Abstract
The Norwegian oil and gas industry (O&G) operates nowadays in more demanding and sensitive drilling environments while it approaches more complex reservoirs facing multiple challenges, both technically and environmentally. Not allowing shortcuts to success, clearly any technology helping to mitigate risks, increasing efficiency and reliability should be embraced. Especially as in parts the public perception towards O&G is more critical, clear corporate governance towards risk reduction by process or technology is more than adequate, assuring to comply with the general guideline of reducing critical activities and operations, such as radioactive source handling and logging with it.
A recent operation on the Norwegian Continental Shelf (NCS) is an excellent example of combining local knowledge with fit-for-purpose technology to minimize timescales and risks while improving efficiency and formation evaluation in an extended reach horizontal well construction to further develop the Marulk field in the Norwegian Sea.
This was achieved through the first global application of geosteering operations using a comprehensive real-time (RT) data acquisition governed by a sourceless "green bottom hole assembly (BHA)" in oil-based mud (OBM) environment. Including most notably a novel high-definition dual physics OBM imager and in the logging-while-drilling (LWD) arena unique accelerator-based radioisotope-free bulk density, neutron, sigma and elemental capture spectroscopy measurements, deployed along with azimuthal ultra-deep electro-magnetic (EM) reservoir mapping technology. All to provide a complete reservoir and geological description of the Cretaceous sandstones deposited in turbidite fans with moderate to good quality.
The utilization of this sourceless LWD technology as the kernel acquisition empowers the well construction to be actively steered not only by formation qualities but also by the fluid characteristics in real-time, basically providing information about the structure, rock properties and in-situ movable fluids.
The quantitative evaluation of petrophysical logs for hydrocarbon saturation had a good match with reservoir delineation and maps from deep EM measurements, confirming the net hydrocarbon bearing producible sands. Surface mud gas data was also analyzed, and its integration with petrophysical interpretation indicated the presence of heavier hydrocarbon fractions towards the toe of the well. A high-resolution sand count interpretation from dual physics borehole imaging tool confirmed the maximum net reservoir potential. The well is currently producing above the predicted rate.
The case studied is a great example where a strong interaction between professionals both in the planning and execution phase making use of available and most suitable technologies. Together with a positive mind-set and a winning attitude it resulted in a better understanding of the complexity of the reservoir and finally placing the lateral in the best evaluated reservoir facies.
