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Collaborating Authors
Results
Calgary-based Suncor Energy said the Terra Nova floating production, storage, and offloading (FPSO) vessel has safely restarted production and is expected to ramp up in the coming months. The restart comes after the completion of the Terra Nova Asset Life Extension project, with the FPSO undergoing extensive repairs in a port in northwestern Spain with the goal of extending the vessel's operational life through 2031. At more than 290 m long--about the size of three football fields laid end-to-end--and 45 m wide, the FPSO can hold 960,000 bbl of oil and accommodate up to 120 people while producing, according to Suncor. "Focusing on safety and operational integrity, we have brought this key offshore project online, providing additional cash flow for our shareholders and many benefits to the Newfoundland and Labrador and Canadian economies," said Suncor President and CEO Rich Kruger. "We appreciate the collaboration and support from the provincial and federal governments regarding this project."
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean (0.53)
- Europe > Norway > North Sea > Northern North Sea (0.53)
- North America > Canada > Newfoundland and Labrador > Labrador (0.34)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.27)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Terra Nova Field (0.99)
- North America > Canada > Arctic Ocean > Arctic Basin > Amerasia Basin > Canadian Basin (0.89)
Static Modelling and Fault Seal Analysis of the Migrant Rollover Structure, Sable Subbasin, Offshore Nova Scotia, Canada
Martyns-Yellowe, K. T. (Basin and Reservoir Lab, Department of Earth and Environmental Sciences, Dalhousie University) | Richards, F. W. (Basin and Reservoir Lab, Department of Earth and Environmental Sciences, Dalhousie University) | Watson, N. (Atlantic Petrophysics Limited, Nova Scotia) | Wach, G. D. (Basin and Reservoir Lab, Department of Earth and Environmental Sciences, Dalhousie University)
Abstract Crestal faulting can lead to breach of trap integrity and leakage. The Migrant structure is an example of a potentially breached trap due to fault leakage and juxtaposition. In this paper we use 3D geocellular modeling, populated with new interpretation of input parameters, including shale volume, to examine the possible mechanism for leakage (crestal faulting). A fault plane profile (Allan diagram) was constructed, which can be taken a further step into dynamic modelling and simulation (not presented in this study). Located in the Sable Sub-basin, the Migrant structure is a fault controlled, four-way dip anticlinal closure, which formed as one of a series of related structures during rift basin extension, sediment loading and salt mobilization in the Cretaceous. Genetically related rollover structures (e.g., the Distal Thebaud Field) in a similar structural and stratigraphic setting have proved viable as a commercial trap. The Migrant N-20 well was drilled to test for hydrocarbons trapped in Late Jurassic to Early Cretaceous deltaic and fluvial-deltaic reservoirs in the structure. The well encountered gas from a deep sand reservoir during drill stem testing (DST 2) with a reported flow rate of 10 million standard cubic feet per day. However, over the duration of the test, an associated decline in flow rate and pressure depletion was observed, which led the operators to consider the target reservoir as non-commercial. In this paper we present a re-appraisal to assess why this trap failed by integrating well data (logs, checkshot and pressure) and 3D seismic to produce a static model demonstrating the trapping mechanism in the Migrant Structure. Initial observation of the 3D seismic shows shallow crestal faults while preliminary observation of well logs from the Migrant N-20 well suggests a diminishing sand/shale ratio from the shallow to deep sections of the trap. This study of the Migrant Structure contributes to the understanding of the relationship between reservoir and seal thicknesses relative to fault displacement and its role in subsurface fluid trapping or cross-fault leakage, through upward and outward displacement (stair-stepping) between reservoirs of different ages across a given fault. The paper shows how data integration and workflows have been combined effectively and is an important contribution for risk assessment in the Sable Subbasin. The proposed model can be applied in other basins including the similar salt cored basins like those offshore Brazil.
- North America > Canada > Nova Scotia > North Atlantic Ocean (0.88)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean (0.28)
- Phanerozoic > Mesozoic > Jurassic > Upper Jurassic (0.48)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous (0.48)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Structural Geology > Fault (1.00)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- (4 more...)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.93)
- (3 more...)
- Oceania > New Zealand > East Coast Basin > PEP 38348 (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Nova Scotia > Scotian Slope > Missisauga Formation (0.99)
- (18 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (1.00)
- (5 more...)
