Abstract
When drilling in mature reservoirs, conventional formation evaluation is not enough. Characterizing these formations properly becomes essential in ensuring longer and sustainable oil producing boreholes. Understanding the geological complexities, permeability drivers and pressure potential is important since they control fluid flow. This work presents the first ever case study from the Abu Dhabi Carbonates where an innovative multi-measurement borehole imager was deployed, providing a comprehensive and integrated formation evaluation not used before in the industry.
A campaign of five extended reach wells was planned in one field offshore of Abu Dhabi. A 15-ft long borehole imager was added to the drilling bottom-hole assembly (BHA) to acquire apparent resistivity and ultrasonic images simultaneously to characterize the often not-observed geological features that control reservoir properties. These complementing images helped in characterizing vug distributions, bioturbation, faults and dissolution seams in addition to the bed boundaries. Around 13,000ft of lateral was logged while drilling, using this data in real time in oil-based mud to target the most permeable and thinnest layers for the first time in the middle east.
Core analysis had defined the 2ft thick most permeable layer of the reservoir where the lateral needed to be exposed for better production. Multi bed boundary detection for waterfront identification was integrated with mobility pretests points along with surface mud gas fluid sampling for Gas Oil Ratio (GOR) determination and the innovative dual imager. For the first time, acquiring a high resolution apparent resistivity image in real time in OBM, made the restriction of placing the lateral in a thin layer possible. Findings redefined the understanding of the geology and the drivers behind the fluid flow within this reservoir. With the new high definition ultrasonic image, vugs that tend to control the permeability in many facies were discovered. This led to the computation of a vug density curve derived from the images which characterized the key-intervals. Qualitative trends were validated with mobility estimated from independent LWD measurement, providing much-needed confidence in the new imaging technology. Completion was re-designed based on the new brought-in information. Sections were isolated based on the high-water saturation zones mapped with the multi bed boundary detection technology and higher gas oil ratio from surface fluid sampling. Completion was then optimized around high vug density/ mobility intervals.
This first-ever case study provides a plethora of new information for model update whether it be the geology or the reservoir model that was hitherto unavailable for some reservoirs where development wells were drilled with OBM. For challenging wells planned in highly constrained environments from structure, petrophysics and reservoir maturity aspects, this new technology cleverly combined with others, opened the door to boost production from otherwise, a highly matured reservoir.
