Annular velocity control technique overpowers gas migration and TDs well

Further hazards can occur in offshore locations where high winds and currents threaten the stability of the caisson platform.

Older HWO methods used cable-type rig-assist snubbing units. These units were used in conjunction with derrick-type workover or drilling rigs for snubbing small-OD (outside diameter) pipe strings in low-pressure conditions. The units consisted of a platform, stationary snubber, traveling snubber, and BOP stack.

Snubbing operations use hydraulic cylinders to apply a force in securing pipe, and push it into a well without having to kill the well. This technique, used in extremely high-pressure situations, can be performed without the use of a derrick-based rig, and can be modified to create a safer working environment. A hydraulic rig-assist unit, used in a non-conventional rig-up, has proven effective in drilling wells where lost-circulation problems prohibited the use of conventional drilling methods.

HWO techniques can be performed on small caisson platform wells in offshore applications rather than with a conventional jackup rig. New techniques provide the following benefits:

• Can be performed in high-pressure hydrogen sulfide wells
• Allows valves to be operated from the ground, rather than on top of the stack
• Provides additional safety features for use in emergency situations
• Can be performed with the use of a conventional derrick-based rig.

AVC drilling method

The drilling crew seals off the wellbore with gunk, cement plugs, and bridge plugs.

When conventional well-control techniques failed to resolve total lost circulation problems in a North Atlantic gas well, gas inverted with the mud column and migrated to the surface. The gas pressurized the surface casing and forced the operator, PanCanadian Petroleum Limited, to suspend drilling and seal off the well.

With few options remaining, a well-intervention team devised a drilling plan, using the only fluid that was readily available offshore - seawater. By bullheading seawater into the well at a velocity greater than the rate of gas and fluid migration, the offshore team was able to safely drill to total depth while containing hydrocarbons in the reservoir.

This unprecedented setting approach, now referred to as the annular velocity control (AVC) drilling method, has been used in two hydraulic rig-assisted drilling operations in the North Atlantic, and for two drilling exploration wells, planned in the near future.

North Atlantic dilemma

The AVC drilling method was first used in 1999 during an exploration well on the Scotia Shelf off the East Coast of Canada. Attempting to explore beneath an existing oil reservoir in search of gas, PanCanadian Petroleum Limited, sidetracked from an existing, oil-depleted wellbore and drilled into a vugular formation below the 7-in. casing shoe at 12,274 ft MD (measured depth).

The drilling mud immediately fell away from the wellbore into the formation, allowing gas to invert with the drilling fluid in the annulus. Lost circulation problems can often be solved by altering the drilling mud weight; however, the formation pressure in this particular environment was so near the mud weight required to slightly overbalance the formation, that all attempts to modify the mud weight resulted in total lost circulation.

Increasing the drilling mud weight from 0.5 lb/gal to 1.0 lb/gal is usually not a problem. The reservoir pressure in this particular situation was such that the operator could not increase the mud weight even 0.1 lb/gal without exceeding the well's bottomhole pressure, and losing the fluid to the reservoir.

Runaway circulation

After battling lost circulation problems and gas migration for nearly three weeks in one of the world's most treacherous offshore environments, the PanCanadian crew killed the well with a series of gunk pills, cement, bridge plugs, and the assistance of well-intervention specialists.

Because the AVC technique has acquired limited experience in offshore environments, the engineering details had to be approved by management and regulatory authorities. In addition, individual equipment components required for safely drilling to the targeted well depth had to be located and certified for offshore use in the North Atlantic.

These components had to be arranged so that the complete well-control stackup could be positioned between the underside of the rig floor and the wellhead deck of the platform. Modifications to the platform, as well as upgrades to the rig, were required to accommodate this additional well-control equipment.

Bullhead flow

Once the well-control equipment was installed and commissioned, the bridge plugs were retrieved, the cement was drilled up, then treated, filtered seawater was bullheaded (pumped down the drillpipe and annulus simultaneously) at a higher rate than the gas could migrate from the formation. This technique served two critical purposes:

• Pumping down the drillpipe cooled the bit, prevented excessive wear of bearings, and cleaned away the cuttings from the drill bit. A double-float check-valve system installed on the drillstring allowed fluids to be pumped into the formation and prevented formation fluids from migrating to the surface.
• Pumping down the back side of the annulus kept well fluids and/or gas from migrating to the surface. The bullheading procedure reduced the surface pressure of the evacuated wellbore by approximately 85%. Sea-water was a natural choice for a pumping fluid, since it was readily available.

