadian tar pit Canada, Athabasca Imperial Oil 100     Imperial Oil ?%, ExxonMobil ?%

 

Project Location Operator Oil Peak Flows (b/d) Gas Peak Flows (mn cf/d) Reserves (mn b) Partners and shareholdings
Onstream 2010
Opec countries
Usan/Ukot/Tongo Nigeria (OPL 222) Elf Nigeria (Total) 150 480+ Elf Nigeria 20%, Chevron 30%, ExxonMobil 30%, Nexen 20%
Non-Opec countries
Jubarte 2 Brazil B60 Santos Petrobras 60 (2005) 540 Petrobras 100%?
Kashagan Ph2 Kazakh Caspian Agip (Eni) +450 (2012) 1,500 10,000 (tot) Eni/Total/ ExxonMobil/Shell 18.52% each, ConocoPhillips 9.26%, Inspex 8.33%,KMG 8.33%
Roncador IV (FPSO P54) Brazil Petrobras 150  
Uvatskoye Russia Siberia TNK-BP 200  
Onstream 2011
Opec countries
Qatar GTL (Ph2) Qatar Qatar Shell Gas 70 (cond)   Qatar Petroleum?%, Shell ?%
Onstream 2012
Non-Opec countries
Horizon Ph2 (tar sands) Canada CNR +122 3,300 CNR ???
Kashagan Ph3 Kazakh Caspian Agip (Eni) +300 (2015) 1,500 10,000 (tot) Agip/Total/ ExxonMobil/Shell 20.37%, ConocoPhillips 10.19%, Inspex 8.33%
Potential Projects
Opec countries
Ahwaz Bangestan devs onshore Iran Pedco? +150  
Arash Iran, in Gulf NIOC     683 boe  
Azadegan (Northern part)*** onshore Iran NIOC/? 400 2,500-3,000
Hamrin Iraq onshore (South) SOC    
Manifa (Arab Heavy) Saudi offshore Saudi Aramco 300   Saudi Aramco 100%
Majnoon Iraq onshore SOC 360 12,100
Minagish EOR project Kuwait onshore KOC 100  
Nuayyim (Arab Super Light) Saudi onshore Saudi Aramco 75 250 Saudi Aramco 100%
Northern Fields "Project Kuwait" Kuwait onshore KOC/? +450  
Ramin Iran, near Ahwaz NIOC   1,500
Sincor II Venezuela Total 180  
Subbah-Luhais Iraq onshore (South) SOC    
Su Tu Nau (Brown Lion) Vietnam block 15-1 ConocoPhillips     PetroVietnam 50%, ConocoPhillips 23.3%, KNOC 14.2%, SK Corp 9%, Geopetrol 3.5%
Tomoporo (23º API) Venezuela PdVSA 250? 1,000 PdVSA, but private investors to 49%
Upper Zakum redevelopment Abu Dhabi ExxonMobil +650?     ExxonMobil to 28%
Yadavaran (Khushk, Hosseinieh) Iran onshore NIOC/Sinopec 300 1,500+ Nioc 80%, ONGC 20%
West Qurna Ph2 Iraq onshore SOC 650 11,300
Non-Opec countries
BC-2 Brazil (Campos) Total    
BS-4 Brazil offshore Shell    
Block 09-03 Vietnam, Cuu Long Petrovietnam 100+? 300-400
Block 18 West (3 fields) Angola block 18 BP   250-300
Block 31 Nth E Plutao+3 dev Angola block 31 BP 500 in block 31   BP 26.67%, ExxonMobil 25%, Sonangol 20%, Statoil 13.33%, Marathon 10%, Total 5%
Block 31 S-Ceres/Palas/Juno Angola block 31 BP 500 in block 31   BP 26.67%, ExxonMobil 25%, Sonangol 20%, Statoil 13.33%, Marathon 10%, Total 5%
Block 32 Perpetua et al Angola block 32 Total   4 discoveries Total 30%, Marathon 30%, Sonangol 20%, ExxonMobil 15% and Petrogal 5%
