Angola's government is determined to halt wastage of the country's natural gas resources. The country produced 354 bcf last year, of which 300 bcf was flared, according to Amadeu Azevedo, Head of Licensing and Exploration at the Ministry of Petroleum. Only a small percentage was harn-essed for domestic consumption as LPG, with the remainder used for re-injection or gas lift on oilfield operations.
However, commercialization studies are well advanced. They have to be, in light of the surge in associated gas production anticipated when the deepwater oilfields come onstream. The most ambitious plan involves gathering gas from numerous shallow and deepwater Angolan blocks for conversion to LNG - the pluses and pitfalls were outlined at the recent Angola Energy Summit in London, organized by IBC Global Conferences.
As elsewhere in West Africa, Angola is devoid of offshore pipeline infrastructure. Its domestic markets are undeveloped, Azevedo added, and it also has lacked the resources, until now, to finance gas-based export schemes.
The government's Gas Master Plan involves two separate projects. The first, relating to associated gas production from fields north of the Congo River mouth in Cabinda, should bring an end to flaring there within four years. (Cabinda currently generates two-thirds of Angola's gas output). In future, the gas will be exploited for conversion into LPG, LNG and NGLs, or for injection/gas-lift purposes.
The more major undertaking relates to blocks in the South Lower Congo basin, where most of the new activity is concentrated. Here, current total production of 350 MMcf/d is expected to double during 2001-2007, Azevedo forecasts, as fields such as Girassol come onstream. The government plans to build a new LNG plant near Luanda to exploit this gas for domestic and external use. Most obvious export markets are neighboring nations in southern Africa, joined in the longer term by southern Europe and Brazil.
Industry targets
In his presentation, Dr. Mourad Belguedj of the World Bank Group estimated Angola's proven reserves at 700 bcm, of which 77% is associated gas. The quantity flared each year would, on its own, drive one LNG train, he asserted, as well as costing Angola over $500 million annually in lost revenue. A key factor hindering commercial exploitation has been the country's continuing civil strife, which has led to Angolan industry operating today at only 10% of its installed capacity.
Power generation capability throughout the country totals 617 MW, Belguedj said, most of it hydroelectric. Around Luanda in particular, there is an urgent need for 50-100 MW gas-fired turbines to meet urban demand. Other major users of the offshore gas could be a proposed ammonia/urea plant in the Soyo area in the north, which would require up to 50 MMcf/d, and a planned 200,000 b/d oil refinery at Lobito in the south, consuming 15 MMcf/d. Gas could also be used to boost domestic LPG consumption, following rehabilitation of run-down bottling plants in the major cities.
The planned LNG terminal would be situated close to Luanda's existing 30,000 b/d refinery. To start with, a single-train facility should suffice, with capacity to handle 3 million tons/year of LNG supplied by the offshore gasfields. Over time, overland pipelines connecting to the terminal could be added tying in other high demand areas to the north and south.
Texaco's progress
Texaco proposed the offshore gas gathering scheme in 1997, and is now joint coordinator of the studies with Sonangol. Bill Hauhe, Texaco's Manager for the Angolan LNG Project, outlined progress to date at the IBC event in a joint paper with Sonangol's Antonio Orfao. He stated that a Joint Planning Agreement had been signed with Sonangol (which owns all Angola's gas) and that gas gathering negotiations were under way with various other block consortia.
Reserves in blocks 15 and 18 have not yet been certified, but in other blocks where there has been concerted exploration, a total of 9.5 tcf has been quantified. Gaffney Cline and Associates estimate upside for the area at up to 25 tcf. This would be more than sufficient to sustain plateau production for over 30 years.
However, Texaco/Sonangol aim to bring onboard initially only selected participants from some of the deepwater blocks that would "add value" to the project, Hauhe said. Not all the harnessed gas would be associated. Some undeveloped, non-associated fields in shallow water areas would also be tied in.
