Detailed analysis of pressure drop in a large diameter vertical pipe

Thesis Overview

<p> </p><p><strong>INTRODUCTION</strong></p><p><strong>1.1 General introduction</strong></p><p>Profitable production of oil and gas fields relies on accurate prediction of the multi-phase well</p><p>flow. The determination of flowing bottom-hole pressure (BHP) in oil wells is very important</p><p>to petroleum engineers. It helps in designing production tubing, determination of artificial lift</p><p>requirements and in many other production engineering aspects such as avoiding producing a</p><p>well below its bubble point in the sand-face to maintain completion stability around the wellbore <strong>(Ahmed, 2011).</strong>&nbsp;Well fluids above bubble point pressure exist as a single phase as it is being produced from the reservoir. However, as they navigate their way through the network of interconnected pores in the reservoir to the wellbore, there is a continuous reduction in pressure as overburden stress is gradually reduced. This phenomenon leads to the liberation of the entrained gas. As the single-phase fluid rises in the tubing, a critical point is reached where some of the gases begin to come out of solution along the length of the pipe. In other words, it changes from single-phase flow to multi-phase flow.</p><p>This leads to some level of complexity as regards to the identification of the physical properties of the individual phases, the flow pattern, the relative volume occupied by the separate phases inside the pipe, and most importantly the implication of the phase separation on the pressure drop along the well tubing string.</p><p>Although most if not all calculations for flow lines in multiphase production systems have been and continue to be based on empirical correlations, there is now a strong tendency to introduce more physically based (so called mechanistic) approaches to supplement if not replace correlations. This is because the latter are well known for their unreliability when applied to systems operating under conditions different to those from which the correlations are derived; such conditions encompass: pressure, temperature, fluid properties and pipe diameter. Furthermore, correlations exist for limited geometrical configurations (i.e. vertical or horizontal pipes) and simple physical phenomena (no mass transfer between phases, constant temperature, etc.). With the advent of more complex production systems involving deviated wells as well as the move to exploit gas condensate resources the production of which will inevitably involve strong mass transfer effects, calculation methods will be required to account for such complexities.</p> <br><p></p>