A project to determine how concrete platforms can be disposed of onshore is being undertaken by Dr. techn. Olav Olsen a.s. In an earlier phase, the Oslo-based consultant engineer confirmed that these massive structures can safely be refloated and brought back to shore.
With 14 large concrete gravity-based structures (GBS) offshore, Norway is the home of the concrete platform. The majority were built in the 1970s and 1980s by Norwegian Contractors. Olav Olsen was the main designer for NC, and as such, was closely involved in the development of the Condeep, the dominant design of this type of platform. Condeep GBS units can be found on the Frigg, Statfjord, Gullfaks, Oseberg, Sleipner, Draugen, and Troll fields.
An important moment came in 1978, when the Norwegian Petroleum Directorate (NPD) stipulated that all concrete platforms should thenceforth be removable, says Kolbj rn H yland, technical manager for technology and business development at Olav Olsen.
In recent years, however, doubts have been expressed about the safety of removing concrete platforms. These relate mainly to the ability to deballast the base in a controlled fashion, especially as the vacuum between the base and seabed is released. While the earlier platforms have short skirts penetrating the seabed, the platforms from Gullfaks C onwards have deep skirt piles round the base which sink into the seabed on installation to reach stronger soil layers.
Skepticism expressed in recent years about the safe refloating of concrete platforms is also reflected in the rulings of the Oslo-Paris (Ospar) Commission. When it met in Sintra, Portugal last year, the commission decided that where concrete platforms were concerned, there should be an option for leaving them in place.
The NPD thought the issue should be clarified, and under a joint industry project, Olav Olsen was commissioned to study the refloating of the Gullfaks C platform. This structure would be among the most difficult cases, having a 240,000 cu meter base and concrete skirts 22 meters deep.
The outcome of the study was that, from a technical and a safety point of view, refloating of the platform was viable, H yland says. Control over the process of release from the seabed is achieved by injecting water within the skirt components while reducing the volume of water in the cells and shafts to increase buoyancy. The operation can be halted at any time.
In the case of some of the platforms, though not Gullfaks C, the piping, valves, and pumps through which water would be injected under the base have not been maintained, but it would be possible to restore these systems.
Although Olav Olsen's brief did not include costing such an operation, it is clear it would be expensive, H yland says. However, the cost must be seen in the context of the alternatives. The Ospar commission ruled that the topsides must be brought to shore anyway. The topsides of some of these platforms are truly enormous, some of them weighing around 50,000 tons.
Moreover, the topsides of all but the earliest platforms were assembled onshore and mated with their bases as single units - a cost-saving feature which was one of the major attractions in building the platforms this way.
The technology does not exist for removing the topsides as single units at sea, and the work of disassembling them for removal in a number of units would be an immense task, in some cases perhaps taking several years and posing high levels of risk, H yland says. A study of the Draugen platform concluded there would be no significant cost difference between removing the topsides offshore or floating the whole structure back to land and then removing the topsides. The same is likely to be true of other platforms.
The new project, which is due to be completed by the end of the year, tackles the question of what is to be done with the concrete giants once they have been brought to shore. It involves making a thorough study of all aspects of demolition and disposal, examining the applicability of available demolition techniques such as sawing, crushing and blasting, and the logistics of running a demolition operation, including the transport of demolished concrete.
It will assess the environmental impact in terms of discharges to sea and land, emissions to the atmosphere, energy consumption, waste management and aesthetic concerns, and assess the risk parameters associated with the various demolition methods and how they may be protected against. The cost and time-efficiency of the various methods will be evaluated and cost and time estimates prepared for the most promising.
The project will also assess the potential for recycling demolished concrete, evaluate the processes involved in recycling, study how materials can be transported, and perform a marketing and economic analysis.
In some respects, the market outlook is promising, H yland says. There is a shortage of materials such as aggregates in some European countries, and increasing environmental restrictions on removing virgin deposits of sand and other materials for concrete enhance the attractions of recycling.;
Cord aiming to tighten noose on offshore operations spending
A campaign to tackle operating costs is gathering momentum in Norway in the shape of the Coor dinated Production, Operation and Maintenance Offshore - Research & Development (Cord) movement.
