Each part of the BHA is designed for a specific role. Drill collars—heavy, thick-walled joints of pipe—provide stiffness and weight to prevent buckling. Stabilizers increase BHA rigidity to prevent vibration and maintain trajectory. In certain formations, specialized reamers are employed to keep the borehole in gauge or enlarge it beyond the bit diameter and help reduce torque and drag. The BHA, in turn, is connected to 31-ft [9.5-m] joints of heavyweight drillpipe that form a transition between the drill collars of the BHA and the standard drillpipe used to make up the drillstring, which drives the bit.
The BHA is lowered through the drill floor, Kelly through the wellhead and into the conductor pipe. Once the bit is on bottom, a kelly bushing hexagonal or square shaped pipe, known as a kelly is screwed into the uppermost joint of drill pipe. The kelly is inserted into the kelly bushing (KB) and the rig's rotary drive is engaged. The rotary table turns the KB, which turns the kelly (Figure 1). The drillstring rotates (turning to the right in a clockwise rotation) and drilling begins. The commencement of drilling is termed spudding in, and, like a birthday, is recorded as the well's spud date.
As the bit bores deeper into the earth, each additional length of drillpipe is connected to the previous joint, and the drillstring grows progressively longer. Drilling fluid or mud, is pumped downhole to cool and lubricate the bit. The mud also carries away rock cuttings created by the bit. Drilling fluids typically consist of a specialized formulation of water or a nonaqueous continuous phase blended with powdered barite and other additives to control the rheology of the mud. (Sometimes water is used in the upper parts of a wellbore; some formation pressures are so low that air can be used instead of mud.)
High-pressure pumps draw the mud from surface tanks and send it down the center of the drillpipe. The mud is discharged through nozzles at the face of the bit. The pump pressure forces the mud upward along the outside of the drillpipe. It reaches the surface through the annular space between the drillpipe and casing, exiting through a flowline above the blowout preventer (BOP). The mud passes over a vibrating mesh screen at the shale shaker; there, formation cuttings are separated from the liquid mud, which falls through the screens to the mud tanks before circulating back into the well.
Drilling fluid is vital for maintaining control of the well. The mud is pumped downhole to offset increases in bottomhole pressure that would otherwise force formation fluids to enter the wellbore, causing a hazardous kick or even a blowout. However, the pressure exerted by the mud must not be so great as to fracture the rock itself, which would lower the pressure of the mud in the wellbore. The pressure exerted by the mud is primarily a function of mud density, which is commonly adjusted by controlling the amount of barite or other weighting agents in the system. Pressure generally increases with depth, so mud weight must also be increased with depth. Drilling typically proceeds until further increases in mud weight would fracture the formation, at which point, casing is set.
Tripping the Bit
The bit's cutting surfaces gradually wear down as they grind away the rock, slowing the rate of penetration (ROP). Eventually, the worn bit must be exchanged for a fresh one. This requires the drilling crew to pull the drillstring, or trip out of the hole. First, the mud is circulated to bring cuttings and gas up to the surface—a process known as circulating bottoms up. Next, the roughnecks disconnect the kelly from the drillstring and latch the uppermost joint of the drillstring to the derrick's elevators—metal clamps used for lifting pipe. The driller controls the drawworks that hoist the elevators up into the derrick.
The drillstring is pulled out of the hole one stand at a time. On most rigs, a stand consists of three joints of drillpipe connected together—some rigs can pull only two-joint stands; others pull four-joint stands, depending on derrick height. Each stand is unscrewed from the drillstring, then lined up vertically in rows, guided by the derrick operator.
The last stand brings the bit to surface. The bit is unscrewed from the BHA and is graded on the basis of wear. A new bit is screwed into the bottom of the BHA, and the process is reversed. The entire process—tripping out and back into the hole—is called a round trip.
Most wellbores eventually require a means to prevent formation collapse so drilling can continue. Drilling mud, pumped down the hole to exert outward pressure against the borehole wall, is effective only to a point. Then steel casing must be run in the hole and cemented in place to stabilize the wellbore wall (Figure 2).
The driller circulates bottoms up, and the drillpipe is pulled out of the hole. The openhole section is usually evaluated using wireline well logging tools. Once logging is completed, a casing crew runs casing to the bottom of the borehole. The casing, smaller in diameter than the bit, is run in the hole in a process similar to making connections with drillpipe.