This chapter presents general processs for drill threading design. The design facets of critical importance and factors commanding drill pipe choice are highlighted.
The term “ Drill Stem ” is used to mention to the combination of tubulars and accoutrements that serve as a connexion between the rig and the drill spot ( RGU talk slides ) . It consists chiefly of Drill Pipe, Drill Collars ( DC ) and Heavy Weight Drill Pipes ( HWDP ) and accoutrements including spot subs, top thrust bomber, stabilizers, jars, juicers etc. Drill root is frequently used interchangeably with the term “ Drill String ” which really refers to the articulations of drill pipe in the drill root.
For the intent of this study, “ Drill String ” will be used to mention to the twine of drill pipes that together with drill neckbands and heavy weight drill pipe make up the drill root see fig 3.1.
3.1 DRILL STEM COMPONENT DESCRIPTION
3.1.1 Drill Pipe
The drill pipes are seamless pipes normally made from different steel classs to different diameters, weights and lengths. They are used to reassign rotary torsion and boring fluid from the rig to the bottom hole assembly ( drill neckbands plus accoutrements ) and bore spot. Each drill pipe is referred to as a joint, with each joint consisting of a pipe organic structure and two connexions ( see fig 3.2 ) . Drill pipe lengths vary, and these different lengths are classified as scopes, the available or more common scopes include:
Scope 1: 18 – 22 foot
Scope 2: 27 – 30ft
Scope 3: 38 – 40ft.
Fig 3.1: Drill Stem with constituents. ( Heriott Watt University talk Notes: Drilling Engineering )
Drill pipes are besides manufactured in different sizes and weights which reflects the wall thickness of the drill 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 air ( pipe organic structure weight excepting tool articulations ) of the drill pipe. A complete listing of API recognised bore pipe sizes, weight and classs are published in the API RP 7G.
The drill pipe class is an indicant of the minimal output strength of the drill pipe which controls the explosion, prostration and tensile burden capacity of the drill pipe. The common drill pipe classs are presented in the tabular array below
Output Strength, pounds per square inch
Table 3.1: Drill Pipe Grades.
Drill pipes are frequently used to bore more than one well, hence in most instances the drill pipe would be in a worn status ensuing in its wall thickness being less than it was when the drill pipe was trade name new. In order to place and distinguish drill pipes, they are grouped into categories. The different categories are an indicant of the grade of wear on the wall thickness of the drill pipe. The categories can be summarised as follows harmonizing to API criterions:
New: Never been used, with wall thickness when to 12.5 % below “ nominal ” .
Premium: Uniform wear with minimal wall thickness of 80 % .
Class 2: Allows bore pipe with a minimal wall thickness of 70 % .
It is indispensable that the drill pipe category be identified in drill pipe usage or design, since the extent of wear affects the drill pipe belongingss and strength.
When stipulating a peculiar articulation of drill pipe, the category, class, size, weight and scope have to be identified, the specification could therefore appear therefore: 5 ” 19.5 lb/ft Grade S Range 2
Fig 3.2: Partss of Drill pipe. ( Handbook for Petroleum and Natural gas )
3.1.2 Tool Joints
Tools articulations are screw type connexions welded at the terminals of each articulation of a drillpipe. The tool articulations have coarse tapered togss and sealing shoulders designed to defy the weight of the drill threading when it is suspended in the faux pass. Tool articulations are of two sorts ; the pin ( male subdivision ) and the box ( female subdivision ) . Each drill pipe has a pin attached to one terminal and a box attached at the other terminal. This makes it possible for the pin of one articulation of drill pipe to be stabbed into box of a old drill pipe. There are several sorts of tool articulations widely used:
Internal Upset ( IU )
Tool articulation is less than the pipe. Tool joint OD is about the same as the pipe.
Internal Flush ( IF )
Tool articulations ID is about the same as the pipe. The OD is upset.
Internal / External Upset ( IEU )
Tool articulation is larger than the pipe such that the tool articulation ID is less than the drill pipe. The tool articulation OD is larger than the drill pipe.
