Front End Engineering And Design Research Articles

Concurrent 10. Presentation for: Unlocking Gippsland reserves with a minimum kit solution – West Barracouta

Presented on Wednesday 18 May: Session 10 The West Barracouta (BTW), field one of the largest proven undeveloped gas fields off the south-eastern Australian coast, commenced production in April 2021. The project was developed by Esso-BHP Gippsland Basin Joint Venture (JV), a 50–50 JV between ExxonMobil’s subsidiary Esso Australia and BHP Petroleum. The BTW gas field is situated ~6 km south west of the existing Barracouta gas field and platform, the first Gippsland Basin Joint Venture platform in Bass Strait. The BTW development involved drilling two subsea production wells, installation of umbilical controls from the existing platform and installation of a ~6 km subsea flowline to connect to existing gas pipeline via a hot tap. The BTW team will share insights on how it: (1) utilised minimum kit solution and verification of existing asset condition; subsea hot tap into operational gas pipeline and re-use of existing platform J-tube to minimise works on and around the Barracouta Platform (including diving work). (2) Managed an Operator first – co-mingled wet gas subsea pipelines while operating in hydrate regions; via detailed water detection metre/software solution, downhole zone isolation and systematic operating guidelines. (3) Leveraged Installation Contractor competitive Front End Engineering and Design (FEED) enabling optimisation of facilities design/execution strategies to align with strengths and maximise overall project value. (4) Leveraged the OneSubsea/Subsea 7 Subsea Integration Alliance and global worldwide network to execute the subsea design (including qualification), manufacture and installation. (5) Utilised the incumbent Engineering, Procurement and Construction (EPC) contractor to integrate the subsea and topsides control systems to support a single operation system linked to the existing to Distributed Control System (DCS). To access the presentation click the link on the right. To read the full paper click here

Unlocking Gippsland reserves with a minimum kit solution – West Barracouta

The West Barracouta (BTW), field one of the largest proven undeveloped gas fields off the south-eastern Australian coast, commenced production in April 2021. The project was developed by Esso-BHP Gippsland Basin Joint Venture (JV), a 50–50 JV between ExxonMobil’s subsidiary Esso Australia and BHP Petroleum. The BTW gas field is situated ~6 km south west of the existing Barracouta gas field and platform, the first Gippsland Basin Joint Venture platform in Bass Strait. The BTW development involved drilling two subsea production wells, installation of umbilical controls from the existing platform and installation of a ~6 km subsea flowline to connect to existing gas pipeline via a hot tap. The BTW team will share insights on how it: (1) utilised minimum kit solution and verification of existing asset condition; subsea hot tap into operational gas pipeline and re-use of existing platform J-tube to minimise works on and around the Barracouta Platform (including diving work). (2) Managed an Operator first – co-mingled wet gas subsea pipelines while operating in hydrate regions; via detailed water detection metre/software solution, downhole zone isolation and systematic operating guidelines. (3) Leveraged Installation Contractor competitive Front End Engineering and Design (FEED) enabling optimisation of facilities design/execution strategies to align with strengths and maximise overall project value. (4) Leveraged the OneSubsea/Subsea 7 Subsea Integration Alliance and global worldwide network to execute the subsea design (including qualification), manufacture and installation. (5) Utilised the incumbent Engineering, Procurement and Construction (EPC) contractor to integrate the subsea and topsides control systems to support a single operation system linked to the existing to Distributed Control System (DCS).

A Feasibility Study of Full Scale, Post Combustion, Amine Based, CO <sub>2</sub> Capture Retrofit Application in the Cement Manufacturing Sector at the Lehigh Hanson Materials Limited Facility

