Summary The dynamic effects of variable pump flow rate, formation-influx distribution, blowout preventer (BOP) and choke closure, choke adjustments, and well stabilization are accounted for in the analysis of a kicking well by solution of the appropriate mass- and momentum-balance equations. In the gas/liquid regions, the system is modeled as separated flow. The mass-balance equations are solved for the gas and liquid separately, but the momentum equation is solved for the mixture. The model predicts the detailed flow and pressure response of the well at all times and wellbore locations during the kick. The model is currently capable of simulating a single kick in a vertical hole (surface or subsea) with water-based mud and the bit on bottom. The drillers' method (DM), wait/weight (WW), or dynamic kill control procedures for either a "perfect controller" [constant bottomhole pressure (BHP) or for any of several choke-control procedures may be simulated. Introduction The prevention and control of gas kicks are of great concern to the petroleum industry. Although most kicks are eventually brought under control, the occasional blowout can result in the loss of millions of dollars, as well as the more serious consequences of injury and potential loss of life. Although gas kicks are an important factor in the successful drilling of a well, the tools available to analyze kick phenomena are not based on realistic assumptions and conditions present during a kick. Current computer models are limited in their applications and validity by the assumption of an arbitrary distribution of the gas in the wellbore. The most common assumption is that the gas enters the wellbore as a single bubble and remains as a contiguous gas slug throughout the kick-control procedures. This is a conservative assumption in that the procedures. This is a conservative assumption in that the pressures calculated from the single bubble are always larger pressures calculated from the single bubble are always larger than those actually experienced but may result in costly overdesign of the well. To have a realistic well-control training capability and to assess the relative merits of various kick-control equipment and control procedures, it is essential to have a computer model capable of simulating as accurately as possible the actual dynamic response of the well to a gas influx. Such a model is also required to perform postanalysis of a blowout in order to determine what actions might have been taken during the initial kick to prevent the blowout or to reduce its severity. The ultimate objective of a kick simulator is to calculate the surface flow rates and pressures at the surface, casing shoe, and bottomhole as a function of time after the initial gas influx. The improved simulation resulting from a realistic model will allow variations in drilling parameters (e.g., pump flow rate, well geometry, parameters (e.g., pump flow rate, well geometry, formation properties, driller response, choke-control procedures, and mud properties) to be evaluated readily and procedures, and mud properties) to be evaluated readily and will permit evaluation of the kick in terms of pit gain, maximum allowable pump pressures, fracture gradients, and potential for multiple kicks (i.e., the adequacy of the control procedure).

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Summary Eventually, gas wells will cease producing as the reservoir pressure depletes. The usual presence of some liquids can reduce production even faster. This paper describes the problem of liquid accumulation in a gas well. Recognition of gas-well liquid-loading problems and solution methods are discussed.1 Introduction Gas wells producing dry gas have a low flowing bottomhole pressure (FBHP), especially for low-rate wells. When liquids are introduced, the FBHP increases. Liquids in the gas may be produced directly into the wellbore or condensed from vapor in the upper portion of the tubing. The total flowing-pressure drop can be expressed as the sum of the pressure drops from elevation (weight of the fluids), friction, and acceleration. For low-rate wells, the acceleration term is very small, and, with correctly sized tubing, the friction term is also small. The elevation, or gravity term, becomes larger when liquid loading occurs. Fig. 1 shows the approximate flow regimes as gas velocity decreases in a gas/liquid well. If the well is flowing as a mist of liquid in gas, then the well still may have a relatively low gravity-pressure drop. However, as the gas velocity begins to drop, the well flow can become slug and then bubble flow. In this case, a much larger fraction of the tubing volume is filled with liquid. As liquids accumulate, the increased FBHP will reduce or prevent production. Several actions can be taken to reduce liquid loading.Flow the well at a high velocity to stay in mist flow by use of smaller tubing or by creating a lower wellhead pressure.Pump or gas lift the liquids out of the well (many variations).Foam the liquids, enabling the gas to lift liquids from the well.Inject water into an underlying disposal zone.Prevent liquid formation or production into the well (e.g., seal off a water zone or use insulation or heat to prevent condensation). If liquid accumulations in the flow path can be reduced, then the FBHP will be reduced and production increased. The liquid-loading problem will have been solved. Recognizing Liquid Loading Liquid loading is not always obvious. If a well is liquid loaded, it still may produce for a long time. If liquid loading is recognized and reduced, higher producing rates are achieved. Symptoms indicating liquid loading include the following.Sharp drops in a decline curve (Fig. 2).Onset of liquid slugs at the surface of well.Increasing difference between the tubing and casing flowing pressures (i.e., Pcf-Ptf) with time, measurable without packers present.Sharp changes in gradient on a flowing-pressure survey. Critical Velocity. Turner et al.2 developed two mechanistic models to estimate critical velocity.A film of liquid on the wall of the tubing.A droplet suspended in the flowing gas. The model that best fit their well data was the droplet model. Gas rates exceeding critical velocity are predicted to lift the droplets upward. Lower rates allow droplets to fall and accumulate. Coleman et al.3 later correlated to well data with lower surface flowing pressures than did Turner. Turner's analysis gives the following for critical velocity: Equation 1 where k=1.92 (Turner et al.2) or 1.59 (Coleman et al.3). Assuming2 s=20 and 60 dynes/cm and ?l =45 and 67 lbm/ft3 for condensate and water, respectively, a gas gravity of 0.6, z=0.9, and a temperature of 120°F, then Equation where C is 5.34 for water or 4.02 for condensate2 or 4.43 for water or 3.37 for condensate.3 The corresponding critical gas rate, Qgc, in MMscf/D is Equation If any water is produced, conservatively use water properties to calculate critical velocity. Typically evaluated at the wellhead, the above equations are valid at any well depth if the in-situ pressure and temperature are known. The distance between the tubing end and the perforations should be minimized because casing flow is usually liquid loaded. Stability and Nodal Analysis. As liquids accumulate at lower gas rates, tubing performance can become unstable. Fig. 3 shows a tubing performance curve (TPC), or "J" curve, evaluated at the tubing bottom near perforations. This flowing pressure is needed for varying production rates at a constant gas/liquid ratio (GLR). It is plotted across a gas-deliverability curve, or inflow-performance curve.

