Gas Lift Design Ch-5 - Fundamentals of Gas Lift Engineering PDF

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Fundamentals of Gas Lift Engineering...

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5

Total system analysis applied to gas lift design The main goals in the design of a gas lift well are to find the depths, area ratios, and calibration pressures of the operating and unloading valves. The gas lift valve through which gas is injected during the normal operation of the well is called the “operating” valve and its depth is referred to as the “point of injection depth.” All valves above the operating valve are called “unloading” valves because they are only used to unload the well. The unloading operation consists in displacing the liquids in the casing–tubing annulus with injection gas until the annular liquid level reaches the point of injection depth. The unloading operation is explained in chapter: Design of Continuous Gas Lift Installations, while design methods for continuous and intermittent gas lift are explained in detail in chapters Design of Continuous Gas Lift Installations and Design of Intermittent Gas Lift Installations, respectively. Before design calculations can be performed, it is necessary to know the well’s target liquid production, the operating injection point depth, and the required injection gas flow rate. All of these parameters can be found following the calculation procedures presented in the chapter. These procedures take into consideration all the gas lift system’s components that play a role in the production of the well: the reservoir, the production tubing, the flowline, and the conditions at the separator or flow station. The explanations given in the chapter focus mainly on the determination of the point of injection depth, the well’s liquid production, and the corresponding injection gas flow rate, which are all explained in Section 5.1. Other types of analyses, with different objectives, that take into account all system’s components are also presented in the first part of the chapter. These additional analyses are usually very helpful in designing and troubleshooting activities. At the end of the chapter, in Sections 5.2 and 5.3, different examples of the effect that each system’s component has on the operation of the well, as well as an example problem, are presented. The reader should be familiar with IPR and outflow curves. The explanation given for Fig. 3.3 describes how outflow curves are constructed. In the chapter, the produced gas–liquid

Fundamentals of Gas Lift Engineering. http://dx.doi.org/10.1016/B978-0-12-804133-8.00005-1 Copyright © 2016 Elsevier Inc. All rights reserved.

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mixture is assumed to flow up the tubing while the gas is injected down the casing–tubing annulus; but the theory presented here works for annular or tubing production and, to avoid confusion, the pressure of the produced gas–liquid mixture is called the “production” pressure and the pressure of the injection gas is simply called the “injection” pressure.

5.1 DETERMINATION OF THE DEPTH OF THE OPERATING POINT OF INJECTION The first step in the design of a gas lift well is finding out the optimum depth of the “operating” valve which, as explained earlier, is the final point of injection once the well has been unloaded. This can be done by following procedures that (with a few minor variations) can be applied to all types of gas lift valves. Together with the determination of the injection point depth, the production liquid flow rate and the required injection gas flow rate are simultaneously calculated. The main objective at this stage is to locate the operating point of injection as deep as the available surface injection pressure allows it to be. The deeper the point of injection is, the more efficient the gas lift method becomes because a greater drawdown can be achieved; however, it is not always possible to inject gas at the deepest point available in the well because of one, or several, of the following reasons: j j j

j

The available injection pressure might not be large enough. The maximum gas flow rate might be limited. Mandrels and/or gas lift valves might not be able to withstand downhole conditions at great depths. The inclination angle of the tubing might be greater than 60–70 degrees (with respect to the vertical), making it very hard for wireline operators to install or retrieve gas lift valves with conventional wireline tools. Although new wireline equipment are making it possible to install and retrieve gas lift valves in horizontal tubing strings, injecting gas at very large inclination angles might actually increase the bottomhole flowing pressure because: (1) the friction component of the pressure drop is increased, and (2) the multiphase flow tends to stratify, increasing the liquid holdup (therefore increasing also the hydrostatic component of the pressure drop along the production tubing).

The procedures described here assume unlimited gas flow rate availability. If that is not the case, these procedures would basically be the same, but it would simply be necessary to check, at each step, if the maximum injection gas flow rate has been reached so that it will not be exceeded.

