193687517 drill string design bha design
DESCRIPTION
Drill String DesignTRANSCRIPT
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DPT Drill String and BHA design
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IPM DPT
Drill String and BHA Design
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DPT Drill String and BHA design
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References API RP 7G Drill Stem Design and Op Limits API SPEC 7 Specifications for Rotary Drilling
Elements API SPEC 5D Specifications for Drill Pipe SLB Drill String Design manual TH Hill DS-1 Drill String Design
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At the end of this lecture YOU will be able to describe:
Functions of Drill Pipe , Drill Collars and BHA selection Grades of Drill Pipe and strength properties Thread types and tool-joints Drill collar weight and neutral point Bending Stress Ratios and Stiffness Ratios Margin Of Overpull Basic design calculations based on depth to be drilled. Functions of stabilizers and roller reamers.
Objectives
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I. Introduction to Drill String Design: Overview
II. Drill String Components
Drill Collars - Drill Pipe - HWDP
III. Drill String Design
Bottom Hole Assembly Design
Drill Pipe Selection
Buckling and max WOB
Agenda
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The drill string is the mechanical linkage connecting the drill bit on bottom to the rotary drive system on the surface.
The drillstring serves the three main following functions :
1. Transmit and support axial loads - WOB
2. Transmit and support torsional loads - rpm
3. Transmit hydraulics to clean the hole and cool the bit. WOBDC
DP
Functions of the Drill String
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The Drill String includes all tubular equipment between the Kelly Swivel and the bit
Kelly Surface Safety Valves
Drill Pipe
Heavy Walled Drill Pipe
Drill Collar
Jars Shock Subs Bumper Subs Junk Baskets Accelerators etc
Drill String Components
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Strictly speaking, Kelly/ Topdrive are not components of the drill string; however, they provide the essential requirements for drilling a well:
The Kelly/Top Drive
1) Transmit rotation to the drillstring.
2) Provide access to the drilling fluid into the drillstring.
3) Support the weight of the string.
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Transmits rotation and weight-on-bit to the drillbit Supports the weight of the drillstring Connects to the swivel and allow circulation thru
pipe.
The Kelly is the rotating link between the rotary table and the drill string.
The Kelly comes in lengths ranging from 40 to 54 ft with cross sections such as hexagonal (most common), square or triangular.
Connected to a Kelly Saver Sub
The Kelly
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The Kelly cock is used to close the inside of the drillstring in the event of a kick.
The upper & lower Kelly cocks operate manually.
IBOP / DPSV are not run in the drill string but kept handy on the rig floor
The Kelly is usually provided with two safety valves, one at the top and one at the bottom, called Kelly cock.
Kelly Cock
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DPT Drill String and BHA design
Schlumberger PrivateAdvantages over the kelly system:
1. Efficient reaming and back reaming.
2. Circulating while running in hole or pulling out of hole in stands
3. The kelly system can only do this in singles; ie 30 ft.
The top drive is basically a combined rotary table and kelly.
It is powered by a separate motor and transmits rotation to thedrill string directly without the need for a rotary table.
Top Drive
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Stabilizers
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StabilizersReasons for Using Stabilizers:
1. They are used as a fundamental method of controlling the directional behavior of most BHAs.
2. Help concentrate the weight of the BHA on the bit. 3. Minimize bending and vibrations which cause tool joint
wear and damage to BHA components such as MWDs.4. Reduce drilling torque by preventing collar contact with
the side of the hole and by keeping them concentric in the hole. (FG!!)
5. Help preventing differential sticking and key seating.
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Roller Reamers
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Drill Pipe
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Drill Pipe
FunctionTo serve as a conduit or conductor for drilling fluidTo transmit the rotation from surface to the bit on bottom
ComponentsA pierced, seamless tube of forged steel or extruded AluminumTool joints attached to each end of the seamless tube
Tool JointsProvide connections for the drill stringSeparate pieces of metal welded to the seamless tubeThick enough to have pin or box cut into them
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Drill Pipe Classification1. Size 2 3/8 to 6 5/8 refers to OD of pipe body
2. Length Range 1 18 to 22 ft, Range 2 27 to 30ft, Range 3 38 to 45 ft
3. Grade E - 75, X 95, G 105, S 135the numbers denote 1000s of psi minimum yield strength
4. Weight Depending upon the size of pipe different weight ranges
5. Class API classification for used pipe
For example a drill pipe could be - 5, Range 2, G-105, 19.5ppf, New
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Drill Pipe Grades
145,000 / 165,000135,000S or S-135
120,000 / 135,000105,000G or G-105
110,000 / 125,00095,000X or X-95
85,000 / 105,00075,000E or E-75
Avg / MaxYieldMin Yield Grade
There are four grades of pipe commonly used today.
