Water Shut-off with Polymer Gels in A High Temperature Horizontal Gas Well: A Success Story

Abstract

Abstract A horizontal hot deep gas well was not on production due to high water cut. The well had a bottom hole temperature of 300°F (149°C) and a bottom hole pressure of 7,000 psi. The well was completed into a carbonate reservoir with an average permeability ranging from 2 to 3 mD. It was completed with a 7 in liner at a measured depth (MD) of 13,611 ft. The open-hole section extends from 13,611 to 16,456 ft. After the well completion operation, water was observed entering the open-hole section at the toe at a depth of 14, 677 ft. The exact water producing zone was identified by the resistivity log run on the subject well. Therefore, a mechanical packer was set in the open-hole section at 14,677 ft to isolate the water producing interval. The packer did not solve the problem. The water production continued to occur. Due to their versatility, polymer gels were considered for remediating this problem and to revive the well. A gel system based on a low molecular weight polymer crosslinked with an organic crosslinker was considered. A serious challenge was the high temperature of the reservoir. The high temperature conditions imposed the use of a retarder to elongate the onset gelation time during the polymer gel placement. The available mixing waters in this field contained significant amounts of salts (a total dissolved solids content of 1,188 ppm). These solids caused compatibility problems upon contact with the commercially available retarder. Therefore, a new retarder was developed. The retarder was cost-effective, efficient and compatible with the available saline mixing water. The retarder's placement was examined in porous media under conditions similar to those encountered in the field (55 minutes placement time). The gel did not show any injectivity problems indicating the efficient nature of the retarder. The initial recommended recipe of the gel showed syneresis due to the extra amount of the crosslinker suggested. This was addressed by reducing the crosslinker concentrations in the gel recipe. The treatment utilized a pre-flush to displace the reservoir fluids around the wellbore and to cool down the near wellbore area. This helped reduce the near wellbore area temperature from 300 to 240°F according to the temperature simulations. The gelant contained 250 gal/1000 gal of polymer with a 10 gal/1000 gal of crosslinker. After the gelant placement, the well was shut-in for three days. Once opened, the well showed an increase in gas production by a factor of 7.7 with a water cut reduction of 42 %.