Topside payloads range from 5 to 50,000 tons, producing oil, gas, or both. A vast array of production systems is available today (see Figure 1). The concepts range from fixed platforms to subsea compliant and floating systems. In 1859, Col. Edwin Drake drilled and completed the first known oil well near a small town in Pennsylvania, U.S.A. This well, which was drilled with cable tools, started the modern petroleum industry.
The majority of offshore fields have been developed with conventional fixed steel platforms. One common feature of fixed steel structures is that it is essentially "fixed" (i.e., it acts as a cantilever fixed at the seabed). This forces the natural period to be less than that of the damaging significant wave energy, which lies in the 8- to 20-second band. As the water depth increases, these structures begin to become more flexible, and the natural period increases and approaches that of the waves. The consequence of this is the structure becomes dynamically responsive, and fatigue becomes a paramount consideration.
Icebergs can pose risks to platforms in arctic and subarctic regions. These risks require careful consideration during design, and as well during operations. Platforms must be designed to withstand potential impacts from icebergs, or to disconnect and move offsite to avoid impacts. ISO 19906 allows use of ice management to mitigate iceberg and sea-ice actions. In the case of icebergs, management may include detection, monitoring, towing, disconnection and evacuation. Threat assessment is also a critical input to the iceberg management decision-making process. For example, given one or more detected icebergs and available information on the iceberg and environment characteristics, what is the probability of exceeding platform design ice actions? Based on the threat assessment, better decisions can be made regarding which iceberg to manage, whether more information should be acquired, and whether shut-down or evacuation is needed.
This paper describes a new tool developed to estimate the distribution of iceberg impact actions from an encroaching iceberg given concurrent metocean conditions, conditional on impact. The tool can be used in a number of ways depending on the information available to the user. It can be used to assess the threat from a single iceberg or can be used to compare actions from multiple icebergs in the region, or for the same iceberg but with changing weather conditions. The iceberg load assessment tool is demonstrated for several example cases on the Grand Banks, showing the benefit of improved iceberg characterization obtained through rapid iceberg profiling.
For oil and gas projects offshore Newfoundland, Canada, subsea structures are generally placed in excavated drill centres which lower the equipment below the natural mudline, protecting the equipment from damage due to iceberg impact. This paper introduces a concept of protecting this equipment by utilizing a concrete structure affixed to the seabed using hammer driven piles.
Iceberg loads have been assessed utilizing a Monte Carlo iceberg contact model and a modified version of the Iceberg Load Software (ILS) developed for regions offshore eastern Canada. The Subsea Iceberg Protection Structure (SIPS) was designed using post-tensioned concrete construction. Preliminary concrete design in addition to pile capacity design is performed utilizing FE analysis. Using a hammer driven piled system, the maximum lateral resistance capacity can be determined in addition to the maximum impact energy absorption.
The internal Subsea Production System (SPS) system has been designed to specifically fit inside the SIPS while maintaining full ROV access for operation, maintenance and future well intervention.
The SIPS was designed as an L1 structure in accordance with ISO 19906. This includes impact from free floating and gouging icebergs. The design load for this impact event was calculated based on energy absorbed through ice crushing. The deformation and global movement of the SIPS was not considered as part of the energy absorption mechanism. The maximum ice crushing design load on the SIPS was determined for four locations on the Grand Banks offshore Eastern Canada.
In addition to the structural design of the SIPS, the piling system was analysed to determine the maximum capacity. The total lateral resistance was determined using a combination of a continuum model and a structural beam model (P-y method). The global movement was less than the maximum allowable deformation of the structure. The structure is therefore considered fit for purpose.
The projected construction and installation cost of this structure shows the potential for reduced costs compared to an excavated drill centre, thereby increasing the feasibility of potential tie-backs.
Using updated knowledge regarding iceberg size and geometry, areal density and ice strength, the analysis and design presented in this paper suggests that it may be more economical to install protection structures rather than dredge excavated drill centres, for marginal fields. In addition, the advancement of the internal SPS system is such that the equipment footprint is compact, requiring limited space within the SIPS.
This paper provides the necessary information to show that installing a structure to protect subsea equipment is technically achievable.
Up to present, the annual iceberg contact frequency for short subsea flowline systems designed for offshore Newfoundland and Labrador has been less than the target reliability level. For longer flowlines, iceberg contact rates will be higher and the consequence of such contacts must be considered. It is possible, for example, that the pipe gets pushed into the seabed with acceptable damage to the pipe and/or localized ice failure takes place. If it can be demonstrated that a pipe could survive some impacts, it might be possible to avoid costly protection strategies such as trenching or rock berms. This paper describes physical tests conducted as part of a preliminary investigation to assess the consequence of a free-floating iceberg interacting with a flowline placed on the seafloor. Two scenarios were considered in this testing program. The first focused on understanding the local iceberg failure processes and the second evaluated the transverse flowline motion when a free-floating keel snags a flexible pipe laid on the seabed.
