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Sharp fall in Angola's production capacity

Angola has seen a substantial loss of production capacity as older fields decline

Angola's production capacity has declined sharply over the past year and is now barely higher than the country’s output, of 1.74 million barrels a day (b/d), according to Petroleum Economist’s field-by-field capacity estimates.

Rising water-cuts are particularly evident for the country’s earlier deep-water fields, which have been producing for more than 10 years. Although two new developments – Eni’s West Hub in Block 15/06 and Total’s Clov in Block 17 – are due to start flowing in 2014, adding a combined peak of 230,000 b/d in 2015-16, this increment might be little more than the capacity to be lost from older fields over the coming few years.

After a spectacular surge of deep-water development in the century’s first decade, work has slowed. For three years, no large deep-water development has been given the go-ahead – the largest projects to see the start of construction work are Chevron’s Mafumeira in shallow-water Block 0 and ExxonMobil’s Kizomba satellites, tied back to existing facilities, in Block 15.

Encouragingly, several large developments could reach their final investment decisions in 2014 – notably Total’s Kaombo in Block 32, Eni’s East Hub in Block 15/06, and Chevron’s Lucapa in Block 14. But it will be 2016-17 before these projects are on stream.

These fields and other projects being planned are likely to see another seven large floating production, storage and offloading (FPSO) vessels installed in Angolan waters, in addition to the 13 large FPSOs already flowing. The new developments are also likely bring another tension-leg platform to Angola, for Mærsk’s Block 16 development. Angola will then be able to claim three out of the world population of (including the new one) 26 such structures, most of which are in US Gulf of Mexico waters.

Block 0: Chevron’s shallow-water licence off Cabinda, divided into Areas A and B, holds a total of 21 fields. Production runs at about 250,000 b/d – down from over 400,000 b/d five years ago – but development work continues.

Early last year the company gave the go-ahead for the second stage of its $5.6 billion Mafumeira field development, which will see the installation of a new processing platform and two wellhead platforms, and the drilling of 34 production wells and 16 water-injectors. The development is due on stream in 2015 and should flow 110,000 b/d of crude and 10,000 b/d of LPG at peak.

Also under way is the Enhanced Secondary Recovery project at the Nemba field, due to start flowing in early-2015, which should add 13,000 barrels of oil equivalent (boe) a day at peak. Projects being planned include: the development of a southern extension of the South N’Dola field, due to flow 28,000 b/d; the Greater Vanza/Longui area development, due to supply gas to the Angola LNG complex; the further development of the Kambala field; and a water-flood project at the Lifua field.

Exploration drilling continues in Block 0, including into pre-salt targets.

Block 4/05: Sonangol brought its Gimboa field on stream in April 2009. The field, lying in 711 metres of water in the western part of the block, produces from three subsea wells to the FPSO Gimboa, with a processing capacity of 60,000 b/d. Production has been running at under 25,000 b/d.

Block 14: Production from Chevron’s three developments has declined sharply, to about 90,000 b/d.

The Kuito field – Angola’s first deep-water development – was brought on stream in December 1999 as a subsea-to-FPSO development, in 385 metres of water. Kuito crude is relatively heavy, at 18-22° API, and production did not reach its expected 100,000 b/d. The field is now in decline.

The four-field Benguela-Belize-Lobito-Tomboco (BBLT) development came on stream in two phases in 2006. Benguela-Belize uses a compliant piled tower – the first installed outside the US Gulf of Mexico – standing in 391 metres of water and carrying surface wellheads, while Lobito-Tomboco is a subsea tie-back to the platform. Production was due to plateau at 200,000 b/d but has fallen well short of target.

Tombua-Landana uses another compliant piled tower, standing in 369 metres of water and with 38 well-slots. Tombua-Landana started flowing through the platform – after early production through BBLT facilities – in September 2009. Production was due to plateau at 100,000 b/d but reached only about 75,000 b/d before moving into decline.

The next development in the block will be the Lucapa field, for which front-end engineering and design work has been carried out. Lucapa, in 1,219 metres of water, will be a subsea-to-FPSO development with 17 wells and a likely peak production of 80,000 b/d. A final investment decision is due in 2014. The Malange field is being studied for development as a tie-back to either BBLT or Tombua-Landana, and developments at Negage and Gabela are being planned.

Chevron is also developing the Lianzi field, in an area – 14K/A-IMI – shared between Angola and Congo (Brazzaville). Lianzi, lying in 900 metres of water, will be a subsea tie-back to the BBLT platform, flowing through a 43-km electrically-heated pipeline. Start-up is targeted for 2015 and plateau production will be 46,000 b/d. Interests in the 14K/A-IMI area are Chevron, 31.25%, Total, 36.75%, Sonangol, 10%, Eni, 10%, Société Nationale des Pétroles du Congo, 7.5% and Galp, 4.5%.