5.1 Determination of the depth of the operating point of injection 153

■ FIGURE 5.1 Production pressure curves for different gas/liquid ratios GLR (all curves have the same liquid flow rate and wellhead pressure).

Before getting into the details of the calculation procedures, a few explanations regarding pressure traverse curves along the production tubing are presented. The effect of increasing the total gas/liquid ratio (keeping the wellhead pressure and the liquid flow rate constant) is shown in Fig. 5.1. As the gas/liquid ratio is increased, the tubing pressure decreases until a limit is reached in which the tubing pressure starts to increase. The curve with the minimum production pressure possible is called the “minimum gradient curve.” As shown in Fig. 5.1, the gas/liquid ratio needed to reach the minimum gradient curve increases for deeper depths along the tubing. But if the wellhead pressure is not constant (because the pressure losses in the flowline are not negligible and should be considered), there might be an increase in the wellhead pressure that has the opposite effect the gas/ liquid ratio has on the production tubing pressure, as the injection gas flow rate is increased from very low values. In this case, as the gas/liquid ratio is increased, the pressure drop along the surface flowline increases, therefore increasing the wellhead pressure and causing a displacement of the vertical pressure curves to the right of the graph, as can be seen in Fig. 5.2. It is possible then that, thanks to the increase of the pressure drop in the flowline, the bottomhole flowing pressure stops decreasing before reaching the minimum gradient curve as the gas/liquid ratio is increased from very low values. The liquid flow rate is kept constant in Figs. 5.1 and 5.2 for didactical purposes. In reality, any change in the injection gas flow rate will cause a change in the liquid production due to the change in the bottomhole flowing

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■ FIGURE 5.2 Production pressure curves for different gas/liquid ratios (the liquid flow rate is kept constant but the wellhead pressure is allowed to change with increasing gas flow rate).

pressure and the way the flow from the reservoir adapts to this new pressure. Understanding how these interactions between the different components of a gas lift well take place is precisely the main objective of the chapter. In Sections 5.1.1 and 5.1.2, several procedures, with increasing level of complexity, that can be used to find the depth of the point of injection, are presented. The intention in these sections is to familiarize the reader with the role of each system’s component. The actual procedures currently being used by commercially available software to find the depth of the point of injection are explained at the end of Section 5.1.3, after some useful additional operations are explained.

5.1.1 Determination of the injection point depth assuming constant wellhead production pressure When the wellhead is near the separator or the flowline length and diameter are such that the pressure drop along the flowline is negligible, the wellhead production pressure can be assumed constant. This is the simplest case possible and an ideal condition to illustrate the required calculations to find the injection point depth. The pressure–depth diagram that describes the location of the point of injection is shown in Fig. 5.3. All procedures presented in the chapter can be easily understood by referring to this type of diagram. Procedure using several gas/liquid ratios to connect the wellhead production pressure to the production pressure at the injection point depth. The

5.1 Determination of the depth of the operating point of injection 155

■ FIGURE 5.3 Location of the operating gas injection point.

procedure that illustrates how the depth of the operating point of injection is found using this approach is as follows: j

In a pressure–depth diagram, like the one shown in Fig. 5.3, the available surface injection pressure and the static reservoir pressure are plotted. The available surface injection pressure is the minimum pressure at the injection manifold (taking pressure fluctuations at the manifold into consideration) minus the following factors: (1) from 50–100 psi (so that a sufficiently large differential pressure between the manifold and the well is available to provide an adequate injection gas flow rate when the first valve is uncovered). A differential pressure larger than 100 psi might be recommended in cases where the gas lift system’s pressure is not very stable; and (2) The number of unloading valves times the required surface injection pressure drop per unloading valve (in case of injection-pressureoperated valves). Because the total number of unloading valves is not known a priori, a reasonable first guess is used to start the iterations. The number of unloading valves is determined during the mandrel spacing procedure (explained in chapter: Design of Continuous Gas Lift Installations) performed after the present calculations are finished. If during the mandrel spacing procedure the point of injection depth calculated here is not reached, all the calculations that are described next should be repeated with a lower (more realistic)

