L. William Abel, Patrick J. Campbell, Joe R. Bowden Sr.
Wild Well Control Inc.
Spring, Tex.
Advances in abrasive cutting technology have improved the methods for removing damaged equipment and preparing wellheads for capping.
This technology, much of which was refined during well control operations in Kuwait in 1991, can improve the safety and efficiency of capping jobs by cutting wellheads or casing quickly and cleanly.
The majority of well control jobs involve one of three types of capping operations: capping to a flange, capping by installing a wellhead, or capping to a casing stub.
Capping operations are often the first major step in regaining control of the well during blowout intervention. The term capping is sometimes used to refer to the whole process of surface intervention, but a more precise definition is the placement of a competent pressure control device onto the blowout well under flowing conditions.
Once the new control device (blowout presenter, valve, or other equipment) is positioned over the well, there must be some means of attaching the device to regain pressure integrity.
The control device is the capping stack or capping assembly. For capping operations, the maximum anticipated surface pressure (MASP) is the maximum shut-in wellhead pressure plus externally applied pressure (for example, pressures exerted while bullheading) multiplied by a safety factor. If the flowing wellhead temperature is high, the blowout presenter (BOP) may need to be derated.
Capping operations also include preparing the wellhead to accept the capping stack and can sometimes involve removal of part or all of the existing wellhead or BOP stack.
The following are some of the important factors to consider in planning a capping operation:
- Forces exerted on the capping stack as it is placed into the flow
- Best method to ensure full control of the movement (no turning or swinging) of the capping stack when it enters the flow
- Measures to minimize the potential for ignition during the capping operation and contingencies if the flow ignites
- Through-bore size (ID) of the capping stack sufficient to allow all subsequent work o Functions of the capping stack (outlets needed for diverting the flow, pumping into the well, pressure monitoring, and snubbing)
- Best attachment method for securing the capping stack to the well
- Pressure and temperature ratings required to control the well throughout all phases of well control
- Forces exerted on the capping stack during post-capping (such as snubbing and bullheading).
Proper planning of a capping operation must take into account the mass flow rate, combustible nature of the flow, well bore geometry, and operations in the post-capping phase of the project.
CAPPING VEHICLES
Well access is necessary before the actual capping can begin. Direct access is not usually possible because of structural damage to the drilling rig or platform. Debris, often melted masses of metal, must be removed first
All purpose capping vehicles (ACV) are used to work on blowing wells that can also be on fire (Fig. 1)(29496 bytes). Originally, Athey wagons were used to drag damaged equipment from the well and remove debris but rarely to convey tools to the wellhead. ACV applications include the following:
- Removing debris using hooks and rakes
- Conveying special tools, such as abrasive jet cutters, venturi tubes, and stingers o Placing explosives at a safe distance for severing or extinguishing the fire
- Hoisting and stabbing on capping assemblies.
There are two basic versions of the ACV: conventional and hydraulic.
The conventional unit relies on the power of a bulldozer and its tail winch to move and position the boom. The tail winch articulates the boom while the dozer positions the wagon.
The hydraulic version was developed primarily for stabbing-on BOPs and conveying tools that require precise positioning. The hydraulic winches provide fine control of the boom articulation. An hydraulic ACV can be secured by a bulldozer (for movement) and has hydraulic winches to control the boom angle and a set of winches at the front of the vehicle for pulling or snubbing on BOPS.
One drawback of the hydraulic ACV is the need for a power pack to operate the hydraulic winches, and this extra pack increases the overall air shipping weight and volume. All components break down into small lifts that will fit on almost all commercial cargo planes, however.
TREE REMOVAL
Once the fire is extinguished or directed through a venturi tube, the wellhead must then be inspected closely to determine whether the existing equipment can be used to attach capping devices or if any of the wellhead must be removed.
Wellhead or BOP components must be removed when they have suffered structural damage. Falling debris can cause mechanical damage, and fire can weaken the integrity of most elastomer seals. Reusing wellhead components that have been involved in a blowout can be hazardous; thorough evaluation of the equipment is necessary. If nothing can be salvaged, the entire wellhead and all casing strings may need to be cut off and new equipment installed.