This paper will present the progress of a feasibility study, jointly conducted by Lehigh Hanson Materials Limited (Lehigh) and the International CCS Knowledge Centre, aimed at retrofitting a cement production facility at Lehigh (Edmonton, Alberta, Canada) with a full scale, post combustion, amine-based Carbon Dioxide (CO2) capture system. This study is a major breakthrough for carbon capture and storage (CCS) as it represents a first in North America for CCS application in the cement industry. The main deliverable of the feasibility study is a Class 4 estimate to assist Lehigh in determining the economic viability of a potential CCS retrofit project. This feasibility study commenced in November 2019 and will be complete in the fall of 2021 and is projected to cost $3.0M CAD. Funding for this study has been contributed to by Lehigh and Emissions Reduction Alberta (ERA) with contributions by the International CCS Knowledge Centre. The study will examine both the carbon capture technology and the “balance of plant”. Successful completion of this feasibility study could lead to a decision to carry out a Front End Engineering and Design (FEED) study and ultimately to a Final Investment Decision (FID) to implement a commercial scale project. A commercial project is projected to reduce emissions by approximately 600,000 tonnes of CO2 per year. The commercial scale project is projected to reduce emissions in Alberta in excess of 13.1 Mtonnes over a 25-year lifespan. The International CCS Knowledge Centre who is providing project management and advisory services, has engaged an experienced CO2 capture technology vendor, Mitsubishi Heavy Industries (MHI) Group, for the design of the CO2 capture system. MHI is responsible for the scope of work that includes the flue gas pretreatment system, the CO2 capture facility, and the CO2 compression process. The International CCS Knowledge Centre is also engaging and directing engineering consultants or other solution providers as appropriate. This direction and guidance will utilize base learnings from both the fully integrated Boundary Dam 3 CCS Facility and the comprehensive second-generation CCS study, known as the Shand CCS Feasibility Study, engineering consultants are being engaged to provide preliminary process and equipment design and cost estimates within their assigned scopes of work or work packages. The captured CO2 would be permanently sequestered and could be also used for Enhanced Oil Recovery (EOR). The Lehigh facility is located near potential storage locations, including being about 50 km away from the Alberta Carbon Trunk Line (ACTL) and nearby EOR opportunities. Lehigh, part of HeidelbergCement, will contribute to the company’s goal of achieving CO2-neutral concrete by 2050 at the latest and make it the most sustainable building material.

Full-scale FEED Study for Retrofitting the Prairie State Generating Station with an 816 MWe Capture Plant using Mitsubishi Heavy Industries Engineering Post-Combustion CO2 Capture Technology

This front-end engineering and design (FEED) study is for a carbon dioxide (CO2) capture system for Unit #2 (816 MW) at the Prairie State Generating Company’s (PSGC) Energy Campus in Marissa, IL. The capture technology used is the Advanced KM CDR Process™ from Mitsubishi Heavy Industries (MHI). The project will be the largest post-combustion capture plant in the world. In addition, it will incorporate advancements in the technology including lessons learned from past projects and a new proprietary solvent. The overall business model being developed by PSGC focuses on the generation of 45Q tax credits as a result of sequestering the captured CO2. Because the Prairie Research Institute (PRI) within the University of Illinois at Urbana-Champaign (UIUC) leads both this capture effort and the storage effort, there is close coordination and integration between the capture and storage efforts. This integration is vital to achieving the desired business targets for the project.

Design and Costing of an ION Clean Energy CO2 Capture Plant Retrofitted to a 700 MW Coal-fired Power Station

