Platform designers and fabricators in The Netherlands weathered the recent recession better than most. The Dutch sector operators have long-term supply commitments to Gasunie, and cannot afford to let developments stagnate. (Below) Pipe installation trials on P6 employed floating delta wing clamping units.
For many years, Elf Petroland has been one of the two major gas producers offshore The Netherlands. Its annual operated gas production is a fairly constant 8 bcm. Between 1996-99, the company averaged six to seven new wells per year in the Dutch North Sea. No new wells are planned this year, however, due to difficulties with rig planning and problems in identifying suitable prospects.
Of late, Elf Petroland has had most success in its core development areas, managing four discoveries last year in blocks K4a, K4b, K5a and F15a. Outside its core areas, the company has made little headway. A dry well on F10, for instance, led Elf to relinquish the acreage, and it has not acquired any new blocks over the past year. This is partly because interesting opportunities on the shelf are getting harder to come by, in Elf's view.
While oil prices tumbled, Elf focused on lower risk "economy" wells close to production centers. Increasingly, its drilling campaigns have also coincided with periods of spare capacity in the Dutch North Sea trunklines (Elf has a 3% share of the Westgastransport line, 15% in the WGT extension and 15% in the Noordgastransport line). This increases the chances of any discovery being fast tracked for development.
Some of Elf Petroland's recent finds have been developed within a month. Some have come via deviated wells drilled from production platforms, but as these types of wells are more expensive to drill, the probability of a discovery must be high. However, Elf is usually confident in this regard, having made so many discoveries over the years in its core Rotliegendes plays. The 96% success rate has also been sustained through use of analytical techniques such as pre-stacked depth migration.
To maximize well productivity and minimize development costs, Elf will routinely employ well fracturing of horizontal drainage sections. Repetitive practice is less applicable in the Carboniferous, where the well design process is usually longer, due to the more complex geological plays.
Among the company's more recent discoveries was K/5-11, which was completed in April 1999. According to Wood Mackenzie, this tested 26.5 MMcf/d in the north-east portion of the K5a block. It has since been renamed K/5-Fe, and could be developed via a small wellhead platform.
An HSM-built wellhead platform is being installed this summer on K4B, discovered in 1996. Gas will be sent for treatment on the K5P platform via the K4A facilities. Elf may also by now have sanctioned development of the K/1-A Field, via a first-stage separation platform exporting gas to Lasmo's Markham processing complex on the Dutch/UK median line. This platform will likely be located in the center of the K/1-A Field, which was discovered in 1997 in lower Permian, Rotliegendes sandstone. According to Wood Mackenzie, test results suggested the reservoir could produce at more than 100 MMcf/d. The field could be onstream by end-2001.
An emerging core area for Elf is just to the north of L4a, where a wellhead platform (L4-PN), also built by HSM, was installed by Seaway Heavy Lifting last summer. By end-October 2000, four satellite fields drilled via single, deviated wells from the platform should be collectively producing 60 MMcfd. A fifth discovery, L/4-G, could also be linked in late next year. From the platform, the gas is piped to Elf's central processing complex in L/7 before feeding into the NGT system. Cost of this ongoing development is estimated at DFl 200 million with remaining recoverable reserves in the range of 5 bcm.
Another new project for Elf involves addition of a new compression module on its F15a platform, to boost production capacity by 2-4 MMcm/d. This should be in service by end-August. The module was designed by Thermodyn and constructed at Mercon's yard in Gorinchem.
Like other Southern Gas Basin operators, Elf has considered duplicating platform designs to lower costs, but concluded that savings would be negligible, given varying production scenarios from field to field. However, it is looking at platforms designed with greater emphasis on environmental features. The company's only subsea well is produced through the Markham complex, but it may develop the L4-G and K5F fields as subsea tiebacks to its own facilities.
One of this year's biggest discoveries in the Dutch sector was made by an operator anxious to exit altogether. It came on block K/12, where seven fields have been developed since the initial K/12-2 discovery well in 1975. Over the intervening period, operatorship has passed from Placid to Occidental and finally to TransCanada Pipelines in 1998.
Last year, TransCanada announced its intent to withdraw from all non-Canadian operations. Drilling a new discovery - K/12-13 - seems to defy logic, likewise the company's recent acquisition of ARCO's 23% share of block K/12. On the other hand, both developments may make the asset easier to sell.
K/12 was developed initially via small wellhead platforms exporting their gas through the NGT system. Three more fields were brought onstream between 1991-1995, bringing total reserves at that stage to 620 bcf. But that figure is thought to have dwindled to around 44 bcf.
