Final Investment Decision Research Articles

Mars-B Development: An Evolution of Traditional Well, Rig, and Facility Design

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25437, ’Mars-B Development: Well Challenges and Solutions - An Evolution of Traditional Well, Rig, and Facility Design,’ by Arno L.M. van den Haak, Wylie J. Cameron, Lisa S. Grant, Nor Janiah H. Japar, and Deandre R. Reagins, Shell, prepared for the 2014 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. The Mars-B project is the operator’s sixth Gulf of Mexico (GOM) tension-leg- platform (TLP) development. The Mars-B project is aiming to unlock resources over the next 50 years through the deployment of a new 24-slot TLP structure [the Olympus direct-vertical-access (DVA) TLP] and additional subsea infrastructure for the west Boreas and south Deimos fields. The Olympus rig is a novel platform drilling rig designed specifically to meet the execution requirements of complex well designs. A high-level overview of the design challenges and the resulting surface-equipment requirements of this project is discussed in this paper. Introduction The operator discovered the Mars field in the Mississippi Canyon Area Block 763 in 1989, located 130 miles southeast of New Orleans in approximately 3,000 ft of water. The Mars-B project made its final investment decision in September 2010 to expand the existing Mars operation with a new 24-slot TLP structure and additional subsea infrastructure for the west Boreas and south Deimos fields. The Olympus TLP is located approximately 1 mile southwest of the existing Mars TLP and represents the first brownfield development of a deepwater field in the GOM. It will enable production of an additional 1.1 billion BOE over the approximately 700 million BOE that has been produced today with the Mars TLP.

Comparative Levelized Cost of Energy Analysis

To estimate the economic feasibility of floating and bottom-fixed substructures at various offshore sites, a generally applicable calculation tool has been developed. With this “LCOE calculation tool” it is possible to optimize the design and reduce the costs of deep offshore wind farms, by analyzing key aspects already during the planning and pre-design phase. Hereby the conducted breakdown of the several cost categories assists identifying main cost-drivers prior a final investment decision. Whereas the influence of varying site specific, technological and financial parameters on the cost-effectiveness is investigated in a sensitivity analysis. To validate and enlarge the tool's dataset, the tool was applied to a real floating concept with the aim to compare the cost-effectiveness of floating solutions with their bottom-fixed counterparts.

Driving superior returns through strategic alignment in oil and gas

In the past decade, Australia has enjoyed significant investment in its LNG, gas and oil projects, with the combined value of projects at the publicly announced stage totalling A$197 billion. The cost of developing new LNG, gas and oil projects has escalated in the past 10 years, making Australia less competitive with locations such as North America and East Africa. The higher costs mean that many proposed projects, especially greenfield developments, will not reach a final investment decision. In this constrained investment environment, it is important for oil and gas companies to execute strategies that earn a strong return on the capital they employ. More than 200 Australian and Asian energy and resources executives were asked to rate their company’s strategic execution capability; this revealed that oil and gas companies that have strategically-aligned operating models earn higher returns on capital employed (ROCE). It was found that while 79% of respondents believe their organisations have the correct strategy in place, only 55% believe their organisation is executing their strategy well now. The research revealed that highly aligned oil and gas organisations are three times more likely to be executing successfully than their less aligned peers. Overall, the results imply that top teams who clearly align behind a strategy and successfully translate its intent throughout their organisations make better use of their invested capital. The level of strategic alignment is a key question for both oil and gas investors and company executives.

Early engagement with NOPSEMA

The Ichthys LNG Project includes a central processing facility (CPF) that is the world’s largest semi-submersible platform. The Ichthys CPF is also the first semi-submersible in Australian waters. Given the novelty of the development concept, the complexity of the design, and the scale of the facilities, the Ichthys Project joint venture participants INPEX and Total wanted to gain a better understanding of what the Australian regulators would be looking for as part of the approval process prior to committing to a final investment decision (FID). On a voluntary basis, the project launched an early engagement with NOPSA (later NOPSEMA) in 2011 to review the design safety case for the CPF. This was the first time such an early engagement process had been undertaken by the regulator. A significant benefit of the early engagement process for both parties was good communication and feedback leading to the establishment of a mutually beneficial long-term relationship. The early engagement process identified no show stoppers at that stage. Feedback from the regulator was incorporated in the detailed engineering. The Ichthys Project considers that the early engagement process with NOPSEMA was positive and constructive. It contributed to an FID being taken in January 2012. INPEX continues to engage proactively with NOPSEMA.