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Mechanical Properties of Steel
Young ModulusE = Stress divided by Strain = 30,000,000
Stress & StrengthStress = Strength divided by Cross Section Area
Strain & stretchStrain = Stretch divided by original length
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Mechanical Properties of SteelElastic LimitLimit of stress beyond which, when the stress is removed, the steel will have acquired a permanent stretch.
Minimum Yield StressThe stress which gives a stretch of 0.5% (0.005). When the stress is removed, the steel will have acquired 0.2% of permanent deformation.
Ultimate Tensile StressThe stress which will break the steel
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Exercise DP-00
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New: No wear, has never been used
Premium: Remaining wall not less than 80%.
Class 2: Remaining wall not less than 70%.Class 3: Remaining wall less than 70%.
Other details such as, dents and mashing, slip area mechanical damage, stress induced diameter variations, corrosion cuts and gouges, specified on Table 24 ( Classification of Used Drill Pipe ) of API RP 7G.
Unlike casing and tubing, which are normally run new, drill pipe is normally used in a worn condition. It therefore has Classes:
Used Drill Pipe Classification
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Where the pipe joins the tooljoint, the pipe wall thickness is increased or upset.
This increased thickness is used to decrease the frequency of pipe failure at the point where the pipe meets the tool-joint.
The drill-pipe can have Internal upsets (IU), ( OD stays the same ) External upsets (EU), ( ID stays the same ) Internal and External Upsets (IEU).
Drillpipe Upsets
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Drill Pipe WeightsWhen referring to Drill Pipe Weights, there are four important ones:
Plain end Weight Refers to the weight per foot of the pipe body.
Nominal Weight - Refers to an obsolete standard. ( Weight of Range I pipe with connections ) Is used today to refer a class of Drill pipe.
Adjusted Weight Refers to the weight per foot of pipe including the upset but excluding the tool joint based on a length of 29.4 ft
Approximate Weight The average weight per foot of pipe and tool joints of Range II pipe. This approximate weight is the number to use in Design calculations.
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ToolJtAdj
ApproxToolJtAdjustedDP
L29.4Wt29.4Wt
Wt/ft
lengthadjustedjttool29.4jttoolwt.approx.29.4DPwt.adj.approx.Wt/ft
++=
++=
Calculating Approximate Weights
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4.29WtupsetNomWtTubeWt AdjDP +=
( ) ( )( )TE
TEAdjJtTool
DDd
DDdDLWt
+=
2
3322
501.0
167.0222.0
L= combined length of pin and box (in) D= outside diameter of pin (in)
d= inside diameter of pin (in) DTE= diameter of box at elevator upset (in)
Data from Spec 7 Fig 6 Table 7
.(1)
.(2)
Data from Table 7API 5D
( ) ftDDLL TEAdjJtTool 12253.2 += .(3)
Datat from Spec 7 Fig 6 Table 7
Calculating Approximate Weights
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Calculate the approximate weight of tool joint and drillpipeassembly for 5 in OD, 19.5 lb/ft Drill Pipe having NC50 tool joints with 6.625 in OD, 2.75 in ID and being internally-externally upset. ( IEU ).
Compare the value against the one published on Table 9 of API RP7G.
Exercise DP-01
Tables 7API 5D and Table 7 of the Specification can be found in handout # 1 of tables.Table 9 of API RP7G can be found on handout # 2 of tables.
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DP Data from Table 7 Spec 5d
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DP Data from Table 7 Spec 7
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Table 1-3 New Pipe Data
Table 4-5 Premium Pipe Data
Table 6-7 Class Two Pipe Data
Table 8-9 Tool-joint Data
Table 10 Make-up Torque Data
Table 12 Connection interchangeability
Table 24 Classification of used DP
API RP 7G
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All API tool joints have a minimum yield strength of 120,000 psiregardless of the grade of the drill pipe they are used on (E, X, G, S) .
API sets tool joint torsional strength at minimum 80% of the tube torsional strength.
Make up torque is determined by pin ID or box OD. The make up torque is 60% of the tool joint torsional capacity. The equation for determining make up can be obtained from the appendix of API RPG7. ( Numeral A.8.2 ). This equation is rather complex, so the API developed a series of charts to find the recommended make up torque to any connection given the tool jt OD of box and ID of pin. These charts can be found in API RP 7G ( Figures 1 to 25 )
Tool Joints
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Exercise DP02Using some tables (?) and some figures (?) of API RP7G what should be the make up torque of NEW 19.5 ppf G105 and S135 drill pipe ?
