A methodology incorporating drilling, cementing and completion techniques helped to mitigate gas hazards in three Gulf of Mexico wells.

Eugene Island Block 273 is a mature natural gas field located 75 miles (120 km) offshore in the Gulf of Mexico. In early 2001, while drilling a developmental well in the block, the drilling rig Ensco 51 was evacuated and subsequently sustained severe damage. After cementing a third casing string at a depth of 1,650 ft (503 m), an uncontrolled annular flow occurred, causing rig personnel to be evacuated and a fire to ensue.
Known shallow gas accumulations pose a unique challenge as they are drilled. When proper precautions are taken, risks are mitigated. When these accumulations are formed by migrating gas from offset wells that lack zonal isolation, they become an unknown. They then become a greater formidable challenge when the fracture gradient and pore pressure become nearly equal. In these cases, gas can broach the casing and cause a blowout (Figure 1).
A new methodology was developed to address this concern and was used in a three-well program in the Eugene Island block.
The technique
Three wells were drilled and completed using a three-component process to eliminate gas migration. These three components included modifying drilling techniques, using chemical gas blocking cementing systems and using mechanical barrier systems.
First, drilling was modified by boring a gauge hole that facilitated improved efficiency in mud removal.
Second, a cementing system was used. Numerous advances in cement slurry have been achieved to prevent gas the opportunity to enter the casing annulus. Gas blockage cements were developed to combat gas migration by using several mechanisms. These mechanisms include reducing cement slurry porosity and permeability, improving fluid loss control, and building gel strength rapidly.
The third component of the strategy was the use of mechanical barriers to ensure good zonal isolation. This was accomplished by utilizing a casing annulus packer, a port or stage collar, and a two-stage cement job. The design called for pumping the tail cement, followed by a casing plug. Once the casing plug landed, pressure was increased and the casing annulus packer was mud-inflated. Next, the port collar was opened utilizing a shifting-cementing tool (combo tool). This tool, which was run on drill pipe, was then pumped through until circulation was achieved in the casing annulus. Cement followed and was circulated to the surface. The operator chose to run a casing annulus packer and a port collar on the conductor, surface and intermediate casing strings in two of the wells. A casing annulus packer and port collar were used on the surface and intermediate casing string in the other well, then two-stage cement jobs were pumped in each well. Figure 2, Well D2, illustrates the typical configuration used in the three-casing annulus packer configuration.
Field experience gained from EI 284, D1 was used to design wellbore architecture for the three wells.
The casing annulus packers were set in the previous casing strings because the compressive strength of the formations was low, the open-hole interval geometry was unknown and the pore pressure of the sand at 1,700 ft (520 m) would not be sufficient to broach the shoe at 680 ft (210 m).
In Well D2, the 26-in. drive pipe was set at a depth of 667 ft (200 m) measured depth (MD). This depth was chosen to isolate a lost circulation zone experienced in the previous D1 well. In
case the drive pipe setting depth was not sufficient to cover the lost circulation zone while drilling the conductor hole to about 20 ft (6 m) above a known shallow gas formation, mud squeezes, lost circulation material pills and drilling ahead without returns were planned as contingencies.
Next, an 81/2-in. pilot hole was drilled to the conductor casing point of 680 ft. The hole was circulated with the appropriate mud weight to minimize gas influx. The hole was progressively opened, and 185/8-in. casing was set with no rigid centralizers. The casing annulus packer was set at 485 ft (150 m) and the port collar at 473 ft (145 m). The first-stage cement was pumped using tail slurry only. After the top plug was bumped, pressure was increased in stages, inflating the casing annulus packer with wellbore fluid. The combo tool was run in the hole and manipulated to open the port collar. The pump was engaged, and circulation was established through the 185/8-in. annulus and out of the plus-ten valve. The second stage of the conductor pipe cement job was then pumped using tail slurry only. In order to clear the combo tool, the cement was over-displaced by one barrel. The port collar was closed and tested.
The surface hole was drilled with a 97/8-in. bit through two suspected gas formations, at approximately 707 ft (215 m) and at 1,700 ft (518.5 m). The same drilling procedure described in the previous casing section was followed. The hole was opened using a 95/8-in. by 171/2-in. hole opener. Then, at 1,695 ft (517 m), the 133/8-in. surface casing was set.
The surface casing was deployed with 15 rigid centralizers. The same cementing procedure employed during conductor pipe cementing was followed when cementing the surface casing. Both a lead and a tail slurry were pumped for the first-stage cementing, and only tail slurry was pumped for the second stage-cementing. Cement was circulated to the surface.
The intermediate hole was drilled with a 97/8-in. pilot hole and back-reamed to a 121/4-in. hole. The 95/8-in. casing was deployed and set at 4,343 ft (1,325 m) MD, using 70 rigid centralizers. Tail slurry was pumped for the first cement stage. During the first stage of cementing, the plug failed to bump. At this point, one additional barrel was pumped. To prevent over-displacing the cement and possibly creating a wet shoe, the combo tool's flexibility was used to inflate the casing annulus packer. After the casing annulus packer was inflated, the combo tool opened the port collar and established circulation. The second stage was then cemented with only tail cement, which was subsequently circulated to the surface.
Finally, the production hole was drilled below the 95/8-in. casing, and both screen and liner were installed.
Two additional wells were drilled and subsequently completed similarly with no gas migration problems.
Summary
Several conclusions were derived from this study:
• Understanding the mechanisms that cause gas migration and addressing them in the drilling program can eliminate it.
• Gas migration can be mitigated by using proper drilling techniques, gas block cement systems and casing annulus packers.
• Wellbore mechanics need to be understood before casing annulus packers are deployed.
• Wellbore abandonment is simplified with the elimination of gas migration.
• Before infield drilling is done, gas migration is a concern that needs to be addressed before problems arise.
• Through better completion practices, the industry will be safer and more environmentally responsible.

Comments