A typical technique for removing wellhead or BOP components is to install clamps on the flange to allow removal of all bolts. A crane hook is attached to the component, and snub lines are installed through the bolt holes. With the snub lines tight, the clamps are removed, and the component can be taken off in a controlled manner. Other removal methods include explosives, cables, or hand-operated hacksaws. Some operators have resorted to tearing the wellhead off with brute force, which has often caused additional damage and prolonged capping work to repair the casing.
Explosives are a precise, reliable method for removing wellhead equipment or sections of casing at the surface. This technology requires special expertise and highly experienced personnel.
Shaped charges can be constructed to accomplish a variety of tasks, from severing the entire wellhead to removing casing valves or strings. If properly applied, shaped charges can remove an outer string of casing without damaging the next inner string.
The cable method is a crude type of friction cut and is now considered outdated technology. Wire rope or cable is wrapped around the wellhead or casing and each end is connected to a swabbing unit which drags the cable back and forth to sever the casing. This method works but can take several days, depending on the number of casing strings and the amount of cement.
Another disadvantage of this method is the difficulty in returning the cable into the cut groove, if the cable comes out. Cable cutting can cause the casing to become oval, further hindering the capping operation.
JET CUTTERS
The oil fires in Kuwait in 1991 proved to be an excellent testing ground for the abrasive jet cutter, a new cutting method. This equipment performed well in the removal of damaged wellhead components and trees.
Two types of jet cutters were used in Kuwait: Halliburton Energy Services' Hydra-jet and the ultra-high-pressure (UHP) abrasive jet cutter. The tools are different, but both use a high-pressure stream of fluid carrying abrasive particles to erode metal and cement (Table 1)(37197 bytes).
The UHP equipment is a trailer-mounted, self-contained system with quick mobilization and rig up. Rig up consists of attaching a split track with hydraulic tractor to the wellhead above or below the area to be cut.
Two men can rig up the UHP equipment without a crane. The tractor and nozzle are then positioned on the track and attached to the water, abrasive slurry, and hydraulic lines.
A high-pressure, low-volume stream of water and abrasive slurry is pumped through the jet. The calculated nozzle velocity at a typical pump rate of 4 gpm is 2,007 fps at 30,000 psi nozzle pressure. The abrasive material used in Kuwait was granulated garnet with a hardness of 7.5 (steel has a 6.5 hardness). In several instances in Kuwait, the jet made circular cuts through seven cemented strings of casing, with one or more blowing, to remove a damaged wellhead. The average time for this type of circular cut was 1-2 hr, with many jobs done in less than 1 hr.
To cut off a wellhead completely, the jet nozzle is pointed directly at the casing, perpendicular to its axis. The jet makes a complete 3600 cut as it moves around the well. The jet stream usually penetrates 15-18 in.; the depth of penetration depends on the tracking speed. To remove just the outer string of casing, leaving the inner strings intact, the jet can be set at an angle where the abrasive stream does not penetrate deeper than the thickness of the outer string.
The cut is remotely controlled by an operator. No personnel are required close to the wellhead during the cutting.
The UHP jet cutter track can be attached to the wellhead to cut under damaged valves or between flanges. With the tool mounted on a tripod, the jet cutter can cut bolts and other small diameter sections. A typical flange stud can be cut in a few minutes.
The UHP cutting tool has some limitations. The operator must physically attach the tractor band to the wellhead or casing, and if there is lateral flow, this job is virtually impossible. The cut is jagged and often irregular, perhaps because of the light construction of the tracking frame.
Halliburton's Hydra-jet was adapted for Kuwaiti wells by using a special carrier to convey it to the wellhead on a conventional ACV boom. Two carriers were used: a vertical cutter with a single nozzle and a horizontal carrier with a U-shaped yoke and two opposing jet nozzles.
A small hydraulic motor drives long worm screws to advance the cutters along the length of the yoke. To make the cut, a slurry of gelled water and 1 ppg sand is pumped at 150 gpm to each 3/16-in. nozzle. The abrasive stream of high-pressure slurry erodes the casing or wellhead and tracks laterally much like a hacksaw blade passing through a piece of pipe.
