PIANC Marcom WG172 LNG Terminals

PIANC

Report n° 172 - 2016

DESIGN OF SMALL TO MID-SCALE MARINE LNG TERMINALS INCLUDING BUNKERING The World Association for Waterborne Transport Infrastructure

PIANC

The World Association for Waterborne Transport Infrastructure

PIANC REPORT N° 172 MARITIME NAVIGATION COMMISSION

DESIGN OF SMALL TO MID-SCALE MARINE LNG TERMINALS INCLUDING BUNKERING 2016

PIANC has Technical Commissions concerned with inland waterways and ports (InCom), coastal and ocean waterways (including ports and harbours) (MarCom), environmental aspects (EnviCom) and sport and pleasure navigation (RecCom). This report has been produced by an international Working Group convened by the Maritime Navigation Commission MarCom). Members of the Working Group represent several countries and are acknowledged experts in their profession. The objective of this report is to provide information and recommendations on good practice. Conformity is not obligatory and engineering judgement should be used in its application, especially in special circumstances. This report should be seen as an expert guidance and state-of-the-art on this particular subject. PIANC disclaims all responsibility in case this report should be presented as an official standard.

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TABLE CONTENTS 1 2 3 4

Background ...................................................................................................................... 3 Definitions ........................................................................................................................ 5 Scope of the Guideline ................................................................................................... 7 Working Group ................................................................................................................ 9 4.1 Members of the WG ...................................................................................................... 9 4.2 Meetings of the WG ..................................................................................................... 10 5 Concept of Operations, Functional Requirements and Basis of Design ................. 11 5.1 Concept of Operations ................................................................................................ 15 5.1.1 Marine Terminal Responsibility Matrix ................................................................ 15 5.2 Functional Requirements ............................................................................................ 16 5.3 Basis of Design............................................................................................................ 16 6 Terminal Planning ......................................................................................................... 18 6.1 Site Selection............................................................................................................... 18 6.2 Site Investigation ......................................................................................................... 19 6.3 Terminal Layout ........................................................................................................... 19 6.4 Cost Considerations .................................................................................................... 20 7 Environmental Conditions ............................................................................................ 22 7.1 Data Requirements...................................................................................................... 22 7.2 Data Collation .............................................................................................................. 22 7.3 Field Data Collection ................................................................................................... 22 7.4 Analysis and Modelling ................................................................................................ 23 8 Navigational Aspects .................................................................................................... 24 8.1 Risk Assessment for Development of Policies and Procedures for Navigation .......... 24 8.2 Towage and Pilotage ................................................................................................... 25 8.3 Approach Channel Design .......................................................................................... 26 9 Berthing & Mooring ....................................................................................................... 27 9.1 General Principles ....................................................................................................... 27 9.2 Berthing ....................................................................................................................... 27 9.3 Mooring ........................................................................................................................ 29 9.4 Alternative Mooring Solutions ...................................................................................... 30 10 Terminal Infrastructure & Equipment .......................................................................... 32 10.1 Infrastructure Components .......................................................................................... 32 10.2 Loading & Unloading Systems .................................................................................... 32 10.2.1 The (Un)loading Operation .................................................................................. 32 10.2.2 LNG Transfer System Concepts ......................................................................... 32 10.2.3 Design Aspects of Marine (Un)loading Systems ................................................. 34 10.2.4 Control and Safeguarding of the LNG Transfer .................................................. 35 10.2.5 Safety Equipment During the LNG Transfer........................................................ 35 10.3 Storage and (Un)loading Points .................................................................................. 37 10.4 Security and Access Facilities ..................................................................................... 38 11 Loads, Loads Combinations and Design Codes ........................................................ 39 11.1 Design Codes .............................................................................................................. 39 11.1.1 Code Order of Precedence ................................................................................. 39 11.2 Loads ........................................................................................................................... 40 11.2.1 Non-Marine Gravity and Lateral .......................................................................... 40 11.2.2 Marine .................................................................................................................. 41 11.3 Load Combinations...................................................................................................... 42 11.4 Displacement Limits .................................................................................................... 42 12 Risk Assessment ........................................................................................................... 43 12.1 Reference Documents for Assessing the Risk at LNG Terminals .............................. 44 12.2 Risk Assessment Methodology ................................................................................... 44 12.3 Hazard & Scenario Identification ................................................................................. 45 12.4 Risk Evaluation ............................................................................................................ 46 12.4.1 Qualitative Risk Assessment. .............................................................................. 47

12.4.2 Quantitative Risk Assessment ............................................................................. 49 13 Safety Management ....................................................................................................... 51 13.1 General ........................................................................................................................ 51 13.2 Requirements for Operations, Systems and Components .......................................... 51 13.3 Requirements to Contain and Control Hazardous Situations...................................... 52 13.4 Emergency Contingency Plan ..................................................................................... 52 14 Inspection and Maintenance ........................................................................................ 53 14.1 Inspection and Maintenance Philosophies .................................................................. 53 14.2 Inspection and Maintenance Strategies ...................................................................... 53 14.3 Guidelines for Civil and Marine Infrastructure Inspection and Maintenance ............... 54 14.3.1 Navigational Infrastructure .................................................................................. 54 14.3.2 Shore and Scour Protection ................................................................................ 54 14.3.3 Concrete Structures ............................................................................................. 55 14.3.4 Steel Structures ................................................................................................... 55 14.3.5 Coating and Painting ........................................................................................... 56 14.3.6 Cathodic Protection ............................................................................................. 56 14.3.7 Elastomeric Bearings........................................................................................... 56 14.3.8 Fender Systems .................................................................................................. 56 14.3.9 Quick Release Hooks .......................................................................................... 57 14.3.10 Bollards ............................................................................................................ 57 14.3.11 Gangways ........................................................................................................ 57 15 Guidelines for Approach to Retrofit ............................................................................ 58 16 Concept of New Use ...................................................................................................... 59 17 Existing Condition Assessment .................................................................................. 60 21 General Overview .......................................................................................................... 67 21.1 Introduction .................................................................................................................. 67 21.2 Drivers for LNG as Bunker Fuel .................................................................................. 68 21.3 LNG Fuelled Vessels Routes ...................................................................................... 69 21.4 Available LNG Bunkering Facilities ............................................................................. 70 21.5 CNG Bunkering Facilities ............................................................................................ 72 22 Design Guidelines of LNG/CNG Supply Points at Existing/New Quays .................. 73 22.1 Greenfield Bunkering Facilities .................................................................................... 73 22.2 Brownfield Bunkering Facilities (Without Current LNG Operations) ........................... 73 23 Design Guidelines of LNG Bunkering Facilities at Existing/New Marine LNG Terminals ....................................................................................................................... 75 23.1 Scope & Definitions ..................................................................................................... 75 23.2 Functional Requirements/BOD .................................................................................... 75 23.2.1 Bunkering Facilities at Existing Conventional Terminals ..................................... 75 23.3 Safety Approach .......................................................................................................... 76 23.3.1 Bunker Barge Terminals ...................................................................................... 77 23.3.2 Truck Bunkering .................................................................................................. 77 23.4 General Remarks on Security ..................................................................................... 77 23.5 Operational Issues....................................................................................................... 78 APPENDIX A. Terms of Reference ................................................................................... 80 APPENDIX B. List of References ..................................................................................... 81 APPENDIX C. Ship Characteristics .................................................................................. 85

PART 0 – INTRODUCTION 1 BACKGROUND The conventional Liquefied Natural Gas (LNG) industry is mainly built around transporting gas from locations with large gas reserves but little local demand to regions desiring gas for power production. Conventional LNG trade consists of facilities which produce and liquefy LNG, large dedicated terminals, custom built vessels to transport LNG, and long-term customers who may regasify LNG for direct use or inject it into the gas grid. Recently, the market for LNG has shown openings for spot trading (for example as a substitute for nuclear power after Fukushima in 2011) and small-scale use of LNG; either for smaller customers such as peak shaving plants or as fuel for vessels. The potential of using LNG as an alternative fuel for ships is gaining momentum due to the recent IMO regulations (especially for the designated Emission Control Areas or ECAs) and as part of the debate of improving the environmental performance of shipping. Recent analysis demonstrates that in terms of operational performance LNG can be considered a viable alternative to marine fuel and results in zero SOx emissions and significant reductions of NO xand CO2 emissions. One of the challenges to the broad application of LNG as fuel is the required investments relating to adequate small to mid-scale infrastructure as well as the best practices and regulations to be applied to LNG bunkering. Nonetheless, in addition to the historic trend of increasing LNG carrier vessel size, new 1,000 to 50,000 m3 LNG carrier vessels and vessels using LNG as fuel are being built and operated. The start of the LNG business was marked by the Methane Princess shipping the first commercial LNG cargo from Algeria to the United Kingdom in October 1964. LNG industry growth between 1964 and 2000 was slow and deliberate, with less than 20 new projects in a dozen countries. The first LNG vessels in the 1960’s and 70’s had a capacity between 25,000 and 50,000 m3. During this period only a few vessels per year were delivered. In the 1970’s vessels from 70,000 to 90,000 m3 came on the market. At the same time 122,000 to 135,000 m3 vessels were constructed, of which many more were ordered than of the smaller sizes. From 1982 to the mid 1990’s hardly any vessels were ordered. In the late 1990’s the LNG business started to grow. Terminal tank storage also increased, leading the way to further increase vessel size to 137,000 to 145,000 m3. The number of vessel deliveries per year quadrupled in the 2000’s in comparison with the years prior. The vessel size increase continues with the 216,000 m3 Qflex and 266,000 m3 Qmax vessels and many LNG terminals coming on stream or being developed. The vast majority of the current fleet is over 122,000 m3. In 2015 the conventional LNG carrier order book predominantly showed 160,000 m3 to 177,000 m3 LNG vessels.

Figure 1.1: Global LNG Fleet by year of delivery versus average vessel size [courtesy: (IHS Inc), (IGU, 2015)]

Figure 1.2: Active global LNG Fleet by capacity and age, end-2014 [Courtesy: (IHS Inc), (IGU, 2015)]

Half a century after the onset of the LNG business, the safety record of the industry is outstanding. LNG has a reputation of being hazardous, which has resulted in a strict regime around dedicated large scale LNG terminals. Due to the environmental drivers and small scale applications for LNG (for power or fuel) the number of LNG terminals, notably small to medium scale terminals, will increase significantly. Small to mid-scale operations are being developed in isolation as well as being integrated into existing terminals. This change in industry focus and these terminals being out of scope of existing LNG codes and standards necessitates the development of this design guideline for small to mid-scale LNG terminals which covers the specific marine terminal infrastructure design aspects of this new LNG market segment.

2 DEFINITIONS Definitions of the terms which explain the scope of this guideline are provided in this section. Liquefied Natural Gas consists of primarily methane and may contain small amounts of ethane, propane and butane. When cooled to -163°C natural gas shrinks to less than 1/600th of its volume and becomes a liquid, making storage and transporting LNG economically attractive. This cryogenic temperature results in specific design challenges. Refrigeration is required for liquefaction, pressure alone is insufficient. Compressed Natural Gas (CNG) is made by compressing natural gas (which is mainly composed of methane), to less than 1/200th of the volume it occupies at standard atmospheric pressure. It is stored and distributed in hard containers at a pressure of 20-25 MPa, usually in cylindrical or spherical shapes. As of 2016 there are very few known examples of CNG in the shipping industry, most activity is taking place in concept design. Conventional or large scale LNG concerns LNG vessels with more than 70,000 m3 capacity used for global trade, as shown in Figure 2.1. They (un)load at terminals using predominantly fixed marine loading arms (cryogenic hoses are thus far not used for large scale LNG, the exception being offloading to certain FSRUs) with a diameter of 16” or bigger and often operate under longterm contracts. Generally the cargo is not divided into parcels, but completely (un)loaded at one terminal. The loading rate is typically 5,000 m 3/hr per arm, leading to an average loading rate of 10,000 to 12,000 m 3/hr with 3 liquid and 1 vapour return arm. Safety standards are high, which has resulted in hardly any incidents in the LNG industry. Small-scale LNG regards LNG vessels smaller than 50,000 m3 used for regional trade, as shown in Figure 2.1, (un)loading at terminals where the smaller vessels predominantly use 4” to 8” diameter hoses. Marine loading arms can also be used for transfer, with 2” to 12” piping. The loading rate typically does not exceed 2,000 m 3/hr per connection (1 arm or 1 hose) and is often much lower. Generally the cargo is divided into smaller parcels for different customers. Mid-scale LNG regards vessel in the range of 20,000 m3 to 90,000 m3 which can be used either for conventional LNG trade or for small scale LNG, as shown in Figure 2.1. Depending on whether the vessel is used for global or regional trade, the (un)loading rate, manifold size and connection points, line diameters and the parcel size, these vessels will either call on conventional largescale terminals or small to mid-scale terminals, the latter of which is the topic of this guideline. LNG or CNG bunkering is defined as the process of transferring LNG or CNG from a supplier to a consumer for the sole purpose of using it as a marine fuel. In the context of this document, bunkering relates to the transfer of LNG or CNG from a fixed supply point or bunkering vessel to the fuel tank of a moored receiving vessel. Ship-to-ship operations are outside the scope of this guideline. Small to mid-scale marine LNG terminals consist as a minimum of a fixed berth, transfer equipment capable of (off) loading LNG and/or CNG and auxiliary facilities to enable (off) loading operations. It may also have storage and/or (off) loading points. Transfer operations as described for small-scale LNG take place. A permanently moored barge, quay wall, jetty, FSRU (Floating Storage and Regasification Unit) or FSU (Floating Storage Units) are considered a fixed berth as the infrastructure is permanently set in location. LNG storage in the context of this guideline are conventional onshore LNG tanks, movable cryogenic containers designed to store LNG (ISO containers) which can be placed onshore or on a pontoon, or the cargo tanks of an FSU (often a barge or converted LNG carrier). Storage is part of the terminal and safely contains the LNG in between transfer operations. (Off)loading points are located at the shore side boundary of the terminal. They include truck or rail (off)loading facilities, cryogenic pipelines to local storage, or cryogenic or high pressure gas pipelines leading to a third party (either an LNG supplier or a customer). LNG vessels calling at a small to mid-scale terminal include dedicated carriers loading and offloading LNG (including bunker vessels and barges) or LNG fuelled vessels such as an inland barge or a ferry bunkering LNG for use as marine fuel.

Figure 2.1: Considered vessels in range of small, mid-sized and conventional LNG vessels Note: the ranges overlap as some smaller vessels are used for global (conventional) trade while some larger vessels are used for local/regional use

3 SCOPE OF THE GUIDELINE This Working Group document provides design guidelines for small to mid-scale LNG fixed terminals including LNG bunkering for designers and operators of marine LNG terminals and infrastructure worldwide. This guidance is given in order to provide a safe, efficient and costeffective operation of these terminals. The Terms of Reference for the Working Group are provided in Appendix A. This document should be considered as an additional document to existing standards, and thus covers only aspects of marine LNG terminal design specific for small to mid-scale terminals. Where relevant, references will be made to codes and standards covering design aspects for conventional (large-scale) LNG terminals and other petrochemical facilities which have been found to also apply to small to mid-scale LNG terminals. This guideline will apply to small to mid-scale terminals with the following modes of operations: 1) 2) 3) 4)

Terminal on standby (with no vessels alongside) LNG carriers offloading to storage or offloading point LNG carriers loading from storage or loading point Vessels bunkering LNG as fuel from storage or loading point

Figure 3.1 schematically shows the types of terminals covered by this guideline. In case the LNG transfer takes place at a fixed terminal, such as a permanently moored barge, quay wall, jetty, Floating Liquefaction Unit (FLU), Floating Storage Unit (FSU) or Floating Storage and Regasification Unit (FSRU), and it is classified as small to mid-scale, this guideline is applicable.

Figure 3.1: Scope included in the WG172 guideline

In case an LNG bunkering vessel supplies another vessel which is moored at a terminal with LNG, such as is the case when bunkering a container vessel at a quay (see bottom right sketch in Figure 3.1), only the effects of the transfer operation on the terminal infrastructure will be covered by this guideline. Bunkering operations itself are covered by other codes and standards, which will be referenced in part 3. Topics that are excluded from this guideline are:  

Conventional large scale LNG terminals LPG (off)loading

   

Vessel to vessel LNG transfer when vessels are not moored to any fixed port infrastructure and are not connected to the shore (See Figure 3.2a) Single Point Moorings (SPMs) and buoy (off)loading terminals (See Figure 3.2b) Bunkering procedures (See Figure 3.2c) Transport of LNG ISO containers

Figure 3.2: Scope excluded from the WG 172 guideline

This report consists of 3 parts in addition to this introduction: 





Part 1 covers the greenfield design of small- to mid-scale terminals and focuses on how they differ in design from conventional LNG terminals. The topics that will be covered are the functional requirements, environmental conditions, terminal planning, navigational aspects, berthing and mooring, terminal infrastructure and equipment, loads, load combinations and design codes, risk assessment, safety management and inspection and maintenance. Part 2 covers the retrofitting of marine terminals to include small- to mid-scale LNG facilities. It will provide guidelines for condition inspection, design checks and facility or operation alterations that are likely necessary to accommodate smaller LNG vessels at existing LNG terminals or marine terminals for other use. Part 3 will cover LNG and/or CNG bunkering at a marine facility either dedicated to bunkering or used for multiple purposes. Only the effect of the bunkering operation on the terminal infrastructure will be covered here, not the bunkering operation itself.

4 WORKING GROUP 4.1

Members of the WG

The Working Group has been comprised by the following members: Chairman Mr Ignacio Sanchidrián Vidal Managing Director MSc CEng EMBA PROES Consultores, S. A. EUROCONSULT GROUP General Yagüe, 39, 28020 Madrid Spain Email: [email protected]

Mr Bob Beasley, PE, PEng Moffatt & Nichol Senior Ports Engineer 3780 Kilroy Airport Way, Suite 600 Long Beach, CA 90806 USA Email: [email protected]

Mr Marc Percher, P.E. Moffatt & Nichol Senior Engineer 2185 N. California Blvd. Suite 500 Walnut Creek, CA 94596 USA Email: [email protected]

Mrs Suze Ann Bakker Shell Global Solutions International B.V. Civil Engineer Kesslerpark 1 2280 AB RIJSWIJK The Netherlands Email: [email protected]

Mr Jose Manuel García Head of Marine Terminal and Operation Division MSc CEng PROES Consultores, S. A. EUROCONSULT GROUP General Yagüe, 39, 28020 Madrid Spain Email: [email protected]

Mr Willem Hoebée Port of Rotterdam Authority Manager Marine Side Planning Wilhelminakade 909 3072 AP Rotterdam The Netherlands Email: [email protected]

Mr Iain Gunn HR Wallingford Technical Director, Oil & Gas Howbery Park, Wallingford, Oxfordshire OX10 8BA, United Kingdom Email: [email protected]

Mr Adam Sharp BEng (Hons) CEng MICE Atkins Principal Maritime Engineer Woodcote Grove Ashley Road Epsom Surrey KT18 5BW United Kingdom Email: [email protected]

Mrs Luciana das Neves IMDC nv International Marine and Dredging Consultants Engineer Advisor & Guest Assistant Professor at UPorto – CEng, MSc, PhD in Civil Engineering Van Immerseelstraat 66 2018 Antwerp Belgium Email: [email protected]

Mr Dominique Durand Elengy Marine Manager – Technical Department 11 av. Michel Ricard 92276 Bois-Colombes France Email: [email protected]

Mrs Sara Calvo MC VALNERA S.L.U. Director of Projects - MSc Civil Engineering San Blas, 2 Entlo. 15003 A Coruña Spain Email: [email protected]

Nominated WG mentor from MarCom was: Mr Rafael Escutia Port insight Managing Director Moll Princep D'Espanya 08001 Barcelona Spain Email: [email protected]

Figure 4.1: PIANC WG 172 Committee Members on site of an LNG Break Bulk Facility Construction

4.2

Meetings of the WG

The Working Group met 5 times before publishing this guideline:     

Madrid, June 24-25, 2014 Brussels, November 5-6, 2014 Rotterdam, May 19-21, 2015 Barcelona, November 3-4, 2015 Wallingford, March 8-10, 2016

PART 1 – GREENFIELD DESIGN OF SMALL TO MID-SCALE LNG TERMINALS 5 CONCEPT OF OPERATIONS, FUNCTIONAL REQUIREMENTS AND BASIS OF DESIGN The Concept of Operations provides a high-level overview of the purpose and objectives of the project, as well as a high level overview of how the facility is expected to operate. The Functional Requirements flow from the Concept of Operations and provide a high-level summary of the functional aspects that must be incorporated into the design. Finally, the Basis of Design follows from the Functional Requirements. While these subjects are separated for consideration of detailed components, they strongly influence each other, as shown in Figure 5.1. This approach is also generally used in the LNG industry for development of new facilities and is considered applicable for small- to mid-sized facilities; however, dependent on the specifics of the facility components, these concepts are subject to vary. The operational, functional and design basis documents are also subject to refinement and development over the project lifetime from site selection through first gas, as shown in Figure 5.2 and described in Table 5.1. Generally, the Functional Requirements and Concept of Operations should be refined early in the project and should be relatively firm prior to the design development or Front End Engineering Design (FEED) phase. Significant changes to either of these during design development can lead to delays in the design process as well or failure of the project to be developed. In many ways, this early phase is intended to weed out projects that are not feasible or economically viable. As much of the work at this phase is based on desktop studies, significant costs may not be incurred. A basis of design should be developed during the concept phase; however, this should be considered a living document which can change during design development. Once a project site, initial layout, and function are known, it is possible to do directed field investigations, such as metocean campaigns, borings and bathymetric surveying. The importance of these investigations cannot be understated in aiding the design development and resulting in an accurate cost estimate for use in making a Final Investment Decision (FID). Unless there is an ample supply of existing data, designers can be in a ‘rubbish in/rubbish out’ situation when developing the design, which can lead to overly conservative estimates from the designers and/or contractors, which may lead to the project not receiving funding. Once the project is funded for construction and/or given notice to proceed to construction from the owner, there may need to be additional field investigations (such as second round borings) to allow for value engineering/final design refinement. It is preferable to have undertaken field investigations prior to the investment decision being made as otherwise it will impact the schedule significantly. Following FID, the project will generally be schedule driven. Close coordination between the owner/operator and construction contractor is critical at this stage to ensure that the final construction is fit for purpose. Once the facility is certified, first gas operations can come online. For complex facilities or those where simultaneous operations occur, it may take several months or years after first gas for further refinement in operations to bring the facility to optimal availability and productivity.