Block 14 holds 11 discoveries: Kuito (April 1997, 385 metres); Landana (December 1997, 400 metres); Benguela (July 1998, 400 metres); Belize (October 1998, 350 metres); Tomboco (February 2000, 500 metres); Lobito (October 2000, 410-510 metres); Tombua (July 2001, 282 metres); Gabela (July 2002, 320 metres); Negage (December 2002, 1,445 metres); Lucapa (October 2006, 1,219 metres); and Malange (August 2007, 266 metres).

Block 15: ExxonMobil’s three developments provide a capacity of over 700,000 b/d, but production has been affected by rising water-cuts and has declined to about 400,000 b/d. Resources in the block amount to 5 billion boe. The company has made extensive use of its “design one, build multiple” approach, installing standardised-design FPSOs and other facilities in short cycle-times.

First production from Block 15 came from the Xikomba field, in the northwest, which started flowing in November 2003 and came off-production in 2011. Xikomba, a subsea-to-FPSO development in 1,480 metres of water, produced about 80,000 b/d.

The Kizomba A development, covering the Hungo and Chocalho fields in 1,000-1,280 metres of water, started flowing in August 2004. ExxonMobil opted for a tension-leg platform with a close-moored FPSO, with surface and subsea wells – there are 33 producers and 26 injectors. The first tie-back to Kizomba A, Marimba North, came on stream through subsea wells in October 2007. Kizomba A has a capacity of 250,000 b/d.

The identical Kizomba B development, producing the Kissanje and Dikanza fields in 1,010 metres of water, came on stream in July 2005. Capacity is 250,000 b/d.

For Kizomba C the company used a second FPSO instead of the tension-leg platform, mooring them about 18 km apart in 700-800 metres of water. The first, producing the Mondo field, started-up in January 2008 and flows 100,000 b/d. The second, producing the Saxi and Batuque fields, came on stream in August 2008. Kizomba C has a capacity of 200,000 b/d.

Development now focuses on the Kizomba satellites, which are utilising spare capacity in existing installations. The first phase, covering development of the Mavacola and Clochas fields as subsea tie-backs to Kizomba A and B, came on stream in May 2012. The second phase, under which the Kakocha and Bavuca fields will be tied-back to the Kizomba B and Mondo FPSOs, is due for start-up in 2015.

ExxonMobil has 17 discoveries in Block 15: Kissanje (February 1998, 1,011 metres); Marimba (April 1998, 1,289 metres); Hungo (July 1998, 1,199 metres); Dikanza (October 1998, 1,154 metres); Chocalho (June 1999, 1,147 metres); Xikomba (September 1999, 1,480 metres); Mondo (June 2000, 740 metres); Saxi (August 2000, 670 metres); Batuque (November 2000, 730 metres); Mbulumbumba (April 2001, 850 metres); Vicango (May 2001, 975 metres); Mavacola (May 2001, 1,155 metres); Reco Reco (September 2002, 1,438 metres); Clochas (July 2003, 1,296 metres); Kakocha (October 2003, 1,030 metres); Tchihumba (October 2003, 1,190 metres); and Bavuca (March 2004, 1,094 metres).

Block 15/06: The block – the compulsory-relinquishment part of Block 15 – was awarded to Eni in 2006. Ten discoveries have been made. Eni launched its West Hub development in 2010, covering the Sangos, Ngoma and Cinguvu fields where there will be 16 subsea wells – 10 producers and six injectors. Oil will be produced to the FPSO previously used by ExxonMobil on Xikomba. Start-up is due in 2014 and production should peak at 70,000 b/d in 2016. 

The next development, East Hub, is being planned. East Hub will tap the Cabaça North and Cabaça Southeast discoveries, to flow 45,000 b/d through an FPSO. Start-up is targeted for 2016.

The discoveries are: Sangos (May 2008, 1,349 metres); Ngoma (October 2008, 1,424 metres); Cabaça North (October 2009, 500 metres); Nzanza (February 2010, 1,400 metres); Cinguvu (February 2010, 1,400 metres); Cabaça Southeast (July 2010, 470 metres); Mpungi (October 2010, 1,050 metres); Mukuvo (2011); Lira (2011) and Vandumbu (March 2013, 976 metres).

