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^
Summary This paper describes the hydraulics of wellbore load-up for gas wells. Atheoretical model of transient load-up hydraulics is presented and comparedwith field test data. Application of this technology allows predictivetechniques to be used in predictive techniques to be used in analyzing gas-wellload-up. It also establishes an understanding of loadup behavior, which isvaluable in analyses of production problems and evaluations of productionalternatives for low-pressure gas wells. Introduction Part 1 of this series outlined data that Part 1 of this series outlined datathat validated the theory for predicting the critical rate, qc, forlow-pressure gas wells. This second part outlines and validates the theory forpredicting the behavior of a low-pressure gas well after qc is reached, whenthe well is in an unsteady-state load-up condition. Doing so will offer abetter definition of gaswell load-up behavior and a better understanding of howto cope with the problem. To understand the transient load-up condition, it is helpful to construct apicture of a gas well in load-up (Fig. 1). Fig. 1a represents a well flowingabove its critical rate; i.e., qg >qc. In this state, at t=O, all fluidproduced with the gas is carried out of the produced with the gas is carriedout of the wellbore conduit and the wellbore exhibits a relatively predictable, steady-state behavior. The drive energy available that causes gas to flow from this well is boundedby the average reservoir pressure in the well's drainage area, PR and thesystem pressure, Ps' The flowing sandface pressure, Psf' is Ps' The flowingsandface pressure, Psf' is dictated by the reservoir performance. The flowingwellhead pressure, psf, is controlled by the performance of any surfaceequipment or pipeline. At the onset of load-up where qg less than qc and t=1, liquid is no longercarried out of the wellbore; instead, it is held up in the wellbore in the formof an aerated column (Fig. 1b). The same boundary conditions exist for thedrive energy; however, psf and p, qr converge toward their pressure p, qrconverge toward their pressure boundaries as the produced fluid accumulates andincreases the hydrostatic pressure of the flowing gas column. The sandfacepressure, psf gradually increases until it is equal to psf gradually increasesuntil it is equal to the average reservoir pressure, PR This increase in psfwith time causes a comparable decline in gas flow rate and During this load-up period, the pressure loss in the well flowline (Pwf-ps), the gas column in the wellbore (Pli-Pwf) and the reservoir drawdown (Pe-Psf)all decrease because these pressure losses are primarily frictional anddecrease with decreasing flow rates. However, the pressure caused by thebuilding of a hydrostatic liquid column in the wellbore (Psf-Pli) increases. This hydrostatic column continues to build until such time as the hydrostaticconditions of the wellbore, combined with pwf balance the reservoir drivingforces and cause the well to die (Fig. 1c). Now, at t=2, the well is completelyloaded and qg=0. Once this occurs, PR continues to increase until it either equalizes withthe reservoir pressure at the well's drainage radius boundary, Pe at t=3 orovercomes the load-up-induced hydrostatic head and begins to unload thewell. The well's ability to unload itself depends on such variables as reservoirtransient flow performance, remaining amount of load performance, remainingamount of load fluid, changes in the system pressure boundary and wellboreconfiguration and depth. When a well can no longer complete the unloading cyclenaturally, it has reached its "blowdown limit which is covered in Part 3 ofthis series. Theory This description of gas-well load-up can be modeled predictively withconventional quantitative analysis techniques. First. because gas-well load-upis driven by the time history of the liquid column height, it is necessary todefine a liquid control volume, as shown in Fig. 2. The primary differentialequation to be solved for the liquid balance is With the definition of the liquid holdup fraction,3 YL, Then, To solve Eq. 3, an expression for the rate of liquid in and liquid out, QLinand QLout must be determined. JPT P. 334
Summary This paper incorporates critical-rate and blowdown-limit technology intosystem-network-analysis (SNA) techniques to predict abandonment pressures fordepletiondrive reservoirs and demonstrates that SNA by itself tends tounderestimate the abandonment pressure. A number of practical operationalconsiderations pertaining to the use of this technology are also outlined. Introduction At the outset of this series, we said that the technology of low-pressuregas-well load-up would be presented to enhance the understanding of gas-wellload-up problems and to establish more consistent and accurate analyticalmethods for evaluating the economic abandonment of depletion-drive gasreservoirs. The first three parts of the series presented the technology fordetermining a presented the technology for determining a well's critical rate, for predicting wellbore hydraulics during load-up, and for calculating a newproducing limit known as the gaswell blowdown limit. This final part presentspractical methods for using this technology practical methods for using thistechnology to predict abandonment pressures, to evaluate productionalternatives, and to perform a reservoir depletion analysis. This paper alsosummarizes considerations for operating low-pressure gas wells and fields. Methods for Predicting Abandonment Pressures In the past, the most common method for predicting the abandonment pressureof a predicting the abandonment pressure of a depletiondrive gas reservoir wascomparison to a similar reservoir's past performance. Because of recentadvances in performance. Because of recent advances in computing technology andtwo-phase-flow calculation methods, an increasing number of engineers are usinga more rigorous SNA to predict reservoir abandonment pressures. This processinvolves integrating pressures. This process involves integrating the reservoirflow performance (inflow) and the wellbore/system flow performance (outflow)for various flow rates and static reservoir pressures. The results of theintegration can then be plotted and analyzed. Fig. 1 is an example of such aplot. The abandonment pressure for each well/ system configuration is typicallyinterpreted as the static reservoir pressure where the wellbore/systemperformance becomes unproducible-i.e., where the inflow and outflow performancecurves no longer intersect. Two-phase-flow correlations indicate that at thispoint the wellbore will load up and the well will die. Using the Liquid-Droplet-Model Critical Rate To Predict Abandonment Pressures If we compare this load-up point to the critical-rate calculation presentedin Part 1 of this series, we can construct