This jet cutter can be rigged up in about 6 hr. Because the- tool is conveyed on an ACV boom, it can cut off a wellhead on fire or with limited access because of lateral flow. The operation can be cooled and shielded from the fire by a water spray. The hydraulic control lines are protected in an arrangement that resembles a tube-and-shell heat exchanger. The lines run inside the tube, and water is circulated around them to cool the system.
The vertical cutter has a single arm jet holder and can cut off wing valves or flow lines. In either vertical or horizontal position, the finished cut is clean and smooth.
Using the Hydra-jet cutter requires some special logistical considerations. The large cutting-fluid volume requires the use of tank trucks (or frac tanks offshore) to supply the fluid and a bulk truck (or skid) to supply the sand. The high-pressure, high-volume fluid discharges generally require a large amount of horsepower and equipment.
Even with their individual disadvantages, both types of jetting tools can outperform other methods of removing damaged components on blowing or burning wells. They are a significant advance in wild well control techniques.
Circumferential cuts must then be made on the casing strings prior to capping. These cuts can be made with an abrasive et cutter or a portable lathe die cutter. The lathe cutter uses a track, air or hydraulic motor, and a hardened cutting blade similar to those used on commercial lathes. The lathe cutter can be split and wrapped around the casing so it can be mounted without entering the flow.
The resulting cuts have beveled, machine-quality edges. The casing strings are cut at different lengths to expose an adequate amount of the innermost string for capping. If necessary, these cuts can be made with the well on fire.
CAPPING TO A FLANGE
In large, violent flows of high velocity, the snub-on technique is generally recommended for installation of a capping stack to an existing flange.
The idea is to control the movement of the capping stack along its three axes by the use of hoist, tag, and snub lines (Fig. 2)(84351 bytes):
- Rig up a capping assembly with a mating flange with proper pressure, temperature, and service ratings. Tack weld the ring gasket to the bottom of the capping assembly flange.
- Hold a final safety and coordination meeting to ensure that all personnel understand the safety procedures and operational plans, including the contingency plan for a flash fire or explosion.
- Snub the capping assembly into the flow. Center and lower the capping assembly, and mate the flanges.
- Install bolts, and tighten to energize the ring gasket seal.
- Connect hydraulic lines between the closing unit and capping assembly.
- Install diverter lines and kill lines as necessary then continue with the chosen course of action (pump t kill, divert, or rig up to snub)
Similar procedures ar used whether the capping assembly consists of a valve arrangement or a BOP stack Torque wrenches should b available to speed the installation and ensure a proper seal because pressure testing is often impossible.
CAPPING TO A STUB
Capping to a casing stub is an option when the entire wellhead has been removed. After the outer strings of casing are cut back to expose the capping string, a standard slip-on, weld-type head is modified by adding pad eyes for attaching the snub lines. For ease of installation, this wellhead should be at least one size larger than the casing stub to be swallowed. For example, a 9 5/8-in. head would be used to cap 7-in. casing.
A plate can be tack welded onto the side of the head to deflect the flow and improve visibility as the spool is placed into the flow over the casing stub. This plate will have to be removed before installation of the casing clamps. Snatch blocks are secured to the base of the casing with a bolt-on clamp. Cables are threaded through the snatch blocks and attached to the head to facilitate the snub-on operation.
Once the head has been positioned over the casing stub, the blocks and snub line are removed. A second clamp is installed, but not tightened, between the existing clamp and the head. Hydraulic jacks are positioned between the two clamps. (The bottom clamp is secure, and the top clamp is loose.) A standard set of split-type casing slips is placed in the bowl and engaged by using the hydraulic jacks. After the slips are in place and the pack-off is energized, the top clamp is secured under the head to hold it in place when the hydraulic jacks are released.
To calculate the jacking force required to fix the wellhead onto the casing stub, all subsequent operations should be considered, including rig dead loads (BOP and snubbing equipment) and dynamic loads (pull from snubbing jack, running casing, and applied pressure).