 Required Infrastructure and Equipment  Design Life  Support & Servicing

Functional Requirements

 Process Selection  Vessel Type(s)

    

Purpose Deliverable Flows Region Stakeholders Phasing

Concept of Operations  Economic Viability

 Layout  Vessel Parameters

 Regulations  Performance / Availability  Risk

Basis of Design  Detailed Design Requirements

Figure 5.1: Relationship and Components of Functional Requirements, Concept of Operations and Basis of Design

roject Stage

Identification

“Engineering” Phase

Concept Screening

Level Of Project Definition End Usage (Purpose Of Estimate)

Initiate opportunity

Expressed As Percentage Of Complete Definition 0 % to 2 %

Assess Feasibility

Demonstrate feasibility of the opportunity

1 % to 15 %

PRE-FEED

Select best concept solution

10 % to 40 %

Define the selected concept. Finalise scope, Cost, Schedule and get project funded

30 % to 70 %

Selection

Definition

FEED

Execution

EPC

Evaluation

Asset management

Final Design

50 to 100 %

-

Start-up, operate and evaluate

-

-

Start-up, operate and evaluate

-

Content (Typical Deliverables/Studies To Be Executed)

Location and capacity of the facilities Site data collection Desk study Functional requirements Site selection study Site visit Metocean Basic study Layout study Preliminary Downtime Basis of design Concept development Survey specifications Preliminary Geotechnical Data Assist with Planning Assist with cost estimate HAZID Final Basis of Design Numerical studies Final downtime study Basic design of structures Pile driving analysis Assist with Planning Assist with cost estimate Perform final geotechnical studies HAZOP Detailed design of structures Site supervision/ management Participate in evaluation teams Review operations Manual/Compare with engineering Requirements Help define maintenance strategy Establish Periodic Inspection Procedures

Expected Accuracy Range

Class Estimation

L: -20 % to -50 % H:+30 % to +100 %

5

L: -15 % to -30 % H:+20% to +50 %

4

L: -10 % to - 20 % H:+10 % to +30 %

Peer review

3

L: -5 % to -15 % H:+5 % to +20 %

Peer review SI supervision

2

L: -3 % to -10 % H:+3 % to +15 %

ICE review

1

-

-

-

-

-

-

Table 5.1: Typical Requirements, Contents and Considerations for Engineering Phases

13

Checks/ Revisions

Functional Requirements

Concept of Operations

Refine

    

Meet with Stakeholders Desktop Studies Collection of Available Data Basis of Design Layout

Refine

Milestones

Concept / Site Selection /Pre-FEED

 Field Data Collection

   

Function and Concept “FINAL”

Site Specific Metocean / Geotech Basis of Design Detailed Engineering Availability Study

Design Development / FEED  More Field Data Collection

Basis of Design “FINAL” Financial Investment Decision Construction Award BOD and Functional Requirements Revisited

 Value Engineering  “FINAL” Design

Construction / EPC  Temporary / Phased Construction  Permanent Construction  Certification Certification Completed First Gas

Maintenance & Operational Refinement Figure 5.2: Flowchart of Project Development (Note: results may vary)

14

5.1

Concept of Operations

The following items are recommended to be addressed in the Concept of Operations: 1. The terminal has to be designed to reduce risk to as low as reasonably practical (ALARP) to ensure safety against minimum costs and schedule. 2. LNG volumes, storage requirements, and high-level overview of the business case/purpose of the terminal, including origin and high-level characteristics of the gas. Operability analysis will be implemented to determine throughput capacity. 3. Short-term vs long-term vision for the terminal in terms of volumes and target markets (scenarios) 4. Descriptions of the stakeholders involved and their roles and responsibilities in the terminal development process 5. Roles and responsibilities of the stakeholders in the operation of the terminal, including who will moor and unmoor vessels as well as who will operate the process equipment. 6. Roles and responsibilities of the stakeholders in the maintenance of the terminal, including fixed structures, process and non-process piping and equipment. A high level assessment of periodic downtime due to maintenance of facilities and equipment should be included. 7. High level overview of the terminal layout and configuration 8. Description of the types and combinations of vessels to berth at the terminal and whether they will be dedicated vessels, spot market vessels, or a combination. (Reference is made to APPENDIX AAPPENDIX C for ship characteristics.) Design of small scale ships are under development, which is one of the difficulties in the design of these terminals. The lack of clarity of what to design for applies to the vessel dimensions, manifold heights and positions, and other vessel particulars. 9. Description of any need for flexibility of the terminal to respond to different scenarios 10. Description of whether the terminal volumes will vary by season, and, if so, what the peak volumes will be. Also, description of whether the terminal will need to operate day and night or be restricted to certain hours of the day. 11. Description of whether the project will be built to full capacity initially or if it will be phased, and the anticipated timing of the phases. Definition of the project horizon lifetime in number of years. 12. High-level description of how the facility will operate, whether crews will live on or off site, whether the platform will be manned or not, and where control operations will take place for the terminal.

Marine Terminal Responsibility Matrix It is recommended as part of the Concept of Operations report that a matrix is developed to clearly identify identify the tasks, roles and responsibilities for both control stations and personnel operating the terminal. terminal. An example of this matrix for a mid-scale facility is shown in

Table 5.2. Note that not all items within this example are applicable to all projects and neither are all topics included.

Tasks Pre-Vessel Arrival Communication to vessel re: logistics issues Notification of 3rd party inspector of vessel arrival Vessel, terminal and transfer system compatibility Execute line pack and/or line cool down Post Vessel Arrival Oversee Vessel initial mooring Conduct ship/shore safety checklist discussion Marine Vapour Recovery set-up (if applicable) Tank line-up in preparation for loading (if applicable) Berth line-up in preparation for loading During Vessel Loading – Normal Operation Linked WARM ESD confirmation by both terminal and vessel after leak testing. Execute Line cool down and COLD ESD tests

15

Berth Operator

MTCC Operator

I R1 R (2)

R R R2 R (1)

R R R R

I R I

Tasks Execute slow start/reduced flow rate (if applicable) Execute full cargo flow rate Monitor mooring lines (if applicable) Maintaining communications with Vessel Monitor MVR ‘conditions/variables’ (if applicable) Make changes to MVR (if applicable) Monitor loading line pressure and flow rates Monitor weather conditions Monitor tank levels (if applicable) Monitor all elements from ship/shore safety checklist Initiate shutdown cargo loading Execute slow topping-off/reduced flow rates Nitrogen purge and disconnect arm or hose During Vessel Loading – Emergency Conditions Activation of ESD system due to an alarm condition First response to losses of containment and alarm conditions Deploy spill or other emergency response resources Respond to alarm conditions Post Vessel Loading Execute arm or hose purging Ensure 3rd party inspector has conducted gauging (if applicable) Deploy mooring crew and arm connection personnel Ensure all paperwork is complete to release ship to sail

Berth Operator

MTCC Operator

I I R R R (2) I R (1) R (1) R R I R

R R R (1) R R (2) R (2) R R -

R (1) R (1) R (2) R (1)

R (2) R (2) R (1) R (2)

R R R R

I I

MTCC = Marine Terminal Control Center R= Responsible for action; R(1)(2)=Dual responsibility w/primary & secondary roles I = Informed of Action Table 5.2: Example Mid-scale LNG – Marine Terminal Responsibility Matrix

5.2

Functional Requirements

The following items are recommended to be addressed for the Functional Requirements of the Terminal (more details regarding specific terminal functions are covered herein): 1. Design service life 2. Description of the number of berths, anticipated occupancy, and required operational availability to support operations 3. Need for service and tug boats needed for operating the terminal 4. Navigational aspects 5. Ship sizes 6. Functional requirements of the mooring and berthing system 7. Functional requirements of the terminal infrastructure and equipment including marine loading arms and/or hoses and access facilities 8. Terminal control requirements 9. Description of exclusion and safety zones in the vicinity of the terminal 10. Safety and emergency response and evacuation requirements 11. Security requirements and access restrictions 12. Inspection and maintenance requirements

5.3

Basis of Design

As shown in Figure 5.1, the Basis of Design overlaps with the Concept of Operations and the Functional Requirements; however, the Basis of Design is focused on technical details and approach in greater specificity. The following issues are recommended to be addressed in the Basis of Design: 1. Design life and strategy for achieving design life, with each component

16

2. 3. 4. 5. 6. 7.

8. 9. 10. 11. 12. 13. 14. 15. 16. 17.

Regulations, reference codes, guidelines Design vessel particulars (Reference is made to APPENDIX C for ship characteristics.) Navigation channel, turning basin, manoeuvring, marine exclusion zones Classification of the terminal (if there is some general system of applicable codes) Geometric dimensioning of terminal component structures (configuration, main dimensions, levels, required surfaces for the different needs, etc.) Site characteristics:  Topography  Bathymetry  Metocean conditions  Sea level rise  Tsunamis  Environmentally sensitive areas  Geotechnical  Morphology  Nearby facilities and surrounding maritime traffic  Nearby hazardous facilities  Surrounding population and industrial areas Mooring type definition and associated survival and operating limits wind/wave design limits requirements Vessel mooring configurations and combinations Layout of platforms, including equipment, access and egress considerations Layout of mooring and berthing system Vessel motion and operating envelopes Shore requirements including parking, equipment staging, sanitary facilities, security, etc. Structural loading requirements and load combinations Hazard analysis and fire protection requirements Equipment Requirements for each structure (Platforms, mooring & berthing facilities) Aids to Navigations (AtoN)

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6 TERMINAL PLANNING Terminal planning occurs during the concept/feasibility study phase of the project to identify any showstoppers and determine critical design criteria that decide the feasibility of constructing a liquefied natural gas terminal at a particular site. For small- to mid-scale LNG terminals there can be additional challenges beyond those for conventional large-scale terminals. Smaller facilities are typically closer to active ports and communities or attempt to take advantage of existing infrastructure, resulting in greater care needed to coordinate with port authorities and other stakeholders and determine acceptable distance from existing facilities to the new terminal.

6.1

Site selection

In order to determine optimal facility siting, several critical parameters must be determined early in the process. SIGTTO’s [SIGTTO, 1997 & 2004], as well as SIGTTO’s [SIGTTO, 2003] provide best practices for the industry and are the basis for this discussion. These parameters define the use, the infrastructure, how the infrastructure relates to adjacent facilities, and how the facility is to be regulated. The following are examples of some of these key parameters, but every project is different and other parameters not listed here may govern: 











LNG supply chain – The means of getting LNG to and from the facility. This may be by delivery from a conventional LNG carrier, by LNG shuttle carrier, by truck, rail, ISO container, or pipeline. Optimally locating the site can be done by determining the minimal transport cost for the LNG from the supply point to the customers. Depending on the use of the LNG facility, it may be desirable to select a location which provides access to multiple customers or to local distribution networks. In that case the pipeline can be non-cryogenic after the vaporisers. Land availability – Where facilities are intended for locations within existing protected ports, it may be difficult to acquire sufficient land to allow for the facility equipment, storage, and proper exclusion zones. Site preparation needs to be addressed. Plot plans and equipment/storage selection must be developed in line with the available land and secured perimeter standoff. Sites must also have proper water access. Delivery and storage modes of natural gas and/or LNG to and at the site will drive the required plot size and thereby the land availability. Alternate solutions, such as FSU’s, may be able to accommodate sites with limited land availability, dependent on available water access. Metocean and geotechnical conditions – Metocean conditions, geotechnical conditions, seismicity and liquefaction potential, tsunamis, flooding, and other site specific conditions may limit the facility location or type of facility (such as mooring system) which can be developed. Some of these hazards may be generally determined at the concept stage based on desktop studies, but will likely need to be further refined in the design development phase when site specific data is available. Site specific data is generally required in order to determine reliable understanding of the site conditions. Environmental restrictions and nature reserves – Some Authority Having Jurisdiction (AHJ) may have environmental restrictions which can significantly limit development, such as areas where fish spawning (eel grass) limits, pile driving or deck shadowing. Protected reserves may be a showstopper for selecting a site; therefore, it is critical at an early stage to contact the local AHJ to determine what sites are protected. Water access – Ideally, the facility should be located where adequate water depth for the expected fleet of vessels is naturally available and the metocean conditions are suitable for mooring and berthing. This may not be possible and dredging and/or breakwater construction may be required, which has a cost and environmental impact on the project. Maintenance or capital dredging may even be a showstopper for small-scale LNG terminals. Where appropriate, trade off studies should be performed considering the length of trestle or submarine pipeway to deep water versus dredging. Where possible it can be advantageous to orient the vessel into the most restrictive direction of wind, current, or waves. This reduces the exposed above and below water area of the vessel and reduces loads. Surrounding infrastructure and facilities – Account will need to be taken of any existing facilities at or adjacent to the site and their potential impact on design, such as potential disruption to/from the existing facilities, operational restrictions, construction restrictions and simultaneous operational issues. Any existing facilities including pipelines and cables will also need to be taken into account. Survey of the location and condition of these facilities may be

18

  

included in the data collection campaign. AHJ’s or terminal operators may require exclusion zones for the terminal itself and any traffic coming into the terminal. The location of the facility may hence be driven by what facilities or population densities have to be passed along the vessels route to the facility. In some situations it may be necessary for port operations to cease while an LNG vessel operates or travels past the port facility; thus some ports may be reluctant to introduce small scale LNG near certain facilities. The risk of collision and passing ships on LNG loading operations requires to be assessed as well. Support availability – Availability of tugs, service vessels, and other support services can be critical to facility siting. Where they are not available, additional cost associated with acquiring vessels and developing home berths must be absorbed by the project. Construction – Vicinity of workforce and material sources (such as quarries, caisson dry docks, precasting facilities, or availability of large construction equipment). Stakeholders – Siting of a new LNG facility, be it large- or small-scale, will likely draw strong attention both from regulators and the public. Early involvement with the AHJ and early public education is critical to selecting an appropriate site which will decrease the likelihood of future challenges in development or even abolition of the project altogether.

It is recommended that a comparative analysis of a few locations and terminal configurations is performed to identify pros and cons of each alternative or location for selection of the terminal site and configuration. When comparing sites, the selected evaluation parameters should be mutually exclusive. A site visit with representatives from the owner, engineers and other project stakeholders to review first-hand the selected locations is highly recommended. Meetings should also be held with the local port authority and other regulators to verify that the planned development is consistent with overall port master plans.

6.2

Site Investigation

At the terminal planning/feasibility stage it is unlikely that in-field site investigation will be performed; however, desktop studies may be possible based on available data (such as navigation charts, information from adjacent sites, local airport wind conditions, or port provided data). Once the location has been determined, field investigations may be undertaken to quantify key risks. Detailed site investigation associated with further design development is covered in Section 7.3.

6.3

Terminal Layout

The main drivers for any LNG terminal layout are costs, minimising lost production and safety. Minimising lost production means that in the event of fire and/or explosions, incident escalation and damage to the facility should be prevented. Terminal layout requirements based on these drivers are: 

  

Minimise escalation of unwanted events using separation distances or physical barriers. Reference is made to Section 13 on the determination of minimum safety distances. Minimum distances can also be prescribed by the AHJ or applicable codes and standards and are smaller than for conventional terminals. An LNG terminal is generally designed such that process plants (if any) and manned buildings or locations where people will frequently be furthest away from each other. The area in between is often used for utilities and storage. Note that the risk profile for atmospheric and pressurised storage is significantly different. In some cases, a barrier, such as a wall, may be required next to a loading bay for the terminal operator to stand behind during LNG transfer. Maximise separation between hydrocarbons and potential sources of ignition and occupied buildings. Minimise the occurrence of a fire and/or explosion by designing the facility such that the probability of ignition is minimised, natural ventilation is maximised and accumulation of hydrocarbons is prevented. Minimise the consequences of a fire and/or explosion by providing suitable means for escape, evacuation and firefighting, minimising congestion and implementing essential safety systems. The location of flange connections, drains, vents and the inlet of air compressors should be carefully chosen.

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 



 

 



Minimise the site footprint Optimise the location and design of the berth depending on any existing infrastructure, site conditions and the vessel fleet expected to call on the terminal. The configuration of the LNG jetty infrastructure can be evaluated by performing manoeuvring and berthing simulations, mooring analysis, evaluation of dredging requirements for both initial construction and maintenance and downtime studies. Take in to account the site topography (elevations, which may require terraces and impact the locations of where hydrocarbons could accumulate), meteorology (e.g. wind direction), geotechnical conditions and seismicity (e.g. to come to optimal foundation solutions) in the layout of the terminal components. Establishing a logical product flow to keep pipe lengths to a minimum (minimises costs and reduces leak frequency) and positioning the utilities in the most convenient location considering their interfaces. Logistics. Traffic required for (un)loading should be logical (e.g. preferably no dead ends or trucks having to reverse for approach and departure), ideally not interfere with other traffic (such as required for operations and maintenance) and should not have to pass storage or process areas. Turning circles of the largest trucks can dictate the terminal road design. Constructability. The terminal layout should consider construction access (especially the logistics for heavy equipment such as storage tanks), required laydown areas, the construction sequence, installation, hook-up and commissioning and start-up requirements. Operability and maintainability. The terminal layout should consider access for operators and maintenance personnel under normal and emergency circumstances (minimum walkway and platform width, minimum headroom, design of stairs and ladders, minimum distance between equipment and pipes). Crane radius, location and required reach are recommended to be assessed. Future expansion or development.

Based upon the above requirements, an initial terminal layout built up from its individual components is made. An early risk assessment is recommended to ensure the plot size and distances between the components are in the right order of magnitude. Reference is made to Section 11 for the infrastructure and equipment of small to mid-scale LNG terminals and to Section 13 on risk assessment. This layout will be discussed in a multidisciplinary team which contains e.g. safety engineers, civil engineers, terminal operators, construction experts, maintenance personnel and process engineers. Generally, the layout will undergo several design cycles before it is finalised. Specific components for small- to mid-scale LNG terminals which should be addressed in determining a terminal layout are:  

   

6.4

Location, size, and structural systems for LNG loading and unloading. This may include loading/unloading platforms, access trestles, rail or truck racks, and associated cryogenic or natural gas pipeways Major equipment that can alter the layout, such as loading arms/hoses, pig launchers and receivers, storage tanks, support facilities (e.g. berths for tugs or service vessels) means and location of access between the calling vessel and the facility, such as gangways and sizing of any process units Drainage design: location of drain points (piping and valves), if and how to retain spilled hydrocarbons (this may be prescribed by the AHJ), sloping of pavements to safely direct spills or leaks of LNG away from loading areas and how to segregate effluent from hydrocarbons Crash barriers: to protect vulnerable equipment against accidents with vehicles Earthing and grounding: of metallic equipment, the vessel, etc. Determination of hazardous zones (such as classified areas): this impacts the equipment requirements, access and safety measures at different locations inside the terminal

Cost Considerations

At site selection and layout concept selection phases of the project, it can be challenging to develop accurate capital cost (CAPEX) estimates. The American Association of Cost Estimating (AACE) provided guidance on various levels (classes) of estimating accuracy. At the preliminary level a Class 5 budgetary cost estimate (-50 %, +100 %) level of accuracy is deemed appropriate.

