Continue the stripping process by going back to step 3 and repeating the steps

During the stripping operation, maintain constant SICP by bleeding mud though the choke. The mud displaced from the hole by the pipe can be measured and corrections made to get the exact annular pressure changes as pipe is stripped in. For most stripping jobs, holding casing pressure constant should be adequate; however, migrating gas may require corrections.

During strip in, every stand of pipe should displace mud; mud displacement and the rise in pressure should stop when no stand is being stripped. If a stand does not displace mud, circulation has been lost. If the pressure does not stop rising and mud displacement stops between stands, use a volumetric correction equation (such as equation 58 or 63).

Stripping Out of the Hole

Stripping out of the hole follows the same general procedures as stripping into the hole; however, a drill pipe float or a pump-down inside BOP is necessary to seal the pipe before coming out of the hole. Strip- ping out of the hole with a gas kick should be care- fully reviewed before a decision is made to proceed; indeed, most operators do not recommend stripping out with gas in the wellbore.

Snubbing

When the upward force that is generated by wellbore pressure acting on the cross-sectional area of the tool joints or drill string is greater than the weight of the drill string, snubbing equipment should be rigged up to force the pipe into the well through the preventers. Equations 60, 61, and

62 can be used to confirm how much pipe will have to be snubbed before stripping operations can commence. Before snubbing operations begin, thorough preparations should be made to ensure that all of those involved in the operation know their duties and positions. A review of the operator’s and contractor’s procedures is essential and all equipment must be in good working order. In general, the same preparations that are made for stripping operations should be made for snubbing. Two general types of snubbing, or pull-down, units are available: mechanical and hydraulic. Whether a mechanical or a hydraulic unit is used, the usual procedure is to snub pipe into the hole until the pipe’s weight is sufficient to allow stripping operations to begin. Usually, the pipe will start to fall through the snubbers by means of its own weight. Once the pipe begins to fall of its own weight, strip- ping procedures can be followed. Keep in mind that

comparatively high casing pressure will continue at the surface.

Mechanical Snubbing Units

Available in several sizes, mechanical units are de- signed to use the hoisting equipment on the rig. The smallest units are capable of exerting about 50,000 lb of force. Larger sizes range upward to units capable of exerting 350,000 lb of force. One type relies on rig power to snub pipe in or out of the hole through a system of pulleys and cables controlled by the rig’s

drawworks. Basic components of a typical mechanical unit are the blowout preventers, or control heads; stationary and traveling snubbers; operating manifold; power package; snub line; and balance weights. Downward thrust to force pipe into the hole against well pressure is achieved by means of the pulley system. Raising the traveling block causes the traveling snubbers that grip the pipe to move down and pull pipe into the hole. After each downward stroke, the stationary snubbers attached to the top control head grip the pipe until the traveling snubbers are raised or lowered to grab another portion of the pipe. Flow around the pipe is shut off by three

hydraulically controlled control heads. The two up- per heads are opened and closed to lubricate pipe in or out of the hole. The bottom head is closed to change packing in the upper heads. Drill pipe must be plugged by use of a landing nipple and plug assembly, slip-type plug, or bridge plug, depending on whether pipe is being run in or pulled out of the hole.

Hydraulic Snubbing Units

Most hydraulic units are self-contained and thus are operated with or without the rig’s being in place on the well. One such unit features a blowout preventer, or control-head, stack similar to that used on a mechanical unit. A multi cylinder hydraulic jack raises or lowers traveling slips that grip the pipe and snub it into or out of the hole. Stationary slips below the traveling slips hold the pipe in place while the traveling slips are being repositioned on the pipe prior to another pull. An integral stripper controls pressures up to 3,000 psi. The control heads are used if

pressures higher than 3,000 psi are involved and as a backup to the stripper. All operations are carried out at a control console in the work basket.

