FIELD OF THE INVENTION

The present invention relates to an apparatus and method for transfer of a cryogenic fluid and more particularly, but not exclusively, to an apparatus and method for transfer of a cryogenic liquid to a ship for transportation.

BACKGROUND TO THE INVENTION

The applicant has identified that, currently, cryogenic liquids as cold as -163°C (for example, liquid natural gas) are loaded onto ships using insulated pipelines on jetties to loading arms. However, the applicant has also identified that jetties are expensive to build and maintain, especially as they may need to be a substantial length to go from land to a water depth suitable for large cryogenic liquid carrier ships.

Examples of the present invention seek to provide an apparatus and method for transfer of cryogenic fluids which alleviate or at least ameliorate the disadvantages of existing technologies for transfer of cryogenic fluids.

SUMMARY OF THE INVENTION

In an aspect, the invention provides an apparatus for transferring liquid hydrogen between an onshore source and an offshore terminal in the absence of a jetty, comprising a pipeline that extends between the source and the terminal; wherein the pipeline includes a first pipe that is adapted to carry the liquid hydrogen subsea from the source to the terminal and a monitoring system that is configured to monitor pressure within an interior volume of the first pipe to detect leaks of the liquid hydrogen within the pipeline.

In a further aspect, the invention provides a method for transferring liquid hydrogen between an onshore source and an offshore terminal in the absence of a jetty, including the steps of: providing a pipeline that extends between the source and the terminal, the pipeline including a first pipe that is adapted to carry the liquid hydrogen subsea from the source to the terminal; installing at least a portion of the first pipe subsea; and monitoring and internal pressure of the first pipe with a pressure sensor to detect leakage of liquid hydrogen within the pipeline.

Described generally herein is an apparatus for transferring a cryogenic fluid, including a subsea pipeline for loading cryogenic fluids from an onshore source to an offshore terminal, wherein the subsea pipeline includes insulation. Preferably, the insulation is in the form of a high integrity insulation.

In a preferred form, the apparatus is used in the absence of a jetty.

Preferably, the subsea pipeline includes an inner pipe housed within an outer pipe. More preferably, an annular volume is defined between the inner pipe and the outer pipe. Even more preferably, the annular volume has a partial vacuum therein. In one form, the annular volume houses the insulation.

In a preferred form, the cryogenic fluid is in the form of liquid hydrogen.

In accordance with an embodiment, there is provided an apparatus for transferring a cryogenic fluid, including a subsea pipeline for loading cryogenic fluids from an onshore source to an offshore terminal, wherein the subsea pipeline includes an inner pipe housed within an outer pipe.

Preferably, an annular volume is defined between the inner pipe and the outer pipe. More preferably, the annular volume has a partial vacuum therein. Even more preferably, the annular volume houses an insulation material.

Preferably, the inner pipe is formed of a material having a low coefficient of thermal expansion. More preferably, the inner pipe is formed of a nickel-iron alloy. Even more preferably, the inner pipe is formed of FeNi36 or Invar (material distributed under the trademark Invar).

In a preferred form, the cryogenic fluid is in the form of liquid hydrogen.

In accordance with another embodiment, there is provided a system for transferring a cryogenic fluid, including an onshore source of cryogenic fluid, an offshore transportation terminal, and a pipeline arranged to transfer the cryogenic fluid from the onshore source to the offshore transportation terminal, wherein the pipeline has at least a portion extending beneath sea level and wherein the pipeline includes insulation.

Preferably, the pipeline includes an inner pipe housed within an outer pipe. More preferably, the insulation is housed in an annular volume between the inner pipe and the outer pipe so as to insulate the inner pipe.

In a preferred form, the cryogenic fluid is in the form of liquid hydrogen.

In accordance with another embodiment, there is provided a method for transferring a cryogenic fluid, including the steps of providing a pipeline having insulation, installing the pipeline between an onshore source of cryogenic fluid and an offshore transportation terminal, and using the pipeline to transfer the cryogenic fluid along the pipeline from the onshore source to the offshore transportation terminal.