ION Clean Energy’s (ION) advanced solvent is one of the leading solvent systems currently under development for post-combustion carbon dioxide (CO2) capture. ION has partnered with Nebraska Power Public District (NPPD), Sargent & Lundy (S&L), Koch Modular Process Systems (KMPS), and Siemens to design a commercial-scale (700 MW) capture system utilizing ION’s advanced solvent. The resulting CO2 capture plant design utilizes ION’s ICE 21 solvent and was designed to take full advantage of the solvent benefits, which include an efficient physical plant layout, reduced energy requirements, less solvent degradation, lower emissions, and lower capital costs relative to systems built with (U.S. Department of Energy) DOE Bituminous Baselines Study (BBS) case benchmark solvents. This Front-End Engineering and Design (FEED) is the continuation of a successful pre-FEED study on a 300 MW capture system at NPPD’s Gerald Gentleman Station (GGS) in Nebraska, USA, where cost of capture was determined to be approximately $32 per tonne of CO2. The overall objective of this project is to provide a detailed design resulting in an accurate cost estimate for a commercial-scale CO2 capture facility retrofitted onto a 700 MW existing coal-fired power station. The engineering design and costing will be provided at an Association for the Advancement of Cost Engineering (AACE) Class 2 estimate, which will result in cost accuracy in the range of 15 to +20%, supported by completion of up to 70% of the engineering effort. This paper reviews the engineering work completed to support the cost estimate, which includes process flow diagrams, utility flow diagrams, and general arrangement drawings. Balance of plant (BOP) engineering design was also completed to support the costing effort and includes the necessary tie-ins to the power station for steam, electricity, cooling water, makeup water, and flue gas. The culmination of this work is a 3D model of the carbon capture system as integrated at GGS. The 3D model incorporates the capture island and all the BOP modifications and necessary subsystems for the inclusion of the CO2 capture plant and ensure that the necessary level of detailed engineering has been achieved to support the cost estimate. A preliminary cost evaluation is discussed projecting the expected capital cost, operation and maintenance (O&M) cost, and cost of capture outcome based on the above engineering work. The CO2 capture rate efficiency was not confined or restricted for the FEED project but when optimized for this design basis remained at approximately 90% for full load operation. During the periods of turndown for the power plant, the CO2 capture efficiency increases to over 95% from the flue gas to fully utilize the installed equipment. This paper will also discuss the design and engineering challenges encountered while striving to integrate a CO2 capture system onto an existing power station. These challenges are not unique to this installation and include: • Sizing the system to best match the power station demands in a flexible power market • Designing a steam supply system that covers operations at all load conditions • Designing a heat rejection system with limited availability of cooling water resources and other factors that are site specific The project team has integrated several independent studies into this FEED project to address these specific challenges and this paper will review these results.

Turritella FPSO - Design and Fabrication of the World’s Deepest Producing Unit

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27663, “Stones Development: Turritella FPSO—Design and Fabrication of the World’s Deepest Producing Unit,” by Blake Moore, Andrew Easton, Jonathan Cabrera, and Carl Webb, Shell International Exploration and Production, and Babu George, SBM Offshore, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission. The Stones Project is in the emerging Lower Tertiary trend in the Gulf of Mexico ultradeep water. A floating production, storage, and offloading (FPSO) unit was selected for the floating production system to address the stepwise development of the Stones Field. The Turritella FPSO (Fig. 1) is the deepest floating production system in the world and presented many challenges to successful execution of the surface host facilities. Overview The Stones development is along the Walker Ridge protraction area in the deepwater Gulf of Mexico, in water depths ranging from 7,500 to 9,500 ft. The field was developed using a disconnectable FPSO tied to a subsea development. Nominal production capacities will be 60,000 B/D of fluids, 30,000 B/D of produced water, and 15 MMscf/D of associated gas. The FPSO design was based on the conversion of an existing Suezmax-scale, double-hull tanker. Design Key design decisions during front-end engineering and design (FEED) and pre-FEED in 2012 and 2011 established many of the key design criteria that guided the design of the FPSO. Riser selection—lazy-wave riser to buoy vs. free-standing risers: An early study identified lazy-wave risers as preferable over free-standing risers because of technical concerns related to flexible pressure ratings and commercial considerations. Disconnectable buoy: Early engagement with regulatory entities (e.g., the Bureau of Safety and Environmental Enforcement) determined that a disconnectable turret to allow the FPSO to escape a hurricane would be required to achieve regulatory approvals. Hull size—Aframax vs. Suezmax: Shell/regulatory requirements for a double hull and the applicable environmental-impact statement for FPSOs in the Gulf of Mexico limiting FPSO storage capacity to less than 1 million bbl led to the limitation of potential hulls. Deck space to accommodate planned topside facilities and turret led to the selection of a Suezmax. FPSO throughput: Technical limitations on riser sizes at the water depth for Stones established maximum throughput. The system choke point was in the risers, and the capacity of the topside matched the riser throughput limit.

