Construction of Angola's first offshore gas-gathering system should begin in earnest in 2004. The project, which has been under discussion for several years, is finally coming together following a series of favorable events. Major recent milestones were outlined by the project's manager Bill Hauhe, of ChevronTexaco:
•October 2001 – The Angolan Council of Ministers approves a resolution authorizing the project to go forward. Discussions are held between Sonangol E&P and its foreign partners operating the various offshore gas deposits concerning an associated, shore-based LNG scheme
•Around the same time, a Joint Ministerial Commission is formed, empowered to act as a communication conduit between the project partners and the relevant government ministries – petroleum, finance, industry, agriculture and rural development, fisheries and the environment, and public works
•Agreement is also reached that fiscal, foreign exchange, and customs issues must be studied (all of great importance to the partners)
•March 2002 – the partners and Sonangol sign a participation agreement, which also serves as the framework for the Angola LNG Co. agreement. Sonangol and ChevronTexaco are this project's joint leaders.
Equity in Angola LNG has been realigned over the past year, following a review of the individual partners' responsibilities. ChevronTexaco has 32%, followed by Sonangol with 20%. BP, ExxonMobil, Norsk Hydro, and TotalFinaElf each hold 12%.
"The basic tenets behind this project haven't changed," Hauhe pointed out. "The main aim still is to reduce gas quantities flared offshore Angola.
The plan involves harnessing the partners' various associated and non-associated gas discoveries through a large offshore gas-gathering hub – which may or may not have processing capability – situated in shallower waters around 260 km west of Luanda. Collected gas would head to a reception terminal sited just offshore the capital before passing to a nearby onshore liquefaction plant. Initially, this plant could process 4 million tons/yr of LNG via a single train.
"The second train comes into place as resource availability and the markets allow," Hauhe added. The partners also see scope for production of liquid petroleum gas as a secondary, valuable product for export. Following the government's recent peace accord with Angola's warring factions, however, there may also be scope for altering the planned plant locations.
Initially, associated gas supplies will likely be drawn from the deepwater blocks 15, 17, and 18, with the shallow water block 2 providing non-associated base case gas. Following the merger between Chevron and Texaco, gas in blocks 0 and 14 north of the Congo River can also be factored in (both operated formerly by Chevron). In addition, there is a potentially large gas structure in block 1. In general, the gas found offshore Angola has been high in quality and rich in liquids, Hauhe said.
"We've updated our resource for the development, based on the operators' block estimates U however, as more gas is discovered, we're constantly having to change our development scenario. We're also looking for a structure in the shallow water block 2 that could be used for storing gas or for managing gas flow."
The most problematic area for export pipelines appears to be the Congo River, where a large seabed canyon has to be negotiated. The study team has looked at laying a pipeline veering west to deeper waters, before heading into block 14 (a costly option), or taking the line onshore into the Democratic Republic of Congo, then on to a more conventional river crossing, before veering back into Angolan waters for offshore tie-ins.
"The deepwater option involves laying through the canyon, and also identifying and avoiding areas of turbidite flow," Hauhe said. "The speed and flow of the water would make it problematic to hold the pipe in place."
Drilling under the Congo canyon crossing would not be a challenge depth-wise, Hauhe said, as the water on both sides of the river is shallow. The issue is more how to connect the pipe sections drilled under either side of the river, gauging what would be the most suitable pipe diameter and flow rate.
"There could be a single very large diameter pipe or several small ones manifolded together. We're still looking at optimizing this."
The LNG reception facility would be built in 15 m of water in Luanda's harbor, with a concrete gravity base for storage. The project team is looking at reliquefying vapors coming off visiting tankers for use as a sales quality product. It is also investigating an electrically-driven LNG plant, using very large motors instead of gas turbines, which require much greater maintenance.
"If you don't have to do shutdowns for maintenance of gas turbines, that in turn improves production availability. The basis for this project is securing long-term supply contracts. I won't say to whom, but, over the last two years, the US has suffered scares over gas prices. LNG imports to the US have since become the flavor of the day, and ChevronTexaco is very interested in developing import facilities in the US. We've also been looking at southern Europe. The European markets have been getting more and more open, but there are still regional areas where you can get long-term sales contracts on fixed terms. In the US, it's always down to prices, but these are attractive at the moment," Hauhe said.