Capacity Building in the UK CCS Research Centre

Abstract A number of commercial-scale projects are currently progressing towards final investment decisions and several studies continue to report that substantial, global deployment of CCS can be expected by the 2050. As CCS technology moves towards widespread commercial-scale deployment, developing ‘fit for purpose’ research capacity that is able to effectively support the development of CCS technology and policy is a significant challenge. A number of exciting opportunities are available to help meet this challenge though. For example, national centres such as the UK CCS Research Centre (UKCCSRC) aim to effectively accelerate capacity building and also ensure that there are excellent opportunities for CCS researchers and practitioners to share their learnings and identify next steps for CCS development. The UKCCSRC was established in spring 2012 with initial core funding provided by £10 M from the Engineering and Physical Sciences Research Council (EPSRC) as part of the Research Councils UK Energy Programme and £2.5 M in match funding from Centre partners. This is complemented by £3.3 M in additional funding from the UK Department of Energy and Climate Change (DECC) to establish new capital facilities that will support innovative research. The Centre is ‘virtual’ providing strong links between around 250 academic researchers based at over 40 UK universities and research institutes and also linking them with over 100 industry and other stakeholder Associate members. In addition there are over 200 Early Career Researchers (ECRs). The UKCCSRC also operates the CCS Community Network, which is a collective of over 500 engineering, technological, natural, environmental, social and economic members with CCS interests. The Network facilitates knowledge exchange on all aspects of CCS R&D and aims to be accessible to anyone interested in contributing to research and innovation in CCS. The UKCCSRC has developed approaches that will allow it to meet the key strategic challenge of understanding ‘real world’ CCS deployment issues, so that the future impact of ongoing research and human and infrastructure capacity development in CCS can be maximised, as much as possible in advance of full-chain CCS deployment and certainly following on rapidly afterwards.

The Ichthys Field: challenges of geological modelling for the field development

Preparation for the Ichthys Field development has been underway since the final investment decision was made in January 2012. The Ichthys Field comprises two reservoirs: the Brewster Member of the Early Cretaceous Upper Vulcan Formation; and the Jurassic Plover Formation. The development will be phased in separate drilling campaigns, commencing with the core area of the Brewster Member reservoir. This reservoir has geological challenges, including: complexity of porosity and permeability distribution in the generally homogeneous sandstone reservoir; and, high gas saturation immediately above and below the free water level. The Ichthys Subsurface team has built geological models of the Brewster Member reservoir. The following methodologies were adopted into the geological models: broad-band seismic inversion data to distribute reservoir porosity away from well control; K Nearest Neighbour methodology to predict permeability from logs utilising core measurements; Cathode-luminescence analysis to understand permeability reduction within the field; imbibition Sw height functions to model high gas saturation immediately above and below the free water level; and, scenario-based geological uncertainty modelling. A series of geological models were utilised to optimise development well locations and to ensure sufficient production from the reservoir.

Ichthys Project update

The US$34 billion Ichthys LNG Project is one of the most complex oil and gas developments attempted. It is effectively three mega-projects in one: an onshore project, an offshore project, and a pipeline project. The Ichthys Project represents: the largest semi-submersible platform in the world; the first semi-submersible production platform in Australia; the largest Japanese investment outside Japan; the largest single French investment in Australia; the biggest ever project financing; the longest subsea pipeline in the southern hemisphere; and, the second largest resource Project in Australia, by CAPEX. The onshore project is being developed in Darwin and involves two processing trains rated to produce a total of 8.4 million tonnes of LNG a year. Offshore, construction of the central processing facility (CPF) and floating, production storage, and off-take (FPSO) vessel is underway. Both facilities will be permanently moored and are designed to withstand the most extreme weather conditions for more than four decades. An 889-km pipeline will link the Ichthys Field, 200 km off the Western Australian coast, to the onshore facilities in Darwin. The project’s final investment decision was announced in January 2012. This triggered intense construction activity and created hundreds of new construction jobs in Darwin and more globally. Since the discovery of the gas-condensate field in 2000, the Ichthys journey has been one of identifying and overcoming geographical, political, technical, financial, and commercial challenges. The project is a global effort, drawing on worldwide expertise to overcome these challenges and work towards first gas in late 2016.