Sub-surface Risk Assessment for the Endurance CO2 Store of the White Rose Project, UK

Between September 2013 and November 2015 Capture Power Limited and National Grid Carbon Limited, undertook a Front End Engineering and Design (FEED) study for the White Rose Carbon Capture and Storage Project. The project planned to construct an oxy-fuel power plant at Drax, Yorkshire, England, and transport high-purity CO2 produced by the plant via a c.135 km long pipeline to a location c.75 km offshore from eastern England. There, it was planned to inject the CO2 into an underground “saline aquifer” storage reservoir, the Endurance CO2 Store. A thorough risk assessment provided confidence that the store would contain CO2 permanently.

Carbon Capture and Storage for Enhanced Oil Recovery: Integration and Optimization of a Post-Combustion CO2-Capture Facility at a Power Plant in Abu Dhabi

Summary Masdar has initiated the Abu Dhabi Carbon-Capture and -Storage Project, with the objective to develop a carbon-capture network in Abu Dhabi capable of creating large reductions of carbon dioxide (CO2) emissions and with the capacity to increase oil recovery by use of CO2 for enhanced oil recovery (EOR). Because Siemens (henceforth referred to as the Technology Owner) has developed, tested, and piloted a proprietary post-combustion CO2-capture technology (PostCapTM) for the removal of CO2 from the flue gas of coal- and gas-fired power plants suitable for the project, both parties decided to cooperate in executing a front-end engineering and design (FEED) study. The technology is based on an aqueous amino-acid-salt solution. The Technology Owner and Masdar have completed a FEED study for capturing 1,800,000 tons of CO2 annually from a natural-gas-fired power plant in Abu Dhabi by application of the PostCapTM technology. Various opportunities and challenges were encountered during the design of the retrofit capture plant. Challenges were often specific to the region, including local climate, water availability, and flue-gas quality. Design and optimization of the plant were influenced by local energy and labor prices. Further opportunities included integration with the power plant and with a local industrial facility. The power plant had to supply the capture plant with steam and power without reducing the original electricity-production capacity. To accomplish this, several heat- and power-integration concepts were evaluated with respect to their feasibility, including the application of a backpressure steam turbine and the retrofit of a simple-cycle gas turbine to combined-cycle gas turbine. Various cooling options were considered in view of climate and resource challenges. Cooling water had to be extracted from a reflux stream produced by an adjacent industrial facility. Drawing on the results of the FEED study, this paper presents the manner in which PostCapTM technology can be applied for capturing CO2 at a power plant in Abu Dhabi for the purpose of EOR, while satisfying specific local needs, and the way utility supply and power plant integration can be facilitated.

사업관리 관점의 FEED 업무 프로세스 구조 및 항목 평가 - 화력발전소를 중심으로 -

해외 플랜트 사업에서의 고부가가치를 창출하기 위해서는 기획 타당성조사, 프로젝트종합관리, FEED 및 기본설계 등 분야의 기술경쟁력 강화가 시급하다. 특히, FEED 업무는 프로젝트 전체에 대한 영향력이 절대적이고, 또한 기자재 및 패키지 산업의 경쟁력 강화에도 결정적 역할을 한다. 그럼에도 불구하고, FEED 관련 선행연구들은 설계업무 중심의 프로세스 및 성과물을 위한 연구가 대부분이며, 프로젝트 전체에 영향을 미치는 관리적 관점의 FEED 업무에 대한 연구는 미흡한 실정이다. 따라서 본 연구에서는 발전플랜트 중 화력발전소를 대상으로 사업관리 관점의 FEED 업무 프로세스 구조 및 항목을 제안하였다. 도출된 FEED 관리 업무는 3개의 레벨로 나누어진 계층적 구조를 가지고 있으며, 업무 항목에 대한 전문가 검증을 실시하였다. 또한 FEED 관리 업무에 대한 평가지표별 평가를 통해 결과를 분석한 결과 설계 중심의 업무들은 역량이 높지만 중요도가 높은 관리적 관점의 FEED 업무들의 역량은 부족한 것으로 나타났다. 그러므로 본 연구에서 제안한 FEED 관리업무 프로세스 구조는 FEED 역량 강화를 위한 가이드라인이 될 것이라 기대한다. FEED (Front End Engineering and Design) is the key area that determines the competitiveness of procurement and construction in the EPC contracts especially in terms of the added value. Nevertheless, previous researches in FEED have been limited to the process and deliverable of design work or the particular management business function (e.g. System Engineering, collaboration, information etc.). In this context, the purpose of this study is to propose a comprehensive FEED structure and its functions from the project management perspective throughout the whole project life-cycle for thermal power plants. Proposed FEED business procedures are classified into three levels; First level is the classification of FEED business phases, the second level defines major FEED management functions, and the third level is detailed FEED functions. A survey using proposed FEED functions and assessment variable was conducted in order to analyze the current status and the areas for future improvement. It is expected that the proposed structure, functions, and evaluation methodology for FEED management will contribute to effective practice of FEED as well as to improvement of competitive capability for engineering, procurement, and construction (EPC) companies.

