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.
Equinor has successfully bid on new exploration parcels in the Jeanne d’Arc basin offshore Newfoundland, boosting its Canadian portfolio. The company said it will operate two exploration parcels totaling 1,593 square miles and will have a minority ownership stake in another parcel operated by Suncor Energy. Equinor has been active offshore Newfoundland and Labrador in recent years. It operates five discoveries in the Flemish Pass Basin: Mizzen, Harpoon, Bay du Nord, Bay du Verde, and Baccalieu. Each field is located in a water depth of approximately 3,600 ft.
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.
Geng, Meixia (Institute of Geophysics and Geomatics, China University of Geosciences, and Department of Earth Sciences, Memorial University of Newfoundland) | Welford, J. Kim (Department of Earth Sciences, Memorial University of Newfoundland) | Farquharson, Colin G. (Department of Earth Sciences, Memorial University of Newfoundland) | Peace, Alexander L. (Department of Earth Sciences, Memorial University of Newfoundland)
We present 3-D inversion results of gravity gradiometry data over the Budgell Harbour Stock (BHS) intrusion, in northern-central Newfoundland, Canada, obtained using a probabilistic inversion method. We examine multiple density contrast models obtained by inverting the single component Tzz and by jointly inverting five independent components. The inversion results show that
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 213B (Anaheim Convention Center)
Presentation Type: Oral
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.
This paper is a subsurface introduction to the Hebron Field focusing on field discovery, delineation and development project history as well as geoscience and reservoir background. We will show how field understanding has evolved over time and how technology and data quality improvements impacted this project. For example, we will show how the recent IsoMetrix seismic survey has contributed to reservoir definition and architecture understanding. Finally, we will review the first drilling results after about six months into the drilling campaign.
This paper is to represent reviews of low dosage hydrate inhibitor's (LDHI) evolution and advances, and to provide a general guide for LDHI considerations, historically, hydrate risk has been managed by keeping the fluids warm, removing water, and/or by injecting thermodynamic hydrate inhibitors (THI), commonly methanol or glycol. THIs require high dosage rate therefore production systems can reach a treatment limited by supply, storage, and umbilical injection constraints. Besides, high dosage of MeOH can cause crude contamination for downstream refineries, which may result in penalty.
Over last two decades LDHIs have been extensively researched and developed as an alternative hydrate management chemical for oil and gas industry. LDHIs are divided into two main categories; Kinetic Hydrate Inhibitor (KHI) and Anti-Agglomerant (AA), both have been successfully used in field applications, but each comes with their unique challenges for applications, OPEX and CAPEX considerations. LDHIs have proven track records in numerous fields in their performance, either as stand-alone chemical treatment or reducing amounts of methanol/glycol usage, which has directly resulted in CAPEX and OPEX reduction. LDHIs have been instrumental in managing risks of early water breakthrough, high cost of THI storage and transportation, HSSE concerns around THI handling, and undersized pump capacity for required chemical volumes. Switching to LDHIs also offers an economic advantage by reducing umbilical line diameter. Latest advances in the LDHI technology is breaking barriers and pushing limits.
The paper summarizes historical advancements in LDHIs over the last two decades, discusses application advantages and limitations, and the criterions to consider for selecting LDHIs.
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.
The Hebron Offshore Development Project, offshore Eastern Canada, is one of the world's most ambitious oil projects. In November 2017 ExxonMobil Canada Properties (EMCP) commenced oil production from this world scale engineering marvel located in 93m of water approximately 350 kilometers southeast of St. John's NL in an area known as the Grand Banks.
The Hebron platform consists of a Gravity Based Structure (GBS) with a storage capacity of 1.2 million barrels of oil and an integrated steel topsides structure. The integrated topsides design with total operating weight capacity of ~65,000 t contains drilling and production facilities with a peak production capacity of 150,000 barrels per day (bpd) and a living quarters for 220 people. The field infrastructure also includes a subsea Offshore Loading System (OLS) providing crude offloading capability to tankers and a fiber optic cable loop linking the offshore platform to an onshore network enabling enhanced digital technology implementation. The project was sanctioned on 31 December 2012 and first oil occurred on 27 November 2017, ahead of schedule.
This paper discusses the Project from design through execution and highlights several of the unique design features, execution sequence and specific challenges which were faced. Special technologies were employed and project management initiatives implemented which enabled the success of the project.