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Neptune Energy began drilling operations on the Ofelia exploration well in the Norwegian sector of the North Sea. The well, 35/6-3 S, is being drilled by the Odfjell Drilling-operated semisubmersible Deepsea Yantai. The prospect is located 13 km north of the Gjøa field within the Neptune-operated PL929 License. If commercial, Ofelia could be tied back to the Neptune-operated Gjøa platform and produce at less than half the average carbon intensity of Norwegian Continental Shelf fields, according to the company. Neptune said it could potentially be developed in parallel with Hamlet (PL153).
Wintershall Dea started production from the Nova oil field in the Norwegian North Sea. The field comprises two subsea templates, one with three oil producers and one with three water injectors, tied back to the Gjøa platform. The expected recoverable gross reserves from the field are estimated at 90 million BOE, of which the majority will be oil. The operator said the completion of Nova emphasizes its strength as one of the largest subsea operators on the Norwegian Continental Shelf. "With the startup of the major project Nova, Wintershall Dea is now operating three subsea production fields in Norway," said Hugo Dijkgraaf, member of the executive board and chief technology officer.
Norwegian shelf operator Aker BP said it plans to spend at least $15.3 billion over the next 5 to 6 years in a bid to increase daily production from almost 400,000 B/D to about 525,000 B/D by 2028. The company said in an announcement that the spending will focus on 15 developments that it operates offshore Norway. Aker BP acquired some of the developments after its $14-billion acquisition of Lundin Energy's oil and gas assets in June. At least $10 billion of the capital outlay is needed to develop the NOAKA (North of Alvheim, Krafla, and Askja) project which Aker BP estimates holds 600 billion BOE at a breakeven crude price of $30/bbl. The project is set to become one of the biggest Norwegian shelf developments started in recent years and may come onstream in 2027.
The complete paper describes an all-electric system (AES) and how its implementation will simplify operating processes, reduce topside and subsea weight and cost, and lower the risk of hazardous fluids escaping into the ocean. The authors place special focus on the electrical actuators that were introduced in this project as well as the challenges faced during project execution. The Vigdis field was discovered in 1986 between the Snorre, Statfjord, and Gullfaks fields in the Tampen area of the North Sea. The development consisted of seven subsea templates and two satellite wells producing to the Snorre A (SNA) facility, which contains a dedicated processing module for Vigdis. In 2002 the plan for development and operation of the Vigdis extension was approved.
As the industry enters a new era in offshore oil and gas development, operators are looking for ways to realize returns from new investments faster and optimize utilization of their existing assets. In addition to ensuring returns-focused performance, operators are simultaneously tasked with doing so in a way that reduces the carbon footprint. The offshore industry is looking to electrification as a means to reduce the amount of carbon emitted per barrel produced while enabling greater performance. Subsea processing systems have offered electric equipment for decades. Over a 20-year period, more than 30 multiphase pumps have been successfully deployed worldwide, including the industry's first all-electric-actuated boosting system, recently installed in the Vigdis Field in Norway. Stephane Hiron, Electrification Program Manager, Schlumberger, and Ole Okland, Advisor, Subsea Processing, Equinor, will discuss how electrification and subsea processing are helping offshore operators drive greater performance, sustainably.
Abstract Drilling horizontal wells in complex formations is always a challenging task. The development of deep and ultra-deep azimuthal resistivity tools has largely improved the accuracy of the wellbore placement in the target zone. The enhanced imaging provided by the stochastic inversion of the azimuthal resistivity data can be applied for mapping both the internal reservoir structure and fluid contacts in the field. Major oil and gas service companies provide the operator with azimuthal resistivity tools and develop their own algorithms for resistivity data processing. Commonly services companies process azimuthal resistivity data internally. We have developed a vendor-independent stochastic inversion method that is applicable to almost any deep-azimuthal resistivity tools. This module allows operators to carry out real-time geosteering, as well as pre-job and post-job data analyses independently from the service company. This paper demonstrates the examples of the azimuthal resistivity data interpretation using synthetic data and actual data from the well offshore Norway. Calculated inversion models, based on actual data, allowed mapping of the oil-water contact and discontinuities in the reservoir that take place at the resistivity contrast boundaries. The application of this technology can increase the percentage of the horizontal well in the pay zone while letting the operator cut drilling costs through optimizing bottom hole assembly and use more advanced interpretation practices. Introduction Exhaustion of fossil energy reserves leads to the constant advancement of the drilling well targets and the increase of the number of infill wells being drilled in conventional reservoirs. The high cost and complexity of the lateral wells require thorough geosteering workflows to achieve the well target. Efficient or proactive geosteering methods require the application of the Log While Drilling (LWD) tools that could detect an approaching reservoir boundary in advance of crossing it while drilling, ultimately allowing the directional drillers to adjust the current well trajectory to stay within the well target zone. Deep and Ultra Deep Resistivity (hereinafter DAR and UDAR, respectively) LWD tools are commonly applied to achieve this aim. Modern azimuthal resistivity tools represent top-tier technological equipment that provide an abundance of multi-spacing, multi-frequency, and multi-component resistivity data and have a complex configuration. Inversion of the tool's response is the common method to interpret azimuthal resistivity data. Traditionally the tools are being provided to the operators by the service companies along with the interpretation results leaving the operators with limited opportunities to process azimuthal resistivity data. Moreover, resistivity LWD tools specifications vary significantly from vendor to vendor, and every vendor has developed their own algorithm to calculate the inversion. In order to process different kinds of azimuthal resistivity data on the operator side, we have developed the unified vendor-independent algorithm and consequently the software module that was described in detail by Sviridov et al., 2021. The goal of the current paper is to show the implementation of this algorithm on the resistivity responses from different propagation resistivity azimuthal tools on synthetic data and the real data from the Troll field located in the North Sea, Norway.