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j

j

j

j

surface injection pressure. This is why the global design (which consists of the total system analyses explained in this chapter plus the mandrel spacing procedures explained in chapter: Design of Continuous Gas Lift Installations) is an iterative process. From the available surface injection pressure, several injection pressures are calculated at different depths. This gives the gas injection line along the casing–tubing annulus (assuming that the gas is injected down the annulus). The injection pressure at depth is usually determined as a static gas column, but there are cases in which frictional losses are not negligible, for example: (1) very large injection gas flow rates, (2) gas is injected down the tubing and the liquid is produced up the annulus, or (3) gas is injected down a parallel string, see Fig. 6.46c. An additional 100 psi is subtracted from the injection pressure line found in the previous step to determine the gas injection line that is actually used in finding the point of injection. This pressure drop corresponds to the minimum pressure drop that should take place through the gas lift valve so that the injection gas is capable of entering the production tubing. To avoid instability problems (like the one shown in Fig. 8.4), a safer pressure drop across the gas lift valve will be one not smaller than 20% of the value of the injection pressure at the maximum depth where a gas lift valve can be installed (the use of the instability criteria, as explained at the end of chapter: Design Of Continuous Gas Lift Installations, might be required to determine the exact value of the pressure drop across the gas lift valve to use in the determination of the depth of the point of injection). For the purpose of this introduction, 100 psi will be taken as the minimum pressure drop across the operating gas lift valve. From the IPR curve, the bottomhole flowing pressure is calculated for different liquid flow rates (q1, q2, and q3, for example). These pressures are plotted at mid perforations’ depth. Then, using the formation gas/liquid ratio, production pressure curves are calculated from the bottomhole flowing pressures (for each liquid flow rate being considered) to the point where they intersect the gas injection line; see Fig. 5.4 (q1, q2, and q3 are shown in Fig. 5.4a, b, c, respectively). Using a multiphase flow correlation for each liquid flow rate, the production pressure is calculated from the wellhead to the gas injection line for different total gas/liquid ratios. This is done separately for each liquid flow rate. At each liquid flow rate, there is one and only one total gas/liquid ratio for which the pressure curve

5.1 Determination of the depth of the operating point of injection 157

j

coming from the perforation (with the formation gas/liquid ratio) is connected to the production pressure curve from the wellhead (with the total gas/liquid ratio), so that the injection gas flow rate and the depth of the point of injection are simultaneously determined for each liquid flow rate. The procedure described in the previous step is repeated for each liquid flow rate, in increasing order (q1, q2, and q3 are respectively shown in Fig. 5.4a, b, c), until a liquid flow rate is found for which the wellhead production pressure is connected to the bottomhole flowing pressure with the minimum gradient curve. For larger liquid flow rates, there is no way of connecting the wellhead pressure to the bottomhole flowing pressure because the pressure at the intersection of the “minimum gradient curve” (from the wellhead) with the gas injection line is greater than the pressure at the intersection of the “production– pressure curve” (from the perforations) with the “gas injection line,” (Fig. 5.4c). Notice that as the liquid flow rate increases (q1 < q2 < q3), the production pressure curves become “heavier” (more horizontally inclined).

The bottomhole flowing pressures for different gas/liquid ratios and different liquid flow rates are superimposed on the IPR curve in Fig. 5.5b. GLRMIN corresponds to the formation gas/liquid ratio while GLRMAX is the gas/liquid ratio at which the pressure traverse curve with the minimum pressure gradient is found. GLRMIN and GLRMAX curves seem to be independent, parallel curves and not a continuous curve like the ones shown in Fig. 3.3. This is due

■ FIGURE 5.4 Procedure to find the liquid production with the minimum gradient curve. (a) Liquid flow rate q1, (b) Liquid flow rate q2, (c) Liquid flow rate q3.