"We need new technology to meet challenges such as increasing water volumes, falling oil production and ageing facilities," says Ernst W M Hansen, head of the Cord Secretariat and Senior Research Scientist at Sintef Energy Research. "Moreover, while most fields are economic at an oil price of $13-14 a bbl, we want to see what we can do if prices drop even below $10."
The initiative for Cord came from the research sector but has found ready acceptance elsewhere in Norway's oil industry. Seven operating companies - BP Amoco, Elf, Esso, Norsk Hydro, Phillips, Saga, and Statoil - are helping to fund the movement, and have their production directors on the board.
The government has also welcomed Cord, and the Oil and Energy Ministry and Norwegian Petroleum Directorate have one representative each on its board. So does the Research Council of Norway, which provides funds and now owns Cord. Suppliers have been a little slower off the mark, but are beginning to join up.
The economic potential of tackling production, operations, and maintenance (POM) costs should not be underestimated, Hansen says - Norway currently spends approximately NKr 3 billion a year on these activities, and over the period 1995-2020, it has been estimated that such spending will total NKr 750 billion. Cord's aim is to save NKr 3 billion a year - about 10%.
Traditionally, it is the more glamorous activity of field development which has attracted the funds for technology development. When the industry first joined forces in the Norsok campaign in the early 1990s, it was to focus on improvement in field development performance. Cord has as worthy an aim, even if the industry has taken longer to recognize it.
"There's a lot to be earned from optimizing existing fields," says Hansen. "It's worth asking whether this may not be a better investment than the development of small or frontier fields." The movement will be looking to secure its share of the NKr 100 million which the government is to make available for offshore technology development this year.
The movement aims to take an overview of the sector's POM needs, identify the areas where research and development efforts can be directed with most profit, and help to get projects off the ground. A clear idea of the direction of the technology drive should emerge this month as a mapping and technology gap analysis group is due to present its report.
Meanwhile, two functional groups have also been set up to review how problems in specific areas can be tackled. One, focusing on the issue of unwanted components in production streams and equipment - such as scale, hydrates, and sand - was also due to report around mid year.
A second on energy optimization is about to start work. More information is available at www.energy.sintef.no on the Cord website.;
Åsgard becomes test site for composite methanol line
NAT Compipe has completed the world's first delivery of spoolable composite pipe. The order, involving a total of 14.6 km of 3-in pipe for methanol injection, is for Statoil's Åsgard Field.
Statoil had originally intended to use coiled steel tubing, but when the product failed on qualification tests, it turned to NAT Compipe. The supplier was able to respond rapidly, making delivery in May within three months of the order being placed, says Business Development
Director Rolf Jemne. The pipe, consisting of two lengths of 8.1 km and 6.5 km, is due to be installed by Stolt Comex Seaway's Seaway Eagle this summer.
NAT Compipe's manufacturing plant is at Tau near Stavanger. The service line pipe the company has developed consists of an internal liner made of cross-linked polyethylene, around which is wound an epoxy matrix reinforced with glass. Other products under development, such as flowlines, consist of carbon, aramid and hybrid fibers.
The liner is extruded, reeled, and cured at high temperature, a process which facilitates the cross-binding and enhances its resistance to gas permeability. It is then reeled off and put through a conditioning oven to remove its ovality.
The composite laminate is applied to the liner by a continuous filament winding method as it passes through a series of 10 winding stations with 60 bobbins each. An outer layer, of glass in the case of the service line, is added. The line is then cured at temperatures of up to 160°C and wound onto a reel ready for delivery. The plant can turn out about 500 meters of composite pipe a day, says Jemne.
NAT Compipe's composite pipe technology has been 10 years in development, the work being supported at different times by companies such as Conoco, Amoco, Elf, Enterprise, Statoil, and Saga. For Jemne, the Åsgard order represents the final breakthrough into commerciality.
"It shows we're competitive with carbon steel and for stainless steel and flexible pipelines. The cost is a fraction of the price for the same pressure," he says. "Composite pipe doesn't need coating, there is no need for anodes, it won't corrode, it's not affected by methanol, and it has a 20-year design life. It has a big advantage in sour service, as it's not affected by the aggressive elements which are fatal to steel."
