TECHNOLOGY AT WORK

Proven new technologies for offshore / onshore applications

escribed here are five new equipment, process and installation innovations that offer valuable alternatives to existing methods. Four of the new technologies represent offshore installations; one field system improvement has broad applications in various field types / locations.

The innovations include:

1. riser buoyancy modules for Asgard field;
2. how Chevron selected / installed an H₂S removal process in the Gulf of Mexico;
3. a multi-function barge (MFB) concept for deep water;
4. a new single-pile platform in Dutch waters; and
5. polyethylene lining of a pre-installed, high-pressure water injection system's piping in Argentina.

Development of Asgard dynamic riser buoyancy modules

With exploration and field development in the offshore industry moving into more hostile and deeper waters, demands on the buoyancy required for these projects becomes ever more rigorous. An order placed by Coflexip Stena Offshore Norge AS with Balmoral Composites in Aberdeen for design, manufacture and supply of dynamic riser modules for the flexible riser system on the Asgard A project was no exception; and it was to set new standards for the industry.

	Dynamic flexible riser buoyancy modules developed for the Asgard project illustrating the company's internal composite clamp tensioning mechanism.

Riser buoyancy modules are used to generate upthrust to the riser to maintain the system's pliant wave configuration. Density and composition of the syntactic foam required for the task was selected by the supplier on the basis of design criteria, considering elements such as hydrostatic pressure, water ingress and elastic / inelastic compression. Current and wave loadings that the buoyancy modules must withstand are exceptionally high, requiring overall size restrictions of the modules to minimize loads inflicted upon them. In addition, multi-axis water channels were incorporated into the rotationally molded module shell to allow convection currents in the sea water to circulate, whatever the module orientation.

Internal clamps are used to prevent sliding of the buoyancy modules along the riser, and they must achieve this by friction alone, without applying excessive pressure or damaging the outer protective layers of the risers. They must also cater for expansion / contraction (both thermal and mechanical) and creep in the risers. This means that the clamp tensioning mechanism has to function as an elastic spring throughout its operational life, maintaining sufficient pressure in the risers to prevent slippage.

The high reservoir temperatures on the Asgard project introduced a new dimension to the equation with the need to use high-spec materials to prevent localized heat build-up in the riser beneath the modules. Thermal conductivity of the internal composite clamps was increased by using a specially developed syntactic matrix, designed to minimize any increase in density which would have had an effect on module size and loads.

Size and demands of the order also required radical changes to both production and processing methods, and new processing equipment was developed to meet these needs.

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Offshore application of H₂S removal system

Chevron USA Production Co. chose to install a natural gas sweetening train at its Mobile Block 864B production platform in the Gulf of Mexico. The entire system, comprising both an amine unit and the sulfur recovery unit, is located on the platform.

Chevron investigated several alternative sulfur recovery options, evaluating each in accordance with the following criteria:

• Gas capacity / H₂S concentration turndown capability
• H₂S removal efficiency
• Operator attention needs
• Sulfur product produced, and
• Proven reliability.

The investigation led to the selection of U.S. Filter's LO-CAT II Hydrogen Sulfide Oxidation Process.

As this was the first installation of the new oxidation unit on an offshore platform, several areas of the unit's standard equipment package, including vessels, structural steel and instrumentation, were redesigned so as to meet offshore requirements involving space, corrosion control and onstream availability.

How it works. The selected oxidation process is a liquid redox technology, which oxidizes H₂S into innocuous, elemental sulfur. The process consists of three major parts: the inlet coalescing filter, the autocirculation unit and the sulfur settler. To speed up the reaction, a proprietary, nontoxic, aqueous, chelated iron catalyst is used to oxidize sulfide ions to sulfur. Ambient air is then used to regenerate the catalyst. The overall reaction is:

    H₂S (gas) + 1/2 O₂ (gas) ® H₂O + S°

In this reaction, the iron ions transport electrons from the sulfide ion to the dissolved oxygen. For the reaction to proceed, at least two iron ions per sulfide ion must be present. In this role, the iron ions act as a reagent. However, because the iron ions are not consumed in the reaction and because the reaction would not proceed at ambient temperatures without it, the iron is also considered a catalyst.

	H2S removal unit installed on Mobile Block 864 B platform in U.S. Gulf of Mexico.

To start the process, the amine acid gas from the amine unit is sent to a coalescing filter to remove any entrained liquids. It is then sparged into the absorber sections of the autocirculation vessel. Centrifugal air blowers sparge air into the oxidizer sections of the autocirculation vessel. The "air-lift" that is created causes circulation of the reduced iron catalyst solution from the absorber to the oxidizer section of the autocirculation vessel. In this way, both the H₂S oxidation to sulfur and the regeneration of the iron catalyst occurs in the vessel.