Pipe reciprocation during a well kill

Most operators and contractors stress that the first concern during a well killing operation is to gain control of the well first and worry about other problems, such as sticking the drill stem, later. If it becomes necessary, however, to reciprocate (move up and down) the drill stem during

a well killing operation, it is important to pay attention to detail. If the annular preventer is closed on the well, the lowest possible closing pressure should be used to prevent as much wear as possible to the packing element. The same holds true for ram preventers. Also, the weight of the drill stem must be heavy enough to overcome the upward force of well pressure; otherwise, it is not possible to strip the drill stem downward into the well—it will have to be snubbed (see the earlier discussion of stripping and snubbing in this chapter). Further, moving the drill stem when the well is closed in on a gas kick is not without risk, because gas continues to migrate upward and increase SICP during the period of pipe reciprocation.

Lost Circulation

Lost circulation is a condition in which whole mud is lost to a formation. Well kicks cause additional pressure in the hole, so special care should be taken to avoid or to minimize lost circulation during a well kick. Most well-control procedures are designed for the purpose of circulating heavy mud to kill the kick. If circulation is lost, it can be difficult or impossible to circulate the annulus full of heavy mud. When a well is shut in after a kick, SIDPP is used to calculate the mud-weight increase needed to kill the kick. Shut-in pressures can also indicate the likelihood of lost circulation. The way to find out if circulation has been lost is to attempt to circulate mud; if returns are reduced or fail to come back to the surface at all, it is safe to assume that circulation is lost.

Conditions for Lost Circulation

In general, three conditions are responsible for lost circulation: bad cement jobs, induced fractures, and vuggy or fractured formations.

Bad Cement Jobs

One of the most common causes of lost circulation during a well kick is a bad cement job at the base of the last string of casing run into the well. Because a bad cement job can cause lost circulation, most operators run leak-off or pressure-integrity tests just after drilling out the shoe to determine the pressure at which fracture occurs. The test is usually conducted to determine the highest mud-weight equivalent that is expected to be used before the next string of casing is set;

sometimes the test is carried out to pressures set by statutory requirement. In any case, a poor cement job is especially hazardous, because it may allow kick fluids to broach around the casing and under the rig. Major losses both on land and offshore have occurred because gas surfaced around the casing.

Induced Fractures

Fractures that are induced by drilling and well-control procedures can also cause lost circulation.

Such fractures can be caused by pressure surges, mud weight that is too high, or other well-control procedures. In most cases, induced fractures close, or heal, on their own in a short period of time if pressure is relieved. Induced fractures occur at the weakest point in the hole—usually at the casing shoe; therefore, an induced fracture can cause the same problems associated with a poor cement job.

Vuggy or Fractured Formations

When drilling in hard-rock country, some formations are vuggy; that is, they have large natural openings into which vast amounts of whole mud can flow. Naturally fractured formations can also take mud in high quantities. Such formations are difficult or impossible to seal and awaiting period often does not help. Many times, the entire formation is vuggy or fractured, so that the pressure required to kill the well is very close to the pressure that causes lost returns.

Well Control with Partial Lost Returns

Lost returns during a well kick can first be detected when mud level in the pits drops. If some returns continue to come back to the surface, several techniques are recommended by well-control personnel:

1. After notifying the supervisor, crewmembers can try to keep the mud volume up by mixing.

The pressure on the zone of lost returns will go down after the intruded kick fluids are circulated above the zone, so the problem may solve itself.

2. Some well-control operators recommend that the pump be stopped and the well shut in if the lost circulation continues to worsen. If the hole is given from 30 min to 4 hr to sit quietly, the lost circulation problem may cure itself. With this technique, most operators recommend keeping SIDPP constant by relieving choke pressure. If choke pressure goes up by more than 100 psi, some operators recommend that the next technique be tried.

3. Pick a slower circulating rate and a new initial circulating pressure. With the pump stopped and the well shut in, open the choke, start the pump at the new, slower rate, and close the choke until annular pressure is the same as when shut in. (With subsea wellheads, reduce annular pressure by the amount of choke-line friction loss.) Then shift to the new initial circulating pressure on the drill pipe.

4. Mix a slug of lost circulation material that is effective in the area. In general, lost circulation material is more effective in hard-rock country than in areas where the rocks are plastic.

5. Mix a slug of heavy mud to try to kill the kick. A heavy mud slug may work with a small kick if the zone of loss is well above the zone that is kicking. After the kick is killed, solve the lost circulation problem.

6. If severe partial returns (60%to90%loss) cannot be stopped, use a barite or gunk plug to seal