Kumar, Devendra (Schlumberger Norge AS) | Aleixo, Renee (Neptune Energy Norge) | Van der Vliet, Rutger (Neptune Energy Norge) | Clerc, Sylvain (Neptune Energy Norge) | Castagnoli, Joao Paulo (Schlumberger Norge AS) | Sanchez, Diego Munoz (Schlumberger Norge AS) | Hassan, Haitham Khalil (Schlumberger Norge AS)
Abstract On the Norwegian continental shelf (NCS), shale instability is a well-known challenge in the Rødby and Sola formations of Early Cretaceous, leading to significant non-productive time (NPT) for well construction operations. Therefore, the Duva field development campaign utilized real-time drilling geomechanics (RTDG) support to assess wellbore stability while drilling. The challenges for planning RTDG, including limited offset well log data from the Agat reservoir section, a long horizontal section through imprecisely located depths of the interbedded shales, and acoustic anisotropy added to the uncertainty borehole stability model forecasts. The paper demonstrates RTDG methodology for horizontal wells in the absence of logging-while-drilling (LWD) sonic logs considering a petrophysics based approach using gamma ray, resistivity, and density logs. During execution of the RTDG the gamma ray (GR) was used to compute the angle of internal friction of rocks, and to distinguish between grain supported and clay supported lithologies (sand-shale). Drilling geomechanics support using the LWD data successfully updated the wellbore stability model, validated by the LWD (ultra-sonic and density) caliper log, capturing the onset of shear failure in real-time. The updated model indicated a slightly higher shear failure trend (1.24 to 1.26 SG) in shale intervals compared with sandy intervals, in-line with the traces of cavings observed while drilling. To prevent the wellbore from failure in the interbedded shales within Agat formation a mud density of 1.26 SG was forecasted in the horizontal section compared to 1.20 SG from vertical wells. The updated model guided the correct mud weight, which gradually increased to 1.30 SG for optimizing drilling operations in horizontal sections and enabled the drilling team to achieve well construction objectives. Introduction The Duva field is situated in the northern North Sea, East of the Gjøa field and 30 km west of the Norwegian coastline and is located on the Måløy Slope between the Gjøa Fault Zone to the west and the Øygarden Fault Complex to the east (Fig. 1). The prospect discovered in 2016, consisted of gas with an oil leg.
Kolbjørnsen, Odd (Lundin Energy / University of Oslo) | Hammer, Erik (Lundin Energy) | Pruno, Stefano (Stratum Reservoir) | Wellsbury, Peter (Rockwash Geodata) | Kusak, Malgorzata (The Norwegian Oil and Gas Association)
Abstract The Released Wells Initiative is a joint industry project administrated and organized by the Norwegian Oil and Gas Association and funded by the majority of companies operating on the Norwegian Continental Shelf (NCS). The project is unique on a worldwide scale, as it will analyze every drill cutting sample from every exploration and appraisal well in the Norwegian national archive. The archive contains about 700,000 samples of unwashed ditch cuttings from more than 1900 wells. Each sample is washed and dried according to a consistent automated procedure, and preserved both in a digital format, using high-resolution white light (WL) and UV (UV) photography and X Ray Fluorescence (XRF) analysis. The cleaned samples from all the wells are available for future analysis. The eighty most recently released wells were subjected to an extended suite of measurements: X-Ray Diffraction (XRD), automated mineralogy (QEMSCAN), Infrared spectroscopy (IRS) and total organic carbon measurement (TOC). We present details of the study design, sample preparation and analysis process. The extended set of observations are not selected based on the results of other measurements. The data set is therefore an independent source of information void of conditional dependencies between measurement types. We discuss the possibilities that the dataset offers and present results from analysis that have been made. In a set of repeated measurements, we find a high degree of consistency. The correlation between the two samples sets is found to be above 0.95 for XRF, XRD, QEMSCAN, IRS, and for the average photon count in white light images. For the UV images the correlation is lower, however typically these UV images have a low photon count. In a case example we show how the XRF data contribute to understanding the provenance of the Brent Group in a region of the North Sea. We show how the study design enables methods of advanced analytics, where the extended measurement set can be used to train predictive models. In our data analysis we utilize boosting threes to predict e.g., XRD mineralogy from XRF data. We report an out of sample error of 4.5%-6.9%, for quartz, total clay and carbonates. We further discuss opportunities and challenges with the dataset. The dataset provides opportunities to aid interpretation and future decision making, with impacts on drilling, completion, geological interpretation, modelling, production and future projects (including carbon capture and storage). The project is also unique in terms of openness as the complete data set will be released to the public in 2024.