Emptynester, Red Here is the whole article. The JDZ receives a plug in the last sentence. The article is from 10/2007, the FSPO mentioned has been on site for some time. If we are lucky the JDZ will contain several Akpo type fields.
Several of our resident oil guys have discussed why the drilling did not extend to total depth. The article may explain why. At these temperatures and pressures the gas, light oil and condensate are a gas and there is no gas/oil interface.
Some of the technical problems have been discussed by Larry " ism". He mentioned the precipitation of hydrates in the production lines. JMHO Good luck, Farrell
Engineering Akpo
Even for an experienced deep-water producer, choosing a difficult and risky condensate field as your first operated development in Nigeria's deep offshore is brave. In December 2008, when first condensate is due to flow from the four-year Akpo development, Total will see if its confidence was justified, Martin Quinlan writes
TOTAL knew on discovery that Akpo was big. The first well in Nigeria's OPL 246 block (the development area is now designated OML 130), drilled at the end of 1999, flowed condensate at 9,000 barrels a day (b/d) and four appraisal wells confirmed the reservoir's extent. But the firm also learned that Akpo would be a particularly demanding development – going beyond the usual challenges of working in over 1,300 metres of water and 140 km off the coast of the Niger delta.
The firm found that because of Akpo's reservoir conditions – high temperatures and a high gas-to-liquids ratio – the reservoir fluid is in a "critical" state, meaning that the fluid type varies with the pressure, temperature and depth. Consequently, there is no distinct gas-liquid contact point in the hydrocarbons column. Developing a critical reservoir in deep water had not been attempted before, Total says.
On the surface, the large production of high-pressure fluids would "push to the limits" a floating production, storage and offloading (FPSO) development. Subsea, there were the usual flow-assurance problems of a deep-water development at a seabed temperature of 4°C, and some additional problems resulting from the high wellstream temperature (of 115°C) and from the unconsolidated reservoir.
The prize was the production of 225,000 b/d of oil-equivalent at plateau, made up of 175,000 b/d of condensate and 9.1m cubic metres a day (cm/d) of natural gas. The reservoir's reserves of critical fluid will yield 0.62bn barrels recoverable of condensate, of up to 53°API, and 28.3bn cm of export gas. The wellhead shut-in pressure is 400 bar and the reservoir gas-to-liquids ratio extends from 45 cm per barrel to a heady 207 cm/b.
The Akpo challenge
Total says its experience of Gulf of Guinea conditions led up to the Akpo challenge. "Because we have been working in Nigeria since 1962 and operating several large projects we were more than ready to develop a deep-water project, combining our technical expertise gathered in, for instance, Angola, our knowledge of Nigeria and our geoscience expertise."
Total's initial concept for the development was for full gas injection, because studies indicated that a small pressure-drop would cause the reservoir fluid to separate out and jeopardise the recovery of condensate. But this concept evolved into a hybrid scheme, with some gas injected and some landed to Nigeria LNG's gas-liquefaction complex at Bonny, to capture some sales revenue from the gas. The firm says further studies of the reservoir showed, surprisingly, that the reduced injection rate would actually increase the recovery of liquids.
The reservoir will be managed by controlling the gas-to-liquids ratio in the wells, with the condensate plateau maximised by producing from low gas-to-liquids parts of the reservoir first and by controlling the arrival of water in the wells. For pressure maintenance, a large number of water-injection wells will be needed from the start of production – there will be 20 and two more for gas-injection.
The production architecture consists of 22 wells, all pre-drilled and all with 3-D trajectories – there are J-shapes and S-shapes and horizontals with departures of up to 3,000 metres. Total will not answer questions about Akpo costings, but it is clear that the drilling programme will account for a large part of the capital expenditure.
High drilling rates
According to Total, Transocean's fifth-generation Deepwater Discovery drillship has been drilling Akpo wells since August 2006. Transocean says the drillship is under contract to Total until August next year – at a day-rate of $364,000. In June, it was joined by GlobalSanteFe's fifth-generation Jack Ryan drillship, which has been contracted by Total until June 2009 at a day-rate said to be close to $300,000. (In July the two drilling companies agreed to merge by the end of the year, under the Transocean name.)
Total calculates it will need nearly 2,000 rig-days for Akpo's development drilling and acknowledges it had to pay "very high daily rates". The firm says it is making the best use of the two vessels by dedicating the Deepwater Discovery to drilling and the Jack Ryan to completion of the temporarily abandoned wells. Advantages of this work pattern include the need to modify only the Jack Ryan to run the completions and wellheads, and "a better learning curve" for each rig's crew. By late August, 12 wells had been drilled.
Cameron has Total's $340m contract for the supply of Akpo's wellheads and other subsea hardware. Deliveries started in late-2006 and are due to continue through 2008.
For bringing the oil to the surface, Total has departed from its previous practice. Most FPSO developments in the deep-water Gulf of Guinea have used flexible risers, and Total's innovative riser towers for its pioneering Girassol development, off Angola, took this approach further. But for Akpo, the firm decided "at the onset of the project" that it would use steel catenary risers.
Contracting considerations were behind the choice. "The basis for the selection was to implement a proved technology, [which is] sufficiently generic to attract competition for its implementation," Total says. In contrast, "for riser towers or flexibles, competition is limited".
Although steel catenary risers are in established use elsewhere, particularly in the Gulf of Mexico, they are relatively new in Gulf of Guinea waters. They were used for the first time by Shell for Bonga and also selected by ExxonMobil for Erha, both off Nigeria.
