Optimal Dead-Leg Tubing Length in Long Perforated Completion Intervals
Matt Vivian
Alec Walker
Abstract
Dead-Leg Tubing Configurations are a good solution to lift liquid below top perforations in long multi-stage fracture treatment wells; however when the entry point is set too shallow it results in liquid across the majority of the production interval and reduced production due to high Bottom Hole Pressures (BHP). Long Perforated Completion Intervals common to gas wells present challenges for High Liquid Gas Ratio (LGR) wells as plunger lift cannot unload sufficient fluid to total depth. Energy Added Lift solutions (gas lift and pumps) would be ideal, but typically fail to meet economic hurdles in gas wells.
Often operating companies setup the well configuration as a Dead-Leg using standard tubing flow from surface to the top perforation and annular flow between casing and tubing string run to bottom perforations to fill dead space as velocity reduction. While the annular flow is more effective than traditional tubing at top perforations, the Turner Critical Rate is still nearly double that of the upper tubing string and thus ineffective at maintaining the liquid level near bottom perforations. Therefore it is best to minimize the Dead-Leg length and flow the full well production down around the end of tubing and cycle a plunger as deep as possible.
In the Pinedale Anticline Field of the Green River Basin over 100 wells have been configured with Dead-Leg entry points and successfully applied plunger lift above the shallower entry point. With a 6,000' perforated interval the Dead-Leg had been placed at 25, 50, and 75% of the completion interval based on the LGR. It has been found the well dictates optimal entry point based on downtime and slugging, but is best setup with as deep an entry point as the LGR can handle and then move the entry point uphole. Findings of field trials will be presented.