Composite pipe weighs only about 40% of an equivalent steel pipe and has far superior fatigue qualities - a fatigue capacity about nine times higher than that of super duplex steel, tests have shown. These are properties which are inherently of benefit as offshore activities move into ever deeper waters, an area which NAT Compipe now has in its sights.
With partial support from the European Union's Thermie program, the company is currently involved in qualifying composite flowlines of 4-in and 10-in diameters for hydrocarbon and injection water transport, and expects to have these products available for the market in the course of 2000.;
Brent Spar disposal project nears successful completion
The disposal of Shell's Brent Spar, the world's most famous oil storage tank, reached an important milestone in July, when three sections of the hull were due to be installed as the foundations of a deepwater quay at Mekjarvik near Stavanger.
The job of transforming the Spar from an environmental problem to a public asset was entrusted to the Wood-GMC joint venture, whose proposal triumphed over several hundred others submitted to Shell after its original plan to dump the troublesome structure in the deep ocean was called off in the face of mounting public opposition triggered by a Greenpeace campaign.
Cutting of the hull took place in the Yrke Fjord using a lifting cradle installed at one end of the world's largest flat-top barge, Heerema's H851. Marine operations, including the placing of the hull in the cradle, were performed by Neptun.
Altogether, the hull has been sliced into five sections. The topmost section, 23 meters high, 17 meters in diameter, and weighing 1,000 tons, contained a lot of equipment, some of it in good enough condition to be re-used. The equipment was brought to shore for dismantling and recycling instead of being made part of the quay.
The remaining four sections are each 22 meters high and 29 meters in diameter. The three mid-sections weigh 1,110-1,775 tons. The bottom section, which contains 6,200 tons of iron ore ballast and weighs a total 7,528 tons, was towed to Mekjarvik and ballasted into position at the quay site in late June. The remaining sections were to be lifted into position by Heerema's crane-barge Thialf, which was also used for the removal of the 1,690-ton topsides last November.
One of the biggest challenges faced before the hull could be dismantled was the disposal of 50,000 cu meters of contaminated water in the tanks, according to Wood-GMC. This was treated with Zydox, an enzyme-stabilized aqueous solution of chlorine dioxide product supplied by Norwegian company Zychem Technology to remove hydrogen sulfide. According to Shell, the chemical reaction process restored the water to a chemistry close to that of the original configuration of seawater. The water was discharged to the sea after passing through a filtration process to further reduce the low level of hydrocarbons.
Onshore disposal of the topsides and upper hull section is being carried out by Norsk Metallretur Offshore Recycling at its facility at Vikaneset in western Norway. Asbestos materials were disposed of at a licensed landfill site, a total of some 1,700 tons of steel is being recycled.;
Concrete U-shaped vessel single-lifts platforms
A new single-lift unit for removing topsides and jackets offshore has been presented by Dr. techn. Olav Olsen. The MPU (multipurpose unit) Heavy Lifter is distinguished from the various other removal vessel designs floating around the abandonment market by its use of concrete technology.
The vessel is U-shaped, and built of lightweight aggregate concrete. It has two columns on either side, one fore and one aft, which are connected by pontoons along either side and at the stern. Steel lifting frames installed on either side bear the topsides. For jacket removal, a beam system is installed on the MPU to which the jacket is attached. The concept was developed under a joint industry project supported by the Research Council of Norway.
"The MPU is tough, rigid, durable and simple," says Kolbjørn Høyland, Olav Olsen's technical manager for technology and business development. "Our main aim has been simplicity of construction and of operation."
An array of patented solutions has been developed for accurate positioning and load transfer both onto and off the vessel. The concept and the patents have been vested in MPU Enterprise, whose owners, in addition to Olav Olsen, include other companies and individuals with offshore expertise.
For a topside removal operation, the MPU ballasts down while positioning itself under the topsides. When ready to take the weight of the topsides, it deballasts up and the top of the lifting frames fit into hooks installed under the deck. Rapid deballasting is achieved by a flushing system.