Hydraulic rig-assist

With the gas migration under control, drilling continued, but the surface pressure created by the bullheading of seawater prevented the rig from moving pipe effectively into the wellbore. To overcome this problem, the crew lowered the rig BOP stack an additional 25 ft to the next deck of the production platform, and positioned a hydraulic rig-assist unit under the rig floor, above the stripping BOPs.

The rig-assist unit effectively overcame the hydraulic forces exerted by the wellbore pressure, allowing the first 20-30 joints of pipe to be run in the hole to achieve a pipe-heavy state. At this point, the rig-assist crew assumed a standby role, and the rig crew took over, running normal pipe stands with conventional equipment.

With the wellbore situation under control and contained by the rig-assist and support equipment, the rig crew members had their normal tripping ability and were back in their "comfort zone." This generated an atmosphere quite different from that of a traditional hydraulic workover (stand-alone snubbing) operation, in which pipe is run one joint at a time and the rig crew members are clearly out of their "comfort zone."

Drilling continues

When the pipe was positioned on the bottom of the hole, drilling continued to a total depth of 13,658 ft MD, with the rig-assist crew standing by only to assist in pulling out of the hole when necessary. Upon completion of drilling and evaluation, a liner was tied back into the 7-in. casing to create a pressure seal for increased wellbore integrity and to regain well control.

AVC operations were complete once the liner was pressure tested. Because of formation and reservoir characteristics, the ability to support a cement column for zonal isolation was unobtainable; therefore, the liner was not cemented. The completed well intersected more than 230 ft of net pay and flowed at approximately 55 MMcf/d during testing.

Special concerns

Seawater is bullheaded down the well to push the gas back into the formation, allowing drilling to continue to total depth.

The hydraulic rig-assist unit is a hydraulic pressure-powered rig that manipulates tubulars under pressure in a live well. Unlike larger stand-alone hydraulic workover units, the hydraulic rig-assist unit is compact enough to fit under the rig floor and is designed to work in conjunction with a rig for greater pipe running efficiency. A two-person crew controls the jack and stripping BOPs from inside a workbasket on the rig-assist unit.

As with any hydraulic rig-assist application, the ability to predict and prevent operational problems is an important factor in the success of an AVC drilling operation. Common problems requiring special pre-well attention are: differential sticking, mechanical sticking, drillstring failure, drillstring washouts, and loss of annular pressure.

Because of the pressure exerted at the surface of the well during the bullheading technique, the integrity of the cement on the intermediate casing is critical. Without good zonal isolation and shoe integrity of this casing string, the gas can migrate around the casing and into the surface casing annulus.

If the drillpipe is run in-hole at high speeds, there is a greater chance for it to strike a vugular ledge and damage the bit or drilling assembly. Surface equipment failure or maintenance also is a key area of concern in the pre-planning phase. The inability to maintain a minimum of two working barriers forces a shutdown of all drilling activities and require the well to be shut in with the rig BOPs until repairs or maintenance can be completed.

In the event of a drillstring failure or washout, fishing operations are conducted in an AVC mode. Depending on the fishing success, numerous trips might be required, resulting in increased wear on the working BOP elements.

Drilling benefits

An uncemented liner is installed in the wellbore in preparation for production.

The AVC drilling method is the safest available means of drilling with pressure because zero hydrocarbons remain in the wellbore. During a typical drilling operation, the circulated drilling fluid carries to the surface cuttings from the formation and whatever gas or oil is present in the drilled area. The risk of gas escaping to the surface is always present. AVC drilling, by comparison, pushes gas back into the formation, reduces surface pressure, and permits drilling to continue.

The PanCanadian AVC operation was performed in one of the most difficult geologic drilling situations in the industry. Lost circulation problems are common among drilling operations and can be very costly in terms of rig down time. With rig and associated costs at $150,000-450,000/day, lost circulation problems can cost an operator $3 million in a single week. A hydraulic rig-assist unit costs about $15,000 a day. In an environment with known lost circulation problems, a hydraulic rig-assist unit can offer substantial savings in drilling and completion costs.

While AVC drilling is especially effective in reducing risk and cost in offshore drilling operations, it can provide the same benefits in land operations where lost circulation problems are likely. The AVC drilling method is a safe, efficient, and cost-effective technique for drilling cavernous or highly permeable formations that are susceptible to lost circulation.

Because this technique forces all hydrocarbons out of the wellbore and into the formation, it maximizes the safety of the operation. The seawater used to suppress the hydrocarbon migration is nontoxic to the drilling environment, and eliminates some of the problems that are experienced with other drilling fluids. In addition, the positioning of the hydraulic rig-assist unit under the rig floor provides additional pipe control when needed, while allowing the rig crew to retain control of the drilling operation in their normal work environment.