Liquid loading is a common production problem in mature gas wells. As the formation pressure decreases and gas flow rate also decreases, the gas kinetic energy is unable to lift the liquid phase completely to the surface. Liquid starts to accumulate at the bottom of the well, which increases the back pressure of the reservoir. This is reflected in a fluctuated production of liquid and gas rates. At the same time, it significantly reduces the production rate and eventually kills the well. Correct prediction of critical gas velocity at which the well starts to load is very important to the operators since they could take appropriate measures to prevent liquid loading and extend the well production life. In the past, most studies on liquid loading focused on vertical wells. Only recently have a few studies been conducted to deal with the liquid loading for deviated and horizontal wells. To date, there are few published studies discussing how to predict the critical gas velocity across a wide deviation angle range. In fact, there are contradictory conclusions made by different researchers. In this paper a database related to the critical gas velocity is compiled with data from published literature. A new model is developed and evaluated with the experimental data. The gaps in the previous studies and modeling are also discussed. Introduction Gas wells often produce water and other condensate. In the early production stage, the gas flow rate is high enough to carry the produced liquids to the surface. As the reservoir pressure is depleted, the produced gas flow rate decreases until the gas reaches a critical condition at which time the liquid loading is initiated. At the inception of liquid loading, the gas flow rate is not enough to carry the liquid completely to the surface and the liquids start to accumulate at the bottom of the well. Then, the back pressure builds up and the increased reservoir pressure will eventually be sufficient to lift the liquid to the surface. Once the liquid slug is pushed out by the gas, the liquid starts to reload the well again and the cycles are repeated again and again until the well is eventually loaded completely and gas production stops. Accurate prediction of liquid loading in the well is very important to the operators since this will allow them to take the necessary measures to void liquid loading and extend the well production life. The most common liquid loading symptoms observed in the field are pressure (or pressure gradient) fluctuations and reduction of gas production. In general, there are two different liquid loading principles proposed in the literature: liquid droplet fall back and liquid film reversal. The liquid droplet mechanism is based on the falling back of liquid droplets while the liquid film concept is related to the partial or full reversal flow of the liquid film.

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Optimizing the development of oil and gas fields necessitates the use of accurate predication techniques. The predictions should also involve minimizing the uncertainties associated with day-to-day operational challenges related to wells, pipelines and surface facilities. The choke size settings, for instance, need to be frequently adjusted to optimize production flowrates using the right techniques. This paper provides a method to optimize the production flowrate for existing wells and to minimize the cost through finding the best cost-effective selection. Providing an insight into factors affecting the flow assurance of oil and gas reservoirs is also included. The study has been implemented by the use of nodal analysis conducted by a surface network simulation, to reach the optimum design of oil and gas production systems. The optimization of the wells can be achieved by changing tubing and flowline sizes, minimizing the skin factor, controlling the water cut, and adjusting the gas-lift injection pressure. The Hurricane oil field that covers a wide range of subsurface and surface facility data is simulated in this paper. Seven reservoirs are considered in this study containing eleven different wells. Seven of these wells are producing naturally while the remaining four wells are gas-lifted. For each of the eleven wells, different parametric scenarios are run on the different size of the pipelines and chokes. Flow assurance study has been conducted to know the effect of severe slugging, wax deposition, and hydrate formation. Severe slugging has been predicted using a surface network simulation, while wax deposition and hydrate formation using a pressure-volume- temperature (PVT) simulation. For the artificial lift wells, as this field was mainly operated by gas lift, a new design has been implemented based on gas surface injection rate as a way to eliminate the workover operations.

Real-time multi-lateral wellbore positioning of horizontal wells for improved reservoir deliverability has been a revolutionary breakthrough worldwide. It has supported the efficient production of hydrocarbons from multiple thin layers within a reservoir to yield maximum recovery and to restrict water coning. Recent advances in real-time geosteering now enable, with even greater precision, successful targeting of "sweet spots" within a reservoir. These advances have the capability to open still more drainage volume for recovery of hydrocarbons.Through successful teamwork from multidisciplinary professionals, numerous uncertainties and challenges were overcome using real-time geosteering techniques in conjunction with advanced logging-while-drilling (LWD) sensors and instrumented rotary steerable systems in Kuwait Oil Company's Magwa field. For this purpose, pre-well modeling, real-time geosteering, advanced LWD sensors, including azimuthal deep resistivity (ADR™) sensor, an azimuthal lithodensity (ALD™) sensor, instrumented rotary steerable systems (RSS), and real-time operation (RTO) services were used. The historically anticipated production rate was surpassed through the optimized placement of this well.The outcome of this particular dual-lateral well using advanced real-time geosteering technology has led to development plans for additional multi-lateral wells in Kuwait. They will be targeted to the highest porosity and permeability zones within the upper compartments of the reservoir while avoiding the adverse water coning effects of wells drilled vertically or in the massive sand. This paper reviews the teamwork and deployment of real-time geosteering operations, as well as new generation LWD and RSS sensors, used to successfully improve reservoir deliverability.

This paper discusses a method for optimizing production facilities design for onshore/offshore wells during new field development. Optimizing the development of new oil and gas fields necessitates the use of accurate predication techniques to minimize uncertainties associated with day-to-day operational challenges related to wells, pipelines and surface facilities. It involves the use of a transient multiphase flow simulator (TMFS) for designing new oil and gas production systems to determine the feasibility of its economic development. A synthetic offshore oil field that covers a wide range of subsurface and surface facility data is considered in this paper. 32 wells and two reservoirs are considered to evaluate the effect of varying sizes of tubing, wellhead choke, flowline, riser, and transport line. A detailed investigation of the scenario of emergency shutdowns to study its effect on the system is performed using TMFS. Other scenarios are also evaluated such as startup, depressurization, pigging, wax deposition, and hydrate formation. This paper provides a method to minimize the cost by selecting the optimum pipelines sizes and diameters, and investigating the requirements of insulation, risk of pipeline corrosions and other related flow assurance parameters. Different facility design scenarios are considered using TMFS tool to achieve operational flexibility and eliminate associated risks. Pressure and temperature conditions are evaluated under several parametric scenarios to determine the best dimensions of the production system. This paper will also provide insight into factors affecting the flow assurance of oil and gas reservoirs.