The purpose of this paper is to highlight the results of a comprehensive investigative study that quantifies the multiphase flow-related differences in multiphase hydrostatic pressure gradient, oil holdup and gas velocities as the gas injection depth is lowered from vertical to higher angles along the heel and into the lateral sections of horizontal wells. The results of this work enable a deeper understanding of gas slippage under gas lift operation at high angle sections of horizontal wells.
When used for optimizing horizontal well liquids unloading, gas lift valves are placed as low in the well as operationally allowable. But what happens if gas lift is applied along the bend or lateral? To help address this important question, we first leverage the vast knowledge gained from the inclined multiphase flow literature. The scientific knowledge base for up/down inclined multiphase flows reveals why such behaviors in laterals are so complex, namely, the extreme slip effects that exist.
In this work, we start with selecting published lab experiments in this area, and then simulate their flow behaviors using an advanced, cutting-edge analytical multiphase flow simulator. Next, we extend our validation to the field-scale using actual horizontal well gas lift field datasets sourced from different unconventional shale oil plays. With this detailed flow modeling substantiated, we then conduct the principal investigation of this work by quantifying the horizontal well gas lift performance at various representative inclinations (0, 30, 60, 88, 90 and 92 degrees from vertical) to better understand how changes in four major sensitivity variables, namely, diameter, gas injection rate, total liquids rate and water cut, impact the effectiveness of the gas lift process. Then, for each of these sensitivities and at each inclination, we analyze and compare the difference in value (value before gas lift - value after gas lift) of the multiphase hydrostatic pressure gradient, oil holdup, wellbore gas velocity and critical gas velocity.
A new learning from this work is that the prior vertical well experience and basis for gas lift being more effective at deeper depths does not translate to horizontal wells. The experience-driven industry viewpoint that gas lift is unaffected by inclination is not supported by both controlled inclined flow loop lab data and horizontal well field data. From the multiphase view, gas lift optimization is governed by the slip behaviors and it is demonstrated in this work that the multiphase hydrostatic pressure gradient reduction will be much lower at horizontal well inclinations of greater than 45 degrees from vertical, meaning the gas lift technique becomes less effective at these higher inclinations deep in the heel and lateral regions. Our results show that in this latter scenario, most of the gas will slip past the liquids, and increasingly so at higher angles (the pipe acts as a separator at these higher angles) and the effectiveness of the gas lift significantly lowers as the flow starts to undergo slugging and other high-slip transitional flow patterns. This has a significant practical impact to operators trying to optimize end-of-tubing (EOT) placement in conjunction with the gas lift lowest valve placement. Summarily, the results from our detailed modeling are used to demonstrate what is and what is not possible in terms of liquids evacuation from horizontal wellbores using gas-assisted lift at up/down inclined angles - and specifically - how gas injection rates affect hydrostatic pressure gradients, oil holdups, wellbore gas velocities and critical unloading gas velocities along the bend and lateral.
