Abstract

Oryx Energy Company has drilled, completed, and produced over 150 horizontal Austin Chalk wells in the Pearsall Field of South Texas. Although rod pumping is the predominant means of artificial lift for these wells, selected wells are equipped with submersible pumps to maximize production in a competitive reservoir. In 1989, the first submersible pump was installed in a horizontal well in the Field, and it was quickly discovered that high volume lift operations in gassy, naturally fractured horizontal wells offer unique challenges. These challenges included unpredictable changes in rates, heavy slugging and frequent pump cycling.

This paper reviews experiences with ten submersible installations in horizontal Chalk wells of varied operating conditions. Actual field performance of the installations will be discussed with special emphasis on the iterative design process that led to a dip tube design which successfully tackled the aforementioned challenges.

Early Experiences

During July 1989, an electric submersible pump (ESP) (Figure 1) was installed in a Dimmit County well (#1) to increase production rates over gas lifted volumes of 900 BOPD / 100 BWPD. During the first week of submersible lift (SL) operation, the well averaged 1300 BO / 200 BW / 700 MCF with pump intake pressures (PIP's) in excess of 600 psig. As PIP's dropped below 600 psig, the pump began cycling on and off due to large gas slugs unloading up the casing annulus (Figure 2). At that time, the surface facilities were modified to handle the increased gas rates, and numerous adjustments were made to the variable speed drive (VSD) and tubing / casing choke sizes in an unsuccessful attempt to reduce pump cycling. Three weeks after start-up, the well was cycling 12 times per day with the following daily production:

Pumping up the tubing at 500 BO / 241 BW / 192 MCF Slugging out the annulus at 441 BO / 39 BW / 1889 MCF TOTAL RATE 941 BO / 280 BW / 2081 MCF

The fluid rates continued to vary, but operating personnel were able to eliminate cycling by "locking out" the motor current underload protection. In this case, annular slug flow prevented the motor from overheating in low current operation. This technique was not considered a viable, long-term operating strategy due to the unpredictability of slug volumes and was therefore not used on other installations. After 47 days, the motor failed as a result of wellbore fluids filling the labyrinth protector in this cycling, gassy environment. Only bag-type protectors were used in subsequent SL installations in the Pearsall Field.

After the failure, a modified ESP installation was run in the well that incorporated a tapered pump, rotary gas separator (RGS), a shroud around the motor (for motor cooling in 9–5/8" casing), and tandem protectors. A 1/8" capillary tube with purge chamber was run below the motor to provide PIP data at the surface (NOTE: The capillary tube was continuously purged with helium to keep out liquids). The pump was lowered approximately 700 feet below the kick-off point (KOP) and set in a section at 33 degree deviation and a dog-leg severity of 4.5 degrees per 100 feet (Figure 3). Additional drawdown was achieved by lowering the pump, but it still cycled 10–15 times per day.

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