Procedures For Drill String Design Engineering Essay

Procedures For activity soak up end Engineering EssayThis chapter presents general procedures for utilization geartrain externalizeing. The trope aspects of vital brilliance and elements dominanceling obligate organ subway up driveion atomic number 18 highlighted.The bourne act Stem is apply to refer to the combination of tubulars and accessories that serve as a contact between the rig and the recitation modus operandi (RGU taunt slides). It consists mainly of recitation yell, action Collars (DC) and Heavy lading unit Drill Pipes (HWDP) and accessories including microchip subs, top drive subs, stabilisers, jars, reamers etc. Drill infrastructure is frequently utilize interchangeably with the term Drill String which actually refers to the joints of activity shrill in the practice session stem.For the purpose of this report, Drill String impart be use to refer to the run of employment shout outs that together with bore pegs and hefty pack bore lowground up make up the recitation stem come over fig 3.1.3.1 DRILL STEM COMPONENT DESCRIPTION3.1.1 Drill PipeThe work out hollos be seam slight(prenominal) thermionic tubes usually do from polar steel puts to different diameters, free fishs and durations. They are utilise to transfer rotary torsion and tireing fluid from the rig to the bottom great deal assembly ( use collars confirming accessories) and do microprocessor chip. Each exercise call is referred to as a joint, with separately joint consisting of a pipe body and two connections (see fig 3.2). Drill pipe lengths vary, and these different lengths are var.ified as shake offs, the usable or more common ranges includeRange 1 18 22 ftRange 2 27 30ftRange 3 38 40ft.Drill Stem. flesh 3.1 Drill Stem with components. (Heriott due west University lecture Notes exertioning Engineering)Drill pipes are to a fault manu detailured in different sizes and weights which reflects the rampart weight iness of the commit pipe. Some common sizes and their corresponding weights include 31/2 in. 13.30 lb/ft and 4 1/2in. 16.60 lb/ft. The indicated weight is the nominal weight in channelize (pipe body weight excluding asshole joints) of the example pipe. A complete listing of API recognised pattern pipe sizes, weight and says are published in the API RP 7G.The practice session pipe print is an indication of the borderline give birth military force of the use pipe which controls the fall apart, crumble out and tractile elongate up dexterity of the utilization pipe. The common practice session pipe cross offs are presented in the table infraGradeYield Strength, psiLetter buildationAlternate DesignationDD-5555,000EE-7575,000XX-9595,000GG-105105,000SS-135135,000Table 3.1 Drill Pipe Grades.Drill pipes are often employ to recitation more than one well, therefore in al virtually cases the tire pipe would be in a emaciated condition resulting in its wall thickn ess world less than it was when the commit pipe was brand new. In order to identify and differentiate utilisation pipes, they are grouped into classes. The different classes are an indication of the degree of tire on the wall thickness of the physical exertion pipe. The classes croupe be summarised as fol low-toneds according to API standardsNew Never been utilize, with wall thickness when to 12.5% below nominal. amplitude Uniform wear with token(prenominal) wall thickness of 80%. clear 2 Allows drill pipe with a minimum wall thickness of 70%.It is prerequisite that the drill pipe class be identify in drill pipe use or end, since the extent of wear affects the drill pipe properties and saturation.When specifying a peculiar(prenominal) proposition joint of drill pipe, the class, word form, size, weight and range put one over to be identified, the specification could therefore appear indeed 5 19.5 lb/ft Grade S Range 2Fig 3.2 Parts of Drill pipe. (Handbook for Petroleum and Natural gas)3.1.2 Tool JointsTools joints are screw role connections welded at the ends of each joint of a drillpipe. The asshole joints have coarse tapered threads and sealing shoulders designed to entertain the weight of the drill disembowel when it is suspended in the grammatical cases. Tool joints are of two kinds the pin (male partition) and the corner (female section). Each drill pipe has a pin attached to one end and a box attached at the other end. This makes it possible for the pin of one joint of drill pipe to be stabbed into box of a previous drill pipe. in that respect are several kinds of irradiation joints widely useJoint emblemDiagramDescription intragroup Upset (IU)Tool joint is less than the pipe. Tool joint OD is approximately the same as the pipe. inner(a) Flush (IF)Tool joints ID is approximately the same as the pipe. The OD is upset.Internal / External Upset (IEU)Tool joint is larger than the pipe such that the tool joint ID is less than the dri ll pipe. The tool joint OD is larger than the drill pipe.Table 3.2 Types of tool joints. (The Robert Gordon