How do these values compare to the ones reported on Table 10 ?
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Make-Up Torque Charts
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The most common thread style in drillpipe is NC
The thread has a V-shaped form and is identified by the pitch diameter, measured at a point 5/8 inches from the shoulder
Connection Number is Pitch dia*10 truncated to two digits
5/8
GAUGE POINT PITCH DIAMETER
The size of a rotary shouldered connection is fixed by its gauge point pitch diameter.
Drillstring Connections
Multiply 5.0417 by 10 50.417Choose first two digits 50Hence NC 50
If the pitch diameter is 5.0417 in This is an NC50 connection
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Typical sizes: NC 50 for tool joints with 6 1/2 OD for 5pipe and NC 38 for 4 3/4 tool joints and 3 1/2 pipe.
Seal is provided by shoulder not threads. A clearance exists between the crest of one thread and the root of the mating thread
Use of Lead based dope vs Copper based dope for DCs. Not for sealing but for lubrication, to help make-up and prevent galling
There are 17 NCs in use : NC-10 (1 1/16) through NC-77 (7 3/4)
NC Drillstring Connections
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Connection Interchangeability
Ext FlushSlim Hole
Dbl Streamline
Extra Hole
Full HoleInt Flush
4-1/2EF4-1/243-1/22-7/8SH
5-1/24-1/23-1/2DSL
54-1/23-1/22-7/8XH4FH
4-1/243-1/22-7/82-3/8IF
NC50NC46NC 40NC 38NC 31NC 26
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Drill Collars
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Drill CollarsDescriptionThey are heavy walled metal tubesThe ends are threaded (box and pin)
FunctionsTo put weight on bit (WOB)To keep the drill string from buckling
TypesComes in many OD and ID sizesTypically 4 to 9 ODMost commonly in lengths of 30-31 feetSquare collars where the holes tend to be crookedSpiral collars where there is chance of getting stuckCollars with elevator and slip recesses
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1. Protect the Drill string from Bending and Torsion
2. Control direction and inclination of wells
3. Drill straighter holes or vertical holes
4. Provide Pendulum effect
5. Reduce dog legs, key seats and ledges
6. Improve the probabilities of getting casing in the hole.
7. Increase bit performance
8. Reduce rough drilling, sticking and jumping
9. As a tool in fishing, testing, completing
More functions of Drill Collars
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Slick Drill Collar Spiral Drill Collar
More Types of Drill Collars
1. Both slick and spiral drill collars are used .
2. In areas where differential sticking is a possibility spiral drill collars and spiral HWDP should be used in order to minimize contact area with the formation.
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Drill Collars Strappinglength
Fish neckelevatorrecess
sliprecess
OD
IDconnection
Well# TRG 1 Bit # 1Date: 28-Jul-03 Sl # 1234
Rig: IDPT Type atm 234BHA#: 1 Manuf Hughes
Hole Size 26" Jets 20-20-20
Item Sl # ID OD FN Pin Box Length RemarksBit 1234 26" 7 5/8" R 0.75 NewBit Sub SL 235 3 1/8" 9 1/2" 7 5/8 R 1.019 1/2" Drill Collar 9546 3 1/8" 9 1/2" 0.67 7 5/8" R 7 5/8 R 8.96Stab 237689 3 1/8" 9 1/2" 0.93 7 5/8" R 7 5/8 R 2.369 1/2" Drill Collar 9503 3 1/8" 9 1/2" 0.78 7 5/8" R 7 5/8 R 9.019 1/2" Drill Collar 9521 3 1/8" 9 1/2" 0.95 7 5/8" R 7 5/8 R 9.049 1/2" Drill Collar 9520 3 1/8" 9 1/2" 1.03 7 5/8" R 7 5/8 R 8.99
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API Drill Collar SizesOD ID Range Weight Range OD ID Range Weight Range
ppf ppf2 7/8 1 - 1.5 16 - 19 6 1/4 1.5 - 3.5 72 - 98
3 1 - 1.5 18 - 21 6 1/2 1.5 - 3.5 80 - 1073 1/8 1 - 1.5 20 - 22 6 3/4 1.5 - 3.5 89 - 1163 1/4 1 - 1.5 22 - 26 7 1.5 - 4 84 - 1253 1/2 1 - 1.5 27 - 30 7 1/4 1.5 - 4 93 - 1343 3/4 1 - 1.5 32 - 35 7.5 1.5 - 4 102 - 144
4 1 - 2.25 29 - 40 7.75 1.5 - 4 112 - 1544 1/8 1 - 2.25 32 - 43 8 1.5 - 4 122 - 1654 1/4 1 - 2.25 35 - 46 8 1/4 1.5 - 4 133 - 1764 1/2 1 - 2.25 41 - 51 8 1/2 1.5 - 4 150 - 1874 3/4 1.5 - 2.5 44 - 54 9 1.5 - 4 174 - 210
5 1.5 - 2.5 50 - 61 9 1/2 1.5 - 4 198 - 2345 1/4 1.5 - 2.5 57 - 68 9 3/4 1.5 - 4 211 - 2485 1/2 1.5 - 2.8125 60 - 75 10 1.5 - 4 225 - 2615 3/4 1.5 - 3.25 60 - 82 11 1.5 - 4 281 - 317
6 1.5 - 3.25 68 - 90 12 1.5 - 4 342 - 379
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Characteristics
