Daniel Picard
Total Oil Marine plc
Aberdeen, Scotland
The North Sea Dunbar platform is due to begin production at the Tend of this year for field operator Total Oil Marine plc. First output will arrive in time to offset the production turndown from Dunbar's host platform, Alwyn North.
Dunbar is the kind of second phase development that has enabled the North Sea to remain viable in the face of competition from the new frontiers. To make the project a success, we have had to decide how to set about exploiting a highly fractured reservoir, in deep water, profitably, with a declining market price for the product.
The Dunbar reservoir, centered on Block 3/14a, was originally known as Alwyn Southwest.
The reservoir was actually discovered in 1973 in the Statfjord oil-bearing formation.
A more commercially attractive discovery at Alwyn North on Block 3/9a delayed any serious attempt to develop the field until after Alwyn North came on stream in 1987.
Alwyn South area as a whole comprises three geologically separate accumulations, with combined reserves estimated at 134 million bbl of oil and condensate, with a further 26 billion cu m of gas.
Reserves of this magnitude put Alwyn South towards the upper end of the marginal field range, but the real challenge lay in the complexity of the reservoir structure combined with a water depth of 145 m.
Initial reservoir studies identified that Dunbar would require at least 16 production wells, with a further six injection wells for either water or miscible gas.
A requirement for an additional two to seven wells to be drilled in at least two phases was also identified at Alwyn Southeast. These reservoirs became known as Ellon and Grant fields, in Blocks 3/15 and 3/14a respectively.
CONCEPT SELECTION
Several early production systems were considered before a full scale development study began. The first important decision was whether to develop Dunbar independently from Alwyn North or as a satellite.
Ellon and Grant were deemed too small to develop as anything other than subsea completions, but Dunbar is of a different order of magnitude.
A number of options were considered for the development of Dunbar as a stand-alone facility, including a floating production unit and a full process/utilities/quarters platform with subsea satellites.
In every case, however, the combined estimate of capital expenditure and operational expenditure was too high for the estimated return. Therefore, the stand-alone concept was abandoned, and work began in earnest to develop both areas as satellites of Alwyn North.
Fortunately, Alwyn North had been designed with spare risers and J-tubes, with future field extensions in mind. Furthermore, with operations reduced to production and workover only, there was a surplus of power and injection water available, sufficient to service a satellite of the size contemplated.
There was also a concerted effort to develop Dunbar, together with Ellon and Grant, as a subsea complex despite the lack of experience in the industry for large scale developments of this type.
To compound matters, contemporary studies indicated that a subsea approach would only be economically advantageous if the number of wells was kept below 24.
When enhanced reservoir definition became available, the estimated number of wells required for Dunbar narrowed into a band above the 24 well limit, pushing the development preference towards a platform concept.
The final factor leading the development away from the subsea route was the high pressure and composition of well fluids which, combined with the seabed geometry along the 21 km export route, posed problems with slugging and hydrate formation across a range of flowing conditions.
These problems would have been extremely difficult to solve in a subsea development and have represented a challenge even in the final platform scheme.
PLATFORM CHOICE
With a water depth of 145 m the options for development, other than a conventional fixed platform, were extremely limited. There was one option, however, that elicited a considerable amount of interest--the TPG 500 jack up concept of Technip Geoproduction SA, Paris.
The Technip concept was attractive but contained a number of technical areas that required further investigation, such as the pod structures required to achieve stability in the deep water.
With the extremely short schedule imposed for Dunbar, there was insufficient time to fully engineer the problems related to the latching and locking systems or the docking system required to mate the platform with the existing subsea template. This led to the abandonment of the scheme for Dunbar, although it has been successfully adapted for use on the BP Operating Co. Ltd. Harding field.
Finally, the development options were reduced to a conventional fixed platform with the target of trying to reduce manning to an absolute minimum or, if achievable, a not normally manned platform.
One obvious option, with the aim of reducing permanent on-site facilities and thereby maintenance and manning requirements, was tender assisted drilling (TAD).
Under normal circumstances the cost advantages of TAD over a full drilling platform diminish at 15-16 wells. Therefore, Dunbar, with a minimum of 22 wells, should have been more cost effective as a full drilling platform.
However, five of the Dunbar wells were scheduled to be predrilled, which, allied to the very competitive conditions in the current rig market, helped to make TAD more cost-efficient than full drilling facilities.
This cost-efficiency, even in the development drilling phase, is more pronounced over the full production lifetime because it provides for a significant reduction in on-site accommodation, thereby reducing both capital and operating expenditure.
MINIMUM FACILITIES
As Dunbar was being developed as a minimum facilities satellite to Alwyn North, maximum use had to be made of available host platform facilities, particularly Alwyn North's extensive processing and export capabilities.
Alwyn North relies on diphasic export of the combined platform oil and subsea gas well fluids, a technique for which Total has a worldwide portfolio of experience. Platform processing equipment is thereby reduced to test separation and chemical injection only.
Power generation, typically a high cost, high maintenance aspect of any platform development, is a commodity which Alwyn North has in abundance. A surplus of power was available following the completion of its development drilling activities.
By exporting power to Dunbar via independent submarine cables, two of Dunbar's requirements were simultaneously satisfied: the provision of electric power, with minimum facility and maintenance implications, and enhanced safety in having two independent, high integrity, and remote power sources.
