TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSubsea cryogenic pipelines are emergenging technologies that are essential for the new generation of offshore LNG loading and receiving terminals. Current LNG product transfer systems use short runs of rigid or flexible pipe. As terminals move further offshore, there is a need to develop longer runs of insulated rigid pipeline LNG transfer systems.A major issue for these systems is the pipe contraction due to the low temperature of the LNG. At present, there are mainly two methods to accommodate this contraction: -Use of INVAR TM or other alloy with ultra-low thermal expansion coefficient, or -Use of bellows, one in each segment (about 50 ft long) of the pipeline, which is a self-contained pipe-in-pipe segment with vacuum insulation. While technically feasible, both methods suffer major disadvantages in cost, reliability, durability, or maintenance requirement.A new pipeline configuration has been developed to address these disadvantages. This configuration uses a highly efficient thermal nano-porous insulation in the annular space between the inner and outer pipes. This material is kept in an ambient pressure environment, which is produced through sealing by metal or non-metal bulkheads. The bulkheads transfer the contraction induced axial compression load on the inner cryogenic carrier pipe(s) to the external jacket pipe. The resulting pipeline bundle is a structural element, which addresses the thermal contraction & expansion loads without resorting to expansion bellows or ultra-low thermal contraction alloys.As an example, a LNG carrier pipe that would be rated for cryogenic service and be configured to transfer thermal loads imparted through the bulkheads would be a 9% Nickel steel, while the jacket pipe is carbon steel. The thermal insulation used in the configuration is a high performance nano-porous aerogel product, approximately 2" thick, in blanket form installed within the annular space without vacuum and under ambient pressure. This paper will discuss the techical details of the configuration, and the Phase I test performed in April 2004 using a cryogenic pipe specimen under flowing LNG conditions.

The interest and rapid development in the transportation of LNG world-wide has prompted a fresh-look at how LNG is transferred to/from an LNG carrier that may be moored offshore in various locations. LNG subsea pipelines are emerging technologies that are critical to a new generation of offshore LNG loading and unloading terminals. This paper addresses a cost-effective pipe-in-pipe design configuration which uses ambient pressure, high efficiency aerogel insulation and high strength 9% Nickel alloys to manage the contraction forces and stresses in an end restrained cryogenic pipeline system. The paper discusses the derivation of stresses in the pipeline and how they compare to common industry codes and recommended practices. The paper also discusses the welding development and qualifications of welding a 9% Nickel alloy steel pipe to achieve the industry's first use of matched strength welds to the parent material, a significant technology breakthrough, with suitable welding consumables and techniques successfully applied in other pipeline projects.The design discussed is based on proven industry materials and components, which have been combined together to form a new cost effective subsea LNG pipe-in-pipe configuration. The presentation discusses the review programs employed by ABS and DNV to certify the technology for project applications, which led to the award of "Fit for Service" certifications.