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Summary Slim-hole drilling and continuous coring for oil and gas exploration havebetween impeded by lack of documentation of well-control methods forsmall-annulus drilling. Research in annular pressure losses, kickidentification, wireline swab effects, and dynamic-kill well-controleffectiveness helped develop a slim-hole well-control methodology. Introduction Slim-hole drilling is increasingly used as an exploration tool. Thistechnique involves using compact, mobile rigs with drag bits and high rotaryspeeds to drill small-diameter, expendable wellbores. Walker and Millheimdescribed such a system, Stratigraphic High-speed Advanced Drilling System(SHADS), which uses mining exploration rigs for slim-hole oil and gasexploration. Mining rigs are equipped to core 6- to 3-in.-diameter (andsmaller) wells. The rigs have large-diameter (relative to hole size)flush-joint drillstrings that result in annular volumes 1/10 the size ofconventional wells. The concern about well-control capabilities insmall-annulus wells has hindered a greater use of slim-hole drilling. Thisconcern is justified for two reasons. First, the annular volume on a slim-holewell is so small that an influx must be detected more quickly than in aconventional well. Second, well-control practices for small-annulus wells havenot been documented in the literature. System pressure losses. The bestkick-detection methods and most effective kill procedures are unknown to manydrilling procedures are unknown to many drilling personnel. personnel. To solvethe well-control problems, a full-scale slim-hole well was drilled andinstrumented for well control research. Fig. 1 is a cross section of the SHADSwell-control well. The well is cased with 5-in. casing with an ID thatcorresponds to the most commonly drilled slim-hole size (for SHADS) of 4 3/8in. Eight 1/4-in. pressure transmission lines are attached at various depths tothe exterior of the casing. Special ported pup joints, similar to a side-pocketported pup joints, similar to a side-pocket mandrel, allow communication withthe casing ID. Two 1-in. lints are also attached to the exterior andcommunicate with the casing bore near the bottom of the casing. These 1-in. lines allow injection of nitrogen into the bottom of the well for kicksimulation. This well is called SHADS No. 7. Results of tests conducted tomeasure the annular pressure losses were used to develop correlations fordetermining system pressure losses based on hole size, depth, and pressurelosses based on hole size, depth, and fluid properties. Kick-detectiontechniques and kill methods were evaluated at the well. Drilling engineers andrig personnel were with a slim-hole rig over the well. A slim-hole well-controlphilosophy was developed and tested on a full-scale research well before fieldimplementation. This paper describes the techniques necessary to plan safe wellcontrol for a slim-hole well. Throughout the paper. typical 8,000-ftconventional and slim-hole wells are used to compare the two systems. Fig. 2illustrates the casing, hole, and drillstring sizes, along with otherspecifics. System Description. In this paper, the well-control system includes mudpumps, surface kick-detection system (pit volume totalizer, gas detector, pressure recorders, etc.), blowout preventers (BOP's) and choke manifold, drilling fluid, drillstring, and wellbore. The functionality of the system isidentical for conventional and slim-hole wells, although a slim-hole rig oftenuses smaller equipment. To apply the well-control practices of this paper, quantitative flowmeters practices of this paper, quantitative flowmeters arerequired on the mudlines into and out of the well. No additional equipmentshould be needed. The physical differences between slim-hole and conventionalwell control are analyzed first. They include annular volume effects, systempressure losses, and swab pressures. The next sections on kick pressures. Thenext sections on kick detection and the dynamic kill method apply the physicalresults to field operations. Finally, physical results to field operations. Finally, the approach to slim-hole well control is outlined. Physical Differences Physical Differences Annular Volume. A small annularvolume is the most apparent difference between slim-hole and conventionalwells. From a well-control standpoint, the height of an influx when a kick istaken is critical to the severity of a well-control situation. The greater theheight of the influx, the more serious the well-control problem. JPT P. 1380

Selection of the most economical artificial lift method is necessary for the operator to realize the maximum potential from developing any oil or gas field. Historically the methods used to select the method of lift for a particularfield have varied broadly across the industry, includingDetermining what methods will lift at the desired rates and from the required depths.Evaluating lists of advantages and disadvantages.Use of "expert" systems to both eliminate and select systems.Evaluation of initial costs, operating costs, production capabilities, etc. using economics as a tool of selection. This paper will highlight some of the methods commonly used for selection and also include some examples of costs and profits over time calculated to the present time as a tool of selection. The operator should consider all of these methods when selecting a method of artificial lift, especially for a large, long-term project. Introduction In artificial lift design the engineer is faced with matching facility constraints, artificial lift capabilities and the well productivity so that an efficient lift installation results. Energy efficiency will partially determine the cost of operation, but this is only one of many factors to be considered. In the typical artificial lift problem, the type of lift has already been determined and the engineer has the problem of applying that system to the particular well. The more basic question, however, is how to determine what is the proper type of artificial lift to apply in a given field. Each of the four major types of artificial lift will be discussed before examining some of the selection techniques. Some additional methods of lift will also be discussed. Preliminary comments related to reservoir and well factors that should be taken into consideration are presented.