Similarly, the water treatment and injection facilities on Alwyn North are more than capable of supplying sufficient throughput to satisfy the requirements of both fields. A single 10 in. line is sufficient to route enough injection water to service the Dunbar wells at the required pressure, with only local manifolding required.
Nevertheless, despite minimization of platform facilities, the reduction in maintenance, operation, and well activity man-hours was insufficient to achieve not normally manned platform status.
Even by absorbing as much planned maintenance as possible into an annual maintenance campaign, utilizing a flotel, the resulting figure was always outside the maximum permitted by the regulations in force or proposed in 1990.
However, by utilizing multidiscipline technicians, by operating a vigorous control of the platform complexity, and by specifying low maintenance equipment, the total number of permanent operating crew was reduced to 16.
The crew will be accommodated in an integrated living quarters with 13 two-man cabins, leaving a small surplus to cater for support crew holdovers and visitors.
TECHNICAL INNOVATION
Three technical innovations have proved particularly important for development of Dunbar field.
The technique adopted to cater for well allocation metering was just one of the many new ideas developed during the Dunbar design phase. With diphasic export already one of the key features of the Dunbar design, allocation metering was the best method of assessing for tax purposes the production from the different licensing blocks.
Production from each of the Dunbar, Ellon, and Grant reservoirs will be periodically passed through a test separator. Oil, gas, and water products will then be measured using coriolis meters.
Well allocation metering will also be performed on Alwyn North, which, together with fiscal metering of the combined exported products, fully satisfies the requirements of the revenue authorities.
Another of the innovative aspects of the Dunbar design is the introduction of fiber optic control links into the subsea power cables. These links enable the process control system designed for Dunbar to be integrated into the existing system on Alwyn North, permitting full remote control of production.
One of the major concerns when transporting mixtures of oil, gas, and water is the risk of hydrate formation when the product temperature falls below a certain limit.
The method selected to overcome this problem, after feasibility studies initiated by Total, was a double wall insulated pipeline patented by ITP Interpipe, Paris. The pipeline from Dunbar to Alwyn North comprises a 16 in. diameter line contained within a 20 in. diameter line.
This design, allied to the use of an insulation medium contained between the two pipe "skins," is intended to reduce conduction heat loss to a quarter of the value of a conventionally insulated pipe. A unique jointing system has also been developed to enable the pipeline to be deployed from a conventional lay barge, the first time this has been attempted.
LIFTED JACKET
The minimum-facilities approach kept weight of the Dunbar topsides low enough to allow a lifted-jacket installation.
Other than Veslefrikk field in 174 m of water offshore Norway, Dunbar will be the deepest development in which a lifted jacket has been attempted for a drilling/production platform. Much of the technical innovation employed on the Dunbar jacket went towards fulfilling this aim.
Use of high strength steel castings for the major nodes and of a diamond bracing scheme rather than conventional K-bracing brought overall weight of the jacket to within a small margin of the maximum capacities of the existing heavy lift vessels, the M7000 or the DB102. But further weight-saving was required before the lifting concept could be guaranteed.
The poor surface soil quality in the Dunbar field would normally have necessitated large and therefore heavy mud mats. The concept of temporarily supporting the jacket on preinstalled underleg piles, used only once before, offered a valuable alternative.
By modifying the existing frame to suit the different Dunbar leg spacing, and using a new subframe to locate over the guide posts on the subsea template, the lifted jacket concept was finally proven. The underleg piles were driven during the spring of 1993.
SAFETY
Dunbar will be one of the safest manned platforms in the North Sea because of a combination of a reduced number of operators; two independent, high-integrity, remote power sources feeding submersed electric firewater pumps (a further two diesel pumps as back-up); two free fall lifeboats; and a platform configuration which segregates the temporary refuge from the hazardous zones by fire and blast rated walls and decks with utility areas forming a physical buffer zone.
In addition to the main safety features, Dunbar provides totally enclosed evacuation tunnels, offering direct escape from the temporary refuge into the lifeboats and, in the event that operators are trapped at the hazardous end of the platform, a rapid deployment seascape device giving direct escape to sea via an evacuation chute to a tethered life raft.
A safe, fit-for-purpose but cost-effective design was the route taken to bring the resources from Dunbar, Ellon, and Grant into production in time to extend the life of the overall Alwyn complex. Many of the techniques employed have been at the forefront of technology and, while sound, will need to be refined in actual operation.
One example is the problem of slugging--formation of liquid "slugs" in the infield lines--and its effect on the Alwyn North process equipment. Total has developed a solution, based on the results of dynamic simulation, which requires the use of a dedicated control system to monitor and control slugs and the gas surges which follow.
The performance of the system, which incorporates a subsea pressure transmitter, will be closely monitored and optimized offshore to measure and maintain its effectiveness under actual operating conditions.
Both the jacket and the integrated deck were successfully loaded out in May of this year. The jacket was installed offshore on June 18 with the deck scheduled to sail away on June 20. By the end of June the platform was in place and ready for hook-up.
With the very high level of completion and commissioning carried out onshore, the hook-up is anticipated to take less than 200,000 man-hr. This means that the 700 million ($1.05 billion) Dunbar development is not only on schedule but has a good chance of beating it.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