Table 3.2 Types of tool articulations. ( The Robert Gordon University Lecture Notes: Drill String Design )
3.1.3 Drill Collars
Drill neckbands are thick walled tubings made from steel. They are usually the prevailing portion of the bottom hole assembly ( BHA ) which provides Weight on Bit ( WOB ) . Due to the big wall thickness of the drill neckbands, the connexion togss could be machined straight to the organic structure of the tubing, thereby extinguishing the demand for tool articulations ( see fig 3.3 ) . Drill neckbands are manufactured in different sizes and forms including unit of ammunition, square, triangular and coiling grooved. The slipperiness and coiling grooved drill neckbands are the most common forms used presently in the industry. There are drill neckbands made from non-magnetic steel used to insulate directional study instruments from magnetic intervention arising from other drill root constituents. The steel class used in the industry of drill neckbands can be much lower than those used in drill pipes since they are thick walled.
Provide weight on spot
Provide stiffness for BHA to keep directional control and minimise spot stableness jobs.
Provide strength to map in compaction and prevent buckling of drill pipes.
Fig 3.3: Carbon Steel Drill Pipes.
3.1.4 Heavy Weight Drill Pipe
Heavy weight drill pipes ( HWDP ) are frequently manufactured by machining down drill neckbands See fig 3.4. They normally have greater wall thickness than regular drill pipe. HWDP are used to supply a gradual cross over when doing passage between drill neckbands and bore pipes to understate stress concentration at the base of the drill pipe. These stress concentrations frequently result from:
Difference in stiffness due to the difference in cross-sectional country between the drill neckband and bore pipe.
Bit resiling originating from rotary motion and cutting action of the spot.
HWDP can be used in either compressive or tensile service. In perpendicular wellbores it is used for passage and in extremely deviated Wellss, it used in compaction to supply weight on spot.
Fig 3.4: Heavy Weight Drill Pipe. ( Heriott Watt University talk Notes: Drilling Engineering )
Drill Stem accoutrements include:
Stabilizers: these are made of a length of pipe with blades on the external surface. The blades are coiling or consecutive, fixed or mounted on gum elastic arms to let the drill threading rotate interior.
Functions of the stabilizer include:
Brace the drill collars to cut down buckling and bending
Ensure unvarying burden of tricone spots to cut down wobbling and increase spot life.
To supply necessary wall contact and stiffness behind the spot to bring on positive side force to construct angle when boring deviated Wellss.
Reamers: used in the BHA to enlarge the well bore diameter and ream out doglegs, cardinal seats, shelfs.
Boring Jars: incorporated in the BHA to present a crisp blow and aid in liberating the drill threading should it go stuck.
3.2 DRILL STRING DESIGN
The drill threading design is carried out in order to set up the most efficient combination of drill pipe size, weight, and classs to carry through the boring aims of any peculiar hole subdivision at the lowest cost within acceptable safety criterions.
In order to plan a drill threading to be used in a peculiar hole subdivision, the following parametric quantities need to be established:
Hole subdivision deepness
Hole subdivision size
Expected clay weight
Desired safety factors in tenseness and overpull.
Desired safety factor in prostration
Length of drill neckbands required to supply coveted WOB including OD, ID and weight per pes.
Drill pipe sizes and review category
The drill threading design has to run into the undermentioned demand:
The working tonss ( tenseness, prostration, explosion ) on the drill threading must non transcend the rated burden capacity of each of the drill pipes.
The drill neckbands should be of sufficient length to supply all needed WOB to forestall clasping tonss on the drill pipe.
The drill pipes used have to guarantee the handiness of sufficient fluid flow rate at the drill spot for hole cleansing and good rate of incursion.