DC connections are rotary shouldered connections and can mate the various DP connections
The shoulder provide the only positive seal against fluid leakage
The lubricant is Copper based dope
The connection is the weakest part of the entire BHA
The DC connections go through cycles of tension-compression and are subject to bending stresses
Improper M/U torque, improper or insufficient lubricant, gallingcan all lead to connection failure
Drill Collar Connections
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Stress Relief Features
Stresses in DC connections are concentrated at the base of the pin and in the bottom of the box (stronger)
DP body bends easily and takes up the majority of the applied bending stress, DP connections are therefore subjected to less bending than the DP body.
DCs and other BHA components are however much stiffer than the DPs and much of the bending stresses are transferred to the connections.
These bending stresses can cause fatigue failure at the connections Stress Relief Groove / Bore Back
Drill Collar Connections
M.Groznybase
M.Groznypin
M.Groznyof the
M.Groznyin the bottom of the box
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Stress Relief Pin Feature
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Stress Relief Pin & Box Features
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Drill Collar Connections The stress relief groove is to mitigate the fatigue cracks where the face and threads would have otherwise joined
The Bore Back serves the same purpose at the bottom of the box
Stress relief features should be specified on all BHA connections NC-38 or larger.
Pin stress relief grooves are not recommended on connections smaller than NC-38 because they may weaken the connections tensile and torsional strength.
Bore Back boxes could be used on smaller connections.
The Low-Torque face is to increase the compressive stress at normal M/U torque above that of a regular face
M.GroznyThe Bore Back serves the same purpose at the bottom of the
M.Groznybox
M.GroznyThe stress relief groove is to mitigate the fatigue crackswhere the face and threads would have otherwise joined
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Lo-Torq FeatureThe low torque feature consists in removing part of the shoulder area of the pin and box.This allows for lower make up torque maintaining adequate shoulder loading.It is a common feature in large OD connections.
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Torsion limits for DC
Torque is rarely limited by the DC connection because it is usually higher in the DP at surface and lower in the DC.
If DC make-up torque >Dp make-up torque you have no routine problems.
BH Torque at any point should not exceed 80% of make-up torque for the connections in the hole to avoid over tightening connections which can lead to damage of seals.
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Torque Limits for DCM/U Torque as % of total torque
API recommended make-up torque for connections is a percentage of the total torsional yield of the connection 62.5%56.8%API NC
56.2%51.1%H-90N/a79.5%PAC
DC>7 inDC< 7 in
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Make Up Torque Tables for DCs
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Heavy Weight Drill Pipe
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Heavy Weight Drill PipeDesignHeavier wall and longer tool jointsCenter wall padAlso available in spiral design
FunctionUsed in transition zones between DC and DPThis prevents the DP from bucklingCan be used in compression (?)Used for directional drillingUsed in place of DC sometimes (?)To keep Drill Pipe in tensionNot to be used for Weight on Bit in normal circumstances
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Has the same OD as a standard drill pipe but with much reduced inside diameter (usually 3for 5 DP) and has an integral wear pad upset in the middle.
It is used between standard Drill Pipe and Drill Collars to provide a smooth transition between the different sections of the drillstring components.
Tool-Joint and Rotary shouldered connection just like DP
HWDP, although stiffer than DP, can also buckle
Characteristics
Heavy Weight Drill Pipe
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HWDP can be run both in tension and in compression
BUT!!!
