Operators, as well as engineering, procurement, and construction (EPC) companies facing large capital expenditure projects, such as new-build and brownfield production and process installations, are creating new designs and practices to accommodate the complexity of changing demands and environments.
Short time scales, high levels of scrutiny, and compliance with standards contribute to the trend of larger and more complex engineering problems. Design, construction, and installation are being modified in unique ways, offering efficiencies and versatility.
In mid-October, BP installed a 750-ton processing unit (18 m long, 13 m wide, and 28 m high) on its existing Andrew platform in the North Sea, 230 km northwest of Aberdeen. The unit will process oil and gas from the Kinnoull and Andrew Lower Cretaceous reservoirs. The Kinnoull field is one of three reservoirs being developed as part of the rejuvenation of the Andrew area. The reservoir, which holds 45 million BOE, will be connected to BP’s Andrew platform and will enable production, forecast to peak at 45,000 B/D, to be extended by a decade.
To access the Kinnoull reservoir, a new subsea system and caisson have been installed onto the Andrew platform. Four subsea pipeline bundles with a total length of 27 km, the longest bundle system in the world, according to BP,
will carry the fluids to the Andrew platform for processing and export.
Production from Kinnoull will be delivered by the existing 10-in. diameter, 16-km long Brae-Forties pipeline system to the Kinneil terminal in Scotland. After separating from oil and water, the gas will be exported through an 8-in. diameter, 44-km long pipeline to the Central Transmission System and onwards to Teesside in northeast United Kingdom (UK).
BP developed the concept for the process module as an upgrade for the Andrew platform. Wood Group completed the design, and the Heerema Fabrication Group started the fabrication early last year at its yard in Hartlepool, UK (Fig. 1).
The module was installed using a bolt-on process to the existing production facility, said Ken Scott, project manager at Heerema. He explained that the Andrew platform has had two large docking hooks welded to the existing steelwork outboard of the existing platform area to accommodate the new process module. Two huge hinge pins engage the process module into the docking hooks, allowing the module to sit alongside the existing platform. The module is then tied back and held into position with 40 to 60 tons of additional steelwork to become one complete structure.
Scott said the process module is essentially a new heart for the Andrew platform, which is nearing the end of its design life. The module will breathe new life into the existing facility, allowing a further 10 years of oil production to take place (Fig. 2).
After Wood Group completed the design, Heerema provided the solutions for the loads, tolerances, types of materials, and development of new welding procedures, Scott said. “We had to find where this particular type of steel could be accommodated in terms of its physical weight and diameter for the machining required of 1.5 to 2.0 tons of steel, 2.3 m long, to our required tolerances. We also had to identify the material houses that could do the stress analysis, the hardening, tempering, and the necessary destructive testing required.”
Dummy pins measuring approximately 2 m long and 400 mm in diameter were located into position on the newly installed docking hooks on the existing platform. The vertical and horizontal angles and slope distances of the pins were measured with the use of a total surveying station, and data were gathered, reviewed, modeled, and issued to Heerema to enable the exact installation tolerances to be met for the docking pin. The tolerances were 1 mm discrepancy in deflection on a 1.3-ton pin.
Scott said, “It is unique in the way BP designed it and particularly in the way it had to be manufactured and fabricated to extreme tolerances across the two pins. It is unique for us as a business and within the oil and gas industry, as far as I am aware.”
“In addition to the tolerances for manufacturing, there were tolerances on deflection during the installation and loading process on the side of the existing platform. The pin is 1.6 m in length, 400 mm in diameter, and 1.3 tons in weight and was installed through a 50-mm node plate with compensating plates added at critical stages throughout the welding process to control the deflection of the pin to achieve the exact allowable tolerances of 1 mm,” he said.
A welding procedure had to be developed to accommodate the effects of the entropy temperature and heat transfer on the steel’s metallurgic properties to optimize the resulting weld shape, size, and properties.
Scott said, “It was a procedure of welding one side, then checking the total station survey to identify where the pin was moving. The temperature would then be taken back to ambient before compensation could be made on the other side of the pin. It took two welders about 1.5 weeks to complete this process. Intermediate support and gusset plates were added to restrain the pins throughout the welding procedure to control deflection on both sides of
The platform sections were rolled out of the fabrication hall in two pieces and spliced together, one on top of the other, to form a 45-m tall skeletal structure. The logistics of installing the cabling after the two pieces were joined to form the 45-m high structure required the use of cherry pickers feeding the cables from the outside of the structure to all the required locations.
Cabling is generally pulled from the ground or immediate locations local to the component parts throughout the module, but the 45-m height and restricted footprint size of the module precluded the usual procedure. Instead, 27,000 m of cable, some of which was 50 to 70 mm in diameter, was fed in from the outside of the module from cherry pickers.
Scott said comprehensive risk review and safety assessment was done prior to a third-party subcontractor beginning the installation. The logistics of personnel working around the outside of the perimeter of the structure at height along with crane movements, injury risk, ergonomics, and training were among the many factors successfully managed during the project execution. With the selected technical solutions, BP was able to achieve minimum downtime of the platform.
