The rotary system includes all of the equipment used to achieve bit rotation. Originally, the main driver in the system of all rigs was the rotary table. The main parts of the rotary system with a rotary table are the swivel, kelly, and drillstring.
The rotary swivel (Fig. 1) serves two important functions in the drilling process. It is a connecting point between the circulating system and the rotary system. It also provides a fl uid seal that must absorb rotational wear while holding pressure. The upper section of the swivel has a bail for connection to the elevator hook, and the gooseneck of the swivel provides a downward-pointing connection for the rotary hose.
The kelly is the fi rst section of pipe below the swivel. The outside cross section of the kelly is square or (mostcommonly) hexagonal to permit it to be gripped easily for turning. Torque is transmitted to the kelly through kelly bushings, which fi t inside the master bushing of the rotary table. The kelly thread is right-handed on the lower end and left-handed on the upper end to permit normal right-hand rotation of the drillstring.
During drilling operations, in every connection, a new pipe is added below the kelly. To avoid premature wear in the kelly’s threads, a kelly saver sub is used between the kelly and the fi rst joint of drillpipe. Kelly cock valves are located on either end of the kelly.
Modern rigs use a topdrive to replace the kelly, kelly bushings, and rotary table. Drillstring rotation is achieved through hydraulic or electric motors. One type of topdrive is shown in Fig. 2
Topdrives are suspended from the hook and can travel up and down the derrick. This will allow drilling to be done with stands of pipes, instead of single joints, which will save considerable time. Comparing with the conventional process, where a new pipe must be added to the drillstring after the length of just one joint has been drilled, using a topdrive system, a new connection will occur only after the length of one stand (two, three, or four pipes) has been drilled.
Besides saving time, a system with a topdrive enables the driller to re-initiate fl uid circulation or drillstring rotation faster while tripping, which reduces the chance of problems such as stuck pipe.
Fig. 1 —(a) Rotary swivel (Steven M. Hain Company, Inc. 2010); used with permission from Steven M. Hain Company, Inc.; (b) rotary swivel (courtesy of OSHA).
Fig. 2 —Topdrive (Bull. 20310 2008).
The drillstring connects the surface equipment with the drill bit at the bottom of the well. The rotary table, or the topdrive, rotates the drillstring and, consequently, rotation is transmitted to the bit.
The drillstring is basically composed of two major portions, the drillpipes and the bottomhole assembly (BHA) (see Fig. 3). Drillpipes (Fig. 3b) are specifi ed by outside diameter, weight per foot, steel grade, and length range. Drillpipes are classifi ed by API in the following length ranges: Range 1 is 18 to 22 ft (5.5 to 6.7 m), Range 2 is 27 to 30 ft (8 to 9 m), and Range 3 is 38 to 45 ft (12 to 14 m).
Range 2 drillpipe is used most commonly. Since each joint of pipe has a unique length, the length of each joint must be measured carefully and recorded to allow a determination of total well depth during drilling operations.
Fig. 3 —(a) Drillpipe tool joint; (b) drillpipe; (c) drill collar. Parts (a) and (b) are from Aadnoy et al. (2009).
The drillpipe joints are fastened together in the drillstring by means of tool joints (Fig. 3a). The portion of the drillpipe to which the tool joint is attached has thicker walls than the rest of the drillpipe to provide for a stronger joint. This thicker portion of the pipe is called the upset. If the extra thickness is achieved by decreasing the inside diameter, the pipe is said to have an internal upset. If the extra thickness is achieved by increasing the outside diameter, the pipe is said to have an external upset. A tungsten carbide hardfacing sometimes is manufactured on the outer surface of the tool joint box to reduce the abrasive wear of the tool joint by the borehole wall when the drillstring is rotated.
The BHA is the lower section of the drillstring. Even though a BHA may have many different tubulars depending on the complexity of the operation, most of the BHA is composed of drill collars (Fig. 3c). The drill collars are thick-walled, heavy steel tubulars used to apply weight to the bit. The buckling tendency of the relatively thinwalled drillpipe is too great to use it for this purpose. The smaller clearance between the borehole and the drill collars helps to keep the hole straight. Stabilizers (Fig. 4) often are used in the drill collar string to assist in keeping the drill collars centralized. Other types of tubulars used include shock absorbers and drilling jars. In addition, heavyweight drillpipes, a type of drillpipe with thicker walls, are commonly placed on top of the BHA to make the transition between the heavier drill collars and the drillpipes.
Fig. 4 —Drillstring stabilizer (National Oilwell Varco 2010a).