Update on the ROAD Project and Lessons Learnt

The Rotterdam Opslag en Afvang Demonstratieproject (Rotterdam Storage and Capture Demonstration project), or ROAD, aims to build and operate a 250 MWe equivalent CCS chain using post-combustion capture technology and off-shore storage in a depleted gas field under the North Sea. The capture plant would be retrofitted to a new 1 070 MWe coal-fired unit (Maasvakte Power Plant 3) in Rotterdam, Netherlands. It was originally intended to reach a final investment decision at the end of 2010, but the project has faced a series delay associated with permitting, complex commercial negotiations and, most seriously, funding. At the moment (September 2014), the European Commission and the Government of the Netherlands are engaged in a renewed push to solve the funding problems and allow construction to finally start. The project has financial support from the European Energy Programme for Recovery (EEPR) and the Government of the Netherlands and is now the only one of the six projects originally supported that still has any realistic prospect of being realized in the short term. This paper presents an update of the overall project development as at the time of GHGT-12 and the accomplished milestones and issues met in the permitting process. In addition, it will focus on the technical and economic aspects of integrating the capture plant with the power plant. Furthermore, it will provide an outlook on future CCS/CCU developments in Rotterdam, describing the steps under development to create a full CO2 hub in the port including options for ship transport and bio-CCS. The paper concludes with the management of the project delays and the implications for the project economics.

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.

Recovering large Brownfield projects in distress

A large body of knowledge exists about how to plan and establish projects for success; from project management guidelines to staged gate-execution methodologies. Despite such prescriptive means to guarantee project success, the upstream oil and gas industry has a poor track record for delivering large projects. Little guidance exists on how to restore delivery assurance to partially executed projects in distress. Furthermore, recovery efforts for large brownfield projects, mid-way through their execution, are further complicated and highly constrained. Operators and contractors alike are understandably concerned about the high failure rate of projects, particularly as Australia competes for global capital in the final investment decision for a project’s development. Issues cover the full spectrum of safety, cost, schedule, start-up, and operability. Furthermore, unanticipated issues such as industrial relations, resourcing, project controls, estimate basis, and design changes all play a central role in why projects find themselves in distress. In a recent case study, a structured recovery approach restored delivery assurance to a $900 m upstream brownfield project. Despite the numerous challenges encountered during the recovery efforts, the project went on to deliver ahead of its revised cost and schedule commitment, while also achieving outstanding safety performance. The self-governance program was instrumental in restoring delivery performance through responsive decision making that was robust, repeatable and preserved free calendar time for early intervention on high value recovery issues. The journey of recovery also restored a fractured client and contractor relationship by fostering a project delivery environment that was highly collaborative.

The Gorgon CO2 Injection Project – 2012 Update

The Gorgon Joint Venture† made the Final Investment Decision (FID) for the Gorgon Project in September 2009. One element of that approval was the decision to proceed with the Carbon Dioxide Injection Project on Barrow Island, whereby CO2 separated from the reservoir gas from the Gorgon and Jansz-Io fields will be injected into a deep sandstone interval beneath Barrow Island.Since FID, the focus has been on delivering the project – this involves preparations for drilling and completing the four different well types, engineering design and procurement of the CO2 pipeline and procurement and manufacture of the CO2 compression system within the LNG plant.In addition to this engineering activity, the subsurface team has continued with improving their knowledge of the injection interval and overlying geology. The focus of this work has been two-fold:1.Deliver work to support the execution decisions, e.g. finalising well locations, well construction design, well completion design, reservoir data gathering plans, etc. In addition work has also been done to prepare for operations, focusing on understanding the behaviour of super- critical CO2 in the full system from the compressor to the reservoir as a basis for developing operations procedures and documents.2.Prepare for long term reservoir and project management; this includes developing a reservoir management plan with emphasis on surveillance data, continuing to develop the monitoring plans for understanding distribution of CO2 in the injection interval and continuing to evaluate and update understanding of subsurface uncertainties.We currently anticipate commissioning of the carbon dioxide injection system contemporaneous with the start-up of the second Gorgon LNG train in 2015. Between now and then the Carbon Dioxide Injection Project will drill and complete 17 wells, install a seven kilometre buried pipeline and associated facilities and construct, install and commission the CO2 compression system.* The Gorgon Joint Venture comprises the Australian subsidiaries of Chevron (47.3 percent), Exxon Mobil (25 percent), Shell (25 percent), Osaka Gas (1.25 percent), Tokyo Gas (1 percent) and Chubu Electric Power (0.417 percent). Chevron Australia is the operator of the Gorgon Project.

