Siliciclastic turbidite lobes and channels are known to exhibit varying degrees of architectural complexity. Understanding the elements that contribute to this complexity is the key to optimizing drilling targets, completions designs and long-term production. Several methods for 3D reservoir modelling based on seismic and electromagnetic (EM) data are available that are often complemented with outcrop, core and well log data studies. This paper explores an ultra-deep 3D EM inversion process during real-time drilling and how it can enhance the reservoir understanding beyond the existing approaches. The new generation of ultra-deep triaxial EM logging tools provide full-tensor, multi-component data with large depths of detection, allowing a range of geophysical inversion processing techniques to be implemented. A Gauss-Newton-based 3D inversion using semi-structured meshing was adapted to support real-time inversion of ultra-deep EM data while drilling. This 3D processing methodology provides more accurate imaging of the 3D architectural elements of the reservoir compared to earlier independent up-down, right-left imaging using 1D and 2D processing methods. This technology was trialed in multiple wells in the Heimdal Formation, a siliciclastic Palaeocene reservoir in the North Sea. The Heimdal Fm. sandstones are generally considered to be of excellent reservoir quality, deposited through many turbiditic pulses of variable energy. The presence of thin intra-reservoir shales, fine-grained sands, heterolithic zones and calcite-cemented intervals add architectural complexity to the reservoir and subsequently impacts the fluid flow within the sands. These features are responsible for heterogeneities that create tortuosity in the reservoir. When combined with more than a decade of production, they have caused significant localized movement of oil-water and gas-oil contacts. Ultra-deep 3D EM measurements have sensitivity to both rock and fluid properties within the EM field volume. They can, therefore, be applied to mapping both the internal reservoir structure and the oil-water contacts in the field. The enhanced imaging provided by the 3D inversion technology has allowed the interpretation of what appears to be laterally stacked turbidite channel fill deposits within a cross-axial amalgamated reservoir section. Accurate imaging of these elements has provided strong evidence of this depositional mechanism for the first time and added structural control in an area with little or no seismic signal.

New technologies, including drilling horizontal wells, have evolved to enhance hydrocarbon production. Drilling profitable horizontal wells requires using available information to minimize uncertainty and proactive geosteering techniques to maximize production by navigating within the sweet spot. When available information is based on 2D seismic and well correlation, advanced geosteering techniques are used to anticipate resistivity changes along the well trajectory, which can be used before and during the drilling process to successfully place a horizontal well. The geosteering process is performed using azimuthal wave propagation resistivity and gamma ray. For landing, an adequate stratigraphic correlation has been crucial. However, for the lateral section, geosignals and azimuthal resistivity measured at different depths of investigation from the top and base of the borehole have helped determine the section with best reservoir characteristics. This paper presents the results obtained in four horizontal wells in which proactive geosteering techniques have helped to position and navigate the wells along the sweet spot. The Lower U Sandstone (Cenomanian) at the Sacha field has become the target for horizontal wells because of the reservoir characteristics present. Offset wells located in the flanks of the structure do not show the presence of water/oil contact in well logs; however, production data proves otherwise. Likewise, the deepest resistivity readings have shown a more conductive zone in the lower portion of the reservoir, which has never been crossed with a horizontal well. After a well is closer to the latter zone, azimuthal and average deep resistivities measure less resistivity than in the upper portion, whereas gamma ray values remain constant; these results are interpreted as clean sandstone. This information helped the team make the right decisions to minimize possible water breakthrough from this zone. The horizontal well drilling process, using advanced proactive geosteering techniques, has helped determine that the flanks of the structure present a less prospective zone and contain less hydrocarbon saturation. Finally, the experience gained by the team, using these techniques and tools could help improve performance in future horizontal wells.

Geostopping is a critical operation due to wellbore-stability, well-control and HSE issues, requiring accuracy of a few meters. Reservoir boundary detection has previously been done with seismic applications and at-bit resistivity or near-bit gamma. However, seismic uncertainty can be up to 20m TVD and at-bit resistivity, and near-bit gamma requires penetrating the target. Early, accurate boundary detection, in vertical or near-vertical wells, requires technology that allows anticipation of boundaries ahead of the bit, enabling geostopping at a safe distance. A recently developed LWD ultra-deep electromagnetic (EM) tool was successfully deployed to geostop a wellbore at a target position. The system successfully predicted the top of the target formation 15m TVD ahead of the transmitter in real time, which was confirmed by gamma ray measurements. A subsequent run that drilled through the formation top confirmed the predicted top and formation resistivity. This is a game-changing technology for well construction, allowing for proactive and efficient wellbore placement. The look-ahead, ultra-deep, EM LWD tool incorporates a deep-transmitting antenna 2.8m from the bit. To achieve a real-time look-ahead capability in near-vertical wells, anisotropic resistivity measurements are incorporated into the transmitting antenna collar, providing resistivity, anisotropy, and dip around and above the transmitter antenna while drilling. The reconstructed formation profile from the anisotropy measurement is combined with the deep measurement, enabling formation determination ahead of the bit. In a favourable condition, the integrated system can detect a formation boundary 30m or more ahead of the bit. The EM tool was tested in challenging well conditions. The distance from the existing casing to the reservoir top was short and the tool was in a conductive formation (less than 0.6 Ω·m). This provided a very small depth interval in which to accumulate the necessary real-time EM measurements, and a relatively short depth of detection (DOD). Despite the suboptimal conditions, the system was able to resolve the target formation top 15m TVD ahead of the EM transmitter while drilling. This was confirmed by gamma measurements after penetrating the formation, which was used as the primary technique to geostop the wellbore. The new EM look-ahead system now offers a more proactive solution to assist operators not only to geostop a wellbore at the planned position, but also to optimize the drilling parameters prior to any unexpected geological variations. This look-ahead EM technique provides more economic and efficient drilling solutions to optimize wellbore placement compared to existing techniques. This new service makes it possible to proactively identify potential risks in vertical or low-inclination wellbores, helping to avoid drilling hazards and optimize casing shoe placement and coring operations.