Investigation CO2 EOR Types with Constrained CO2 Volume and Impurities for a High-Quality Sandstone, Stratified Offshore Newfoundland Reservoir
Pham, Chau Quynh (Memorial University of Newfoundland) | Esene, Ebeagbor Cleverson (Memorial University of Newfoundland) | James, Anne Lesley (Memorial University of Newfoundland)
Abstract The objective of this study is to evaluate the potential of CO2 sequestration coupled with oil recovery to lower the carbon intensity of incremental oil recovered considering different CO2 EOR types. A compositional stratified reservoir model (with/without crossflow) is used to investigate the effect of limited CO2 volume on the performance of CO2-WAG, enriched CO2-WAG, and carbonated water injection (CWI). We show that joint optimization of oil recovery and carbon storage can decrease carbon intensity. CO2 flooding, CO2-WAG, enriched CO2-WAG, and CWI are investigated under constrained CO2 volumes on a percentage pore volume basis. A sensitivity analysis using Response Surface Methodology (RSM) is carried out within a range of reservoir temperature (50-130°C) and pressure (20-70 MPa) conditions. CO2 volumes that can be captured from offshore power generation are likely insufficient for CO2 flooding but could work for CWI, CO2 WAG or enriched CO2 WAG (CH4-CO2 WAG). Highest incremental oil was found using CWI. However, it did not consider carbon pricing nor look to minimize oil production emissions intensity. Emissions intensity is the new metric during our transition to cleaner energy. CWI can store less than 20% amount of CO2 captured while CO2-WAG, enriched CO2-WAG with 7-10% lower oil recovery, however, can store much larger quantities. The stratified reservoir with crossflow cases had higher recovery factors and later water breakthrough than without crossflow cases. The use of WAG reduced the extent of crossflow and the high WAG ratio (3:1) would lead to a higher oil recovery (additional 3% for enriched CO2 WAG case). Recovery factor increased with decreased temperature and increased pressure, since CO2 is in its supercritical state in the range studied. Proxy models showed good performance with high determination coefficients (R), between 0.93 - 0.99. EOR studies focus on incremental oil recovery (without carbon pricing). CCUS studies maximize CO2 storage (assuming infinite CO2). We investigate the value of capturing post combustion CO2 from offshore power generation considering constrained CO2 volumes and different EOR methods without reproducing CO2. This study investigates the joint optimization of oil recovery and carbon storage bringing a unique perspective and way to decrease carbon intensity during the oil transition era.
- North America > United States (1.00)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean (1.00)
- Europe (1.00)
- Asia > Middle East (1.00)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > White Rose Field > Avalon Formation (0.99)
- (14 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
It was an area once thought to be the last untapped jewel in the hunt for hydrocarbons in the Great White North—a frontier of equal parts promise and peril. The lure of massive oil deposits lurking miles below its icy waters had operators taking a hard look at offshore Eastern Canada as far back as the late 1960s; however initial production from the area—Cohasset-Panuke off Nova Scotia—did not begin until 1992. Logistical challenges related to the remote area and the lack of existing infrastructure made bringing on new production in the region an expensive proposition. The discovered fields would need to be sizable to warrant the required investment. After decades of fits and starts, offshore Eastern Canada has yielded just a handful of major developments, with the best of those facing their own sets of challenges. Newfoundland and Labrador’s Terra Nova, the first development in North America to use floating production, storage, and offloading (FPSO) technology in a harsh-weather environment featuring sea ice and icebergs, came on line in 2002, but has been suspended for the past 3 years due to issues with the vessel. White Rose, another FPSO-based development, came on stream in late 2005 via subsea wells tied back to the SeaRose vessel. After successful completion of one expansion project in the 2010s, a further expansion—West White Rose—was planned but halted in 2020 due to unfavorable oil markets caused by the COVID-19 pandemic. The project envisaged a wellhead platform supported by a concrete gravity structure (CGS) and topsides. The platform will produce back to the SeaRose FPSO. Cenovus approved the restart of the project in May 2022. The West White Rose project is expected to increase the production life of the field by 14 years. Newfoundland and Labrador’s landmark oil production platform Hibernia became the first to produce oil in the province just over 25 years ago. As of August 2022, the project has produced more than 1.2 billion bbl of oil from the field, with almost 580 million bbl remaining proven and possible reserves. The region’s newest producer is the ExxonMobil-operated Hebron. First oil from the field was produced in November 2017—37 years after the field’s discovery by former operator Chevron. Plans to develop the field were shelved in the early 2000s only to be revived later in the decade. As a result of production interruptions and project delays, overall production trends in the region have been on the decline since the end of 2019 (Fig. 1). Off Nova Scotia, both ExxonMobil’s Sable Offshore Energy Project and Ovintiv’s (formerly Encana) Deep Panuke produced commercially for a combined 24 years (19 and 5, respectively) before each was abandoned and decommissioned in 2018. However, the outlook for offshore Eastern Canada today is somewhat brighter.
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Orphan Basin (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > White Rose Field > Avalon Formation (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Terra Nova Field (0.99)
- (6 more...)
