Fields in Bredasdorp Basin Block 9.
Subsea wells linked to a remotely con trolled buoy will safeguard supplies to the gas-liquids refinery at Mossel Bay, South Africa. The development must generate first gas this spring, to counter falling production from the F-A platform, 85 km to the south in the Indian Ocean.
The Mossgas-operated refinery employs the Fischer-Tropsch conversion process in three trains, each with a capacity of 65 MMcf/d. Throughput of 195 MMcf/d of dry gas must be sustained at all times, but there is also a requirement for richer gas to sustain the correct product balance from the refinery.
Since the early 1990s, all supplies have come from the F-A field in South Africa's Bredasdorp Basin Block 9 - the gas and condensate product streams are piped directly to the refinery. In 1997, the production platform was modified to tie in four satellite wells from the F-AH and F-AR structures. But these alone will not maintain plateau output beyond 2001.
Other gas accumulations had been discovered in the western part of Block 9 in the mid-1980s. The largest was E-M, 50 km west of the F-A platform. The discovery well in 1984 tested 17 MMcf/d from Late Jurassic - Early Cretaceous shallow marine and fluvial sandstones. Reservoir quality seemed passable, with typical porosity of 13% and net-gross ratios varying from 72-98%. Permeability ranged from 5-200 mD.
Over the next two years, five more wells were drilled on this structure, while other wells in the area encountered the same shallow marine and fluvio-deltaic sequence.
Early on in the Mossel Bay project, the E-M area had been a candidate for joint development with the F-A fields. In the event, further studies were shelved until May 1997, when Mossgas launched a FEED competition between two sets of contractors. They were given four and a half months to put forward an all-embracing scenario, reservoir description, sub-surface engineering, production facilities, net present value, South African content, and so on to arrive at the best business case. The winner was Dresser Kellogg Energy Services (DKES), based near London. This division of Halliburton draws on expertise from several group companies, including Halliburton Energy Services for well construction/drilling and Granherne for project management/facilities engineering.
Mossgas decided to develop both the E-M Field and E-BF, just to the east - combined reserves are around 600 bcf. During the concept screening process, three overriding issues had to be resolved:
- Export tie-in location for the produced fluids
- Nature of the sub-surface development
- Location for the fluids processing equipment.
DKES opted to export the fluids to the F-A installation via an 18-in. pipeline. This diameter was selected based on fluid types and anticipated production levels over the fields' lives. A separate platform was discounted in favor of an unmanned control buoy connected to up to ten development wells. This would be operable from the F-A platform via a UHF link. Several buoy concepts were considered, but DKES opted for the Sea Commander, devised by Ocean Resource in Chepstow, Wales. They already had an application working successfully on the East Spar Field off northwest Australia. Another attraction of a buoy for DKES was the possibility of a future re-deployment elsewhere.
Reservoir re-analysis
Phase 1 and 2 wells (E-M03 is optional).
As part of its remit, DKES used the existing E-M area datasets to generate a reservoir simulation model. New analysis suggested probable reservoir compartmentalization - the recommended action was to drill high angle sub-horizontal wells to access gas from the suspected fault compartments. Once these conclusions had been accepted by Mossgas, DKES proceeded to revisit the subsurface data.
The most recent 3D seismic over this area, acquired in 1991, was of good quality down to the top reservoir section, but deteriorated rapidly further down. In conjunction with PGS Reservoir (UK), DKES set about re-processing the whole survey to improve clarity of the fault imaging. A coherence volume was also generated based on measurement of the similarity of adjacent seismic traces. This allowed faults of a much smaller throw to be imaged than would be possible using conventional seismic. The data was also important for optimizing future well locations.
In the southern part of the E-M structure, petrophysics and analysis of appraisal well wireline logs revealed partial erosion of the reservoir sequence. Subsequent biostratigraphic studies of core samples from a well in this area confirmed one of the geological models, and also identified another potential development area in the field.
Development drilling got underway last February, using Pride Foramer's South Seas Driller semisubmersible (following an upgrade in Cape Town). The rig has been contracted on a long-term hire. Last year, it also drilled two exploraton and appraisal (E&A) wells as part of a parallel appraisal of Block 9's future potential. Further E&A well locations are being identified and developed for drilling, following interpretation of a new 800 km, 3D seismic survey commissioned by DKES in the southeast of the block in 1998.
According to John Fleming, the Bredasdorp Alliance E-M Field Development Project Manager, "there are a number of basins in the area. Soekor has several oilfields nearby such as Oribi, Oryx, and Sable. Mossgas, however, is looking solely for gas, and there are quite a few prospects. The area is on a fault line where the Falkland Islands started out."
A Wells Alliance has been assembled for the drilling campaign. Aside from Pride Foramer, this consists of Sperry Sun for directional drilling, Schlumberger for cementing and wireline logging, Baroid (muds and chemicals), Weatherford (running tubulars), Expro for the subsea completions and wireline services, and Dresser Oil Tools for completion equipment.
In the run-up to scheduled first production in April, two wells on E-M and one on E-BF have been drilled. Three locations have been selected for the Phase 2 development wells, and a seventh well may be drilled thereafter - once the production history has been examined. To maximize productivity, wells with horizontal sections up to 1 km long are being drilled through fault compartments.