University Lecture Notes Drill String Design)3.1.3 Drill CollarsDrill collars are thick walled tubes made from steel. They are unremarkably the predominant part of the bottom hole assembly (BHA) which plys Weight on arcminute (WOB). Due to the large wall thickness of the drill collars, the connection threads could be machined directly to the body of the tube, thereby eliminating the need for tool joints (see fig 3.3). Drill collars are manufactured in different sizes and shapes including round, square, triangular and voluted grooved. The slick and spiral grooved drill collars are the most common shapes used currently in the industry. There are drill collars made from non- magnetic steel used to isolate directional survey instruments from magnetic interference arising from other drill stem components. The steel grade used in the manufacture of drill collars give the axe b e much light than those used in drill pipes since they are thick walled.FunctionsProvide weight on bitProvide scratchiness for BHA to maintain directional control and understate bit stability tasks.Provide strength to function in compression and prevent buckling of drill pipes.Fig 3.3 Carbon Steel Drill Pipes.3.1.4 Heavy Weight Drill PipeHeavy weight drill pipes (HWDP) are often manufactured by machining down drill collars expose fig 3.4. They usually have greater wall thickness than perpetual drill pipe. HWDP are used to bid a gradual enshroud over when making transition between drill collars and drill pipes to minimise seek concentration at the base of the drill pipe. These try concentrations often result fromDifference in stiffness due to the contrast in cross-sectional area between the drill collar and drill pipe.Bit bouncing arising from rotation and cutting action of the bit.HWDP lot be used in either compressive or tensile service. In upright well dolts it is used for transition and in highly deviated rise up, it used in compression to provide weight on bit.Fig 3.4 Heavy Weight Drill Pipe. (Heriott Watt University lecture Notes Drilling Engineering)3.1.5 AccessoriesDrill Stem accessories includeStabilisers these are made of a length of pipe with blades on the external surface. The blades are spiral or straight, fixed or mounted on rubber sleeves to go away the drill with shed rotate privi limbed.Functions of the stabiliser includeStabilise the drill collars to reduce buckling and change formEnsure uniform make fulling of tricone bits to reduce move and increase bit life.To provide necessary wall contact and stiffness behind the bit to induce positive side force to contour angle when drilling deviated well.Reamers used in the BHA to enlarge the well bore diameter and ream out doglegs, key seats, ledges.Drilling Jars incorporated in the BHA to hold open a sharp blow and assist in freeing the drill bowed quartered instrument should i t become stuck.3.2 DRILL STRING DESIGNThe drill drawstring design is carried out in order to establish the most economic combination of drill pipe size, weight, and grades to fulfil the drilling objectives of any particular hole section at the lowest cost within unobjectionable sentry go standards.In order to design a drill string to be used in a particular hole section, the pastime parameters need to be established welter section profoundnessHole section sizeExpected bog down weightDesired safety cistrons in tensity and overpull.Desired safety work out in cut offLength of drill collars needed to provide desired WOB including OD, ID and weight per foot.Drill pipe sizes and inspection classThe drill string design has to cumulate the following requirementThe works haemorrhoid (tension, break in, burst) on the drill string must non exceed the rated lodge capacity of each of the drill pipes.The drill collars should be of sufficient length to provide all required WOB to prevent buckling freightage up on the drill pipe.The drill pipes used have to view the availability of sufficient fluid flow rate at the drill bit for hole cleaning and good rate of penetration.3.2.1 Design Safety FactorsDesign safety genes are use to cypher working loads to consider for any unexpected service load on the drill string. They are used to consist any features that are not considered in the load calculations e.g. temperature and corrosion, thus ensuring that service loads do not exceed the load capacity of the drill pipe. Design safety factor determine are often selected based on experience from direct within a particular area, the extent of uncertainty in the direct conditions e.g. when operating in HPHT conditions, a larger safety factor is applied than when operating in less harsh conditions. Some commonly used design safety observe are illustrated in the table belowLoadDesign Safety Factor ValueTension1.1 1.3 boundary line of overpull (MOP)50,000 100,00 0. MOP of 400,000 have been used in ultra deep wellsWeight on Bit1.15 or 85% of available Weight on bit to realize neutral microscope stage is 85% of drill collar string length measures