Cenovus Energy and its partners have agreed to restart the West White Rose Project offshore Newfoundland and Labrador following a 2-year-plus period of inactivity and uncertainty related to the COVID-19 pandemic and Cenovus' merger with Husky Oil. First oil from the platform is anticipated in the first half of 2026, with peak production anticipated to reach approximately 80,000 B/D of oil, 45,000 B/D net to Cenovus, by yearend 2029. The deal to restart West White Rose was made possible by the restructuring of both the working interests in the field and its satellites as well as an amended royalty structure with the Newfoundland and Labrador government. "The joint-venture owners have worked together to significantly de-risk this project over the past 16 months," said Alex Pourbaix, Cenovus president and chief executive. "As a result, we're confident restarting West White Rose provides superior value for our shareholders compared with the option of abandonment and decommissioning. With the project about 65% complete, combined with the work done over the past 16 months to firm up cost estimates and rework the project plan, we are confident in our decision to restart this project in 2023."
- North America > Canada > Newfoundland and Labrador > Labrador (0.48)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean (0.19)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > White Rose Field > Avalon Formation (0.94)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Terra Nova Field (0.94)
Summary In recent years, the Flemish Pass Basin has been gaining momentum as an area of potential high-volume resources on the frontier of remote, deep-water offshore oil development. This simulation study utilizes three sector models representing regional, discovered reservoirs, and two tuned fluid models representing oil sampled from wells in the Flemish Pass Basin. Generally speaking, WAG is considered a late-life enhanced oil recovery (EOR) technique, while implementing WAG immediately upon first oil for secondary recovery is less common; however, may be equally or more valuable. This study aims to evaluate three secondary oil recovery methods, water flooding, gas flooding, and water-alternating-gas (WAG) flooding. Each recovery method is simulated with Schlumberger’s ECLIPSE reservoir simulator and uses a combination of three distinct reservoir geo-models and two fluid models. This study is a sensitivity analysis using geo-models that represent three discovered regions and two sampled fluids from the Flemish Pass Basin. The study is aimed at evaluating the effects of the various recovery methods over a duration of either five- or twenty-year forecast periods. Results from this study capture an inherent uncertainty by drawing from eighteen simulation cases to quantify the relative benefit of each recovery method. These results indicate that using WAG as a secondary recovery method can yield a 4% to 10% increase in recovery over water or gas flood, and that secondary WAG can extend a well pair’s production plateau by up to 80% in specific circumstances. Further observations indicate that secondary WAG in light oil reservoirs yield a ∼10% increase in recovery over secondary water or gas flooding. Using WAG in a medium oil reservoir yields a 4% to 9% increase in recovery over water flood, and a 2% to 16% increase in recovery over gas flood. In terms of geology, WAG is observed to be most valuable in ultra-high-quality reservoirs. The better the reservoir quality, the more recovery improvement. In terms of fluids, the medium oil responds best to the gas injection phase of WAG while the light oil appears to respond well to both phases. During development optimization, these trends can be accounted for in the injection cycle timing and duration for each phase. In terms of using WAG as a tertiary recovery method after a period of water or gas flooding, tertiary WAG is observed to be most beneficial in the low to medium quality reservoirs. Tertiary WAG extends the production duration and results in a ∼4% increase in recovery beyond water flooding. Study results go on to quantify the differences in water and gas breakthrough as a factor of pore volume injected (PVI) and conclusions further indicate which reservoirs are best suited for each recovery method.
- Research Report > New Finding (1.00)
- Overview (1.00)
- Geology > Geological Subdiscipline (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Terra Nova Field (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Flemish Pass Basin > Bay du Nord Field (0.99)
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.
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.
- North America > United States (1.00)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean (1.00)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hebron Field (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Terra Nova Field (0.94)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hibernia Field > Hibernia Formation (0.94)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hibernia Field > Avalon Formation (0.94)
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.
- Europe > Norway (0.35)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean (0.25)
- Europe > Russia > Barents Sea > East Barents Sea Basin > Shtokmanovskoye Field (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > White Rose Field > Avalon Formation (0.94)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Terra Nova Field (0.94)
Abstract Currently, iceberg risk mitigation at production facilities in shallower waters (80 to 120 m) on the Grand Banks off the coast of Newfoundland and Labrador is accomplished using iceberg surveillance, towing, water cannons and, in the case of floating facilities, disconnection. Future developments in deeper waters such as the Flemish Pass or the Orphan Basin may be able to utilize compliant mooring and riser systems to allow a floating facility to simply move out of the path of an approaching iceberg without disconnecting. The analysis described here shows that, using simple extrapolation of the observed iceberg trajectory, the risk mitigation provided by facility side-tracking is comparable to existing physical management techniques (iceberg towing and water cannons). Improved short-term iceberg drift forecasting would allow further risk mitigation.
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Orphan Basin (0.99)
- North America > United States > Pennsylvania > Hebron Field (0.93)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > White Rose Field > Avalon Formation (0.93)
- (2 more...)