In 2010, the design team in Horton Wison Deepwater, an affiliate of Shanghai-based Wison Offshore and Marine, began working to come up with a new drilling and production platform concept suitable for shallow to mid-water depths which could be easily fabricated and then installed without the need for a heavy lift crane barge. The team developed the buoyant tower using elements from its previously successful cell spar design. In September, the first buoyant tower drilling and production platform, CX-15, was installed in BPZ Energy’s Corvina field offshore Peru in a water depth of 175 ft.
Horton Wison Deepwater, GMC, and Wison Offshore and Marine were responsible for the EPC and installation of the facility’s 2,500-ton buoyant tower hull and 2,200‑ton topside. The hull comprises four, ring-stiffened and connected cylindrical tubes, similar to proven cell spar technology, with one central suction can foundation (SCF) for connection to the seabed. Each cell measures 27.5 feet in diameter and 197 feet in length, with a total hull length, including the SCF, of 227 ft.
The three-level topside weighs approximately 440 tons and features a 120´100 ft drilling deck, a 120´100 ft production deck, and 100-ft and 45-ft cellar decks. Twenty-four well slots, a 27-ton deck crane locatable on two pedestals, a 10-ton deck crane, and a flare boom round out the topside.
Equipped to produce 12,200 BOPD, 12.8 million ft3/D of gas, and inject 3,500 BWPD, the onboard facilities, weighing approximately 745 tons, include equipment for the handling of oil and associated gas, separation, treatment, gas and water injection, power generation and utilities, and transfer of hydrocarbons and water via subsea pipelines to the existing CX-11 platform approximately one mile away. A tender vessel will assist in drilling on the CX-15.
Chris Harding, vice president of business development at Horton Wison Deepwater, said, “BPZ Energy contracted this design because it met its seismic criteria and because of the unavailability of heavy lift crane vessels for that region. To mobilize a heavy crane vessel to Peru would have killed the economics of their project. The installation of both the topside and the hull was performed off the same submersible ship that transported these items from China to Peru. The cost of the services of the transport ship was an order of magnitude less than the cost of the services of a heavy lift crane barge.”
Both the buoyant tower and its topside were fabricated in Wison Offshore and Marine’s facility in Nantong, China. Fabrication cost was reduced because of the simplicity of the cells that made up the hull. The cell fabrication of the BPZ tower was completed in only 3 months because about 80% of the welds were done with sub arc and track welders. The cells were then transported to the assembly site where outfitting, stacking, and assembly were done. Turnaround from contract award to loadout was 11 months.
The hull together with its topside was transported to the Corvina field by Offshore Heavy Transport’s (OHT) Osprey, a submersible heavy lift vessel (Fig. 3). The Osprey was used to launch the tower and to mate the topside to the tower. The use of the transport ship to perform both these operations was an industry first, Harding said.
During the installation, the Osprey’s stern was submerged near the final installation site, and the hull was floated off in a horizontal orientation before it was upended by allowing seawater to flood the variable ballast tanks in a controlled operation (Figs. 4 and 5). Magnetite (iron oxide) ballast material was pumped into the bottom of each cell to stabilize the tower and increase its draft before the hull was moved back alongside the Osprey for the topside mating.
Before loadout in China, the topside had been placed on top of a cantilever truss system to keep it above water during the hull float-off. The truss cantilever extended over the side of the vessel and incorporated guide beams to funnel the hull into the correct position for mating
(Fig. 6). Once the hull was secured beside the Osprey within the truss structure, the topside was skidded outboard of the vessel and positioned over the tower’s mating pins (Fig. 7).
Deballasting of the tower caused it to rise and the mating pins to slide into conical receptors in the deck legs. Each receptor was equipped with elastomeric pads to minimize banging caused by heave. Further deballasting lifted the topside clear from the supporting truss system. The integrated topside and hull structure was then towed to its final location on the field (Fig. 8) and set into the seabed by ballasting with seawater.
A SCF holds the buoyant tower in position. Located at the bottom end of the main cells, the SCF is forced into the seafloor by ballasting tanks in the tower and allowing the tower weight to push the can into the soil. Additional forces can be generated by lowering the water pressure inside the SCF; however, this additional force was not needed for the CX-15. The SCF provides lateral and vertical support to the tower and permits the tower to move in compliant response to the environment and earthquakes.
Lyle Finn, chief technology officer of Horton Wison Deepwater, said, “Because it is a buoyant tower, it only rests lightly on the bottom. Compliant and guyed towers, in contrast, bear a larger bottom load with the entire deck weight pushing down on the bottom.”
Harding said the sweet spot water depths for the design are approximately 200 to 900 ft. At greater depths, the cost of the tower increases to the point at which floating concepts may become more economic. The compliant nature of the buoyant tower offers an alternative for earthquake-prone locations.