3.2.1 Design Safety Factors
Design safety factors are applied to calculated working tonss to account for any unexpected service burden on the drill threading. They are used to stand for any characteristics that are non considered in the burden computations e.g. temperature and corrosion, therefore guaranting that service tonss do non transcend the load capacity of the drill pipe. Design safety factor values are frequently selected based on experience from operating within a peculiar country, the extent of uncertainness in the operating conditions e.g. when runing in HPHT conditions, a larger safety factor is applied than when runing in less rough conditions. Some normally used design safety values are illustrated in the tabular array below
Design Safety Factor Value
1.1 – 1.3
Margin of overpull ( MOP )
50,000 – 100,000. MOP of 400,000 have been used in extremist deep Wellss
Weight on Bit
1.15 or 85 % of available Weight on spot to guarantee impersonal point is 85 % of drill collar twine length steps from the underside ( API RP 7G )
1.0 ( based on the lesser of the pipe organic structure or tool joint strength )
1.1 – 1.15
3.2.2 Drill Collar Selection
The drill neckbands are selected with the purpose of guaranting that they provide sufficient WOB without clasping or seting the lower subdivision of the drill threading in compaction.
184.108.40.206 Size choice
Lateral motion of the drill spot is controlled by the diameter of the drill collar straight behind it. Therefore the size/diameter of the drill collar closest to the spot will be dependent on the needed effectual minimal hole diameter and the relationship can be given as
When two BHA constituents of different cross-sectional countries are to be made – up, it is indispensable that the bending opposition ratio ( BRR ) be evaluated. This is of import because BHA constituents have tensile and compressive forces moving on them when they are dead set in the well bore. These forces cause emphasis at connexions and any location where there is a alteration in cross-sectional country. Therefore it is of import to guarantee that these emphasiss are within acceptable scopes. The bending opposition ( BR ) of a drill threading constituent is dependent on its subdivision modulus which is given as
Z = subdivision modulus, in3
I = 2nd minute of country, in4
OD = outside diameter, in
ID = inside diameter, in
The BRR is used to show any alteration in BR and can be calculated utilizing
BRR should by and large be below 5.5 and in terrible boring conditions, below 3.5.
When choosing connexions to be used with drill neckbands, it is indispensable to look into that the BRR of the pin and box indicates a balanced connexion. The BRR for drill collar connexion is calculated as the subdivision modulus of the box divided by the subdivision modulus of the pin. The API RP 7G contains tabular arraies that can be used to find BRR for any box and pin OD. BRRs of 2.5 have given balanced connexions ( RGU Lecture notes, 2005 ) .
220.127.116.11 Weight on Bit
The maximal weight on spot required is usually a map of the spot size and type. The regulation of pollex is:
Maximum WOB of 2000lbf per inch of spot diameter when utilizing Polycrsyalline Diamond Compact spots ( PDC ) and mud motors.
Maximum WOB of 5000lbf per inch of spot diameter when utilizing tricone spots.
Other factors commanding WOB include disposition, hole size and buckling.
In perpendicular wellbores the length of drill neckbands required to supply a specified weight on spot is given by
LDC = Length of Drill Collars, foot
WOB = Weight of Bit, pound
DFBHA = Safety factor to maintain impersonal point in drill neckbands.
WDC = Weight per pes of Drill Collars, lb/ft
Kb = Buoyancy Factor.
The impersonal point as described by ( Mian, 1991 ) mentioning to Lubinksi, is the point that divides the drill root into two parts, with the subdivision above the impersonal point in tenseness and that below in compaction. Therefore in order to guarantee that the full length of drill pipes remain in tenseness, the impersonal point of the drill root has to be maintained within the drill neckbands. Harmonizing to the API RP 7G, the tallness of the impersonal point measured from the underside of the drill neckbands will be 85 % of the entire length of drill neckbands used, with 85 % being the safety factor.
In inclined wellbores, the angle of disposition has to be taken into consideration when ciphering the maximal WOB that can be applied without clasping the drill pipe. This is because although the WOB is applied at the disposition of the wellbore, this weight acts vertically, therefore cut downing the available weight at the spot.
Therefore to let for this decrease, the buoyed weight of the BHA would be reduced by the cosine of the well disposition, therefore WOB in inclined holes is calculated with the expression
All parametric quantities remain as defined in equation 5 ; I? is the angle of disposition of the well.
As a consequence of the vertically moving weight of the BHA, the drill threading 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 impersonal point could merely clasp if the compressive forces in the drill threading exceed a critical sum. This critical buckling force is calculated as follows
Fcrit = critical buckling force, pound
ODHWDP = outside diameter of HWDP, in.
ODtj = maximal outside diameter of pipe, in.
