Block 35/1 with the dry Sturlason structure, is located on the northernmost part of the Marflo Ridge in the Norwegian part of the Northern North Sea. It is separated by deep faults from the Sogn Graben to the east and the Marulk Basin to the west. The 35/1-1 well proved only minor shows of gas and oil in the well. The Sturlason structure comprises a series of upthrown fault blocks in a structurally complex area. The well-established Brent Formation carrier and reservoir sandstone has shaled out this far north and the stratigraphically deeper Lower Jurassic Statfjord Formation and Triassic Lunde Formation sandstones were, in the exploration model, suggested as both carrier beds and reservoirs. The prolific Upper Jurassic Draupne (Type II organic matter, OM) and Heather (Type II/III OM) Formation source rocks were, based on seismic data, interpreted to be absent or thin over the prospect, thus implying lateral migration for filling the structure with petroleum. Structural back-stripping suggests that part of Block 35/1 was sub-aerially exposed as an island during deposition of the Upper Jurassic source rocks. This may have impacted the quality and nature of the fringing organic material due to a more oxic environment and a greater influx of Type III organic matter. The geochemical analyses were hampered by contamination from the use of oil-based mud (C 13–23 range hydrocarbons) while drilling. Despite this, traces of true indigenous C 4–10 and C 25+ range hydrocarbon are demonstrated. These results suggest presence of an evaporative condensate and heavy oil fraction originating from a source rock related to a hypersaline carbonate depositional environment. A buoyancy-driven fluid flow study, without taking faults into account, shows the difficulty in charging the prospect and clearly suggests the presence of sealing faults. The latter are also substantiated by a separate fault-seal analysis. Traps in flanking areas could, however, receive petroleum. Gas is also interpreted to be present in shallower sediments over the eastern flank of the Sturlason structure.
The post-rift history of the North Viking Graben has been backstripped in 3D, producing a sequence of palaeobathymetric maps that culminates at the Late Jurassic synrift stage. The backstripping takes into account the three main processes which drive post-rift basin development: thermal subsidence, flexural-isostatic loading and sediment compaction. Before backstripping was performed, the Norwegian Trench, a bathymetric feature within the present-day seabed, was smoothed in order to remove associated decompaction artefacts within the backstripping results. Palaeobathymetric restorations at the top and base of the Paleocene take into account regional transient dynamic uplift, probably related to the Iceland Plume. 350 m of uplift is incorporated at the Base Tertiary (65 Ma) and 300 m at the Top Balder Formation (54 Ma), followed by rapid collapse of this same uplift. At the top of the Lower Cretaceous (98.9 Ma), very localized fault-block topography, inherited from the Jurassic rift, is predicted to have remained emergent within the basin. At the Base Cretaceous (140 Ma), the fault-block topography is much more prominent and numerous isolated footwall islands are shown to have been present. At the Late Jurassic synrift stage (155 Ma), these islands are linked to form emergent island chains along the footwalls of all of the major faults. This is the Jurassic archipelago, the islands of which were the products of synrift footwall uplift. The predicted magnitude and distribution of footwall emergence calibrates well against available well data and published stratigraphic information, providing important constraints on the reliability of the results.
Oil-based mud additives are used frequently during drilling for various purposes. The chemical compositions of these may interfere/overprint the chemical composition of hydrocarbon shows in the well and thereby complicate geochemical interpretations. This is likely to be an increasing problem as hydrocarbon findings become more subtle. It is important that the geochemist compiles a list of all additives used during drilling and obtains a sample of the pre-drill oil-based mud additives used. In the case of detailed geochemical analyses to be carried out post-drilling, it is then possible to check the influence/contamination of the additives on the hydrocarbons found.The chemical composition of a frequently used oil-based mud additive is demonstrated to have overprinted the hopane signature of an oil-slick sample in well 35/1-1, northern North Sea. This could easily have resulted in erroneous interpretations regarding age and depositional environment of the source rock of the oil. However, the steranes used for interpretation of facies are shown to be unaffected by the mud additive. A study of shows from well 35/1-1 suggested the source of these to be an atypical developed Upper Jurassic source rock, despite the hopane signature suggesting a carbonaceous Permian source. The main argument was that a Permian source would imply higher maturities than observed. The present study reveals that the hopanes in the shows are contaminated completely by the mud additive used during drilling and, hence, a Permian source is ruled out successfully. This paper demonstrates that if one biomarker group from the mud additive overprints that of the indigenous oil show this does not preclude other biomarker groups from truly representing the oil show.
A new azimuthal electromagnetic (EM) logging-while-drilling (LWD) tool has been developed with multiple tilted antennas to measure three-dimensional (3D) electromagnetic fields. Multiple field trials successfully demonstrated the ultradeep detection range of more than 200 ft (60 m) with various transmitter-to-receiver spacings and operating frequencies, providing valuable geomapping insight for large-scale reservoir development. Additionally, this paper reveals the tool's capabilities in different geosteering applications, requiring different depth of detection (DOD) ranges for landing a well, optimizing well placement in thin reservoirs, and eliminating the need for a pilot hole. This paper discusses in detail a new 3D finite-difference (FD) method to simulate realistic and complicated formation structures in three dimensions, enabling accurate formation interpretations and inversion of reservoir geology. Solving the scattered potential boundary value problem with the 3DFD numerical algorithm simulates the EM signals in this new LWD ultradeep application, and the modeling accuracy was benchmarked alongside in-house modeling codes and 3D commercial software. To accelerate the computation in the 3D modeling, sliding window, multicore parallel cloud computing, and decoupling between model pixel grid and FD simulation grid have been implemented for practical applications. Additionally, 3D modeling is used in the inversion to provide more accurate and complex reservoir determinations. In addition to inversion, the tool provides 3D azimuthal multispacing, multifrequency geosignal, and resistivity measurements. Using the inversions and the 3D azimuthal images of the geosignal and resistivities enable improved reservoir understanding and geosteering decisions for the three dimensions. This paper describes two field trials from relatively thin to thick reservoirs to establish great and flexible geosteering performance because of multispacing, multifrequency measurements, and a robust signal and inversion process to optimize wellbore placements in the reservoir.
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