The Hebron field has finally begun production 37 years after it was discovered 200 miles off the east coast of Canada. Production is expected to peak at 150,000 B/D and is ultimately expected to yield about 700 million bbl of oil over its life. Hebron is one of a cluster of discoveries made between 1979 and 1985 in the outer banks area of Newfoundland and Labrador, which includes the Hibernia and Terra Nova fields. The glacial pace of Hebron's development reflects an array of challenges at the field, which contains more than 2 billion bbl of oil in place. The project will produce heavy oil (17–20ºAPI), which is harder to get out than lighter grades, and it is located in an iceberg-prone area.
A busy week for ExxonMobil marked a continued companywide transition for the world's largest public oil and gas firm, headlined by its withdrawal from once-promising Russian joint ventures and its announcement of a seventh oil discovery off Guyana. According to a filing with the US Securities and Exchange Commission, ExxonMobil is pulling out of its JVs with Rosneft, established earlier this decade, that involved exploration and development of Arctic, Black Sea, and shale resources. ExxonMobil's role in those partnerships was quashed when the US government levied sanctions on Russia in 2014 following its annexation of Crimea and expanded those measures in late 2017. ExxonMobil sued the US Department of the Treasury last year in response to a $2-million fine for violating the 2014 sanctions. "This decision puts a formal end to ExxonMobil's long-term strategy of exploring the Arctic, which led to the discovery of the giant Pobeda field in 2014. It also makes the progress at the Far East LNG project less likely," explained Samual Lussac, senior research manager, Russia upstream, at consultancy Wood Mackenzie.
It is well known in the industry that the environment for all offshore oil and gas marine operations has unique challenges the world over. However, when operating in a subarctic region with notoriously difficult sea states, regular encounters with sea ice, icebergs, strong winds, thick fog and numerous forms of solid and liquid precipitation, the challenges become a major consideration for even the most straight forward task. It was in this very environment in Newfoundland and Labrador (NL), Canada, the Hebron Project safely and successfully executed a number of very complex, industry first, major marine operations. Successful management of these major operations was only possible due to a strong, experienced team who were able to balance critical technical planning processes with an appropriate risk based approach to decision making. The basis for this approach to planning and executing these marine activities for the Hebron Project will be explained in this paper, including some of the key success factors that enabled the team to overcome many safety, environmental and technical challenges that were encountered.
Morandi, Alberto (GustoMSC formerly with American Global Maritime Inc.) | Kwan, Chi-Tat Thomas (Kwan Engineering Services) | Shelton, John (Delmar Systems Inc) | Yao, Aifeng (contributed while under employment with Shell)
An Arctic Mooring JIP was initiated by Kwan Engineering Services and Global Maritime in 2013 to address the issue of Arctic mooring design and operation practice, which was completed in 2016. There were 24 participants including operators, drilling contractors, regulators, designers, and hardware manufacturers with a total funding of $780k. The JIP had five tasks related to mooring in the Arctic: Task 1 – Guidance on mooring strength design practice Task 2 - Assessment of disconnect devices and requirements Task 3 - Assessment of mooring components for operations in the Arctic Task 4 – Guidance on methods for ice load prediction Task 5 - Guidance on ice management strategies
Task 1 – Guidance on mooring strength design practice
Task 2 - Assessment of disconnect devices and requirements
Task 3 - Assessment of mooring components for operations in the Arctic
Task 4 – Guidance on methods for ice load prediction
Task 5 - Guidance on ice management strategies
A guidance summary on Arctic mooring design and operation practice was developed by the JIP for input to industry standards. This paper presents the key elements in the guidance summary.
ISO 19906 ‘Arctic Offshore Structures’ (
Widianto, _ (ExxonMobil Development Company) | Chichester, Justin (ExxonMobil Production Company) | Younan, Adel (ExxonMobil Production Company) | Khalifa, Jameel (ExxonMobil Development Company) | Komperla, Krishna (WorleyParsons) | Bidne, Knut (Kvaerner)
The Hebron platform was successfully installed on the Grand Banks (Offshore Newfoundland and Labrador) in June 2017 with first oil produced in November 2017. It consists of a single shaft concrete Gravity Based Structure (GBS) supporting an integrated drilling and production topsides. The design of the platform was challenged by subarctic and extreme metocean conditions which required innovative design and layout approaches for many elements considered routine for typical platforms. This paper highlights the underlying innovative technologies, analytical and design methods as well as the capital-efficient execution strategies employed.