An openhole gravelpack (OHGP) gas well was planned as part of an infill drilling campaign on a mature Norwegian Continental Shelf field. A geological pilot hole unexpectedly identified a significant pressure differential between two reservoir intervals. This paper describes an innovative modification of the lower completion, within a short turnaround time, in order to manage the clean-up of the reservoir intervals and limit crossflow. Calculations based on the pilot hole results predicted that the low pressure reservoir would not flow until there was significant depletion in the high pressure reservoir. This risked formation damage due to delayed clean-up. Additionally, there was potential for very high crossflow rates that risked mechanical damage to lower completion equipment and/or causing formation damage. There was insufficient time to completely redesign the completion. A solution, supported by simulations, showed that a fixed choke in the lower completion would enable immediate clean-up of both reservoir intervals. Additionally, aplug had to be set in the gravel-filled annulus to prevent flow diverting around the fixed choke. These modifications would reduce the potential crossflow rate to an acceptable level. The OHGP was performed as originally planned. A wireline tool was run to inject an epoxy resin plug into the gravel and the fixed choke was then set at the same depth. The well was cleaned up as planned to the drilling rig, with both reservoir intervals observed to be producing. The choke toolstring included an additional flow area that automatically opened after a pre-defined time delay. Simulations predicted the pressure differential at this time to be significantly lower. Reducing the choking effect in this way, once the risks from crossflow at the start of well life had been minimised, avoided hindering production in later well life. The well has performed as expected with no indications of production impairment having occurred, despite the initial period of high differential pressure between the reservoir intervals. This is believed to be the first injection of epoxy resin into a newly completed gravelpack. Coupled with the implementation of the two-sized choke it has been possible to manage a problematic reservoir pressure differential in a new well without resorting to costly and lengthy redesign of the completion.
Gas breakthrough for horizontal oil producers can sometimes be an advantage for keeping the well producing, particularly in late life when the reservoir pressure is low and the water-cut is high. However, this additional gas may be unavailable after a long shut-in due to the gas front migrating upwards from the near wellbore. This results in a much lower inflow of gas during well start-up, which can make it difficult to overcome the hydrostatic head to kick off the flow. This paper is intended to summarize the study of such a case where a high GOR horizontal well failed to start up after a long shut-in. The study considered all given potential causes of the start-up failure such as mechanical restrictions and the presence of a hydrate plug in addition to the assumption that only the low GOR oil rim would contribute to the inflow during the early phase of the start-up. A commercially available advanced transient multiphase flow simulator was used to simulate each scenario and the results were then compared with the field measurements. It was determined that the missing reservoir gas influx at the start-up was the most likely reason for the failure of the well to restart. This conclusion has provided valuable input to the well intervention decision making. After the study was completed, a light well intervention was performed on the well and it was confirmed that there was no mechanical blockage or restriction in the wellbore.
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