Lessons in the Development of Large-scale CO2 Storage Projects

Significant reductions in CO2 emissions to atmosphere from established industrial processes such as power generation and also cement, iron and steel production require increased, widespread deployment of commercial-scale CCS projects. Large-scale integrated projects (LSIPs) face different challenges than do smaller pilot and demonstration projects that have contributed much toward technical research. LSIPs have a much larger spatial scale of operation and a much larger temporal scale as they are expected to be operational for many decades and will require on-going monitoring, performance assessments, and must satisfy regulated reporting requirements. Among the most significant factors required to move an LSIP forward is the need to provide confidence internally to the project proponents that the technical appraisal of the project and the prospective business case can justify a final investment decision (FID) of tens to hundreds of millions of dollars or more. Many non-geological factors also have major influence over CCS project success such as regulatory environment continued uncertainty around national and international policy development around greenhouse gas mitigation, and uncertain public support. Considering the large commitment in financial and technical resources required to reach FID, perhaps neither the slow progress in LSIP development nor the highly visible project cancellations and postponements in this nascent industry should be unexpected.Although all project proponents are confronted with unique geological and non-technical issues there are common aspects that may be recognized within projects achieving FID that may be broadly instructive. Storage exploration and site appraisal is a lengthy process that will take years and should not be underestimated. Industrial scale CCS requires a firm and large commitment and investment in human, technical, and financial resources. Recent LSIPs that have achieved FID have employed dedicated full-time subsurface teams for years to reduce uncertainties in the storage plan. Multi-faceted projects such as large-scale CCS require decisions be made even though uncertainties exist at various stages of project lifecycle. There is a critical need to manage these uncertainties in all aspects of the project, particularly when dealing with changes in project scope or framework in order to reach milestones and decision gates. Projects may not always proceed linearly through lifecycles and may need to recycle back to an earlier development phase if appropriate. Interface management around project integration is a critical process that must be actively managed to consider exploration and appraisal requirements. For example, capture requirements <remove-image>feed into storage requirements, and storage limitations may impact capture considerations and project feasibility. Focused stakeholder engagement is required: projects must provide transparency to the community and the regulator; public reviews and technical due diligence exercises such as independent peer reviews bring confidence to the government; environmental assessments bring confidence to the community all of the above build confidence in the project.

The Ichthys LNG Project: big, bold and beautiful

The Ichthys LNG Project is one of the most complex oil and gas developments attempted. It is three mega-projects in one: an onshore project, an offshore project, and a pipeline project. The onshore project is being developed in Darwin and involves two processing trains rated to produce a total of 8.4 million tonnes of LNG per year. Offshore, the central processing facility (CPF) will feature the world's largest semi-submersible platform. A substantial floating, production storage and offtake (FPSO) vessel, designed to hold more than one million barrels of condensate, will be stationed nearby. Both the CPF and FPSO will be permanently moored in an area notorious for cyclonic weather conditions and will be designed to withstand even the most extreme weather conditions for more than four decades. An 889 km subsea pipeline will link the Ichthys Field, 200 km off the Western Australian coast, to the onshore facilities in Darwin. This represents the longest subsea pipeline in the southern hemisphere and fifth longest in the world. A final investment decision for the project was announced in January 2012. This triggered intense construction activity and created hundreds of new construction jobs in Darwin and more globally. More than 4,000 direct jobs will be created at the peak of construction. An approved capital expenditure of $US34 billion by INPEX and the Ichthys Project joint venture participants shows a tremendous commitment to Australia. Since the discovery of the gas-condensate field in 2000, the Ichthys road has been one of identifying and overcoming geographical, political, technical, physical, financial, and commercial challenges. The Ichthys Project is a global effort, drawing on worldwide expertise to overcome these challenges and work towards first gas in late 2016.