3.2.1 Developing empirical connections based on interrelation analysis between technical activities of systems engineering and FEED processes in plant ‐ construction industry

AbstractPlant owners and engineering, procurement and construction contractors are facing increasing pressure to increase plant efficiency, reliability, availability and safety. Front End Engineering and Design (FEED) is a key process that identifies technical challenges and estimates investment cost. Systems engineering (SE) translates an operational need into a system designed to meet that need; therefore SE can help to implement FEED. This study develops guidelines about how to build and apply SE during the implementation of FEED. A House of Quality matrix is used to investigate causal connections between FEED processes in the plant‐construction industry and technical activities of SE, and a survey of engineering experts is used to quantitatively demonstrate the opportunity to increase the effectiveness of SE, and to demonstrate the implications of the relationship between FEED and SE in terms of plant type, business type, and area of expertise.

Evaluation of the DMX Process for Industrial Pilot Demonstration – Methodology and Results

Abstract The SP3 Subproject of the OCTAVIUS EU FP7 project was dedicated to the demonstration of the DMX CO2 capture process, developed by IFP Energies nouvelles (IFPEN) and licensed by PROSERNAT, on the 3.5 MWe equivalent industrial pilot of ENEL at Brindisi. The DMX process is based on the particular property of demixing solvents to form, for specific CO2 loadings and temperature conditions, two immiscible liquid phases. The light phase being almost free of CO2, only the high capacity heavy phase is sent to the stripper, which makes possible energy savings but also requires an adapted process flow scheme and extra equipment. Prior to launch the corresponding retrofit and perform the pilot tests, two conditions were settled. First, a quantitative evaluation of the process must show a significant interest in comparison with the benchmark MEA 30 wt.%. To evaluate this first conditions, 24 criteria were considered. Second, an acceptable cost for the retrofit of the existing industrial pilot, determined from a Front End Engineering and Design (FEED) study must be obtained. Most of this paper deals with the evaluation of these two conditions which ended in November 2013 and a small section is dedicated to the FEED study. It is shown that most of the parameters considered for the process evaluation are in good agreement with the initial targets. The proposed evaluation methodology could be used for any new process prior to demonstration.

The Peterhead-goldeneye Gas Post-combustion CCS Project

Abstract Full scale demonstration projects are the key to gaining policy acceptance for CCS. They also form the vital first step towards reducing the cost of clean power: only when a project is built can engineers examine it and identify improvements and savings opportunities. A number of projects are currently in development for coal CCS, but carbon capture on gas is also important if the world is to make the depth of cuts in emissions required by the current scientific consensus. Shell and SSE plan to deliver the world's first full scale CCS project on gas in Scotland. Up to 10 million tonnes of carbon dioxide (CO 2 ) emissions could be captured over a 10-year period from flue-gas from a 400MW combined cycle gas turbine at the existing Peterhead Power Station in Aberdeenshire, Scotland and then transported by pipeline and stored, approximately 100 km offshore in the depleted Goldeneye gas reservoir, at a depth of more than 2 km under the floor of the North Sea. This would provide enough clean electricity to power the equivalent of 500,000 homes per year. The project is one of two preferred bidders in the UK Government's CCS Commercialisation Programme and is currently in the midst of a front end engineering and design (FEED) phase. Subject to positive final investment decisions by Shell and the UK Government, and the receipt of all relevant permits and consents, the project is expected to be up and running by the end of the decade.