"Currently we're at Work Stage 1 for this development – pre-front end engineering, resolving technical questions, optimization. And also putting in place commercial structure agreements and fiscal regimes. That phase will continue into 2003. Work Stage 2 will involve front end engineering, with some appraisal wells if necessary, as part of our ongoing subsurface evaluation effort. That phase should last nine to ten months. Then we should be into the engineering, procurement and construction phase, about 36 months, followed by first gas in 2007."
Cautious progress on Greater Plutonio
Rick Waite of BP's Block 18 operations team outlined his company's preparations for deepwater field developments off Angola. The company is 50% operator of block 18, where Shell is its partner. In the ultra-deepwater block 31, it is 27% operator, with a range of partners. BP itself is a partner to ExxonMobil and TotalFinaElf in, respectively, blocks 15 and 17, where it is gaining first-hand experience of potential development hazards.
The production-sharing agreement for block 18 was signed in 1996 by Amoco, Shell, and Sonangol.
"The water depths we're focusing on are 1,200 to 1,500 meters, in the area closest to Girassol and Dalia in block 17," Waite said. "During 1999-2001 we drilled six exploratory and two appraisal wells, with six discoveries: Platino, Plutonio, Galio, Paladio, Cromio and Cobalto. Platino and Plutonio are 35 km apart. All are substantial in terms of reserves, but they are also all spread out. The two appraisal wells have been on Plutonio. Flow assurance and tieback distance are among the issues we have to face," he said.
Range of concepts
"As we wade through the process of working out our development, maximizing the value of our spread resource, do we think large or small, very extensive or very simple systems? We have looked at a whole range of development concepts for block 28 – a single field with a small-scale development, or multiple field developments, wet or dry trees, small or large FPSOs," Waite said.
Early this year, BP settled on the Greater Plutonio Development, the concept for which involves a single, large FPSO with subsea wells spread across multiple fields.
"This means a fairly extensive flowline system on the seabed, with potentially quite long tiebacks. The (front-end engineering and design) FEED started in the first quarter of this year, and we are now in our contractor's offices working through cost definition, in preparation for final sanction for the project from our main shareholders," Waite said.
Subsurface/well engineering teams have also been focusing on requirements during the post-sanction period.
"Once Greater Plutonio is in place, we will have an opportunity to look at future exploration prospects in block 18."
Block 31 was awarded in May 1999. The Tertiary plays from deepwater blocks 15, 17, and 18 extend into this block, Waite said.
"There are issues concerning salt that influence the way we understand the seismic, and may image potential reservoirs. Water depths in block 31 are 1,500 to 2,800 meters. We drilled our first exploration well, Jupiter-1, last year. Plutao-1 was scheduled for this June. We think the block has enormous development potential."
The main technical issues include long-distance tiebacks, insulation systems, and flow assurance for spread-out resources (slug management, hydrates, operability).
"We have gone through an extensive flow assurance study program, looking at how we'd react in the event of a shutdown of one or two fields or an FPSO. When would we intervene, how much cool-down time would be needed? Shutdowns bring potential for hydrates."
BP has studied use of flowlines with built-in insulation systems and possible methanol injection.
"But we need to work out the cost of installation in this water depth. It's a voyage of discovery for all the deepwater block operators off Angola. Our development will involve a significant number of wells, like others nearby. And we will face similar issues on sand control and subsea systems. We're trying to leverage experience from subsea projects elsewhere in the world, but we can also learn a lot from Girassol and the other Angolan developments as they go forward."
Another focus in block 18 is the reduction of carbon dioxide emissions.
"Our aim is to achieve no routine flaring, and to have an energy-efficient topsides design. We also intend to re-inject produced water. We see this as an opportunity for reservoir management, as well as disposal. We're also looking at how to deal with oily, contaminated drill cuttings."
Waite said the partners were hoping to sanction a development in block 18 by the end of this year, followed by a 36-40 month construction and installation program.