The vessel's lifting capacity is a function of the freeboard and center of gravity of the topsides or jacket. It can typically lift a 12,000-ton topsides with a freeboard of 25 meters. As the freeboard is reduced, its capacity rises.
The MPU has a total weight of 36,000 tons, and is 88.6 meters long, 96 meters wide, and 40 meters high. It has a relatively deep draft, which, combined with a rim around the base of each column, helps to give it very good motion characteristics, says H yland. In a significant wave height of 3 meters, it has a heave amplitude of only 60 cm, calculations show.
The construction cost is estimated to be NKr500-600 million, putting it on the low side compared with some of its rivals. "We can expect the vessel to spend a lot of time idle, so we wanted to make it relatively cheap," says H yland. The cost is divided equally between the hull structure and the equipment. The vessel has no propulsion, but will use a spread of probably four tugs to position it horizontally.
MPU Enterprise has floated its concept around the oil companies with upcoming abandonment programs and submitted proposals for platform specific studies to companies such as Phillips and Elf. "We will cooperate with Aker Offshore Partner (AOP) on such studies," says H yland.
"We will take care of the lifting and transport, and AOP will provide the offshore preparation and the onshore solution."
In parallel with the specific studies which it expects to materialize later this year, MPU Enterprise will develop further documentation for the concept and perhaps perform model tests. This will keep it on schedule to meet the target dates for invitations to participate in the design competition phases for proposed removal programmes in the North Sea. "At present we aren't planning to go ahead and build the MPU without either a contract or a firm expression of intent to give us one," says H yland.;
First Norwegian LNG development scheduled for 2005
Plans for developing the Snøhvit Field in Norway's Barents Sea are moving forward, though paradoxically, the tentative start-up date has been moved back a year to 2005. The decision to push back startup was taken as potential buyers of Sn hvit gas in the US and around the Mediterranean say they are unlikely to need it before the new date, Statoil says.
Meanwhile, an important step forward has been taken with the resolution of the operatorship issue. Statoil, which was already operator on five of the two licenses in the so-called Troms Patch, has now acquired the operatorship of the remaining two, following an asset swap with Norsk Hydro.
Statoil says it now has an overall interest in the area of 35%, followed by Total Fina with 17%, and Hydro with 10%. Other licensees are Amerada Hess, RWE-DEA, and Svenska Petroleum.
In addition to Snøhvit, the Tromsø Patch also includes the Askeladd and Aladdin fields. Together, the three fields provide a substantial gas resource base with estimated recoverable reserves of 163.5 bcm, according to the Norwegian Petroleum Directorate. Sn hvit will likely be not only the first field to be developed in the Norwegian Barents, but, as it is so far from potential markets, the first in northwest Europe to export gas in liquified form.
Environmental considerations rank high for a production project in such an ecologically sensitive region, but in public consultations, Statoil has been able to satisfy the concerns of most interested bodies. In addition to the problem of carbon dioxide emissions, which is general to offshore production, concerns are centered on the risk of an oil spill. The company is to report the results of a study into the possible impact of such an event, and present proposals on contingency cleanup arrangements, when further hearings are held in the autumn.
Snøhvit contains thin oil layers holding an estimated 75 million bbl, but these are not judged to be economically recoverable with current technology at current prices. There is significant upside potential, but a delineation well, which would have investigated this, was cancelled last year when oil prices fell. The key player in an oil development would be Hydro, which has acquired expertise in producing Troll's thin oil layers.
A decision on whether to produce the oil must be made before the development concept is fixed, perhaps by the end of next year. If the answer is yes, some on-the-spot processing will be required - a semisubmersible platform was previously the base case. If not, the gas will be produced through subsea wells tied directly back to shore - a distance of 170 km. There, it will be delivered to an LNG plant and shipped off to market in liquified form.
Statoil faces design challenges of Norway's longest gas trunkline
Moving dense phase gas with high CO2 and H2S
The 700-km, 42-in. Åsgard Transport System pipeline will export rich gas from the Åsgard field located offshore Mid-Norway to Kärstø in South West Norway. This is a Gas Trunkline mostly in deepwater, about 300 meters, where several future branch lines will be connected.