IDHWDP = inside diameter of HWDP, in.
Kb = perkiness factor.
Dhole = diameter of hole, in.
I? = hole disposition, grades.
Since HWDP are sometimes used to use WOB in inclined Wellss, and bore pipes are sometimes used in compaction, the critical buckling force is calculated for both HWDP and bore pipes.
3.2.3 Drill Pipe Selection
Factors to be considered for drill pipe choice include:
Maximum allowable working tonss in tenseness, prostration, explosion, and tortuosity.
Maximum allowable dogleg badness at any deepness in order to avoid fatigue harm in the drill pipe.
Combined tonss on the drill pipe.
The tonss considered when choosing drill pipes to be used in the drill twine is dependent on the well deepness, good bore geometry and hole subdivision aims.
In shallower perpendicular Wellss, prostration and tenseness are of more importance than explosion or tortuosity. Burst is usually non considered in most designs since the worst instance for a burst burden on the drill pipe would happen when coercing the drillstring with a out of use spot nozzle, even with this status, the explosion opposition of the drill pipe is likely to be exceeded. Torsion is of less importance in perpendicular well dullards because retarding force forces are at minimum sums unlike in extremely deviated Wellss. The dogleg badness of the well for both perpendicular and deviated Wellss is of import because of increased weariness in the drill pipe when it is rotated in the curving subdivisions of the wellbore.
A graphical method is recommended for drill pipe choice, with the tonss plotted on a burden versus deepness graph. This makes it possible for tonss at peculiar points on the drill threading to be easy visualised, and any subdivisions of the drill pipe that do non run into the burden demands are easy identified and redesigned.
Drill pipes are sometimes exposed to external force per unit areas which exceed its internal force per unit areas, thereby bring oning a prostration burden on the drill pipe. The worst scenario for prostration in a drill pipe is during drill root trials when they are run wholly empty into the wellbore. The prostration tonss are highest at the bottom articulation of the drill pipes, as a consequence, the prostration burden would usually command the drill pipe class to be used at the underside of the drill threading. The API specified prostration opposition for different sizes and classs of drill pipe presuming either elastic, fictile or passage prostration depending on their diameter to palisade thickness ratio have been calculated and are published in the API RP 7G with the relevant expression.
The maximal prostration force per unit area on the drill pipe when it is wholly empty can be calculated as follows:
Personal computer = prostration force per unit area, pounds per square inch
MW = clay weight, ppg
TVD = true perpendicular deepness at which Pc acts, foot.
On some occasions, the clay weight outside the pipe varies from that inside the pipe, besides the fluid degrees inside and outside the pipe may besides change. This state of affairs could besides bring on prostration tonss. The prostration tonss induced by this scenario can be calculated therefore
L = Fluid deepness outside the drill pipe, foot
MW = Mud weight outside the drill pipe, ppg
Y = fluid deepness inside drill pipe, foot
MW ‘ = Mud weight indoors drill pipe, ppg.
The value for Pc is so plotted on the prostration burden graph as the prostration burden line see fig 3.5.
It is recommended pattern to use a design safety factor to the prostration burden calculated from equations 8 or 9 ( depending on expected scenarios ) in order to account for unexpected extra tonss every bit Wellss as unknown variables. The value of the design factor is frequently between 1.1 – 1.5 for category 2 drill pipes. Harmonizing to ( Adams, 1985 ) the design factor should be 1.3 to account for the fact that new drill pipes are frequently non used for drill root trials. The value of the prostration burden multiplied by the prostration design factor is plotted on the prostration burden graph as the design line, this is so used to choose an appropriate class and weight of drill pipe to carry through these load conditions.
Fig 3.5: Sample Collapse burden graph.
18.104.22.168 Tension Load
The tensile burden capacity of the drill twine should be evaluated to guarantee there is adequate tensile strength in the topmost articulation of each size, weight, class and category of to back up the weight of the drill threading submerged in the wellbore, therefore the demand to include perkiness in the computations. There has to besides be plenty modesty tensile strength to draw the drill threading out of the well if the pipe gets stuck. The stabilizer and spot weight can be neglected when ciphering the drillstring weight.