Preferably, the cryogenic fluid is in the form of liquid hydrogen.

BRIEF DESCRIPTION OF THE DRAWINGS

Preferred embodiments of the invention will be described, by way of a non-limiting example only, with reference to the accompanying drawings in which:

Figure l is a diagrammatic view of a system for transferring a cryogenic fluid from an onshore source to an offshore transportation terminal in accordance with an example of the present invention;

Figure 2 shows loading lines (pipe in pipe) and a vapour return line (pipe in pipe) of an example system for transferring a cryogenic fluid from an onshore source to an offshore transportation terminal; and

Figure 3 is cross sectional view of a liquid hydrogen line in accordance with an example of the present invention.

DETAILED DESCRIPTION

With reference to Figures 1 to 3 of the drawings, there is shown an apparatus 10 for transferring a cryogenic fluid in accordance with an example of the present invention. Advantageously, the apparatus 10 removes the requirement for near shore jetty construction along with the associated dredging for construction of the jetty, and the requirement for dredging to increase water depth for ship carrier access.

More specifically, with reference to Figure 1, there is shown an apparatus 10 for transferring a cryogenic fluid, the apparatus 10 including a subsea pipeline 12 for loading cryogenic fluids from onshore piping 26 of an onshore source 14 to an offshore terminal 16. In the example shown, the offshore terminal 16 is in the form of a fixed terminal 28 and the subsea pipeline 12 extends upwardly from the seafloor to the fixed terminal 28 by way of rigid risers 44. Marine loading arms 30 may be used to assist in transferring the cryogenic fluid to a carrier in the form of a cryogenic liquid carrier 24. The subsea pipeline 12 includes insulation 18 (see Figure 3). The insulation 18 may be provided in the form of a pipe-in pipe system with high integrity insulation between the pipes.

Advantageously, the apparatus 10 may be used in the absence of a jetty. For example, with existing apparatus for transferring cryogenic fluids to a carrier ship, a jetty is built from the shore to the mooring for the ship such that the pipe for transferring the cryogenic fluid is supported above sea level along the jetty. Building of the jetty is costly and may have a significant environmental impact during construction. It is of benefit that the present invention obviates the need for such a jetty to be built.

The cryogenic fluid may be in the form of liquid hydrogen for which the operating temperature is -253°C. Figure 2 shows detail of an apparatus 10 for transferring a cryogenic fluid in the form of liquid hydrogen. In the example shown in Figure 2, the apparatus 10 includes twin loading lines (pipe in pipe) 20 as well as a vapour return line (pipe in pipe) 22. As can be seen in Figure 2, there is provided a recirculation loop 46 using the loading lines 20 for recirculating the cryogenic fluid between loading operations. The cryogenic liquid carrier ship 24 depicted in Figure 1 is moored at the offshore terminal 16 for transporting the cryogenic fluid. Each of the loading lines 20 and the vapour return line 22 is in the form of a pipe-in-pipe (PIP) line.

Figure 3 is a diagrammatic cross-section of the liquid hydrogen line.

As can be seen in the export line cross-section 42 in Figure 3, the subsea pipeline 12 may include an inner pipe 32 housed within a first pipe in the form of an outer pipe 34. In the example shown, an annular volume 36 is defined between the inner pipe 32 and the outer pipe 34. The annular volume 36 has a partial vacuum therein which may assist with the performance of the insulating material of the insulation 18 which is housed in the annular volume 36.

The inner pipe 32 may be formed of a material having a low coefficient of thermal expansion. In particular, the inner pipe 32 may be formed of a nickel-iron alloy. In one example, the inner pipe 32 may be formed of FeNi36 or Invar. Advantageously, Invar is a nickel-iron alloy notable for its uniquely low coefficient of thermal expansion. The name Invar comes from the word "invariable", referring to its relative lack of expansion or contraction with temperature changes. The outer pipe 34 may be formed of low-temperature carbon steel (LTCS) and may be provided with a coating system 40 formed of 3LPE material (3-layer polyethylene). The coating system 40 may be used to protect the subsea pipeline 12 from external corrosion. A cathodic protection in the form of sacrificial anodes or impressed current cathodic protection (ICCP) may also be used. There may also be provided a steel shaft 48 between the outer pipe 34 and the insulation 18.

