An Analytical Model for Gas-Water-Coal Particle Flow in Coalbed-Methane Production Wells

Abstract

Abstract Coalbed methane (CBM) plays an important roll in US energy market. Prediction of CBM well performance is vitally important for enhancing CBM production. It is highly desirable to have a simple and accurate tool to do the prediction job. Assuming homogeneous mixture flow of liquid, gas, and solid in pipes, a simple analytical model was developed for simulating 3-phase flow in production strings. Liquid holdup effects were considered by applying a tuning factor to friction factor. The tuning factor was defined as a function of gas-liquid ratio (GLR) and vertical depth. The analytical model was coded in a spreadsheet program and calibrated with measurements from a full size physical well model. The calibrated analytical model was used for predicting performance of CBM wells during gas-lift dewatering operations and proven to be accurate for upward flow of CBM gas and water in a 2-7/8" tubing. Introduction Studies in 1980's indicate that US has coalbed methane (CBM) reserves of approximately 400 TCF.1 A later study2 in 1990's estimate that CBM account for some 17% of total recoverable natural gas reserves in the US. The CBM production is primarily centered in the San Juan and Black Warrior Basins,3 and it has become a significant source of natural gas production in US energy industry. Coalbeds are characterized as naturally fractured, low pressure, water saturated gas reservoirs. Methane occurs in coalbeds in free and adsorbed gas states. Free methane occurs in the fractures. The adsorbed methane, which is the majority of gas in CBM reservoirs, is stored in the micropore structure of the coal matrix. The adsorbed methane becomes free methane after desorption normally associated with depressurization. Therefore, reducing coalbed pressure by well dewatering is essential for releasing methane gas from the coal matrix in most coalbeds. CBM wells can be dewatered using different techniques including sucker rod pumps, hydraulic gas pumps, and gas lift system installations. The gas lift method has been found viable and cost effective in some areas in the Black Warrior basin. However, due to the nature of gas-water-solid 3-phase flow, there is a lack of production analysis techniques that can be easily used for identifying the CBM wells capable of high water production and the lift gas requirements. Literature surveys reveal that numerous correlations and mechanistic models on gas-liquid two-phase flow have been published.4–6 However most of the correlations were developed on the basis of data measured from small-scale research facilities and oil wells. Applications of these correlations to CBM wells, which contain water and coal/sand particles, frequently cause error in pressure and flow rate predictions. Although a few sophisticated two-phase mechanistic flow models were developed recently in drilling industry,7–9 they have not been proven to be applicable to the 3-phase flow in CBM wells. The difficulties in multiphase flow simulation arise in handling multiple flow regimes (bubbly, dispersed bubbly, slug, churn, and annular flow) and transitions between them. These flow regimes have been identified in laboratory studies under very different conditions. In the real wells, only some of the regimes exist and normally one or two of them dominate the flow in a given type of wells. Based on the author's experience in simulation of oil and gas flow with various computer simulators which coded various flow correlations and mechanistic models, there is no unique technique that match any given flow condition satisfactorily without tuning. It is always required to calibrate computer models with field measurements before performing predictions with the models.