The Åsgard Transportation Pipeline represents a large step forward in pipeline technology. Challenges facing the project include:
- Large diameter pipeline in deepwater, stretch ing the capability limits of the existing lay vessels
- Use of a flexible riser system for gas export, connected to a riser base structure
- Diverless subsea pig launching
- Diverless subsea tie-in of a large diameter pipeline, using clamp connectors, in deepwater
- Transportation of dense phase gas with high content of carbon dioxide and hydrogen sulfide
- Connectable pipelines (Norne) with a higher design pressure without a pressure control valuable system on the specification break point
- Designing a pipeline crossing areas with rough seabed, inducing numerous free spans and uncertainty of behavior in a fairly hot pipeline over a rough seabed.
The Åsgard transportation pipeline is designed with an effective transport capacity of 68 MMcm/d and a design pressure of 212 bar. Åsgard will deliver 37.6 MMcm/d on plateau. This means there is significant spare capacity for production from other, future fields. The starting point for this gas trunkline is the semisubmersible Åsgard B platform which serves as the field center for gas. The Åsgard B is connected to the export pipeline via four, 14-in. flexible risers to the ERB at roughly 300 meters water depth, about 500 meters from the platform.
The trunkline starts out as a 28-in. line from the ERB, going directly over to a 42-in. pipeline via a specially constructed 2 meters long transition piece installed about 500 meters downstream the ERB. The tie in of the pipeline to the ERB structure will be performed using a rigid spool and clamp connectors. Equipment to handle such connectors has to be built.
The pipeline route follows the coast southwards to where the pipeline comes ashore in a subsea tunnel though a rock piercing at 60 meters water depth. The 20-km long land section from the landing point at Kälstø to Kärstø includes three fjord crossings. The section is designed for a 72-bar pressure in order to keep the wall thickness within reasonable limits. A pressure control system is therefore installed at the landfall valve station to protect the landline from potential overpressure.
The design temperature of the Åsgard Transport is 60°C. At full flow, the line cools to ambient temperature after about 100 km. Parts of this 100-km section are highly irregular (iceberg scoured), creating a continuous series of freespans. Pipeline expansion, due to the high temperature, in combination with trawl induced buckling, initially creates a challenge in predicting the behavior of the pipeline and the associated loads and bending moments. A further challenge is to control and limit the expansion, and thereby keep the loads and bending moments within acceptable criteria.
It was determined that, due to the temperature, the pipeline would thermally buckle and the associated bending moments exceed the allowable limits. A conventional approach to this problem (fully constraining the line) would require about 1.6 million cu meters of rock dump intervention. There was a large scope for optimization.
The first step was to establish which criteria should be applied to this pipeline. Should it be based on load controlled (with local buckling being the limiting criteria) or displacement controlled criteria (with fracture being the limiting failure mode). By definition, an unsupported pipe is load controlled, and therefore the initial approach is load controlled. A freespanning pipeline cannot be characterized as displacement controlled, unless it is fully locked in or frozen. However, work is ongoing to demonstrate that a fully supported thermal buckle can be characterized as displacement controlled.
Load controlled approach
In the hot section it was demonstrated by 3D finite element in-place analysis that the pipeline would globally buckle at relatively low effective forces (circa 7MN) and the associated pipeline expansion into the buckle would result in unacceptably high bending moments. Totally preventing the pipeline from buckling would require very large rock volumes, and was therefore ruled out. The options were to either increase the moment capacity or decrease the expansion. Increasing the moment capacity by wall thickness increase was ruled out as the pipeline was being fabricated and the moment capacity was fully optimized. The project elected to control the expansion into the thermal buckle to limit bending moments to within allowable limits.
From the detailed analysis of the 3D in-place analysis the accurate placing and sizing of berms was possible, demonstrating that each berm could accommodate the associated effective force to prevent pipe feed-in. The revised intervention estimate for controlling the expansion was determined to be about 350,000 cu meters of rock. Although this figure represents approximately 20% of the fully constrained estimate it still represented a significant cost to the project.
The alternative approach currently being evaluated by the project, is to change the criteria in the buckle, and demonstrate that it is displacement controlled. The advantage of this approach would be that the berms to control expansion would not be required, and the intervention volume would decrease to around 50-100,000 cu meters, 6% or less of fully constrained approach. On the basis that when a pipeline is in freespan it is load controlled, then the first requirement is that pipeline in the buckle has to be fully supported.