Early-Life Field-Development Optimization of a Complex Deepwater Gulf of Mexico Field

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 22252, ’Early-Life-Cycle Field-Development Optimization of a Complex Deepwater Gulf of Mexico Field,’ by Patrick F. Angert, SPE, BP Exploration; Obiajulu J. Isebor, SPE, Stanford University; and Michael L. Litvak, SPE, BP Exploration, prepared for the 2011 Offshore Technology Conference Brasil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed. A complex deepwater Gulf of Mexico field contains several stacked hydrocarbon-bearing intervals charged with volatile oil or rich gas condensate. Well locations, drilling schedule, and reservoir units into which wells will be initially completed and then later recompleted were optimized, maximizing net present value (NPV) while matching field-development constraints. Potential well locations and recompletion locations in geologically justified areas were evaluated. Drilling-rig pace and order and associated project and drilling economic constraints have been considered. BP’s Top Down Reservoir Modeling (TDRM) Option Evaluation (OE) technology has been extended to cover the simultaneous optimization of well completions and recompletions in reservoirs containing multiple stacked pay. Introduction Assisted-history-matching technologies have proved extremely useful for identifying multiple geologically plausible matches of historical production and surveillance data within existing fields. Assisted field-development optimization, although slightly newer, is nevertheless proving extremely useful in the identification, categorization, understanding, and ranking in economic and recovery terms of the multitude of possible development scenarios that could be implemented to produce oil, gas, or condensate from a field. These technologies couple with existing full-physics reservoir simulators and rely on search-and-optimization algorithms such as genetic algorithms, Monte Carlo, or other optimization/search routines. Typically, tens of thousands of possible development scenarios are generated in search of a much smaller set that meets all of the initial criteria specified while achieving higher overall project NPV and recovery. High potential cases are then investigated further, and, ultimately, a final development scenario is selected and refined further as a project progresses toward a final investment decision and commitment of project development capital. Field Background For the field under investigation, rich-gas-condensate and volatile-oil accumulations sit in a water depth greater than 6,000 ft. The upper hydrocarbon-bearing intervals occur below approximately 24,000-ft true vertical depth subsea (TVDSS) and extend to greater than approximately 29,000-ft TVDSS. The highest initial pressure of a hydrocarbon-bearing interval is approximately 20,000 psia.

2012 offshore petroleum exploration acreage release

Australia has abundant natural gas reserves and is experiencing a rapid expansion of its liquefied natural gas (LNG) production capacity. In 2011 alone, four Australian LNG projects received final investment decisions (FIDs) and another FID was made in the first weeks of 2012. These projects will add more than 33 million tonnes of new LNG capacity, represent more than $100 billion in investment, and will see Australia become the world’s second largest LNG exporter by 2015. These projects are underpinned by Australia’s stable economic environment and our effective and efficient legislative regime that provides the industry the confidence to pursue a variety of investment opportunities. The essential first step covered by this regime is exploration, which is supported by Australia’s annual Offshore Petroleum Exploration Acreage Release. Prepared by the Department of Resources, Energy and Tourism and Geoscience Australia, the annual Acreage Release is the key mechanism used by the Australian Government to encourage investment in petroleum exploration. The 2012 Acreage Release areas have been carefully selected to offer the global petroleum exploration industry a variety of investment opportunities. Areas vary in size, level of existing geological knowledge, and are located in a range of water depths. Selected areas are supported by pre-competitive geological and geophysical data and analysis undertaken by Geoscience Australia. The detailed Acreage Release information package is available at online at www.petroleum-acreage.gov.au or by visiting the Commonwealth Government’s booth at the APPEA conference.

2011 PESA industry review: production and development

2011 was a lacklustre year for Australian hydrocarbon production, however a stellar year for LNG development. Domestic gas production was flat despite two new gas developments, Reindeer/Devil Creek and Halyard/Spar, which came into production during the year. Oil production fell, primarily due to the redevelopment of North West Shelf oil facilities, with Kitan in the Timor Sea being the only new offshore oil field that commenced production. LNG production was also flat however, Final Investment Decisions (FID) were announced for five new LNG projects, including Ichthys early in 2012, bringing the combined value of all eight sanctioned LNG projects to more than $180 billion. This is a huge volume of development, not only for the industry but for the whole Australian economy. Importantly, it has also moved Australia closer to becoming the world’s largest LNG producer. Increasing development costs and competition for skilled labour still remain the biggest challenges for the industry. Introduction of the carbon tax was also an important development in 2011, marking a significant step towards a low-carbon economy and increasing the opportunity for natural gas, but also burdening trade-exposed industries like LNG. The success of unconventional gas in the United States and CSG in Australia has sparked a step-change in exploration and development of unconventional gas in onshore Australia. Consolidation in coal seam gas sector continued on the east coast with the two acquisitions of Eastern Star Gas by Santos and Bow Energy by Arrow Energy. Continuing to effectively engage with the community will be central to the industry’s success.

