This paper will detail the successful operation to remove a barite plug from this wellbore using a viscoelastic fluid, with true yield stress properties. Extensive field rheologies, pumping rates, and pressures were captured; and compared with those predicted by modeling. The mechanical and chemical maintenance of the fluid system during the operation will also be discussed.
The development of this fluid enabled a coiled tubing intervention to go forward, as planned. In contrast to an earlier attempt, the coiled tubing successfully reached total depth (TD) while properties stayed within safe operating parameters. The milling operation was carried out, with over 185 ft of hole being recovered from the initial coiled tubing tag at 19,412 ft. At no time was there any danger of ‘sticking the coiled tubing’ or being unable to circulate due to excessive friction pressures.
The successful field application of this technologically advanced fluid system in combination with sophisticated computer engineering software, gives the industry a new tool in attempting deep HTHP coiled tubing workovers.
Tuscaloosa Trend deep gas wells are characterized by high temperatures, >350°F, and high pressures, >15 lb/gal equivalents. H 2S in concentrations as high as 15 ppm, is also a common problem with these wells.
The high pressure regime and hazardous H2S encountered while drilling these wells has caused the operating companies to respond with higher than normal safety margins when selecting a mud weight. In the case of the well reviewed for this paper the bottomhole section was drilled with 19.0-lb/gal oil-based mud (OBM). The reservoir pressure equated to a 16.0-lb/gal. Almost 2,000 bbl of 19.0-lb/gal mud was lost to the reservoir while drilling the interval. Concomitant with this was the suspected dehydration of barite in the perforation tunnels and even encroaching into the well bore. This wellbore encroachment was verified by logging runs to gauge the well diameter across the interval.
Attempts to produce this well through the damage were unsuccessful, and plans for a coiled tubing (CT) intervention were formulated. As will be detailed in the remainder of this paper, the first intervention was unsuccessful and well operations were suspended.
As part of the planning for the next attempt, a milling fluid, thermally stable at greater than 400°F, was developed to remove the barite plug above the interval. Maintenance of the rheological properties at high temperature and shear was deemed critical to the task of successfully carrying the 4.6 sg barite cuttings to the surface. Additionally this fluid needed to exhibit superior lubricious properties to enable the coiled tubing to reach the well's plugged back total depth (PBTD) of 19,710 ft. The previous attempt to perform this workover using a near-Newtonian fluid had failed due to the inability to reach the top of the barite plug at 19,412 ft. Coiled tubing pickup weights had reached 80% of maximum over pull at the liner top at 16,231 ft and it was deemed too risky to continue.
Laboratory work commenced using potassium formate as the base brine. Various viscosifier loadings, thermal extenders and anti-oxidants were then added. Once a suitable fluid was attained with regards to thermal stability, a computer wellbore simulator was used to model its rheological properties. The goal in this modeling was to determine what pumping rates could be sustained during the milling operation. The laboratory testing and the computer modeling indicated that this fluid would perform within the ‘hydraulic window’ of the coiled tubing by production tubing geometry and a decision was made to proceed with the workover.
The first CT operation consisted of two runs in an attempt to reach TD and displace the drilling fluid. Neither run was able to reach bottom due to excessive overpull on the coil. It is suspected that the dogleg section of the new sidetrack was corkscrewed and caused excessive friction forces that ultimately resulted in the CT being unable to reach depth as required.