This paper describes the field implementation of a novel gas lifting strategy used to enhance production from water flooded reservoirs. A patented "one level" gas injector, initially designed and tested for stripper well applications, was redesigned and successfully employed for a water flooded field. One of the strengths of the novel gas injector is its simplicity and robustness. More importantly, the application of this technology resulted in a productivity increase of 40%, as compared to commonly used rod pumps and maintenance costs were considerably reduced. The economic and theoretical criteria used to select candidate wells for the novel gas lift, to design surface equipment, and to optimize gas injection (including the start-up procedure) are discussed in some detail. A comparison is made between the theoretical gas lift performance curve as based on Taitel-Dukler two-phase flow pattern identification, and field results. The limiting criteria for gas lifting strategy, as based on theoretical and practical considerations, demonstrate the effectiveness of this novel technique, and indicate the range of conditions over which it can be applied successfully.
In a previous laboratory and theoretical study a novel gas lifting injector and strategy for increasing productivity of wells with limited reservoir pressure and high GOR was discussed. Field implementation of the one-level gas injector tool requires in-depth assessment of gas-liquid flow in the producing tubing and in the injector. 1his assessment demonstrated the feasibility and economics of the system. To find acceptable candidate wells and to decide upon the depth of the injector and compressor characteristics, design criteria developed during a previous laboratory-theoretical study were used. The design criteria included:
production well history and economics,
static fluid level (where available, bottom hole flow pressure or the inflow performance relationship-IPR-),
depth of the injector and submergence,
tubing-casing geometry and
two-phase flow pattern and pressure drop (vertical lift performance -VLP-).
The submergence, defined as the ratio of the distance between the static fluid level and the injector to the distance between the injector and surface separation, was found to be one of the most important criteria for obtaining a quick estimate of the gas lifting productivity and therefore the potential success of the application'. Overlooking the "submergence criteria" during preliminary testing of the novel gas lifting tool and strategy lead to unsatisfactory results as described below: 1. In the Gooseberry Lake field (completion at approximate 923 mKB and fluid level at 540 mKB) a submergence of only 0.35 was achieved by positioning the injector at 835 mKB; for this particular situation, the static fluid level was too low for implementing a risk-free, efficient gas lifting strategy. Low fluid level and production history indicated that the well should not even be considered for gas lifting. Errors in the initial measurements of the static fluid level (initiallyestimatedat316 mKB instead of 540mKB) as well as non-technical considerations were used for the selection. The futile effort to gas lift the "Gooseberry Lake" well demonstrated that previous laboratory and theoretical conclusions suggesting a minimum of 0.5 submergence as a primary (but not unique) well selection criteria should be respected for selection of potential site selection.
