WEST AFRICA: Angola's Block 17 could pull $8 billion in investment, produce 450,000 b/d by 2006

The Girassol FPSO, built by Hyundai in Korea, is due to sail out to Angola this month, with first production from the field expected toward year-end.

Girassol, Angola's deepest and most complex offshore development to date, is on schedule for first oil by year-end. The program includes drilling 39 subsea production and injection wells tied to the world's largest floating production, storage, and offloading (FPSO) vessel. At least two developments of similar size are planned in the same prolific Block 17 that has so far yielded 11 commercial discoveries. The challenge for the partners is integrating these fields at a reasonable price, given their widespread location and variable oil quality.

Block 17 and adjacent Block 16 were the first deepwater Angolan tracts Sonangol offered to the industry. Following a bidding competition, Elf became operator of Block 17 in September 1991, with the PSA terms being ratified a year later.

The partners selected at the time by Sonangol remain in place today, aside from Fina, which merged with Total and BP/Statoil which farmed in. Current participation is TotalFinaElf E&P Angola (40% operator), Esso Angola (20%), BP (16.67%), Statoil (13.33%), and Norsk Hydro (10%).

Work on the 5,030 sq km block began in earnest in February 1993, when the partners acquired 3,820 km of 2D seismic. A regional seismic grid was the only data previously available, and no wells had been drilled in the area. In October 1994, the partners initiated drilling with a well on the Margarida prospect in the center of the block, situated in just over 1,000 meters water depth. Oil and gas shows were encountered in Tertiary sandstones, but the well was not tested.

Breakthrough on block

Well number 2 in April 1996 provided the breakthrough. This well targeted a giant structure named Girassol in the southwest corner of the block in 1,355 meters water depth. The well intersected five oil-bearing zones in Tertiary age Malembo group sandstones. Of these, the shallowest was the B3 sand complex which tested good quality crude at a restricted rate of 2,800 b/d. Subsequent analysis revealed the presence of three main reservoirs in a 95-meter interval, about 1,100 meters below the seabed.

A few months later, the partners mounted a two-month 3D seismic acquisition program over a 1,300-sq-km area, covering Girassol and other promising structures. Twin appraisal wells followed in December 1996, 6 km north of the Girassol discovery. On test, the wells flowed 14,000 b/d from the same B3 sands, and 4,000 b/d from the deeper lying B1 sand complex. The second part of this well (Girassol 2B) was deviated to a target 500 meters to the southwest. The well again tested oil, at 3,080 b/d, and also penetrated the B3 sands. By early 1997, Girassol was shaping up as a 700-million-bbl-plus resource.

Second discovery

Earlier that year, exploration had started on an apparently separate structure 3 km to the east, named Dalia. This proved to be yet another productive well, testing 16,000 b/d cumulatively from two Tertiary Malembo sandstone intervals. On completion of this well, Dalia-2 was promptly spudded 7 km further east, in 1,255 meters water depth, in recognition that Dalia could be a larger reservoir than Girassol. This second well tested oil from two different sands from those surrounding Dalia-1.

During 1998-99, two more appraisal wells were drilled northeast and west of Dalia-1. Both flowed oil and were successfully sidetracked for further appraisal. Another appraisal well in 2000 also yielded oil. According to analysts Wood Mackenzie, the two Dalia fields currently are thought to harbor 800-1,200 million bbl recoverable reserves. However, the field's 22°-23° API Miocene oil is significantly heavier than Girassol's 32° API Oligo-cene oil.

Other discoveries

TotalFinaElf's third major discovery in Block 17 came in November 1997, when it drilled yet another Malembo prospect, Rosa, 14 km northwest of Gira-ssol in 1,400 meters water depth. This well tested 12,000 b/d of oil, which was of the same quality as Girassol's. Two successful appraisal wells followed on Rosa in 1999-2000.

Other discoveries and tight-hole status wells followed, of varying oil quality and reserve size:

• Lirio - 32 km north-west of Girassol, in 1,365 meters water depth, flowing 11,000 b/d (33° API )
• Tulipa - close to Margarida-1, tested 7,000 b/d, in a prospective new play east of Girassol and Dalia
• Orquidea - near Rosa, but in a different reservoir horizon
• Cravo - in the southern part of the block, tested 12,800 b/d (34° API)
• Camelia - 6.5 km southeast of Dalia, flowed 9,000 b/d (23° API)
• Jasmim - 6.2 km northeast of Girassol, tested 10,800 b/d (29° API)
• Perpetua - in a more remote location, 35 km east of Dalia in 795 meters water depth, tested 8,740 b/d of heavy oil (20° API)
• Violeta - 26 km north of Girassol in 1,080 meters water depth, is also thought to have been successful, but carries tight hole status
• Anturio - unidentified, but also carries tight hole status.

