Gas well liquid loading occurs when gas production becomes insufficient to lift the associated liquids to surface. When that happens gas production first turns intermittent and eventually stops. Hence 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), which 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 on average 40%, and analyses 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 due to liquid film flow reversal rather than droplet flow reversal. The impact of these findings on gas well deliquification is explored. Introduction Offshore gas production in the Southern North Sea started some 40 years ago. As a result of depletion the percentage of liquid loading wells has steadily increased over the last 10–20 years. The accurate prediction of the future date that currently stable wells will start liquid loading is essential for production forecasting. Moreover the liquid loading gas rate controls the remaining reserves, which is a key parameter when operating depleting wells and fields approaching their economic end of field life. Liquid is transported up gas well tubulars via liquid droplets entrained in the turbulent gas core and a liquid film moving up the tubing wall. The classical paper by Turner et al. (1969) derived a practical method of predicting the critical gas rate by equating the upward drag and downward gravity forces on the largest possible liquid droplet. The maximum Weber number determined the largest possible droplet size. The so-called Turner expression for liquid loading includes a 16% upward adjustment to best-fit field data. The Turner method has been a favourite of the industry for decades because it only requires readily measurable wellhead parameters. A great number of authors have offered refinements and modifications of the Turner expression. Coleman et al.(1991) showed that the 16% adjustment is not required to fit a different set of field data at typically lower gas rates. Nosseir et al.(2000) matched both sets of field data by considering the influence of the Reynold's number on the drag force. Guo and Ghalambor (2005) presented an energy balance approach based on minimizing kinetic energy, which increases the liquid loading rate by about 10%. Zhou and Yuan (2009) explored the impact of droplet coalescence on the minimum gas rate. Sutton et al.(2009) presented an in depth analysis of the different parameters that make up the Turner expression. Notably, the values used for the gas-condensate interfacial tension required significant correction. They also explored the variation in Turner rate along the wellbore and show that under certain circumstances (low pressure, cool reservoir) liquid loading is controlled by downhole conditions rather than wellhead conditions. Veeken et al.(2003) defined the Turner ratio (TR) for comparing the actual liquid loading gas rate Qmin with the Turner calculated QTurner as follows: TR = Qmin / Qturner (1) Dousi et al.(2005) introduced the term metastable rate Qmeta to describe the gas-only flow regime where the associated liquids drain into the reservoir.

Foam-assisted lift (FAL) is a well-established gas well deliquification technique to prolonge stable production from depleting, liquid loading gas wells. Field tests were carried out to delineate the operating envelope of FAL in PDO liquid loading gas wells. The field tests in five different wells consisted of step-down tests with and without continuous downhole injection of liquid foamer, to establish the associated reduction of the minimum stable gas rate. At the same time, the produced fluids were sampled and analyzed to diagnose potential impact on surface processing. The step-down tests were carried out using five different foamers that passed screening based on laboratory testing. FAL reduced the minimum stable rate by more than 40% independent of water cut i.e. for BS&W ranging between 14% and 96%. The step-down procedure required a surface choke which resulted in a significant reduction of the minimum stable gas rate, independent of the application of FAL.

The Yibal carbonate reservoir in North Oman is developed using horizontal wells. The completion technique has evolved from open hole to cemented and perforated liner. In parallel, the stimulation technique developed from spotting small volumes of acid across barefoots to selective acid treatment of perforated liner sections.This paper describes the completion and stimulation techniques and compares their production performance based on a 55 well data set.

Reservoir pressure depletion in gas reservoirs causes gas flow reduction with time and eventually leads to liquid loading as the gas flow up the well can no longer efficiently lift the associated liquids to surface. Liquid loading has a detrimental impact on production and a suitable deliquification method is required to continue production and maximize recovery. A downhole pump is one such deliquification measure where the pump sits at the bottom of the producing interval and evacuates the accumulated liquids up an insert (coiled tubing) string. It is important to assess beforehand whether the pump will effectively remove the liquids and hence deliver sufficient business value. A transient multiphase simulator has been used to simulate the gas well liquid loading process in a candidate well completed with 5.5" tubing, followed by the deliquification process triggered by a downhole pump installed 20 m above the bottom of the producing interval on a 1.5" coiled tubing. Simulations have been conducted for seven different liquid pump rates, three reservoir pressures and two water-to-gas ratios to assess the effectiveness of the pump under different operating conditions and to arrive at the optimum pump size and operation methodology. Simulations indicate that the downhole pump is capable of deliquifying the well and restoring production. However, for a given pump capacity and reservoir pressure, the surface gas production may either oscillate or settle at a steady state value. Oscillations occur when the pump capacity is too high and causes gas ingress into the pump, which introduces partial albeit temporary liquid loading of the wellbore. Continuous steady state gas production occurs when the pump capacity is not too high and an equilibrium situation is reached between the liquid being pumped out and the liquid being produced. The optimum pump rate is controlled by the effectiveness of the downhole separation between the gas and liquid phases and will minimize oscillating ingress of gas into the pump. This study emphasizes the role of transient simulations in predicting the effectiveness of a deliquification measure before embarking on field deployment. The simulations provide valuable insight into flow and pressure transients inside the wellbore during a gas well deliquification using a downhole pump. The information retrieved from the transient simulations is used to decide the optimum pump capacity and operation guidelines. To the best of authors' knowledge, this is the first time that a transient simulation of a downhole pump for gas well deliquification is presented in open literature.