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This level of estimate is typically developed from previous experience on the part of the designer with minimal engineering. Such an estimate should be considered for all sites and layout schemes on a comparison basis and should include the following:          

Marine structures (platforms, dolphins, trestles, quay walls, etc.) Connecting infrastructure Construction supporting infrastructure, such as worker villages, quarries, MOFs, heavy haul roads etc. Liquefaction and processing facilities (if they occur at the site) Storage facilities (if it occurs at the site) Site preparation Dredging Major equipment such as loading arms and gangways Gas and cryogenic pipeline facilities, including pigging Gas metering (flow or fiscal)

Often the capital costs will depend heavily on the concept of operations as it will drive the vessel size, the facility layout, and other major constraints. Therefore, it is critical that all concepts use equivalent concepts of operations or the full economic impact of the operations (both throughput and capital cost) be considered where different operations are considered. Cost risks can also play a significant role in selecting between options. As an example, if geotechnical conditions are unknown, options should use the same geotechnical assumptions or options with more geotechnical risk should be recognised as having possible higher variance in capital costs. It behoves the owner to recognise that options which may appear less expensive on a capital cost basis may carry higher risk of future cost/schedule increase; therefore, care should be taken in assuming appropriate contingencies. Operational expenses (OPEX) need to be considered at the site selection and layout stages. Development of specific operational cost can be difficult in such an early phase; however, the following are some key items that should be examined: 





Maintenance dredging – large sediment flows, such as from nearby rivers, can greatly increase operational costs. In some conditions channel maintenance dredging may be performed by the local port or other authority. It is beneficial to investigate whether dredging can be avoided. Replacement life of equipment – In some cases, equipment with larger capital costs may have longer design lives. As an example, loading arms typically have larger capital costs than equivalent hoses; however, hose service life is shorter, requiring replacement during the design life of the facility Manning philosophy/ownership structure.

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7 ENVIRONMENTAL CONDITIONS This section describes the required data and data collection and analysis typically required for LNG facilities, including small- to mid-sized facilities. Data would be initially collected from that readily available from nearby facilities, airports, online databases, or other publically available sources for use in desktop studies. Once design development proceeds field investigations should be performed which are geared towards the needs of the ongoing design.

7.1

Data Requirements

An understanding of the surrounding physical environment is fundamental to the successful planning, design, construction and operation of any marine terminal. In general, the environmental data requirements for small- to mid-scale terminals will be similar to larger facilities. The following data parameters are amongst those typically required to evaluate sites and then to progress the design of the terminal.                 

Topography and bathymetry Geology and geotechnical conditions and hazards Contamination Sediment transport/seabed morphology Vertical and horizontal datums (coordinate system) Water levels (fluvial & tidal ranges including atmospheric effects and sea level rise) Precipitation, snow and ice Seawater/fresh water effects Temperature (air and water) Currents (fluvial and tidal) Wind Waves, wind induced operational or extreme waves, storm surge and swell waves Visibility (fog) Seismicity Tsunami Seiche Flooding

Some data will be available from publically accessible databases; others may be obtained from private databases or from direct field measurement only. Analysis of the above datasets (possibly involving simulation or modelling) is then required to interpret and extrapolate the data to generate environmental design conditions. These design conditions will include operational and extreme cases for the key data parameters as well as combinations of conditions which may consider the joint probability of occurrence of conditions (i.e. the joint probability of high waves and water levels occurring at the same time).

7.2

Data Collation

A description of the typical existing sources of the parameters (shown in Section 7.1) is provided in PIANC [PIANC Report 116, 2012]. Coordination with the local port authority can also often lead to points of contacts at adjacent facilities where site specific data is available. This data may be different from that at the actual site, but representative of the local region. It is not recommended to solely rely on existing data collected by others as or at adjacent sites as it may lack verifications, proper controls, or the local area may be more variable than assumed.

7.3

Field Data Collection

The extent of the field data collection is dependent on the availability of existing data. Field data collection in a marine setting comes with increased complexity compared with typical land-based surveys due to; 

Difficulties operating and deploying equipment from floating vessels (in particular in the shallow or intertidal zone or where tide ranges are several meters or more)

22

 

Degradation of equipment over time due to bio fouling and other durability effects Many of the parameters being observed are below water and out of sight

Various methods are available for acquisition of new data for each of the parameters listed in Section 7.1. In order to obtain high quality gapless data, it is important that appropriate equipment and deployment methods are used for the given circumstances. The selection, specification and installation of survey equipment should be made with input from specialists in field measurement and the field measurement campaign should then be appropriately planned to ensure safe and effective data collection. Metocean data is often collected via metocean buoys, Acoustic Doppler Current Profiler (ADCP), or local weather stations (commonly at airports). Care should be taken that the recorded data captures peak seasonal events (such as monsoon seasons). While placement of such equipment can be expensive, it is highly recommended as it will allow for appropriate design of the mooring system and evaluation of facility availability. Geotechnical investigations, both geophysical and field borings/Cone Penetration Tests (CPTs)/vibrocore, are one of the largest costs associated with site investigation, but often are the most significant in regards to civil structure design. While preliminary analysis can be performed with data from adjacent sites, these studies should be considered to carry a high risk for cost and schedule increases. It is, therefore, highly recommended that geotechnical field investigations be performed prior to FID. Geophysical investigations are often undertaken on a preliminary basis prior to fielding a full boring/CPT investigation. This method can result in early knowledge of bedrock depth; however, it can also provide false results if it is not paired with a minimal number of borings or CPTs. In rough marine environments great care should be taken in evaluating the equipment selection and crew experience.

7.4

Analysis and Modelling

Various analytical methods are available for specialists to develop operational and extreme design conditions and assumptions from environmental dataset. The methods used may include:    

Desktop/judgement based analysis of data to derive reasonable and reliable design conditions Extremes analysis on wind, waves, water levels or currents Computational analysis to determine wave or current conditions over a wider area than at their measurement points Computational analysis of sediment transport regime

Consideration should be given to extremes as well as more statistically common events and the design events should be based on rational combinations of these events. As an example, it is overly conservative to consider an extreme tide level in combination with an extreme swell, wind storm, tsunami or other low probability event. Design events considered should be consistent with the expected lifetime of the facility and risk acceptance level of the owner, insurer and AHJ.

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8 NAVIGATIONAL ASPECTS This section describes the design process with regard to navigation access for small- to mid-scale LNG marine terminals. The following two PIANC publications provide general design guidance for navigation access and both are applicable to LNG vessels. [PIANC Report 121, 2014] [PIANC Report, 2012] The above guidelines are also supplemented by the following SIGTTO guidelines: [SIGTTO, 2009] and [SIGTTO, 1997 & 2004].

8.1

Risk Assessment for Development of Policies and Procedures for Navigation

While some of the above guidelines provide some initial guidance on typical operating procedures and design, they all make it clear that marine operations conducted within a port should be controlled by policies and procedures within a wider Safety Management System (SMS), which is based upon a structured and formal assessment of risk within the port. Each port or developer should therefore develop navigation and towage guidelines based on risk assessment which are specific to particular ship types and sizes approaching or leaving particular berths or difficult navigational areas within the port. The relationship between this wider SMS and the risk assessment is presented in Figure 8.1 while risk assessment for small- and mid-scale LNG is dealt with in Section 13.

Figure 8.1: Relationships between the Safety Management System and Risk Assessment: Risk Assessment defines the risk, Safety Management System manages the risk [PIANC Report 116, 2012]

When developing policies and procedures for safe navigation of gas carriers of any size, the following factors should be considered:       

The geography of the port and approaches Any difficulties associated with specific berths, locks, bridges, etc. Size, type and manoeuvrability of ships concerned Weather and tidal factors and limits including wave heights and time periods Environmentally sensitive areas Capability for active (tug made fast to the vessel) or passive (running close but not made fast) escorting Whether tugs need to be used to facilitate certain manoeuvres (turning, un-berthing, etc.) and if so, where they should be available Whether the ship has enhanced means of control (e.g. bow and stern thrusters, twin propellers, high lift rudders, etc.) and how this may offset tug requirements.

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The assessment to develop policies and procedures for safe navigation should take into account the following:      

Geographical features of the transit, such as the extent of navigable waters, bends in the channel, obstructions and isolated dangers, nature of the seabed, etc. Water factors, such as tidal range, tidal streams and currents Environmental factors, such as the incidence of poor visibility, strong winds, swell, etc. Traffic density and likely encounters with other ships. The frequency and geometry of likely encounters should be considered, in combination with estimated probabilities of mechanical failure or operational error on-board the ships Existing Navigation Aids (those on-board), Aids to Navigation (external) and safety systems, i.e. risk control measures already in place The historical incident rate for the transit passage concerned, noting the regime of risk control measures in place over the period for which the data is taken and any changes in them. The availability of such information will affect the accuracy of the probability assessment. If little or no data is available, then probability assessment will have to place greater reliance on professional judgement.

Through consideration of the above, it is possible to assess the probability of collision, contact or grounding for any given ship type and transit.

8.2

Towage and Pilotage

For large LNG carriers it is widely accepted that tug attendance is necessary for risk management/mitigation in addition to any towage which is required for manoeuvring. Pilotage will also be mandatory in all ports for large and medium sized LNG carriers. The general requirements of the tug fleet are to cover the following services:      

To provide necessary assistance during the berthing and unberthing operation to counteract wind, wave and/or current forces To enable the carrier to turn safely in the available area To act as a restraining or anchoring force on a carrier moving towards the berth structure To act as a stand-by vessel when a gas carrier is moored To carry out emergency, fire-fighting and antipollution operations To assist a carrier in an emergency situation, e.g. due to break down of propulsion machinery, steering gear, etc. The tug should be able to assist directly at any time during the carrier’s approach or departure, as defined in the terminal’s navigation risk assessment.

Navigation of smaller LNG vessels, such as that shown in Figure 8.2, will come with reduced risk due to a number of factors. Consequently, with reduction in vessel size it is reasonable to assume that some practices, which are almost standard for large LNG carriers (e.g. escort towage), may not be required for certain smaller LNG vessels. Where small LNG vessels make frequent fixed route transits these may also be pilotage exempt. However, the development of such safe policies and procedures has to be subject to risk assessment regardless of the size of the vessel. It must also be specific to the port and operations under consideration. Factors which may influence a reduced need for towage, etc. may include the following;     

Improved manoeuvrability of some smaller vessels Lower risk associated with smaller parcel sizes Enhanced means of control (e.g. bow and stern thrusters, twin propellers, high lift rudders, etc.) Scale of the small LNG vessel relative to the port navigation areas which may have been developed for larger ships Vessels on regular transit with crew trained for local conditions

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Figure 8.2: Small-scale LNG carrier Coral Energy (15,600 m3).

8.3

Approach Channel Design

An approach channel is defined as any stretch of waterway linking the berths of a port and the open sea. There are two main types:  

An outer channel in open water and exposed to waves that can produce significant vertical ship motions of heave, pitch, and roll An inner channel that lies in relatively sheltered waters and is not subject to wave action of any significance to large ships.

The channel normally terminates at its inner end in a manoeuvring area (turning and/or berthing area) which allows stopping, turning and berthing manoeuvres to be undertaken. Approach channel design (existing or proposed/modified) is a critical factor in the navigation risk assessment process and conversely, approach channel design or modification may be an outcome from a risk assessment. PIANC Report 121 (2014) provides guidance for conceptual design with regard to the following issues, but also notes that detailed design will use risk assessment methods in association with available tools such as navigation simulation. The same approach is applicable to small- and midscale LNG albeit subject to lower risks associated with smaller vessels for some (not all) scenarios:        

Vertical motions of ships in channels Vertical clearances under bridges, overhead cables, etc. (air draught) New and future generation ship characteristics Acceptable levels of risk and clearance margins Methods for assessing operating limits Use of ship navigation simulation in channel design Manoeuvring limits in adverse conditions, e.g. consider tug effectiveness at speed and in waves Restrictions on pilot boarding, tug attachment/detachment.

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9 BERTHING & MOORING 9.1

General Principles

The general principles towards berthing and mooring are very similar to those of larger LNG berths. As such, good general guidance, though not specific for LNG, is already available in OCIMF (2008), BS 6349-4 (2014) and PIANC WG 153 (2016). Mooring layouts in line with the guidance above and based upon the range of expected vessels will normally be suitable for design in a multi-directional environment (i.e. an environment where no single approach direction dominates). In cases where a specific direction is known to dominate then it is good practice to try to optimise the mooring arrangements to this. That said, the ultimate responsibility for mooring in practice remains with the ship’s captain. The berth designer should ensure maximum operability. The range of vessels the berth is expected to accommodate should be fully understood. APPENDIX C provides ship characteristics. Where there is a larger range of vessels it is advisable not to simply review the largest and smallest vessels at the berth, as quite often this can lead to unsuitable mooring layouts for ships within the middle of the expected range. This is particularly applicable when applied to smaller vessels as variation of vessels within the same class is likely to be higher as well as their sensitivity to forces, particularly from waves. Preferably berths should be tailored to the specific vessels expected to utilise the facility. However, particularly with small to middle range vessels this is likely to be unknown and so representative vessels should be used, with an allowance for variation in the vessel particulars (e.g. flat sided length, freeboard, LOA, etc.). Future use of the terminals (phasing, expected fleet transformation, etc.) should also be considered. Small- to mid-scale terminals likely have to accommodate a larger range of manifold positions than conventional terminals. Whilst preparing the mooring layouts, the designer should also be aware that manifolds on the design vessels (as well as the berth) may not necessarily be in the middle and have a specific elevation. This needs to be compatible with the location and specifications of the transfer system. Gangway access to the vessel should be considered as part of the design; which may be a terminal-supplied gangway or the ship gangway. Due to the higher sensitivity of small to medium LNG vessels to waves the siting of the terminal can have a great impact on the success of the berthing and mooring of vessels and the berths associated downtime. The available budget per terminal throughput quantity to construct the site is also potentially lower than that of an equivalent berth for a large vessel. As such, the siting of the facility should be carefully considered. More information to this regard is given in Section 6.

9.2

Berthing

Designing for berthing of small to mid-scale LNG vessels does not differ significantly from designing for conventional LNG berths; though more consideration of a range of vessel sizes to call at the facility will need to be considered. Two typical approaches are used for fendering systems:  

Discrete fenders – absorb all of the energy at a single point (such as on a dolphin), as shown in Figure 9.1. Continuous fenders – use multiple energy absorbing elements along a contact length of the vessel with individual fenders located at a regular spacing (such as along a quay wall).

Conventional LNG berths typically use large discrete fenders with fender panels that always strike the vertical face of the vessel. Small to mid-scale facilities may see a larger variation in vessel size (especially at breakbulk facilities with shared berths) which means that continuous fender systems may become advantageous. For small- to mid-scale facilities with discrete fenders, not all vessels calling at the facility may touch all fender systems or strike at the most desirable elevation or angle to the fender. Development of systems which are combined (all fenders share the same berth face line) or nested (smaller vessels have a berth line closer to the pier, inside of the larger vessel berth face line) to account for differing vessel sizes may therefore be desirable.

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Figure 9.1: Idealised Discrete Fender Breasting Dolphin Layout [PIANC WG 153, 2016]

Figure 9.2 shows examples of various fender systems related to relative energy absorption and cost. This figure does not capture the wide array of varying system and fender configurations, and each of the typical systems shown have a large variance of both energy absorption and cost. Generally, systems comprising continuous fender systems have lower energy absorption on an individual basis, but satisfy the energy absorption demand by activating several fenders simultaneously. Discrete fender systems offer significantly higher energy absorption, but at greater cost (on an individual basis). Where a limited fleet of vessel sizes are calling at a facility, discrete fender systems will likely be advantageous as they allow for high energy absorption at the desired point of impact. Where a wide range of vessel sizes is likely to call, a continuous fender system may be advantageous.

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Figure 9.2: Fender System Summary [Trelleborg, 2015]

Selection of the fendering system will be dependent on the fleet, energy absorption and performance, it should consider both the capital cost as well as the ongoing maintenance costs. As an example, timber, steel and concrete fender piles are less expensive than composite fender piles, however if local regulations restrict the use of timber preservative treatment then composite fender piles may be more cost effective over their lifetime. More drastic alternatives, however, are available and are discussed below in Section 9.4. Where calling vessels are small, there may be water level conditions where the deck of the vessel is significantly lower than the structure top of deck height. In these conditions fender piles, floating fenders, or larger fender panels may be necessary. As smaller vessels may arrive at a larger angle of incidence, care should also be taken to address the shape of the bow in relation to the fender elements such that it is not possible for the bow to impact the pier without first impacting the fender. In the case where the vessel top of hull could occur at an elevation below the fender panel, the fender panel should be extended lower, in any case the bottom edge should be chamfered so that it cannot catch on the vessel hull. While there are significant differences in vessel size, the underlying theory of design is unchanged from small- to large-scale and is well addressed in PIANC WG 33 (2002) and later on in PIANC WG 145, which is undergoing an update at the time this document is published. The major difference will be in the selection of an Abnormal Berthing factor, which provides for a safety factor for accidental berthing conditions. For smaller vessels, PIANC recommends an abnormal berthing factor of 1.5 to 2.0, dependent on the size of the vessel. The angle of approach to the berth may also require examination for larger angles, which can impact the fender system design in regards to the fender performance, fender spacing, and fender panel size. In some cases, such as where no tug assistance will be provided and/or where no approach monitoring/scoreboard is provided,

29

a higher approach velocity may be appropriate as there will be fewer controls on the vessel approach and possible greater impact from wave forces. Spacing of fendering systems requires careful consideration that appropriate fendering is provided within the flat side body areas of the full range of vessels (generally within the range of 0.25LOA to 0.4LOA). On a jetty, this is likely to require fenders to be placed within the range of the central loading or unloading platform. This can be mitigated with the use of separate dolphins underneath the platform or fenders attached to the central platform itself. Both do have notable disadvantages, namely:  

Dolphins under the platform will likely be at least partially submerged at some states of the tide, increasing corrosion rates of the dolphin and fenders. Fenders attached to the central platform will induce horizontal forces to the platform that require extra support, as well as risking undesirable horizontal deflections, beyond the allowance of topsides. Cargo transfer pipe stress evaluation will need to consider deflections due to berthing. This is generally not considered good practice, but may be required based on necessity.

Permanent breasting, such as that for permanently moored FS(R)U or other vessels, requires additional consideration of the service life of consumable components, such as rubber fender units. Ship-to-ship transfer may also occur at permanently moored vessels and the load transfer mechanism should be considered from the berthing vessel throughout the entire system.

9.3

Mooring

As discussed above the general principles of mooring are likely to remain unchanged for a smaller facility in comparison to a larger facility. As a result an idealised mooring layout, such as that shown in Figure 9.3 is preferable for facilities in a multi-directional environment.

Figure 9.3: Idealised Mooring Arrangement [PIANC WG 153, 2016]

However, with smaller vessels an idealised mooring layout may not be practical to be achieved. In principle, the mooring layout works if the line loads and movements are proven to be sufficiently low, even with a non-ideal mooring configuration (for example in a ship to ship situation, or a berth primarily laid out for large LNGCs). Smaller vessels will typically have a lower freeboard (deck elevation), which could potentially mean that the vertical angle of mooring lines is higher than desirable (i.e. the deck of the vessel may be significantly below the deck of the structure). For the determination of appropriate mooring facilities, it is recommended that static and dynamic mooring analyses (depending on the vessel parameters, metocean environment and operational conditions) are undertaken to ensure that the mooring system is practical. This may also be further supplemented with the use of physical modelling. Typically, the dynamic assessment is considered for partially sheltered and open water facilities where the effects of wind, waves and current must be carefully considered or at facilities affected by passing vessels.

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Smaller vessels will be less sensitive to wind loads than larger vessels due to their comparatively small wind areas. However, as they are lighter they will be far more susceptible to short period wave effects. When positioning the terminal the designer must therefore consider the wave forces. If the berth is to be placed within a comparatively narrow channel, wake forces from passing vessels can be significant and have the potential to pull vessels off their moorings. Traditionally QRHs are the preferred mooring hardware for LNG terminals as they allow a quick exit for vessels in emergency situations and easy and safe handling of lines. However, for small scale LNG berths, bollards may be more appropriate (e.g. a ferry bunkering at the terminal). When using bollards, earthing and electrical continuity should be considered. The decision of the mooring hardware should be assessed on a risk based analysis, an appropriate vessel berth and release plan (in the event of an emergency) and local regulations.

9.4

Alternative Mooring Solutions

Alternative solutions to a traditional jetty are available and can offer advantages in terms of mooring and berthing small- to mid-scale LNG vessels. Alternative solutions may allow for multiple smaller vessels, shorter connection/disconnection times, or to accommodate more extreme environmental conditions. Some examples of these alternative solutions are discussed below, however there is an ever increasing variety of alternative moorings. Alternative structures:  

Intermediate vessel or pontoon – Use of a permanently located floating platform can accommodate a wide range of vessels; however, this will provide a less stable mooring environment and could lead to unacceptable downtime. Quay wall – Gravity structure or retaining wall with a continuous face. The larger face allows for a wider range of vessel sizes along the continuous fendering system. This can be incorporated into land use to reduce the facility footprint. Unless mooring line equipment is set back from the berth though, an idealised mooring arrangement will not be achievable.

Alternative mooring hardware: 





Bollards – Bollards are not typically used for conventional LNG facilities as they do not allow for quick release. For small facilities it is likely that bollards would be used as they are significantly less expensive. The use of bollards or other moorings that do not allow for quick release should be considered in the risk assessment. Alternative mooring such as suction moorings – a more recently developed system for mooring vessels uses suction pads which are tied to the quay. This system has not been used at LNG facilities, but may be acceptable for smaller facilities and would allow for quick connection and disconnection of the berth. Clamps or rings – proprietary systems which incorporate mechanical clamps, rings and pins, or other articulated connections that allow for rapid connection. These systems are novel and will need to be carefully considered in the risk assessment.