In a perpendicular wellbore, the forces moving on the drill threading are tenseness from its ego weight and the hydrostatic force per unit area from the fluid in the wellbore. The hydrostatic force per unit area in the wellbore exerts an upward force on the cross sectional country of the drill twine, which is normally referred to as perkiness. Therefore the ensuing tensile burden on the drill threading attached to bore neckbands, taking history of perkiness is calculated as:
FTEN = end point tensile burden on drill twine, pound
LDP = length of drill pipe, foot
LDC = length of drill neckbands, foot
WTDP = air weight of drill pipe, lb/ft
WTDC = air weight of drill neckbands, lb/ft
MW = Mud weight, ppg.
ADC = Cross sectional country of drill neckbands, in2
FTEN is plotted on the tenseness burden graph as the tensile burden line.
The tensile strength values for different sizes, classs and review categories of drill pipes are contained in the API RP 7G, and can be calculated from the equation:
Fyield = lower limit tensile strength, pound
Ym = specified minimal output emphasis, pounds per square inch
A = cross subdivision country, in2
Fyield is plotted as the lower limit tensile strength line on the tenseness burden graph.
However, these values ( Fyield ) are theoretical values based on minimal countries, wall thickness and output strength of the drill pipes. Therefore, these values merely give an indicant of the emphasis at which a certain entire distortion would happen and non the specific point at which lasting distortion of the stuff begins. If a pipe is loaded to the lower limit tensile strength calculated from equation 11, there is the possibility that some lasting stretch may happen, thereby doing it hard to maintain the pipe directly in the wellbore. In order to extinguish the possibility of this happening, 90 % of the lower limit tensile strength as recommended by the API ( American Petroleum Institute ) , should be used as the maximal allowable tensile burden on the drill pipe, i.e
Fdesign = maximal allowable tensile burden
0.9 = a changeless relating relative bound to give strength.
Fdesign is plotted on the tenseness burden graph as the maximal allowable tensile burden line.
As with the prostration burden, a design factor would be applied to the tensile loads to account for dynamic tonss in the drill pipe which occur when the faux pass are set, every bit good as prevent the happening of pipe separating near to the surface. The merchandise of FTEN and the design factor is plotted as the tenseness design burden line in the tenseness burden graph see fig 3.6.
Margin Of Overpull
A border for overpull is added to the tenseness burden to guarantee there is sufficient tensile strength in the drill pipe when it is pulled in the event of a stuck pipe. This border is usually 50,000 – 100,000lb, but in deeper Wellss borders of overpull have reached 300,000lb. The value obtained after adding the border of overpull is besides plotted on the tenseness burden graph see fig 3.6.
The difference between the deliberate tensile burden at any point in the drillstring ( FTEN ) and the maximal allowable tenseness burden would besides stand for the available overpull. This value represents available tensile strength of the drill pipe to defy any excess forces applied to the drill threading when seeking to let go of it from a stuck pipe state of affairs.
FTEN and Fa can besides be expressed as a safety factor
This safety factor is an indicant of how much the selected drill pipe will be able to defy expected service tonss. Due to uncertainness with existent service tonss and conditions, a safety factor greater than 1 is ever required.
Slip suppression is by and large non a job if the faux pass are decently maintained. However, it is necessary to use a safety factor for faux pas suppression when planing the drill threading. This helps account for the hoop emphasis ( SH ) caused by the faux pass and the tensile emphasis ( ST ) caused by the weight of the drill threading suspended in the faux pass. This relationship between SH and ST can be represented by the undermentioned equation
SH = hoop emphasis, pounds per square inch
ST = tensile emphasis, pounds per square inch
D = outside diameter of the pipe, in.
K = sidelong burden factor on faux pass,
Ls = length of faux pass, in.
= faux pas taper normally 9A° 27 ‘ 45 ”
omega = arctan I?
I? = coefficient of clash, ( about 0.08 )
The deliberate tensile burden is multiplied by the faux pas crush factor ( ) to obtain the tantamount tensile burden from faux pas suppression:
Ts = tenseness from faux pas suppression, pound
TL = tenseness burden in drill twine, pound
SH / ST = faux pas crush factor.