A slipstream of the solution is then sent to a cone-bottomed sulfur settler vessel. From there, progressive cavity pumps are used to deliver the sulfur slurry to a vacuum belt filter. This filter produces a 60 wt% sulfur cake that falls into a dumpster, while the recovered catalyst solution is pumped back to the autocirculation vessel.

Platform installation. The existing platform had little space available for the new unit. Therefore, space limitations required that the main processing vessel, the autocirculation vessel, be split into two vessels connected by tunnels. This in turn resulted in modification of the vessel's internals to allow for seal welding of the tunnels, eliminating any chance of leaks at "normally bolt-up" connections between vessels and tunnels.

To save additional space:

1. The oxidizer air blowers were mounted on top of, rather than beside, the autocirculation vessel,
2. Platforms around the settling vessel and the vacuum belt filter were consolidated, and
3. The standard external shell and tube heat exchanger was replaced with an internal tube exchanger mounted through the top of the autocirculation vessel.

Due to the corrosive marine environment, external design of the autocirculation vessel was modified. Because Chevron corrosion control specs required that all external vessel designs have 100% seal welding, the supplier installed poison plates (a piece of stainless steel welded between different materials) between the carbon steel support beams and the stainless vessel skin.

The operator also required that — after seal welding all vessels to the deck plate-the deck plate beneath the vessel be removed. The autocirculation vessel, typically designed to be supported on a rigid foundation, was redesigned for this application so that the floor beams would both span the large open area and support the vessel. Several instrument modifications including redundant level controls, modified level safety switches and modified temperature safety switches were required to meet the offshore availability requirements.

The unit was started up in September 1996. While operating at a reduced sulfur load, it is exceeding H₂S removal requirements. It requires about 25 hr per week of operator attention, i.e., about 3 hr/day on a continuously manned platform.

Acknowledgment

Technical information for this article was supplied by William Rouleau, applications engineering team leader for U.S. Filter / LO-CT, Schaumburg, Illinois.

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Barge concept combines all deepwater development capabilities

The multi-function barge (MFB) concept has been developed for deepwater, mild environment areas to combine in one facility the capabilities of an FPSO with the ability to drill and tie-in development wells and to perform subsequent workovers. The most significant innovation of the MFB concept is that only one facility is required for economical development of a deepwater field. Subsea wellheads or a separate wellhead platform are not needed.

This approach would reduce CAPEX because of more economical drilling, reduced subsea installations and simpler well intervention. Operating expenses will also be lower.

Bouygues Offshore, the contractor for the N'kossa barge project, is developing the MFB with Sedco Forex and Institut Français du Pétrole. The MFB will be a concrete monohull that combines oil and gas treatment, utilities and living quarters with crude oil storage and offloading. In addition, drilling, tie-back, completion and workover facilities with surface trees would be incorporated.

The MFB concept is intended for deepwater developments in the Gulf of Guinea or in other offshore areas having similar environments.

	The concrete hull of the multi-function barge (MFB) will be rectangular, measuring 1,103 ft by 243 ft. Its spacious deck permits a reduction in the number of deck levels, is less congested and offers maximum separation of hazardous areas from manned areas.

MFB description. The multi-function barge is composed of a concrete hull designed to support all production facilities while providing built-in segregated storage of up to two million bbl of crude and water ballast.

Drilling and production would be performed simultaneously with 20 well slots available inside a central moonpool. Crude production up to 200,000 bpd would be stored in the hull between concrete bulkheads. Offloading operations would be by tandem-moored tankers.

The MFB has been designed for 5,000-ft waters, but it could be adapted for a range of 650 to 6,500 ft, or even deeper. These depths, combined with the mild environment of the Gulf of Guinea, will allow the wellheads to be located above deck in a central moonpool, with rigid risers to the seabed.

To limit relative vertical motion between the barge and surface trees, the distance from barge to seabed will be controlled by water ballasting for draft adjustment to compensate for the predictable effects of changes in the amount of crude stored. The tide range (6 ft for the Gulf of Guinea) is not compensated by ballast, but this is a predictable, slowly varying vertical motion that is easy to accommodate.

The tensioning system between surface wellheads and barge is similar to those use on TLPs or SPARs, but with greater relative motions due to the higher heave response of the barge. The resulting riser strokes could be compensated by either conventional hydro-pneumatic tensioners with large stroke capacities, or by individual riser buoyancy units.

For station keeping, 12 chain / steel wire catenary lines, positioned in groups of three at each barge corner, are secured to suction anchors on the seabed and connected to the hull through deck fairleads and tensioners. This mooring system is designed for high horizontal stiffness to limit maximum barge offsets in intact and damaged conditions, and to comply with drilling and workover requirements by providing a smaller surface wellhead setdown.

