New Field Methods for a Maximum Lift Gas Efficiency Through Stability
Authors: Garnaud F. , Casagrande M. , Fouillout C. , Lemetayer P. 
Published: December 2007

Abstract
Well stabilisation significantly contributes to a safer well operation, increases the lift-gas efficiency and avoids drawbacks on wells or facilities. Gas lift valve optimisation is a well known mean to stabilize wells. However, it has limits even when using the new turbo valve. A set of expert adjustment sequences has been built to cope with any situation. It modulates both oil and gas chokes especially during transient phases to achieve well stabilisation Thus, a single well optimisation is combined with a global optimisation including the well known lift gas allocation. Experience from many wells for several years show that stabilisation significantly increases lift gas efficiency. Sequences have proved to be efficient to stabilise wells even without of design equipments, with very low injection rate and under other difficult conditions. Extended field experience also confirms that the sequences are suitable for any well. A gas-lift simulator has been used for several years and has widened knowledge of field operators. Sequences simultaneously, continuously and quickly combine several actions accounting for several measurements. Therefore, an automated operation of wells has been developed to achieve all actions more efficiently.

Introduction
Low lift gas injection rate with maximum efficiency is an issue especially on mature fields. It becomes critical with low oil prices and scarce lift gas.
Low injection flow rate is well known to emphasize instability risk. Conversely, unstable production mode of gas-lifted wells causes many drawbacks. First of all, surge is not in agreement with smooth operation. Therefore, it implies safety aspects and shut down risks. Secondly, unstable mode often decreases sharply the lift gas efficiency. Difficulties with lift gas allocation computation due to instabilities are also usual. Well instabilities induce other drawbacks on facilities and well operation or equipments.
As a result, much theoretical research has been done about gas-lifted well stability. However, results and recommendations are difficult to apply because they induce usually a risky or/and costly operation to fix the problem. For example, figure 1 shows surge phenomenon following the start-up phase of #53well. A simple analysis easily relates surging to an unstable lift gas flowrate into the tubing. A further analysis might conclude that out-of-design equipment is a possible reason. Therefore, such recommendation will not be often applied.
Much pragmatic research has been done as well by the field personnel to solve or only to overcome the instabilities. Field solutions are mainly based on a lift gas rate increase or oil choking. However, they are usually not acceptable on a permanent basis due to lift gas cost and limited availability or due to back pressure increase. In most cases, too much gas is injected or the production flow rate is not maximised.
Expert analysis has been combined to field observations to modulate adjustments just as required. Transient phenomena analysis has been especially deepened. Adjustment sequences have been built to cope with very small amount of lift gas, out-of-design equipment or any difficult condition.
Statement of theory and definitions
Existing theoretical work about well stabilisation For a long time, stability has been approached through mathematical models. More recent work include enhanced derivative equations. These approaches were trying to define criteria for stability.
However, latest theoretical developments are based on transient simulation of the whole well system. Such approach clarifies transient phenomena especially during the start-up phase. Casing heading such as on figure 1 can be easily simulated. For example, it helps identify possible problems during unloading and allows corrections to the design before it is run in hole. P.175