The length of drillcollars, L that are required for a particular drilling situation depends on the Weight on Bit, WOB that is required to optimise the rate of penetration of the bit and the bouyant weight per foot, w of the drillcollars to be used, and can be calculated from the following:

L = WOB/w

If the drillpipe is to remain in tension throughout the drilling process, drillcollars will have to be added to the bottom of the drillstring. The bouyant weight of these additional drillcollars must exceed the bouyant force on the drillpipe This will be sufficient to ensure that when the entire weight of the drillcollars is allowed to rest on the bit, then the optimum weight on bit will be applied. The WOB will however vary as the formation below the bit is drilled away, and therefore the length of the drillcollars is generally increased by an additional 15%. Hence the length of drillcollars will be 1.15L.

Institute of Petroleum Engineering, Heriot-Watt University

A drilling bit does not normally drill a vertical hole. This is partly due to the forces acting on the string by sloping laminar formations. When the slope (or dip) of the beds is less than 45 degrees the bit tends to drill up-dip (perpendicular to the layers). If the dip is greater than 45 degrees it tends to drill parallel to the layers (see Figure 12). In hard rock, where greater WOB is applied, the resulting compression and bending of the drillstring may cause further deviation. There are two techniques for controlling deviation.

Drilling through dipping strata

•     Packed hole assembly (Figure 13) – This is basically a stiff assembly, consisting of reamers, drill collars and stabilisers. The purpose of this design is to align the bit with the hole already drilled and minimise the rate of change in deviation.

pendulum effect
•     Pendulum assembly – The first stabiliser of a pendulum assembly is placed some distance behind the bit. The unsupported section of drill collar (Figure 13) swing to the low side of the hole. A pendulum assembly will therefore tend to decrease the angle of deviation of the hole and tend to produce a vertical hole. This will tend to reduce deviation. The distance “L” from the bit up to the point of wall contact is important, since this determines the pendulum force. To increase this distance, a stabiliser can be positioned some distance above the bit. If placed too high the collars will sag against the hole and reduce the pendulum force. The optimum position for the stabiliser is usually based on experience, although theoretical calculations can be done. When changing the hole angle it must be done smoothly to avoid dog legs (abrupt changes in hole angle). The method of calculating dog leg severity will be given later. Some typical Bottom hole assemblies (BHA), for different drilling conditions, are given in Figure 14.

BHA

Institute of Petroleum Engineering, Heriot-Watt University
 

The purpose of these tools is to deliver a sharp blow to free the pipe if it becomes stuck in the hole. Hydraulic jars are activated by a straight pull and give an upward blow. Mechanical jars are preset at surface to operate when a given compression load is applied and give a downward blow. Jars are usually positioned at the top of the drill collars.

A roller reamer consists of stabiliser blades with rollers embedded into surface of the blade. The rollers may be made from high grade carburised steel or have tungsten carbide inserts (Figure 10). The roller reamer acts as a stabiliser and is especially useful in maintaining gauge hole. It will also ream out any potential hole problems (e.g. dog legs, key seats, ledges).

roller reamer

Stabilisers consist of a length of pipe with blades on the external surface. These blades may be either straight or spiral and there are numerous designs of stabilisers (Figure 8). The blades can either be fixed on to the body of the pipe, or mounted on a rubber sleeve (sleeve stabiliser), which allows the drillstring to rotate within it.

The function of the stabiliser depends on the type of hole being drilled. In this section we are concerned only with drilling vertical holes. Drilling deviated holes will be dealt with later. In vertical holes the functions of stabilisers may be summarised as follows:
• Reduce buckling and bending stresses on drill collars
• Allow higher WOB since the string remains concentric even in compression.
• Increase bit life by reducing wobble (i.e. all three cones loaded equally).
• Help to prevent wall sticking.
• Act as a key seat wiper when placed at top of collars.

Generally, for a straight hole, the stabilisers are positioned as shown in Figure 9.Normally the stabilisers used will have 3 blades, each having a contact angle of 140 degrees (open design). When stabilisers begin to wear they become undergauge and are less efficient. Stabilisers are usually replaced if they become 1/2” undergauge (3/16” undergauge may be enough in some instances).

Drillstring Stabilisers

Institute of Petroleum Engineering, Heriot-Watt University

Anti Wall Stick

When drilling through certain formations the large diameter drillcollars can become stuck against the borehole (differential sticking). This is likely to happen when the formation is highly porous, a large overbalance of mud pressure is being used and the well is highly deviated. One method of preventing this problem is to reduce the contact area of the collar against the wellbore. Spiral grooves can be cut into the surface of the collar to reduce its surface area. (Figure 7)

spiral drill collar

Square collars
These collars are usually 1/16” less than bit size, and are run to provide maximum
stabilisation of the bottom hole assembly.

