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Equinor struck oil in Production License 554 with a pair of wells at its Garantiana West prospect. Exploration wells 34/6‑5 S and 34/6-5 ST2 were drilled some 10 km north-east of the Visund field, with the former encountering a total oil column of 86 m in the Cook formation. The latter well encountered sandstones in the Nansen formation, but did not encounter commercial hydrocarbons. Recoverable resources are estimated at between 8 and 23 million BOE. "This is the first Equinor-operated well in the production license, and the fifth discovery on the Norwegian continental shelf this year," said Rune Nedregaard, senior vice president, exploration and production south. "The discovery is in line with our roadmap of exploring near existing infrastructure in order to increase the commerciality."
Interwell tracer tests are widely used. This article reviews some of the studies reported in open literature. The selection introduces different problems that have been addressed, but the original papers should be studied to obtain a more detailed description of the programs. The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page.
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.
An equipment failure onboard Northern Ocean semisubmersible West Mira resulted in production equipment descending to the seabed. The rig owner said no one was injured and the well at the location was secured "with three barriers in place." The unit was in the process of lowering the equipment on the Wintershall-operated Nova field. "While lowering a x-mas tree from West Mira, the winch wire snapped when the tree was five meters below the sea surface. The x-mas tree sunk to the seafloor 368 meters below water level. Eight people were working in the area of the rig where the incident occurred in safe distance from moving equipment," said Wintershall.
Equinor and its partners have completed the initial phase of construction on the concrete spar substructures that will host the turbines for the 88-MW Hywind Tampen floating wind power project. With work completed on the first 20 m of 11 substructures at Aker Solutions' yard at Stord, the project now moves to the deepwater site at Dommersnes where the substructures will be completed to a total length of 107.5 m. This is the first concrete slipforming for an offshore project on the Norwegian continental shelf since the Troll A platform was delivered in 1995. Hywind Tampen will be the world's largest floating offshore wind farm and the world's first to power offshore oil and gas platforms. It is also the first floating wind project from Equinor using concrete technology.
Kozlowski, Maciej (Halliburton) | Chakraborty, Diptaroop (Halliburton) | Jambunathan, Venkat (Halliburton) | Lowrey, Peyton (Halliburton) | Balliet, Ron (Halliburton) | Engelman, Bob (Halliburton) | Ånensen, Katrine Ropstad (Aker BP) | Kotwicki, Artur (Aker BP) | Johansen, Yngve Bolstad (Aker BP)
The Alvheim Field in the Norwegian North Sea was discovered in 1998. Two wells were drilled in 2018 in the Gekko structure to confirm oil column height and to evaluate reservoir quality in the Heimdal Formation. A comprehensive wireline logging program, including NMR and formation testing, was optimized to reduce formation evaluation uncertainty. Evaluating fluid properties, oil column height, and reservoir quality were primary objectives. Well A was first drilled on the south of the structure, followed by Well B on the north of the structure. Reservoir quality encountered in both wells was very good, and a project to develop these resources is currently in the selection phase. Formation evaluation uncertainty encompassing pore geometry distribution, permeability, reservoir quality, and hydrocarbon identification are mitigated by studying the nuclear magnetic resonance (NMR) log response. NMR fluid typing has been widely used in the oil industry since the 1990s. NMR fluid typing today is a combination of the contrast of spin relaxation time T1, the spin-spin relaxation time T2 (T1T2), and the diffusivity (T2D) of formation fluids (Chen et al., 2016). NMR fluid typing can be obtained from a continuous log and/or stationary log measurements. This paper showcases excellent, textbook-quality NMR data, as well as the integration of NMR data in the petrophysical workflow. High-confidence fluid properties and fluid contacts are determined. This paper also highlights a comparison of NMR data acquired in stationary vs. continuous depth-based log modes in both wells. The continuous log data quality is equivalent to stationary data, implying continuous log data quality is sufficient for reliable NMR fluid properties evaluation without depending on time-consuming stationary NMR measurements. Reducing logging operations rig time is very advantageous in the North Sea, where drilling rig operations cost is high, and enhanced rig time management is constantly required.