By means of reducing the submerged weight of the pipeline in given sections, use of trigger berms and use of the simulator, a very high level of confidence is reached on where the pipeline buckles are going to occur before operation. Applying this approach, pre-lay intervention can be performed at the buckle locations satisfying the criteria that the buckle is fully supported. To further reduce the pre-lay intervention, it is only the apex of the buckle where displacement controlled criteria is required about 20 meters length, so the majority of the 300-500 meters long buckle does not require supporting based on load controlled criteria.
Drilling riserless to 4,000 ft TVD
Each of Buckland's wells has been spudded with a 36-in. hole which was drilled riserless to a point 250 ft below the seabed. This section was drilled using seawater and viscous sweeps. The 26-in. hole section was drilled riserless to between 2,200-4,000 ft true vertical depth (TVD), also using seawater and viscous sweeps. After running the BOPs and riser, the 17 1/2-in. hole sections were drilled to 4,800-8,700 ft MD, using a simple prehydrated gel PAC water-based mud.
Next, the 12 1/4-in. hole section was directionally drilled with water or oil-based muds. Formation overpressure was not an issue, but a mud weight of 11.5 ppg was required to maintain borehole stability. The 9 5/8-in. casing string was set prior to drilling each reservoir section.
The 8 1/2-in. hole section was then drilled through the reservoir at inclinations according to the well profile (horizontal in P1). An oil-based mud was used in all 8 1/2-in. hole sections. All oil-based mud cuttings were recovered and shipped to shore.
Transocean-Sedco Forex transaction terms
Under terms of the agreement negotiated during the merger of Schlumberger Sedco Forex and Transocean, Schlumberger shareholders will receive 52% of the fully diluted stock of the combined company (109 million shares), with Transocean shareholders receiving the remaining 48% (101 million shares). This equates to Schlumberger shareholders receiving one Transocean Sedco Forex share for every five Schlumberger shares held, with the total 109 million shares valued at $3.2 billion based on the Transocean Offshore closing stock price on July 9, 1999.
Victor E. Grijalva, Vice Chairman of Schlumberger, will serve as the Chairman of Transocean Sedco Forex, while J. Michael Talbert, Chairman and CEO of Transocean, will serve as President and CEO. The Board of Directors of the Transocean Sedco Forex will consist of 10 members, five designated from each company.
The Boards of Directors of both companies have approved the agreement, but it is still subject to the approval of the stockholders of both companies in addition to regulatory approvals and customary closing conditions. The transaction is anticipated to close on December 31 of this year. The resulting Transocean Sedco Forex stock will be traded on the New York Stock Exchange under the symbol RIG.
Transocean Sedco Forex will have a total fleet of 75 mobile offshore drilling units. This will be made up of 47 semisubmersibles, seven drillships, 17 jackups, and four tender rigs. Will Davie, Investor Relations Manager for Schlumberger Ltd., said that Transocean was "an ideal partner for Schlumberger, with a technical focus and a mix of assets. Tthey are building drillships; we are building semisubmersibles."
"The new company has great financial strength and a strong balance sheet," assessed Jeff Chastain, Director of Investor Relations for Transocean. "In addition, the new company
will have a much larger shareholder base. Transocean goes from 101 million shares to 210 million shares. It gives Transocean access to many more investors, some of which will recognize the long-term benefits of this combination and hold the shares. It makes for a challenging opportunity and a broader shareholder base."
Merger of equals
This agreement has been called a "merger of equals." Under the terms of the agreement, Schlumberger will spin-off Sedco Forex as a separate entity to combine with Transocean.
"Sedco Forex Offshore is being returned to the shareholders," Davie said. "The shareholders owned it when it was part of Schlumberger and they own it when it's on its own. Schlumberger chose that route, rather than pay a premium for an acquisition or sell Sedco Forex. They didn't want to sell Sedco Forex and they didn't want to buy another company. This way, it could achieve the objective of forming a very strong offshore drilling company without having to do a purchase or a sale."