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■ FIGURE 5.5 Determination of the injection point depth with variable gas/liquid ratio.

(a) Pressure traverse curves, (b) Inflow-outflow curves.

to the fact that points in Fig. 5.5 correspond to different injection point depths while the ones in chapter: Multiphase Flow are for a constant gas injection point depth. The point at which the maximum liquid flow rate is obtained corresponds to the point where the GLRMAX curve intersects the IPR curve. This takes place between liquid flow rates q2 and q3 as can be appreciated in Fig. 5.5b. The liquid flow rate so obtained is the maximum rate the well can produce for the available injection pressure. This procedure also gives the injection gas flow rate because it is equal to the liquid flow rate found in this procedure times the difference of the total gas/liquid ratio to reach the minimum pressure gradient minus the formation gas/liquid ratio. Procedure using the minimum pressure gradient at each step. The determination of the injection point depth (with constant wellhead pressure) can also be illustrated using the following approach: j

j

j

In a pressure–depth diagram like the one shown in Fig. 5.3, the static reservoir pressure and the surface available injection pressure are plotted. The available surface injection pressure is the same pressure defined in the previous procedure. From the surface available pressure, injection pressures are calculated at different depths to find the gas injection line along the annulus. The injection pressure at depth is usually determined as a static gas column; but, as explained in the previous procedure, there are cases in which frictional losses are not negligible. 100 psi (or 20% of the gas injection pressure at the maximum depth where a gas lift valve can be installed) is subtracted from the line found

5.1 Determination of the depth of the operating point of injection 159

j

j

in the previous step to give the gas injection line that is actually used in finding the point of injection. As in the previous procedure, this pressure drop is the minimum pressure drop that should take place through the gas lift valve. From the wellhead production pressure, pressure traverse curves are calculated for several probable liquid flow rates (q1 < q2 < q3), all of them with the injection gas/liquid ratio that gives the minimum gradient curve. These curves are plotted from the wellhead to the point where they intersect the annulus gas injection pressure line minus 100 psi (or minus 20% of the gas injection pressure at the maximum depth where a gas lift valve can be installed). From that point to the perforations, production pressure curves are plotted with their respective liquid flow rates (but with the formation gas/liquid ratio) to obtain the flowing bottomhole pressures for the different liquid flow rates that were considered. The bottomhole flowing pressure for each liquid flow rate is plotted together with the IPR curve of the well, see Fig. 5.6b. The intersection of the IPR curve with the curve that joints all of the bottomhole flowing pressures (at GLR MAX) determines the liquid production, the required injection gas flow rate, and the depth of the point of injection.

Procedure using equilibrium curves. The minimum-gradient production pressure curves, for different liquid flow rates, are plotted from the wellhead production pressure to the bottom of the well. Each of these curves should intersect its corresponding curve (the one with the same liquid flow rate)

■ FIGURE 5.6 Determination of the injection point depth with the minimum gradient curve. (a) Pressure traverse curves, (b) Inflow-outflow curves.

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■ FIGURE 5.7 Determination of the injection point depth using the minimum-productionpressure-gradient equilibrium curve. (a) Pressure traverse curves, (b) Inflow-outflow curves.

plotted from midperforations’ depth using the formation gas/liquid ratio and starting at the flowing bottomhole pressure predicted from the IPR curve for each liquid flow rate. The curve obtained by joining all the intersection points corresponding to each liquid flow rate is called “the equilibrium curve with variable injection gas flow rate.” The intersection of this equilibrium curve with the injection pressure line (which is the pressure in the annulus minus 100 psi or minus 20% of the gas injection pressure at the maximum depth where a gas lift valve can be installed) corresponds to the injection point depth, see Fig. 5.7. The equilibrium curve presented in Fig. 5.7 is the curve that guarantees the maximum possible liquid production for a given injection pressure. Each point on this curve corresponds to a different liquid production and injection gas flow rate. There is another type of...