Pushing the Limits of Damage Identification Through the Combined Use of Coiled Tubing, Distributed Sensing, and Advanced Simulations: A Success Story from Japan

Abstract

The success of water-conformance operations often depends on clear identification of the water-production mechanism. Such an assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed-temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water-bearing zones in an onshore well in Japan. The subject well experienced unexpected contamination of oil-based mud (OBM) and completion brine, which generated tight emulsions in the wellbore during the completion phase. Despite a thorough cleanout and perforations, severe damage was observed and mostly water was produced. With the presence of persistent damage in the wellbore preventing any logging-tool use, DTS was selected as main diagnostic method, with the fiber optics being deployed with CT to ensure full coverage of the interval. Acquired temperature surveys were processed and matched with simulated profiles, which tested various scenarios of damage. Ultimately, results were used to drive the design of remedial actions. The following operational sequence was implemented: temperature-baseline measurements (6 hours), brine bullheading through the CT/tubing annulus at 0.2 bbl/min (22 hours), and shut-in (6 hours) for warmback. The long injection stage was required to ensure that enough fluid was being injected across the entire interval while keeping the downhole pressure at less than the fracturing pressure. Real-time DTS data during pumping and warmback indicated the presence of a main intake zone in the middle of the interval. Below that section, only marginal temperature changes were observed, which might be a direct consequence of the low-injection-rate limitation. Post-job processing using numerical temperature simulation was performed to complement that analysis and quantify intake along the well. Temperature inversion against the DTS response was conducted independently using two different simulators, both of which yielded similar profiles, confirming the soundness of this approach. The results supported the presence of a larger intake in the middle interval and also showed that the bottom zone most likely took some fluid. Complementary information eventually pointed to the larger-intake interval being the primary water-bearing zone. This analysis led to the selection of the remedial actions to be performed in damaged oil zones. This study demonstrates how integrated use of data from design to job execution to interpretation can change the perception of a well and how DTS can be a viable alternative to damage and water-production diagnostics in some extreme conditions when production-logging tools (PLTs) cannot be used. Results of the DTS quantitative analysis provided local damage profiles along the well, which were critical to the subsequent planning of remedial activities.