The continually evolving water management practices of liquids-rich tight oil operators (for optimizing the water use and costs of their water life cycle) is a topic of major impact. One area during the produced water phase of the water life cycle, is the less understood effect of different water cut fractions of the total fluids production from the formation on both the producing three-phase flow rate trends on surface as well as the downhole multiphase flow conditions, in particular, lateral to bend slugging and loading tendencies. This paper quantifies this effect of varying water cut production in a variety of operational conditions. In order to quantify the effect of varying water cut production, the methodology of this work involves first understanding the basic differences between gas-and-water (100 % water cut) and gas-and-oil (0% water cut) multiphase production in terms of their averaged slip behaviors, and therefore, total pressure gradient observations. We utilize published lab-scale flow loop experiments and a few actual, field-scale wells to demonstrate the different reported behaviors. An analytical multiphase flow simulator is then validated against these observations. Once verified, we then use the simulation tool to perform downhole calculations of flowing bottomhole pressure, gas volume fraction (gas-liquids slip), wellbore flow pattern, difference in wellbore and critical gas velocities and slugging flow characteristics (slugging frequency, velocity and lengths) for a given set of surface operating conditions. The workflows presented in this work will enable a deeper insight into the differences between gas and liquids slip under varying water cut fractions in both lighter condensate fluids as well as denser black oil fluids production. This work adds an improved understanding of the effect of water cut fractions on the total pressure gradient behaviors and downhole multiphase flow slugging and loading behaviors in liquids-rich tight oil developments.