DETERMINATION OF RESIDUAL OIL SATURATION IN A WATER AND GAS FLOODED GIANT OIL RESERVOIR USING CORE, CONVENTIONAL AND PULSED NEUTRON LOGS
Authors:   BP Exploration Operating Company, Davenport Mike , Guliyev Rufat ,   BP Exploration Operating Company, Sadikoglu Kasim ,   BP Exploration Operating Company, Gramin Pavel ,   BP Exploration Operating Company, Zett Adrian ,   BP Exploration Operating Company
Published: August 2021

The understanding of residual saturation in an oil field in mid-development is essential for estimating the cumulative production achievable, optimizing the future production mechanisms planned for infill targets, development of adjacent reservoir levels and optimizing the design of future facilities. The ACG (Azeri, Chirag, Gunashli) field is a giant oil field located about 120 km offshore in the South Caspian Sea, Azerbaijan. The field consists of multiple stacked clastic reservoirs including the Fasila and Balakhany formations, each with variable oil water contacts, and variable presence and fill level of gas caps. The Fasila reservoirs have been nearly fully developed. Both down flank water injection and crestal gas injection have been employed to drive oil towards producers. These two processes result in different residual oil “trapping” mechanisms which have been explored by logging and coring. Future development of overlying reservoirs can be optimized if we understand the effectiveness of these mechanisms to improve oil recovery and understand produced fluid compositions to enable facilities optimization to handle them. Established techniques to measure the residual oil saturation in a live field depletion, such as conventional open hole logging, pulsed neutron logging and direct core measurements have been employed. This paper investigates the methodology of each technique and the comparison of the magnitude and uncertainty of the saturations obtained. The sands in the ACG main reservoirs are relatively massive and high Net-to-Gross (NTG), however their clay content and distribution is quite variable leading to a range of rock types which behave differently under fluid sweep, and the presence of both intra reservoir sealing shales and lateral sand quality variations lead to a complex pattern of sweep behavior. It was considered that conventional core would be the principle measurement, with the most direct estimation of downhole fluid conditions as well as achieving all other coring objectives. Core was acquired on two pilot wells, one behind the water flood front and another behind the expanding crestal gas cap. Several innovative core analysis techniques were employed. A full conventional log suite was acquired in both wells as well as an open hole pass of a multi detector pulsed neutron log in the crestal gas swept well. The analysis of all this data has led to some interesting conclusions. Previous core flood experiments had led the team to believe gas is more efficient than water in terms of lowering residual oil saturation and reaching higher recovery factors. The new core demonstrated that such low residual oil saturations are achieved more slowly than originally thought, though it didn't change the view of efficiency of gas displacement relative to water. It is also likely that reservoir heterogeneity has had a bigger impact on the variation in residual oil saturation between layers than reservoir quality itself.