The CX-15 buoyant tower was designed for the relatively mild environmental conditions of Peruvian waters. Other similar regions, such as west and east Africa, Brazil, and parts of southeast Asia, are natural candidates for the concept. The design met the offshore Peru 100‑year significant wave height criterion. Finn said studies for buoyant towers in the Mediterranean and Caspian seas show the concept is feasible in these areas. Extension of the design to withstand harsher environments is under study and is showing promising results.
Harding said the company is developing concepts allowing for the storage of 150,000 to 300,000 bbl of oil within the cells. “This would be ideal for marginal fields,” he said. “With a reasonable tanker frequency, an FPSO (floating production, storage, and offloading) or FSO (floating storage and offloading) vessel can be eliminated.”
Marginal fields are generally defined as containing less than 30 million bbl of oil or oil equivalent with a recovery factor of 20 to 30%. Applying lower cost solutions to smaller fields makes the economics sufficiently attractive to justify developing fields that would otherwise have been overlooked or abandoned. BPZ plans to tap 23 million bbl of proved undeveloped oil using the CX-15 platform.
Southeast Asia’s marginal fields offer opportunities for lower cost platforms. Petronas, the national oil company of Malaysia, reported that it has 106 marginal fields containing 580 million bbl of oil.
Harding said the company has been discussing other buoyant tower designs, some of which use a novel SCF, in southeast Asia. “Instead of being fixed, the central can is lowered or raised within the core, providing a variable water depth capability similar to a conventional jackup.”
The desire for flexibility in investment in structures and their operational locations is driving the demand for leasing options. Tore Lea, managing director of GL Noble Denton (GLND) Norway, said, “In more benign waters, there are fewer requirements related to the environment. In these areas, there has been a lighter approach, such as conversion of existing units, like the conversion of conventional tankers to FPSO.”
The limited production periods associated with marginal fields make leasing a viable alternative. Lea said, “Many of these marginal fields cannot sustain a dedicated investment. To achieve economy and profitability in such fields, lease-based installations like FPSO are being provided by contractors on a limited lease period of the field’s lifetime, anywhere from 1 to 15 years. The flexibility and versatility are keys for an FPSO contractor to take on residual value on the unit.”
Lea said in harsher environments, such as Canada, northern Russia, the Norwegian and Barents areas of Norway, West of the Shetlands, and offshore UK, new-build construction for development projects remains the prevailing approach.
Offshore Norway, where the base infrastructure of the big fields was built in the 1970s and 1980s, many of the fields have surpassed their production top volumes and now have surplus processing capacity. Lea said, “With the boom we’ve had in exploration, and with the new discoveries, not only in the frontier areas but also in the mature areas of the North Sea, there has been a conceptual trend that in the smaller, more marginal discoveries in the mature regions, development is increasingly occurring as subsea tiebacks to existing platforms.”
Lea said project development using standardized concepts and technologies is a trend seen in recent years. For example, in July, Statoil awarded FMC Technologies a contract for subsea production systems (SPS) for the Gullfaks South field, with options to cover its subsea tieback demand in the fast-track portfolio for 2014 and 2015. Estimated contract value is close to NOK 1.2 billion, in addition to possible extensions worth NOK 4 billion.
Statoil said standardized subsea solutions are important for the development of marginal fields located near existing infrastructure. An SPS comprises a wellhead, Chrismas tree equipment, template structures, a manifold, and a control system. The company has a frame agreement with its suppliers, one of which is FMC, for SPS services. The contractors will deliver subsea equipment for relevant fast-track projects and tieback demand.
The contractual technical requirements will be frozen for a 2-year period to form a standard catalog for SPS. Working closely with the suppliers, Statoil plans to build equipment quickly and develop marginal fields more efficiently. To simplify logistics, the company has set new requirements enabling the same systems to be used regardless of the supplier chosen to deliver the seabed infrastructure.
GLND recently established a global design center for floating structures at its offices in Brevik, Norway, to align its capabilities with GLND’s international activities and the global market for floaters.
The company brought together more than 50 engineers to provide design services for offshore and floating oil and gas structures, including deepwater units, FPSO, mobile offshore semisubmersible and monohull drilling units, and specialized tankers and offshore support vessels. Evaluation and development of initial concepts, and asset design and drafting capabilities are available. The company has an existing design center in Sharjah, United Arab Emirates, for jackups and jackets, and design resources in the UK, US, China, India, and Germany.
Lea said, “Platforms for the Norwegian sector were mostly executed locally until 10 to 15 years ago. However, development projects have become more global over the years. Projects coming up in the Norwegian sector of the North Sea with Norwegian operators have construction of the elements of an installation being done elsewhere. For example, jacket construction typically takes place in Holland, Spain, or Norway, deck construction with process facilities in Korea, and hull construction in China, Korea, or Singapore.”
He said the Asian yards are increasingly capable of meeting the required regulations of NORSOK and the Petroleum Safety Authority Norway. “Some years ago, these yards did not know about the regulations, so they could not build according to them. Many operators decided to make a one-off construction in the country of the project’s origin. This has changed to an industry where the operators can hand out parts of the construction in separate tender processes and get competitive pricing on the different elements. At the end, the operator contracts with a service provider for putting together the different elements.”