With reference to Figures 1 and 2, another aspect of the present invention resides in a system which includes the onshore source 14, the offshore terminal 16 and the subsea pipeline 12 arranged to transfer the cryogenic fluid from the onshore source 14 to the offshore transportation terminal 16. As can be seen clearly in Figure 1, although opposite ends of the pipeline 12 are above sea level, an intermediate portion of the pipeline 12 is beneath sea level.

Another aspect of the present invention provides a method for transferring a cryogenic fluid. The method includes the steps of providing a pipeline 12 having insulation 18, installing the pipeline 12 between an onshore source 14 of cryogenic fluid and an offshore transportation terminal 16, and using the pipeline 12 to transfer the cryogenic fluid along the pipeline 12 from the onshore source 14 to the offshore transportation terminal 16.

Examples of the invention remove the requirement for near shore jetty construction along with the associated dredging for construction of the jetty, and dredging to increase the water depth for ship carrier access. The concept allows transfer of cryogenic liquid hydrogen via a subsea pipe to a fixed structure (for example, a fixed berth structure and moorings) at a suitable water depth. This fixed structure can provide mooring and a point for the carrier (for example, a carrier ship) to connect and unload as it would at a conventional jetty/wharf.

The concept allows for transfer of liquid hydrogen without excessive boil off and loss of product by utilising a pipe-in-pipe construction with a partial vacuum plus insulation in the annular gap.

Examples of the invention may address problems such as the high costs associated with dredging and jetty construction, high environmental impact of dredging, and/or the social impact of near shore bulk flammable liquid transfer in populated areas/shipping routes.

In one example (see Figure 2), the subsea pipe configuration would consist of two loading lines 20 and a single vapour return line 22. Under normal operation, the two loading lines 20 act as a recirculation loop to maintain cryogenic temperature in the lines and remove any heat leak into the system. During loading, both lines are used to pump out the product from the onshore storage to a vessel 24 moored offshore. The displaced vapour from the ship is sent back onshore via the vapour return line 22.

Embodiments of the invention propose to use a system of continuous operation to ensure the cryogenic subsea pipeline is maintained at a cryogenic temperature with appropriate monitoring. Continuous operation and monitoring can be achieved during normal operation by diverting product flow from the liquid hydrogen production plant via our crossover connection at the end of the loading lines before being sent to storage and using additional equipment to pump a small flow from product storage outside of normal liquid hydrogen production periods.

Integrity of the pipeline is ensured through the use of specific material (which may be in the form of material distributed under the trade mark Invar). Such material may be chosen to withstand hydrogen embrittlement at low temperatures and have a low coefficient of expansion resulting in lower thermal stress loads on the system and a simpler design with respect to expansion joints/loops and transition joints. The use of the Invar material allows for a continuous inner pipe and partial vacuum annulus. The use of Invar material is beneficial as it has a low coefficient of expansion and therefore has a simpler configuration as it does not require expansion loops and joints to deal with changes in temperature and the associated family driven stresses. However, the applicant has identified that the use of Invar for the proposed subsea pipelines may bring with it a significant expense which may possibly be avoided or at least reduced. In particular, the applicant has identified that the material and insulation system used for the piping could be substituted for a lower grade material and a simpler insulation system that does not rely on the use of a partial vacuum. For example, instead of Invar material, high nickel content stainless steel (lower nickel content than Invar) may be used. Such material may provide a benefit in material cost, with further cost savings being available by using conventional insulation rather than a pipe-in-pipe system.

The applicant has identified that this may be catered for by providing more monitoring and operational control to ensure the thermal cycling of the system is minimised. Also, the applicant has identified that a variation of the invention may implement a dual use vapour return line and recirculation line to reduce total number of subsea pipelines. Examples of the invention may also use a circulation system for maintaining cryogenic temperatures.

