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)
These collars are usually 1/16” less than bit size, and are run to provide maximum
stabilisation of the bottom hole assembly.
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
• 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.
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.
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.
When manufactured, new pipe will be subjected by the manufacturer to a series of mechanical, tensile and hydrostatic pressure tests in accordance with API Specification 5A and 5AX. This will ensure that the pipe can withstand specified loads. A joint of drillpipe will however be used in a number of wells. When it has been used it will undergo some degree of wear and will not be able to withstand the same loads as when it is new.
It is extremely difficult to predict the service life of a drillstring since no two boreholes experience the same drilling conditions. However, as a rough guide, the length of hole drilled by a piece of drillpipe, when part of a drillstring will be :
soft drilling areas: 220000 – 250000 ft
hard or deviated drilling areas: 180000 – 210000 ft
This means that a piece of drillpipe may be used on up to 25 wells which are 10,000 ft deep
During the working life of the drillpipe it will therefore be necessary to determine the degree of damage or wear that the pipe has already been subjected to and therefore its capacity to withstand the loads to which it will be exposed in the future. Various non-destructive tests are periodically applied to used drillpipe, to assess the wear and therefore strength of the pipe, and to inspect for any defects, e.g. cracks. The strength of the pipe is gauged on the basis of the remaining wall thickness, or if worn eccentrically, the average minimum wall thickness of the pipe. The methods used to inspect drillpipe are summarised in Table 4.
Following inspection, the drillpipe is classified in terms of the degree of wear or damage which is measured on the pipe. The criteria used for classifying the drillpipe on the basis of the degree of wear or damage is shown in Table 6. The ‘Grade 1 or Premium’ drillpipe classification applies to new pipe, or used pipe with at least 80% of the original wall thickness still remaining. A classification of Grade 2 and above indicates that the pipe has sustained significant wear or damage and that its strength has been significantly reduced. The strength of some typical drillpipe sizes when new, and when worn, is shown in tables 11 and 12.
Drillpipe will generally be inspected and classified before a new drilling contract is started. The operating company would require that the drilling contractor provide proof of inspection and classification of the drillstring as part of the drilling contract.In general, only new or premium drillpipe would be acceptable for drilling in the North Sea.
It is not uncommon for the drillpipe to undergo tensile failure (twistoff) whilst drilling. When this happens, drilling has to stop and the drillstring must be pulled from the borehole. The part of the string below the point of failure will of course be left in the borehole when the upper part of the string is retrieved. The retrieval of the lower part of the string is a very difficult and time consuming operation.
The failure of a drillstring can be due to excessively high stresses and/or corrosion. Drillpipe is exposed to the following stresses:
1. Tension – the weight of the suspended drillstring exposes each joint of drillpipe to several thousand pounds of tensile load. Extra tension may be exerted due to overpull (drag caused by difficult hole conditions e.g. dog legs) when pulling out of hole.
2. Torque – during drilling, rotation is transmitted down the string. Again, poor hole conditions can increase the amount of torque or twisting force on each joint.
3. Cyclic Stress Fatigue – in deviated holes, the wall of the pipe is exposed to compressive and tensile forces at points of bending in the hole. As the string is rotated each joint sustains a cycle of compressive and tensile forces (Figure 3). This can result in fatigue in the wall of the pipe.
Stresses are also induced by vibration, abrasive friction and bouncing the bit off bottom.
Corrosion of a drillstring in a water based mud is primarily due to dissolved gases, dissolved salts and acids in the wellbore, such as:
1. Oxygen – present in all drilling fluids. It causes rusting and pitting. This may lead to washouts (small eroded hole in the pipe) and twist offs (parting of the drillstring). Oxygen can be removed from drilling fluids using a scavenger, such as sodium sulphate. Even small concentrations of oxygen (< 1 ppm) can be very damaging.
2. Carbon dioxide – can be introduced into the wellbore with the drilling fluid (makeup water, organic drilling fluid additives or bacterial action on additives in the drilling fluid) or from the formation. It forms carbonic acid which corrodes steel.
3. Dissolved Salts – increase the rates of corrosion due to the increased conductivity due to the presence of dissolved salts. Dissolved salts in drilling fluids may come from the makeup water, formation fluid inflow, drilled formations, or drilling fluid additives.
4. Hydrogen sulphide – may be present in the formations being drilled. It causes “hydrogen embrittlement” or “sulphide stress cracking”. Hydrogen is absorbed on to the surface of a steel in the presence of sulphide. If the local concentration of hydrogen is sufficient, cracks can be formed, leading rapidly to a brittle failure. Hydrogen embrittlement in itself does not cause a failure, but will accelerate failure of the pipe if it is already under stress or notched. Only small amounts of H2S need be present to induce fatigue (< 13 ppm). Special scavengers can be circulated in the mud to remove the H2S (e.g. filming amines).
