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The necessity of improving the risk-return-balance for lifecycle decision making in the offshore wind energy industry, which is required to enhance competitiveness of this form of power generation, has been investigated and results are presented in this paper. All activities were carried out in the course of work package 6 “Uncertainty and risk management” of the EU H2020 LIFES50+ project, focusing on development of next generation industry scale floating substructure supported solutions.
An introduction to the main ideas behind the general asset management theory is provided and supplemented by practical examples from the offshore wind industry. The link of asset and risk management is made in order to establish the right context for embedding risk assessment in an asset management chain. Challenges involved with implementing risk assessment in asset management are highlighted by practical examples and results are summarized and discussed in a concluding section at the end of the presented work.
The offshore wind energy industry is growing rapidly in many European countries that have access to suitable sites. Large areas are under development in the Baltic Sea, the North Sea and the East Coast of the North Atlantic Ocean. Ambitious targets have been set by the European Union, demanding the industry to install, commission and connect 40 GW (Gigawatts) of offshore wind capacity by 2020 to national electricity grids.
Until now, investments have been mainly financed directly by the utility companies developing a wind farm. They perceive the potential profits to be gained by investing in large scale offshore wind energy projects to be an attractive alternative to conventional fossil-fuelled or nuclear power plants. They therefore actively finance a significant proportion of the investment from their own capital. However, a report recently published by the Boston Consulting Group (Rubel, 2013) points out that utilities will not be able to finance future investments of approximately €3 billion per GW in the same manner as it has been done up to now. Such investments tend to be high risk, considering all major unfavourable events that could potentially materialise during the various lifecycle phases from planning to decommissioning. Such events could, e.g., be an unexpected increase of manufacturing costs, exceedance of planned installation times due to adverse weather conditions, major component breakdowns during operation or large expenditures during decommissioning due to new environmental regulations. The different risk sources to be taken into consideration are elaborated in details in a publication by Proskovics (2016).
Abstract Oil and gas megaprojects have adopted project management practices, such as interface management, change management, and risk management to manage increased project complexity caused by many factors, including complex engineering, the involvement of numerous global stakeholders, and changing environmental factors. However, integrating these key business practices continues to remain a challenge for many organizations. This paper discusses specific approaches on how an integrated approach creates cross-discipline data relationships that provide teams with better information for decision making and progress tracking, and thus helps to improve project performance. In particular, specific attention is paid to interface management and its impact on the following well-established practices. Change Management – Changes are inevitable in megaprojects and well-developed change management programs ensure all changes and their potential impact are appropriately assessed before implementation. As a form of scope management, interface management can often lead to change during project execution. In addition, change can often lead to interface modifications. Establishing a relationship between these two practices is essential to ensuring alignment between these functional areas. Risk Management – The project risk register is a key tool used in managing risk for projects. Risk management is a mature practice and the importance of implementing risk management for project success is rarely challenged. Poorly controlled interfaces can represent significant risk to a project; however, these are rarely captured in the risk register. Better management and visibility of project risk is achieved by ensuring high-risk interfaces are identified and logged in the project's risk register. Deliverables Management – Ensuring all documents, drawings, and specifications are received on time and distributed appropriately is a key goal in deliverables management. Integrating this process with interface management ensures that not only are internal project teams kept informed of new documents and new revisions, but that interfacing parties are also kept informed. Projects will find value in integration across all of these processes by allowing interface management either to feed information into or receive information from them. Key benefits include: Increased visibility Early identification of potential issues Consistent execution and data capture Better decision making with better data and data links All parties, including interfacing parties, are kept informed in real-time Reduced time spent searching for information The future of managing oil and gas megaprojects at a higher level will involve integrating project management processes. This integration will give project teams a higher level of oversight and enable them to make better and more informed decisions, all of which help improve project performance to ultimately gain a competitive edge. Although this integration was not previously possible due to limitations in the tools being used, new advanced systems that support full integration are now making this an achievable reality.
There is a global trend for integrated subsea alliances to be involved in projects earlier, with a broader scope and in closer collaboration with the operating company. Sometimes, this is achieved by enabling contractors to develop and propose their own field development concept, known as a supplier-led solution (SLS). This paper refers to a case study that demonstrates an effective way to improve project economics.