Under normal operation, the line is maintained at cryogenic temperatures via a circulation loop which will reduce any transient thermal stresses between loading operations that can occur as cryogenic systems are cycled in temperature.

As the majority of the concept is located under water, examples of the invention also propose to use a system where the state of the loading system is constantly monitored to provide data in lieu of visual inspections which are commonplace for above ground piping systems.

Real time cryogenic loading system monitoring may be implemented to provide continuous real-time online monitoring and support alarm and alert capabilities to assist in the safe and efficient operation of the loading lines. The system may be based on a transient network flow model, which may use measured process data including temperature, pressure and velocity from redundant field sensors as boundary conditions. Revision of the boundary conditions over time is required in the case of sensor failure or drift. The model results shall provide a complete picture of the current state of the loading line in real time. Field data for the model shall be sampled automatically from a plant instrumented control system via a process integrity management system at a sufficient frequency for accuracy requirements. Additional measurements may be provided for redundancy and to help increase the integrity of the instrumented monitoring solution.

The parameters for monitoring may include: pressures and temperatures along the length of offloading system, discharge pressure, valve states for normal operation valves in the flow path, volume, flow velocity.

As will be appreciated from the above, the applicant has developed a system for loading cryogenic liquids (such as liquid hydrogen) to ships without the need for a jetty and associated dredging.

The system comprises a heavily insulated pipeline consisting of a pipe-in-pipe construction and a high integrity insulating material in the annulus formed between the inner pipe and the outer pipe. The pipeline will be installed using offshore pipeline installation technology and connected to a terminal which can provide both mooring for the ship and loading of the liquid.

The following four aspects may be implemented:

1. Use of marine technology for liquid hydrogen loading

2. Material substitution of stainless steel for high nickel "Invar"

3. Reduction of the number of pipelines from 3 to 2 by pressure boosting and creating dual use for a vapour return line

4. Use of cryogenic flexible pipe for commercial flowrates of liquid hydrogen.

In one aspect, the apparatus implements a dual use vapour return and liquid circulation line. The subsea pipe configuration is proposed to consist of a single loading line and a dual use single vapour return and recirculation line. Under normal operation, the loading line and vapour return/circulation line act as a recirculation loop to maintain cryogenic temperature in the lines and remove any heat leak into the system. During loading, the single loading line is used to pump out the product from the onshore storage to a vessel moored offshore. The displaced vapour from the ship is sent back onshore via the vapour return line. It is understood, therefore, that the displaced vapour within the return line can serve as a refrigerant to maintain cryogenic temperature within the loading line to effectively manage and/or reduce boil-off and associated product loss.

In order to remove the liquid and allow the flow of returned vapour from the recirculation line, additional compression onboard the carrier is required. Liquid hydrogen carriers are under development and additional compression facilities can be considered to allow for this mode of operation. Alternatively a suitable compressor located at the ship mooring location could be used. Facilities to handle the returned liquid along with any additional vapour generated in the line may be included in the onshore facilities. Accordingly, an example system has been developed for exporting hydrogen via vessel loading pipeline systems. The applicant proposed to provide ahydrogen carrier case to transfer Liquid Hydrogen (LH2) at -253°C, loading 80,000m ³ in 36 hours. It will be appreciated by those skilled in the art that the loading volume and duration may vary in other examples. EXAMPLE

LH2

The principal challenge associated with the export of liquid hydrogen is the need to operate at and maintain the cryogenic design temperature of -253°C. This introduces the requirement for the use of low thermal expansion Invar material (material distributed under the trademark Invar) as part of a Pipe-in-Pipe (PiP) system, sized at 14” internally for export loading, with an additional 12” PiP line for vapour return and transportation of boil off gases.