The net upward forces are transferred to the casing slips. These forces should not be allowed to exceed 80% of the casing tensile strength. Because the casing slips are incapable of imparting a downward force, all net downward forces are transferred to the casing via the casing clamp.
Maximum unsupported buckling length calculations should be made to evaluate the possibility of failure. If the forces associated with the worst case scenarios exceed 50% of the maximum tensile stress, axial and hoop stress calculations should be performed to evaluate the safety of the rig up.
SWALLOWING THE STUB
Capping by swallowing the stub is an alternative when the entire wellhead has been removed (Fig. 3)(101976 bytes). This procedure can also be used for capping drill pipe or tubing.
Unlike pipe and blind rams, slip rams are not pressure-sealing devices. They provide a mechanical grip which is used only to fix the BOP to the casing stub.
Once the proper amount of casing is exposed, a casing clamp is installed on the outer casing stub. This clamp is then used to connect the snatch blocks and the snub lines. The BOP stack is lifted with the crane and controlled with the snub and tag lines while being placed over the casing stub. With the BOP assembly safely over the casing stub, the hydraulic lines are connected from the closing unit. The rams are closed in the following sequence:
- Slip rams - To fix the BOP stack onto the casing stub (Note that the BOP must be laterally supported to prevent casing damage from bending forces.)
- Inverted pipe rams - To contain the pressure exerted from the top
- Blind rams - To shut off the flow or direct the flow through the side outlet valves for diverting.
The BOP stack can be stabilized with hydraulic jacks and casing clamps if further rig up (snubbing or coiled tubing equipment) is required.
SPIN-AN TECHNIQUE
Spinning a val-,,e or BOP into a flow is a viable option for capping a flow by installing valves or BOPs (Fig. 4)(99363 bytes). Very large flows can be handled safely and efficiently with this technique, which requires no special materials or fabrication.
As in any capping operation, the potential for ignition cannot be eliminated, so fire water protection for the capping crews must be maintained during this and all capping maneuvers. One drawback is the close proximity of the capping crew to the flow, and this aspect must be carefully evaluated.
The following procedure is for installation to an existing flange:
- Install a hinge bolt (one longer bolt).
- Install a lever arm to the capping assembly, and sling the assembly for lifting.
- Lift and position the capping assembly onto the hinge bolt at 1800.
- Position the crane hook at centerline of the flow/flange to be capped.
- Cover the work area with fire water.
- Manually spin the valve into the flow, and align capping and mating flanges. 0 Drop in bolts, and torque-up to seal the well.
CAPPING ON FIRE
An emphasis on environment and personnel safety has led to certain wells being capped on fire. Leaving a well on fire can reduce the amount of pollution, providing the well is burning cleanly.
Capping operations may take longer to complete, however, if the well is left on fire throughout the operation. If the well is not burning cleanly, then a judgment is needed to determine if less pollution will occur if the fire is extinguished and thereby allow quicker capping.
Capping a well on fire is also justified if toxic gases (H2S) are produced. Leaving the well on fire may reduce the personnel hazards from escaping toxic gases. Regardless of whether the well is on fire, the work will need to proceed carefully with precautions for H2S hazards and care to guard the personnel from burns.
STINGING
Stinging is a technique that can be used to kill a blowing well (on fire or not) providing certain well conditions prevail. This technique involves placing a stinger in the throat of a blowing well in such a way that it functions as a temporary valve. The stinger has a hollow bore that will enable a kill fluid to be pumped into the well by bullheading.
Stinging may be the most expedient means to control a well providing wellhead and downhole conditions are favorable. In offshore operations, extra equipment fabrication is sometimes necessary. Some means of placing the stinger in the wellhead will have to be fabricated based on the conditions of the well and structure. The following are the conditions necessary for a successful stinging operation:
- Shut-in wellhead pressure
- Fairly small cross sectional flow area
- Unobstructed access to the flow area
- Downhole conditions conducive for a bullhead kill o Pressure-area effect must be
If the shut in well head pressure is 1,000 psi, it may be difficult to create a seal with bridging agents. Common bridging agents are hard rubber, gel, barite, nylon rope, or other lost circulation materials.
