We must comment a bit about gas lift systems because they are in widespread use and have a significant impact on the facility process. Figure 2-19 is a diagram of a gas lift system from the facility engineer’s perspective. High-pressure gas is injected into the well to lighten the column of fluid and allow the reservoir pressure to force the fluid to the surface. The gas that is injected is produced with the reservoir fluid into the lowpressure system. Therefore, the low-pressure separator must have sufficient gas separation capacity to handle gas lift as well as formation gas.
If gas lift is to be used, it is even more important from a production standpoint that the low-pressure separator be operated at the lowest practical pressure.
Figure 2-20 shows the effects of wellhead backpressure for a specific set of wells. It can be seen that a one psi change in well backpressure will cause between 2 and 6 BFPD change in well deliverability.
The higher the injected gas pressure into the casing the deeper the last gas lift valve can be set. As shown in Figure 2-21, for a typical well the higher the design injection the higher the flowrate. Most gas sales contracts are in the 1,000 to 1,200 psi range. Therefore, the process must be designed to deliver the sales gas at this pressure. As seen from Figure 2-21 at about this range a rather large change in gas injection pressure is necessary for a small change in well deliverability. In the range of pressures under consideration (approximately 65-psia suction, 1,215-psia discharge) a 1-psi change in suction pressure (i.e., low-pressure separation operating pressure) is equivalent to a 19-psi change in discharge pressure (i.e., gas lift injection pressure) as it affects compressor ratio and thus compressor horsepower requirements. A comparison of Figures 2-20 and 2-21 shows that a 1-psi lowering of suction pressure in this typical case is more beneficial than a 19-psi increase in discharge pressure for the wells with a low productivity index (PI) but not as beneficial for the high PI wells. The productivity index is the increase in fluid flow into the bottom of the well (in barrels per day) for a 1-psi drawdown in bottomhole pressure.
Figure 2-22 shows the effect of gas injection rate. As more gas is injected, the weight of fluid in the tubing decreases and the bottomhole flowing pressure decreases. This is balanced by the friction drop in the tubing. As more gas lift gas is injected, the friction drop of the mixture returning to the surface increases exponentially. At some point the friction drop effect is greater than the effect of lowering fluid column weight. At this point, injecting greater volumes of gas lift gas causes the bottomhole pressure to increase and thus the production rate to decrease. Each gas lift system must be evaluated for its best combination of injection rate, separator pressure, and injection pressure, taking into account process restraints (e.g., need to move the liquid through the process) and the sales gas pressure. In the vast majority of cases, a lowpressure separator pressure of about 50 psig and a gas lift injection pressure of 1,000 to 1,400 psig will prove to be near optimum.