Introduction to Drilling Systems PDF

Soran University Introduction to Drilling Systems Introduction to Drilling Systems SOU20242 CHAPTER 3 – DRILL STRING 1|Page Dr. Jagar Aziz Ali Contents 1. Introduction................................

Soran University Introduction to Drilling Systems Introduction to Drilling Systems SOU20242 CHAPTER 3 – DRILL STRING 1|Page Dr. Jagar Aziz Ali Contents 1. Introduction.............................................................................................................................3 2. Drill Pipe.................................................................................................................................4 1.1. Drillpipe Stress and Failure..............................................................................................6 1.2. Drillpipe inspection..........................................................................................................7 1.3. Drillpipe Classification....................................................................................................8 3. Tool joints...............................................................................................................................9 4. Heavy wall drillpipe (HWDP)..............................................................................................11 5. Drill collars...........................................................................................................................12 a. Special types of collar........................................................................................................12 6. Other drillstring components................................................................................................13 a. Roller reamer.....................................................................................................................13 b. Stabilisers...........................................................................................................................13 c. Subs (substitutes)...............................................................................................................14 d. Drilling jars........................................................................................................................14 e. Shock Sub (vibration dampener).......................................................................................14 7. Drill-string design.................................................................................................................16 a. Design of a stabilized string...............................................................................................16 b. Drillstring selection............................................................................................................17 i. Drillpipe selection..........................................................................................................17 ii. Drillcollar weight and length.....................................................................................18 c. Drillstring design criteria...................................................................................................18 i. Collapse load..................................................................................................................20 ii. Tension Load..............................................................................................................21 iii. Design Factor.............................................................................................................23 iv. Slip Crushing..............................................................................................................23 v. Additional design variables............................................................................................24 8. Calculations...........................................................................................................................25 2|Page Petroleum Engineering Department  Soran University Introduction to Drilling Systems 1. Introduction The term drillstring is used to describe the tubular 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: Component Outside diameter (in) Length (ft) Drillbit 12 1/4” Drillcollars 9 1/2” 600 Drillpipe 5” 9400 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. Figure 1 Components of the drillstring. 