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The co-owners of the Terra Nova project offshore Newfoundland have reached an agreement in principle to restructure the project ownership and provide short-term funding toward continuing the development of the Asset Life Extension Project, with the intent to move to a sanction decision in the fall. A subset of owners will increase their ownership of the project for consideration payable from the other owners. Full details of the ownership swap were not disclosed, however, as a result, operator Suncor's ownership will increase to 48% from around 38%. The agreement is subject to finalized terms and approval from all parties, including board of director approval where appropriate, and is contingent upon the previously disclosed royalty and financial support from the Government of Newfoundland and Labrador. "Over the past year, Suncor has worked diligently with all stakeholders to determine a path forward for Terra Nova," said Mark Little, Suncor president and chief executive officer.
Suncor Energy is preparing for all contingencies when in comes to the fate of the Terra Nova FPSO. The operator recently issued Expressions of Interest (EOI) related to the FPSO, including two that prepare for decommissioning of the vessel and the field, while another provides an update to a previous EOI preparing for remediation of the FPSO to support the asset life-extension project. The move has the Newfoundland and Labrador Oil & Gas Industries Association (NOIA) concerned about the future of the vessel and the field. "NOIA members and our Board of Directors are deeply concerned for the future of the Terra Nova Project and the far-reaching impacts decommissioning and abandonment would have upon our industry, the people who work in it, and our province," said Charlene Johnson, chief executive of NOIA. "I understand the deadline to reach a deal on the Terra Nova Project was extended to April 30--which has now passed--and NOIA is encouraging all parties to reach an agreement as quickly as possible."
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.
The status of Suncor Energy's Terra Nova floating production storage and offloading (FPSO) remains in flux after the company reported a fire on 30 May coming from the vessel's low-pressure (LP) separator. The fire was extinguished with no injuries and all personnel accounted for. There is no gas or crude held onboard the vessel, which has been shut down for maintenance. The fire comes 6 months after the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) issued an order to suspend production-related operations on the FPSO vessel, approximately 350 km east of St. John's. The C-NLOPB determined in December that Suncor was not compliant with regulatory requirements under the Atlantic Accord Implementation Acts to maintain and comprehensively inspect equipment critical in the safe operation of the installation, to ensure repairs are carried out in a timely manner, and to ensure that mitigation measures are effective in minimizing hazards.
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.
In this paper, an analysis of the selection of integrated template structures (ITSs) for Arctic environments is presented. An analysis of several actual projects has been carried out. One of the important parts of this work was devoted to the requirements on ITSs conceived in relevant standards. The main elements of subsea-production modules, including their specific characteristics and components, are considered in the work. The Terra Nova and White Rose fields, on the Grand Banks of Newfoundland, have been developed; other offshore projects are being prepared, such as Goliat and Skrugard in Northern Norway. These projects can be considered as true stepping stones toward oil and gas development in the Arctic region.
Kornishin, Konstantin A. (Rosneft Oil Company) | Efimov, Yaroslav O. (Arctic Research Centre) | Tarasov, Peter A. (Rosneft Oil Company) | Mamedov, Teymur E. (Arctic Research Centre) | Smirnov, Konstantin G. (Laboratory "Arctic-Shelf,") | Skutin, Andrey A. (Arctic and Antarctic Research Institute (AARI)) | Skutina, Elena A. (Laboratory "Arctic-Shelf,") | Naumov, Aleksey K. (Arctic and Antarctic Research Institute (AARI)) | Gudmestad, Ove T. (Laboratory "Arctic-Shelf,")
ABSTRACT To ensure safety of marine operations during ice management in arctic seas, it is essential to understand an iceberg's stability. Stable icebergs can be towed away from offshore facilities using standard vessels and procedures. Unstable icebergs create high risks and can easily capsize during the vessel's maneuvering and towing. As is known, an iceberg capsize event could lead to iceberg destruction into several pieces. The total danger from the parts often would exceed the initial one. Especially dangerous are large icebergs that may capsize and damage the towing vessel. Due to interaction with the seawater, the icebergs have their natural oscillations, which under certain environmental conditions can significantly complicate the towing process due to resonance phenomena. We should also notice that during the melting, icebergs will change form and motion characteristics. The paper presents calculations of icebergs' stability criteria (metacentric height) based on iceberg towing experiments conducted in 2016–2017 in the Barents and Kara seas. Longitudinal and roll oscillations of various icebergs are considered. The appearance of resonance phenomena during iceberg drift is studied for characteristic periods of waves of the Kara and Laptev seas. Periods of natural oscillations are defined using 3D models of icebergs constructed from aerial and sonar surveys. The results obtained show the dependencies of the iceberg's stability criteria on the iceberg's above-water parameters – and demonstrate that unstable icebergs may be identified without sonar surveys. INTRODUCTION Due to significant mass of icebergs and sophisticated underwater geometries that are hard to determine, aspects of icebergs stability significantly affect the tactics of ice management operations. On the one hand, an iceberg can overturn during towing (Efimov et al., 2019) or even while a tow rope or net is being deployed requiring prompt vessel maneuvering, and in the worst case, causing some damage to a towing vessel. On the other hand, an unstable iceberg may breakup due to wave action from the vessel without direct contact with vessel or rope (Kornishin et al., 2019).