The Norwegian Petroleum Directorate (NPD) on Wednesday announced the biggest discovery yet this year on the Norwegian Continental Shelf, after project operator, Equinor Energy AS, and partners Vår Energi, Idemitsu Petroleum, and Neptune Energy completed the drilling of two wildcat wells. The wildcats, wells 31/2-22 S and 31/2-22 A, in the Blasto prospect were drilled about 3 km southwest of the Fram field, 11 km northwest of the Troll field, and 120 km northwest of Bergen. Preliminary estimates place the size of the discovery at 75–120 million barrels of recoverable oil equivalent. "The discovery revitalizes one of the most mature areas on the Norwegian Continental Shelf. With discoveries in four of four prospects in the Fram area during the past 18 months, we have proven volumes that in total will create considerable value for society," says Nick Ashton, Equinor's senior vice president for exploration in Norway.
Hussain, Sajjad (Schlumberger) | Dahroug, Mohamed Saher (Schlumberger) | Mikalsen, Belinda (Schlumberger) | Christensen, Karianne Holen (Schlumberger) | Nketah, Daniel Ndubuisi (Schlumberger) | Monterrosa, Leida (K&M Technology Group) | Van Aerssen, Mark (Wintershall Dea) | Angell-Olsen, Frode (Wintershall Dea) | Midttun, Mons (Wintershall Dea) | Fjeldsbø, David (Odfjell Drilling) | Ritchie, Graham Martin
Abstract Drilling a nine km (Kilometers) extreme ERD (Extended Reach Drilling) well by a rig which was initially designed for six km and on a platform that did not provide any empty well slot posed a challenge to the Brage asset team. The well (A-36 A/B) was planned with an ambitious slot recovery operation removing all casing strings to surface to allow for a 24-inch sidetrack. Due to unexpected challenges during the slot recovery only a 19-m window between the 28-in conductor shoe (at 315-m MD) and the old 13 3/8-in casing stump was available. A very successful kick-off using a mud motor and Gyro-While-Drilling bottomhole assembly (BHA) was performed. An RSS (Rotary Steerable System) BHA was used to drill the rest of the section Both "push the bit" and "point the bit" RSS technologies were the key enablers in drilling long sections and helping to deploy casing strings. The well was successfully geosteered through two reservoirs, including a new reservoir landing strategy, adding valuable extra reservoir meters. The reservoir Mapping-While-Drilling and Magnetic Resonance-While-Drilling service helped to navigate in challenging reservoirs maximizing reservoir exposure. Advanced polyglycol Water-Based Mud system was utilized in 24-in section followed by advanced Oil-Based Mud (OBM), and Low Solids OBM systems enabled drilling this extreme ERD well. An upgraded Cuttings collection and transportation system meeting ERD requirements and offshore slop water treatment system also played key role in drilling optimization. Real-time monitoring of critical well construction operations was performed using specialized technologies. Optimized Viscous Reactive Pill (VRP) was successfully used for the first time in North Sea to provide cement plug base at deeper depths (7200-m MD) resulting in a successful kick-off using "point the bit" RSS systems. An ERD specialist subsidiary of the service company was involved in ERD design verification and training of offshore personnel. Outstanding equipment reliability of surface equipment and downhole tools enabled shoe-to shoe drilling of these sections. The OneTeam culture combined with the main service provider integrated solutions, and an open-minded and brave approach led to drilling longest well in this brownfield ever. It was completed 32-days ahead of plan with all objectives met. The deep lower screen completion was successfully deployed, and the well is producing as expected. This 9,023-m MD well is the longest Offshore well drilled by the Operator and 2nd longest drilled by the Operator ever.
When used for running sand-control screens, low-solids, oil-based completion fluids (LSOBCF) maintain reservoir wellbore stability and integrity while minimizing the potential risks of losses, screen plugging, completion damage, and productivity impairment. Until now, using LSOBCF as a screen running fluid has been limited by fluid density. The complete paper discusses the design, qualification, and first deployment of an LSOBCF that incorporates a newly developed, high-density brine as the internal phase to extend the density limit. This new field's well forms part of the greater Alvheim area located in the central part of the North Sea, close to the UK sector. The formations discussed present excellent reservoir characteristics but also significant drilling challenges.
The Norwegian Petroleum Directorate has granted Equinor a drilling permit for wildcat well 31/11-1 S in the North Sea offshore Norway, 62 km south of the Troll field. The drilling program is the first exploration well to be drilled in production license 785 S, awarded on 6 February 2015 (APA 2014). Operator Equinor and Total E&P Norge are 50/50 partners in the license, which consists of parts of Blocks 26/2 and 31/11. In January, Equinor exercised one additional well for the Deepsea Atlantic rig in addition to the two new wells it exercised for the rig in December 2020. The work will start in the second quarter of this year.