Access to natural gas will be a vital part of the world’s energy strategy in the years to come. Because the regions of greatest new supplies are distant from sources, demand for liquefied natural gas (LNG) is forecast to more than double by 2020 compared to an increase of only 2-3% in overall gas demand for the same period (Wood Mackenzie LNG Tool 2008). LNG technology provides the means to transport large volumes of gas around the world in liquid form thus bridging the transportation gap.
Conveying LNG from plant to transportation vessel and back again requires a pipeline along which the liquid gas flows. LNG pipelines must be kept below circa minus 160oC, thus introducing the need for insulation and steels that can perform at ultra-low temperatures.
Corus Tubes is developing a cost-effective solution for LNG conveyance and jetty lines using 9% nickel steel, which has an established track record of use for cryogenic applications, but has not been fully utilized in pipelines. The company commissioned J P Kenny Ltd, one of the world’s largest pipeline and subsea engineering and management contractors, to study its relative performance for an LNG jetty-supported unloading line compared to conventional and alternative technologies and to quantify the resultant potential material, design and construction cost savings.
Innovation In LNG Transportation
LNG is created when natural gas is cooled from ambient temperatures to less than minus 160oC. The cooling is performed in large industrial (liquefaction) plants that take gas gathered from contiguous fields and process it for despatch via vessel. The vessels themselves contain from approximately 80,000-145,000 cubic meters of LNG (M.W. Kellogg; LNG Terminals 2002), which is then transported to receiving terminals (re-gasification plants) worldwide.
As demand for energy increases LNG technology is being increasingly used to exploit reserves of “stranded gas.” LNG technology is expensive but for distances greater than 1,000 km, it represents the most economical method to transport natural gas. For lesser distances, gas can be transferred in high-pressure pipelines.
Thus far, LNG installations have been politically sensitive for a number of reasons, not least the question of safety. Large volumes of gas stored in liquid form present a potential catastrophe should the incorrect approach to design and specification be taken. As such, there is pressure on LNG-processing plants to be remote from habitation. Furthermore, the potential risks involved in the transfer of LNG from plant to vessel are managed by locating and performing the loading operation remote from the plant and in deeper water berthing. This requires a pipeline to move the LNG safely from the plant to the vessel.
Material Choice And Design
There is now only one option to transfer LNG from the shore to the vessel – through a stainless steel rigid pipeline supported above sea level on a jetty. There are approved systems for running the pipeline subsea but, to date, such a system has not been applied in practice. The transportation of LNG presents the following challenges:
- Maintaining the low temperature of the product to prevent it re-gasifying on the way to the vessel.
- Selection of a pipeline material capable of resisting the low temperatures involved with the LNG processes.
- Conveying the pipeline from the shore out to the vessel.
The question of material choice and design is crucial to withstand the extreme temperature of the fluid within the linepipe while allowing efficient welding fabrication and construction. This ultra-low temperature would render carbon steel, the material of choice for most gas pipelines, brittle and susceptible to fracture and pipeline rupture. The extreme difference between the ambient temperature of the line and the temperature of the LNG causes the pipeline to contract considerably in length, thus inducing stresses into the pipe material itself, with the consequence of possibly exceeding the yield strength (or design code limits) of the material. Therefore, a suitable pipe material needs to be ductile at low temperature, able to withstand thermal stress and be readily welded. There are two materials considered for these installations:
- 36% nickel alloy steel.
- Stainless steel.
36% Nickel Alloy Steel
By alloying carbon steel with nickel the expansion/contraction of the material under extremes of temperature can be minimized. This minimization is optimum with the addition of 36% nickel to the product. At these levels of nickel the expansion is limited to 1.5 ?m/mK, which is less than a tenth that of stainless steel. It also has good fracture toughness properties at low temperatures. However, the high alloy content of this material makes it prohibitively expensive. Furthermore, it is difficult to weld and not readily available.
Stainless steel (304L) – as compared to 36% nickel alloy steel – retains the fracture toughness requirements, is readily available and can be purchased at a lesser cost. However, this material has a much greater thermal expansion coefficient, meaning the stresses in the line need to be managed appropriately. This has traditionally been achieved by including expansion loops in the pipeline at regular intervals along the route length. Through these loops and complex pipeline mountings, the stresses in the line are managed and – through prescribed displacements – stress alleviation can be achieved. The pipeline can therefore be designed to be suitable for these systems. Stainless steel has become the material of choice for these installations, despite the excessive cost of large supporting jetty construction.
9% Nickel Alloy Steel Pipeline
In response to the limitations of 36% nickel alloy steel and stainless steel, Corus Tubes has invested its efforts into the development of 9% nickel pipeline material. This material has thermal expansion properties that lie between stainless steel and 36% nickel alloy steel. However, the strength of the 9% alloy is more than three times higher than the other materials and can withstand much greater internal stresses before it reaches its design code/yield limit. The material is available in plate form for pipe construction and is already used in the construction of LNG vessels. With the application of careful design, 9% nickel pipelines can be designed with the following cost savings and benefits:
- Complete removal or significant reduction in the number of required expansion loops compared to a stainless steel solution.