Manufacturers recommend not to run HWDP in compression in hole sizes larger than 12
Experience shows that they should not be run in compression in Vertical Holes
If run in compression, rules of thumb are: TJOD + 6 > OH diameter 2 x TJOD > OH diameter
HWDP in Compression?
Heavy Weight Drill Pipe
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I. Introduction to Drill String Design: Overview
II. Drill String Components
Drill Collars - Drill Pipe - HWDP
III. Drill String Design
Bottom Hole Assembly Selection
Drill Pipe Selection
Buckling and max WOB
Agenda
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Drill Collar Selection Principles Drill Collar selection is governed by two major factors:
Weight and Stiffness --- Size! Usually the largest OD collar that can be safely run is the best selection
More weight available for WOB Greatest stiffness to resist buckling and smooth directional tendencies Cyclical movement is restricted due to tighter Clearances
Usually Shortest BHA possible to Reduce handling time at surface Minimize # of Connections in the hole Minimize total DC in contact with the wall for differential sticking
exposure
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Weight
BHA Weight must be sufficient for the planned WOB BHA Weight must be sufficient to account for Buoyancy BHA Weight must be sufficient to account for hole
inclination BHA Weight must be sufficient so that the neutral point of
axial loads is within the BHA with a safety factor of 15%
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Compression
Tension
Neutral point
Design WOB
WOB
BHA DesignDrill Collar Weight & Neutral Point
DF for excess BHA=1.15
Neutral Point (NP) to tension should be in drill collars
15.1=WtWorkingMaxWtAvailableMax
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Procedure For Selecting Drill Collars:1. Determine the buoyancy factor for the mud weight in use using the formula below:
where
BF =Buoyancy Factor, dimensionless
MW =Mud weight in use, ppg
65.5 =Weight of a gallon of steel, ppg
BHA Design
BF = 1- (MW/65.5)
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2. Calculate the required collar length to achieve the desired weight on bit:
DC Length = 1.15* WOB / (BF*Wdc)
where:
WOB=Desired weight on bit , lbf (x 1000)
BF =Buoyancy Factor, dimensionless
W dc =Drill collar weight in air, lb/ft
1.15 =15% safety factor.
The 15% safety factor ensures that the neutral point remains within the collars when unforeseen forces (bounce, minor deviation and hole friction) are present.
BHA Design
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3. For directional wells:
DC Length = DC Length Vertical / Cos I
where: I= Well inclination
Note that for horizontal wells drill collars are not normally used and BHA selection is based entirely on the prevention of buckling
BHA Design
M.GroznyNote that for horizontal wells drill collars are not normally used andBHA selection is based entirely on the prevention of buckling
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Determine the number of 9 inch OD by 3 in ID drill collars required to provide a weight-on-bit of 55,000 lbf assuming
Hole deviation = 0
Mud density = 12 ppg
Number And Size Of Drill Collars
Exercise DP-03
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Stiffness
The BHA must have sufficient Stiffness to stabilize the BHA, optimize ROP and prevent the formation of Key Seats, ledges and doglegs
The larger the DC, the stiffer the BHA
Stiffness Coefficient := Moment of Inertia x Youngs Modulus of Elasticity= (OD4 ID4) / 64 x 30.000.000
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Exercise DP-04
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Bending Strength Ratio BSR is the relative stiffness of the box to the pin of a given connection. Describes the Balance between two members of a connection and how they
are likely to behave in a rotational cyclical environment
RdR
DbD
ZZBSR
RdR
DbD
ZZBSR
pin
box
pin
box
)(
)(
)(32
)(32
44
44
44
44
==
==
Where:
Zbox = box section modulusZpin = pin section modulusD = Outside diameter of pin and boxb = thread root diameter of box threads at
. end of pin.R = Thread root diameter of pin threads
. of an inch from shoulder of pin.
. d= inside diameter or bore.
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Section Modulus for Connections
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BSR in DC Connections A Connection is said to be balanced
if the BSR is 2.5 When BSR is higher tend to see
pin failures When BSR is lower tend to see
more box failures However, field experience has
shown that: 8 Dc having BSRs of 2.5
usually fail in the box 4-3/4 DC having BSR as low as
1.8 very rarely fail in the box.
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BSR in Connections
This table is from T.H. Hill & Associates Inc. Standard DS-1.
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Additional BSR Guidelines
High RPM, Soft Formation Small DC (8 in in 12.25 hole or 6 in in 8.25 hole) 2.25-2.75
Low RPM Hard Formations Large DC (10 in in 12-1/4 hole 2.5-3.2 (3.4 if using lo-torq connection)
Abrasive formations 2.5-3.0 New DCs 2.75 more wear resistant
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Fortunately for you API have worked the problem!!!