Only one in the series since Margarida, on the Jacinto prospect, has been dry. Further exploration drilling could occur through to the end of the current contract period of December 2002.

Geological characterization

According to Wood Mackenzie, all the discovered reservoirs are Oligo-Miocene turbidite sands characterized by long, channelized reservoir bodies. In Girassol, the main reservoirs are Upper Oligocene distal turbidite sands. These sands were deposited from channels with northeast-southwest to north-south axes, extending over an area 18 km long and 10 km wide. The Girassol reservoirs are shallow, lying 1,100 meters below the seabed, and the sands are commonly unconsolidated, which will mean using sand-screen devices in the producer wells. Porosities range up to 40% and permeabilities up to 6 darcies. Typically, reservoir temperatures are 65° C, with pressures of around 265 bar.

The Girassol development is exploiting the B1, B2, and B3 sand complexes - B1 is the oldest, situated in the field's center, while B2 and B3 lie respectively east and west. The initial development is focusing on B3, which is the most prolific, according to Jean-Philippe Magnan, Director of Block 17 for TotalFinaElf E&P Angola. The second phase will exploit B1 and B2.

Girassol development

Prior to its merger with TotalFina, Elf had initiated the first-phase, $2.5 billion development of Girassol in 1998. The scheme allows for 39 subsea wells tied back in bundles, via riser towers, to an FPSO spread-moored in 1,350 meters water depth. Mar Profundo Girassol, a joint venture between Bouygues Offshore and Stolt Offshore, is providing the FPSO, which will be the world's largest, at 2 million bbl storage capacity.

The vessel's 300 meter by 60 meter hull and 23,000-ton topsides were completed by Hyundai in Korea in March. The FPSO was due to arrive, already fully commissioned, in Angola mid-July. According to Magnan, "this will be the most critical phase ellipse when everything has to be connected." If all goes well, first production should be achieved by year-end.

1st, 2nd phases

The newbuild drillships Pride Africa and Pride Angola were hired on extended contracts for the development drilling, which began in May 2000. Currently eight wells have been completed, and development drilling will be run through 2003.

Of the 39 development wells, 23 are expected to be oil producers, 14 are water injectors, and two are gas injectors. Water injection will be applied throughout the field's life to maintain pressure. Individual wells will be able to produce 20,000-30,000 b/d of oil, and a collective rate of 242,000 b/d is feasible. However, the plan at this stage is to attain plateau production of 200,000 b/d six months after start-up and maintain that level for at least four years.

A second Girassol development phase, due to start end-2002, will determine future production rates. Oil will be exported through an offloading buoy to visiting tankers.

Onboard the FPSO, a 400,000 b/d seawater desulfatation plant will provide water for injector wells. Water injection capacity will be 390,000-400,000 b/d. The gas injection facilities will operate at up to 280 MMcf/d at 285 bar, with compression at around 8 MMcm/d. There will also be a 235 MW gas-fired power plant. According to Wood Mackenzie, the average gas-oil ratio in the Girassol reservoirs is 600 cf/bbl.

None of the produced gas will be flared. All of it belongs to Sonangol under the contract terms. There is a contingency plan to lay a gas pipeline to shore to a future Angola LNG plant. If this is the case, the three gas injectors, initially set to re-inject produced gas into the B3 system reservoir, could be converted to water injectors.

Alto Mar Girassol

A second joint venture, called Alto Mar Girassol (also Bouygues Offshore and Stolt Offshore), is supplying and installing the flowlines and 77 km of control umbilicals under a $410 million contract. Doris Engineering in Paris participated in the design and engineering of the subsea scheme, which will employ flowline bundles and three self-supporting, 1,350-meter tall hybrid riser towers.

For the bundles, two 8-in. production lines are installed inside a 30-in. carrier pipe. Syntactic foam inside the bundles provides buoyancy and a degree of insulation that limits temperature loss to 1° C per km of bundle (thermal conductivity < 0.13 W/m.K after 20 years). Submerged weight of one bundle will be 40-50 kg/m.

