Field-Validated Simultaneous Calculations of Global Gas Split, ESP Head Degradation (PIP) and Gaseous Liquids Level Above Pump (FBHP) in Gassy-Oil Unconventional Wells

Abstract For the first time in the ESP industry, the full-physics, analytical multiphase flow modeling of the dual-flow-paths of oil, gas and water phases (via both tubing and casing) are performed using simultaneous calculations of the ESP head-degradation due to gas interference (for PIP determination), the overall downhole gas separation efficiency (for global gas split determination) and the gaseous liquids level above the pump (for FBHP determination). Field validation against two Permian gassy-oil horizontal wells is provided to demonstrate this next-generation thermo-hydraulic ESP wellbore multiphase flow modeling for digital monitoring and surveillance applications. For the past 60+ years, we have designed and modeled separate aspects of the hydraulics upstream and downstream of an operating ESP system using crude and inapplicable lab-based correlations and models. As one example, all older ESP manuals/textbooks still falsely attribute the gas volumetric flow rate fraction calculation to the actual in-situ gas volume fraction calculation at pump intake. So, to fix this we bring high-fidelity, non-linear system of equations multiphase flow modeling to the ESP arena. We perform dual-flow path modeling to showcase a deeper understanding of how the three major macroscopic hydraulic elements surrounding an ESP system interact with each other, i.e., gaseous liquids level (FBHP), PIP, and the global gas split between the tubing and casing. Favorable observed comparisons between measured PIP and its predicted values highlight the reliability and consistency of our advanced simulations. As a consequence of our detailed modeling of the well sections upstream and downstream of the ESP, we eliminate the need for reliance on older rules of thumb. Additionally, we present a new, widely applicable explicit equation relating the PIP and in-situ gas volume fraction. Another major result of this work is the ability to ascertain whether confusing ESP observations are in fact due to hydraulic effects or not (e.g., power, cables, mechanical wear etc.). This is because the modeling of head degradation due to gas interference used in this work incorporates both the in-situ gas volume fraction at pump intake and total developed head (TDH) versus total liquids rate curves at different run frequencies. Several new ESP modeling capabilities are presented in this paper: Fully non-linear, simultaneous system of equations multiphase flow calculations upstream and downstream of an ESP system along both tubing and casing flow paths, i.e., calculating PIP, liquids level above pump (FBHP) and global gas split.Detailed modeling of local flow characteristics (slug frequencies, lengths, flow patterns, etc.) all along the ESP system.A widely applicable equation for PIP as a function of in-situ gas volume fraction (not gas flowing fraction) and flow conditions.The capability to diagnose confusing ESP observations as due to multiphase flow hydraulics or something else.