Associated gas produced from the deepwater fields would be exported via a series of long-distance manifolded flowlines to a centrally located production facility, situated in shallow waters on Texaco's block 2. From there a newly installed pipeline, 30-36-in. diameter and 260 km long, would carry the gas subsea to the reception center in Luanda. Capacity of this line would be 750 MMcf/d initially, but it would likely be raised over time to above 1 bcf/d. The development may also entail some dehydration, acid removal, and compression at a later date.
Although a land-based LNG terminal is the preferred solution, there is one problem in the shape of a 30-meter-high cliff at the proposed beach site. As an alternative to shore-based LNG tanks, the partners are considering a concrete GBS storage and tanker loading structure, designed by Kvaerner, which could be floated to a point 300 meters offshore at the harbor entrance, where it would then be installed on the seabed in a water depth of 15 meters.
If this solution is chosen, a front end engineering design contract could be issued late this year. The chosen contractor would also be responsible for the offshore facilities FEED work. By the end of 2001, the project partners aim to have all necessary finance for the project in place, leading to first LNG shipments early in 2005. Once sufficient markets have been identified, capacity in the plant could be expanded to over 6 million tons/year.
Supply doubts
Pierre-Rene Bauquis is a special adviser to the chairman of TotalFinaElf, which is a major partner in Indonesian, UAE and Qatari LNG projects. There are three pre-conditions, Bauquis suggested, for any large gas scheme to prosper, namely:
- Sufficient reserves
- Adequate gas profiles
- Suitable regulatory framework.
In Angola's case, all of these conditions remain to be established, but without them, ambitions can founder. Bauquis alluded to the case of Segazcam, launched by Mobil and Total in Cameroon. After the two companies had put in $50 million, it failed because of insufficient gas reserves. Another project to take Algerian gas to the US also collapsed, due to misunderstandings over pricing in the US market, Bauquis claimed. Newbuild terminals and LNG tankers had to be scrapped, incurring multi-billion dollar losses. Governments also can disrupt planning, he warned, by amending tariff rules without warning.
Angola looks to have the required reserve volume, but there is a major risk, he said, in that this is the only planned LNG project in the world where the main feedstock is associated gas. Furthermore, much of the gas lies in deepwater fields, far from the shore, which will push up development costs. Banks will seek firm assurances on these issues before committing to loans.
Bauquis added that with such a high percentage of the gas coming from multiple sources, the project team will need a strong understanding of the varying chemical compositions - but this could prove difficult to predict. Gas output will depend on quantities of oil produced, with the result that there will be little room for production flexibility.
In the buildup to first LNG, maximum amounts of gas produced will somehow have to be stored to avoid flaring, Bauquis commented. Once the project was onstream, the gas would then need to be exported to shore as regularly as possible, he said. "You could re-inject the gas in the producing oilfields, but the reproduction profile is non-controllable. Alternatively, you could re-inject it into the original field from which it was produced - provided that doesn't deteriorate oil recovery - or into other fields using secondary or tertiary recovery. You could also store the gas in underground aquifers, as is common in France, or use depleted oilfields as storage centers.
"Whichever method is chosen, some gas will be lost and the costs will have to be calculated. The best storage locations will be those with the lowest costs, the lowest potential storage losses, and the highest flexibility for producing at different rates."
Most important of all, Bauquis concluded, is the need for an adequate Angolan regulatory framework. "Operators need incentives to discover and delineate gas, and then to certify it. How also do you create incentives to produce the gas? All LNG projects have faced this problem ... however, few have faced a situation as complex as Angola's with its multi-block, multi-supply system, involving such a large number of suppliers."
Profits in other LNG schemes have been concentrated either upstream (Indonesia), downstream (Abu Dhabi), or both. An optimum method has yet to be determined for Angola, he pointed out. Another problem facing long-haul exports is that Angola is 500 miles further than Nigeria from the major markets, which might depress the rate of return from the gas.