The concrete hull will be rectangular, measuring 1,103 ft by 243 ft. Structural design was performed using Norwegian Standard 3473E. The hull will be heavily reinforced and post-tensioned to withstand overall and local environmental forces, as well as functional loads applied to the structure. High performance concrete will be used for strength and durability.

The spacious deck is designed for uncongested topsides arrangement, with a simple interface between the topsides and hull. The large deck size permits a reduction in the number of deck levels, less congestion, maximum separation of hazardous areas from manned areas and ample allowance for potential changes such as retrofits, tie-ins, etc.

Production equipment will be split between two main zones. Low risk modules will be forward near the quarters facilities, more hazardous equipment will be astern. The moonpool will be in the middle of the deck to minimize relative motion between risers and hull. Wide areas around the moonpool provide easy handling of tubulars and for mud tanks.

Conclusion. Development of the MFB was carried out by the three partners with assistance from BP, Elf, Shell and Statoil. Studies have shown the concept to be technically and economically sound for deepwater, mild environment areas such as the Gulf of Guinea. It should be very competitive to the combined use of a TLP and FPSO. When the number of wells to be drilled from the same location is sufficient, the MFB as the central production facility should be a sound choice.

Acknowledgment

This article was excerpted from OTC paper 8813, "The MFB, a Deep Water FPSO with Surface Trees and Drilling Facilities," by C. Valenchon, et al., presented during the 1988 Offshore Technology Conference, May 4 – 7, 1998, Houston.

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Single pile platform targets marginal fields

During late July 1997, the first Single Pile Platform (SPP) was handed over to Dutch operator NAM in the North Sea. SPP is a complete exploration / exploitation platform on a single column. This innovative concept is designed to enable operating companies to optimally exploit marginal fields with considerably reduced investment.

The SPP consists of a single steel cylinder, Fig. 1. Diameter is approximately 6 m (20 ft). A maximum six conductors can be attached to the cylinder, on which a platform can be constructed immediately or in a later stage. The result is a complete offshore platform on a single pile, attuned to developing marginal fields in water as deep as 35 m (115 ft). Dutch manufacturer Genius Vos developed the SPP on its own initiative, including the installation method and equipment. A patent for this unique concept has been applied for.

"The costs for installation of a conventional platform in a marginal field are totally disproportionate to its yield," said Genius Vos Managing Director Ron Davio. "The SPP, on the other hand, is a platform that can be installed relatively inexpensively, and its concept is flexible." As noted by Davio, the SPP enables an operator to conduct test drilling and, if this is successful, to begin production immediately without having to drill a production pit first. Thus, development of a marginal field is quicker and less expensive, thereby maximizing the yield.

Another advantage is the SPP's minimal effect on the environment. Even if an oil spill occurs, no pollution occurs, because the spill remains enclosed in the tube that holds the conductor.

After the first SPP was built, it was transported on a pontoon from the manufacturer's base in the city of Ijmuiden to its destination. Upon arrival at NAM's N7-FA gas field on the Dutch Continental Shelf, a work platform was used to vertically lift the enclosing pile, Fig. 2. Next, the assembly was drilled down to a 23-m (75.5-ft) depth, thus enclosing the conductor used by the operator for test drilling. Once the pile was situated, pressure tests were performed at 1,000 t, and the pile passed with excellent results, Fig. 3.

Operators are showing good interest in the SPP concept, as it is deemed suitable for any offshore location where water depths do not exceed 35 m (115 ft). For instance, this would apply to a number of locations offshore the Middle East and China.

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Polyethylene lining increases water injection line life

In 1997, after 27 years of steady production, the Rio Neuquén oil field in southern Argentina began to show its age. When Perez Companc S.A. took over field management in 1994, it was only producing 1,600 bopd. With a heavy investment, the operator increased oil production to more than 6,000 bopd; and similar increases in gas production have been realized. At that time, it was decided that a network of high-pressure water injection wells could increase production and greatly extend field life.

The first phase of the plan called for three high-pressure trunk lines which would carry water from a treatment plant to up to 19 injection wells. Each of these lines would start as 8-in. pipe at the plant and step down to 6 in., then to either 3 in. or 4 in. at wellheads, Fig. 1. There would be 3,300 m (10,820 ft) of 8 in., 7,000 m (22,960 ft) of 6 in., 2,000 m (6,560 ft) of 4 in., and 5,000 m (16,400 ft) of 3 in., for a total 17,300 m (56,700 ft) of pipe.

Design options. Perez was concerned about the safety of this high-pressure distribution system because it would be installed under some of the most productive fruit plantations in Argentina. The injection water would be extremely aggressive to steel pipes, and an underground leak could damage the fruit trees and the surrounding environment.

