Fractional Flow Modeling and Monitoring for the Assessment of Commingled Fluid Production Across Thinly Laminated Formations
Thinly laminated fluvial and turbidite sediments are valuable and commonplace assets in subsurface fluid exploration. Unlike conventional reservoirs, wells intersecting these formations produce from multiple layers simultaneously at different rates. Substantial differences in petrophysical properties between sandstone and shale layers, coupled with their minimal thicknesses, pose challenges for assessing fluid-transport properties. Understanding the relative contribution of each layer to total borehole inflow, along with monitoring production changes over time, is critical for accurate production allocation and diagnosing well production performance. We address the latter challenges by developing a new method to simulate multilayered commingled production in thinly laminated formations and to estimate changes in vertical fractional flow. Production contribution from each layer within a stack of layers can be estimated through either a production logging tool (PLT), which measures local flow rates, or through geochemical methods that analyze variations in hydrocarbon compositions. Numerous analytical, semi-analytical, and numerical methods exist to evaluate multilayered commingled production. In this study, we employ the UTAPWeLS (University of Texas at Austin Petrophysical and Well-Log Simulator) fluid flow simulator to investigate commingled production in thinly laminated formations, calculate fractional flow rates for each layer, and generate PLT-like logs. To ensure the accuracy and reliability of the method, the simulator is validated against formation-testing measurements, with simulated data showing strong agreement with the field data. The shape and magnitude of pressure changes are preserved, with differences of less than 1%. Following validation, the UTAPWeLS fluid flow simulator is used to predict the fractional flow of water in thinly laminated field cases. Results indicate variations in water and hydrocarbon flow rates due to differences in petrophysical and fluid flow properties across the formation. In the absence of PLT logs or when layer thickness falls below tool resolution, our method provides valuable insights into the production behavior of thinly laminated formations, even when layers are thinner than 0.1 m. However, the accuracy of the results depends on the quality and availability of core measurements, particularly capillary pressure and relative permeability data.