Well K/12-13, spudded this January by the Noble Piet van Ede jackup, was drilled in the central part of the block, 7 km southwest of the main K/12-C processing platform. According to Wood Mackenzie, the structure looks to hold 200 bcf - four times the anticipated amount - and there may be two further compartments that could double that total.
Fast-track development looks probable through a dedicated wellhead platform, with first gas achievable in 2002. This should also extend the K/12 facilities' productive life way beyond the predicted shutdown in 2005. That in turn will strengthen TransCanada's hand when sale time approaches.
One of the Dutch sector's most consistent drillers is Clyde Petroleum Exploratie. Over the past three years it has drilled seven exploration wells, four of which have yielded commercial discoveries.
According to General Manager John LeGrow, "we were able to maintain our drilling effort, even when oil prices were low, partly because we're smaller than some of the other North Sea operators. That means we can do certain things at lower cost. While we look for and have made larger discoveries, we are also interested in sub-30 bcf prospects because we can develop them commercially if drilled from our platforms."
Recent Clyde-operated discoveries include the inshore Middelie Zee-1 well situated 4 km southeast of the Q/8 producing field, and P6-9, situated 4.5 km northwest of the producing P6-8 gasfield. This well tested 54 MMcf/d in total from two reservoirs and will likely be brought onstream next year as a subsea or satellite platform tieback to the P/6 facilities.
Clyde was formerly a UK-based independent, which entered The Netherlands in the 1980s. During the 1990s, it achieved growth through buying BP and Mobil's Dutch assets, and also brought onstream the P/2 and P/6 offshore developments as operator. In 1997, Clyde was itself acquired by Gulf Canada Resources.
"Pre-Gulf, Clyde was very successful in the North Sea," LeGrow says, "but its strategy was acquisition, development, and exploration - in that order. It may have averaged one exploration well per year. When Gulf came in, we established a mission statement to become one of the southern North Sea's pre-eminent gas producers and to put more emphasis on exploration."
The attractions of the package from Gulf's perspective were a sizeable inventory of gasfield prospects, plus interests in various Dutch sector trunklines, all with ullage. The new team decided to focus on increasing exploration and optimizing existing production (from the P-block fields plus Q8, also operated by Clyde).
In 1998, Clyde also moved into oil production when it bought Conoco's 100% interest in the declining Kotter and Logger fields. Both lie south of the main Rotliegendes gas production fairway in blocks K/18b and L/16a, and were brought onstream through platforms in the mid-1980s. Both were slated to shut down early in 1998, but Clyde has managed to more than offset the historical annual decline of 20% and eke out to date a further 2.5 million bbl through measures such as water flood optimization and installation of larger submersible pumps. "We also looked for opportunities to reduce operating costs and focused on pump optimization to maximize the production and run life of the existing pumps," adds LeGrow. Clyde is now scouring the area for oil and gas exploration opportunities that could be developed through these platforms.
Gas production at Clyde's onshore complex at Waalwijk was also raised through well fracturing. "We have increased our emphasis on the use of subsurface techniques to optimize reservoir production," LeGrow says. At Waalwijk, this has resulted in the 50 MMcf/d plant being once again full some eight years after it was put on line. We have also reduced Clyde's Dutch sector operating costs by 15% through continuing to do things more efficiently, including improvements to our purchasing contracts."
Clyde has more than 20 exploration licenses across the Dutch shelf, and is on the lookout for more blocks, particularly ones close to existing infrastructure. One area under scrutiny is the median line with the UK North Sea, where there are several substantial gas discoveries pending development. Last year, Clyde also gained operatorship of block 53/8 in an unexplored region on the UK side of the line.
Most of Clyde's Dutch gas production comes from Rotliegendes-Bunter formations in the P and Q quadrants. In Q4 block, it is preparing to install a refurbished wellhead platform to develop two recent discoveries. After unsuccessful campaigns by three previous operators between 1968-89, Clyde hit the target immediately with the Q4-8 well, drilled on the eastern boundary of Q4 block in summer 1998. This tested up to 27 MMcf/d. Q4/9, completed a year later, flowed 54 MMcf/d combined from two separate zones at a location 6 km northwest of Q4/8.
Under a phased development, the second discovery, named Q/4-A, should be brought onstream this December with the gas being piped to Clyde's P6 processing platform through a new 35 km, 14-in. line to be installed by Allseas. Q/4-B (the 1998 find) should follow next year or the year after.