3|Page Dr. Jagar Aziz Ali  2. Drill Pipe 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 tooljoints are clearly visible in the drillstring. Tooljoints will be discussed in greater depth below. Figure 2 Tooljoints 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 rig-site 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 drillpipe tally. The drillpipe is also manufactured in a variety of outside iameters, 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 specification for a particular string of drillpipe could therefore appear as: 5” 19.5 lb/ft Grade S Range 2 4|Page Petroleum Engineering Department  Soran University Introduction to Drilling Systems The drillpipe is also manufactured in a variety of material grades (Table 3). The grade of drill pipe describes the minimum yield strength of the pipe. API defines five grades: D, E, X, G and S. However, in oil well drilling, only grades E, G and S are actually used. In most drillstring designs, the pipe grade is increased if extra strength is required. 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 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 Table 1 Drillpipe lengths API Range Length, ft 1 18-22 2 27-30 3 38-45 Table 2 Dimensions of drillpipe OD (in) ID (in) Weight (Ib/ft) 2 3/8 1.815 6.65 2 7/8 2.151 10.40 3½ 2.992 9.50 3 1/2 2.764 13.30 5 4.602 15.52 5 4.408 16.25 5 4.276 19.50 5 4.00 25.60 5½ 4.776 21.90 5 1/2 4.670 24.70 Table 3 Drillpipe Material Grades API Grade Minimum Yield Minimum Tensile 𝐘𝐢𝐞𝐥𝐝 𝐒𝐭𝐫𝐞𝐬𝐬 Stress (psi) Stress (psi) (𝒓𝒂𝒕𝒊𝒐) 𝐓𝐞𝐧𝐬𝐢𝐥𝐞 𝐒𝐭𝐫𝐞𝐬𝐬 D or D-55 55,000 95,000 0.58 E or E-75 75,000 100,000 0.75 X or X-95 95,000 105,000 0.7 G or G-105 105,000 115,000 0.91 S or S-135 135,000 145,000 0.93. 5|Page Dr. Jagar Aziz Ali a. Drillpipe Stress and Failure 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: 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. 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. 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. Figure 3 Cyclic loading 6|Page Petroleum Engineering Department  Soran University Introduction to Drilling Systems Corrosion of a drillstring in a water-based mud is primarily due to dissolved gases, dissolved salts and acids in the wellbore, such as: 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. 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. 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. 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 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). Organic acids – These produce corrosions by lowering the pH, remove protective films and provide hydrogen to increase hydrogen embrittlement. b. Drillpipe inspection When new pipe manufactured, they will be subjected to a series of mechanical tests by the manufacturer such as; 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. 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 7|Page Dr. Jagar Aziz Ali This means that a piece of drillpipe may be used on up to 25 wells which are 10,000ft 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 use 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 summarized 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 are shown in Table 5. 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. Table 4 Summary of inspection techniques Method Description Comments Optical Visual inspection Slow and can be in error if pipe internals not properly cleaned Magnetic Particle Magnetise pipe ends and observe Simple and efficient. attraction of ferrous particles to cracks No information on wall thickness detected by UV light Magnetic Induction Detect disturbances in magnetic flux No information on wall thickness. field by pits, notches and cracks Internal cracks have to be verified using magnetic particle technique Ultra Sonic Pulse echo technique No information on cracks. Very effective on determination of wall thickness c. Drillpipe Classification Drill pipe, unlike other oilfield tubulars such as casing and tubing, is re-used and therefore often worn when run. As a result, the drill pipe is classified to account for the degree of wear. The API has established guidelines for pipe classification in API RP7G. A summary of the classes follows:  New: No wear, has never been used.  Premium: Uniform wear and a minimum wall thickness of 80% of new pipe.  