Formation evaluation logging while drilling was tested successfully for the first development well and is being used on all subsequent wells. Each well will be tested through the completion (rather than through a testing string) in order to provide a truer assessment of future well performance. Having actual wellhead pressure recorded on test should also allow correlation of vertical pressure loss, thereby narrowing the predicted range of initial well deliverability.
There is also a Facilities Alliance for this project which includes Kongsberg/FMC for the horizontal trees and electro-hydraulic subsea control systems. Stolt-Comex Seaway is responsible for installation of the buoy, subsea flowlines, and related equipment (using the Seaway Discovery vessel). SA Five, a local South African company, is responsible for fabrication of pipeline end module and other subsea structures, as well as the 330-ton reception module for the buoy on the F-A platform. This is the company's first offshore-related contract.
Saibos, using the Castoro 8 lay barge, installed the module on F-A and completed installation of the 18-in., 50-km export pipeline and 3-in. piggyback MEG line in December. Offshore installation work was timed to coincide with the more tranquil summer season - this part of the Indian Ocean is subject to strong swells and storms. Lateral tees have also been fitted in the main pipeline to tie in current and future wells.
In view of the need to maintain supplies at 195 MMcf/d minimum, downhole pressure and temperature measurements will be performed throughout the fields' lives, with multiphase flow measurements taken on each well at the surface using Venturi meters. The current reservoir simulation model will be revised as new development well results come in. Some water production is possible later on, so the completions have been designed to allow for a potential water shut-off.
Buoy construction
The control buoy has been fabricated by J.Ray McDermott Middle East in Jebel Ali, UAE. Its total length from the bottom of the lower cone to the top of the radio mast is 52 meters. Dry weight is approximately 300 tons. McDermott was also charged with installing and connecting the various onboard systems and equipment packages including chemical injection, power generation, subsea controls, emergency shutdown system and telecommunications. The completed buoy is due to be delivered to Mossel Bay this month.
Compared with the system for East Spar (Australia), E-M's buoy is more complex in that it is configured to control more wells (up to 10). Another difference is the three-point, 75 mm dia. taut wire mooring system, compared to four for East Spar. "This made it more attractive from an installation and hookup point of view," says Fleming. The buoy will be moored to a 2,700-ton concrete gravity base, built by Civil & Coastal at the Simonstown naval dockyard in Cape Town. DKES and Ocean Resource performed basic design of the cellular-type structure, with Stellenbosch-based Entech handling detailed design.
The buoy consists of a series of stiffened, steel-shell tubular sections with an access tube at the water surface. On top of this is the mast section housing communications antennae, air intake systems, navigation aids and storage tank vents. Operations are controlled via a VHF radio connection to the F-A platform, with a backup Inmarsat satellite communications link.
At the buoy's lower levels are tanks for storing chemicals to be injected for hydrate removal, when necessary during startup. MEG supplied from the platform is the normal inhibitor. Local contractor, Barron Engineering, assembled the MEG regeneration package, supplied by Allen Process Systems. "Kinetic hydrate inhibitor might be a more elegant way of suppressing hydrate formation long term in the larger diameter flowlines," says Fleming. Specialist supplier TROS (Aberdeen), which worked on BP's ETAP project in the UK North Sea, has undertaken a study for E-M.
The bottom deck houses diesel for four 8.8 kW generators, which provide power for the control and chemical injection process. Next level up are the chemical injection pumps, then subsea control hydraulic unit and power pack, and above this level are the generators. The umbilicals used to control the wells extend from the control tower at the top to a termination point at the GBS.
McDermott assembled the various decks in stacks from the bottom upwards, subsequently welding them together. The completed buoy was then rotated to a horizontal position for loadout via cranes onto the Japanese-owned transport carrier. Following installation, a short-period of pre-commissioning ensues - the planned annual F-A platform shut down will also be used to effect final tie-ins from the new facilities.
"We've designed the buoy for a 25-year life in this basin," says Fleming, "and a 100-year storm. There have been a lot of tank tests in Stellenbosch and at HR Wallingford in England to validate computer simulation models.
"Everyone assumes the buoy will move up and down in operation. In fact, as demonstrated by the tank tests, this buoy will only move backwards and forwards, all the time remaining in a vertical position." Twice-yearly routine maintenance visits are anticipated, mainly for chemical storage refueling. These would involve up to four operations/maintenance personnel. Otherwise, the installation remains unmanned. Subsea well intervention, although not planned, should not be problematic - the vessel can be positioned safely away from the buoy, above the wells.
According to a paper given last year at the Offshore Europe Conference in Aberdeen by the project team "reservoir management of these new fields will be strongly influenced by the future performance of the existing fields. Numerous options exist to manage production once spare supply becomes available from the E-M area. These include the potential use of the F-A platforms wells as swing producers, the ability to operate under combined free-flowing versus compression when flowing from the E-M pipeline, and a well prioritization scheme that will maximize condensate yield whilst maintaining a refinery security of supply for as long as possible."