A benchmark field layout plan was first generated using the customer's reference case. Then, a fully unconstrained SLS was developed to challenge and improve this reference case based on six main factors:
Integrated production system modelling
Fit-for-purpose project and design scoping
Alternative field architecture
Use of standardization
Use of supplier or industry specification
Integrated project execution
A production assessment, cost estimation, and schedule were developed first for the reference case, fully compliant with the customer specifications, and with no deviation to the scope of work, and second, for the completely unconstrained SLS.
Comparing the SLS to the reference case for this case study, the main improvements were as follows:
Accelerated production thanks to integrated modelling and the introduction of subsea boosting technology
Significant improvement in capex of approximately 41%
Accelerated schedule due to a proposed innovative bidding process and a reduced equipment lead time enabled by standardization
Lower project risk profile by improving the execution predictability primarily due to the integrated subsea offering
The combination of these improvements resulted in better project economic viability and allowed lower contingency cost accruals due to proactive risk management. The SLS also helped the operating company to build a viable development scenario in order to pass through the next project stage gate.
This paper demonstrates how an integrated subsea alliance with a broad spectrum of capabilities from the reservoir to the surface can deliver value through fully integrated earlier engagement. The methodology presented in this paper can be customized for any offshore prospect; the only prerequisites are early engagement, access to required data, and the freedom for the contactors to develop their own solution, in coordination with the operating company. A key feature of the proposed methodology is to link the SLS to reservoir representation, which avoids the common pitfall of delivering capex savings at the expense of larger production (revenue) losses.
The modern reservoir management process involves goal setting, planning, implementing, monitoring, evaluating, and revising plans. Setting a reservoir management strategy requires knowledge of the reservoir, technology, and an understanding of the business, political, and environmental climates. Formulating a comprehensive management plan involves depletion and development strategies, data acquisition and analyses, geological and numerical model studies, production and reserves forecasts, knowledge of facilities requirements, economic optimization, and management approval. Implementing the plan requires management support; field personnel commitment; and multidisciplinary, integrated teamwork. Project success depends on careful monitoring/surveillance and thorough ongoing evaluation of its performance. If the actual performance of the project does not agree with the expected performance, the original plan should be revised and the cycle (implementing, monitoring, and evaluating) reactivated.
This paper presents sound reservoir management concepts and methods including a team approach based on integration of geoscience and engineering professionals, tools, technology, and data.
The newest industry buzz word, reservoir management, has received significant attention in recent years. Various panel, forum, seminar, and technical sessions provided the framework for information sharing and exchanging ideas on many practical aspects of integrated, sound reservoir management. The needs to enhance recovery from the vast amount of remaining oil and gas in place around the world and to compete globally require better reservoir management practices.
A reservoir's life begins with exploration, which leads to discovery; reservoir delineation; field development; production by primary, secondary and tertiary means; and abandonment (Fig. 1). Sound reservoir management is the key to successful operation of the reservoir throughout its entire life. It is a continuous process, unlike how the baton is passed in traditional E&P organizations.
Historically, some form of reservoir management has been practiced only when a major expenditure is planned, such as original field development or waterflood installation. The reservoir management studies at these specific times were not integrated; i.e., different disciplines did their part separately. During the last 20 years, however, greater emphasis has been put on synergism between engineering and geosciences. Halbouty stated in 1977: "It is the duty and responsibility of industry managers to encourage full coordination of geologists, geophysicists, and petroleum engineers to advance petroleum exploration, development, and production." Despite the emphasis, progress in integration has been slow.
Many leading-edge technological advances have been achieved in geophysics, geology, petrophysics, production, and reservoir engineering. Mainframe supercomputers, more powerful personal computers, and workstations are providing ever-increasing computing power and more efficient database management systems. The technological advances and computer tools (i.e., 3D seismic surveys, cross-well seismology, horizontal wells, geostatistics, EOR processes, and facilities automation) can facilitate better reservoir management, enhancing economic recovery of hydrocarbons (Fig. 2). Even a small percent increase in recovery efficiency could amount to significant additional recovery and profit.