Pages 39-44 of Spec 7G list the BSR of Connections by OD and ID of the collar
API BSR Charts
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T.H.Hill BSR Tables
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Stiffness Ratio The SR measures the stiffness of a connection in a transition between 2
types of pipe Based on field experience, in a transitionfrom one collar or pipe to another the SR should not exceed
5.5 for routine drilling 3.5 for severe or rough drilling
( )( )4444
upruprlwr
lwrlwrupr
upr
lwr
IDODODIDODOD
ZZSR
==
Note: Stiffness ratios are calculated using tube ODs & IDs, not connections.
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BHA Design Process Design the Collars
Max OD DC which can be handled, fished and drilled with Excess BHA wt
WOB Buoyancy Safety factor
Connection Selection BSR SR Torque capability
Stabilization and other directional requirements
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Exercise DP-05On Seeyoulater land rig we find the following collars:9 OD x 3 ID 6 5/8 FH connection8 OD x 3 ID 6 5/8 REG connection6 OD x 2 ID NC46 connection
Given that we will drill a vertical 12 hole, with 9.5 ppg mud and 65000 pounds in a relatively hard formations, what API collar would you recommend?
What would your recommendation on BSR be for the connection chosen?Check your recommended DCs with your recommended BSR
What would be the SR between the DC and 5 DP be? Is it acceptable?If not what would you do?What would be your final BHA? Length? Buoyed Weight?
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I. Introduction to Drill String Design: Overview
II. Drill String Components
Drill Collars - Drill Pipe - HWDP
III. Drill String Design
Bottom Hole Assembly Selection
Drill Pipe Selection
Buckling and max WOB
Agenda
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Drill Pipe Selection Principles Drill Pipe selection is governed by two major factors:
Size+Weight and Strength
Usually the Drill Pipe with largest OD and ID is preferred Less pressure loss in the string More hydraulics available at the bit
The Drill Pipe selection must address the following: Drill Pipe must allow to drill to TD Drill Pipe must support all weight below it (BHA+DP) Drill Pipe must provide Overpull capacity Drill Pipe must withstand slip crushing force Drill Pipe must resist burst and collapse loads Drill Pipe might have to work in H2S environment
M.GroznyUsually
M.Groznythe Drill Pipe with largest OD and ID is preferred
M.GroznyLess pressure loss in the string
M.GroznyMore hydraulics available at the bit
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DPT Drill String and BHA design
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The greatest tension (working load Pw) on the drillstring occurs at the top joint at the maximum drilled depth
Working Strength
Drillcollars
Drillpipe Ldp
Ldc
P
Axial Loads
Tension Design
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DPT Drill String and BHA design
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Tension Design
Total weight, Tsurf, carried by the top joint of drillpipewhen the drill bit is just off bottom ;
( )[ ] BFWLWLT dcdcdpdpsurf +=Ldp = length of Drill Pipe
Wdp = weight of Drill Pipe per unit length
Ldc = weight of Drill Collars
Wdc = weight of Drill Collars per unit length
.(1)
Drillcollars
Drillpipe Ldp
Ldc
P
Drill Pipe Selection Parameters
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DPT Drill String and BHA design
Schlumberger Private
The drillstring is not designed according to the minimum yield strength!!!If Drill Pipe reaches yield:
Drill Pipe can have permanent deformation.
To prevent deformation damage to drillpipe, API recommends the use of maximum allowable design load ( Pa)
Tmax = 0.9 x Tyield .(2)
Tmax = Max. allowable design load in tension , lb
Tyield = theoretical yield strength from API tables , lb
0.9 = a constant relating proportional limit to yield strength
IPM Defines a tension Design factor of 1.1 be applied to design loads. These accomplish the same thing.
Do not double dip!