Shell To Build World's First Floating LNG Facility

Shell will build and deploy the world’s first floating liquefied natural gas (FLNG) facility, a milestone in industry efforts to commercialize gas supplies that have been stranded for economic reasons stemming from logistical, technical, business, and marketing challenges. The Prelude FLNG project, which Shell will operate with a 100% interest, received its final investment decision in late May. The facility will produce an estimated 3 Tcf of gas and equivalent resources from the Prelude field, discovered by Shell in 2007 approximately 125 miles offshore northwest Australia. First production is anticipated in 2017. On the facility, field gas will be produced, processed, liquefied, stored, and offloaded to oceangoing LNG carriers that will transport cargoes to multiple markets. The facility will also handle field liquefied petroleum gas (LPG) and condensate for ship-borne transport to market. “Our decision to go ahead with this project is a true breakthrough for the LNG industry, giving it a significant boost to help meet the world’s growing demand for the cleanest-burning fossil fuel,” said Malcolm Brinded, executive director of upstream international at Shell. The FLNG technology, he said, “is an exciting innovation, complementary to onshore LNG, which can help accelerate the development of gas resources.” A consortium composed of Technip and Samsung Heavy Industries (SHI) has been contracted by Shell to provide engineering and procurement and perform construction and installation of the Prelude FLNG facility. The facility will be the largest floating structure ever built, measuring 1,602 ft (488 m) long by 243 ft (74 m) wide. Its length is slightly less than the height of the Willis Tower in Chicago and greater than the height of the Petronas Towers in Kuala Lumpur. With a weight of more than 600,000 tons when fully ballasted, the facility has a displacement approximately six times that of the world’s largest aircraft carriers. Construction will take place at SHI’s Geoje Shipyard in South Korea, one of the few locations in the world with a dry dock big enough to accommodate a facility of this size. Once constructed, it will be towed to location—a six-week journey—where it will be fully moored and commissioning of the facility will begin. Once operational, it will produce 4 million tons/yr of LNG, 1.4 million tons/yr of condensate, and 0.4 mil-lion tons/yr of LPG. On a composite basis, the production is equivalent to 110,000 bbl of oil.

PESA 2010 production and development review

2010 was another busy year for Australian hydrocarbon production and development. Natural gas production was the standout performer with both domestic gas and LNG production increasing by about 5% compared to 2009. Domestic gas output was strong with significant growth in production from the Gippsland Basin, coal seam methane in the Surat-Bowen Basin, and the start-up of the Blacktip gas project in WA. Domestic gas output is set to reach record levels again next year and has strong growth prospects in the future with final investment decisions being taken on coal seam gas projects in Queensland and the Macedon project in WA. Australian LNG production increased 4.5% in 2010 accounting for 34% of Australian hydrocarbon production. LNG production will grow further in 2011 with first gas expected from Pluto LNG project during the year. Oil production was steady in 2010; however, it is set to increase in 2011 with a full year of production from the Van Gogh and Pyrenees projects. Production levels only tell part of the Australian hydrocarbon story. In addition to the proposed domestic gas and oil projects, the combined value of committed and potential LNG projects in Australia has surpassed $100 billion. A highlight of 2010 was the final investment decision on the A$15 bn Queensland Curtis LNG Project (QCLNG). The first phase of QCLNG will consist of two LNG trains with a combined capacity of 8.5 million tonnes per annum, with first LNG exports expected in 2014. QCLNG is the first of many proposed coal seam gas to LNG (CSG-LNG) developments in Queensland. Other CSG-LNG projects reached significant milestones this year. Of particular note is the federal environmental approval of Gladstone LNG and state environmental approval of Australia Pacific LNG. In WA, the Browse LNG project complied with all Browse Basin retention lease conditions and remains on track for a targeted final investment decision in 2012. Other major LNG projects including Ichthys and Wheatstone also continue to make positive progress towards a final investment decision in the next 24 months. Sunrise, Prelude and Bonaparte LNG set a technology milestone in the industry with all three selecting floating LNG (FLNG) as their preferred development concept. 2010 has also seen the emergence of further new technologies in the form of small scale LNG projects for resources previously considered un-commercial. This has opened the door for South Australia and New South Wales to enter the LNG export market in the future. The Australian hydrocarbon industry continues to grow and its global importance, particularly in LNG, reflected by the increasing number of foreign companies entering Australia. In 2010, Shell and PetroChina increased their involvement in the Australian industry purchasing Arrow Energy for A$3.5 bn. CNOOC has increased its involvement in a number of areas, including purchasing a 5–10% stake in QCLNG and investment in CSM exploration through Exoma Energy. GDF Suez and Total have reinvigorated their interests in offshore WA and Petrobras made their first entry into Australia acquiring an interest in exploration acreage offshore WA. 2010 was an active year for Australian hydrocarbon production and development–continued success depends on the successful execution of committed and proposed projects. Escalation of development costs and a looming skills shortage remain the largest risks to the Australian hydrocarbon industry as multiple projects attempt to move forward simultaneously.