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10 TERMINAL INFRASTRUCTURE & EQUIPMENT 10.1 Infrastructure Components A small-scale LNG terminal consists of the following components:    

Marine structure(s) (Section 9) – mooring location for the vessel in order to safely transfer LNG Loading and unloading system (Section 10.2) – equipment that is required to transfer the LNG from the storage and/or supply point to the vessel’s manifold, including control, safeguarding and safety equipment LNG storage and (off)loading points (Section 10.3) – LNG supply or offtake base which can be a storage and/or a connection at the shore side boundary of the terminal. Security and access facilities (Section 10.4) – to ensure unauthorised persons cannot access or cause damage to the facilities

The main challenge for small to mid-scale terminals is to scale the required infrastructure to fit the required throughput and keeping the development economical while not compromising on safety. The conceptual design of the transfer system is a priority. Reference is made to NFPA 59A (2014) and ISO 18683 (2015) for the design of LNG terminals.

10.2 Loading & Unloading Systems The (Un)loading Operation The unloading and loading operation consists of several phases. They are briefly described in order to understand the infrastructure and equipment that is required for (un)loading. The operation is generally planned a few days or weeks in advance and includes a berth compatibility check. The dedicated vessel will enter the port area and if required a pilot will board to assist in sailing to the LNG berth and berthing. After mooring, the transfer will be prepared. This may include clearing all the paper work related to the transfer, checking of the equipment and inerting to remove moisture and oxygen from the system to prevent it from malfunctioning due to ice or hydrates in the system and from posing a fire hazard.

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Cooling down of the transfer equipment and vessel tanks may be required before the actual LNG (un)loading can take place. As LNG is liquid at -163°C this may take time. Before disconnecting the transfer lines are generally purged with nitrogen to remove natural gas from the system to eliminate a potential source for fire hazards and may need time to warm up before they may be handled again. Then the vessel can disconnect from the berth and sail away.

LNG Transfer System Concepts There are 2 main concepts for small- to mid-scale LNG transfer: Marine Loading Arms (MLAs) and flexible hose based transfer systems. They can be connected to the vessel with Quick Connect/Disconnect Couplings (QC/DCs), flanges with bolts or threaded couplings. In addition, all systems will essentially have either a dry breakaway coupling (for small bore hose systems) or an active emergency breakaway coupling.

Figure 10.1: LNG bunkering loading arm at Risavika harbour Fjordline Facility [Cryonorm, 2016]

Figure 10.2: Small-scale LNG Loading Arm [FMC]

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MLAs dedicated for small scale applications are very similar to conventional MLAs, as shown in Figure 10.2. Conventional LNG loading arms are generally 16”, for small scale applications diameters of 2” to 12” are more appropriate. If necessary, for these smaller arms a piggy back vapour return line is possible, eliminating the need for a separate vapour return MLA. MLAs are generally equipped with a QC/DC and ERS (Emergency Release System). The advantage of MLAs is their proven safety performance, reliability, high throughput, operating window, wide applicability and easy handling and operations. However, they are costly to install and require careful maintenance. Critical components in the design and maintenance are the swivel joints, the structural bearing (as it requires removal of the complete arm in case it needs to be replaced), the hydraulic system (which is the main cause of malfunctioning of an MLA) and the emergency release coupling (ERC). The challenge is increased in small scale as the thermal cycles and movement loads are expected to be more frequent on small MLAs compared to large-scale MLAs. Reference is made to OCIMF (1999) and EN 1473 (2007). Hoses are an alternative for MLAs. Depending on their diameter and connector (which both translates into weight) they can be connected using hose towers, a crane or by personnel. Hoses will be connected to the vessel manifold either with QC/DCs or a bolted or threaded flange. They are generally made from a stainless steel inner pipe, insulation layers and external armour. For small scale application, insulation can also be accomplished by using saddles or other protective means. The hoses used in marine bunkering need to comply with BS EN 1474-2 (2009) or BS EN 12434 (2008). The main advantages of this transfer system are the limited upfront investment, a high degree of flexibility, especially when no additional handling equipment is required to connect the hose(s) and the relative ease of operation as limited training is required. Depending on the hose diameter and what type of connection is required, handling may, however, not be straightforward. The hose and its connections can quickly become too heavy to handle by personnel, hence requiring handling aids such as a crane or a hose tower. Operational costs should be taken into account as the hoses have to be replaced regularly (approximately every 5 years) or recertified every year in case of prolonged use.

Design Aspects of Marine (Un)loading Systems The following aspects drive the selection and design of the (un)loading systems: 









Throughput and berth occupancy – Comparable to large-scale LNG terminals the required terminal throughput and (un)loading duration will determine the number of berths and the required loading rates. Generally, the turnaround time will be less than for large LNG vessels, which may result in a higher berth occupancy, smaller loading line diameters, fewer loading lines and smaller loading rates than at conventional LNG terminals. However, up to multiple thermal cycles a day may be expected and the reliability of the loading time is important in light of the business commitments to keep. Berth availability and operating window – Comparable to large-scale LNG terminals, the design operating envelope (based on vessel manifold and relative motions of the vessel due to the vessel characteristics, motions due to passing ships, port design and metocean conditions) has to be determined. The relative motions and terminal availability requirements can drive the choice for a certain (un)loading system and their design and qualification requirements Manifold compatibility – The transfer system has to be compatible with the expected fleet of vessels that will use the terminal. For small to mid-scale LNG vessels this has not been standardised yet and this will have to be investigated. Compatibility should not be limited to the number of connections and their size, but also include the location, layout and accessibility of the manifold. Reducers can be considered when a wide range of vessel manifolds has to be accommodated. The reducer is commonly provided by the vessel, nonetheless provision of reducers and spools by the terminal should be considered. Loading rate – The required parcel sizes, manifolds and berthing time will dictate the required loading rate and hence the selection of the number of loading lines, the diameter, loading rate, the need for a vapour return line, the extent of the hazardous zone and safety zone and the need for safety measures. Note that therefore this aspect has a large impact on terminal layout and design. Transfer operation aspects – Positive means of confirming draining, de-pressurising and inerting of the transfer system should be possible before connecting and disconnecting. The ease of handling the system, personnel requirements and the required training and competences influence the choice for a (un)loading system.

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







Safety aspects – Terminal operations and regulations dictate the safety measures at the terminal, such as emergency shutdown and disconnection systems, firefighting equipment and personnel and ship-terminal communication requirements. The acceptable risk of leakage and potential quantity of spills may drive the selection of a transfer system. Reference is made to Section 12 on risk assessment and Section 13 on safety measures. Inert gas supply – Nitrogen or inert gas is required to inert and purge the (un)loading lines. This will need to be scaled to suit the terminal demands. It can either be supplied from the vessel or the terminal. The terminal may have a fixed storage tank or container, a nitrogen generator or smaller cylinders. Management of boil-off gas – A decision on how to deal with boil-off gas needs to be made based on environmental regulations and vessel characteristics. Options are recirculation, designing the vessel tanks to handle the additional pressure or only accept vessels with this restriction, direct use of the gas as fuel or designing boil-off handling facilities at the terminal. This will also drive the necessity of a vapour return line. Under normal circumstances venting should not be accepted as a boil-off management measure as methane is a strong greenhouse gas. The AHJ can pose strict limits on venting of gas; quantities may need to be measured and recorded. Economics – Cost and schedule influence the choice of transfer system as well. Some hoses and couplings may be on stock and readily available, while MLAs are typically long lead items specifically designed and manufactured for a terminal. The costs and schedule for the (un)loading system should be evaluated as part of the total terminal development.

With reference to these design aspects, in general a high throughput, high berth availability, large operating window, high loading rates and strict safety requirements would favour the choice for MLAs. Hoses are favourable for low throughputs, infrequent operation, small parcel sizes and benign vessel motions at the berth. They can also serve as a back-up means of transfer, for example if only one MLA is installed at the terminal. It can also be decided to install both loading arms (e.g. for seagoing vessels) and hoses (e.g. for barges).

Control and Safeguarding of the LNG Transfer The following control and safeguarding equipment should be evaluated during terminal design: 

 

 

Communication channels – It is advised to have at least two reliable and independent means of communication during LNG transfer. This can be UHF, radio and/or a ship-shore interface cable. Transfer operations can only begin when effective communications have been confirmed by all parties involved. Control console and associated power supply – A possibility to control the transfer in the proximity of the (off)loading area with clear visibility of the transfer system and the vessel manifold should be included. Connections of both LNG tank and control systems – Best practice is to connect the two monitoring and control systems to allow each side to monitor level and pressure to avoid overfilling and over-pressurisation. Such systems are available as a part of the linked ESD systems in the market. For small-scale fuelling applications instrument air can also serve as a ship-shore interface. Metering – The amount of LNG that is transferred requires careful measuring as it is the basis for accounting. Flow control – Backflow can be mitigated by proper design pressure determinations or by non-return valves, high pressure trips and level trips.

Safety Equipment During the LNG Transfer The following safety equipment can be considered when designing a small-scale LNG terminal: 

Emergency Shutdown (ESD) equipment – In case of an emergency a two-staged alarm system is common. ESD philosophy shall be developed during the design phase and terminology is recommended to be in accordance with SIGTTO (2009). ESD-1 or emergency shutdown stage 1 shuts down the LNG transfer operation in a controlled manner by closing the shutdown valves and stopping the transfer pumps. Activation of ESD-1 shall set off visual and audible alarms. It should be highlighted that in small-scale LNG operations transfer to and from pressurised tanks is more common and stopping of a pump does not effectively stop the flow of LNG in scenarios of single point failure of an ESD valve. Therefore, reliable safety

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

 

 





valves, a pump trip and/or an emergency button will need to be designed on a suitable location in the terminal. It is part of the safety philosophy (refer to Section 13) to determine what triggers the ESD-1 and who and from which location can activate it. Any safety system should be separated from the control system. ESD-2 is a secondary shutdown state activated after ESD-1 which allows for separation of the transfer line. ESD-2 or emergency shutdown stage 2 shuts down the transfer operation (ESD1) and activates the Emergency Release System (ERS) after closure of the ERS isolation valves; the isolation valves of a breakaway coupling are near the transfer point closes and the hose or MLA is automatically disconnected. ESD-2 can only be activated after ESD-1, as disconnection (ESD-2) can only take place after the transfer is stopped (ESD-1). (Un)loading line is only fitted with ERS coupling (different than the QC/DC or LNG transfer connection flange), for use during emergencies. Based on the risk assessment and legal requirements the necessity of an ERS and its extent will have to be determined. The introduction of the ERS has minimises LNG spills volume in case of an emergency disconnection of the transfer system. The ERS system should be backed by its own independent power supply to guarantee that it will operates when necessary. Depending on the case, an ESD-2 may not be available and passive (forced by exerted tension) breakaway may be activated while transfer takes place. Boil-off gas management system – Due to heat leak in loading lines and storage tanks and heat dissipation of the LNG loading pumps the temperature of the LNG will increase, resulting in boil-off gases. When too large amounts of boil-off are generated which the receiving end cannot handle, a vapour return line is required during transfer. Careful design, execution and transfer operations can minimise the amount of boil-off gas that is produced, which is beneficial from an economical and environmental perspective. Leak, gas and fire detection – The risk assessment should identify where leak, gas and fire detection should be placed and which alarms have to be generated. Firefighting systems – Appropriate gas firefighting means should be available both on-board the vessel and at the terminal. Access routes for fire fighters and similarly escape routes for vessel and terminal personnel should be planned and made available before LNG transfer operations can begin. Passive fire protection – The risk assessment should identify any critical components which need passive fire protection. Cold splash protection – As the LNG is extremely cold, coming in contact with LNG may cause material to become brittle and fracture. Carbon steels used for shipbuilding and fixed structures can be affected. Stainless steel and aluminium do not become brittle and are therefore normally used for cryogenic pipework and valves. Depending on the expected spill quantities and frequencies cold splash protection can be incorporated in the design. A water curtain, which is common for conventional LNG terminals, a protective coating on the platform, drip trays or concrete paving to prevent brittle fracture after a spill could be considered. Note that in case of a spill over water, LNG will float on top as it is lighter than water and may get into contact with berth components at the waterline (such as dolphin piles or quay wall sheet piles) before it dissipates, which subsequently may need to be protected. Additionally, a thermal barrier between a drip tray and any support pillars to protect against cryogenic temperatures may be necessary. The cold splash protection of the vessels that will call on the terminal (if any) needs to be checked and found acceptable. Drains and drainage system – The need for a drainage system which collects spills and transports them to a safe location is dependent on the outcome of the risk assessment (see Section 12). Design aspects are the required gradient at the (un)loading area, the location and sizing of sumps to dissipate LNG spills, the location and sizing of an impounded basin with a foam system and pumps (if needed) and whether a separate drainage system for rainwater is needed. For small-scale a spill basin may not be required if ALARP could be demonstrated when e.g. using welded connections to the first ESD-valve in combination with fire and gas detection. Barrier walls – In congested areas a barrier wall between the transfer point and any adjacent activities can be considered to mitigate safety risks. Adjacent activities can be truck (un)loading, passing vehicles on a road nearby, (un)loading cargo or personnel presence. The preference would be not to require barrier walls, but to eliminate the need for barrier walls by distance through a sufficient terminal layout or spacing activities in time by activity planning.

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Procedures (e.g. to avoid any ignition sources during transfer by prohibiting smoking in the terminals or using certain tools, equipment and electronic devices) are also part of the safety measures of a small-scale LNG terminal. Reference is made to Section 13 for these ‘soft’ terminal aspects. Which equipment and measures will be implemented depends on the risk assessment and regulations.

10.3 Storage and (Un)loading Points Depending on the purpose of the terminal, LNG can be supplied or exported to the vessel from (intermediate) storage, a truck, rail or a pipeline, either as LNG or as gas. In case gas will be exported vaporisers will be required and if gas is imported liquefaction units need to be built. Reference is made to Section 2 for the definition of storage and (un)loading points. The LNG transfer system is connected to the (un)loading point of the terminal. The most common (off)loading points of a small-scale terminal are: 

  

Cryogenic pipeline – will be part of every facility to transport the LNG from the transfer system to the storage, an intake or an offtake point. The pipeline is designed to minimise heat loss and boiling of the LNG inside. Cryogenic pipelines are expensive and add significant heat to the cargo; hence, minimising its length can be a design requisite. Refer to Section 6 on terminal layout. Truck or rail loading facility – to supply trucks or trains with LNG, either as fuel or for further transportation by road or rail of small supplies of LNG to end-customers Truck offloading facility – to supply the terminal with LNG, most likely to bunker small vessels due to the small parcel size a truck can contain (20-50 m3), but alternatively to load LNG. Gas export pipeline and vaporiser – LNG can be vaporised at the terminal and send to third party customers (e.g. a peak shaving plant) or the local gas grid.

Cryogenic import or export pipelines crossing the terminal boundaries are possible, but unlikely considering the high costs for cryogenic pipelines favour large-scale infrastructure. Importing gas from the grid or a producer and liquefying it at the terminal for export is also an option, although small scale liquefaction units are relatively expensive at the moment. The listed (un)loading points will cover most of the small-scale terminals. The design of a rail and truck (un)loading facility, small scale vaporizers and gas pipelines is not part of the scope of this guideline. Critical components of (un)loading points are:  

Pumps – The need for pumps needs to be investigated. They may not be required if (un)loading will be done using the pumps on board the calling vessel or if differential pressure is used. Pipelines – Pipelines to and from the transfer system, storage and any (un)loading point are required. Flow direction, flow rate and the temperature of the gas or LNG will drive their design.

The need for onsite storage is determined based on the purpose of the terminal and the choice of (un)loading point. Small-scale LNG storage options currently include:   

Conventional onshore LNG tanks – they can either be scaled down tanks or horizontal tanks comparable to vessels on trucks, as shown in Figure 10.3. ISO containers – movable cryogenic containers designed to store LNG that can be placed on a suitable foundation. LNG cargo tanks of an FS(R)U

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Figure 10.3: Conventional small-scale LNG tanks (Above. Source: IGU) and ISO tanks (Below. Source: Chart Ind.)

The design of mid-scale LNG storage does not principally differ from conventional LNG storage. The same codes and standards apply. Small-scale makes use of pressurised storage and generally does not use concrete storage. The following aspects should be taken into account:       

Distance to the berth: to minimise the need for expensive cryogenic lines Required capacity Necessity for pressure control Maximum pressure rating Maximum evaporation rate Foundation (to prevent differential settlement) Risk profile (which is inherently different for atmospheric and pressurised storage)

At the moment of writing, many small-scale LNG storage solutions are under development. Before including these in the design, it is important to check whether they meet the relevant codes and standard and are classified and/or certified.

10.4 Security and Access Facilities Access to the LNG terminal should be restricted and controlled from both the shore side and seaside. In principle security requirements do not differ from requirements for conventional LNG terminals. Security fences, an entrance gate and CCTV can be used as a minimum. Physical barriers provided at the terminal boundary should not hinder the entry or exit of emergency services. Local regulations and owner’s wishes may influence the requirements significantly. When part of a larger port area, security measures can be shared. Further reference is made to IMO, SOLAS (2004).

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11 LOADS, LOADS COMBINATIONS AND DESIGN CODES Loads, load combinations, and design codes are determined and subject to the requirements of the AHJ. AHJs include local, state, federal or regional governmental agencies with oversight for marine terminals. There are two situations that may arise as the engineer seeks to satisfy code requirements. For the case wherein the AHJ has a higher requirement that provided in this reference, then the user is compelled to go to the higher standard and follow the directives of the AHJ. For the situation where the AHJ has no code requirements, or has no knowledge of marine engineering, this reference may provide a reasonable set of guidelines and recommendations to follow. PIANC WG 153 developed recommendations for the design of marine oil and petrochemical terminals of any size. Much of the guidance provided by that WG is directly applicable to smallto mid-scale marine LNG terminals; therefore, this document will only discuss areas where there is a divergence between these types of facilities. The main difference between LNG facilities and oil terminals is in the acceptable risk levels defining criteria such as seismic return events and setbacks to the site perimeter. Generally, LNG facilities are intended to meet a higher level of protection than other petrochemical terminals which corresponds to a lower level of risk acceptance. In many cases, the design intent provided in the PIANC guidance [PIANC WG 153] is consistent with that for small- to mid-scale LNG terminals, with some adjustment for alternate risk levels. As discussed above, much of the code development and research performed to date has focused on large international trade terminals that see regular calls of high volume vessels. The exposed volumes during transfer operations may be orders of magnitude greater than those at a small- to mid-scale LNG terminals. However, pressurised transfer systems are more common for smallscale, introducing other risks. Therefore, the difference in risk may be justification for adapting prescriptive requirements that AHJ’s developed for large international trade terminals. Negotiation with the AHJ’s on prescriptive requirements and development of site-specific risk assessments and mitigations may be necessary, especially at locations where the AHJ has limited experience with LNG. These evaluations and designs developed must be based on a rational basis of design and have consistency throughout the project development; therefore, early involvement of the AHJ is highly recommended.

11.1 Design Codes Design codes selected are dependent on the requirements of the AHJ. LNG facility specific design codes, such as NFPA 59A (2014), Canadian Standards Association (CSA) (2015), EN 1473 (2007), EN 13645 (2002), and ISO 18683 (2015) are available, but some AHJ’s may not be familiar with or have adopted these codes. Additionally, these codes are often geared towards conventional landside construction, with little consideration of marine facility design. In case codes are not available, the designer will be required to develop a basis of analysis which must be approved by the AHJ. Code selection is critical in the development of a basis of design for the project. Where possible, selected codes should be consistent in their determination of both demand loads as well as member capacity; therefore, codes from the same region should be used together and codes from different regions should not be mixed. As an example, American codes should not be used to develop demand loads if European codes are used to determine section capacity. Additionally, consideration of location of material supply, fabrication, and construction should be considered in selecting the appropriate code. As an example, European code would be inappropriate for use in the Caribbean, where most source materials come from North America. An approach of referencing multiple codes can lead to confusion in both the design and review process; therefore, conciseness of code selection is highly recommended.

Code Order of Precedence When referencing multiple codes, it is important to set an order of precedence to ensure that areas where the codes overlap do not lead to confusion in the design or review. Order of precedence can generally be listed as follows: 

Local/Regional/Federal Regulations – Codes prescribed by the AHJ that must be satisfied.

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 

Owner or contractor guidance documents – Some companies have internal requirements or guidance specific to marine terminals. Where available, these criteria should be used; however, smaller companies may not have developed such criteria. International standards and guidelines – Guidelines, such as this document, are not legal requirements, but often provide sources of information for industry standard design techniques. Where standard and guidance documents are referenced, detail should be provided on what specific sections of the document are to be used.

Note that not all the above categories may be available for a project. All codes selected will need to be reviewed and accepted by the AHJ. Where no specific code or guidance is applicable, technical journals or papers may also be referenced. Finally, a ‘rational basis’ method may be used; however, this may require additional effort determined by the AHJ, such as an independent peer review.