Tension Design
Drill Pipe Selection Parameters
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DPT Drill String and BHA design
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Margin of overpull is nominally 50-100k, or in the limit of the difference between the maximum allowable load less the actual load
Choice of MOP should consider
Overall drilling conditions
Hole drag
Likelihood of getting stuck
Slip crushing
Dynamic loading
Margin of Overpull
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DPT Drill String and BHA design
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1. Determine max design load (Tmax) : (maximum load that drillstring should be designed for)
Tmax = 0.9 x Minimum Yield Strength lb
Class of pipe must be considered
Drill Pipe Selection ParametersMargin of Overpull
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DPT Drill String and BHA design
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surf- TTMOP max =
3. Margin Of Overpull : Minimum tension force above expected working load to account for any drag or stuck pipe.
2. Calculate total load at surface using
( )[ ] BFWLWLT dcdcdpdpsurf +=
.(3)
.(1)
Margin of Overpull
Drill Pipe Selection Parameters
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DPT Drill String and BHA design
Schlumberger Private
dcdp
dc
dp
yielddp LW
WBFW
MOPTL
= 9.0
4. The maximum length of Drill Pipe that can be used is obtained by combining equations 1 and 3 and solving for the length of Drill Pipe
.(4)
Margin of Overpull
Drill Pipe Selection Parameters
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DPT Drill String and BHA design
Schlumberger Privatedc
dp
dc
dp
yielddp LW
WBFW
MOPTL
= 9.0
When the Drill String is stuck, (and it most certainly is if there is Overpull !) the buoyancy is lost!
.(4)
THINK OF STUCK PIPE!!!
When the Drill String is stuck, (and it most certainly is if there is Overpull !) the buoyancy is lost!
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DPT Drill String and BHA design
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Exercise DP-06 Drill Collars length : 600 and weight in air is 150 lb/ft. MOP = 100,000 lbs. 5 / 19.5 lb/ft Premium G-105 DP with NC50 connections. Calculate the maximum hole depth that can be drilled ? Assume BF= 0.85
Carry out calculations without MOP and with MOP of 100,000 lb
Use API - RP7G Tables for the values of Approximate Weight (Wdp) and for Minimum Yield Strength
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DPT Drill String and BHA design
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Slip Crushing Force Slips because of the taper try to crush the Drill Pipe. This
hoop stress is resisted by the tube, and this increases the overall stress in the steel
( )( )dopeforFrictioncoeffArcTanz
TaperSlipyzyKinlengthSlipLinODPipeD
LDK
LDK
SS
StressTensileStressHoop
s
sst
h
08.0;)()45279(;)tan(/1
;)(
221
'''
2
===+===
++=
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DPT Drill String and BHA design
Schlumberger Private
Generally expressed as a Factor
DPTUBE 12 in 16 in2 3/8 1.25 1.182 7/8 1.31 1.223 1/2 1.39 1.284 1.45 1.324 1/2 1.52 1.375 1.59 1.425 1/2 1.66 1.476 5/8 1.82 1.59
SLIP LENGTHHorz to Tang Stress Ratio
LoadAxialEquivalentStressTensile
StressHooploadWorking =*
Axialt
hLoad PS
SP =
Slip Crushing Force
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DPT Drill String and BHA design
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Drill Pipe Selection Parameters
You can only drill as far as you can set pipe in the slips. Different than overpull, this is based on working loads
dcdp
dc
dp
T
h
yield
dp LWW
BFWS
ST
L
=
9.0
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DPT Drill String and BHA design
Schlumberger Private
A drill string consists of 600 ft of 8 in x 2 13/16 in drill collars and the rest is a 5 in, 19.5 lbm/ft Grade X95 drill pipe with NC50 connections. If the required MOP is 100,000 lb and mud weight is 10 ppg, calculate:
1) The maximum depth of hole that can be drilled when using (a) new and (b) Premium Drill Pipe. (MOP only)
2) What is the maximum depth that can be drilled taking into consideration slip crushing force for (a) and (b) above? To whathook-load does this correspond? What is the MOP in this case?
Exercise DP-07
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DPT Drill String and BHA design
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Step 2 Drill collars and bottom drillpipe act as the weight
carried by top sectioneffectively the drill collar
Apply the equation for top drill pipe last
Step 1 If we use different drill pipe, the weaker pipe goes on
bottom and stronger on top Apply equation to bottom drill pipe first
dcdp
dc
dp
tdp LW
WW
MOPPL = 9.0
Mixed String Design
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DPT Drill String and BHA design
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An exploration rig has the following grades of DP to be run in a 15,000 ft deep well :
Grade E : New 5 OD 19.5 # NC 50 Grade G : New 5 OD 19.5# NC 50
It is desired to have an MOP of 50000 lbs on the grade E pipe. The total length and weight of DCs plus HWDP are 984 ft and 101,000 lb respectively. MW at 15,000 = 13.4 ppg.
Calculate :1. Max. length of E pipe that can be used.2. Length of G pipe to use.3. MOP for the G and E pipe.4. Max weight on slips for the G and E pipe.