Block 16: Mærsk made a discovery with its Chissonga-1 well, at a water-depth of 1,355 metres, in July 2009. A second find was made in September 2012 with Caporolo-1, drilled 13 km from Chissonga but into a separate structure, at a water-depth of 1,235 metres. Appraisal drilling has raised reserves expectations for Chissonga and the company is planning a development using an FPSO together with a tension-leg wellhead platform.

Previous operators made non-commercial finds in the block – Canadian Natural Resources with Zenza-1 at 1,300 metres in 2003 and Shell with Bengo-1 at 600 metres in 1994.

Block 17: Total’s three development complexes provide a production capacity of 710,000 b/d, which will rise soon to 870,000 b/d when the fourth complex starts up. Recoverable resources in the block exceed 5 billion boe. Production has declined to about 600,000 b/d.

The discovery of the Girassol field in April 1996 changed the perception of Angola’s deep-water areas. Girassol was brought on stream in December 2001 through a subsea-to-FPSO development at a water-depth of 1,350 metres, with 39 subsea wells feeding into three riser towers.

Two satellite fields have been developed as subsea tie-backs to Girassol – Jasmim (on stream in November 2003) and Rosa (June 2007). Processing capacity on the FPSO Girassol has been increased from the original 200,000 b/d to 250,000 b/d. Production runs at about 200,000 b/d.

The second production hub, for the Dália field, started flowing in December 2006. The subsea-to-FPSO development, at water-depths of 1,200-1,500 metres, uses an elaborate subsea architecture to handle the relatively heavy 23°API crude – there are 71 wells (37 producers, 31 water-injectors and three gas-injectors), tied-in to nine manifolds. Over 40 km of insulated flow-lines on the seabed feed crude to eight flexible risers. Production reached its 240,000 b/d plateau rate in 2007 and now runs at about 200,000 b/d.

Total launched its third stand-alone development, Pazflor, at end-2007 and brought it on stream in August 2011. Pazflor produces the Perpétua, Hortensia, Zinia and Acacia fields in the eastern part of the block, at water-depths of 600-1,200 metres, holding reserves of 590 million barrels. Production is close to 200,000 b/d.

The development uses an FPSO with facilities to process two grades of crude – a heavy stream of 17°-22°API (mainly from Perpétua, Zinia and Hortensia) and a light stream of 35°-38°API. Because the heavy-oil reservoirs have low energy, Total has used subsea separation facilities – gas is taken to the surface in separate risers, allowing the crude to be pumped to the surface without the use of multiphase pumps and without the risk of hydrate formation.

Pazflor uses 49 production and injection wells, of which 35 (18 producers and 17 water-injectors) will be needed for the heavy-crude reservoirs, with 14 (seven producers, five water-injectors and two gas-injectors) at the light-crude reservoirs.

The fourth development, covering the Cravo, Lírio, Orquídea and Violéta (Clov) fields, in water 1,100-1,400 metres deep, was launched in August 2010. An FPSO with a processing capacity of 160,000 b/d will handle commingled crude of two different qualities, lifted from 34 subsea wells. First oil is due in second-quarter 2014.

Block 17 has yielded 15 discoveries: Girassol (April 1996, 1,350 metres); Dália (August 1997, 1,200-1,500 metres); Rosa (March 1998, 1,300-1,500 metres); Lírio (August 1998, 1,365 metres); Tulipa (June 1999, 1,005 metres); Orquídea (September 1999, 1,197 metres); Cravo (October 1999, 1,357 metres); Camélia (December 1999, 1,296 metres); Jasmim (April 2000, 1,400 metres); Perpétua (August 2000, 795 metres); Violéta (February 2001, 1,059 metres); Anturio (March 2001, 929 metres); Zinia (December 2002, 718 metres); Acacia (April 2003, 1,030 metres); and Hortensia (April 2003, 830 metres).

Block 17/06: Total took the licence to Block 17/06, the compulsory-relinquishment part of its Block 17, to retain control over the whole area. Three discoveries have been made: Gardenia (October 2009, 977 metres); Begonia (April 2010, 453 metres); and Canna (May 2011, 445 metres). 

Block 18: Greater Plutonio, BP’s first development in the country, flowed first oil in September 2007. Greater Plutonio covers five fields lying over a large area in the northwestern part of the block, at water-depths of 1,200-1,450 metres – Galio, Cromio, Paladio, Plutonio and Cobalto. The development uses 20 producing wells, 20 water-injectors and three gas-injectors. Oil flows through a riser tower 1,258 metres high to an FPSO.

A production plateau of 220,000-240,000 b/d had been expected but there have been problems with corrosion in cooling systems, leading to a long shut-down in 2011. Production averaged 100,000 b/d in that year and increased to about 200,000 b/d in 2013.