from the bottom (API RP 7G) contortion1.0 (based on the lesser of the pipe body or tool joint strength) hand1.1 1.15 dissever1.23.2.2 Drill Collar SelectionThe drill collars are selected with the aim of ensuring that they provide sufficient WOB without buckling or putting the lower section of the drill string in compression.3.2.2.1 Size selectionLateral movement of the drill bit is controlled by the diameter of the drill collar directly behind it. therefore the size/diameter of the drill collar obstructst to the bit allow for be open on the required effective minimum hole diameter and the relationship can be given asWhen two BHA components of different cross-sectional areas are to be made up, it is essential that the plication subway system ratio (BRR) be evaluated. This is important becaus e BHA components have tensile and compressive forces performing on them when they are bent in the well bore. These forces cause idiom at connections and any location where there is a change in cross-sectional area. Therefore it is important to ensure that these stresses are within agreeable ranges. The bending protection (BR) of a drill string component is dependent on its section modulus which is given asZ = section modulus, in3I = split second meaning of area, in4OD = away diameter, inID = inside diameter, inThe BRR is used to express any change in BR and can be calculated utilizeBRR should generally be below 5.5 and in severe drilling conditions, below 3.5.3.2.2.2 ConnectionsWhen selecting connections to be used with drill collars, it is essential to check that the BRR of the pin and box indicates a balanced connection. The BRR for drill collar connection is calculated as the section modulus of the box divided by the section modulus of the pin. The API RP 7G contains tab les that can be used to determine BRR for any box and pin OD. BRRs of 2.5 have given balanced connections (RGU Lecture notes, 2005).3.2.2.3 Weight on BitThe utmost weight on bit required is normally a function of the bit size and type. The rule of thumb is maximal WOB of 2000lbf per inch of bit diameter when using Polycrsyalline Diamond Compact bits (PDC) and mud motors. utmost WOB of 5000lbf per inch of bit diameter when using tricone bits.Other factors controlling WOB include inclination, hole size and buckling.In vertical wellbores the length of drill collars required to provide a condition weight on bit is given byLDC = Length of Drill Collars, ftWOB = Weight of Bit, lbDFBHA = Safety factor to keep neutral stoppage in drill collars.WDC = Weight per foot of Drill Collars, lb/ftKb = irrepressibility Factor.The neutral point as described by (Mian, 1991) referring to Lubinksi, is the point that divides the drill stem into two portions, with the section above the neutral point i n tension and that below in compression. Therefore in order to ensure that the entire length of drill pipes remain in tension, the neutral point of the drill stem has to be maintained within the drill collars. harmonise to the API RP 7G, the height of the neutral point measured from the bottom of the drill collars will be 85% of the total length of drill collars used, with 85% being the safety factor.In inclined wellbores, the angle of inclination has to be taken into consideration when calculating the supreme WOB that can be applied without buckling the drill pipe. This is because although the WOB is applied at the inclination of the wellbore, this weight acts vertically, thus reducing the available weight at the bit.Therefore to allow for this reduction, the buoyed weight of the BHA would be decreased by the cosine of the well inclination, thus WOB in inclined holes is calculated with the formulaAll parameters remain as defined in par 5 is the angle of inclination of the we ll.As a result of the vertically playacting weight of the BHA, the drill string tends to lie on the low side of the hole and is supported to some extent by the wall of the well bore. Therefore the pipes above the neutral point could only rumple if the compressive forces in the drill string exceed a captious amount. This critical buckling force is calculated as followsFcrit = critical buckling force, lbODHWDP = outside diameter of HWDP, in.ODtj = maximum outside diameter of pipe, in.IDHWDP = inside diameter of HWDP, in.Kb = buoyancy factor.Dhole = diameter of hole, in. = hole inclination, degrees.Since HWDP are sometimes used to apply WOB in inclined wells, and drill pipes are sometimes used in compression, the critical buckling force is calculated for two HWDP and drill pipes.3.2.3 Drill Pipe SelectionFactors to be considered for drill pipe selection includeMaximum permissible working loads in tension, clang, burst, and torsion.Maximum deductible dogleg acerbity at any depth in order to avoid dig damage in the drill pipe.Combined loads on the drill pipe.The loads considered when selecting drill pipes to be used in the drill string is dependent on the well depth, well bore geometry and hole section objectives.In