An Effective Method for Modeling Non-Moving Stagnant Liquid Columns in Gas Gathering Systems

Abstract

Abstract Gas gathering system modeling is often complicated by the presence of localized pressure losses that are not easily explained by traditional pressure loss correlations. The tendency is to assume the pressure loss correlation must be tweaked to match measured operating conditions. This often leads to inappropriate manipulation of tuning factors (efficiency factor or roughness). A more appropriate approach is to recheck the validity of the input data and, most importantly, visit the field prepared to gather additional data to resolve the causes of the localized pressure losses. The objectives of this paper are to discuss one of the causes of localized pressure losses —Stagnant Liquid Columns —and to present several cases where localized pressure losses were interpreted to be caused by stagnant liquid accumulations. Introduction The maturation of the gas gathering systems throughout North America has resulted in the majority of systems being operated well below their original design conditions. Consequently, it is common to encounter pressure losses that exceed those predicted by steady-state single-phase and two-phase correlations. The reasons for these pressure losses are varied and most often relate to measurement issues, poor understanding of the pipeline and facility connections and sometimes non-moving liquid accumulations called stagnant liquid columns. Liquid accumulations are a concern because their continuous removal is difficult and they increase backpressure for all upstream wells, which reduces well deliverability and can result in localized pipeline corrosion. One would think that the traditionally used steady-state two-phase pressure loss equations would be capable of predicting the pressure loss that occurs in these liquid accumulations. However, the steady-state flow of fluid must be, by definition, continuous: inlet rate equal to outflow rate. If the liquid enters the conduit and accumulates while the gas continues through, we no longer have steady-state flow and the validity of the correlation no longer holds. It has been the authors' experience that localized pressure losses are often associated with liquid accumulations. Typically, field staff usually know there is a problem and may or may not have already realized that it is due to liquids, but it is usually a surprise for head-office staff because there is little or no liquid production reported. This leads to the question, how do we reliably identify stagnant liquid columns and how should they be modeled? To answer this question, a discussion of recommended modeling procedures is required. Discussion Pressure Loss Categorization The existing steady-state pressure loss correlations generally do a very good job of estimating pressure losses when used appropriately. Consequently, a comparison of simulated line pressures with field measured line pressures should result in a reasonable match within a preset tolerance. Measured line pressures that do not match modelled line pressures must be scrutinized closely to determine the cause of the mismatch, rather than relying primarily on tweaking tuning factors such as pipeline roughness or flow efficiency. For wells or groups of wells where a reasonable match is not initially obtained, it is good practice to begin by attempting to classify the unmatched pressure losses as either a systemic or localized step pressure loss problem before making changes to the model to force a match.