A New Look at Predicting Gas-Well Load-Up

Abstract

Summary. This paper discusses results of field tests conducted to verify minimum flow rate (critical rate) required to keep low-pressure gas wells unloaded and compares results to previous work. This paper also covers liquid yield effects, liquid sources, verification that wellhead conditions control onset of load-up, and effects of temperature, gas/liquid gravities, wellbore diameter, and packer/tubing setting depth. Introduction As natural gas is produced from depletiondrive reservoirs, the energy available to transport the produced fluids to the surface declines. This transport energy eventually becomes low enough that flow rates are reduced and fluids produced with the gas are no longer carried to the surface but are held up in the wellbore. These liquids accumulate in the wellbore over time, and cause additional hydrostatic backpressure on the reservoir, which results in continued reduction of the available transport energy. In most cases, if this condition is allowed to continue, the wellbore will accumulate sufficient fluids to balance the available reservoir energy completely and cause the well to die. This phenomenon is known as gas-well load-up. As Fig. 1 shows, load-up can easily be recognized on a typical gas-well L-l0 chart by the characteristic exponential rate decline caused by accumulating wellbore liquids. Numerous papers have offered methods for predicting and controlling the onset of load-up. Turner et al. method for predicting when gas-well load-up will occur is most widely used. They compared two physical models for transporting fluids up vertical conduits: liquid film movement along the pipe walls and liquid droplets entrained in the high-velocity gas core. A comparison of these two models with field test data yielded the conclusion that the onset of load-up could be predicted adequately with an equation developed from liquid droplet theory (Stokes law), but that a 20% upward adjustment of the equation was necessary. Turner et al. also suggested that in most instances wellhead conditions controlled the onset of liquid load-up and that liquid/gas ratios in the range of l to 130 bbl/MMscf did not influence the minimum lift velocity. Examination of Turner et al. published data indicates that most of the wells used in the comparison had wellhead flowing pressures (WHFP's) above 500 psi. Because gas-well load-up problems generally worsen with continued decline in reservoir energy, this paper focuses on wells with lower reservoir pressures that are experiencing liquid load-up and have WHFP's below 500 psi. Wellbore Liquid Sources Before examining the wellbore-liquid-loading mechanism, we must first consider the source of the liquids. There are two obvious sources: liquids condensed from the gas owing to wellbore heat loss and free liquids produced into the wellbore with the gas. Both liquid hydrocarbons and water may be present, depending on the specific reservoir. In examining these sources, one might tend to minimize the impact of condensed water, particularly at low reservoir pressures. Because the gas is saturated with water at reservoir conditions, a plot like Fig. 2 can be constructed to show the impact of condensed water for a typical 8,000-ft, lowpressure gas well. As shown, the amount of water condensed increases exponentially as the static reservoir pressure declines. This is unfortunate because, as reservoir pressures decline, the amount of load fluid required to balance the reservoir hydrostatically and to kill a well also declines, compounding the problem. Other problems may also occur as a result of gas-well load-up. The near-wellbore region of the reservoir may begin to become saturated with liquids, causing the relative permeability to gas to decrease. further reducing the well's potential to remain productive. Also, condensed water can be damaging to formations containing swelling clays because it is low in total chlorides (less than 500 ppm). Critical-Rate Theory-Liquid-Droplet Model As Turner et al. showed, a free-falling particle in a fluid medium will reach a terminal velocity that is a function of the particle size, shape, and density and of the fluid-medium density and viscosity. Applying this concept to liquid droplets in a flowing column of gas, we can calculate the terminal velocity, vt, of the drop using which assumes a fixed droplet shape, size, and drag coefficient and includes the +20% adjustment suggested by Turner et al. JPT P. 329^

Liquid loading in gas wells: From core-scale transient measurements to coupled field-scale simulations

“…As presented in Table 1, several investigators have suggested different modified expressions derived from Turner model. Turner et al, 1969 Created the widely accepted Turner equation Coleman et al, 1991 Suggested not to use the 20% correction factor for low pressure gas wells Nosseir et al, 2000 Considered influences from different flow regimes Li et al, 2002 Involved the droplets' shape Veeken et al, 2003 Defined the concept of Turner ratio Guo et al, 2006 Took the minimum required kinetic energy of gas flow into account Belfroid et al, 2008 Concerned with the effects due to wellbore inclination Sutton et al, 2010 Used more realistic PVT properties Zhou and Yuan, 2010 Included the liquid droplet concentration in gas wells Veeken et al, 2010 Designed a specific expression for offshore gas wells Luan and He, 2012 Comprised droplets rollover in the gas rising process…”

Visible Research of Loading Speed in Vertical Gas Well

“…Through the experimental data, liquid flow rate and critical gas flow rate of three main models (Turner model [1], Colemon model [2,3] and LiMin model [4]) in the tube are calculated, drawing the following correlation curves shown in Fig. (1).…”

Lagrangian relaxation based decomposition for well scheduling in shale-gas systems

“…The most widely applied model for calculating q gc is given by [21], with the onset of liquid loading observed for the majority of gas wells to be controlled by the wellhead conditions. Coleman, Clay, Mccurdy, and Norris III [22] modified Turner's criterion for onset of liquid loading for gas wells with lower wellhead pressures. As shale-gas wells normally operate at low wellhead pressures, we hence use their model for calculating q gc .…”