Norway's DNV, which carried out the design verification for the Akpo risers, says the Gulf of Guinea's benign sea conditions do not call for FPSOs to be turret-moored – in which the FPSO swivels with sea forces to take up the position of minimum resistance. Instead, they are spread-moored, aligned to the prevailing swell from the south-southwest. Accordingly, the Akpo FPSO will mostly be exposed to pitch motion – but roll motion has to be allowed for and presents design difficulties with rigid risers, of which there are 14, hanging off both sides of the vessel.
"The FPSO and steel catenary risers comprise a dynamic system," says DNV, which carried out advanced analysis to establish the integrity of the risers in normal service and against accidents and fatigue.
Total acknowledges that the fatigue life of the risers "is very much influenced by the hydrodynamic behaviour of the FPSO", and for this reason it bundled the FPSO's mooring system with the engineering, procurement, construction and installation contract for the risers. The $0.85bn contract, which also covers umbilicals, flowlines, the loading buoy and the gas-export pipeline, went to Saipem. The Italian firm started work offshore this summer with the Saipem FDS and will be sending the Saipem 3000 out to join it in the first half of next year.
The FPSO, under construction at Ulsan, South Korea, will be 300 metres long and 61 metres wide, with a storage capacity for stabilised condensate of 2m barrels. Because of the very large gas-processing requirements, the topsides load will be much greater than that of other FPSOs – there will be extensive processing capacity to separate gas and water from the condensate, and 15 topsides modules in total. The facility will be moored in 1,314 metres of water with 12 suction anchors and is designed to have a 1% slope towards the bow to help drain the tanks. The contract for the FPSO, worth $1.08bn, went to Technip and Hyundai.
Deep-water engineers spend much of their time thinking about flow assurance – capital costs are so large that even a small loss of production can have a significant effect on project economics. With deep water and cold seabed temperatures, the formation of hydrate and wax in production lines is a big risk during shut-downs.
Total's answer at Akpo takes advantage of the high wellstream temperature: the firm specified a high level of thermal performance for the production lines to give a long "no-touch" period, of four hours. For protection during the following five hours, methanol is injected into the wells, wellheads and jumpers (which connect the wellheads to the manifolds). For the following four hours, protection is provided by the circulation of "dead" condensate through the production loops. Consequently, the need for costly pipe-in-pipe insulation was avoided.
Unfortunate timing
Engineering problems might be tricky, but commercial problems can be more unpredictable: Total went to tender on Akpo at the end of 2003, just when the world construction market became overheated. "Contractors had full orderbooks, shipbuilding was booming and steel prices were soaring," the firm says. "It was not the best time for an operator to launch a global deep-offshore project."
The firm's answer was to include a steel-price escalation formula into the bidding process. It also allowed multi-currency pricing, to be converted into US dollars through forward currency purchases, to cover the risk of a falling dollar. "The unwillingness of bidders to accept a realistic level of risk could not be overcome, without accepting unreasonable price increases," Total says. Consequently, it had to carry the risk itself by accepting negotiated caps on liability.
It also had to introduce reservation agreements, because the bidding process was started more than a year before the development was approved by the Nigerian authorities (in April 2005). Successful bidders were guaranteed the contract award on project sanction, were paid "a consideration" to reserve construction facilities for Akpo work, and their bids were raised by an agreed escalation formula at the time of the go-ahead. Total says its reservation agreements allowed all the main facilities contracts to be awarded "within days" of project sanction – but it notes that the drilling firms would not accept them.
Who owns Akpo?
DESPITE the vast sums being spent in the Akpo licence – the field development will cost well over $3bn and early last year China National Offshore Oil Corporation (CNOOC) paid a breathtaking $2.268bn to join the group – ownership shares are less than transparent.
Akpo was discovered in the OPL 246 exploration licence, then held by Total, the operator, with 24%, South Atlantic Petroleum (Sapetro) – a Nigerian firm headed by a former government minister – with 60%, and Braspetro, a subsidiary of Petrobras, with 16%. The government made moves to claim a stake in the licence for state-owned Nigerian National Petroleum Corporation (NNPC), and legal action is said to have started. In February 2005, the eastern part of the block, holding Akpo, was transferred to the OML 130 production licence, but, at the time, Total would say only that its share in OML 130 was 24% "alongside NNPC, Petrobras and Sapetro".
In January 2006, CNOOC struck its deal with Sapetro to join OML 130, paying $1.75bn to Sapetro and a total of $0.518bn to Total and Petrobras to repay advances made by them to Sapetro.
According to CNOOC, OML 130 is covered by a production-sharing agreement (PSA) and a production-sharing contract (PSC), both signed in April 2005 and each covering a 50% share in the licence. Signatories to the PSA are Total, Sapetro and Petrobras, while the PSC is between Sapetro, NNPC and Total – with Sapetro as the sole contractor. CNOOC's agreement covered the acquisition of 90% of the PSC from Sapetro – and, accordingly, "a 45% economic interest in the whole of OML 130", CNOOC says.
Therefore, interests in the licence appear to be Total, 24%, CNOOC, 45%, Petrobras, 16%, and Sapetro, 15% – the latter made up of 5% through the remaining holding in the PSC and 10% through the PSA. (Petroleum Economist would welcome any further information from readers with knowledge of this licence.)
Akpo is the only commercial field in OML 130 at present, but three other significant discoveries have been made – Egina, Egina South and Preowei. Early this year, Total said Egina might be suitable for a stand-alone development – five wells have been drilled at the field, which lies only 20 km from Akpo, with the last three appraisals hitting oil columns of 60-80 metres. Shell and ConocoPhillips have discoveries in adjacent licences and the area is bordered to the south by Block 1 of the Nigeria-São Tomé e Príncipe joint development zone, where Chevron made a discovery with its first well, Obo-1. n
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