The operator has long maintained a progressive policy for environmental improvement. In fact, Rio Neuquén field was recently audited by the international firm of DNV (Det Norske Veritas Quality Assurance) to obtain certification that its environmental management system conforms to the ISO 14001 standard. Therefore, it was natural that the engineers from Perez and SADE, an engineering / construction subsidiary, should conduct extensive research to find the safest, most cost-effective design.

Epoxy-coated carbon steel, heavy-walled fiberglass, stainless steel and polyethylene-lined carbon steel pipe were among the solutions considered. Perez had experienced failures with epoxy-coated pipes after only five years in some fields they operate. Heavy-walled fiberglass pipe is expensive, and engineers were concerned about reliability and jointing. Stainless would certainly meet the challenges, but it would have been "extremely" expensive. Thus, the designers discovered that their objectives could be met by the Swagelining process developed by BG plc (formerly British Gas).

Lining process description. The Swagelining process allows an existing pipe to be lined with an extremely tight-fitting polyethylene (PE) pipe. In addition, it is the only PE lining process with the technology to allow sections to be welded into a continuous pipeline. With the process, it would not be necessary to include flanged joints in the system.

The technique was developed by BG as a rehabilitation process for its own gas lines. However, because of its uniqueness, it has been used successfully to protect more than 500 mi (800 km) of pipe ranging from 3 in. to 36 in. (75 mm to 900 mm) in diameter. This protection includes gas, oil, water, forced sewer and a wide range of industrial production lines all over the world, both on- and offshore.

The process uses PE pipe with an outside diameter slightly larger than the inside diameter of the pipe to be lined. During installation, this pipe is pulled through a die to temporarily reduce its outside diameter, Fig. 2. This reduction allows the PE to be easily pulled through the outer pipe. When the pulling force has been disconnected, the liner begins to return to its original diameter; and within hours, it will be pressing tightly against the ID of the outer pipe.

For couplings, at Rio Neuquén, the patented technology called for a short section of specially adapted duplex stainless pipe to be welded to each end of each section of the X85 carbon steel pipeline before it was lined with the medium density polyethylene (MDPE) pipe, Fig. 3A. After being pulled through the carbon steel pipeline and allowed to relax, the MDPE lining would be cut off inside the stainless steel section. A stainless steel compression ring would then be inserted inside the PE pipe to create a seal which could withstand the 3,000-psi pressure of the water injection system. This would allow consecutive sections of lined pipe to be welded together without leaving any of the X85 material exposed to the aggressive effluent which the line would carry, Fig. 3B.

The tight-fitting PE pipes used in the Swagelining process are manufactured to ISO, AGA, ASTM and API standards, so the linings have known physical properties and an established service life. For the Rio Neuquén injection lines, the engineers selected a MDPE pipe manufactured by Uponor, one of the largest PE pipe manufacturers. This company is headquartered in Finland, but has several plants around the world, including one in Argentina. Lining for the 3-in. and 4-in. steel pipes would have a wall thickness of 5 mm; for 6 in. and 8 in., WT would be 7 mm.

An important factor in the decision to use the swaging process was the fact that Nortek, the Buenos Aires licensee who would line the steel pipes, would guarantee the lining for 25 years. This unusual guarantee was made possible by the combination of the inherent characteristics of PE pipe, the patented process, and the unique coupling technology developed by BG and proven in BP's Foinaven oil field in the Atlantic Ocean.

Field installation. Another company involved in the operation was Avon Lippiatt Hobbs Contracting Ltd. (ALHCO), a process licensee headquartered in the UK. ALHCO became involved in the project through BG, and sent a representative to Argentina to assist Nortek with what would become the first Swagelining installation in that country.

The whole of the steel network was laid in-ground and backfilled. Bend diameters were kept to a minimum, and installers were careful to adhere to the welding spec of API-1104, so the root weld would not penetrate too deeply inside the pipe.

After the entire piping system was installed, Nortek went back and installed the MDPE lining. Between 40 and 50 separate insertions were made. And because the operation was conducted in an open area with no paved roads, the insertion points could be placed wherever they were needed.

After SADE excavated an insertion pit, they removed a section of the steel pipe equal to the length of two stainless steel couplings. They then lifted the ends of the pipe with shear legs or jacks so couplings could be welded on and the sections lined up. When the polyethylene pipe had relaxed inside the steel pipes, the ends were trimmed and the compression rings were inserted. The ends of the steel pipe were then lowered and the couplers were welded together.

The installer said the project was a little slow, initially, but "after we were up and running, we maximized the lengths we could pull, achieving 750-m pulls in the 4 in. and even longer pulls in the larger diameters." The project was judged to be successful; it has been tested and inspected in every way, and no problems have been found.

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Copyright © 1999 Gulf Publishing Company