Frontier potential
As for Angola's crude inventory, the recent discoveries trebled reserves from 1996 levels to 12 billion bbl, said Amadeu Azevedo, and the Petroleum Ministry predicts that a further 4 billion bbl will be added over the next three years. Current Angolan production of 780,000 b/d should climb to around 1.3 million b/d by 2005. Over the next decade, more than 20 large discoveries could be developed, he added.
The government now wants to extend the exploration process to the ultra-deep blocks in the Lower Congo Basin, and also to the Namibe Basin shared with Namibia. This is the only undrilled offshore basin in the Namibian margin - it stretches from just above the Walvis Ridge northwards to the Angolan port of Namibe. Joint geological studies are under way between Sonangol and Namibia's Namcor to identify exploration plays. These involve re-interpretation of the entire 20,000 line km 2D seismic database on the Namibian side.
According to Namcor's Managing Director Joe Vatanavi, the Namibe Basin is part of the West African Salt Basin and is distinctly different from the sedimentary succession found in the explored Namibian basins south of the Walvis Ridge.
Another important characteristic of the basin is the relative abundance of structuration which enhances the potential for trapping of hydrocarbons. Several large structures are visible on the seismic. The presence of regional shale intervals increases the seal potential. Thus a working petroleum system is envisaged."
Block 18 prospects
BP Amoco is operator of ultra-deepwater block 31 and deepwater block 18, where there have been three recent discoveries - Platina, Plutonio, and Galio. A fourth well is currently being drilled on another prospect, Paladio, which will be followed by a further period of evaluation, said Joe Bryant, the new President of the company's Angola Business Unit. "Our development strategy for block 18 is as follows:
- Must ensure alignment from the outset with the other stakeholders, Sonangol and Shell. There is an extremely high CAPEX involved, so we must all work to common objectives.
- We are focusing on risk mitigation both of the reserves available for the development and the technology to access them. We're in the early planning stages, but we're also getting more comfortable each day with quantifying the risk.
- We must minimize the time from discovery to first oil, due to the large outlay involved. Currently, we see sanction for a development coming in 2001, leading to initial production in 2004-05."
Block 31 operatorship was awarded to BP Amoco in the May 1999 licensing round, covering blocks in 1,500-2,500 meters water depth. "We recently completed a very low cost, rapid acquisition rate 3D survey on our acreage," Bryant said, "and we plan our first well there in 2001. Exploration could open up new geological plays."
Bryant stressed the importance of minimizing exploration, development and operating costs in order to maximize margins. "Angola may have one of the world's lowest finding costs, but this is offset by the high development costs needed to bring the oil online. And the deepwater operating costs have yet to be determined. We can't let our exploration successes cloud these future issues.
"On the reservoir engineering side, we need more high quality 3D and 4D seismic, plus more flexible reservoir models. We need more specialist workover vessels in the area, extended open hole gravel pack techniques, long distance satellite tiebacks, and more flexible production units such as multi-function barges and Spars."
As for deepwater field backup, "a lot of services will have to be imported in the short term," he said. "But in the longer term, Angola will have to build up its fabrication capability, and also its skilled work force pool in all technical and financial disciplines. We need a wider breadth of expertise and strength in depth." BP Amoco, for its part, hopes to employ 500 Angolans in its enterprise within the next five years.
Bill Nicholson, Odebrecht Oil & Gas Vice President, Angola, agreed that in terms of platform construction, "local content is currently very low, not much more than hookup and commissioning. But if you could at least build the hull in Angola, that would raise the local content to 25-30%."
Stolt Offshore's emerging yard in Lobito is assembling riser towers for Girassol. But Nicholson was disturbed that Angolan input into facilities design remains practically zero. "We must build up this capability if we are to build larger structures in Angola," he warned.
"The cost of doing business in Angola is still too high, and the support infrastructure is lacking. We also need a new center to serve the southern offshore blocks, with a good natural harbor with port facilities, plus an existing industrial base to cater for the offshore industries."