shallower vertical wells, crack up and tension are of more importance than burst or torsion. Burst is normally not considered in most designs since the thrash case for a burst load on the drill pipe would overtake when pressuring the drillstring with a blocked bit nozzle, even with this condition, the burst resistance of the drill pipe is likely to be exceeded. Torsion is of less importance in vertical well bores because drag forces are at minimal amounts unlike in highly deviated wells. The dogleg severity of the well for two vertical and deviated wells is important because of increased fatigue in the drill pipe when it is revolve in the curving sections of the wellbore.A representical method is recommended for drill pipe selection, w ith the loads plan on a load versus depth graph. This makes it possible for loads at particular points on the drill string to be easily visualised, and any sections of the drill pipe that do not meet the load requirements are easily identified and redesigned.3.2.3.1 CollapseDrill pipes are sometimes exposed to external pressures which exceed its congenital pressures, thereby inducing a open load on the drill pipe. The worst scenario for washout in a drill pipe is during drill stem tests when they are run all empty into the wellbore. The come apart loads are highest at the bottom joint of the drill pipes, as a result, the disclose load would normally control the drill pipe grade to be used at the bottom of the drill string. The API specified collapse resistance for different sizes and grades of drill pipe assuming either elastic, pliant or transition collapse depending on their diameter to wall thickness ratio have been calculated and are published in the API RP 7G with the applicable formulae.The maximum collapse pressure on the drill pipe when it is completely empty can be calculated as followsPc = collapse pressure, psiMW = mud weight, ppgTVD = true vertical depth at which Pc acts, ft.On some occasions, the mud weight outside the pipe varies from that inside the pipe, as well the fluid levels inside and outside the pipe may also vary. This situation could also induce collapse loads. The collapse loads bring forth by this scenario can be calculated thusL = eloquent depth outside the drill pipe, ftMW = Mud weight outside the drill pipe, ppgY = fluid depth inside drill pipe, ftMW = Mud weight inside drill pipe, ppg.The value for Pc is and so plotted on the collapse load graph as the collapse load line see fig 3.5.It is recommended practice to apply a design safety factor to the collapse load calculated from pars 8 or 9 (depending on expected scenarios) in order to account for unexpected additional loads as wells as un chousen quantity variables. The value of the design factor is often between 1.1 1.5 for class 2 drill pipes. According to (Adams, 1985) the design factor should be 1.3 to account for the fact that new drill pipes are often not used for drill stem tests. The value of the collapse load multiplied by the collapse design factor is plotted on the collapse load graph as the design line, this is then used to select an appropriate grade and weight of drill pipe to fulfil these load conditions.Fig 3.5 examine Collapse load graph.3.2.3.2 Tension LoadThe tensile load capacity of the drill string should be evaluated to ensure there is enough tensile strength in the topmost joint of each size, weight, grade and class of to support the weight of the drill string submerged in the wellbore, whence the need to include buoyancy in the calculations. There has to also be enough reserve tensile strength to pull the drill string out of the well if the pipe gets stuck. The stabiliser and bit weight can be neglected when calculati ng the drillstring weight.In a vertical wellbore, the forces acting on the drill string are tension from its self weight and the hydrostatic pressure from the fluid in the wellbore. The hydrostatic pressure in the wellbore exerts an upward force on the cross sectional area of the drill string, which is commonly referred to as buoyancy. Therefore the resulting tensile load on the drill string attached to drill collars, taking account of buoyancy is calculated asFTEN = resultant tensile load on drill string, lbLDP = length of drill pipe, ftLDC = length of drill collars, ftWTDP = air weight of drill pipe, lb/ftWTDC = air weight of drill collars, lb/ftMW = Mud weight, ppg.ADC = Cross sectional area of drill collars, in2FTEN is plotted on the tension load graph as the tensile load line.The tensile strength values for different sizes, grades and inspection classes of drill pipes are contained in the API RP 7G, and can be calculated from the equationF move over = minimum tensile strength, lbYm = specified minimum give up stress, psiA = cross section area, in2F stomach is plotted as the minimum tensile strength line on the tension load graph.However, these values (Fyield) are theory-based values based on minimum areas, wall thickness and yield strength of the drill pipes. Therefore, these