Class 2: Drill pipe with a minimum wall thickness of 65% with all the wear on one side so long as the cross-sectional area is the same as the premium class.  Class 3: Drill pipe with a minimum wall thickness of 55% with all the wear on one side 8|Page Petroleum Engineering Department  Soran University Introduction to Drilling Systems Drill pipe classification is an important factor in the design and use of drill pipe since the degree of wear will affect the pipe properties and strengths. API RP7G provides a series of tables which detail the strengths and properties of the various grades and classes of pipe as shown in table 5. Table 5 Classification of used drillpipe and used tubing work strings Classification of used drill pipe and used tubing work strings (All Sizes, Weights and Grades. Nominal dimension is basis for all calculations) 1 2 3 4 Condition Pipe condition Premium class Class 2 Class 3 A) OD wear wall Remaining wall not less Remaining wall not less than Remaining wall than 80% 65% not less than B) Dents & marshes Not over 3% of OD Not over 4% of OD 55% C) Slip area dia. variations; 1- Crushing Not over 3% of OD Not over 4% of OD 2- Necking Not over 3% of OD Not over 4% of OD D) Stress induced dia. variations; 1- Stretched Not over 3% of OD Not over 4% of OD reduction Exterior reduction 2- String Shot Not over 3% of OD Not over 4% of OD increase increase E) Cuts, gouges & corrosion Remaining wall not less - Round Bottom Remaining wall knotless than than 80% 65% Remaining wall not less - Sharp Bottom: than 80% Longitudinal Remaining wall not less than Remaining wall not less 65% than 80% and length not Transverse Remaining wall not less than over 10% 65% and length not over 10% F) Fatigue cracks None None None - Corrosive piping wall Remaining wall not less Remaining wall not less than than 80% 80% Interior - Erosion & wear wall Remaining wall not less Remaining wall not less than than 80% 80% - Fatigue cracks None None None 4. Tool joints Tooljoints 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 tooljoints. 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 9|Page Dr. Jagar Aziz Ali 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 tooljoints (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 6. It should be noted that the I.D. of the tooljoint is less than the I.D. of the main body of the pipe. Figure 4 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 and is therefore exposed to possible damage. Tool joint life can be substantially extended if connections are greased properly when the connection is made-up and a steady torque applied. 10 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems Table 6 API tool joints 5. Heavy wall drillpipe (HWDP) 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: 1. Increased wall thickness 2. Longer tool joints 3. Uses more hard facing 4. 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. Figure 5 Heavyweight drillpipe 11 | P a g e Dr. Jagar Aziz Ali  6. Drill collars 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 functions 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 drillcollars 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. Drillcollars 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. It is very important that proper care is taken when handling drillcollars. 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. Special types of collar Square collars These collars are usually 1/16” less than bit size, and are run to provide maximum stabilization 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. 12 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems 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 6). Figure 6 Spiral drillcollar 7. Other drillstring components a. Roller reamer 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 7). 