- Readily available plate material for pipe.
- Lower cost base material.
- Proven weldability.
To understand the benefits that the material could offer a typical LNG pipeline, Corus Tubes commissioned J P Kenny to study the material and see how it compared in performance to the other materials (Figure 1).
Figure 1: Table of material properties.
The limitations of a pipeline design are determined by the application of piping and pipeline codes as demonstrated in Figure 2. Because there are no specific codes for LNG pipelines, an assessment of relevant existing codes was made to determine which was the most applicable for LNG design. The report chose the most conservative of these codes: ASME B31.3, B31.4 and B31.5; a risk assessment of particular projects could elect some less conservative assumptions for the design. However, even with these harsh limitations on allowable stress, the benefits of the 9% nickel material were clearly demonstrated.
Figure 2: Summary comparison of the piping and pipeline code allowable stress levels.
For a typical LNG-unloading pipeline, the study explored the maximum pipeline length that could be allowed before stress relief was required by way of an expansion spool. This model was applied to each material with a representative 24-inch pipeline nominal diameter and 10-mm wall thickness. A simple L-spool end configuration was considered (Figure 3). The dimensions of these spool configurations were optimized for improved performance. However, the design was not optimized for any individual material as the main focus of the study was to understand how the materials compare.
Figure 3: Spool configuration for Finite Element Analysis (FEA).
The results demonstrated that the spool configuration is key to the maximum allowable pipeline length for each of the materials. An indicative comparison of the performance of these materials is given in Figure 4.
Figure 4: Comparison of pipe material performance to ASME B31.4.
In this simple model applied by J P Kenny the relative performance of each material is clearly demonstrated. The 36% nickel, without complex design, never reaches its yield and should not require expansion loops in any realistic installation. This is an incredible claim for the material, but the costs of the material and welding difficulties make its use prohibitive as well as over-engineered for many applications.
Without spool optimization the application of the 9% nickel pipe material was found to reduce the number of expansion loops by more than three-fold compared to stainless steel pipelines. Thus, for many jetty designs, expansion loops may be eradicated completely, particularly with a less conservative choice of code.
The study then proceeded to consider further optimization of the 9% nickel design only. For this design, larger spool geometries were chosen but only at pipeline ends where jetties normally increase in size. These spool configurations and pipeline lengths are given in Figure 5 and the results are shown in Figure 6. From this analysis it was found that – through spool optimization – intermediate loops could be eradicated altogether for a pipeline length of up to 2 km.
Further benefits could be considered by looking at spool pre-stressing, flexible end connectors or pipe-in-pipe systems. The applicability of each of these approaches would depend on each pipeline design. Due to the weldability of 9% nickel, when these benefits are added to the improved site construction pipeline, it is clear that this material could offer significant savings to LNG plant construction.
Figure 5: Spool configurations.
Figure 6: Maximum stress results for each spool configuration.
J P Kenny applied its experience in the pre-estimation of the cost of these constructions to analyze the potential cost savings by using 9% nickel material. The study looked at the material cost savings of removing spools from a jetty pipeline and showed that material costs of jetties and pipelines could be reduced by over 12% for a typical 2.5-km jetty compared to conventional stainless steel construction.
Manufacturing 9% Nickel Pipe
Corus Tubes manufactures 9% nickel alloy steel pipe on its UOE double-submerged arc welded (DSAW) mill in Hartlepool, UK. The mill takes plates of 9% nickel material and progressively forms the pipe by processes of crimp, U press and O press. The facility is predominantly used for carbon steel pipe forming and at this stage a carbon steel pipe would be welded to form the finished pipe in one multi-wire pass. However, this process is not suitable for such highly alloyed steels. Instead, the pipe is only continuously tack-welded inline. Next, it is taken to another processing line where it is welded using a multi-pass procedure.
The welding process has been developed to generate material properties in the weld that exceed those in the parent plate while maintaining low temperature toughness.
Comparison of 9% nickel alloy steel with 304L stainless steel shows that 9% nickel pipe enables a significant reduction in the number of required expansion hoops, delivering time and cost savings to the client. When compared to a 36% nickel solution, the 9% nickel pipe offers significant savings on material cost and subsequent on-site welding. A study by J P Kenny also has demonstrated that, by careful consideration of design and risk at the start of a project evaluation, it is possible to use 9% nickel to deliver useful solutions for LNG transfer that will further increase the viability of the technology.
Richard Freeman is a business development manager with Corus Tubes and a member of the Institute of Mechanical Engineers. He graduated from the University of Leicester in 1992. He joined the company in 2004 as a development engineer. He played a major role in the development of the company’s pipe-in-pipe capabilities at Hartlepool, UK.
Steve Langford has more than 11 years of working experience for J P Kenny in offshore oil and gas related pipeline projects and is a multi-disciplined project/engineering manager. His experience encompasses all aspects of pipeline design, procurement, construction, installation and maintenance. He is a principal member of the firm’s R&D and Technology departments.