Legislation, Commerce, and Ethics Drive Design of Quieter Facilities in Australia

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156732, ’Why Quiet? Legislative, Commercial, and Ethical Drivers Behind the Design of Quieter Offshore Facilities in Australia,’ by Andrew Chandran, Chevron Australia, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed. Legislation, economics, and ethics are major drivers behind the adoption of engineering noise controls during offshore-facility design in Australia. The global challenge facing noise advisers is to understand how these factors influence the adoption of engineering noise controls and to work closely with project teams to ensure that operational-noise risk is as low as reasonably practicable (ALARP). Implementing these controls during the front-end engineering and design (FEED) can ultimately protect a company and its workforce during facility operation and can turn major capital projects (MCPs) into valued legacy operations. Introduction It is commonly said that “health and safety are good for business” without seeing substantiated claims. However, if health and safety truly are good for business, it should be demonstrably so. This may involve an evaluation of the costs vs. benefits of each health and safety initiative, as well as the feasibility of implementing them. One such initiative is hearing preservation. Cost/benefit analysis (CBA) is an important tool that can be used to com-pare the net economic worth of various health and safety initiatives to deter-mine how best to allocate finite project resources to maximize a project’s value. Various international cost/benefit models exist to help companies perform economic evaluations of health and safety initiatives. An Australian ALARP model recently used by Chevron Australia during the design of an offshore production facility in the North West Shelf of Western Australia is one of them. Additionally, discounted-cash-flow (DCF) analysis is introduced as a means of supplementing conventional CBA to help decision makers determine when, during the lifetime of a project, engineering noise controls should be implemented to maximize a project’s net present value (NPV). The decision to implement effective engineering noise controls is not based solely on economics, but it is a major driver behind the selection and implementation of proposals that can affect a company’s bottom line. Other key drivers are legislation and business ethics or cultural expectations.

Huge Saudi Field Begins Production Ahead of Schedule

Manifa Saudi Aramco started production in April at its Manifa field, the fifth-largest oil field in the world, 3 months ahead of schedule. The field’s output reached 500,000 BOPD of crude from a network of wells drilled through manmade islands. By the time it is fully operational in December 2014, the offshore field is forecast to produce 900,000 BOPD of Arabian Heavy crude oil, 90 MMscf/D of sour gas, and 65,000 B/D of hydrocarbon condensate. Manifa is one of the largest engineering projects in the world, involving 41 km of causeways, 3 km of bridges, 27 drilling islands, 13 offshore platforms, 15 onshore drillsites, water supply wells, injection facilities, multiple pipelines, and a 420 MW heat and electricity plant, not to mention the relocation of an entire coral reef. After the Khurais project, the USD 9.28 billion Manifa field development is the second-largest project being developed by Saudi Aramco, as part of its effort to boost its production capacity to 12.5 million BOPD by 2015. Discovered in 1957, Manifa is located in the shallow waters southeast of the Safaniyah field, about 200 km north-west of Dhahran, with estimated proven reserves of 10 billion bbl. The field has six oil-bearing reservoirs: Upper Ratawi, Lower Ratawi, Manifa, Arab A, Arab B, and Arab C/D. The reservoirs for incremental development are the two most prolific: the Lower Ratawi and Manifa reservoirs. Production from the field dates back to 1964 following the drilling of eight development wells. However, the facilities were mothballed in 1985 because of the heaviness of the crude. Early Start Planning for the Manifa project began in 2006 when global oil demand was soaring, and the front-end engineering and design (FEED) was completed in the third quarter of 2007. The FEED and project management services contract was awarded to Foster Wheeler in November 2006. Foster Wheeler’s remit was the FEED for the central processing facility, detail design, ordering of long lead equipment, coordination of the FEED development across the project including the offshore sections and development of the bid package for the engineering, procurement, and construction stage. The first construction contract was signed in late 2007 and construction was scheduled to begin in the first quarter of 2008. The project, however, was consistently delayed with construction beginning in the first quarter of 2010.

