Fluid Heterogeneity in Tight Unconventional Reservoirs

Abstract

This thesis deals primarily with layer-wise fluid heterogeneity in tight unconventional reservoirs. The industry has almost exclusively assumed that the fluid system within a well-box, i.e. contributing production to a single well, is homogeneous in composition. From the open literature in the field of geochemistry, some data-based evidence is given to indicate the presence of possible vertical fluid heterogeneity for individual parasequences, also on a well scale. This led us to investigate the impact of layer-wise vertical fluid heterogeneity, both separately and with petrophysical heterogeneity, on a well-box scale during depletion performance. The assessment provided in last four of the five papers constituting this thesis, and presented at various conferences, provide the industry with alternative in-situ fluid models that impact the production forecast of wells in tight unconventional reservoirs. A numerical reservoir simulation model of a single horizontal well with multiple planar fractures is used to study many two-layer systems. The PVT formulation used is mostly black oil, though some simulations were run using an EOS PVT formulation that verified the validity of using a black-oil PVT model. The well simulation model was initialized with distinct fluid (in-situ solution GOR) in each layer, but the fluid being homogenous laterally within each layer. The model was populated with lateral heterogenous or homogenous petrophysical properties φ and k (that were correlated by the relation aφb, with b=1 or b=3). The final paper applies the observations and results from the previous papers that were theoretical case studies to study a wide range of plausible systems with fluid and rock heterogeneities. This last paper uses field data from the Eagle Ford basin for some 30 wells, including a detailed assessment of fluid heterogeneity and its impact on history match performance for one of the wells.