Production Optimization in the Midland Basin Through Lateral Multiphase Flow Simulation

Abstract

Abstract Operators in the Permian Basin continue to advance their knowledge on unconventional horizontal wellbore constructions for optimal production. However, it is often assumed that drilling and completing the longest possible laterals is the obvious solution. Motivations to drill and complete the longest possible laterals could come from either maintaining lease agreements held by production, reducing cost, and/or reducing the surface foot-print. Wells with high tortuosity wellbores will experience liquid holdup along the lateral, thus, it might be a better solution to drill wells as uniform as possible to avoid undulations. Therefore, analyzing the effect of production over time due to various wellbore trajectories is necessary to advance our understanding of production optimization. This paper demonstrates the workflow to determine optimal lateral lengths and trajectories in the Midland Basin by studying the impact of the lateral length and trajectory on well production performance. This study couples reservoir simulation models with transient multiphase wellbore models. The reservoir simulation model is first calibrated with historical well production data. The calibrated model is then used to forecast the long-term well productivity. The long-term productivity is then used to study the impact of wellbore trajectory and lateral length on well performance. This paper details the following multiphase flow simulation cases: (1) horizontal wellbores with vertical deviations, and (2) horizontal wellbores with vertical deviations and tortuosity, combining with different lateral lengths, and reservoir and production conditions. For each case, the paper compares the impact on well production, liquid holdup, and EUR potential at different production time steps. The workflow has been applied to two University Land wells in the Midland Basin. The University Land wells pertain to one Lower Spraberry well from the Northern Midland Basin and one Wolfcamp B well from the Southern Midland Basin. At least one operator has statistically shown that uniform, toe up wells yield higher productivity and production potential. However, the study also reveals that long lateral lengths do not completely ensure proportionately more production, and wells with high tortuosities could hinder production potential. Wellbore lateral lengths and uniformity are important for production optimization to minimize liquid holdup and maximize productivity throughout the wells’ production lives. However, wellbore construction designed for holding leases and completed under time constraints could negatively impact production and limit operators’ potential for their acreage. To determine an optimal lateral wellbore length, it is necessary to study wellbore multiphase flow behavior and resulting production for unconventional horizontal wells.