Novel Uncertainty-Based Well Test Design and GG-Consistent Interpretation Technique Delivers Results in the Arctic for Wisting Field, Norwegian Barents Sea

摘要

Well tests for smart, horizontal wells in faulted and heterogeneous reservoirs with complex fluids and uncertain contacts are nearly impossible to design and interpret with geological consistency using traditional analytical methods. Such cases lend themselves to numerical reservoir simulation, but the number of uncertain parameters and their interaction can make design difficult and the interpretation process time- consuming. We used an uncertainty-based technique for test design and interpretation with numerical models for a test in the Norwegian Barents Sea. We describe a new global sensitivity analysis methodology to determine how the interaction of multiple uncertain reservoir parameters (such as water contact depth, fault transmissibility, reservoir permeability, and anisotropy) influences the uncertainty in the pressure derivative response. With time-dependent plots of parameter sensitivity, confident decisions can be made about the test duration and the ability to address test objectives. Our methodology shows how exploration of the full range of reservoir uncertainty gives confidence in the expected flowing conditions, which are used to manage operational risks. The results of the design study, which are fully-integrated with the geological and geophysical description of the reservoir, are used during real-time monitoring and final interpretation. The full methodology was applied for the first time to a well test targeting the shallow Mid-Jurassic Sto Formation in Wisting discovery, the northernmost oil discovery situated in the Hoop area of the Barents Sea. The test design clearly indicated that water breakthrough was not expected but that gas production could not be ruled out given the range of uncertainty of the reservoir parameters. The test was monitored in real time. From the hundreds of cases produced and analyzed, matches were obtained during monitoring to give an indication of the future behavior of the well during the final buildup. This helped to dictate the test plan and buildup duration. As predicted, interpretation of the final derivative was challenging due to reservoir complexity. Traditional analytical interpretation could easily have suggested sealing faults in the near-well vicinity. However, using an amalgamated numerical model derived from the initial real-time matches and then further calibrated to the test data, we provided an interpretation of all the data obtained during the test, including matching the liquid ratios and accounting for wellbore dynamics. We not only achieved a good pressure and pressure derivative match with a model coherent with the geology, but also confirmed connected volumes.