5. Organic acids – These produce corrosion by lowering the pH, remove protective films and provide hydrogen to increase hydrogen embrittlement.
Although added chemicals can build up a layer of protection against corrosion, the fatigue stresses easily break this layer down, allowing corrosion to re-occur. It is this interaction of fatigue and corrosion which is difficult to combat.
Institute of Petroleum Engineering, Heriot-Watt University
Drillpipe is the major component of the drillstring It generally constitutes 90-95% of the entire length of the drillstring. Drillpipe is a seamless pipe with threaded connections, known as tooljoints (Figure 2). At one end of the pipe there is the box, which has the female end of the connection. At the other end of each length of drillpipe is the male end of the connection known as the pin. The wall thickness and therefore the outer diameter of the tooljoint must be larger than the wall thickness of the main body of the drillpipe in order to accommodate the threads of the connection. Hence the tool joints are clearly visible in the drillstring.
Each length of drillpipe is known as a joint or a single. The standard dimensions for drillpipe are specified by the American Petroleum Institute. Singles are available in three API length “ranges” (see Table 1) with range 2 being the most common. The exact length of each single must be measured on the rigsite since the process used to manufacture the drillpipe means that singles are not of uniform length. Since the only way in which the driller knows the depth of the drillbit is by knowing the length of the drillstring the length of each length of drillpipe (and all other drillstring components) made up into the drillstring must be measured and recorded on a rillpipe tally. The drillpipe is also manufactured in a variety of outside diameters, and weights (Table 2) which assuming a specific gravity for steel of 490 lb/cuft, is a reflection of the wall thickness of the drillpipe. The drillpipe is also manufactured in a variety of material grades (Table 3). The specification for a particular string of drillpipe could therefore appear as:
5” 19.5 lb/ft Grade S Range 2
All of these specifications will influence the burst, collapse, tensile and torsional strength of the drillpipe and this allows the drilling engineer to select the pipe which will meet the specific requirements of the particular drilling operation.
Care must be taken when using the specifications given in Table 2 since although these are these are the normally quoted specifications for drillpipe, the weights and dimensions are ‘nominal’ values and do not reflect the true weight of the drillpipe or the minimum internal diameter of the pipe.
The weight per foot of the pipe is a function of the connection type and grade of the drillpipe and the weight per foot that should be used when calculating the true weight of a string of pipe is given in Table 13.
The weight of the pipe calculated in the manner described above will reflect the weight of the drillpipe when suspended in air (“Weight in air”). When the pipe is suspended in the borehole it will be immersed in drilling fluid of a particular density and will therefore be subjected to a buoyant force. This buoyant force will be directly proportional to the density of the drilling fluid. The weight of drillpipe when suspended in a fluid (“Wet Weight”) can be calculated from the following:
Buoyant Weight (“Wet Weight”) of Drillpipe = Weight of pipe in Air x Buoyancy Factor
The buoyancy factor for a particular density of drilling fluid can be found from Table 15.
Institute of Petroleum Engineering, Heriot-Watt University
The term drillstring is used to describe the tubulars and accessories on which the drillbit is run to the bottom of the borehole. The drillstring consists of drillpipe, drillcollars, the kelly and various other pieces of equipment such as stabilisers and reamers, which are included in the drillstring just above the drillbit (Figure 1). All of these components will be described in detail below. The drillcollars and the other equipment which is made up just above the bit are collectively called the Bottom Hole Assembly (BHA). The dimensions of a typical 10,000 ft drillstring would be :
The functions of the drillstring are:
• To suspend the bit
• To transmit rotary torque from the kelly to the bit
• To provide a conduit for circulating drilling fluid to the bit
It must be remembered that in deep wells the drillstring may be 5-6 miles long.
Safety requires constant monitoring of the drilling process. If drilling problems are detected early remedial action can be taken quickly, thereby avoiding major problems. The driller must be aware of how drilling parameters are changing (e.g. WOB, RPM, pump rate, pump pressure, gas content of mud etc.). For this reason there are various gauges installed on the driller’s console where he can read them easily.
Another useful aid in monitoring the well is mudlogging. The mudlogger carefully inspects rock cuttings taken from the shale shaker at regular intervals. By calculating lag times the cuttings descriptions can be matched with the depth and hence a log of the formations being drilled can be drawn up . This log is useful to the geologist in correlating this well with others in the vicinity. Mudloggers also monitor the gas present in the mud by using gas chromatography.
To remove the formation fluids now trapped in the annulus a high pressure circulating system is used. A choke manifold with an adjustable choke is used to control flow rates during the circulation. Basically heavier mud must be pumped down the drillpipe to control the formation pressure, and the fluids in the annulus circulated to surface. As the kick starts moving up the hole the choke opening is restricted to hold enough back pressure on the formation to prevent any further influx. The fluids are circulated out via the choke line, through the choke manifold out to a gas/mud separator and a flare stack (Figure 16). Once the heavier mud has reached surface the well should be dead.