In the Alaskan North Slope field of Nikaitchuq, the standard shut-down strategy of oil producers was to inject warm diesel inside the tubing of the wells for freeze prevention of the tubing. The procedure requires that a Gas Lift Valve (Shear Orifice Valve) located at 2,000 ft be ruptured to displace the tubing fluid inside the annulus. It was desired to evaluate whether this procedure could be avoided to reduce both operational risk and costs associated with this strategy.
An evaluation was performed using a transient fluid-dynamic simulator based on oil producers. Based on geothermal gradient acquired by DTS fiber optic technology and considering the salinity of formation water, the depth of the tubing under freezing risk was defined. Simulations were performed for both the rate of cooling of the produced fluids in the tubing and the time required to reach ice formation conditions.
In the paper, we will show that the sweeping effect of gas during production does not allow for water accumulation at the x-mas tree and surface piping. In addition, the vertical geometry in the tubing results that any water present falls below the permafrost line during shut-in conditions. As no bulk water is present in the well inside of the ice stability region, the risk of a blockage from ice is not present during a planned shutdown and the previous preservation strategy is not required.
The change in the standard operating procedure for planned shutdowns was successfully applied, leading to a marked reduction of costs and reduced down-time with a consequential recovery of otherwise lost production.