Fort Hills oil sands Canada, N Alberta PetroCanada 190 2,800 Petro-Canada 55%, UTS Energy Corp 30%, Teck Cominco 15%
Great White Gulf of Mexico Shell   500-1000 boe Shell ??
Jeruk Indonesia, offshore Java Santos   170 boe Sampang PSC: Santos 45%, Singapore Petroleum Co (SPC) 40%, Cue Energy 15%
Kebabangan Malaysia, off Sabah ConocoPhillips   200-300 Block J: Petronas Carigali 20%, ConocoPhillips 40%,Shell 40%
Kharyaga Russia Siberia Total PSA   5,200
Khvalynskoye Russian Caspian Lukoil/KazMgaz   627 boe
Kirkuk Khurmala Dome Iraq onshore NOC 100  
Kizomba D Angola block 15 ExxonMobil    
Kurmangazy N Caspian (Russ/Kaz) Rosneft/KMG 600? 7,000 Rosneft 25%, other Russian 25%, KazMunaiGaz 25%, Total 25% (tbc)
Lungu China Tarim basin Petrochina 500  
Marimba Leste (FPS-Semi) Brazil (Campos) Petrobras    
Marimba Leste (FSO) Brazil (Campos) Petrobras    
Northern Lights oil sands Canada, N Alberta Synenco 100   Synenco 60%, Sinopec 40%
Northern Territories 4flds Russia Timan-Pechora Lukoil, ConPhillips 990  
Stybarrow Australia Exmouth basin BHP Billiton 100 90 BHP Billiton 50%, Woodside Petroleum 50%
Su Tu Vang (Golden Lion) 15-1 Vietnam, Cuu Long ConocoPhillips 100? 400? Petrovietnam 50%, ConocoPhillips 23.25%, KNOC 14.25%, SK Corp 9%, Geopetrol 3.5%
Suncor (tar sands) Canada 100  
Talanskoye Russia Siberia Surgutneftegas   832
Tiof Mauretania Woodside   298
Tsentralnoye block Russia/Kazakh Caspian Lukoil/Kazakhoil   3,800 TsentrKaspneftegaz JV : Kazakhoil 50%, Lukoil and Gazprom 50%
Val Gamburtsev Russia Siberia Yukos/Sibneft   600
Verkhnechonsknoye Eastern Siberia TNK-BP?   1,500
Yalamo-Samur Russia/Azeri Caspian Lukoil   3,750 boe
Yuri Korchagin Russian Caspian Lukoil   879 boe  
Yuzhno-Shapinskoye Russia Siberia SeverTek   500 Lukoil Fortum
*limited production from 12/2004, Vadelyp 2006; ** 250,000 b/d 2007-2009; *** 5,000mn barrels for field; **** Al Dhabiya, Rumaitha, Shanaget

Table 2: Oil demand, supply and depletion to 2010(mn b/d)
2004 2005 2006 2007 2008 2009 2010
Oil demand 82.1* 83.5* 85.3* 87.0+ 88.8+ 90.5+ 92.3+
Demand increase 2.9 1.4 1.8 1.7 1.8 1.7 1.8
Supply increase** 1.1 2.4 3.1 3.1 2.8 2.8 1.5

Opec

0.3 0.9 0.9 0.9 1.0 1.4 0.9

Non-Opec

0.8 1.5 2.1 2.1 1.8 1.4 0.6
5% depletion 4.1 4.2 4.3 4.4 4.4 4.5 4.6
Extra volume required++ 2.3 3.2 3.0 3.0 3.4 3.4 4.9

Source: *International Energy Agency (IEA) Oil Market Report, September 2005; **from Petroleum Review megaprojects database; +calculated on 2% growth; ++volume required from infill drilling and the small projects not tabulated in the megaprojects database

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