Predicting Onset and Dynamic Behaviour of Liquid Loading Gas Wells

Abstract

Abstract As reservoir pressures decrease in maturing gas wells, liquid drop-out forms an increasing restriction on gas production. Even though virtually all of the world's gas wells are either at risk of or suffering from liquid loading, the modeling of liquid loading behavior is still quite immature and the prediction of the minimum stable gas rate not very reliable. Many wells start liquid loading at gas rates well above the values predicted by classic steady state prediction models such as Turner. The loading point is strongly dependent on inclination angle, flow regime transitions and the interaction between tubing outflow behavior and the reservoir IPR. In the paper, the behavior of different natural gas wells and of an air-water test setup are analyzed. Simulations were performed using both commercially available software and dedicated dynamic models. The onset of liquid loading and the dynamic behavior of a flooded well during a restart were predicted. These were then compared to actual production data. The influence of the reservoir parameters and of the tube inclination were of special interest. The influence of dynamic disturbances on the stability are not taken into account by the classic prediction models. Systems with high permeable reservoirs are less able to cope with disturbances. This leads to higher critical rates for those systems. This corresponds to data from field observations. A maximum in the critical velocity is observed around an inclination of 50° with a critical rate 40% higher than for a vertical well. To solve this, relations found from flooding experiments are used to modify the current prediction models. Based on the current work an adaptation to the Turner equation, which takes the inclination effects into account, is proposed. For the observed natural gas wells and for the airwater experiments the modified Turner equation predicts the observed loading points within 20% accuracy. Introduction Liquid loading, that is the process when the gas is no longer able to lift liquid to the surface, is a major limiting production factor for maturing gas wells. Solutions such as gas lift, soap injection, velocity string or plunger lift are required to solve this problem. Accurate predictions of the onset of the liquid loading process allow for better planning and choosing the right countermeasure. Currently, the most widely used model is still the classic Turner criterion, which is based on a force balance on a falling droplet, although it is known to not always be correct. In laboratories, liquid loading occurs due to the drainage of the liquid film which is present at the tubing walls in annular flow (Belt 2008, Westenende 2008). In practice the production decline may also be due to other mechanisms, which may be difficult to distinguish. The main mechanisms for the production decline are thought to be:Film drainage,System instability,Flow regime change (Toma 2007). In film drainage the force balance on the liquid film results in a part of the liquid film with a negative (downwards) velocity. System instability occurs when the inflow performance relation (IPR, reservoir curve) intersects the tubing performance curve (TPC) to the left of the minimum in the tubing curve. In practice the liquid drainage point may be to the left or to the right of the TPC minimum. The system stability is also governed by the pressure drop as is the force balance across the liquid film. The flow regime change is a separate mechanism and is less determined by gravity but is more influenced by increased hold up and wave formation. The flow regime change itself is more likely a result than an initiator. Slug formation can occur when the liquid hold up increases. This increase is expected to be caused by the negative liquid film velocity. Therefore, these three mechanisms may interact and coincide in field cases and the direct cause of a production decline may be difficult to detect.