Application of the CO2QUALSTORE guideline for developing a risk-based investment schedule for an integrated CCS project

Abstract The investment schedules of CCS projects that benefit from public funding may be driven by external schedules not derived from bottoms up project-specific timelines. This situation can increase project risk by obliging projects to execute a number of discrete engineering and exploration steps in parallel that would otherwise be staggered to minimize investment risk. Further complications may arise by combining power sector and upstream engineering practices within the same project in order to fulfill the requirements of parallel CO 2 capture and storage sub-projects. Both industries make use of decision gate workflows to create a robust framework for investment, but the workflows themselves can be significantly different due to the dissimilar levels of risk and uncertainty involved. Here, the major difference between an industrial plant project and a storage site project is that the latter involves an additional exploration and verification process prior to selecting an engineering concept for storage and making a final investment decision. For an integrated CCS project this exploration process will ultimately decide the optimal locations of both the storage and the power/capture plant and it is therefore advised to prioritize this process and put all post-concept selection activities on hold until the project location is verified. The CO2QUALSTORE guideline was developed by a consortium of companies representing both power and upstream industry sectors and therefore offers a unique and valid starting point for developing a project specific, risk optimized investment schedule. A method for considering this is in a generic manner is presented.

Gorgon To Drive Australian LNG Asia-Export Surge

Gorgon project One of the world’s largest natural-gas projects, involving one of the largest, most advanced carbon-dioxide-sequestration initiatives, is moving ahead in Coastal Western Australia. The Chevron-operated Gorgon project will develop offshore reservoirs for liquefied-natural-gas (LNG) export and domestic gas-market supply, centered around LNG and gas-plant facilities to be built on Barrow Island. Sanctioned in 2009, Gorgon is in its construction phase and is slated to begin operations in 2014. Not far behind is another huge Chevron-led natural-gas/LNG project, Wheatstone, in which company and third-party fields off Western Australia will be developed and tied into a planned coastal LNG-export and domestic-gas processing hub. Front-end engineering and design are under way, with a final investment decision expected in 2011. LNG exports to Asia Pacific customers are at the heart of both projects, which together point to a surging importance of Australian LNG in the world market. Australia is the world’s sixth largest exporter of LNG, and some market observers believe that anticipated projects could elevate Australia to No. 1 in world LNG exports within about a decade. ‘An Energy Sweet Spot’ “In every sense, the biggest game in town is the development of megaprojects for the export of LNG,” Western Australia Premier Colin Barnett said earlier this year. In a recent talk to the Australian Petroleum Production &amp; Exploration Association, Roy Krzywosinski, managing director, Chevron Australia, said, “Our industry finds itself in an energy sweet spot, surrounded by natural-gas resources on the doorstep of the world’s biggest and fastest-growing market, the Asia Pacific region.” Gorgon’s reserves lie within the Greater-Gorgon-Area gas fields in the Carnarvon basin off the northwest coast of Western Australia. The initial phase of development includes 18 subsea wells to be drilled in two separate fields: Gorgon, approximately 80 miles offshore in 660 ft of water; and Jansz-Io, approximately 125 miles offshore in 4,300 ft of water. It is anticipated that up to 30 wells will be drilled in the Gorgon-area fields over approximately 30 years. From the wellheads, gas will flow to one of several cluster manifolds to be installed nearby on the seafloor, at which production from multiple wells will be combined and routed in a single flow path from each manifold to pipeline-termination structures. A system of flowlines will connect these termination points with each other. Produced gas will flow through lines leading from the termination structures and eventually traveling up a steep, 5/8-mile-high underwater escarpment en route to the Barrow Island processing facilities. All subsea equipment will be monitored and controlled from the onshore LNG plant by means of an electrohydraulic multiplexed system with primary fiber-optic communications, which will incorporate a system of subsea control umbilicals to tie in the seafloor infrastructure with the plant.