11.2 Loads Loads can generally be broken into marine structure specific loads (such as mooring and berthing) and those which are not marine structure specific. Most regulatory codes do not have marine specific requirements; therefore, it is often up to the designer to select appropriate design criteria for marine specific loads. Other loads, such as dead, live, and seismic, are often specified by the AHJ based on local standards. The discussion which follows is general in nature as the actual loads required will be based on the selected or required criteria specific to the site location and intent of the AHJ.

Non-Marine Gravity and Lateral Non-marine specific loads are those that are typical for any structure. Usually the controlling criteria will be selected from local building or highway/transportation system code(s).  

  

Dead and superimposed dead loads – Self-weight of structural elements as well as weight of any permanent fixtures. Live Loads – Any transient load due to operations. Typical live loads include:  Uniform: averaged live load from personnel or temporary works  Equipment: such as crane lift or oscillation loads  Vehicular: trucks, forklifts, and mobile cranes (including lifts) Wind on fixed structures – Loads due to wind on permanent structure and fixed equipment. In areas of hurricanes or typhoons this load will often control the design of the structure lateral force resisting system outside of the mooring/berthing system. Snow and ice – Snow (gravity) and ice (lateral) loads are common in colder regions. Earthquake – The hazards to be considered and methods used for evaluation of earthquake loads vary by region in relation to the strength of local seismic events. Some of the primary hazards and methods are discussed below:  Inertial shaking – Shaking of the ground results in movement of the structure due to inertial response. LNG facilities are commonly designed for a multiple levels of events such as a smaller Operational Basis Earthquake (OBE), after which the facility can continue to operate, or a Safe Shutdown Earthquake (SSE), after which the facility can safely stop operations, but there may be significant structural damage. Each event is associated with a different return period and structural performance.  The selected return period event will significantly alter the demand loads for which the structure must be evaluated and retrofit. In many regions, LNG facilities have been historically held to a lower risk acceptance level by use of a longer return period event; therefore, while a marine oil terminal may be designed for a 475-year return period event, a LNG facility at the same location would be required to satisfy a 2,500 year or longer return period event, as shown in Table 11.1. As of 2015, no existing small- to mid-scale LNG projects have been fully developed (that the authors are aware of) which have not made use of the 2,500 year (or greater) SSE event; however, consideration of a lesser event may be appropriate if it is examined through the risk assessment process and is agreed to by the AHJ. For small- to mid-sized facilities, the desired performance (damage) level may be altered while the SSE design event is held at 2,475 years or greater. Thus, for the same event size, the structure may allow for more rotation and permanent displacement. PIANC

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

Report 34 (2001) recommends for ‘special’ structures (which can be interpreted to apply to conventional LNG) that the structure remains serviceable (undamaged) following a major event. For small- to mid-sized facilities the performance may be lowered to allow for slight nonlinearity, assuming that this approach is accepted by the AHJ. Strain limits and other parameters associated with this nonlinear approach are presented in and other marine structure specific documents. Strains maybe considered at slight damage (L1 or OLE), heavy damage repairable within months (L2 or CLE), or collapse prevention (L3 or DE). Soil slope (kinematic) movement – An additional hazard that is significant to marine structures is soil slope (kinematic) movement. Kinematic movement is one or more of liquefaction, slope stability, or flow slide soil failures. Kinematic movement should be considered in combination with inertial response with input from the geotechnical engineer or record.

Reference Document NFPA 59A (USA) CSA Z276 (Canada) NOM 013 (Mexico landside LNG) DNV-OS-C503 Concrete LNG Terminal Structures and Containment Systems (Offshore Structures) BS EN 1473 (Conventional plants)

Performance Level

Design Return Period Event (years)

OBE (operational) SSE (safe shut down) OBE (operational) SSE (safe shut down) Operational (SOB) Extreme (SPS)

475 2,475 475 2,475 Minimum of 2/3 of 2,475 years or 475 years Minimum of 4,975 years or twice SOB

Strength Level (SLE)

100

Ductility Level (DLE)

10,000

OBE (operational) SSE (safe shut down)

475 5,000

BS EN 13645 (Satellite plants < 200 t)

‘Foundations shall be designed in accordance with recognized civil engineering practice’

ISO 18683 (LNG bunkering supply points)

Not Discussed, Risk Analysis Based Selection

Table 11.1: Seismic Return Period Event required by Various International Codes



Earth Pressure – Typically applicable to retaining structures.

Marine  

   

Buoyancy – Uplift due to displaced water is typically insignificant, but can be important for floating structures. Wave – Wave loads may control the design of trestles and/or platforms where significant seismic loads do not occur or where exposure is severe. Development of wave loading should be performed as part of a site-specific metocean study. Extreme and operational wave conditions should be considered. Wave return event selection should also be rationalised against the design life of the facility. Berthing – Load transferred from the vessel to the structure during berthing (impact) when the vessel is coming to berth. These loads are further discussed in Section 9.2. Mooring – Load transferred from the vessel to the structure from a combination of other environmental conditions (including wind, wave, current, passing vessels, etc.) while the vessel is moored at berth. These loads are further discussed in Section 9.3. Ice – Ice loading specific to marine structures can occur when ice builds up against or between piles or when floating ice impacts piles. Tsunami – Project risk assessments should include determination of appropriate tsunami risk from near field and far field events. Operating procedures need to consider the likely warning mechanisms and timing that may be available in consideration of planned evacuation for personnel and vessels.

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11.3 Load Combinations Load combinations are highly dependent on regional requirements and input of the AHJ. As there are a large variety of load combinations; this document does not attempt to prescribe specific combinations for use when designing structures.

11.4 Displacement Limits Displacement conditions can often control the design of marine structures, with pipe allowable displacements being of critical importance when considering extreme events (such as seismic). Total differential displacement between independent structures should be combined by adding displacements of each structure, assuming the structures are out of phase, unless otherwise shown through analysis.

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12 RISK ASSESSMENT Risk can be defined as the product of the probability of an event occurs and the consequences flowing from it. Thus, an event which occurs infrequently and has a low level of consequence constitutes a lower risk than one which occurs more frequently and has a higher consequence. The analysis for each hazard requires the establishment of probability of occurrence and the consequences reasonably expected to be associated with that level of probability. IMO Guidelines define a hazard as “something with the potential to cause harm, loss or injury” the realisation of which results in an accident. The potential for a hazard to be realised can be combined with an estimated (or known) consequence of outcome. The risk methodology assessment as described below is consistent with other PIANC reports intended for marine terminal design, in particular PIANC WG 153 and PIANC WG 116 (2012). The main risks during LNG transfer are spills that will be ignited or build-up of vapour pressure resulting in explosions. Through application of rigorous safety standards, the LNG industry nonetheless has an impressive safety record. Fatalities and injuries to terminal or vessel staff are very rare. Determining hazardous zones, safety zones and security zones is an important part of achieving an essential result of a risk assessment. A safety zone should be established around the bunkering station/facilities to control ignition sources and ensure that only essential personnel and activities are allowed into any area that could be exposed to a flammable gas in the event of an accidental release of LNG or natural gas during operations (as shown in Figure 12.1). These zones may also be temporary. The extent of the safety zone is calculated using the vapour dispersion data for the largest credible leak. As an alternative, a safety zone can be defined following a risk-based assessment. The safety zone should not be less than the hazardous areas and/or the minimum distance defined by authorities. Project specific determination of these zones is required.

Figure 12.1: Example of Safety and Security Zones [ISO/TS 18683, 2015]

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12.1 Reference Documents for Assessing the Risk at LNG Terminals American Standards The main reference document for the design of LNG plants is the NFPA 59A (2014). In this document all basic criteria linked to the equipment, fabrication and operation of LNG terminal is collected in order to assess the safety of the facility itself and any third party facility that may be affected. European Standards The European standards comprise of four main documents for the LNG safety terminal evaluation. Those are ISO 28640 (2010), ISO 18683 (2015), EN 1473 (2007), and EN 13645 (2002). The first document refers mainly to the LNG transfer facilities between the jetty head and the vessel aiming to provide recommendations for the safety loading and unloading operations. The last two documents provide the basic safety criteria for the design, construction and operation of all onshore LNG plant facilities including specifically the liquefaction, storage, regasification, transfer and handling operation either for the marine on the process areas facilities.

12.2 Risk Assessment Methodology A risk assessment consists of the systematic analysis of all cases that might occur as a function of their probability of occurring and their consequences. Subsequently, it will be decided whether the risk is acceptable or not and, if not, controls or safety measures may be implemented to modify the risk to acceptable standards. A typical risk assessment methodology flow chart is shown below:

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Risk Study Design Criteria Definition

Corrective Measures

Risks Identification HAZID

Scenario Definition

Quantitative Consequence Analysis Numerical Models

Qualitative Consequence Analysis

ANALYSIS

ANALYSIS

.Event Trees

.Acceptance Criteria

.Risk Valuation

Risk Assessment

Effectiveness Cost Analysis ACCEPTANCE Acceptance

Operational Procedures Figure 12.2: Typical Risk Assessment Methodology Flow Chart

12.3 Hazard & Scenario Identification The first step of a risk assessment is the hazard identification to define the scenarios to be assessed. Typical LNG terminal scenarios to be analysed are: loss of control of vessel heading resulting in vessel grounding, vessel collision, an impact with the berth, quay wall or jetty, capsizing or loss of hull integrity; and loss of containment due to storage overpressure, storage overfill, leaks, mechanical impact, human error, hose rupture or MLA disconnect resulting in a 45

release of flammable vapours, a gas cloud build-up, fire, explosion, spills and personal injury. Threats may also come from outside the terminal, such as fires and neighbouring traffic. At conventional LNG terminals the most adverse consequences result from a release of LNG. Downscaling a terminal does not change the evaluation process, but does influence the hazard identification. The following are typical for small- to mid-scale LNG terminals: 



  



Manoeuvrability. Tug allocation for manoeuvring will be reduced either in the number of tugs or the bollard pull available compared with typical LNG operation (even no tugs may be used) so the potential of grounding, collision, etc. must be analysed during the risk assessment process. Vessel movements. Vessel movements will be particularly important when analysing berths where waves are beam-on or where passing vessel effects are significant. Dynamic mooring analysis is essential when assessing this risk and should be used to determine operational limits and implement preventive measures. LNG transfer quantities and flow rates. The LNG parcel sizes and transfer flow rates at smallto mid-scale LNG terminals will be significantly lower than at conventional terminals, hence trapped volumes between ESD valves can be considerably lower as well. Pressurised LNG. Conventional LNG deals with non-pressurised LNG. Small-scale LNG may include pressurised transfer and storage (which may only be a few bar), which impacts potential spill quantities and release scenarios which should be taken into account. LNG transfer frequencies. The LNG operations at small to mid-scale terminals may be more frequent than at conventional terminals. The equipment may have to endure more frequent thermal cycles. Location. Small- to mid-scale terminals will most likely be built close to other activities, existing infrastructure, the supply point and the customers. The area around the terminal may be less restricted than for conventional terminals. The impact of the terminals on surrounding activities and vice versa may lead to certain hazards and require measures.

Additional scenarios and hazards are provided in DNVGL (2014). Simultaneous operations to LNG loading/unloading should be considered when identifying hazards and may include:      

Navigation of vessels adjacent to the LNG berth Adjacent facility operations Proximity of public roads and buildings Loading/unloading of trucks/rail at the facility Construction or dredging operations Maintenance

12.4 Risk Evaluation Risk evaluation of the identified hazards will be performed as per the applicable code. Two different approaches are available: 



Qualitative Risk Assessment. The probability and consequences of an event can be represented using an interval scale, where each interval is typically represented by a nonnumerical label, such as ‘high’, ‘medium’ and ‘low’ for the probability and ‘negligible’, ‘serious’ and ‘catastrophic’ for the consequence. Quantitative Risk Assessment. Fixed numerical values (within a margin of error) are assigned to both the probability and consequences of an event. For example, the probability can be expressed as a chance of occurrence per year and the consequence in a monetary value.

For conventional LNG terminals the qualitative risk assessment is typically used during the preliminary stages of a project whilst the quantitative assessment is used for detailed engineering. The approach to be adopted will mainly depend on applicable legislation and regulations and the requirements from the owners and operators. In certain circumstances a qualitative risk assessment may be accepted for small- to mid-scale LNG terminals in the detailed design phases.

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Qualitative Risk Assessment A qualitative risk assessment consists of the following steps for each hazard, as shown in Figure 12.4: 1. Determination of the probability. Frequencies are derived for notional ‘most likely’ and ‘worst credible’ hazard events in each case, using the defined frequency intervals. In general, it is expected that small- to mid-scale LNG terminals may have frequent loading and unloading operations, resulting in increased probabilities of a hazardous event. Particular attention must be paid to those facilities intended for bunkering operations where frequent (or even continuous) operations will be expected leading into an increase of the probability compared with a conventional LNG facility. 2. Determination of consequences. The determination of consequences has to be evaluated on different aspects, such as:  People, health and safety: consequences for personnel involved in work on the facilities or people outside the facilities who could be affected by the activities, such as frost bite and asphyxiation without ignition and burns and potential fatalities in case of ignition. These risks are generally divided into process safety risks and personal safety risks in the oil & gas industry. Process safety concern the major accidents, such as a fire or explosion whereby multiple people can be injured or even killed, which generally have a low probability of occurring. Personal safety concerns the smaller accidents, but high probability events, such as frostbite or trips, slips and falls. Design typically addresses process safety issues, while personal safety is addressed through personal protective devices.  Assets: downtime, damage and/or destruction of property, either within the facility or outside as a consequences of the hazard event.  Environmental: consequences of loss of containment, which may impact the ecosystem. LNG release results in greenhouse gas emission, but is unlikely to result in localised environmental damage.  Reputation: Consequences to the owner’s reputation due to a change in stakeholder’ and public perception, principally related to major events with large impact on the community. This could result in loss of permits and restrictions on future development. Typically, the assessment of hazard consequences for small- to mid-scale LNG terminals will lead to lower consequence classes than for conventional terminals, which is mainly due to the lower volumes being handled and stored. This may not be the case if the terminal is at close proximity to other activities or the public and when pressurised LNG is handled. A hazard may have consequences for different aspects. 3. Assess the risk using the Risk Assessment Matrix (RAM). Based on the probability and consequence a risk level is assigned to each hazard using a RAM, as shown in Figure 12.3.

Probability of Occurrence (Frequency)

Likely

NOT ACCEPTABLE

Unlikely Very Unlikely

ALARP

Extremely Unlikely Remote

ACCEPTABLE Moderate Serious

Major

Catastrophic Disastrous

Severity of Consequence Figure 12.3: Risk Assessment Matrix

The different scenarios are evaluated and placed in the above matrix. Then identified most probable risks are studied in detail to put risk control measures in place.

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4. Identification of risk control measures. The aim of risk control measures is to reduce the likelihood of occurrence of an event or reduce its consequences. A control measure only rarely addresses both the probability and consequence. Reference is made to Section 13 for examples of control measures. 5. Assess residual risk after implementation of risk control measures using the RAM. Scenarios have to be re-evaluated after the implementation of risk-reducing measures that reduce the frequency of occurrence (prevention) and/or the impact (mitigation or protection). The aim is for the risk to be acceptable and as low as reasonably practicable (ALARP), which means that reducing the risk further leads to disproportionate costs. The measure should be technically feasible, practicable and at an acceptable cost. Unfeasible proposals should still be recorded to demonstrate that all possible measures have been considered. 6. Re-do step 4 and 5 until all risks are acceptable or ALARP. Once the preliminary assessment has been completed, based on the residual risk it needs to be decided whether all risks are acceptable and ALARP. If not, step 4 and 5 need to be redone for those risks which are not. Note that the total risk level for the facility generally has to fulfil the standard set by the AHJ.

Hazard Identification 1. Determine Probability

5. Reassess

2. Determine Consequence

Current Risk for Hazard

3. RAM:

4. Determine Mitigations

Probability of Occurrence (Frequency)

Likely

NOT ACCEPTABLE

Unlikely Very Unlikely

ALARP

Extremely Unlikely Remote

ACCEPTABLE Moderate Serious

Major

Catastrophic Disastrous

Severity of Consequence

Assess Residual Risk 6. All are ALARP and Acceptable

NO

Probability of Occurrence (Frequency)

Likely

NOT ACCEPTABLE

Unlikely Very Unlikely

ALARP

Extremely Unlikely Remote

ACCEPTABLE Moderate Serious

Major

Catastrophic Disastrous

Final Risk for Hazard

Severity of Consequence

GOAL: Mitigate risk to ALARP and maximum risk level as set by AHJ (Move down and left) Figure 12.4: Flowchart of Qualitative Risk Assessment Methodology (HAZID)

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Quantitative Risk Assessment It may be necessary to apply a QRA for small- to mid-scale LNG terminals; for example, if it is requested by the AHJ or the terminal owner or operator. For a QRA, the hazards to be identified and quantified. Scenarios leading to loss of containment (LOC) of flammable or toxic substances have to be quantified by assessing the release quantity and associated probability. LOC may concern the ESD-2 of the loading arms or hose rupture. Scenarios leading to asset damage are quantified by estimating the probability of occurrence and the monetary damage. This is done using event trees. Event tree analysis provides a systematic means of determining which factors will influence the hazard, in addition to the probability associated with each of those factors. The following parameters are generally considered in event tree analysis for a release:   

Probabilities of release detection and isolation Time taken to detect and isolate the release Probability of ignition (immediate ignition and delayed ignition)

For each release scenario developed, the consequences should be determined in term of thermal radiation, overpressures, domino effects and toxic cloud formation, which leads to a probability of a fatality. Individual risk relates to the annual risk of fatality of a particular individual, taking into account their exposure throughout their working year, to all company-induced hazards. It is often referred to as IRPA (Individual risk per annum). The risks should be prorated for a full year’s activities. For a typical onshore project a maximum IRPA tolerability criterion of 10-4 per year for process safety contributions to individual risk is often applied. In addition, some onshore projects specify 2x10-4 per year for total work-related IRPA (i.e. including both process safety and personal safety). The location specific risk refers to the annual risk of fatality to a hypothetical individual at a location for 24 hours per day, 365 days per year, unprotected and unable to escape. This is usually used for onshore projects to represent offsite risk and is the cumulative risk from all potential scenarios that could cause a hypothetical person at the specific location to be fatally injured. In a QRA, all location specific risks are translated into risk contours, resulting in a risk contour map for the facility. An example risk contour is shown in Figure 12.5. Depending on the assessment code to be followed, different risk contours have to be depicted.

Figure 12.5: Example of Risk Contour

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Projects typically adhere to the following values, dependent on the selected design code: 

 

Zone A - 10-5/yr contour. Within the 10-5 risk contour there should be no third party activities unless these activities are controlled by the terminal operator. Emergency response within this zone should be linked with that of the facility. When this cannot be achieved, the 10-5 contours should be within the facility fence. Zone B - 10-6/yr contour. There should be no permanent housing within zone B. Although residential developments would be permitted in some countries at these distances from the LNG facilities, in general this should be discouraged. Zone C - 10-8/yr contour. No large congregations of people (hotels, schools, etc.) or facilities where it would be difficult to evacuate people should be located in this area.

Note that these requirements may drive the required plot size and even the location for the facility. Therefore, it is important to make a well-founded decision on the plot size early in the project as a QRA will generally be done well after site and plot size selection. It is also possible that risk contours associated with adjacent facilities (such as petrochemical facilities) may overlap with the hazards of the facility studied and therefore they need to be added to determine a full risk profile. Operations have to assess acceptable safety zones and possible limitations in port activities and regulate all operations and simultaneous operations. Similar to a qualitative risk assessment, a quantitative risk assessment should be performed at least twice, before (original design) and after implementation of controls or risk reduction measures, in order to quantify the effectiveness of the mitigation and assess whether the remaining risk is acceptable and ALARP.

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13 SAFETY MANAGEMENT This section focuses on the safety targets for the operations inside the terminal which shall take into considerations simultaneous operations and the interaction with third parties, including those related to the navigation safety management and implementation of safety. Further reference is made to Part 3 on safety management for LNG and/or CNG bunkering where the operation of the bunkering is discussed in more detail. Procedural risk control measures may address the following points:            

Establish mooring guidance Establish operational limits (navigational and mooring) Navigation marks Port regulations Anti-collision regulations Pilots and Masters expertise and training Training/drills Ship/shore safety check lists Transfer procedures Establish exclusion zones Establish emergency procedures Access restrictions/controls

Reference is made to Section 10.2 which contains hardware barrier safety management systems.

13.1 General In order to ensure that operations can be conducted in a safe way the following minimum requirements shall be met:   

Requirements for operations, systems and components aiming at prevention accidental events that could develop into hazardous situations [first layer of defence]; Requirements to contain and control hazardous situations and thereby prevent/minimise the harmful effects [second layer of defence]; Emergency contingency plan to minimise consequences and harmful effects in situations that are not contained by the second layer of defence [third layer of defence].

Structured training for all personnel involved in the LNG operations and in the LNG and/or CNG bunkering and for all relevant third parties shall be part of the safety management and implementation of safety inside the terminal. The training shall cover, as minimum, roles and responsibilities, potential hazardous situations, risk reduction measures, international and national regulations and guidelines, procedures to be followed during normal operations, and emergency contingency plan.