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). b. Stabilisers 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 stabilizer), which allows the drillstring to rotate within it. The function of the stabilizer 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 summarized 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 under gauge and are less efficient. Stabilisers are 13 | P a g e Dr. Jagar Aziz Ali usually replaced if they become 1/2” under gauge (3/16” under gauge may be enough in some instances). c. Subs (substitutes) Subs are short joints of pipe which act as crossovers (i.e. connect components which cannot otherwise be screwed together because of differences in thread type or size). d. Drilling jars 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. e. Shock Sub (vibration dampener) A shock sub is normally located above the bit to reduce the stress due to bouncing when the bit is drilling through hard rock. The shock sub absorbs the vertical vibration either by using a strong steel spring, or a resilient rubber element (Figure 10). Figure 7 Roller reamers 14 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems Figure 8 Stabilisers Figure 9 Stabiliser positions for Figure 10 Shock sub straight hole drilling 15 | P a g e Dr. Jagar Aziz Ali  8. Drill-string design There are four basic requirements which must be met when designing a drillstring: 1. The burst, collapse and tensile strength of the drillstring components must not be exceeded. 2. The bending stresses within the drill string must be minimized. 3. The drillcollars must be able to provide all of the weight required for drilling. 4. The BHA must be stabilised to control the direction of the well. a. Design of a stabilized string 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 Figure11). 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. Packed-hole assembly – 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 minimize the rate of change in deviation (Figure 12). Pendulum assembly – The first stabiliser of a pendulum assembly is placed some distance behind the bit. The unsupported section of drill collar (Figure 12) swing to the low side of the hole. Figure 11 Drilling through dipping strata 16 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems 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. Figure 12 Pendulum effect b. Drillstring selection i. Drillpipe selection The drillpipe is to provide a fluid conduit for pumping drilling mud, imparting rotary motion to the bit and for drill stem testing and squeeze cementing. Basic factors for consideration in drill string design includes: collapse, tension, dogleg severity and slip crushing. Collapse together with tension primarily applies to weight selection, grades and couplings. High-strength pipe is required in the lower sections of the drillstring for collapse resistance. Tension is considered to dictate the higher strength at the top of the well. “Classes” are given to drill pipe to account for its weight, grade and class. The weight per foot of the pipe is a function of the connection type and grade of the drillpipe. The weight per foot that should be used when calculating the true weight of a string of pipe is given in table 9. 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 17 | P a g e Dr. Jagar Aziz Ali 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 ii. Drillcollar weight and length The sizes and weight per foot of a range of drillcollar sizes are shown in table 10. The weights that are quoted in table 9 are the “weight in air” of the drillcollars. The length of drillcollars, L that are required for a particular drilling situation depends on the Weight on Bit, WOB that is required to optimize the rate of penetration of the bit and the buoyant weight per foot, w of the drillcollars to be used, and can be calculated from the following: 𝑊𝑂𝐵 𝐿= ………………………………………………....1 𝐵𝐹∗𝑊 For directional well: 𝑉𝑒𝑟𝑡𝑖𝑐𝑎𝑙 𝐿𝑒𝑛𝑔𝑡ℎ 𝐿= ……………………………………….2 𝐶𝑜𝑠 𝜃 Where: 𝞱 = well inclination 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 buoyant weight of these additional drillcollars must exceed the buoyant 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 1.15 L. c. Drillstring design criteria The criteria used in a drill string design are: 1. Collapse Load 2. Tension Load Burst pressure is not considered in drillstring design due to the fact that burst loads and backup loads are provided by the same fluid in the well. Therefore, under normal circumstances there are no effective burst loads, except during squeeze operations where surface pressure is applied. If squeeze pressures are high, a back-up annulus pressure would normally be applied to reduce the effective burst pressure. Collapse and tension considerations are used to select the pipe weights, grades and couplings. Slip crushing affects the tension design and pipe selection. Dogleg analysis is performed to study the fatigue damage resulting from rotation in doglegs. Doglegs analysis may not affect the selection 18 