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.
Summary Gas-well liquid loading occurs when gas production becomes insufficient to lift the associated liquids to surface. When that happens, gas production becomes intermittent and eventually stops. In depleting gas reservoirs, the technical abandonment pressure and ultimate recovery are typically governed by liquid loading. To date, most methods for predicting liquid loading have followed Turner et al. (1969), who describe liquid loading as the point where the liquid droplets suspended in the gas flow start moving downward rather than upward. This paper presents (offshore) liquid-loading field data that exceed the Turner predicted values by an average of 40%, and analyzes the sensitivity of the liquid-loading gas rate for different well parameters. It subsequently presents the results of steady-state and transient multiphase-flow modeling, carried out to identify the influence of the same well parameters. A modified Turner expression is proposed that best fits the liquid-loading field data and broadly agrees with the results of a multiphase-flow model that uses a modified version of the Gray outflow correlation. The results of transient-flow modeling support the flow-loop observation that liquid loading occurs because of liquid-film-flow reversal rather than droplet-flow reversal. The impact of these findings on gas-well deliquefication is explored.
To be able to assess the mechanical integrity of piping structures for loading to multiphase flow conditions, air-water experiments were carried out in a horizontal 1″ pipe system. Forces and accelerations were measured on a number of bends and T-joint configurations for a wide range of operating conditions. Five different configurations were measured: a baseline case consisting of a straight pipe only, a sharp edged bend, a large radius bend, a symmetric T-joint and a T-joint with one of the arms closed off. The gas flow was varied from a superficial velocity of 0.1 to 30 m/s and the liquid flow was varied from 0.05 to 2 m/s. This operating range ensures that the experiment encompasses all possible flow regimes. The magnitude of the measured forces was found to vary over a wide range depending on the flow regime. For slug flow conditions very high force levels were measured, up to 4 orders of magnitude higher than in single phase flow for comparable velocities. The annular flow regime resulted in the (relative) lowest forces, although the absolute amplitude is of the same order as in the case of slug flow. In case of slug flow, the measured results can be described assuming a simple slug unit model. For both the frequency and amplitude the available models can be used in assessments. In annular and stratified flow a different model is required, since no slug unit is present. Instead, the amplitude of the excitation force can be estimated using mixture properties. To predict the main frequency for the annular flow and stratified flow additional experiments are required.
Two-phase flow occurs in many situations in industry. Under certain circumstances, this can be the source of flow-induced vibrations. The forces generated can be sufficiently large to affect the performance or efficiency of an industrial device. At worst, the mechanical forces that arise may endanger structural integrity. Thus, it is important to take these forces into account in designing industrial machinery to avoid problems during operation. Although the occurrence of such forces is well-known, not much is known about their magnitudes. Unfortunately, the amount of experimental data available in literature is rather limited. This paper describes an investigation into the forces in a two-phase flow in a 6mm pipe containing a bend. The results are analyzed based on flow regime and bend configuration. Finally, a simple model is proposed to predict the forces generated by slug flow.
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