BP is evaluating development options for the Platina, Chumbo and Cesio fields, which lie about 30 km from Greater Plutonio. The company had planned to use subsea tie-backs to the Greater Plutonio FPSO, to take up spare processing capacity, but is now seeking approval for a stand-alone development.

Eight discoveries have been made in Block 18, with just eight wells: Platina (May 1999, 1,400 metres); Plutonio (July 1999, 1,362 metres); Galio (January 2000, 1,238 metres); Paladio (November 2000, 1,233 metres); Cromio (October 2000, 1,223 metres); Cobalto (December 2000, 1,429 metres); Cesio (2003, 1,600 metres); and Chumbo (2003, 1,600 metres).

Block 18/06: Petrobras announced a discovery with its Manganese-1 well, drilled in 1,500 metres of water, in November 2009.

Block 20: Cobalt made a pre-salt discovery with its Lontra-1 well, at 1,400 metres water-depth, in October 2013. The well tested an equipment-limited 2,500 b/d of oil and 1.1 million cm/d of gas from a liquids and gas zone, and there is also an oil zone. The company is drilling another pre-salt well, Orca-1, 25 km northeast of Lontra.

Block 21: Cobalt made a pre-salt discovery with its Cameia-1 well in December 2011 and confirmed it with Cameia-2, drilled 3.5 km south of the discovery well, in July 2012. The company describes Cameia as a large hydrocarbon accumulation in a high-quality reservoir. Water-depth is 1,700 metres. In October 2013 Cobalt made a pre-salt discovery with Mavinga-1, close to Cameia, which it expects to be tied-back to the planned Cameia development.

Block 23: Mærsk announced a discovery in January 2012 with the Azul-1 well, in 923 metres of water, claiming it as the first pre-salt discovery in Angola’s deep-water areas.

Block 24: Former-operator ExxonMobil made the non-commercial Semba discovery in June 2001 with its first well in the block, at a water-depth of 1,170 metres. Devon took over as operator in April 2003 and drilled the Kabetula-1 well in the northeast part of the block in late 2005. Now operated by BP.

Block 31: BP’s Plutão, Saturno, Vênus and Marte (PSVM) development, the first development in an ultra deep-water block, came on stream in December 2012. PSVM, in about 2,000 metres of water in the northeast area, is a subsea-to-FPSO development with 40 wells, including injectors, and 15 manifolds. PSVM is claimed to be the world’s largest subsea complex, with facilities extending for 34 km. Production was due to reach its plateau of 150,000 b/d at the end of last year.

The second development in the block, covering fields in the southeast area, is being planned.

BP has 19 discoveries in the block: Plutão (September 2002, 2,020 metres); Saturno (July 2003, 1,804 metres); Marte (November 2003, 2,000 metres); Vênus (June 2004, 2,000 metres); Palas (February 2005, 1,602 metres); Ceres (March 2005, 1,633 metres); Juno (July 2005, 1,601 metres); Astraea (August 2005, 1,496 metres); Hebe (October 2005, 2,008 metres); Urano (May 2006, 1,938 metres); Titania (October 2006, 2,100 metres); Terra (January 2007, 2,328 metres); Miranda (April 2007, 2,436 metres); Cordelia (May 2007, 2,308 metres); Portia (February 2008, 2,012 metres); Dione (October 2008, 1,696 metres); Leda (March 2009, 2,070 metres); Oberon (May 2009, 1,624 metres); and Tebe (October 2009, 1,752 metres).

Block 32: Total is close to a final investment decision for its first development in this ultra deep-water block. Kaombo, covering fields in the central-southeastern area, will use two FPSOs, giving a production capacity of 200,000 b/d. Start-up is targeted for 2017.

The block holds 12 discoveries: Gindungo (May 2003, 1,445 metres); Canela (April 2004, 1,540 metres); Cola (2004, 1,600 metres); Gengibre (June 2005, 1,703 metres); Mostarda (February 2006, 1,758 metres); Salsa (December 2006, 1,806 metres); Manjericão (February 2007, 1,977 metres); Caril (February 2007, 1,673 metres); Cominhos (May 2007, 1,594 metres); Louro (May 2007, 1,806 metres); Colorau (August 2007, 1,700 metres); and Alho (December 2007, 1,607 metres).

Block 33: Total made a discovery with the Calulu-1 well, drilled in 2004 in 1,900 metres of water in the north of the block. In April 2013 the firm made a find with Sumate-1, about 30 km east of Calulu, drilled in 1,700 metres of water.

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