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems of the pipe; however, it will assist in determining the maximum permissible dogleg during any section of the well. Table 9 Drillcollar Weights Figure 14 Axial load on the drillstring 19 | P a g e Dr. Jagar Aziz Ali When selecting the drillpipe, the maximum tensile load that the string could be subjected to will have to be considered. In addition to the design load calculated on the basis of the string hanging freely in the wellbore the following safety factors and margins are generally added: Design Factor – a design factor is generally added to the loading line calculated above (multiply by 1.3). This allows for extra loads due to rapid acceleration of the pipe. Margin of Overpull – a “margin of overpull” (MOP) is generally added to the loading line calculated above. This allows for the extra forces applied to the drill string when pulling on stuck pipe. The MOP is the tension in excess of the drill string weight which is exerted. The MOP may be 50,000 – 100,000 lbs. Safety Factor – a safety factor for slip crushing is generally added to the loading line calculated above. This allows for the interaction of hoop stress (Sh) caused by the slips and the tensile stress (St) caused by the weight of the string. This effect reduces the allowable tension load. i. Collapse load The criteria to be used as a worst case for the collapse design of drill pipe are typically a DST. The maximum collapse pressure should be determined for an evacuated string, with mud hydrostatic pressure acting on the outside of the DP. Use of this criterion also accounts for incidence of a plugged bit or failure to fill the string when a float is used during trips into the hole. A design factor is used in constructing the collapse design line. The design factor to be used for this full evacuation scenario is 1.0. Collapse calculation 1. Drill Stem Testing (DST) The collapse pressure can be calculated when the string is partially empty, with different fluid density inside than outside, using the following equation: 𝐿∗𝜌1 (𝐿−𝑌)∗𝜌2 𝑃𝑐 = − …………………………………...…………………3 19.251 19.251 Where: Pc = collapse pressure (psi) Y = depth to fluid inside drillpipe L = total depth of well (ft) 𝞺1= fluid density outside the drillpipe (ppg) 𝞺2= fluid density inside the drillpipe (ppg) 20 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems The drillpipe is completely empty, Y = 0, 𝞺2= 0, then it becomes: 𝐿∗𝜌1 𝑃𝑐 = ………………………..………….…………........…………4 19.251 When the fluid density inside drillpipe is the same as that outside drillpipe, i.e. 𝞺1 =𝞺2 =𝞺, then it becomes: 𝐿∗𝜌 𝑃𝑐 = ………………..……………………………5 19.251 2. Design factor 𝑐𝑜𝑙𝑙𝑎𝑝𝑠𝑒 𝑟𝑒𝑠𝑖𝑠𝑡𝑎𝑛𝑐𝑒 𝑜𝑓 𝑑𝑟𝑖𝑙𝑙𝑝𝑖𝑝𝑒 𝐷𝐹 = …………………….6 𝑐𝑜𝑙𝑙𝑎𝑝𝑠𝑒 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 (𝑃𝑐 ) The valve of 1.125 is normally used for DF in collapse. ii. Tension Load The tensile resistance of drill pipe is usually de-rated by a design factor. The tension loading can be calculated from the known weights of the drill collars and drill pipe below the point of interest. The effect of buoyancy on the drill string weight, and therefore the tension, must also be considered. Buoyancy forces are exerted on exposed horizontal surfaces and may act upwards or downwards. These exposed surfaces occur where there is a change in cross-sectional area between different sections. The tension design is established by consideration of the following: Tensile Forces: These include: - weight carried - shock loading - bending forces Design factor Slip Crushing Design Tensile Forces a) Weight Carried The greatest tension (P) on the drillstring occurs at the top joint at the maximum drilled depth, see Figure 15. This is given by: 𝑃 = [(𝐿𝑑𝑝 𝑥 𝑊𝑑𝑝 + 𝐿𝑑𝑐 𝑥𝑊𝑑𝑐 )] 𝑥 𝐵𝐹 ……………….