a comparison plot like that in Fig.2. As this figure shows, as the static reservoir pressure declines, thetangency point diverges from the critical rate. Thus, the previous analysiswith the tangency point as the load-up point yielded a lower abandonmentpressure than is indicated by liquid-droplet-model criticalrate technology. Thedata presented in part 1 showed that the liquid-droplet-model critical rateaccurately predicts the load-up threshold for low pressures. We can concludethat the two-phase-flow correlation does not correctly interpret this samepoint of wellbore instability. Although examination of the causes of this difference is beyond the scope ofthis paper, it is worthy of a few comments. As a general rule, mosttwo-phase-flow correlations use an interpretation of vertical flow regime topredict where the transition from mist to slug predict where the transitionfrom mist to slug flow begins. This transition point is generally consideredthe point where the wellbore becomes unstable. The correlations, however, cannot determine the point where liquid droplets begin to be held up in thewellbore. This difference in load-up-point interpretations could explain thedivergence between the two methods. Using the Blowdown-Limit Model To Predict Abandonment Pressures A comparison of the abandonment pressures predicted with liquid-droplettechnology predicted with liquid-droplet technology combined with SNA tohistorical data for various reservoirs showed that the criticalrate abandonmentpressure is still not the correct ultimate abandonment pressure of mostdepletion-drive reservoirs. In fact, many reservoirs are depleted below thepressure predicted with this method. To pressure predicted with this method. Tounderstand the reason behind this, it is helpful to examine the technology ofthe blowdownlimit model and its application to the same SNA analysis. JPT P. 344
Summary This paper introduces the technology defining the gas-well productive limitknown as the productive limit known as the blow-down limit. This limit is thestatic reservoir pressure at which a gas well becomes incapable of unloadingthe fluids that collected during load-up. The theoretical background ispresented, along with field data that presented, along with field data thatsupport the theory. This technology establishes a method for determining theabandonment pressure of a depletion-drive gas reservoir. Introduction The first two parts of this series discussed the theory for predicting whenand why a gas well experiences liquid loading problems and the methods forpredicting problems and the methods for predicting behavior during load-up. Once load-up occurs, corrective action is generally required to return a wellto production. Methods typically used include swabbing, gas lifting, andpumping. In each of these methods, energy pumping. In each of these methods, energy is added to the well/reservoir system to aid in load-fluid removal. Because of the cost of these options, many operators choose an alternativemethod known as blowdown to extend the productive life of the well. In thismethod, the productive life of the well. In this method, the wellhead pressureis reduced enough to induce sufficient reservoir flow to lift the load fluidsfrom the well and to blow the well down. Additionally, the operator mightchoose to shut the well in for an extended period to allow for near-wellborereservoir-pressure buildup, thereby aiding in the blowdown. In this case, thewell/reservoir system energy is used to unload the well. No external energy isadded to the system. As one might imagine, many variables determine the success of a blowdown. The amount of energy available to remove the load fluid, the amount of loadfluid present, the well depth, the gas flow rate, and the amount of liquidfallback play important roles. This paper presents the logic, theory, and fielddata to further the definition of these variables and their effects on thelimits of blowdown. This technology is presented in the form of a new term, thegas-well blowdown limit. Defined in its simplest terms, the blowdown limit isthe Static reservoirpressure at which a gas reservoir is no longer capable ofunloading a well's natural load-up fluids' without external energy (swabbing, gas lift, etc.). The blowdown limit is controlled by the buildup of reservoirpressure in the near-wellbore region, pressure in the near-wellbore region, wellbore hydraulics during blowdown, and chants in the flowing wellheadconditions. As this paper shows, the blowdown limit can be key to determining theultimate recovery from a depletion drive gas reservoir. The decision to makeinvestments and their timing regarding depletion of reserves from low-pressuregas reservoirs can be influenced significantly by the blowdown limit, Theblowdown limit also enhances the understanding of well operations for loadingwells. This understanding alone can maintain well production and increaseultimate recovery. Blowdown-Limit Model Theory Examining the stages of blowdown is useful in mathematically modeling theblowdown limit. As Fig. 1 shows, the blowdown limit is, in many ways, thereverse of the load-up model discussed in Ref. 2. Once a well loads (t=0), theaverage reservoir pressure equalizes with the sandface pressure(PR" "Psf) and the wellhead pressure equalizes with the system pressure(pwf-ps). As time passes, (PR=Psf) and Pe will equalize. passes, (PR=Psf) and Pe will equalize. After a period of shut-in, Psf may become higher than theload-up-induced hydrostatics of the wellbore plus psf if the well is thenopened to the system, the reservoir will begin to flow (t=l). If the reservoircan deliver enough gas under these conditions to change the wellbore flowregime from bubbly to slug flow, then the column of load fluid will begin to belifted from the bottom of the well. As the slug is lifted to the surface and removed from the well, psf isreduced, causing a continued increase in flow from the reservoir (t=2). Assuming that the well can maintain a rate above its critical rate for a periodlong enough to remove the remaining period long enough to remove the remainingload fluid (owing to liquid fallback of the slug), the well will unload itselfcompletely and return to steady-state production (t=3). This proposed blowdownmodel indicates that three criteria must be met for a well to unloaditself.Psf must be capable of increasing (or pwf decreasing) to a point greaterthan the pwf decreasing) to a point greater than the load-up-inducedhydrostatics to set up a differential pressure across the reservoir, which willinduce reservoir flow.The reservoir flow performance in this insteady-state condition must becapable of producing initial wellbore velocities high producing initialwellbore velocities high enough to move the wellbore flow from a bubble-flow toa slug-flow regime. JPT P. 339
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