Abstract The paper focuses on the history of the development of the Floating Production Storage and Offloading (FPSO) system and its evolution to be the most adaptable and versatile of floating production systems. These facilities have been deployed in a variety of water depths and metocean conditions in almost every offshore oil producing basin in the world, with a large range of topsides throughput for both oil and gas. The paper has summarized the development of the FPSO system as a function of time, water depth, location, system, type and complexity to illustrate its adaptability to offshore producing basins worldwide. The paper also provides a brief historical description of the evolution of the system by decade, highlighting key projects and technologies and their development over the years. The paper also looks forward to the short-term future of FPSOs in the Oil and Gas industry based on trends and forecast, and the future development especially related to digitalization and carbon footprint reduction. The paper also speculates on the possible application of the system and component technologies to support alternative energy development in the future.
At the present time, more than 9,000 offshore platforms are in service worldwide, operating in water depths ranging from 10 ft to greater than 5,000 ft. 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.
Abstract During offshore drilling operations, the disposal of drill cuttings and associated residual drilling fluid is determined by regulatory constraints, which are usually based on environmental risk. The environmental risk of drill cuttings disposal options is influenced strongly by the location of the well, the level of residual drilling fluid, and the type of drilling fluid. The International Association of Oil & Gas Producers (IOGP) has divided drilling base fluids into water-based drilling fluids (WBDFs) and non-aqueous drilling fluids (NADFs), which are categorized as Group I: High Aromatic Content, Group II: Medium Aromatic Content, and Group III: Low/Negligible Aromatic Content. Group III fluids encompass many types of fluids with low or undetectable levels of aromatic, including olefins, synthetic paraffins, and enhanced mineral oils. Laboratory testing and post-drilling environmental surveys clearly show the difference between WBDFs, Group I and Group III NADFs. However, despite laboratory studies differentiating the various Group III fluids, this differentiation is not clearly observable in single-well environmental monitoring studies. The objectives of this research are (1) to model the environmental risk from offshore drill cuttings discharge with several different Group III drilling base fluids, (2) to determine the impact of formation oil on the calculated environmental risk, and (3) to assess the use of modeling to differentiate drilling base fluids. In this project, DREAM (Dose-related Risk and Effect Assessment Model) was used to simulate the environmental risk from drill cuttings discharge with different drilling base fluids under identical discharge conditions of bore hole diameter, retention on cuttings (ROC), particle size distribution, current, etc. The drilling fluids modeled are: diesel (Group I), four Group III fluids (internal olefin, two enhanced mineral oils, and a synthetic paraffin), and water-based fluid (WBDF), as well as formation oil on cuttings. Benthic environmental risk is quantified using four factors that potentially impact sediment organisms: chemical stress (toxicity), burial, change in sediment grain size, and oxygen depletion due to biodegradation of chemicals present in the drilling base fluid. The modeling results presented in this paper support the differentiation between different drilling fluids and provides insight into the primary drivers of risk. For all fluids, grain size and burial posed small risk in this modeling scenario. As expected, the largest risk was predicted for diesel based on chemical toxicity while the smallest was for WBDF. Most WBDF toxicity impacts are in the water column and not the sediment. Group III NADFs, except for one enhanced mineral oil, had similar risk, but the main risk contributors were different. For the enhanced mineral oils and synthetic paraffin, chemical toxicity influenced overall risk; internal olefins did not exert risk from chemical toxicity. For all Group III NADFs, the main contributor to environmental risk from the discharged matter is oxygen depletion by degradation of the organic load in the base fluid, with more biodegradable Group III fluids having higher predicted risk. This higher predicted risk assessment runs counter to what is seen in environmental surveys. One shortcoming of DREAM is the inability to accommodate anaerobic biodegradation, which leads to predicted long timeframes for contamination that do not match environmental monitoring results. While DREAM is useful for comparing fluids, the outputs of the model should be assessed in context of available environmental studies and operator experience.