13.2 Requirements for Operations, Systems and Components All operations, systems and components shall be designed, manufactured and installed in compliance with the relevant and applicable codes, standards, regulations and other guidelines, aligned with national/port laws and regulations and in accordance with a recognised quality management system. Typical measures for LNG operation are: vessel vetting, crew matrix and competence, VTS port control, competent pilot, passage plan and navigational aids, available and efficient tugs, SMS, port rules, nautical procedures and ship/berth interface applicable recommendations. An organisational plan shall be prepared and implemented to regulate all operations and simultaneous operations. It is part of the requirements for operations to assess the acceptable safety zones, security zones and possible limitations in port activities. This assessment shall reflect the interaction with third parties and the required operational envelopes for the simultaneous operations, monitoring and control of ship traffic and other activities within the defined zones.

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Operating procedures shall be established and documented to define procedures during normal operations and to ensure that components and systems are operated in a safe way within their design parameters during all operational phases. All components and systems shall be maintained and tested according to, as a minimum, manufacturer recommendation to maintain their integrity. A specific quality control programme including inspection and tests shall be set up to monitor the quality throughout the different phases of the planning, design, procurement, construction and operation of the greenfield and the retrofit of small- to mid-scale LNG terminals and the delivery of LNG and/or CNG as marine fuel.

13.3 Requirements to Contain and Control Hazardous Situations Appropriate safeguard measures shall be implemented in order to detect any potentially hazardous situation, reduce immediate consequences and prevent escalation. The safeguard measures to contain hazardous situations vary, but shall at least comprise the delimitation and implementation of safety and security zones inside the terminal based on the risk assessment, in which measures are taken to reduce possible ignition sources, and to avoid collisions, impacts or other harmful effects during the operations and/or damage to systems and components.

13.4 Emergency Contingency Plan As part of the emergency preparedness inside the LNG terminal, a contingency plan shall be in place outlining the requirements for the evacuation of personnel and third parties; the mobilisation of fire-fighting, first aid, hospitals and ambulances; and finally, for the communication to authorities and third parties. This plan shall be communicated to all parties involved including the planned emergency response team and be part of a training programme. Key information from this plan related to access, evacuation and ignition shall be communicated.

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14 INSPECTION AND MAINTENANCE Inspection and maintenance activities are key to guarantee the terminal operates as expected during its lifetime. The aim is for safe operations while meeting the required throughput and availability. To ensure this the LNG (un)loading and transfer system is critical. Within the LNG industry, maintenance and inspection for LNG process and transfer facilities have reached very high compliance levels. The civil and marine infrastructure of a terminal generally requires and receives less attention, though regular inspections and maintenance remain important. In this respect, small-scale LNG berths do not differ from conventional LNG berths. This section will not focus on the LNG transfer and process facilities, but on inspection and maintenance of civil and marine equipment as this is the focus of PIANC.

14.1 Inspection and Maintenance Philosophies Inspection and maintenance philosophies should be developed in the design phase and executed during operations. The design philosophy will drive the choice for an inspection and maintenance philosophy:  

Design for the entire expected life of the facility with the aim of minimising inspection and maintenance during the operational phase. Design to a set minimum standard while trying to minimise upfront investment. Regular inspection and maintenance is required to maintain this standard during the operational phase.

The first philosophy requires higher capital expenditure but less operational costs and the second option is the opposite. The choice for a philosophy depends on the design life. A design should be such that maintenance during the design life of a structure is acceptable and does not negatively impact the availability of the terminal below its required availability. This is generally specified by Client requirements and commercial conditions. It should be kept in mind that many structures are used well beyond their design life; which often results in the need to perform inspections more often and to perform increasingly invasive repairs.

14.2 Inspection and Maintenance Strategies There are two common maintenance strategies:  

Corrective maintenance: unplanned and reactive maintenance which is done after breakdown of a system or component. This is also called run-to-failure. Preventive maintenance: planned maintenance before breakdown. This can be either timebased or condition-based. Time-based preventive maintenance regards pre-determined tasks per equipment or system that are executed according to a set schedule. Conditionbased maintenance is determined by an assessment of the actual condition of the component or system before failure (this is generally an inspection); the required maintenance and next inspection date is determined based on the outcome of the assessment.

For each terminal component a strategy is selected and documented. A decision for a strategy can be based on criticality, failure mode (resulting in safety and/or environmental risks), life time, costs, repair time, procurement schedule for components and/or reliability. For less critical and cheaper components, corrective maintenance may be acceptable and most efficient. Predictable and/or frequent maintenance requirements, such as touching up or painting steel structures, can be fulfilled by pre-set time-based maintenance actions. Civil and marine terminal infrastructure generally have a long design life and require little maintenance, but repair and replacement after failure is expensive. Therefore, condition-based maintenance determined by inspection may be the preferred strategy for the civil and marine components of a small- to mid-scale LNG terminal.

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14.3 Guidelines for Civil and Marine Infrastructure Inspection and Maintenance Due to the long design lifetime and limited maintenance requirements the focus for civil and marine infrastructure is likely to be on inspections to assess the condition of the structure or component and maintenance tasks to prevent degradation and large-scale failure. Inspection and maintenance should only be done by qualified personnel. This can be trained operators, certified civil inspectors or maintenance staff from the original equipment manufacturer. For inspection and maintenance of components under water specialised diving companies and/or Remote Operated Vehicles (ROV’s) can be used. Any terminal incidents should be logged and the affected equipment and infrastructure should be checked afterwards. Any follow-up activities should be documented. All inspection findings and maintenance activities, planned and unplanned, should be recorded in a live data base during the life time of the terminal. Civil and marine infrastructure component, guidelines will be provided to help determine an inspection and maintenance strategy. Depending on the terminal, it may or may not have all components as listed in this section. Note that inspection and maintenance of non-civil and marine infrastructure such as piping and process equipment, the transfer system (hoses or marine loading arms), pumps, control and safeguarding equipment (including any ERS- and ESDsystem) is not covered by this guideline. The inspection interval and whether this is time-based or risk-based and should be defined in the maintenance strategy. Reference documents which provide detailed guidance include: 

  

PIANC WG 103 (2008): “Life Cycle Management of Port Structures, Recommended Practice for Implementation”. PIANC WG 119 (2013): “Inventory of Inspection and Repair Techniques of Navigational Structures”. ASCE (2015): “Waterfront Facilities Inspection and Assessment”. OCIMF/SIGTTO (2008): “Jetty Maintenance and Inspection Guide”. OCIMF (2012): “Marine Terminal Management and Self-Assessment (MTMSA)”.



BS 6349-4 (2014): “Maritime works. General. Code of practice for materials”, last section.



Navigational Infrastructure It is expected that navigational infrastructure for small- to mid-scale terminals are maintained by third parties such as port authorities. This includes the approach channel, the turning basin, any breakwaters, and reclaimed land. If, however, this is not the case, an assessment of the required inspection and maintenance for this infrastructure should be included in the design phase. For example, the costs for maintenance dredging may have a significant impact on the terminal operating costs and overall terminal economics.

Shore and Scour Protection Damage or loss of shore protection can occur due to ship propellers, tidal actions, etc. Periodical inspection is needed to check possible land subsidence or collapse, the condition of the armour layer and the slope of the different layers of the shore protection that could be affected by wave effect. Water penetrating inspection techniques and/or ROVs are needed for the submerged part of the shore protection. Diving is possible, but preferably avoided as it has a substantial HSSE risk. An inspection interval of every five years could be considered. More frequent inspections are recommended directly after construction. An additional inspection is recommended after any major extreme event (storm, earthquake, tsunami, collision) or in case of vessels exceeding speed limits or thrusters limits.

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Concrete Structures As a general recommendation, an inspection should be performed the first year after construction of all concrete structures to check their condition, followed by an inspection interval determined by a risk-based approach. The location of these structures, being (semi-)submerged or non-submerged, determines the ease of inspection and preferred method. Non-submerged concrete structures such as roads and paving are generally easily accessible and therefore easily inspected. Drains and drainage systems are an exception and more difficult to inspect, and in the case of an LNG terminal may be safety critical (potential for gas accumulation). In the case of (semi-)submerged structures such as loading platforms, dolphin piles, deck slabs, trestle beams and quay walls, divers and/or ROV’s are required for inspection. Water quality (mainly visibility) greatly impacts the quality of the visual inspection. The costs of underwater inspections need to be included in the terminal operating costs as they can be substantial. During an inspection of concrete structures, the following should be assessed:            

General state (structural and superficial) Reduction of cross-section due to impacts, concrete spalling and/or wall collapse Deformations, delamination, spalling, cracks and holes Excessive deterioration and damage to edges Material loss and discontinuity in joints Evidence of corrosion, such as rust staining and cracks Evidence of chemical damage of concrete, such as efflorescence or disintegration Dampness in non-exposed areas Water leakage Bond degradation Decomposition and bleeding Blockage (of drains and drainage systems)

Concrete in a marine environment is most often degraded due to chloride induced corrosion, sulphate attack, solution leaching and biological attack. When finding any of the above failures the concrete should be repaired (e.g. by grout injection, adding a thicker or more compacted cover or patching) or partially replaced. Repairs should extend beyond the damage to existing reinforcement and should incorporate new sacrificial anodes or other methods to prohibit future corrosion due to dissimilar concrete materials. Particular care should be taken when repairing deck areas, especially those fitted with bollards or equipment requiring a strong and level base. Expert advice should be sought to define an appropriate method of repair, including material selection and repair procedures, of the affected area.

Steel Structures It is recommended to check the condition of all steel and metallic structures, welds and bolted joints. The inspection method will differ depending on material and location (above or below the water line and/or ground). During an inspection of steel structures, the following should be assessed:        

General state Permanent deformations (due to dent, buckling and impacts) Any thickness reduction Evidence of corrosion (corrosion is typically most severe in the splash and lower tidal zone) State of coating/paint (See Section 14.3.5) State of cathodic protection (See Section 14.3.6) Scouring around piles Joint integrity (bolted connections and welds)

In addition to visual inspection, measurements can be done to assess the structure or joint integrity. Welds can be inspected using techniques such as visual, radiographic, magnetic particles, liquid penetrant and/or ultrasonic inspection. The most typical weld defects and failures are deformations, superficial or internal discontinuities, cracks, porosity, inclusions and corrosion.

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Steel sections can also be inspected with many of these methods as well as with bathycorrometers. When finding any failures or degradation actions should be taken to ensure the integrity of the structure and prevent further failure or damage.

Coating and Painting It is suggested that all coating and paint is inspected for deterioration or damage in order to repair it before major damage occurs. Concrete-steel interfaces especially, should be inspected. Coating and painting inspections are recommended to cover, as a minimum, the general state and any damage such as chips, flakes, rust and porosity. Depending on the maintenance strategy, touch-up painting can be done as soon as damage occurs or blasting and renewal of paint can be done when larger areas of the coating have failed. As coatings are generally applied to protect structural elements such as jetty piles, maintaining the integrity of coatings can prevent significant maintenance and even replacement costs of civil and marine infrastructure. Timing of coating repairs is therefore critical.

Cathodic Protection The integrity of the cathodic protection system can be assessed by checking the state of the corrosion monitoring system (if any) and by assessing the amount of corrosion. The degree of corrosion cannot always be determined from visual inspections; hence, non-destructive measuring techniques may be needed. The inspection of the cathodic protection system should focus on the following aspects:     

General state of the system Detection of any corrosion Characterisation of the corrosion type Quantification of the corrosion damage (individual anode weights and dimensions) Evaluation of the environmental conditions that can affect the protected structures (microbiology, saline-fresh water effects, etc.)

If a high consumption rate or an unusual degradation of the cathodic protection is found, it is recommended to investigate the underlying cause and take corrective measures to reinstate (and if necessary change) the cathodic protection system. It is also prudent to evaluate the effectiveness of impressed current systems when there is a stringent requirement for electrical isolation of LNG carriers moored alongside the terminal. For active (impressed current) systems, regular checks should be performed between inspections to verify that the rectifier is powered and functional.

Elastomeric Bearings Visual checks are suggested for elastomeric bearings. When inspecting the terminal’s concrete and steel structures, inspection of any elastomeric bearings is also recommended as any damage to the bearings may be caused by the structures and failure may negatively impact the structures’ integrity. Inspection of elastomeric bearings should include an assessment of:       

General state Any local cracks near or on the support Ageing and dirt (grease, oils, etc.) State of the anchoring system Position of the bearing (any misalignment, displacement and/or blockage) Dimensions of the bearing (flattening or excessive deformation due to vertical loads) Other defects

Fender Systems As a starting point, visual inspections to check the vertical position of the fender shields and the chains could be done every month. The wear of polyethylene plates could be checked every six

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months. A detailed inspection of the fendering system is recommended at least every two to four years and after an incident. Fendering should be inspected during the overall structural inspection. The most typical defects and failures for fendering systems are:    

Rubber defects due to marine growth Damaged steel elements (such as eroded areas) Cracks, elongations and/or expansion differences Loss of the chains, sleeve nuts and tightening system

The fendering system can be accompanied by a jetty berthing system which provides further aid for vessel berthing. It is recommended that its functionality is checked every month. The following checks are recommended:   

Functionality of the lasers for the measurements (which serves as input to calculate the distance, berthing angle, speed, etc.) Functionality of the monitoring panels (which provide the different berthing parameters such as distance, speed, etc. to the captain of the approaching vessel) Clear line of sight from the vessels’ bridge to the monitoring panels

In case of any findings during the inspection an assessment should be made if safe berthing of vessels can continue. If not, repairs should be done before the terminal can be operated again.

Quick Release Hooks Quick Release Hooks (QRHs) should be inspected frequently. When inspecting or doing maintenance on QRHs, the system should be properly isolated, with electricity disconnected before opening the box or working on the QRH and no work should be done when the surface or the device is wet or humid. Inspection of the QRHs should include:    

Assessment of the general state Detection of any corrosion Electric check of the capstans (i.e. power availability, internal fuses, thermal protection, footswitch contact blocks, capstan control relays, availability of control voltage, etc.) Mechanical check of the hooks (i.e. state of the springs, lubrication of the hooks, etc.)

Bollards Cracks, deformation, corrosion and the interface between the bollard and its supporting structure should be investigated to prevent failure of bollards. In case of deck area repair, particular care should be taken near bollards to ensure that their integrity is not negatively affected.

Gangways It is recommended to do an operational check of the gangway every 6 months, which consists of checking the following:      

Gangway envelopes Envelope limit alarms Functioning warning bell Appropriate illumination Mechanical brake Electrical bonding and isolation (gangways are an ignition source and may be close to the transfer point)

The hydraulic system, power pack and control box should be checked every three months. This inspection should include:      

Leak integrity test of the hydraulic system during a functional test of the gangway Check of the hydraulic piping and fittings Check of the oil level of hydraulic power pack Visual check of cylinders, hoses, piping, connections, pumps, valves, instruments, etc. Verification of the correct functioning of the control box Check of the electric components

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PART 2 – RETROFIT OF EXISTING MARINE TERMINALS 15 GUIDELINES FOR APPROACH TO RETROFIT While Part 1 focuses on the design of new facilities at new (greenfield) sites, Part 2 focuses on the design of new facilities or functions at existing LNG facilities, existing marine facilities without LNG but with continued use (multi-use), or existing marine facilities without LNG or other activities (brownfield). This part is summarised in the flow chart shown in Figure 15.1. While the specifics of design will vary with each project, the overall approach for retrofit projects will be similar. Specific topics from this flow chart are discussed in greater detail below.

Concept of New Use

Existing Use

Existing Condition Assessment

Basis of Design Repair and Retrofit Design

Retrofit Design

Risk Assessment Iterate Design

Construction Permits Granted Phased Construction for Operations Certification of New Use Operate and Maintain

Figure 15.1: Flow Chart of Approach to Retrofit for Small- to Mid-Sized LNG Facilities

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16 CONCEPT OF NEW USE The concept of new use developed for an existing facility is similar to the concept of operations developed for a new facility (see Section 5.1); however, the new operation must be shown to be consistent with or replace the current use. At existing LNG facilities where existing operations will continue the new use must be considered in relation to the current use. This includes the following:     

Vessel navigation for continued LNG vessel calls during construction as well as at the commencement of new operations Re-use of existing LNG storage and conceptual planning of new manifolds or pipeways Re-use of existing LNG loading equipment (feasibility study level of detail) Re-use of existing mooring hardware (feasibility study level of detail) Evaluation of safety/exclusion zones (feasibility study level of detail)

The intent of these studies is to determine if the new use can be reasonably incorporated into the existing use of the facility without unacceptably affecting the current use of the facility. At facilities that will be converted to multiple uses, similar studies will need to be performed; however, evaluation of the available setback distances may be most critical as it may be difficult to alter existing property lines. Early use of quantitative risk assessment, at a feasibility study level, may be justified in order to verify that the site is appropriate for use as an LNG facility. Careful consideration of simultaneous operations should be included in any such study. New operations must be considered in relationship to the continuing operations at the facility. If LNG operations are to be done on an irregular basis, then plans should incorporate the different safety and security measures (with and without LNG operations). Where LNG storage is to be added to a multi-use site, additional safeguards may be necessary ensure that non-LNG use does not create a hazard to the LNG storage and vice versa even when no LNG operations are underway. At single use brownfield sites there may be a greater ability to alter the site or facilities. Preliminary feasibility studies should include those discussed above as well as evaluation of the existing facility footprint to determine if it is sufficient to fit all new planned operations. If it is expected that new marine structures will be required, then condition assessment studies can be altered to focus on facility replacement. A clear scope should be defined, which should take into account the following specifics for brownfield development:     

Unidentified scope and scope growth Execution complexity and planning Ongoing operations and simultaneous operations Downtime HSSE considerations

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17 EXISTING CONDITION ASSESSMENT The existing condition assessment is critical when considering retrofit of existing facilities. Assessment(s) may include direct observation (visual and/or tactile inspection), limited physical examination (such as scraping of biological growth), or destructive testing (coring of piles, sampling of materials). Facility elements which should be examined include (but are not limited to):             

Marine structures – both above water and underwater inspections mooring/berthing hardware Available water depths – via bathymetric or side-scanning sonar surveys Backland surfaces – settlement or infill loss induced surface cracking Slope protection & scour protection Piping – hydrostatic, ultrasonic, or radiological investigations Equipment – hydraulic systems and pumps Corrosion protective systems – remaining life of anodes and upkeep of rectifiers Elastomeric bearings Gangways Firewater monitors Environmental monitoring systems – anemometers, ADCP, etc. Lighting, aids to navigation, and jetty berthing systems

The focus of these assessments is to determine if the existing elements are in an acceptable condition to be re-used, what repairs and/or upgrades (if necessary) are needed to bring the facility to a fit-for-purpose condition, and whether the conceived operations discussed in Section 16 are consistent with the actual conditions of the facility. The condition assessment serves the added purpose of documenting initial conditions prior to the start of work, which can become important if construction errors or damages occur. Therefore, it is recommended that the condition assessment be performed across all areas of the site that may be subject to construction or construction staging. There are many excellent documents discussing the details of existing condition assessments of marine structures and petrochemical facilities, as discussed in Section 14.2. Where possible, collection of original as-built documents, studies, or any other available information should be compiled. This information can be incorporated into the existing condition assessments or may be included in the retrofit design / preliminary feasibility studies. Information, such as that given below, can be critical to understanding the existing facility:             

Original construction documentation  Scope of work, design lifetime, codes and regulations, design vessel fleet characteristics, design loads, load combinations Climate/Metocean/Tsunami studies Jetty Availability and Navigation or Simulation Studies As-Built Drawings LNG transfer system specifications Mooring and Berthing Hardware Specifications Corrosion Protection System Specifications Tugboat and other marine services records Permitting and authorities releases Material properties and quality control specifications and test reports Geophysical, geological, and geotechnical surveys or reports Pile driving records Existing LNG operations and piping design  If the existing facility is a large-scale facility, the transfer system and piping have an existing design thermal cycle period. In the case of small-scale operations, the connection and disconnection requirement may be more frequent than the existing design thermal cycle allows. The design capability of piping and systems should be compatible to the new requirement of thermal cycles. In case of multiple parcels, a day, forced warming (to decrease disconnect times) may be required.

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Original studies should be re-evaluated to determine if they are consistent with current design practice. Often data underlying geotechnical or metocean studies may not change, but the interpretation of the data or modelling techniques will have been refined with time. A formal gap analysis of original design criteria versus modern codes should be performed to verify that all elements are captured and to determine what additional data should be collected. Where limited data is available, it may be necessary to assume structural characteristics (such as material strength or detailing) consistent with similar structures of the same construction era in the same region. Non-destructive testing (such as radar, x-ray, or ultrasonic testing) or destructive testing (such as coring, limited demolition, or coupon sampling) may be necessary in order to determine material strengths or corrosion states.

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18 RETROFIT DESIGN Retrofit design is typically an iterative process which can evolve as greater knowledge of the existing facility is developed. While the existing condition assessment is intended to determine all existing information, it is often necessary to revisit data collected or perform more invasive studies during the design development. In some cases it may be necessary to alter the concept of operations or basis of design based on the findings of continuing investigation and design development.