Ts is besides plotted on the tenseness burden graph as the faux pas crush design line.
Fig 3.6: Sample Tension burden graph
The general bit-by-bit process for drill pipe choice utilizing the graphical method is given as
1. Calculate the expected prostration burden on drill pipe and use the prostration design safety factor to deduce the design burden. Use the consequence to choose weight and class of drill pipe that satisfy prostration conditions. Plot expected prostration burden and design burden on a force per unit area vs. deepness graph.
2. Calculate maximal allowable tensile burden for the drill pipe selected in ( 1 ) above. Besides calculate tenseness burden on the drill threading including perkiness effects. Plot the tenseness burden, specified minimal output strength, and maximal allowable tensile burden values on axial burden vs. deepness graph.
3. Use tenseness design factor, border of overpull, and faux pas crush factor to the deliberate tenseness burden and secret plan the single consequences on the axial burden vs. deepness graph. Of the three factors applied to the tenseness burden, the one resulting in the highest value is selected as the worst instance for tensile tonss.
4. Inspect graph and re-design any subdivisions non run intoing the burden demands.
When planing a tapered drill twine, the maximal length of a peculiar size, weight, class and category of drill pipes that can be used to bore the selected hole subdivision with specified WOB can be calculated as:
All parametric quantities remain as defined in equation 10 and 11. Note that equation 16 is merely used when the MOP design line is the worst instance scenario for tensile tonss. When faux pas suppression is the worst instance, the expression below is used
SF = safety factor for faux pas suppression.
The lightest available drill pipe class should be used foremost in order to guarantee that that the heavier classs are used upper subdivision of the drill threading where tensile tonss are the highest.
3.2.4 Dog Leg Severity
Fatigue harm is the most common type of drill pipe failure. It is known to be caused by cyclic flexing tonss induced in a drill pipe when it is rotated in the curving subdivisions of the wellbore. The rotary motion of the drill pipe in the curving hole subdivisions induce emphasiss in the outer wall of the drill pipe by stretching it and increasing its tensile tonss. Fatigue harm from doglegs tends to happen when the angle exceeds a critical value. This critical value can be calculated as:
C = maximal allowable Canis familiaris leg badness, deg/100ft
E = Young ‘s modulus, pounds per square inch ( 30 x 106 for steel, 10.5 Ten 106 for aluminum )
D = Drill pipe outer diameter, in.
L = half the distance between tool articulations, ( 180 in, for scope 2 pipe )
T = tenseness below the dogleg, pound
I?b = upper limit allowable bending emphasis, pounds per square inch.
I = drill pipe 2nd minute of country, =
I?b, is calculated from the buoyant tensile emphasis ( I?t ) and is dependent on the class of the pipe.
I?t = T/A, where T is defined in equation 19, and A is the transverse sectional country of the pipe organic structure in in2.
For class E pipe,
The consequences from equation 20 are valid for I?t values up to 67,000psi.
For class S pipe,
The consequences from equation 21 are valid for I?t values up to 133,400psi.
It is recommended that an allowable dogleg badness ( DLS ) versus depth chart be plotted for every hole subdivision with a peculiar drill threading design since DLS alterations with deepness. The chart is plotted with the DLS on the x-axis and deepness on the y-axis ( see fig 3.7 ) . When DLS lies to the left 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 insecure conditions.
Fig 3.7: Allowable Dogleg Severity Chart. ( Mian, 1991 )
Drill pipe torsional output strength is of import when planning deviated Wellss and extremist deep Wellss. In deviated Wellss, increased retarding force forces moving on the drill threading from its interaction with the wellbore addition torsional tonss on the drill pipe. In deeper Wellss, it is of import in stuck pipe state of affairss, in order to cognize the maximal torsion that can be applied to the drill twine.
The pipe organic structure torsional output strength when subjected to torque entirely can be calculated from the equation:
Q = minimal torsional output strength, foot pound
J = polar 2nd minute of country, Iˆ/32 ( D4 – d4 )
D = pipe OD in, vitamin D = pipe ID in.
Ym = minimal output strength, pounds per square inch.