……7 21 | P a g e Dr. Jagar Aziz Ali  Where: 𝐿𝑑𝑝 = length of drillpipe per foot 𝑊𝑑𝑝 = weight of drillpipe per unit length 𝐿𝑑𝑐 = weight of drillcollars 𝑊𝑑𝑐 = weight of drillcollars per unit length BF = buoyancy factor Figure 15 Tension The drillstring should not be designed to its maximum yield strength to prevent the drillpipe from yielding and deforming. At yield, the drillpipe will have: - deformation made up of elastic and plastic (permanent) deformation - permanent elongation - permanent bend and it may be difficult to keep it straight To prevent this, API recommends that the use of maximum allowable design load (Pa), given by: 𝑃𝑎 = 0.9 𝑥 𝑃𝑡 …………………………………………….8 Where: 𝑃𝑎 = Max. Allowable design load in tension, lb 𝑃𝑡 = theoretical yield strength from API table 3, lb 0.9 = a constant relating proportional limit to yield strength From the above equation number 7 & 8 can obtain: 𝑀𝑂𝑃 = 𝑃𝑎 − 𝑃………………………………………….9 𝐷𝐹 = 𝑃𝑎 /𝑃 ……………………………………………10 Where: MOP = Margin of overpull, lb. DF = Design factor, dimensionless The Margin of Overpull is the minimum tension force above expected working load to account for any drag or stuck pipe. The MOP used is usually of the order of 100,000 lbs. When deciding on the magnitude of the MOP or DF, the following should be considered: Overall drilling conditions 22 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems Hole drag Likelihood of getting stuck Re-arranging equations 7, 8 & 9 gives the maximum length of pipe (Maximum Hole Depth) which can be used from a given grade/weight of drillpipe: 𝑃𝑡 ∗0.9−𝑀𝑂𝑃 𝑊 𝐿𝑑𝑝 = − 𝑊 𝑑𝑐 𝑥 𝐿𝑑𝑐 ………………………………11 𝑊𝑑𝑝 ∗𝐵𝐹 𝑑𝑝 b) Shock Loading The additional tensile force generated by shock loading is given by: 𝐹𝑠 (𝐼𝑏𝑓) = 1500 𝑥 𝑊𝑑𝑝 ……………………..………………12 Where 𝑊𝑑𝑝 = weight of drillpipe per unit length, lb/ft c) Bending The additional tensile force generated by bending is given by: 𝐹𝑏 (𝐼𝑏𝑓) = 63 𝑥 𝜃 𝑥 𝑊𝑑𝑝 𝑥 𝐷………………..……………..13 Where 𝜃 = dog-leg severity in °/100 ft D = outside diameter of pipe in inches iii. Design Factor A design factor of 1.6 should be applied to the tension loads calculated above if shock loading is not accounted for. If the shock loading is quantified and included in the load calculation, a design factor of 1.3 can be used. iv. Slip Crushing The maximum allowable tension load must also be designed to prevent slip crushing of the pipe. Reinhold and Spini proposed an equation to calculate the relationship between the hoop stress caused by the action of the slips and the tensile stress in the pipe resulting from the load of the pipe hanging in the slips. The equations used are as follows: 𝑇𝑠 = 𝑇𝐿 (𝑆𝐻 ⁄𝑆𝑇 )………………….…………………………..14 Where: TS =Tension load due to slip crushing TL =Static load tension SH/ST=Hoop stress to tension stress ratio as derived from the equation below: 0.5 𝑆𝐻 𝐷𝐾 𝐷𝐾 2 = (1 + 2𝐿 + (2𝐿 ) ) ……………......….……………..15 𝑆𝑇 𝑠 𝑠 23 | P a g e Dr. Jagar Aziz Ali Where: SH =Hoop stress (psi) ST =Tensile stress (psi) D =OD of the pipe (in) K =Later load factor on slips (1/tan (y + z)) y =Slip taper (typically 9.4625 degrees) z =Arctan µ µ =Coefficient of friction, typically 0.08 - 0.25 Ls =Length of slips, usually 12 - 16 in When all tension loads are calculated, the pipe grade selected in the collapse calculation can be assessed and modified for the tension requirements. It is usually preferable to increase the grade rather than the weight, as increasing weight usually has negative effects in terms of smaller clearance and high pressure drop. Couplings are then selected based on the tension design. For highly deviated well or horizontal wells torque and drag modeling is performed to evaluate tension strength requirements of the pipe and couplings and the computed torque is used for determining coupling requirements. v. Additional design variables Torsion The drillpipe torsional strength, when subjected to pure torsion is given by: 0.096167∗J∗ 𝑌𝑚 Q= ……………………....…………………16 𝐷 Where: Q = minimum torsional yield strength (lb-ft) Ym= minimum unit yield strength (psi) 𝜋 𝑥 (𝐷 4 −𝑑4 ) J = polar moment of yield inertia = = 0.098175 * (𝐷4 − 𝑑 4 ) 4 D = outside diameter (in) d = inside diameter (in) When drillpipe is subjected to both torsion and tension, as is the case during drilling operations, equation 16 becomes: 24 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems 2 2 −𝑃 0.096167∗J√𝑌𝑚 2 𝐴 𝑄𝑡 = …………………………………17 𝐷 Where: QT = minimum torsional yield strength under tension (lb-ft) A = cross-sectional area (in2) P = weight carried, (lb) Pipe Stretch of Submerged Drillstring e1 = stretch due to weight carried (i.e. weight of drillcollars) 𝑃𝑥𝐿 𝑒1 = 735,444 x 𝑊 ………………..