The Q/4 platform was installed originally in 1983. Clyde and its license partners Dyas and Clam have commissioned new processing facilities for the deck, as well as adding some steelwork for reinforcement. This work is being handled by Genius Vos in Ijmuiden. The jacket has had to be modified for the 28-meter water depth, which is 5 meters shallower than at its original location. The platform has also been recertified for the anticipated 15-20 years extra in service on Q/4. Seaway Heavy Lifting's Stanislaw Yudin should be on site currently, installing the platform. The jackup Noble Lynda Bosler is contracted for development drilling later this year.
Clyde took this novel approach to development because of the cost, time, and environmental benefits compared to a new platform built entirely from scratch. If the project is a success, Clyde may use a similar concept by relocating the P/6-S platform (due to cease production shortly) over the suspended P/6-9 discovery well.
Clyde is also examining re-use of submarine pipelines. Under a project supported by European Community funding, it recently performed trials on a 350-meter section of unused 12-in. pipe on its P6 Field. The method tested involves attaching floating delta wing clamping units to the pipe, allowing the depth which it is transported to be controlled through increasing or decreasing the tow speed. Increasing it generates extra lift force through the wings, making the pipeline rise to the surface. Decreasing it causes the pipeline to sink to the seabed.
For the trials, eight wing clamp units were attached to the pipe at pre-calculated distances. Increasing the towing force in controlled stages caused lift-off of the pipe from the seabed at a pre-determined tow speed of six knots, until it surfaced above the water surface. Towing operations continued for a further six hours. Clyde is now ready to consider this concept for future development plans, but has yet to identify a suitable application.
According to LeGrow, "one of the keys to developing smaller fields economically is to reduce the time to first gas. The challenge is to balance this against moving too quickly and making inappropriate decisions. I believe we are well on our way to reaching our goal of at least doubling our Dutch sector gas production in the next three years as a result of the exploitation and exploration success we have had and the shorter development times we can achieve through being innovative."
The Hanze GBS was recently towed to the field location by Smit Maritime Contractors from Rotterdam.
Germany's Veba Oil is another independent hitherto small in upstream terms, which is building a reserves base in the North Sea. Hanze, 200 km offshore Den Helder in block F/2, is its first operated development in the Dutch sector. Veba became operator in 1998 when it bought RWE-DEA's controlling interest in the field.
Hanze is a rare Dutch oilfield project, located on the same fairway as BP Amoco's F/3-FB. It was discovered in 1996 through the F2/5 well, which encountered oil within an overpressured Danian and Maastrichtian chalk reservoir. An initially buoyant reserve assessment was later downgraded to 34 million bbl, plus 40 bcf of associated gas.
The field is being developed with nine wells (initially two producers and two water injectors), using an 8,100 ton production platform and gravity base derived from Doris Engineering's Sepat concept. The integrated production deck, built by Hyundai in Ulsan, includes facilities for first and second stage separation, oil stabilization, oil cooling, gas handling and power generation, in addition to accommodation for a crew of 25.
Water injection is required from startup. Water displaced from the subsea storage tank will be treated, mixed with water and then re-injected into the reservoir. At 60% water cut, gaslift will also be deployed. Oil will be produced at up to 5,000 cu m/d, gas at 500,000 cu m/d, with water injected at up to 9,000 cu m/d.
Processed oil will be stored in the 15,600-ton GBS, which has a capacity of 150,000 bbl. It comprises a steel tank and a framed tubular structure - an additional structure housing the nine conductors is attached to one of the main unit's frames. Oil will be offloaded by shuttle tanker to a nearby single point mooring. Gas will be exported to Den Helder via the NOGAT trunkline.
Doris provided conceptual engineering of the platform, plus detailed engineering of the deck and the GBS. It also established procedures for the marine operations. Smit Maritime Contractors began the towout of the GBS from Rotterdam last month. The 14-meter high structure was towed by three tugs to its location, where it was due to be temporarily suspended via a four-leg, pre-installed mooring system.
Around 31,000 tons of solid ballast were needed to reduce its center of gravity height to the stability required for the final installation, in 43 meters water depth. Boskalis is dredging a 2-meter-deep pit on the seabed site to take the base of the GBS. The ballast tanks will then be filled gradually, in a pre-determined sequence, to lower it into the pit. The GBS' underside features a steel skirt, which will penetrate the pit floor. Stability of the foundation will then be increased by filling the void between the GBS under-base and the floor with grout - this should also create uniform pressure distribution. Finally, the temporary mooring system will be removed, with Boskalis adding a scour-protection rock layer by means of a fall-pipe vessel.