3.2.6 Combined Loads On The Drill String
Collapse and Tension
The prostration opposition of the drill pipe is frequently reduced when the drill pipe is exposed to both tenseness and prostration tonss. This happens because tensile tonss stretch the drill pipe thereby impacting its D/t ( diameter -wall thickness ratio ) which controls the prostration opposition of the drill pipe.
In extremist deep Wellss, the consequence of combined prostration and tenseness is experienced when map proving the Blow out Preventers ( BOP ) . It is going common pattern in ultradeep boring to fit BOPs with trial random-access memory in order to enable the BOP be tested without puting stoppers in the well caput. This is done to salvage lilting clip due to extreme good deepnesss. An illustration given by ( Chatar, 2010 ) , utilizing 65/8in 27.70lb/ft drill pipe showed that with 65/8in drill pipe holding 860kips of maximal allowable tensile tonss, at half of this burden, the drill twine is merely capable of defying 4,500psi prostration tonss, which is frequently non sufficient for ultradeep boring BOPs.
The corrected prostration opposition of drill pipes under tenseness can be calculated utilizing the expression
Roentgen represents the per centum of the prostration opposition left when the drill pipe is under tenseness, hence in equation 25, the value for R is used to multiply the normal plastic prostration opposition of the pipe to give the prostration opposition under tenseness.
Roentgen can besides be determined diagrammatically with the undermentioned stairss
1. Calculate Z utilizing equation 24
2. Enter the oval for biaxal emphasis ( fig 3.8 ) on the horizontal axis with the value for Z and pull a perpendicular line to the oval curve.
3. Pull a horizontal line from the perpendicular line drawn in ( 2 ) above to the perpendicular axis and read off the value.
4. Use the value from ( 5 ) above to multiply the prostration opposition to acquire the corrected prostration opposition with tenseness.
Fig 3.8: Ellipse of Biaxial output Strength: Consequence of tensile lading om prostration opposition. ( RGU Lecture notes: Casing design )
Combined tenseness and tortuosity
The torsional output strength of a drill pipe is significantly reduced when the pipe is under tenseness tonss. The torsional output strength of the drill pipe under tenseness can be calculated with the equation
Q = minimal torsional output strength under tenseness, foot pound
J = polar 2nd minute of country.
D = pipe OD in, d= pipe ID in.
Ym = minimal output strength, pounds per square inch
P = entire burden in tenseness, pound
A = cross – sectional country, in2
3.2.7 Tool Joint Performance
The make-up torsion to be applied to the tool articulations when linking bore pipes is calculated as follows
ID = inside diameter, in.
OD = outside diameter, in.
Valuess for X, M, B and Q for standard connexions are presented in the tabular array below
Type of Connection
NC 31 ( 2 7/8 IF )
NC 38 ( 3 A? IF )
NC 46 ( 4 IF )
NC 50 ( 4 A? IF )
6 5/8 Regular
7 7/8 Regular
8 5/8 Regular.
Table 5: Ten, M, B and Q for standard connexions. ( RGU talk notes: Drill threading design )
Valuess of emphasis ( S ) to be used
Make up Torque Calculation
Tool articulation of drill pipes
S = 72,000psi
S = 120,000 pounds per square inch ( 2 )
Drill Collar ( OD & lt ; 7 ” )
62,500 ( 1 )
110,000 ( 2 )
Drill Collar ( OD & gt ; 7 ” )
62,500 ( 1 )
100,000 ( 2 )
( 1 ) API recommendation ( RP 7G )
( 2 ) Minimum yield strength of stuff, specified by API ( Spec. 7 )
Table 6: Stress values for make up ( RGU talk notes: Drill threading design )
3.2.8 Critical traffic circle Speed
The critical traffic circle velocity to bring on cross quiver in the drill twine can be estimated with the undermentioned expression
L = length of one pipe, in.
D = outside diameter of pipe, in
D = inside diameter of pipe, in.
The critical traffic circle velocity to bring on axial quiver in the drill twine can be estimated with the undermentioned expression
L = entire length of twine, foot.
Operation under the critical velocities calculated from the expressions above should be avoided every bit much as possible to forestall bring oning a combination of both quiver sorts.