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Strong storms can trigger steep, breaking waves that slam into platform and wind turbines with tremendous force. Scientists at the Norwegian University of Science and Technology (NTNU) and SINTEF are studying the behavior of offshore structures subjected to these kinds of waves. Their goal is to increase safety at sea. The force of waves slamming into offshore rigs, wind turbine pillars, ships or other offshore structures can do an enormous amount of damage. One of the fundamental--and unresolved--problems with designing these kinds of large structures is being able to predict exactly how they will react to extreme stresses.
An exploration well drilled by Wintershall on its Dvalin North prospect in the Norwegian Sea has encountered a significant gas reservoir. The discovery at Dvalin North is estimated to hold to hold 33–70 million BOE and is just 12 km north of the company's operated Dvalin field and 65 km north of the operated Maria field. The well also encountered hydrocarbons in two shallower secondary targets, with a combined resource estimate of 38–87 million BOE, making the potential for the field in excess of 150 million BOE. The well, drilled by the Deepsea Aberdeen rig, encountered gas, condensate, and oil columns of 33 m and 114 m in the Cretaceous Lysing and Lange formations, respectively. In the primary target in the Garn Formation, the well found a gas column of 85 m.
Equinor and partners Total E&P Norge AS and Vår Energi AS have struck oil and gas in a new segment belonging to the Tyrihans field in the Norwegian Sea. Exploration well 6407/1-A-3 BH in production license 073 was drilled from subsea template A at Tyrihans North. The well was drilled to a measured depth of 5332 m by semisubmersible drilling rig Transocean Norge and struck a gas column of about 43 m and an oil column of about 15 m in the Ile formation, including about 76 m of moderate to good reservoir quality sandstone. In the Tilje formation, moderate to good quality water-bearing reservoir was struck. The Tyrihans field is in the middle of the Norwegian Sea, some 25 km southeast of the Åsgard field and 220 km northwest of Trondheim.
Abstract The Cretaceous Cape Vulture prospect (Norwegian Sea, Norway) consisted of three Cretaceous sand levels: Cape Vulture Lower, Main, and Upper. The prospect was drilled in 2017, targeting seismic amplitude anomalies that represented a combination of reservoir facies and hydrocarbons. As the first well (6608/10-17S) proved hydrocarbons down to base reservoir in Cape Vulture Main and Upper, an appraisal well with two sidetracks were planned and drilled to determine the reservoir development, pressure communication and oil-water contact. A good understanding of the lateral variation within the reservoir was of importance to the technical economical evaluation of the discovery. The appraisal wells planned for a comprehensive coring and logging program. The main objectives were to reduce the uncertainty of estimated in place volumes by establishing the depth of the hydrocarbon-water contact, prove lateral pressure communication within each reservoir level, reduce the uncertainty of lateral and vertical reservoir distribution and quality, reduce the uncertainty of hydrocarbon saturation and understand the relationship between seismic amplitude anomalies and subsurface properties / fluids. The logging program included triaxial resistivity, nuclear spectroscopy, electrical images, nuclear magnetic resonance (NMR) complementing triple combo, followed by formation pressure measurements, and fluid sampling. The presence of clay minerals in varying amounts within the reservoirs depresses the resistivity measurement and leads to underestimation of the hydrocarbon saturation when using conventional Archie’s equation - a common petrophysical challenge in such conditions. The hydrocarbon saturation is an important parameter when calculating reserves and estimating whether a discovery is of commercial value. Hence, reducing the uncertainty span on hydrocarbon saturation (total and effective) and estimating the net pay thickness is critical. Using core data and advanced down-hole measurements to optimize a resistivity-based saturation model can reduce the uncertainty of the saturation estimates. Here we document the petrophysical evaluation of the data acquired, assessing heterolithic low resistivity pay with wireline log measurements combined with core data. Focus on the coring strategy, recommendations on sampling intervals for the core analysis, and key logging measurement requirements. The results show substantial improvements in the understanding of the hydrocarbon saturation, ultimately increasing in-place volume estimates. The integrated analysis, including NMR measurements, helps to delineate the fluid contacts, further reducing the uncertainty on the recoverable net pay thickness. The core data validate the independent log-based laminated sand analysis. This illustrates how an integrated approach combining core measurements, logs, and formation testing provide an accurate evaluation of low resistivity pay reservoirs, reducing the uncertainty in the technical economical evaluation.
