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^