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As the petroleum reserve discovery goes deeper in the offshore oil industry, high pressure reserves are discovered. Those wells will produce at very high initial flowing wellhead pressures (> 10,000 psi) and at much lower flowing wellhead pressures after a period of production. This presents a significant challenge for design and operation of the production system, especially, the subsea production choke, being required to have very low flow coefficient (Cv) in early life to restrict flow, and very high Cv in late life to reduce pressure loss. Initially, the pressure across the choke is required to be 5000 psi or higher. Associated with the high pressure loss across the choke, the Joule-Thompson effect will cause much higher temperatures (up to 30 – 40 °F) at the downstream of the subsea choke compared to non-restricted flow. The elevated temperature challenges the materials of the downstream equipment and the pipelines/risers. This paper presents an innovative concept ¾ using dual subsea chokes to split the pressure to protect the chokes and improve production operations. The advantages and disadvantages of using dual subsea chokes are presented. Introduction Major High Pressure High Temperature (HPHT) reserves are being developed in the North Sea and the Gulf of Mexico. The learning curve has been very steep on key completion technologies, subsea equipment and installations. The range of pressure and temperature are not well defined as industry consensus. In the UK sector of the North Sea the wells are called HPHT wells with a reservoir pressure (>14,500 psi or 1000 bar) and high temperature (>266°F or 130°C) [1]. In the Gulf of Mexico (GoM), operators are looking at the ultra-high pressure and temperature prospects (>25,000 psi and >450°F) [2, 3]. The current deepest well is completed at 29,860 ft TVD. New discoveries may exceed 30,000 ft. A three-tier classification has been proposed for well completion in the paper [2]:Tier I: 15,000 psi (1034 bar) and 350 °F (177 °C)Tier II: 20,000 psi (1379 bar) and 400 °F (204 °C)Tier III: 30,000 psi (2068 bar) and 500 °F (260 °C) Fluid characterization regarding sour/sweet service is a major challenge to set the design criterion for well tabular and subsea equipment, including the choke body and trim material selection. Figure 1 shows the subsea choking requirement on subsea choke to maintain low flowline pressures. In a 10,000 ft water depth, if a well is completed at 30,000 ft TVD, the choking pressure loss is about 5000 psi, the water depth and pipeline pressure loss is about 3500 psi and wellbore pressure loss is about 7,000 psi. The reservoir pressure loss is usually in the range of 500 -1,500 psi. Those numbers are not precise calculation results, instead, only to show the magnitudes of each component in a deepwater HPHT production system. A reliable subsea adjustable choke is essential to a subsea production system. The critical challenge is trim material and configuration. A historic review for choke development was presented in references [4, 5]. A list of parameters for selecting a subsea production choke has been presented in reference [5] and being slightly modified and shown as Table 1. The flow characteristics of orifice-type and cage-type subsea chokes have been investigated [6]. Effective choking is critical to apply HIPP systems to the subsea pipeline [7, 8]. The choke is required to set the pressure at the inlet well below the design pressure to allow for flow transients and to provide sufficient time for HIPPS valve to close in the event of a pressure increase due to blockage. Background Recent discoveries of High Pressure High Temperature oil and gas reserves in the Gulf of Mexico and the North Sea presented a significant challenge to subsea production technologies, and especially for the production control. Most significantly, while the pressure differences at early production are estimated to be around 5000 psi or even higher, they are expected to substantially decrease over time. Such anticipated pressure gradient is difficult to manage in a safe and economic manner using currently known technology.

The increased interest and rapid development in the transportation of LNG world-wide has prompted a fresh look at how LNG is transferred to/from an LNG carrier that may be moored offshore in various locations. The traditional shoreside loading/unloading of LNG to/from marine carriers may be prohibited due to proximity to populated areas, safety and/or environmental concerns. Also, the extension of an offshore jetty structure to support the transfer pipelines with related seabed dredging to facilitate vessel access, may be prohibitively costly. This presentation discusses how new developments in high-strength Nickel alloy cryogenic pipelines and high-efficiency insulation systems have significantly improved the prospects for the installation of the first subsea cryogenic pipeline for LNG service. Subsea cryogenic pipelines designs to date focus on the use of vacuum systems for insulation and Invar pipe materials to control growth and differential stress in the pipeline systems. This approach, while successful, has also resulted in high cost systems and welding issues. A new design approach using ambient pressure, high efficiency insulation and high strength Nickel alloys reduces the cost of the system and improves constructability. The design and installation techniques are based on proven systems used in operating high temperature pipelines. This paper addresses the design, fabrication and installation of subsea cryogenic pipelines as well as possibilities for inspection, maintenance and real time monitoring of the installed system. The designs to be reviewed focus on the use of new developments in high-strength Nickel alloy cryogenic pipelines and high-efficiency insulation systems. The presentation also discusses the test program employed to certify a Fluor developed ambient pressure subsea LNG pipeline for commercial use. Introduction Terminals are required for both the loading and offloading of LNG into tankers. For locations with sufficient deep water access terminals may consist of jetty structures and breakwaters where tankers can be moored and offloading can take place via standard loading arms. Several LNG facilities have the jetty terminal connected to an onshore facility by a short trestle structure, which supports the LNG and utility piping, and may in some cases support vehicular access to the loading terminal. Location of the jetty terminal is dependant upon not only the requirements for the LNG tanker maneuvering and positioning with respect to water depths, currents and ship traffic, but also with prevailing winds which may influence the location from a safety view point. In the design of the jetty terminal and trestle structure, a major consideration is the final location and layout to satisfy safety considerations from vapor plumes that may result from leaks or damage to the LNG piping on the jetty and along the trestle structure. [1] Special precautions must also be taken in the design of jetty piping for protection against damage that may result in leaks. This may include additional structural protection and block valves that isolate segments of the piping. In the U.S. handling requirements for LNG on jetty structures require full containment to be designed into the structure to contain a leak or spillage.