Abstract During well planning, drillers and petrophysicists have different principle objectives. The petrophysicist’s aim is to acquire critical well data, but this can lead to increased operational risk. The driller is focused on optimizing the well design, which can result in compromised data quality. In extreme cases, the impact of well design on petrophysical data can lead to erroneous post-well results that impact the entire value-chain assessment and decision making toward field development. In this paper, we present a case study from a syn-rift, Upper Jurassic reservoir in the Norwegian Sea where well design significantly impacted reservoir characterization. Three wells (exploration, appraisal, and geopilot) are compared in order to demonstrate the impact of overbalanced drilling on well data from both logs and core. Implications for reservoir quality assessment, volume estimates, and the errors introduced into both a static geomodel and dynamic reservoir simulation are discussed. This case study highlights the importance of optimizing well design for petrophysical data collection and demonstrates the potential for value creation. Extensive data collection was initially carried out in both exploration and appraisal wells, including full sets of logging while drilling (LWD), wireline logging, fluid sampling, and extensive coring. Both wells were drilled with considerable overbalanced mud weights due to the risk of overpressured reservoirs in the region. The log data was subsequently corrected for significant mud-filtration invasion, with calibration to core measurements guiding the interpretation. Geological and reservoir models were built based on results from the two wells, and development wells were planned accordingly. A thorough investigation of core material raised suspicion that there could also be a significant adverse effect of core properties resulting from overbalanced drilling. The implications were so significant for the reservoir volume that a strategic decision was made to drill a geopilot well close to the initial exploration well, prior to field development drilling. The well was drilled six years after the initial exploration phase with considerably lower overbalance. Extensive well data, including one core, were acquired. The recovered core was crucial in order to compare the reservoir properties for comparable facies between all three wells. The results from the core demonstrate distinctly different rock quality characteristics, especially at the high end of the reservoir quality spectrum. Results of the core study confirmed the initial hypothesis that overbalanced drilling had significantly impacted the properties of the core as well as the well logs. The study concluded that the updated reservoir model properties would significantly increase the in-place volumes compared to the pre-geopilot estimate. This study shows how well design adversely affected petrophysical measurements and how errors in these data compromised geological and reservoir models, leading to a suboptimal field development plan that eroded significant value. This example provides a case study that can be used to improve the well design so that petrophysicists and drillers can both be part of the same value creation result. Future work will include further laboratory investigations on the effects of high overbalanced drilling on core and possible “root causes” for compromised core integrity.
The Norwegian Petroleum Directorate granted Wintershall Dea Norge a drilling permit for well 6406/3-10 A to spud a follow-up probe to a discovery made in April 2020. The Bergknapp appraisal will be drilled from the Odjfell semisubmersible Deepsea Aberdeen once the rig has concluded the drilling of wildcat well 6507/4-2 S for Wintershall in production license 211. The Bergknapp appraisal will be drilled about 8 km west of the Maria field in the Norwegian Sea. Preliminary estimates of the Bergknapp discovery indicate it could hold between 26–97 million BOE. The find is in production license 836 S where Wintershall is the operator and holds a 40% stake.