These materials are mixed as a slurry and pumped ahead in a pill. They should be graded in size from 2 mm up to 20 mm. Strips of rubber from tire tubes are an excellent bridging agent for stinging operations, but almost any type of lost circulation material will suffice.
If the shut-in pressure will produce more than 35,000 lb of upward thrust from the pressure-area effect, it may not be possible to provide rigging or tie downs that will prevent pump out (ejection) of the stinger or failure of the seal.
To form a seal between the stinger and the inside bore of the well, the ovality of the well must be less than 5%. The gap between the stinger (which is assumed to be 99% round) and the well must be X, in. If this gap is small, the bridging agents can seal the leak (Fig. 5)(72400 bytes).
Downhole conditions must be conducive for a bullhead kill for the stinging operation. Although a pump-and-bleed (volumetric kill) procedure may be possible, the general idea is to sting in, pump the bridging agents to seal the leaks, and then bullhead the well dead.
Once the well is killed, the objective is then to secure the well. The stinger and its bridging agent seal cannot in any way be considered a permanent barrier. The options are then to install a slip-on, weld-type head, a temporary wellhead, a capping assembly (swallow stub), or permanent wellhead.
OFFSHORE
Blowouts offshore present additional environmental concerns, especially when the well is situated near extremely sensitive ecosystems. It is not possible to discuss every possibility which may arise during an offshore blowout; however, a general discussion of the equipment and techniques typically used on a major inland water blowout reveals the complexity of such a project.
The initial phase of the intervention involves clearing damaged or unnecessary equipment from the structure to provide working room and to remove valuable equipment from danger. The intervention team then attempts to board the structure under a covering water spray from the primary support vessel .
Once on board, the team assesses the situation and proceeds accordingly. The support vessel crane removes any accessible equipment. The use of existing cranes may not be feasible because of damage or the inability to reconnect power.
Clearing debris may be difficult if there is extensive structural damage. If the well is on fire, conventional cutting techniques (torches) can be used where possible. If the well is not on fire or if debris must be cut out from around the burning well, jet cutters or explosives ma be used.
To handle an offshore blowout safely, the intervention team must have the capability to apply large volumes of water. The water cools the area to allow wellhead access or prevents ignition while the crew works in proximity to the flow.
Dedicated pumping equipment and specially designed marine manifolds are typically used for water supply. If the primary support vessel has no firefighting capabilities, these pumps can be used exclusively. If other firefighting capabilities are available, they can be used in conjunction with the onboard pumps.
At some point in the intervention project, usually following debris removal, firefighting monitors (outlets) are placed on the structure, if possible. These monitors provide precise placement of water for cover and cooling. Temporary conduits, (large, low-pressure hoses from the support vessel) are connected to the monitors on the structure. If space and conditions allow, pumps can be placed on the structure, and their suctions charged by the pumps on the support vessel.
If possible, the existing deluge piping on the structure may be used. These systems have been used on platform fires and blowouts in the past and have proven very beneficial to the project. This piping is relatively inexpensive and should be considered for installation on all platforms.
Oil slicks can present a hazard to the vessels working near the blowout. Measures must be taken to prevent accumulations of flammable liquids around the work vessels. If significant slicks develop and become difficult to contain, additional firefighting equipment should be placed on the primary support vessel to combat fires that may ignite on the water. Foam injection will likely prove beneficial.
Once sufficient room is available, operations are undertaken on the structure. All operations near the wellhead are usually conducted with a protective, cooling water spray cover. In some instances, a portable crane may be assembled on the deck of the structure for further debris removal, precise equipment placement, and eventually for capping the well.
FIREFIGHTING
If the well is on fire, all heated metal debris must be removed or cooled before the fire can be extinguished. A venturi tube may be placed over the well flow to raise the ignition point and consolidate the flow.
Fires which cause major structural damage sometimes require extensive fabrication projects to rebuild a working platform around the wellhead. Plans should be in place to mobilize a well-equipped fabrication crew with ample material for this type of work on all major offshore blowouts.
