Whistling behaviour of two geometrically periodic systems, namely corrugated pipes and multiple side branch systems, is investigated both experimentally and numerically. Tests are performed on corrugated pipes with various lengths and cavity geometries. Experiments show that the peak-whistling Strouhal number, where the maximum amplitude in pressure fluctuations is registered, is independent of the pipe length. Experimentally, a decrease of the peak-whistling Strouhal number by a factor of two is observed with increasing confinement ratio, i.e. the ratio of pipe diameter to cavity width. A numerical methodology that combines incompressible flow simulations with vortex sound theory is proposed to estimate the acoustic source power in periodic systems. The methodology successfully predicts the Strouhal number ranges of acoustic energy production/absorption and the nonlinear saturation mechanism responsible for the stabilization of the limit cycle oscillation. The methodology predicts peak-whistling Strouhal numbers in agreement with experiments and explains the dependence of the peak-whistling Strouhal number on the confinement ratio. Combined with an energy balance, the proposed methodology is used to estimate the acoustic fluctuation amplitudes.

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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.

Multiphase flow meters are indispensable tools for achieving optimal operation and control of wells as these meters deliver real-time information about their performance. For example, multiphase flow meters located downhole can improve the production of multilateral and multizone wells by timely allocating the zone where a gas or water cone occurs. However, multiphase meters are either expensive, inaccurate, or cannot be used downhole due to the harsh conditions. An alternative that can be used to overcome these disadvantages is to use multiphase soft-sensors, i.e. to estimate holdups and flow rates from relatively cheap and reliable conventional meters, such as pressure and temperature measurements, and a dynamic model connecting these measurements with the unknown quantities. The aim of this paper is to demonstrate, via two simulation based case studies, some possibilities and limitations of such multiphase soft-sensors. In the first case study the question is adressed whether it is possible to use only downhole pressure and temperatures measurements to estimate in real-time the water, oil and gas flow rates in a well. This question is of practical importance as these measurements are relatively cheap and reliable. The second case addresses the question whether it is possible to allocate the gas cone in a well with multiple inflow points or zones. This question is relevant as the estimated flow rate and holdup profiles can be used to manipulate Inflow Control Valves in such a way that gas breakthrough is prevented. Using amongst others OLGA data as "real-life" data, an additional question addressed here is what the influence is of soft-sensor model error and measurement noise on the quality of the estimates. From the first case study it can be concluded that, due to bad observability, pressure and temperature measurements alone are not sufficient to accurately estimate in real-time well flow composition parameters in a practically relevant situation. The preliminary results discussed in the second case study indicate that a soft-sensing solution to the gas cone allocation problem may very well be feasible. Introduction Motivated by the ever growing discrepancy between demand for and availability of oil and gas and by the improvement and increased availability of downhole measurement and control equipment, the oil and gas industry has recently embraced the "smart wells" philosophy. The main idea of this philosophy can be stated as the improvement of current reservoir management by improving current reservoir and well monitoring and control practice. By doing so, one aims at a higher yield from a given reservoir, on the short-term and/or on the long-term, while simultaneously fulfilling constraints that are imposed out of environmental and (other) operational considerations. Here, the focus is on the improvement of current well monitoring practice. Well monitoring can be defined as real-time measuring or estimating well production performance parameters such as water, oil and gas flow rates. These can be delivered to an operator or a control system to allow for taking steps to improve current well production performance. In particular, monitoring devices located downhole can improve the production of multilateral or multizone wells by determining at which areas/zones of the well which fluids are entering. Even more specific, this knowledge allows for a better handling of gas or water breakthrough. See e.g. Leemhuis et al. (2007).