……………………..18 𝑑𝑝 e2 = stretch due to suspended weight of drillpipe 𝐿2 𝑒2 = 9.625 x 107 𝑥 (65.44 − 1.44 x 𝜌𝑚 )…………………….19 Where: P = load carried in lbf L = length of drillpipe 𝜌𝑚 = mud density in ppg 9. Calculations Example 1: Dimensions and Weight of Drillpipe a. What is the weight in air of a joint (30 ft) of 5” 19.5 lb/ft Grade G drillpipe with 4 1/2”? b. What is the wet weight of this joint of drillpipe when immersed in a drilling fluid with a density of 12 ppg? Solution i. The weight (in air) of 30 ft, of 5” 19.5lb/ft Grade G drillpipe with 4 1/2” connections: 19.5 lb/ft (Approx. wt.) x 30 ft = 585 lbs ii. The weight of this string in 12 ppg mud: 585 lbs x 0.817 (buoyancy factor) = 578 lbs 25 | P a g e Dr. Jagar Aziz Ali Example 2: drillcollar dimensions and weights i. What is the weight in air of 200 ft of 9 1/2” x 2 13/16” drillcollar? ii. What is the weight of this drillcollar when immersed in 13 ppg mud? Solution i. The weight (in air) of 200 ft of 9 1/2” x 2 13/16” drillcollar is: 220.4 lb/ft (Approx. wt.) x 200ft = 44080 lbs ii. The weight of this string in 13 ppg mud: 44080 lbs x 0.801(buoyancy factor) = 35308 lbs Example 3: Length of drillcollars for a given WOB You have been advised that the highest rate of penetration for a particular 12 1/4” bit will be achieved when 25,000lbs weight on bit (WOB) is applied to the bit. Assuming that you are drilling a vertical well and that the bit will be run in 12 ppg mud, calculate the length of drillcollars required for providing 25,000 lbs WOB. A. Calculate the weight (in air) of 10000 ft of 5” 21.5 lb/ft Grade G drillpipe with 4 1/2” IF connections. B. Calculate the weight of this string in 12 ppg mud. C. Calculate the length of 9 ½″ x 2 13/16″ drillcollars that would be required to provide 25,000lbs WOB and keep the drillpipe in tension in 12 ppg mud. Solution A. The weight (in air) of 10,000 ft of 5” 19.5 lb/ft Grade G drillpipe with 4 1/2” IF connections: i. = 19.5 lb/ft x 10,000 ft ii. = 195,000 lbs B. The weight of this string in 12 ppg mud: i. = 195000 lbs x 0.817 (buoyancy factor) ii. = 159315 lbs C. The length of 9 1/2” x 2 13/16” drillcollars that would be required to provide 25,000 lbs WOB in 12 ppg mud: 25,000 lbs = 139 ft 220.4 lb/ft x 0.817 An additional length of drillcollars is required to ensure that the drillpipe is in tension when drilling. This additional length of collars will be required to overcome the buoyant force on the drillpipe and from the above will be equal to: 26 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems (195000 − 159315) = 198 ft 220.4 x 0.817 With an additional 15% length of drillcollar the total length of collar will be: (139 x 1.15) + 198 = 358 ft ******************************************** Example 4: Tension design with a single drillpipe A drill string consists of 600 ft of 8 ¼ in x 2 13/16 in drillcollars and the rest is a 5in drillpipe, 19.5 lbm/ft Grade X 95 drillpipe. If the required MOP is 100,000 lb and mud weight is 10 ppg, calculate the maximum depth of hole that can be drilled when (a) using a new drillpipe (Pt = 501,090 lb) (b) using Class 2 drillpipe having a yield strength (Pt) of 394,000 lb. Solution a) For new drillpipe (Pt = 501,090 lb), from using equation 11: 𝑃𝑡 ∗ 0.9 − 𝑀𝑂𝑃 𝑊𝑑𝑐 𝐿𝑑𝑝 = − 𝑥𝐿𝑑𝑐 𝑊𝑑𝑝 ∗ 𝐵𝐹 𝑊𝑑𝑝 Wight of the 8 ¼ in x 2.13/16 in drillcollars can be found from Table 10, which is equal to 161.3 Ibm/ft. Buoyancy factor, BF could be calculated as follow; 10 𝐵𝐹 = 1 − ( ) = 0.847 65.5 501,090 ∗ 0.9 − 100,000 161.3 𝐿𝑑𝑝 = − 𝑥 600 19.5 ∗ 0.847 19.5 𝐿𝑑𝑝 = 16,287 ft The maximum hole depth that can be drilled with a new drillpipe of Grade X95 under the given loading condition is = length of drillpipe + length of drillcollars = 16,287 + 600 = 16,887 ft b) For class 2 drillpipe (Pt = 394,000Ib), from using equation 11: 394,000 ∗ 0.9 − 100,000 161.3 𝐿𝑑𝑝 = − 𝑥 600 19.5 ∗ 0.847 19.5 𝐿𝑑𝑝 = 10,452 ft Maximum hole depth = 10,452 + 600 = 11,052 ft ******************************************** 27 | P a g e Dr. Jagar Aziz Ali Example 5: Drill Pipe Design Using Pressure-Area Method Well Data: Hole size =12¼" Bit Depth =11,000 ft Collar length =500 ft Drill Pipe =5" OD 4.276" ID (Available Grade X-95) Drill Collars =8" OD 3.0" ID Overpull =100,000 lbs Mud Weight =11.5 ppg DST packer depth =10,700 ft Length of Slips =16" Maximum anticipated surface pressure = 5000 psi Design Factors: Tension = 1.3 - 1.6 Collapse = 1.0 Burst = 1.1 Solution A graphical method will be used to select drillpipe grade/weight: 1. Construct the collapse load line by calculating the maximum collapse pressure at the bottom of the drill pipe, using equation 5. 