Solving Gas-Well Liquid-Loading Problems

Abstract

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.

Shut-in based production optimization of shale-gas systems

“…Shale-gas wells may produce at these pseudo steady-state rates for some hundred days or even for years, depending on the well and reservoir properties. Along with the slow but steady decline in the pseudo steady-state rates, comes one of the foremost operational challenges of shalegas wells, which is to prevent the state of well liquid loading (Redden, 2012;Sutton et al, 2010;Al Ahmadi et al, 2010;Awoleke and Lane, 2011;Lea and Nickens, 2004;Whitson et al, 2012). This state is reached when the pressure support in the well is insufficient to lift co-produced liquids to the surface, causing accumulation of liquids in the wellbore and thereby increased bottomhole hydrostatic backpressure.…”

“…Accumulated liquids may be due to some low saturation of water in the formation, gas condensates, or left-over water injected during HF stimulation . Onset of liquid loading in gas wells can be recognized by highly erratic and unstable gas rates, a sharp drop in the decline curve (Al Ahmadi et al, 2010;Lea and Nickens, 2004) or as semi-stabilization of the production rate at significantly lower levels (Dousi et al, 2006;Whitson et al, 2012), i.e. at so-called meta-stable rates, illustrated by the green erratic rates in Fig.…”

“…Eventually, there will be insufficient pressure to lift the accumulated or coproduced liquids to the surface, and the well will exhibit liquid loading. This state can be recognized by erratic and unstable rates, sharp drops in the decline curve (Lea and Nickens, 2004), or stabilization of the production rate at significantly lower levels Dousi et al, 2006), so-called meta-stable rates. Liquid loading is frequently observed at late and intermediate times for shale-gas wells (Al Ahmadi et al, 2010;Awoleke and Lane, 2011;Cipolla et al, 2010;Kravits et al, 2011;Ilk et al, 2008;Mayerhofer et al, 2005;Sutton et al, 2010), and will additionally worsen the already low late-life rates.…”

“…Liquid loading is frequently observed at late and intermediate times for shale-gas wells (Al Ahmadi et al, 2010;Awoleke and Lane, 2011;Cipolla et al, 2010;Kravits et al, 2011;Ilk et al, 2008;Mayerhofer et al, 2005;Sutton et al, 2010), and will additionally worsen the already low late-life rates. Furthermore, operating multiple wells under liquid loading is generally undesirable, since it may give rise to sudden liquid slugs at the surface (Lea and Nickens, 2004) and thereby very unstable rates.…”

A New Approach for Accurate Prediction of Liquid Loading of Directional Gas Wells in Transition Flow or Turbulent Flow

“…And the main cause of this phenomenon is that in the later period during the gas well production, the formation pressure, gas velocity, and liquid-carrying capacity will be reduced, and the part of formation water in the wellbore will stay in well bottom causing fluid accumulation [2,3]. Liquid loading will create an increased backpressure on the formation and reduce production pressure differential, which decreases the gas rate and even kills the gas well [4,5]. Based on the theory of hydrodynamics, the formation water can be drawn to the surface when current gas velocity is higher than critical gas velocity.…”