As will be appreciated from the above, the applicant is has investigated opportunities to develop renewable energy resource opportunities, which involve the complete hydrogen value chain from power generation to hydrogen carrier loading to a carrier ship. Accordingly, the present invention provides concepts for cryogenic fluid to be loaded to a single point mooring/single buoy mooring located offshore and connected by a subsea pipeline. LH ₂ PIPELINE

The pipeline is in the form of a pipe-in-pipe (PIP) construction characterised by the use of a low expansion alloy inner pipe, microporous insulation in a controlled atmosphere and the absence of expansion loops. The system can be used subsea, fully constrained, and buried. The pipeline presents the following key advantages:

• Subsea and buried application.

• Optimal thermal performance.

• An inert insulation.

• Most compact PIP for a given thermal performance providing significant material cost savings, and easier handling on site.

• No expansion loops.

• Integrated leak detection system due to monitoring of annulus pressure.

• Key features include:

• A 36% NiFe inner pipe with a coefficient of thermal expansion (CTE) which is ten times lower than the CTE of stainless steel. The ultra-low CTE minimizes the expansion and contraction of the pipeline and thus mitigates the need for any expansion loops or bellows.

• Insulating material providing microporous insulation. In one form, the insulating material may provide improved thermal performance under reduced pressure (medium to low vacuum). · A continuous annulus along the entire pipeline length. The inner annulus operates at a reduced pressure between 10 and 20 mbar. The reduced pressure has three advantages: it increases the thermal performance of the insulation; it acts as a straightforward, robust, and very sensitive leak detection system.

An outer pipe designed for external environment and potential aggressions. • The system includes pipeline integrity monitoring based on continuous pressure monitoring of the annulus. Additionally, a fibre optic system can be included on the outer pipe to provide temperature profile for secondary leak detection and location.

PIPE CONSTRUCTION The inner pipe is made of 36NiFe alloy. It is ideally suited to cryogenic use, remaining ductile at low temperature and increasing in strength. The coefficient of thermal expansion of 36% Ni-Fe is approximately 10 times less than stainless steel and as such internal bellows and expansion loops are not required. The pipe is typically longitudinally welded. Insulation is wrapped around the inner pipe and fastened using a thin steel sheet.

The steel sheet serves to hold the insulation in place, and to facilitate insertion during fabrication. The insulating material is compressively strong and no discrete spacers are required between the inner and outer pipe. The annulus between the pipes forms a closed space, and the pressure is reduced to approximately 10 mbar. Monitoring of the annulus pressure provides a sensitive leak detection system and on-line indicator of the system integrity.

The insulation may be supplied in panels, which are wrapped around the inner pipe and covered with a thin steel sheet.

The outer pipe is made of low-temperature carbon steel, and it is designed to resist external loads. The pipe may have a Charpy Impact test requirement based on the low temperature design temperature. The pipe is typical seamless or longitudinally welded. The outer surface has an anti-corrosion coating.

Optional - A fibre optic, deploying Distributed Temperature Sensing technology, may be used to provide the temperature profile along the pipeline. Strapped to the outer pipe, this fibre optic will indicate the temperature of the outer pipe. Under normal operations, the temperature profile will be close to ambient temperature. Localised cooling is an indication of a potential pipe leak. The cold spot chainage is also indicated, providing leak location. The fibre optic provides an additional layer to the leak detection, present through pressure monitoring. The fibre optic cable is design for the external environment, with the necessary mechanical protection.

The PIP pipeline is protected from external corrosion with a coating system on the outer pipe. The coating is typically an epoxy or three-layer system, like 3LPE. In addition to the coating, a cathodic protection in the form of sacrificial anodes or impressed current is used. In addition to the above components, the PIP system also includes bends and bulkheads. In-line bulkheads serve to link the inner and outer pipes together, so the system expands and contracts as a system. The bulkheads may be used as a way to make transitions between pipeline and risers. Detail of the bulkheads may be designed and qualified to make the structure mechanically robust for the life of the operation.

PIPELINE INTEGRITY MONITORING SYSTEM

The proposed pipeline integrity monitoring system is based on the continuous pressure monitoring of the annulus (between the inner and outer pipes), which detects leaks and differentiates between leaks in any of the pipe walls. Since the annulus being monitored is a closed volume, this leak detection methodology is orders of magnitude more sensitive than conventional pipeline integrity monitoring systems. Additionally, an optional fibre optic system can be included on the outer pipe to provide secondary leak detection and location. The fibre optic provides the temperature of the outer pipe along the entire length of the pipeline, for example at 1 m intervals with an accuracy of ±1°C.