Risk Assessment and Management for CO2 Capture and Transport Facilities

When discussing risk assessment and risk management related to Carbon Capture, transportation and Storage (CCS) the attention usually focuses on risk related to storage. However, planning and designing a CCS value chain will also require demonstrating the risk associated with carbon dioxide capture and transport is satisfactorily managed.Risk related to processing and transport of carbon dioxide is not a totally new aspect, but the amounts processed and contained as well as the physical state in which carbon dioxide will be handled is outside the boundaries of today's industrial application of carbon dioxide.As a project progresses from feasibility study via front end engineering to detail engineering, construction and finally commissioning and normal operation, the amount of input data for a risk assessment of course increases. It may thus be tempting to delay the safety risk assessment in the early stages as it can be done more accurately at a later stage. However, early identification of safety issues can usually enable those issues be resolved with much less impact to a project's budget and schedule and therefore this opportunity should not be lost. It should be noted that safety concerns are commonly cited in objections for CCS projects and therefore getting an early understanding of the safety risk will also help gain acceptance and support.This paper will present an evaluation of the typical level of risk assessment done in early phases of a CCS project, including a review of the risk analyses performed in the Front End Engineering and Design (FEED) for selected CCS projects. Moreover, experiences from the risk for carbon dioxide pipelines as well as processing and injection will be included.Challenges related to risk assessment at each stage in the project, from feasibility study to normal operation, will be discussed. Risk management measures, both of the preventive and of the consequence mitigating type, that should be included within a project risk assessment and evaluations, will also be included in the discussions.For the early stages the focus will be on how to identify hazards that may have a significant impact and/or be costly to mitigate at a later stage. The paper will focus on strengths and weaknesses of approaches and methods applied, and will provide guidance on their selection and use.As the project progresses, the attention will shift to managing the residual risk with the quantification and specification of design load requirements. For quantitative risk analysis the paper will give an overview of available risk analysis tools and their capabilities, with emphasis on modelling consequences of loss of containment.Loss of containment of carbon dioxide encompasses an extensive range of widely different scenarios. Most dispersion modelling tools will be capable of predicting the development of some scenarios, while other scenarios may represent a yet insurmountable challenge for one tool on its own. A range of predictable loss of containment scenarios will be presented, with an evaluation of the capabilities of selected tools for modelling these scenarios. Further, practical examples from quantitative risk analyses on supplementing integral dispersion models by computational flow dynamics models as well as simple calculations and available data will be given.

Costs of CO2 Transportation Infrastructures

The aim of the paper is to present an analysis of the overall cost for CO2 transportation systems; this will be an engineers approach about what is driving the overall cost. Recent studies of CCS projects calculated that the transportation system of the CCS chain is more expensive than previously expected.An engineer's approach with cost background is used to assess what projected transport costs are, how high additional costs may be and where under- or overestimations are made compared to earlier reported values. This investigation will make use of experts in the field, who are able to search through the recently presented Scottish Power CCS Consortium and E.ON FEED (Front-End Engineering and Design) studies and compare these with normally used cost estimation figures, such as can be found in standard cost guides like the DACE handbook. Finally it is concluded that CO2 transportation is no simple affair. Only now, after thorough FEED studies, there is some insight in the impact of design choices on the actual expected cost of CO2 transport.

New deals revive PNG gas export scheme

Long dormant plans to develop a major gas export scheme in Papua New Guinea (PNG) have been unexpectedly revived following the signing‐up of two customers in Australia. Queensland Alumina Ltd (QAL) has agreed to take between 31 mn cfd and 77 mn cfd for 20 years for its alumina refinery at Gladstone, in central Queensland, and Brisbane's CS Energy has said it will take a further 26 mn cfd for power generation in the Brisbane area, in the south of the state. On the basis of these agreements, ExxonMobil and its project partners have decided to go ahead with front‐end engineering and design (FEED) for the scheme, known as the Highlands Gas Project.