18.1 Basis of Design The Basis of Design developed for new LNG use at an existing facility is similar to that developed for greenfield sites (Section 5.3); however, consideration of the existing use and/or continued use must be incorporated into the criteria. For existing LNG facilities, the introduction of new small to mid-sized operations will likely be straightforward as the Basis of Design will likely be similar to that of the original construction, with the following exceptions:    

Calling vessels will change Equipment flow rates and operations will change Loading arm or hose envelopes may be significantly different Out-of-date design criteria will need to be updated to current requirements of the AHJ. This may result in the requirement for structural alteration; however, it is not expected to typically be the case. Elements outside of altered areas will likely not require upgrade to satisfy newer code.

Where LNG operations are being first introduced to existing facilities, the introduction of LNG will be considered a change in use which may require more stringent codes than the original design criteria. The design criteria selected for re-use of an existing structure for LNG bunkering will require to be selected and/or approved by the AHJ. Therefore, it is important to confirm all stakeholders are included in discussion of design criteria at an early phase of the design.

Mooring Criteria Mooring criteria at existing facilities is unchanged from greenfield sites in analysis methods (See Section 9.3); however, the criteria for selection of mooring hardware may be limited to allow for the use of existing hardware. If the AHJ or operator does not allow for the use of existing bollards or existing mooring hardware is insufficient, then alteration of the existing structure may be necessary.

Seismic Criteria In regions with high seismicity, design of the LNG operations supporting structure (platforms and approach trestle) for seismic load will likely control the decision to retrofit or replace existing structures and will likely govern the acceptability of loading/unloading platforms and trestles. While it may be possible to economically retrofit an existing structure for higher levels of performance (less damage) at longer return period events than the original inertial design incorporated, it is often the soil slope movement which controls the structural response under these larger earthquake events. If the site features significant fill, poorly placed rock dykes, or other geotechnical features which may move during seismic events, there can be a combination of slope stability failure/liquefaction/flow slide (generically referred to as ‘kinematic movement’) which results in large soil movements beneath the structure, as discussed in Section 11.2.1. If this response occurs, it is typically difficult to make existing structures perform satisfactorily. Smaller diameter concrete is likely to rupture within the soil and steel piles will likely see rotations within the soil greater than their acceptable strain or stress. Retrofit of the piles themselves is not possible as they are below the mudline. Soil improvement is often un-economical due to the soils being below water. In some cases it may be required to remove the existing structure and install a new structure.

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Tsunami and Sea Level Rise Criteria For existing structures, tsunami and/or Sea Level Rise are hazards that should be considered. Unlike new structures, existing structures have set deck elevations which may be uneconomical to alter. If inundation of the existing deck elevation is expected, then new LNG piping and support systems must be located above predicted tsunami and/or sea level rise elevations (with additional protections against floating debris impact) or new structural systems should be provided. Existing retaining systems may be able to have the top surface raised; however, study of the capacity of the existing retaining structure as well as induced settlement from the extra overburden need to be made.

Existing Equipment Re-Use It is possible that existing equipment may be re-used for new operations. Hose towers, cranes, and other handling equipment may be re-used if they are found to meet current design requirements and can be retrofit as necessary to satisfy cryogenic exposure risks. Piping for firewater lines and other utilities may be re-used; however, cryogenic piping for LNG will require new systems as it requires specialised material and insulation which is not typical of non-LNG uses. Any existing piping or equipment to be re-used will likely require thorough inspection, possible rehabilitation, and re-certification. Consideration of the cost of rehabilitation/alteration compared with the cost of replacement should be performed early in the design development as in many cases it may be more economical to not re-use existing equipment.

18.2 Repair and Retrofit Design Repair Repair of existing damage is highly recommended in order to make the design life of the existing facility consistent with the operational design life desired for the new use. Additionally, repairs may be performed to provide for acceptable structure performance, such as providing additional ductility to brittle elements in seismic regions. In some cases, retrofit of existing structures to have a greater design life than the original construction (such as providing jackets to timber piles) may be necessary in order to meet the desired design life or demand loads/displacements of the new use. Repairs will likely need to meet a performance consistent with current code requirements, per direction of the AHJ.

Retrofit Design Most structural design criteria are intended for new construction, not for evaluation of existing facilities. When there is a significant change in use (such as introduction of LNG operations), there is a trigger to re-evaluate and upgrade the facility to meet new construction requirements. For the purposes of this document, it is assumed that the existing facility will be developed to meet the recommendations of this document, as well as other new construction documents (such as PIANC WG 153). In some cases it may not be possible to meet prescriptive design code requirements (such as concrete detailing requirements) and exemptions may be required from the AHJ. Early identification of conditions where current code cannot be satisfied by existing structure should be the focus of preliminary feasibility studies as they can significantly increase the capitol costs of a new facility, to the point where removal and replacement of existing structure may be more cost effective in some cases. Where existing mooring hardware and/or supporting structure is undersized for the new vessels (possible with re-utilised existing facilities) it may be necessary to install new mooring hardware or fender systems. Fender systems may be sized to provide reactions that are acceptable to the structure by use of larger softer fenders. If the existing structure is found to be insufficient to support new mooring/fendering hardware, then localised structural replacement may be necessary, such as the installation of a monopile or dolphin within the footprint of an existing structure. Where the AHJ requires that tension monitored quick release hooks be used, this will also likely force the replacement of structure (which may be limited to just the deck) as existing hardware may not be readily removed and replaced. All retrofit hardware and structures should be designed consistent with the mooring and berthing requirements for new design and based on up-to-date metocean and mooring/berthing analysis findings.

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Cryogenic protection of existing structures which have not been used for LNG operations will be required to be added. This may include providing new concrete jackets or other thermal protection to the existing structural members. Containment areas should also be protected from cryogenic exposure.

18.3 Risk Assessment Risk assessments for existing facilities for new use should be performed consistent with those of new facilities at greenfield sites (Section 13) with the added complication that multi-use facilities (including multiple LNG operations) require that evaluation of simultaneous operations must be considered. Additionally, the risks of heavy construction on its own may be incorporated into the risk assessment or may be assumed independent of the facility, depending on the desire of the owner and requirements of the AHJ. If multiple phases of construction are to be performed in order to continue operations during construction, then additional emphasis needs to be placed on the transitional phases of operations. Items of particular interest may include     

Major downtime or turnaround events Temporary piping, equipment, structures or other facility elements. Extensions or alterations of the site perimeter during the phases Heavy construction (pile driving, welding) which may result in hot work or unusual levels of vibration Structural capacity in all (temporary) phases of the construction

Safety and exclusion zones determined for all phases of construction should be summarised in reference figures which ensure that classified or exclusion areas are not entered by construction activities. A safety management system should be put in place during construction and an organisational chart of responsible parties and contacts for all scenarios should be distributed.

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19 PHASED CONSTRUCTION Unlike new facilities at greenfield sites, for existing facilities where operations will occur during and following introduction of the new LNG functions, it can be expected that new operations will require multiple phases of construction. Phased construction requires consideration of all current operations, alterations of those operations during the construction, and determining a final condition that allows for acceptable continuing operations. This mode of construction also requires close coordination between the contractor and operators. In some cases, contractor construction windows may be limited to times between vessel calls for some or most activities. This can lead to higher construction costs (due to contractor downtime); however, it is often economically advantageous compared to the cost of facility downtime. In some cases, the costs of capitol expense associated with phased construction may require that pipeways or equipment be relocated during construction. It is also common to remove portions of a structure to make room for newer structures. New structures may be temporary in nature or may be designed as final construction. Typically, structure designed to be temporary in nature may be designed for less stringent requirements (no protective coatings, lower seismic return event, lower design storm event) consistent with a very short design life.

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20 CERTIFICATION/OPERATIONS/MAINTENANCE Following the completion of construction the facility must still go through certification and will continue to have ongoing operation and maintenance work. Certification includes all testing and final calibration efforts to bring the facility online. It is expected that small- to mid-sized LNG facility certification at existing facilities will be similar to that at greenfield sites. Where multiple uses or berths are located at the same facility, the certification process may occur during various portions of the phased construction and be associated with specific piping/equipment only. Operations and continuing maintenance are also to be expected for any facility and will be dependent on the functions of the facility; however, it is not expected that maintenance at newly retrofit existing facilities will significantly vary from that at greenfield sites. Regular maintenance inspections should be performed over the lifetime of the facility and should verify the current condition of all systems and structures, as discussed in Section 14.

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PART 3 – LNG AND/OR CNG BUNKERING 21 GENERAL OVERVIEW 21.1 Introduction This part covers LNG and/or CNG bunkering at a marine facility. Only the effect of the bunkering operation on the terminal infrastructure will be covered herein, not the bunkering operation itself. In this document only bunkering directly from an LNG terminal or LNG bunkering station and by LNG tanker truck is considered, since these activities affect the civil and marine infrastructure. Although CNG is mentioned as a bunker fuel, the focus of this section will be on LNG bunkering, since the use of CNG as fuel for shipping is very limited to date. CNG bunkering will be mentioned separately when applicable and briefly discussed in Section 21.5. Guidelines for LNG bunker operations are provided by, but not limited to, ISO 18683 (2015), SGMF (2014), and (IAPH). At present there are two main approaches for refuelling an LNG-powered vessel: Ship to ship: Bunker supply from a floating storage to any receiving ship. This guideline scope is limited to effect in infrastructure for this supply arrangement.

Figure 21.5: Typical ship to ship bunkering arrangements/layouts

Shore to ship: Transfer of LNG from shore side source (tank, truck, rail, pipeline, ISO container, etc.) to the vessel.

Figure 21.6: Typical shore to ship bunkering arrangements/layouts

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Figure 3.1 and 22.6 schematically shows the involved elements described above of LNG bunker supply terminals covered by this guideline. In case the bunker LNG transfer takes place at a fixed terminal, such as a permanently moored barge, quay wall, jetty, Floating Liquefaction Unit (FLU), Floating Storage Unit (FSU) or Floating Storage and Regasification Unit (FSRU), and it is classified as small- to mid-scale, this guideline is applicable. Ship to ship LNG bunkering, such as that performed by vessels such as the one shown in Figure 21.1, is discussed briefly in regards to the infrastructure needed to support side-by-side operations, but not in regards to the operations themselves, which are covered by other documents (IMO). Containerised LNG (or ISO containers) requires no specific marine infrastructure; therefore, it is not discussed herein as only specific operational safety aspects are applicable, which are outside the scope of this guideline.

Figure 21.1: Small-scale LNG Bunker Barge [HHPInsight, 2015]

21.2 Drivers for LNG as Bunker Fuel The use of natural gas (LNG or CNG) as a fuel is a possibility for complying with emissions of harmful atmospheric pollutants, such as nitrogen oxides (NOx) and sulphur oxides (SO x). In addition, it reduces the carbon footprint of vessels. Within an ECA (Emissions Control Area) the maximum allowed sulphur content in ship fuel has been lowered to 0.1 % (by mass) as of January 1, 2015. Similarly, NOx will be set at Tier III limits within ECAs starting in 2016. There are also Sulphur Emissions Control Areas (SECAs) for which only the above-mentioned Sulphur reduction applies. The first SECA was the Baltic Sea (since 2006) followed by the North Sea (2007). The first complete ECA is the North American ECA (2013).

Figure 21-2: IMO Worldmap for Emission Control Areas

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Inland waterway traffic in western Europe (Belgium, Germany, the Netherlands and Switzerland) already effectively operates as a SECA, with a limit of 10 ppm (approximately 0.001 %) of sulphur in diesel fuels. ECAs have been proposed for many other areas but are yet to be fully defined. The International Maritime Organization (IMO), through its marine pollution protocol (MARPOL), is working to reduce emissions of sulphur and particulate matter worldwide by 2020 or 2025 from the current limit of 3.5 % to 0.5 %. Compressed natural gas has been used for many years as a road transportation fuel and more recently for ships. A CNG-fuelled ferry is operating in Brazil. The disadvantage of CNG, and to a lesser extent LNG, is its energy density. CNG is stored at 250 times atmospheric pressure and has an energy density of only about 9 MJ/m 3. LNG is more than twice as dense as CNG at 22.2 MJ/m3. Petroleum fuels are still much better than either CNG or LNG as they have densities at about 35-40 MJ/m3, as shown in Table 21.1. This means that CNG vessels (and to a lesser extent LNG fuelled vessels) need large fuel tanks or short distances between refuelling. In addition, the cost for LNG and CNG tanks and installations are higher than conventional tanks for petroleum fuels. Energy Source

Energy Density

Relative Required Tank Volume (Excluding Insulation etc.)

Petroleum fuels (e.g. HFO)

35-40 MJ/m3

X m3

LNG

22.2 MJ/m3

Approximately 2 * X m 3

CNG

9 MJ/ m3

Approximately 4 * X m 3

Table 21.1: Relative required tank volume for different energy sources

21.3 LNG Fuelled Vessels Routes Interest in the use of LNG as a bunker fuel is growing rapidly, not just in ECAs but around the world. As of Q1 2016, the confirmed world fleet of LNG fuelled vessels consists of fewer than 150 vessels, of which 63 are in operation, such as the Viking Princess shown in Figure 21.3. As of Q1 2016 the state of LNG vessels usage by region is listed below: 







Europe. Most of the gas-fuelled vessels in service are in Norway. The Norwegian government stimulates the use of LNG as marine fuel through the ‘NOx fund’ aiming to reduce NO x emissions. The first vessel entered service in 2000 and by the end of 2013 the Norwegian fleet had increased to more than 30 vessels. Northwest Europe and France are also involved or have ordered vessels for their coastal or short-sea trades. On the inland waters of Northwest Europe, 6 LNG fuelled inland barges are in operation. US/Canada. North America started later than Europe. However, the amount of activity over the last two years means that this region looks set to overtake Europe very quickly – primarily in the USA, but also in Canada. Initial LNG bunkering projects for container vessels are developed for dedicated routes that require US flagged ships and remain within the ECA for the majority of their route. East Asia, Japan, China, Malaysia and Singapore. Countries within this region are very active in putting systems in place to enable LNG to be used as a marine fuel. South Korea has built the first vessel (a public relations vessel for the Incheon port) which is in service in Incheon harbour. China has two LNG-fuelled tugs in service and continues to push forward with more vessels. Other regions. Brazil has a CNG ferry in operation. Indonesian ferry owner Pelni is examining converting its 26-ship fleet to LNG with national oil and gas company Pertamina. Australia is close to ordering its first gas-fuelled ferry to run between Melbourne and Tasmania.

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Figure 21.3: LNG fuelled vessel PSV Viking Princess operating at Norwegian facilities

A number of large container vessels and also cruise vessels under construction will be ‘LNG ready’, which means that space for LNG tanks and equipment is available in these vessels. The actual installation of the LNG components however is foreseen in a later stage. In particular for cruise vessels one of the drivers for LNG is having a ‘green image’ to the public.

21.4 Available LNG Bunkering Facilities LNG can be bunkered at a number of Norwegian ports, including Bergen, Oslo and Risavika/Stavanger. In most cases bunkering is performed by a tanker truck. The port of Bergen has a dedicated terminal for LNG bunkering. Halhjem has a dedicated LNG bunker station for a LNG fuelled ferry. Stockholm operates an LNG bunker vessel to supply an LNG fuelled ferry. LNG is available for marine fuel use in the European ports (not limited) of Antwerp, Amsterdam, Rotterdam, Stockholm, and Zeebrugge. LNG bunker barges have been ordered for operations in the ports of Zeebrugge and Rotterdam. Ports in Finland, Italy, and Spain have also loaded LNG as bunker. All of these ports are able to offer LNG to prequalified vessels that are compatible with the LNG-loading infrastructure.

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Figure 21.3: Existing and Forcast Global LNG Bunkering Infrastructure [DNV, 2014]

EU policy is to have at least one LNG bunkering port in each member state. About 10 % of European coastal and inland ports will be included, for a total of 139 ports. To date Denmark, Estonia, Finland, France, Germany, Norway, Spain, Sweden and the UK are considering where to locate LNG bunkering facilities. There are several ports under development offering LNG bunkering in North America e.g. mostly in the Gulf of Mexico and around the Great Lakes. South Korea is able to offer LNG bunkering in the port of Incheon for ferry operations on the west coast and is looking at a second facility at Busan. Elsewhere in Asia, countries such as Singapore, Japan and China are looking at LNG facilities.

Figure 21.4: 3-D view of LNG breakbulk terminal in the Port of Rotterdam

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Figure 21.4: LNG breakbulk terminal under construction in the Port of Rotterdam

21.5 CNG Bunkering Facilities CNG is well developed for land based transport, but the use of CNG as fuel for shipping is very limited to date. As mentioned earlier a disadvantage of CNG is its energy density. CNG is stored at 250 bar and its density is less than half of the density of LNG. Hence, CNG vessels need relatively large fuel tanks and/ or short distances between refuelling; CNG might be chosen for shorter voyages within the same or between a few ports. As of Q1 2016, the confirmed world fleet of CNG fuelled vessels consist of only a limited number of ferries operating at short sailing distances. CNG fuelled ferries operate in Brazil and Thailand. In 2016 another dual fuel ferry (CNG) will enter into service in Brazil and the first European CNG ferry (dual fuel) will enter into service in The Netherlands with its own dedicated CNG Bunker station. The International Association for Natural Gas Vehicles (NGV GLOBAL) (not restricted to ships) has a useful website for CNG developments.

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22 DESIGN GUIDELINES OF LNG/CNG SUPPLY POINTS AT EXISTING/NEW QUAYS This chapter focuses on the design of LNG / CNG bunkering supply points at new (greenfield) or existing (brownfield) facilities, which is similar to the design guidance provided in Parts 1 and 2; therefore, the discussion which follows is intended to focus on differences between bunkering facilities and conventional small- to mid-sized LNG facilities. Persons interested solely in bunkering should still review the first two parts of this report as much of the information is applicable to bunkering facilities as well. Existing facilities in this chapter are assumed to not have LNG operations occurring prior to the introduction of LNG bunkering. Chapter 24 addresses existing facilities wherein LNG operations are occurring in advance of bunkering operations being introduced. As the number of bunkering facilities grows, it is likely that new challenges or unforeseen consequences will likely grow. The information provided below is not all inclusive and care should be taken to consider site specific characteristics that may not be included. As LNG bunkering is a relatively new field, careful evaluation of new conditions and lessons learned from previous experience should be incorporated into each design.

22.1 Greenfield Bunkering Facilities Development of new small bunkering facilities at greenfield sites will likely be unusual as the relative cost to develop the infrastructure is high. Likely, such facilities will be intended for larger bunkering operations (such as supplying bunker barges) or will share their LNG storage capacity with other operations, such as peak shaving power facilities for the electrical grid. Design of greenfield bunkering facilities will be consistent with Part 1, with the following exceptions or critical items: 

  

If bunkering operations are temporary in nature, then security perimeters will likely require to shift during operations. This will require coordination with adjacent sites and possibly with other vessel operations in the area. Truck-to-ship and ISO container transfer are further discussed in Section 22.2 as they are more likely to occur at existing facilities then dedicated new terminals. For bunkering of smaller vessels, use of bollards or cleats may be acceptable (so long as agreed to by the AHJ). The cost of tension monitored hooks for small facilities is likely prohibitively expensive and inconsistent with typical small vessel operations. LNG transfer lines are likely to be hoses for small vessel bunkering, due to the lower capital costs and smaller flow rates. In case of high throughput, MLAs are easier and quicker to connect. For small vessel bunkering, where exposed volumes are low, it may be possible to locate bunkering facilities closer to existing infrastructure than is possible with mid-sized or larger facilities. Site location will still be dependent on risk assessments consistent with that discussed in Section 13. Quantified risk evaluations may be advantageous for smaller facilities as they will allow for better understanding of off-site setback requirements.

22.2 Brownfield Bunkering Facilities (Without Current LNG Operations) It is expected that development of new LNG bunkering operations will likely occur at existing facilities in order to minimise costs of new construction and due to limited availability of greenfield sites. As an example, Figure 22.1 shows the installation of a new LNG storage tank for bunkering operations at an existing ferry terminal. This new usage is likely to drive challenges in facility design and retrofit. The introduction of LNG bunkering equipment and operations is likely to change the criteria by which the existing structure should be evaluated, and retrofit should be designed. In some cases, the cost of retrofitting an existing structure may be prohibitive compared to the cost of removal and replacement.