values only give an indication of the stress at which a certain total deformation would occur and not the specific point at which permanent deformation of the material begins. If a pipe is loaded to the minimum tensile strength calculated from equation 11, there is the possibility that some permanent stretch may occur, thereby making it difficult to keep the pipe straight in the wellbore. In order to eliminate the possibility of this occurrence, 90% of the minimum tensile strength as recommended by the API (American Petroleum Institute), should be used as the maximum allowable tensile load on the drill pipe, i.eFdesign = maximum allowable tensile load0.9 = a constant relating propo rtional limit to yield strength.Fdesign is plotted on the tension load graph as the maximum allowable tensile load line.As with the collapse load, a design factor would be applied to the tensile loads to account for kinetic loads in the drill pipe which occur when the trips are set, as well as prevent the occurrence of pipe parting close to the surface. The product of FTEN and the design factor is plotted as the tension design load line in the tension load graph see fig 3.6.Margin Of OverpullA margin for overpull is added to the tension load to ensure there is sufficient tensile strength in the drill pipe when it is pulled in the event of a stuck pipe. This margin is normally 50,000 100,000lb, but in deeper wells margins of overpull have reached 300,000lb. The value obtained after adding the margin of overpull is also plotted on the tension load graph see fig 3.6.The difference between the calculated tensile load at any point in the drillstring (FTEN) and the maximum allowable te nsion load would also represent the available overpull. This value represents available tensile strength of the drill pipe to stand fast any extra forces applied to the drill string when attempt to release it from a stuck pipe situation.FTEN and Fa can also be verbalized as a safety factorThis safety factor is an indication of how much the selected drill pipe will be able to withstand expected service loads. Due to uncertainty with actual service loads and conditions, a safety factor greater than 1 is always required. splay CrushSlip crushing is generally not a problem if the slips are properly maintained. However, it is necessary to apply a safety factor for slip crushing when designing the drill string. This helps account for the hoop stress (SH) caused by the slips and the tensile stress (ST) caused by the weight of the drill string suspended in the slips. This relationship between SH and ST can be delineate by the following equationSH = hoop stress, psiST = tensile stress, ps iD = outside diameter of the pipe, in.K = lateral load factor on slips,Ls = length of slips, in.= slip taper usually 9 27 45z = arctan = coefficient of friction, (approximately 0.08)The calculated tensile load is multiplied by the slip crush factor () to obtain the equivalent tensile load from slip crushingTs = tension from slip crushing, lbTL = tension load in drill string, lbSH / ST = slip crush factor.Ts is also plotted on the tension load graph as the slip crush design line.Fig 3.6 Sample Tension load graphThe general step-by-step procedure for drill pipe selection using the graphical method is given as1. search the expected collapse load on drill pipe and apply the collapse design safety factor to derive the design load. Use the result to select weight and grade of drill pipe that satisfy collapse conditions. spell expected collapse load and design load on a pressure vs. depth graph.2. Calculate maximum allowable tensile load for the drill pipe selected in (1) above. Also ca lculate tension load on the drill string including buoyancy effects. Plot the tension load, specified minimum yield strength, and maximum allowable tensile load values on axial load vs. depth graph.3. Apply tension design factor, margin of overpull, and slip crush factor to the calculated tension load and plot the individual results on the axial load vs. depth graph. Of the 3 factors applied to the tension load, the one resulting in the highest value is selected as the worst case for tensile loads.4. Inspect graph and re-design any sections not clashing the load requirements.When designing a tapered drill string, the maximum length of a particular size, weight, grade and class of drill pipes that can be used to drill the selected hole section with specified WOB can be calculated asAll parameters remain as defined in equation 10 and 11. Note that equation 16 is only used when the MOP design line is the worst case scenario for tensile loads. When slip crushing is the worst case, the formula below is usedSF = safety factor for slip crushing.The lightest available drill pipe grade should be used first in order to ensure that that the heavier grades are used stop number section of the drill string where tensile loads are the highest.3.2.4 get across Leg SeverityFatigue damage is the most common type of drill