Soares, Ricardo Vasconcellos (NORCE Norwegian Research Centre and University of Bergen (Corresponding author) | Luo, Xiaodong (email: email@example.com)) | Evensen, Geir (NORCE Norwegian Research Centre) | Bhakta, Tuhin (NORCE Norwegian Research Centre and Nansen Environmental and Remote Sensing Center (NERSC))
Summary In applications of ensemble-based history matching, it is common to conduct Kalman gain or covariance localization to mitigate spurious correlations and excessive variability reduction resulting from the use of relatively small ensembles. Another alternative strategy not very well explored in reservoir applications is to apply a local analysis scheme, which consists of defining a smaller group of local model variables and observed data (observations), and perform history matching within each group individually. This work aims to demonstrate the practical advantages of a new local analysis scheme over the Kalman gain localization in a 4D seismic history-matching problem that involves big seismic data sets. In the proposed local analysis scheme, we use a correlation-based adaptive data-selection strategy to choose observations for the update of each group of local model variables. Compared to the Kalman gain localization scheme, the proposed local analysis scheme has an improved capacity in handling big models and big data sets, especially in terms of computer memory required to store relevant matrices involved in ensemble-based history-matching algorithms. In addition, we show that despite the need for a higher computational cost to perform model update per iteration step, the proposed local analysis scheme makes the ensemble-based history-matching algorithm converge faster, rendering the same level of data mismatch values at a faster pace. Meanwhile, with the same numbers of iteration steps, the ensemble-based history-matching algorithm equipped with the proposed local analysis scheme tends to yield better qualities for the estimated reservoir models than that with a Kalman gain localization scheme. As such, the proposed adaptive local analysis scheme has the potential of facilitating wider applications of ensemble-based algorithms to practical large-scale history-matching problems.
Abstract There are 26 sedimentary basins in India divided into four categories on the basis of hydrocarbon prospectivity. A total of about 3.14 million square kilometres area is covered by these sedimentary basins which includes both onshore and offshore. One of the most prominent category-1 (commercially producing) basin of India is Krishna Godavari basin with an estimated hydrocarbon potential of about 1130 million metric tonnes. It is is formed by the extensive deltaic plain formed by the two large east coast rivers, Krishna and Godavari. It covers an area of 15000 square kilometres onshore and about 25000 square kilometrs offshore, upto a water depth of about 1000m (National Data Repository, DGH-MoPNG, GOI). It is believed that India relies heavily on KG basin for its energy security. However, one of the major challenges being faced in the KG basin offshore field development is Flow Assurance. Since most of the fields offshore KG basin are in deepwater setting, high pressure and low temperature conditions aggravate flow assurance problems. Flow assurance is identified as a significant deepwater offshore development challenges and hence has emerged as a prominent discipline in the oil and gas industry. There are several definitions of Flow Assurance, one of the most common of which is: Flow Assurance is the analysis of thermal, hydraulic and fluid related threats to flow and product quality and their mitigation using equipment, chemicals and procedure (Makogon T.Y., 2019). It can be understood as an all-encompassing holistic approach of fluid flow from the reservoir to point of sale with an integrated perspective of asset development. In simple terms flow assurance aims to ensure fluid flow irrespective of flow trajectory, fluid chemistry and environmental conditions (Brown L.D., 2002). It has become increasingly important in recent times as the industry has turned to deepwater resources for energy sources. There are multiple examples where the proper utilization of Flow Assurance technology has saved billions of dollars for oil and gas companies. Norske Shell saved approximately 30 billion NOK in the Troll field by resorting to direct electrical heating of produced fluids. The same was utilized by Italian company ENI for its Goliath development and by BP in its Skarv field (Makogon T.Y., 2019). This paper describes a comprehensive workflow to identify and mitigate flow assurance risks for the deepwater block in KG basin.
Equinor and its partners will proceed with the NOK 1.4-billion Åsgard B low-pressure project in the Norwegian Sea. The partners, which include Petoro AS, Vår Energi AS, and Total E&P Norge AS, awarded a NOK 800-million engineering, procurement, construction, and installation contract to Aker Solutions to conduct the work. The contractor scooped the front-end engineering and design work for the project back in December 2019. The selected concept is a modification of the platform to reduce inlet pressure by replacing the reinjection compressors and rebuilding parts of the processing facility. "We're pleased that the Åsgard owners have given their go-ahead for the low-pressure project," said Geir Tungesvik, Equinor's senior vice president for projects.
ConocoPhillips announced today that it has made a new oil discovery offshore Norway. Located about 14 miles north-northeast of the Heidrun Field in the Norwegian Sea, the newly tapped Slagugle prospect is estimated to hold a recoverable volume of 75 to 200 million BOE, according to ConocoPhillips. The discovery well was drilled in 1,165 ft of water to a total depth of 7,149 ft by the Leiv Eiriksson drilling rig. ConocoPhillips is the operator of the prospect with an 80% stake. Norway-based Pandion Energy is the license partner with a 20% working interest.