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.

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

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Underground coal gasification receives renewed interest in both Western and Eastern Europe because of the vast amounts of otherwise unminable coal deposits that occur on the European continent. A field test is currently being carried out in Spain. Other countries in Europe show interest in this method of utilizing coal resources. In this study we present a model that describes the development of an underground coal gasifier. Both permeable bed and channel surface gasification are combined with thermo-mechanical failure of both coal and overlying rock. By this combination the model predicts the channel development and thus the sweep efficiency of the gasification process. The model consists of two modules: the first module solves the flow equations in the entire flow domain. The second module selects a block of coal for gasification and a block of coal and/or rock for thermo-mechanically induced spalling. Other features such as ash content and heterogeneity are included in the model as well. Model calculations show that the ash content of the coal and the coal and rock spall rate determine largely the sweep efFiciency of the gasification process. The model is used for field test evaluation purposes and can be used for extrapolation of the test results to other situations, e.g. the deep lying thin coal layers that occur in North-Western Europe. Introduction Underground coal gasification is a method of utilizing the vast otherwise unminable coal resources. Deep lying, thin coal seams such as occur in North-Western Europe can possibly be economically recovered by the application of standard directional drilling techniques. A typical configuration consists of a horizontal injection well with a vertical producer. Prior to the gasification step a final linkage path is created between injector and producer using, for example, reverse combustion techniques to char the coal. The gasification step starts by ignition of the coal and the injection of air or air enriched with oxygen. Subsequently, a cavity is formed in the coal seam. When the gas quality deteriorates the injection well is burnt to inject further upstream. This technique is called CRIP i.e. controlled retraction injection point. The situation during the first CRIP step is schematically shown in Figure 1. The successful underground coal gasification field tests were designed for two or more of these CRIP steps. The design of a field test and its interpretation would greatly benefit from a simple (i.e., low computational cost) dedicated simulator. The model must be able to describe the development from the early stages of gasification to a fully developed gasifier. The field test in Pricetown shows a possible mature configuration of a gasifier; gases percolate through ash and rock debris to a teardrop shaped channel where surface gasification takes place. A model for the initial stages has been developed by Britten and Thorsness. Their model was successful to describe field tests in thick coal layers. For economical gasification of thin coal layers, however, the cavity must develop to cover a radius much larger than the layer thickness. P. 191^

After a well has been drilled, the drilling fluid should be removed and replaced with either cement and/or completion fluids. For effective zonal isolation and optimum hydrocarbon production during the life of the well, the entire drilling fluid should be removed from the annulus. Cement and completion fluids are sensitive to drilling fluid contamination, and even a thin layer of oil-based drilling fluid could prevent the cement from bonding to the formation and the casing. In addition, for optimum hydrocarbon production, the cement sheath must be able to withstand the stresses throughout the life of the well. 1 Several factors affect the success of drilling fluid removal from horizontal annuli. Under static conditions, drilling fluid usually forms a gel structure. Under positive differential pressure, the drilling fluid loses filtrate and forms a filter cake on the formation face. Sometimes the filter cake is mushy and difficult to remove, but the formation fluid can easily flow through it. The successful removal of the gel and mushy filter cake depends on the structures that form and how these structures behave under flow conditions. In addition, casing centralization affects the fluid flow profile in the annulus, which affects gel and filter-cake removal.To investigate the mechanism of drilling fluid removal, we conducted both numerical and experimental studies. In the experimental studies, chemical flushes and spacers were tested for their effectiveness in removing drilling fluid. The experiments showed that annulus cleaning begins around the inner pipe and progresses outward at increasing fluid flow rates. Analytical fluid flow models and full 3D multiphase numerical models allowed us to estimate flow profiles and the success of removing drilling fluid under downhole conditions. The large-scale ex-fax 01-972-952-9435.References at the end of the paper. periments and analytical/numerical modeling have led to a better understanding of the factors controlling drilling fluid removal from horizontal wellbores.