Abstract
The reservoir formation in a major oilfield in South of Iraq is highly fractured. The operator has set as requirement that any losses had to be cured before drilling ahead. Whenever losses are encountered, drilling is stopped to cure the losses, most of the times spotting at least four cement plugs before drilling ahead are required. The current process leaves the well in an underbalanced condition for a long time posing well control risk. It was necessary to come up with an optimized solution that reduces this exposure.
Drilling the entire reservoir formation to expose all loss zones before spotting cement plugs to cure all the losses was the first step taken. Secondly, since encountering total losses across the reservoir formation was inevitable, redesigning the cement slurry formulation was an objective. Many alternative designs were proposed but were disqualified as some of the chemicals or fibers were not bio-degradable causing some damage to the reservoir. After a consensus between all parties, it was proposed to introduce temperature-degradable fibers into the cement slurry. Pilot tests were performed at maximum anticipated downhole temperature which proved successful.
The analysis results from the lab were approved and one well was assigned for the field test of the proposed solution. The selected well was drilled to expose all the loss zones, losses were encountered as expected, cement slurry incorporated with temperature degradable fibers was spotted which resulted in all the losses getting cured at the first attempt. This solution was tested in all subsequent wells drilled on the field achieving the same successful result. This solution has since been adopted for curing total losses encountered across the reservoir formation in this field as it ensures that less time is spent on curing losses, less cement material is consumed and those wells are delivered quicker and at reduced cost. This solution has led to average savings of approximately 5 days per well drilled subsequently on this field. Previously it took an average of 166 hours to restore fluid well control barrier (see wells 1 and 2 in figure 2), these days in 52 hours fluid well control barrier is fully restored barrier (see wells 3 and 4 in the attached image). Well control risk is greatly reduced.
This paper will show how minor changes to operational procedure and improvement to conventional solutions can greatly impact well control and the quick restoration of well barrier element when drilling across highly fractured reservoir formation. It will also discuss the comprehensive analysis of the loss zones, the cement laboratory analysis, the trial jobs, the measures that were put in place to reduce operational risks in order to ensure that the job was executed successfully.
Multiphase Flow Law and Well Control Risk Analysis in Deep Water Gas Hydrate Horizontal Well While Drilling