Monel collars
These collars are made of a special non-magnetic steel alloy. Their purpose is to isolate directional survey instruments from magnetic distortion due to the steel drillstring.

Drillcollars are tubulars which have a much larger outer diameter and generally smaller inner diameter than drillpipe. A typical drillstring would consist of 9” O.D. x 2 13/16” I.D. drillcollars and 5” O.D. x 4.276” I.D. drillpipe. The drillcollars therefore have a significantly thicker wall than drillpipe. The function of drill collars are:
•     To provide enough weight on bit for efficient drilling
•     To keep the drillstring in tension, thereby reducing bending stresses and failures due to fatigue.
•     To provide stiffness in the BHA for directional control.

Since the drillcollars have such a large wall thickness tooljoints are not necessary and the connection threads can be machined directly onto the body of the collar. The weakest point in the drill collars is the connection and therefore the correct make up torque must be applied to prevent failure. The external surface of a regular collar is round (slick), although other profiles are available.

Drill collars are normally supplied in Range 2 lengths (30-32 ft). The collars are manufactured from chrome-molybdenum alloy, which is fully heat treated over the entire length. The bore of the collar is accurately machined to ensure a smooth, balanced rotation. Drill collars are produced in a large range of sizes with various types of joint connection. The sizes and weight per foot of a range of drillcollar sizes are shown in Table 14. The weights that are quoted in Table 14 are the “weight in air” of the drillcollars.

It is very important that proper care is taken when handling drill collars. The shoulders and threads must be lubricated with the correct lubricant (containing 40-60% powdered metallic-zinc or lead).

Like drillpipe, collars are subjected to stresses due to:
•     Buckling and bending forces
•     Tension
•     Vibrations
•     Alternate compression and tension.
However, if properly made up, the shoulder/shoulder connection will be sufficient to resist these stresses. Figure 6 shows how numbered connections should be selected to provide an efficient seal, and adequate strength.

Institute of Petroleum Engineering, Heriot-Watt University

Heavy wall drillpipe (or heavy weight drillpipe) has a greater wall thickness than ordinary drillpipe and is often used at the base of the drillpipe where stress concentration is greatest. The stress concentration is due to:
• The difference in cross section and therefore stiffness between the drillpipe and drillcollars.
• The rotation and cutting action of the bit can frequently result in a vertical bouncing effect.
HWDP is used to absorb the stresses being transferred from the stiff drill collars to the relatively flexible drillpipe. The major benefits of HWDP are:
• Increased wall thickness
• Longer tool joints
• Uses more hard facing
• May have a long central upset section (Figure 5)

HWDP should always be operated in compression. More lengths of HWDP are required to maintain compression in highly deviated holes.

heavy weight drill pipe

Institute of Petroleum Engineering, Heriot-Watt University

Tool joints are located at each end of a length of drillpipe and provide the screw thread for connecting the joints of pipe together (Figure 4). Notice that the only seal in the connection is the shoulder/shoulder connection between the box and pin. Initially tool joints were screwed on to the end of drillpipe, and then reinforced by welding. A later development was to have shrunk-on tool joints. This process involved heating the tool joint, then screwing it on to the pipe. As the joint cooled it contracted and formed a very tight, close seal. One advantage of this method was that a worn joint could be heated, removed and replaced by a new joint. The modern method is to flash-weld the tooljoints onto the pipe. A hard material is often welded onto the surface of the tooljoint to protect it from abrasive wear as the drillstring is rotated in the borehole. This material can then be replaced at some stage if it becomes depleted due to excessive wear. When two joints of pipe are being connected the rig tongs must be engaged around the tool joints (and not around the main body of the drillpipe), whose greater wall thickness can sustain the torque required to make-up the connection. The strength of a tool joint depends on the cross sectional area of the box and pin. With continual use the threads of the pin and box become worn, and there is a decrease in the tensile strength. The size of the tooljoint depends on the size of the drillpipe but various sizes of tool joint are available. The tooljoints that are commonly used for 4 1/2” drillpipe are listed in Table 5. It should be noted that the I.D. of the tooljoint is less than the I.D. of the main body of the pipe.
tool joint

Tooljoint boxes usually have an 18 degree tapered shoulder, and pins have 35 degree tapered shoulders. Tool joints are subjected to the same stresses as drillpipe, but also have to face additional problems:

•     When pipe is being tripped out the hole the elevator supports the string weight      underneath the shoulder of the tool joint.
•     Frequent engagement of pins and boxes, if done harshly, can damage threads.
•     The threaded pin end of the pipe is often left exposed.

Tool joint life can be substantially extended if connections are greased properly when the connection is made-up and a steady torque applied.

table 5