The riser towers will house six production/ injection lines, plus gas lift or service lines, and incorporate the same syntactic foam. These will be anchored to the sea floor via a suction pile and held in place by a 40-meter-high steel buoyancy tank with a top elevation at 50 meters below the sea surface. The towers will be connected to the FPSO through flexible jumpers and to the flowlines by jumper spools. The riser tower concept was successfully modeled and tested in a basin in France last year.

The riser towers are being built in Lobito, south of Luanda. On completion, the insulated tower section will be pulled into Lobito Bay for connection to the upper tower unit. The assembled towheads will then be towed 600 km to the Girassol Field for upending and installation. The bundles, assembled north of Luanda in Soyo, will be transported to the field via a bottom tow method.

The other major contract, valued at $220 million and won by FMC, is for a guidelineless, remotely controlled subsea production system.

Dalia development

Around 725 million bbl are thought to be recoverable from Girassol's System B reservoirs, but Dalia's reservoirs could yield 1 billion bbl, Wood Mackenzie suggests. Dalia was declared commercial in May 1999, and ABB was subsequently commissioned to perform basic engineering and to evaluate alternate development concepts.

A design competition was recently launched for the umbilicals and flowlines, and tenders have been invited for an FPSO, which may be leased. According to Magnan, "by Q4 2001, we expect to have all bids in for all of the major contracts - subsea production/seabed flowlines, FPSO/topsides and drilling, and we expect all contracts to be awarded Q1 2002." An application for a development license has been awarded.

The value of Dalia's crude is $2/bbl less than Girassol's, he adds, so the partners are looking to limit total costs (investment + operating costs) for this project to $6/bbl. "Dalia's FPSO will be able to produce 225,000 b/d of Miocene oil, which is more or less the same flow rate as Girassol's," Magnan said. "However, the topsides composition and weight will be different, as Dalia's heavy oil is more complicated to process. Washing the oil with water will require more heating. We need two process trains, compared with one on Girassol."

The subsea scheme also will be more expensive. The design team is working on 68 wells, Magnan says, 35 producers, 30 water injectors, and three gas injectors. Two rigs could be hired for two years of development drilling, with one of these retained for four more years. But reservoir management is still open, and the optimum number of wells needed at first oil is still under review.

Large subsea scheme

On Dalia, there will be no subsea pumps, only gas lift at the riser base. So far, there has been no commitment to riser towers, "although this is definitely a possibility." As at Girassol, gas will be re-injected into the reservoir until the LNG plant is operational or a commercial outlet is found. Dalia first oil is scheduled for the first half of 2005.

Of the other discoveries on Block 17, only Rosa looks large enough to warrant a standalone platform-based development. Wood Mackenzie estimates recoverable reserves at 450 million bbl.

Girassol C, Rosa D, Rosa E, Cravo, and Lirio are all higher quality Oligocene oil. "We have completed conceptual engineering studies and the selected scheme is to connect all Oligocene discoveries to the Girassol FPSO and all Miocene discoveries to the Dalia FPSO. We are currently working on how to connect all these discoveries," says Magnan.

Another potential satellite for Dalia - Perpetua - lies 50 km distant. Tulipa and Orquidea, both smaller, are also somewhat remote. At the Institute of Petroleum's deepwater conference in London this February, Jean-Francois Duhot of TotalFinaElf's Africa E&P division, suggested that downhole separation could solve problems associated with variable oil quality, while multiphase pumps on the seabed could offset low energy drive in the more remote reservoirs. Subsea processing would avoid having to treat huge quantities of water on the FPSOs, he added.

Wood Mackenzie estimates 3.1 billion bbl of recoverable oil have been identified in Block 17, with substantial upside in upgrades to existing discoveries. The unexploited system C reservoirs west of Girassol could contain a further 300 million bbl.

Capital expenditures, assuming all the fields are developed, could top $8 billion with the production plateau from Block 17 exceeding 450,000 b/d in 2006. There may be further discoveries to come, as the exploration license for Block 17 does not expire until end-2002.

The entire block is now covered by high resolution 3D seismic that is still being interpreted, Magnan says, using the most advanced techniques available. "The problem in the deep offshore is that drilling costs are high. You have to counter these costs with improved interpretation."