There are several key features including:

• The annulus is sealed so that arbitrarily small leaks will eventually be detected.

• The annulus will be continuous between isolation valves. It should be highlighted however, that the pipeline integrity monitoring system described here does not cover the areas of the vents, valves, drains, or nitrogen purges, where there is single pipe. Those areas will require separate monitoring systems. In-line bulkheads can be made with holes to allow pressure communication within the annulus. • The annulus operates at a reduced pressure. This reduced pressure has two advantages: it increases the thermal performance of the insulation; and it acts as a straightforward, robust, and very sensitive leak detection system.

• The outer pipe is designed to handle collapse, any potential external load and for double containment of the fluid. It should be noted that areas not covered by the intermediate and outer pipes (vents, valves, drains, & nitrogen purge lines) will not have double containment and thus leaks in these areas will be released into the environment.

• Monitoring the pressures in the annulus allows detection of leaks of the inner pipe or the outer pipe.

• The outer pipe has anti-corrosion coating.

• The fibre optic system located on the outer pipe is used to identify the location of an inner pipe leak.

In alternative examples of the present invention, an outside pipe may not be required.

Advantageously, the applicant has determined that the use of a subsea pipeline in accordance with an example of the present invention for loading cryogenic liquids to an offshore terminal where a jetty is not nearby provides a lower cost and lower impact facility than dredging and jetty construction. Accordingly, examples of the present invention may provide a solution which is significantly more environmentally friendly, does not require the manufacture of a jetty, avoids or eliminates dredging and does not require the clearing of forest. Designers of delivery infrastructure for liquid natural gas are typically familiar with onshore only (that is, without liquid natural gas pipes being wet) and subsea pipelines are generally not well understood by onshore system designers, particularly as the maintenance requirements are quite different. The applicant has overcome significant technical challenges by combining high integrity insulation with subsea pipelines, shore crossings and offshore connections by way of the present invention.

The applicant has identified that pipelines and, in particular, pipelines using Invar material, have not previously been used for subsea transfer of liquid hydrogen (-253°C). Advantageously, the present invention enables use of a pipe for subsea transfer of liquid hydrogen for large flow through a relatively large diameter.

Examples of the present invention may provide the following advantages:

- Significant cost reduction and schedule improvement for a jetty-less solution; - Reduced social impact by locating the terminal away from shore;

- Improved safety by locating the hazardous liquid transfer in a buried pipeline;

- Flexibility of ship loading location away from the shore; and

- Reduced marine construction requirements.

While various embodiments of the present invention have been described above, it should be understood that they have been presented by way of example only, and not by way of limitation. It will be apparent to a person skilled in the relevant art that various changes in form and detail can be made therein without departing from the spirit and scope of the invention. Thus, the present invention should not be limited by any of the above described exemplary embodiments. The reference in this specification to any prior publication (or information derived from it), or to any matter which is known, is not, and should not be taken as an acknowledgment or admission or any form of suggestion that that prior publication (or information derived from it) or known matter forms part of the common general knowledge in the field of endeavour to which this specification relates.

LIST OF REFERENCE NUMERALS

10 Apparatus for transferring a cryogenic fluid

12 Subsea pipeline 14 Onshore source

16 Offshore terminal 18 Insulation 20 Loading lines (pipe in pipe) 22 Vapour return line (pipe in pipe) 24 Carrier in the form of cryogenic liquid carrier ship

26 Onshore piping 28 Fixed terminal 30 Marine loading arms 32 Inner pipe: Invar 34 Outer pipe: LTCS (low-temperature carbon steel)

36 Annular volume 40 Coating system: 3LPE (3 -layer polyethylene) 42 Export line cross-section 44 Risers 46 Recirculation loop (using loading lines)

48 Steel shaft