pipe failure. It is known to be caused by cyclic bending loads induced in a drill pipe when it is rotated in the curved sections of the wellbore. The rotation of the drill pipe in the curved hole sections induce stresses in the outer wall of the drill pipe by stretching it and increasing its tensile loads. Fatigue damage from doglegs tends to occur when the angle exceeds a critical value. This critical value can be calculated asC = maximum permissible dog leg severity, deg/100ftE = Youngs modulus, psi (30 x 106 for steel, 10.5 X 106 for aluminium)D = Drill pipe outer diameter, in.L = half the distance between tool joints, (180 in, for range 2 pipe)T = tensi on below the dogleg, lbb = maximum permissible bending stress, psi.I = drill pipe second moment of area, =b, is calculated from the buoyant tensile stress (t) and is dependent on the grade of the pipe.t = T/A, where T is defined in equation 19, and A is the cross sectional area of the pipe body in in2.For grade E pipe,The results from equation 20 are effectual for t values up to 67,000psi.For grade S pipe,The results from equation 21 are valid for t values up to 133,400psi.It is recommended that an allowable dogleg severity (DLS) versus depth graph be plotted for every hole section with a particular drill string design since DLS changes with depth. The chart is plotted with the DLS on the x-axis and depth on the y-axis (see fig 3.7). When DLS lies to the left hand of the line or below the curve, the drill pipe is in safe operating conditions, and when it falls above or to the right of the curve, it is in unsafe conditions.Fig 3.7 Allowable Dogleg Severity Chart. (Mian, 1991)3.2.5 TorsionDrill pipe torsional yield strength is important when planning deviated wells and ultra deep wells. In deviated wells, increased drag forces acting on the drill string from its interaction with the wellbore increase torsional loads on the drill pipe. In deeper wells, it is important in stuck pipe situations, in order to know the maximum torque that can be applied to the drill string.The pipe body torsional yield strength when subjected to torque alone can be calculated from the equationQ = minimum torsional yield strength, ft lbJ = polar second moment of area, /32 (D4 d4)D = pipe OD in, d = pipe ID in.Ym = minimum yield strength, psi.3.2.6 Combined Loads On The Drill StringCollapse and TensionThe collapse resistance of the drill pipe is often reduced when the drill pipe is exposed to both tension and collapse loads. This happens because tensile loads stretch the drill pipe thereby affecting its D/t (diameter -wall thickness ratio) which controls the collapse resistance of th e drill pipe.In ultra deep wells, the effect of combined collapse and tension is experienced when function testing the Blow out Preventers (BOP). It is decent common practice in ultradeep drilling to equip BOPs with test rams in order to enable the BOP be tested without setting plugs in the well head. This is done to save tripping time due to extreme well depths. An example given by (Chatar, 2010), using 65/8in 27.70lb/ft drill pipe showed that with 65/8in drill pipe having 860kips of maximum allowable tensile loads, at half of this load, the drill string is only fitting of withstanding 4,500psi collapse loads, which is often not sufficient for ultradeep drilling BOPs.The corrected collapse resistance of drill pipes under tension can be calculated using the formulaWhereR represents the percentage of the collapse resistance left when the drill pipe is under tension, therefore in equation 25, the value for R is used to cover the normal plastic collapse resistance of the pipe to gi ve the collapse resistance under tension.R can also be determined graphically with the following steps1. Calculate Z using equation 242. Enter the ellipse for biaxate stress (fig 3.8) on the swimming axis with the value for Z and draw a vertical line to the ellipse curve.3. Draw a horizontal line from the vertical line drawn in (2) above to the vertical axis and read off the value.4. Use the value from (5) above to multiply the collapse resistance to get the corrected collapse resistance with tension.Fig 3.8 Ellipse of Biaxial yield Strength Effect of tensile essence om collapse resistance. (RGU Lecture notes Casing design)Combined tension and torsionThe torsional yield strength of a drill pipe is significantly reduced when the pipe is under tension loads. The torsional yield strength of the drill pipe under tension can be calculated with the equationQ = minimum torsional yield strength under tension, ft lbJ = polar second moment of area.D = pipe OD in, d= pipe ID in.Ym = minimum yield strength, psiP = total load in tension, lbA = cross sectional area, in23.2.7 Tool Joint PerformanceThe make-up torque to be applied to the tool joints when connecting drill pipes is calculated as followsID = inside diameter, in.OD = outside diameter, in.Values for X, M, B and Q for standard connections are presented in the table belowType of ConnectionX