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Figure 22.1: Installation of LNG Storage Tank at Existing Ferry Terminal [Port of Hirtshals, 2015]

The design criteria selected for re-use of an existing structure for LNG bunkering will require to be selected and/or approved by the AHJ. In some cases, such as truck-to-ship or container-toship transfer operations, there may not be clear jurisdiction or structural criteria appropriate for LNG transfer. Therefore, it is important to confirm all stakeholders are included in discussion of design criteria at an early phase of the design. It is advised that even for mobile operations (truck-to-ship or ISO container-to-ship transfer) where LNG is only temporarily on site that the infrastructure be assessed corresponding to the risk based evaluation of the mobile operations. The selected risk criteria at these mobile operations must be approved by the AHJ. Items of particular interest for mobile operations include:      

Live loads, such as truck loading Seismic return periods appropriate for the existing structure Accidental truck impact loads requiring safety barriers Electrical earthing/grounding Cold spill assessment / protection Drainage/containment which could lead to entrapment/confinement of LNG

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23 DESIGN GUIDELINES OF LNG BUNKERING FACILITIES AT EXISTING/NEW MARINE LNG TERMINALS 23.1 Scope & Definitions This section applies to existing or new small to mid-scale LNG terminals adapted to LNG bunkering activities. This guidance is given in order to provide a safe, efficient and cost-effective operation of bunkering facilities at these terminals. Alternatives for bunkering services are provided herein, including considerations of the supplied vessel or supplying ship size, LNG storage and throughput capacity, ship traffic, berthing compatibility, etc. This discussion is not intended to address unmanned facilities.

23.2 Functional Requirements/BOD Bunkering Facilities at Existing Conventional Terminals Conventional terminals may be adapted as shore to ship bunker points. In this case, the small- to mid-scale LNG bunkering shall be incorporated into the existing LNG basis of design. Critical aspects that must to be verified when assessing the feasibility of conducting bunkering operations at conventional terminals are listed below. These aspects assume that ships being supplied at the facility will be small-scale LNG carriers, LNG fuelled ships, bunker barges and could even include small auxiliary crafts, such as tugboats, pilot boats, etc: 1. Nautical compatibility, including items involving port planning and facility layout: a. Navigational areas: Section 8 addresses general navigational aspects. Smaller bunker barges and auxiliary boats are not likely to require tug assistance. However, larger small- to mid-scale LNG bunker carriers or LNG fuelled ships may be tug assisted to ensure safe operations. Navigation areas should consider whether tug support will be provided. b. Berthing arrangement: Section 9.2 addresses berthing issues. Fenders will require to be evaluated for adequate contact against the vessel’s hull flat parallel body. Special care should be given to the expected low tidal ranges for LNG fuelled ships, small-scale LNG carriers and bunker barges as vessel’s deck level may be below a conventional terminal’s fender panel/shield. In case additional fenders are required, the designer should consider the economic impact and feasibility of installing new fenders onto the existing structures or providing independent breasting dolphins or fenders for the smaller LNG vessels. c. Mooring arrangement: Section 9.3 addresses mooring issues. Mooring line vertical and horizontal angles will require special attention due to the smaller vessel size of small-scale LNG carriers, LNG fuelled ships or bunker barges. Compatibility at conventional terminals may require the introduction of new fendering systems. Additional mooring hardware can be installed at the berth to allow for Optimised mooring line orientation, but structural evaluation will be required to ensure that imposed loads are acceptable for existing infrastructure. d. Terminal operational limits: At the time of establishing terminal operational limits two alternative processes can be followed depending on the design stage. At pre-feasibility stages assessment based on typical acceptable values for LNG carriers, LNG fuelled ships or bunker barges; as collected in Codes or Recommendations (such as PIANC (1995)). When further detailed design activities are to be undertaken such as basic engineering a design based on numerical models is strongly recommended to achieve the required target availability or confirm operating limiting conditions. Smaller vessels at facilities shared with mid- or larger- sized vessels are likely to have longer mooring lines which lead to larger vessel excursions. These large vessel excursions may control the terminal operating limits.

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Figure 23.1: Fender contact [SAGGAS LNG Terminal, Sagunto 2016]

Figure 23.2: Mooring configuration for small vessel at Existing Larger Vessel Berth [SAGGAS, 2016]

2. Ship-to-shore compatibility, including equipment and operations: a. Loading arms compatibility: Loading arms are addressed in Section 10.2. Vertical and horizontal working envelopes should be verified, including adequate reference to arms/hoses anchor axis offset from berthing line, and incorporating vessel induced waves, winds and current movements. Conventional terminals are intended for vessels with manifolds at higher elevation; therefore, it is common that arms at conventional facilities cannot reach the manifold of smaller LNG vessels at low tide. Some bunker barges or small-scale LNG carriers are designed to include a redundant manifold capable of being reached by a conventional terminal loading arm even at low tide. Adequate consideration should be given to alarms for shut down and disconnection when evaluating transfer equipment compatibility as well as any other safety clearance or margin. b. Access gangway/alternative access equipment: In case access is required from the terminal to the vessel, Geometric compatibility should be verified for gangway supporting surface and inclination in order to maintain safe operations. c. Ship-shore link: Ship-shore communications are discussed in Section 10.2.4. Ship data and cargo transfer control systems according to safety of ship at berth. In some cases these requirements could be relaxed when compared to conventional terminals.

23.3 Safety Approach If the LNG terminal is an existing facility, then a complete revaluation of safety and risk assessment studies should be performed in order to review the terminal procedures, reclassify all areas and establish the corresponding exclusion zones accordingly. If the terminal is a new facility the process does not differ from those typically associated to LNG terminals and, therefore, the assessment process will essentially be similar to the one described in the Section 13 and 14 of this document

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Bunker Barge Terminals It is expected that providing an LNG terminal which supplies bunker barges which then feed LNG fuelled vessels will be the more typical case to address for bunkering within most ports. From a safety point of view, the main differences with a conventional marine LNG terminal (those intended for trading) are: 



Vessel dimensions. Small mid-sized LNG/CNG supplying vessels are to be handled so particular attention is to be paid for incoming or outgoing operations that are likely to be performed without the help of tugs. In addition, the assessment of the mooring behaviour at existing/new quays will be essential to establish the operational limits that surely will differs to those associated to the large LNG carriers. Frequency of the operations. Bunker supply barges will be operated much more frequently than trading LNG carriers. Operations could be on a continuous basis for truck loading facilities on-shore. Risk assessment and safety management as well as the operation procedures have to be established or adapt accordingly.

Truck Bunkering For truck to ship operations, such as that shown in Figure 23.3, a safe location for truck drivers or other personnel during transfer needs to be provided. If the driver does not require to be located at manifold locations, they should be located away from possible exposure.

Figure 23.3: Truck to ship bunkering at Port of Civitavecchia [Marinelink, 2014]

23.4 General Remarks on Security Security within the port limits is governed by the ISPS code [IMO, SOLAS, 2004]. For existing or new LNG terminals the process consists of the risk evaluation and the development of the corresponding plans to be implemented during operations. There is no significant difference between bunkering and conventional terminal process evaluation. It is likely that independent security access and control should be implemented for the bunkering operations when bunkering occurs at a dedicated bunkering facility.

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23.5 Operational Issues Bunkering at LNG terminals differs from conventional LNG loading/unloading operations due to the following: 



Frequency of the operations (mainly for supplying barges): LNG terminals handle LNG carriers typically once each 3 to 4 days and each single full operation is extended an average of 24 hours. Bunkering operations will be much more frequent and operating times are expected to be from 1 to 4 hours depending on the type of supply (i.e. for barges it is anticipated that it will take 1 to 2 hours for complete transfer time, similar to what happens in an onshore truck loading facility). In some cases, where bunkering occurs less frequently, the facility may be unmanned for extended periods of time. For small vessels/trucks LNG handling will be performed by as few as a single operator, who will have training suitable for small facilities. Loading/unloading rates: Typical loading and unloading rates at the LNG terminal are from 7,000 m3/h corresponding to medium LNG carriers to 15,000 m3/h for the largest ones. Bunkering loading rates are expected to be much less, ranging from 100 m3/h to 1,000 m3/h.

Additional risk scenarios and hazards specific to bunkering are provided from DNVGL (2014) in Table 23.1. Scenarios and hazards discussed in Section 12.3 may also be applicable. ISO 18683 (2015) also provides additional scenarios and hazards for LNG bunkering facilities.

24 Source of Release

25 Scenario

26 Possible Causes

LNG Truck

Releases during transfer

Rupture of transfer hoses, truck or piping, Operational errors, mechanical erros Catastrophic rupture, warm BLEVE Structural damage

LNG supply ship

Leakage from cargo tank

Collision damage if this is identified as a credible risk in the HAZID

Table 23.1: Scenarios and hazards for bunkering facilities [ISO/TS 18683, 2015]

Bunkering procedures are expected to be more simplified than conventional ones in order to be adapted to the large frequency and the low rates expected. These procedures will mimic those for larger facilities functionally, but technically may involve the use of alternate means and methods to provide these functions. Simplified technologies which are available on the market may provide for the operational requirements at these smaller facilities. Examples of these are:   

Simplified custody transfer process Rapid ESD connections and testing Alternate purging procedures

The following steps should be followed when bunkering vessels/barges: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14.

Port clearance Navigation to berth Mooring at berth Preliminary meeting: Completion of the safety checklist Hoses/arm connections. Check for linked ESD systems Warm ESD test Inertisation and watertightness tests Cooling down Cold ESD tests. Loading Purge and drainage Custody transfer Inertisation and disconnection Berth departure

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Typical operation times for supply barges is expected to be between two to four hours depending on the barge capacity. Direct bunker vessel (such as ferries or tugs) duration and frequency of fuelling will depend heavily on operational use. Particular attention is to be paid to the custody transfer process that differs to those applicable to conventional LNG carriers. Reference should be made to SGMF (2015) Quantity and Quality. Operational considerations for mobile bunkering facilities include   

Temporary exclusion zones on land and on water Temporary/permanent access control and overall facility security Emergency procedures and response equipment

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APPENDIX A. TERMS OF REFERENCE The Terms of Reference provided to the Working Group at the start of development of this guideline were:

A.1 HISTORICAL BACKGROUND (DEFINITION OF THE PROBLEM) The potential of using Liquefied Natural Gas (LNG) as an alternative fuel for ships is fast gaining momentum due to the recent IMO regulations (especially for the designated Emission Control Areas – ECAs) and as part of the whole debate of improving the environmental performance of shipping. Within this framework, the use of LNG as fuel for maritime and inland shipping is being investigated. Recent analysis demonstrates that in terms of operational performance LNG can be considered as a viable alternative to marine fuel while it clearly leads to zero SO x and significant reductions of other emissions (NOx, CO2). One of the outstanding issues that the broad application of LNG faces are the required investments relating to adequate infrastructure for bunkering as well as the rules (safety) to be applied for bunkering. The European Maritime Safety Agency (EMSA) initiated some time ago a study on the potential of LNG where ESPO and ECSA were asked to contribute. Their part was primarily to investigate the current situation regarding the availability of LNG bunkering facilities and infrastructure in Europe. IAPH has established an ‘LNG fuelled vessels working group’ (IAPH) dealing with LNG Bunkering, LNG Risk Perimeters and LNG Public Awareness. The current regime around dedicated LNG terminals are very strict and if one should increase the number of LNG terminals, small and medium, one has to consider the risks and design in a new way also consider integrating these new LNG terminals in existing terminals, such as multipurpose terminals.

A.2 OBJECTIVES OF THE WORKING GROUP Today's LNG terminals consist almost exclusively of large dedicated terminals. LNG has a ‘reputation’ of being extremely hazard which has resulted in the safety and design of existing terminals. As it is expected that by 2015 a number of shipping lines will have LNG-powered maritime and inland vessels in there fleet, it is necessary to establish new terminals in far more places than the dedicated terminals. These terminals will in many cases be considered as smalland medium-sized and must also be established near other terminals. Examples of this are from Norway, where the newly established LNG terminals are integrated into a multipurpose terminal after careful studies and risk assessments. There are also several small and medium LNG terminals in Japan. The WG should provide guidance to owners and designers of marine LNG terminals and infrastructures worldwide, in order to provide a safe, efficient and cost-effective operation of the terminals, focussing on the marine aspects of these terminals. This document should be considered as an additional document to existing standards, as at the moment on this topic few standards exist and this document will be useful for design and operations. Bunkering facilities is a new topic and looking to this together with LNG terminals will be one of the main objectives for the WG.

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APPENDIX B. LIST OF REFERENCES AACE (n.d.): American Association of Cost Estimating. Retrieved from www.aacei.org. ASCE (2015): "Manual of Practice 13. Waterfront Facilities Inspection and Assessment". ASCE (American Society of Civil Engineers) (2014): "Seismic Design of Piers and Wharves". BS EN 12434 (2008): "Cryogenic Vessels - Cryogenic Flexible Hoses", British Standards Institution. BS EN 1474-2 (2009): "Installation and equipment for liquefied natural gas - Design and testing of marine transfer systems - Part 2: Design and testing of transfer hoses", British Standard Institution. BS6349-1-4 (2013): "Maritime Works. General. Code of practice for materirals, last section.", British Standards Institution. BS6349-4 (2014): "Maritime Works, Part 4: Code of practice for design of fendering and mooring systems", British Standards Institution. CSA (Canadian Standards Association) (2015): "Z276. Liquefied Natural Gas (LNG) - Production, storage and handling". DNV (Det Norske Veritas) (2004): "Concrete LNG terminal structures and containment systems", Norway. DNVGL (2014): "RP-0006. Development and operation of liquefied natural gas bunkering facilities". Drennan (n.d.).: Drennan Marine Consultancy Limited, United Kingdom. Retrieved from www.drennanmarine.com. EN13645 (2002): "Installation and equipment for liquefied natural gas - Design of onshore installations with a storage capacity between 5t and 200t". EN1473 (2007): "Installation and equipment for liquefied natural gas - Design of onshore installations". FEMA (2008): "Federal Emergency Management Agency. P646. Guidelines for Design of Structures for Vertical Evacuation from Tsunamis". IAPH (n.d.). International Association of Ports and Harbours. In LNG fuelled Vessels Working Group (http://www.lngbunkering.org). IGU (2015): International Gas Union. In World LNG report. IHS Inc. (n.d.), Retrieved from www.ihs.com IMO (1973,1978,1997,1983): "International Convention for the Prevention of Pollution from Ships (MARPOL)". IMO SOLAS (2004): "Safety of Life at Sea Convention". In International Ship and Port Facility Security (ISPS) Code. ISO 18683 (2015): "Guidelines for systems and installations for supply of LNG as fuel to ships". ISO 28640 (2010): "Petroleum and natural gas industries. Installation and equipment for liquefied natural gas - Ship-to-shore interface and port operations". ISO TC67 WG10 (2013): ""ISO Working Group under the ISO's Technical Committee 67". In Guidelines for bunkering of gas fuelled vessels. NFPA 59A (2014): "National Fire Protection Association". In Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG). NGV GLOBAL (n.d.): International Association for Natural Gas Vehicles. Retrieved from www.ngvglobal.com. NOM 013 (2012): "Norma Oficial Mexicana". In Safety requirements for the design, construction, operation and maintenance of storage terminals for liquefied natural gas including

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systems, equipment and facilities for reception, transportation, vaporization and delivery of natural gas. OCIMF (1999): "Design and construction specification for marine loading arms". OCIMF (2008): "Oil Companies International Marine Forum. In Mooring Equipment Guidelines (MEG3)", ISBN: 978-1-905331-32-1, Witherby, London, United Kingdom. OCIMF (2012): "Marine Terminal Management and Self Assessment (MTMSA)". OCIMF/SIGTTO (2008): "Jetty Maintenance and Inspection Guide". PIANC (1995): "Supplement to bulletin nº88". In Criteria for movements of moored ships in harbours. A Practical Guide, ISBN: 978-2-87223-070-X, Bruxelles, Belgium: PIANC, Secrétariat Général. PIANC Report 103 (2008): "Life Cycle Management of Port Structures, Recommended Practice for Implementation", Bruxelles, Belgium: PIANC Secrétariat Général. PIANC Report 116 (2012): "Safety Aspects Affecting the Berthing Operations of Tankers to Oil and Gas Terminals", Bruxelles, Belgium: PIANC Secrétariat Général. PIANC Report 119 (2013): "Inventory of Inspection and Repair Techniques of Navigational Structures", Bruxelles, Belgium: PIANC Secrétariat Général. PIANC Report 121 (2014): "Harbour Approach Channels Design Guidelines", Bruxelles, Belgium: PIANC Secrétariat Général. PIANC Report 34 (2001): "Seismic design guidelines for port structures", Bruxelles, Belgium: PIANC Secrétariat Général. PIANC Report 45 (n.d.), The World Association for Waterborne Transport Infrastructure. In: "Berthing Velocities and Fender Design". PIANC Report 153 (n.d.): "Recommendations for the Design and Assessment of Marine Oil and Petrochemical Terminals". PIANC Report 33 (2002): "Guidelines for the Design of Fender Systems", Bruxelles, Belgium: PIANC Secrétariat Général. SGMF (2014): Society for Gas as a Marine Fuel. In Gas as a Marine Fuel. SGMF (2015): "Safety Guidelines for Bunkering". SIGTTO (1997 & 2004): "Site Selection and Design for LNG Ports and Jetties (Information Paper 14)". SIGTTO (2001): "Guide to Contingency Planning for Marine Terminals Handling Liquified Gases, Bulk", Second Edition". SIGTTO (2003): "LNG Operations in Port Areas". SIGTTO (2009): "ESD arrangements and linked ship/shore systems of liquefied gas carriers”.

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ABBREVIATIONS/GLOSSARY (Listed alphabetically) AACE

American Association of Cost Estimating

ADCP

Acoustic Doppler Current Profiler

AHJ

Authorities Having Jurisdiction

ALARP

As low as reasonably practical

ASD

Allowable Stress Design

BOD

Basis Of Design

CAPEX

Capital Expenditures

CCTV

Closed Circuit Television

CLE CNG

Contingency Level Earthquake Compressed Natural Gas

CPT

Cone penetration testing

DE ECAs

Design Event Emission Control Areas

ECSA

European Community Shipowners' Associations

EMSA

European Maritime Safety Agency

ERC

Emergency Release Coupling

ERS

Emergency Release System

ESD

Emergency Shutdown

ESPO

European Sea Ports Organisation

FID

Financial Investment Decision

FLU

Floating Liquefaction Unit

FSRU

Floating Storage and Regasification Unit

FSU

Floating Storage Unit

HSSE

Health, Safety, Security, Environment

IAPH

International Association of Ports and Harbors

IMO

International Maritime Organization

IRPA

Individual Risk Per Annum

LBP

Length between perpendiculars

LNG

Liquefied Natural Gas

LOA

Length Overall

LOC

Loss Of Containment

LPG

Liquefied Petroleum Gas

LRFD

Load Resistance Factor Design

MLAs

Marine Loading Arms

MTCC

Maritime Terminal Control Centre

MVR

Mechanical Vapour Recompression

NFPA

National Fire Protection Association

OBE

Operational Basis Earthquake

OCIMF

Oil Companies International Marine Forum

OLE

Operating Level Earthquake

OPEX

Operational Expenses

QC/DCs

Quick Connect/Disconnect Couplings

QRA

Quantitative Risk Assessment

QRHs

Quick Release Hooks

RAM

Risk Assessment Matrix

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ROV SECAs

Remote Operated Vehicles Sulphur Emissions Control Areas

SITTGO

Society of International Gas Tanker and Terminal Operators

SLS

Service Limit State

SMS

Safety Management System

SOB

Sismo de Operación Base (Base Operation System)

SPMs SPS

Single Point Moorings Sistema de Paro Seguro (Safety Stop System)

SSE

Safe Shutdown Earthquake

UHF

Ultra High Frequency

ULS

Ultimate Limit State

WG

Working Group

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APPENDIX C. SHIP CHARACTERISTICS Loa (m)

Lbp (m)

Beam (m)

Draught (m)

Approx. Capacity (m3)

125,000

345.0

333.0

55.0

12.0

267,000

97,000

315.0

303.0

50.0

12.0

218,000

90,000

298.0

285.0

46.0

11.8

177,000

80,000

280.0

268.8

43.4

11.4

140,000

52,000

247.3

231.0

34.8

9.5

75,000

27,000

207.8

196.0

29.3

9.2

40,000

75,000

288.0

274.0

49.0

11.5

145,000

58,000

274.0

262.0

42.0

11.3

125,000

51,000

249.5

237.0

40.0

10.6

90,000

60,000

265.0

245.0

42.2

13.5

50,000

248.0

238.0

39.0

12.9

40,000

240.0

230.0

35.2

12.3

30,000

226.0

216.0

32.4

11.2

20,000

207.0

197.0

26.8

10.6

10,000

160.0

152.0

21.1

9.3

5,000

134.0

126.0

16.0

8.1

3,000

116.0

110.0

13.3

7.0

DWT (t) LNG Carriers (Prismatic)

LNG Carriers (Spheres, Moss)

LPG Carriers

Source: PIANC WG-report 121 – ‘Harbour Approach Channels Design Guidelines’

Small to Medium LNG Carriers

Loa (m)

Lbp (m)

Beam (m)

Draught (m)

Approx. Capacity (m3)

257.0

232.0

36.0

12.5

70,000

170.0

160.0

27.0

11.0

20,000

155.0

146.7

22.7

8.2

15.600

152.0

143.0

23.5

10.1

10,000

117.8

111.2

18.6

6.8

7,550

100.0

94.0

16.0

5.5

5,000

88.0

82.0

15.0

5.0

3,000

69.0

63.4

11.8

3.5

1,100

Source: Tom Drennan (Drennan Marine Consultancy)

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