Once the wellhead is accessible, the flow should be configured into a single vertical stream. Many fires can be extinguished with water alone. The venturi tube may be used in conjunction with water application to improve the chances of success. If these attempts fail, explosives may be used to extinguish the fire.
Unless major structural damage is imminent, the fire may be left burning as a pollution control measure until all preparations have been made for capping. In certain situations, such as with H2S gas present, the well may be capped while on fire. This technique has been used on several offshore operations, although the technique is mainly used onshore.
POLLUTION CONTROL
Inland water blowouts often present major difficulties to the intervention project. Because of the sensitivity of the environment and space restrictions, extensive containment projects may be necessary before the actual well intervention can begin.
Immediately upon arrival, the well control team assesses the overall situation, with emphasis on planning the intervention in conjunction with the pollution containment project.
If the blowout well is in a man-made slip, well control intervention usually begin with the slip already evacuated and containment measures implemented at some point between the well and open water. Once the initial measures have been completed for pollution containment, collection, and removal, efforts can begin to move into the well slip.
If the well is situated in relatively open water, the pollution containment and intervention measures do not usually conflict. Once containment measures are in place, the well intervention can proceed. A great deal of coordination is still needed for the two projects to proceed simultaneously.
INTERVENTION EQUIPMENT
Before the well can be approached, it is usually necessary to install firefighting pumps on an open deck barge, usually at the dock facility nearest the well. Installation of the pumps does not entail extensive fabrication if a special marine firefighting package is used.
Heat shields are normally constructed on one or more sides of the barge with the pumps. The welders construct these shields from corrugated tin and small pipe or angle iron.
The crew moves inside the containment booms as soon as possible. The first equipment moved in is usually an open deck barge with firefighting pumps, monitors, and piping installed on the deck. Foam injection capabilities are included in the pumping system to cover combustible fluids which may have accumulated on the water surface.
Once the firefighting barge is in place, efforts can begin to remove equipment from the well area. Support equipment such as mud barges, cuttings barges, pipe barges, and other service barges are removed first. Under the protective cover of the firefighting barge's water spray, these other barges are boarded, tied, and removed with one of several tugs needed for the project.
A crane barge may be needed to remove equipment from the rig. A second open deck barge and tug are normally used to load this equipment and transport it away from the well site.
Dredging may be necessary to provide adequate room for the intervention equipment. In some cases it may be necessary to extend or widen a slip to allow work to proceed from the predominantly upwind side of the well.
If fire has caused extensive structural damage, the main wall to the well bay may be collapsed, allowing equipment to slide onto the wellhead. The rig will have to be boarded and the damaged equipment cut away from the wellhead This cutting is most easily accomplished with high-pres sure abrasive jet cutters. If jet cutting is necessary, the AC and bulldozer may have to b mounted on the second open deck barge to convey the cutting equipment.
RIG REMOVAL
Once all equipment has been cleared from the wellhead area, the rig is then removed. All compartments will have to be emptied of ballast water, using portable trash pumps, to facilitate the move. It is extremely important to deballast the rig before attempting to move it. Trying to remove an unballasted rig by applying massive amounts of force may damage the outer hull and internal bulkheads, which will cause flooding and make the rig virtually impossible to move. If the rig is equipped with a jetting system, the crew can tie a pump into the system to aid removal by breaking the bottom suction. Under some conditions, it may be possible to drag a large cable or drill line under the rig to break the bottom suction.
Depending on the situation, a significant number of tugs may be required to remove the rig. Six shallow draft tugs, each rated at 1,200 hp, should be available.
With the rig removed from around the well, final site preparations can begin for the capping project. A key-slot barge is often used as the work platform for the blowout intervention work. The barge is positioned with the key-slot around the wellhead and submerged. Guide rails can be welded to the end of the barge to allow a plate to be lowered making the key slot into an enclosure. This enclosure can then be pumped dry to expose the entire wellhead for further operations. The flow has to be in a single vertical stream before the enclosure can be pumped dry.
The ACV and bulldozer are placed on the barge to convey cutting tools, remove wellhead components, and eventually begin capping.