𝐿∗𝜌 𝑃𝑐 = 19.251 Collapse load at 10,700 ft = 0.052 x 10,700 ft x 11.5 ppg = 6399 psi The design factor for collapse is 1.0. The design load is the calculated load multiplied by the design factor. In this case the design load is also 6399psi. 2. Plot the load and design lines graphically (see Figure 16) and select an appropriate pipe grade using API tables of pipe collapse resistance data. 3. Check the burst rating of the pipe grade chosen against the maximum anticipated applied surface pressure. Plot burst load and burst design (see Figure 16) In this instance the maximum applied surface pressure will be 5000 psi. Use of a design factor of 1.1 gives a design load of 5500 psi. 28 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems Figure 16 collapse and burst design loads 4. Calculate the tension load line using the following steps and plot graphically (figure 17). i. Calculate the buoyancy force (BF1) acting on the bottom of the drill collars using: BF1 = - (P x A) = - (0.052 x 11,000 x 11.5) x ((𝜋/4) x (82 - 32)) = - (6,578 psi) x (43.197 in2) = - 284,149 lb ii. Calculate the buoyancy force (BF2) acting at the top of the drillcollars. BF2 = (P x A) = (0.052 x 10,500 x 11.5) x [π/4 (82 - 52) + π/4 (4.2762 -32)] = (6,279) x (30.631 + 7.292) = + 238,119 lb iii. Calculate the drill collar weight DC Weight = 150 x 500 ft = + 75,000 lbs iv. Calculate the drill pipe weight DP Weight =19.5 x 10,500 = + 204,750 lb v. Calculate the shock load Shock load = 1500 x pipe weight per foot = 1500 x19.5 lb/ft = 29,250 lb vi. Now calculate the total dynamic load at surface Total dynamic load = - 284,149 (BF1) + 238,119 (BF2) + 75,000 (drillcollar weight) + 204,750 (drill pipe weight) + 29,250 (shock load) 29 | P a g e Dr. Jagar Aziz Ali  Total dynamic surface load = + 262,970 lbs Note: static load at surface = 233,720 lb i.e. Without shock load Static load at top of drillcollars = -284,149 + 75,000 (DC weight in air) = -209,149 lb Static load at bottom of drillpipe = 238,119 (BF2) + (-209,149) = 28,970 lb Dynamic load at bottom of drillpipe = 28,970 + 29,250 = + 58,220 lb Plot the static and dynamic load as shown in figure 16. 5. Calculate the design line for the tension load by multiplying the load on the drill pipe at surface and at the top of the collars by the 1.3 design factor (since shock loads have been included) and plot as in figure 17. Figure 17 static and dynamic loads 6. Calculate the design line for the MOP by adding the 100,000 lb overpull factor to the static tension load values calculated earlier and plot as in figure 18. 7. Calculate the design line for slip crushing using equation (15): K = (1/tan (y + z)) y = 9.4625 degrees z = Arctanπ = Arctan 0.08 = 0.0798 Ls = Length of slips, usually 12-16 in 1 K = =4 tan(9.5 + 0.09798) 30 | P a g e Petroleum Engineering Department  Soran University Introduction to Drilling Systems 0.5 SH 5x4 5x4 2 = (1 + +( ) ) = 1.42 ST 2 x 16 2 x 16 TL = static tension at surface = 233,720 lb Therefore, at the top of the well where the static tension load (i.e. excluding drag) is 233,720 lb. The slip crushing load: TS = TL (SH/ST) = 233,720 X 1.42 = 331,882 lb The slip crushing value is then recalculated at the bottom of drillpipe (28,970 x 1.42) and the slip crushing design line plotted through the two points as shown in figure 18. Figure 18 complete tension design 8. The tensile rating of the pipe in lb is computed from the cross sectional area of the pipe and the yield strength as follows: Drillpipe area = (π/4) (52 - 4.2762) =5.281 sq. in Tensile strength = area x yield strength =5.281 x 95000 psi=501,695 lb 9. Calculate the tension design factors (TDF) at surface: Tensile strength 501,695 Static TDF = = = 2.15 Static load 233,720 31 | P a g e Dr. Jagar Aziz Ali  Tensile strength 501,695 Dynamic TDF = = = 1.91 Dynamic load 262,970 Tensile strength 501,695 Overpull TDF = = = 1.5 Overpull load 233,720 + 100,000 ******************************************** Example 6: Pipe Stretch A 3.5’’ drillpipe, 13.3 lbm/ft. Grade S135 premium class, is used to run a 4.5’’ OD liner to 21,000 ft. If the length of drillpipe is 17,500 ft, the mud weight is 16 ppg and the total weight of the liner is 50,000 lb, calculate the total stretch in the drillpipe. Solution: e1 = stretch due to weight carried: 𝑃𝑥𝐿 50000 𝑥 17500 𝑒1 = = = 𝟖𝟗. 𝟓′′ 735,444 x 𝑊𝑑𝑝 735444 𝑥 13.3 e2 = stretch due to suspended weight of drillpipe 𝐿2 𝑒2 = 𝑥 (65.44 − 1.44 x 𝜌𝑚 ) 9.625 x 107 (17500)2 𝑒2 = 𝑥 (65.44 − 1.44 x 16) = 𝟏𝟑𝟒. 𝟗′′ 9.625 x 107 Total Stretch = e1+ e2 = 89.5 +134.9 = 224.4 in 32 | P a g e Petroleum Engineering Department