Exercise DP - 09 Mixed Drill Pipe
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DPT Drill String and BHA design
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Other Loads Collapse under Tension Burst Other loads not covered here
Shock Loads Bending Loads Buckling Loads Torsion Torsion with Simultaneous Tension
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DPT Drill String and BHA design
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Biaxial Collapse The DP will collapse if:
External Pressure Load > Collapse pressure rating A Design factor of 1.15 is used:
External Pressure Load < Collapse rating / 1.15 When the string is in tension, the Collapse rating is further
de-rated:
1
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DPT Drill String and BHA design
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Biaxial Collapse Collapse load is worst when For dry test work where pipe
is run in empty
Note the use of the Average Yield Point not minimumAverage
CollapsealNo
CollapseBiaxial
YpIDODLoadZ
ZZPP
*)(7854.0
234
22
2
min
=
=
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DPT Drill String and BHA design
Schlumberger Private
Biaxial Collapse For nominal Collapse
Use D/t and correct formula Spec 7G Appendix A 3 Use the results found in Table 3-6 RP-7G
For OD and ID, use Table 1 RP-7G For Avg Yp Use Table in section 12.8 RP 7G
145,000S120,000G110,000X85,000EYpAvgGrade
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DPT Drill String and BHA design
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Exercise DP-10 We are going to dry test a liner lap at 9,000 ft. We will run in
with a packer set in tension with 50,000 lb. We will run the packer in on 5 in 19.5 #/ft Grade E premium grade DP. At the time of the test there will be nothing inside the drill pipe. The annulus will have 12.0 ppg mud. What is the collapse load on the bottom joint of DP?
New 5 Gr E 5 OD, 4.276 ID, Avg Yp= 85,000 psi
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DPT Drill String and BHA design
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DP-10 Premium has 80% wall remaining
Wall will be 0.8*(5-4.276)/2=0.2896 ID will be 4.276 OD will be 4.276+2*0.2896 =4.855
1417.0000,85*)276.4855.4(7854.0
000,50
*)(7854.0
22
22
==
=
Z
Z
YpIDODLoadZ
Average
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DPT Drill String and BHA design
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DP -10
Nominal Collapse is 7,041 Biaxial reduced collapse is 6,489
922.0
214167.014167.0*34
234
min
2
2
min
=
=
=
CollapsealNo
CollapseBiaxial
CollapsealNo
CollapseBiaxial
PP
ZZPP
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DPT Drill String and BHA design
Schlumberger Private
DP-10 Collapse load is 9,000*0.052*12= 5616 psi Design load is 5616*1.15= 6,458 Derated collapse is 6489, so we are ok Collapse design factor is 6489/5616=1.16
IPM Specified Collapse design factor is 1.1-1.15
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DPT Drill String and BHA design
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Burst Barlows formula applies
Results are found in Spec 7G Table 3,5 & 7
Burst will occur if internal pressure load > burst rating
DtYpPBurst
**2=
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DPT Drill String and BHA design
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Exercise DP11 - Burst Load Case
Worst load case happens during DST operations in a gas well. Pressure at surface is BHP- gas gradient with no backup
In the last example assume we are performing a DST test in the well at 9000 ft with BHP 200 psi less than the mud wt. What is the burst DF on the top of the Premium Grade E
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DPT Drill String and BHA design
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DP-11 From last Example 5 19.5# E Premium
OD=5, Wall = 0.2896 Yp= 75,000 Burst = 8688 psi BHP= 12*0.052*9,000-200=5,416 psi P Surf= 5416-900=4516 psi
Design factor = 8688/4516=1.92
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DPT Drill String and BHA design
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Drill String Design Process-2
After the BHA Design is performed: Slip Crushing forces on DP Overpull tensile design at surface Lengths of DP Sections Burst Design Check Collapse under tension Design check
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DPT Drill String and BHA design
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Drill String Design Factors
Tension DFt Governs Max allowable tension on the system SLB DFt is 1.1
Margin of OverPull MOP Desired excess tensile capacity over an above the hanging weight of the string at Surface. SLB MOP 50-100K
Excess BHA Wt Dfbha Amount of BHA in terms of Wt in excess of that used to drill to assure all Compressive and torsional loads are kept in the Collars, SLB Dfbha is 1.15
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DPT Drill String and BHA design
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Torsion No Design Factor Required. Tool Joints are made up to 60% of Torsional Capacity, and Tool joints are designed to 80% of the tube Torsion Capacity. Thus if the design limits to tool joint make-up there is an adequate design factor built into the system
Collapse DFc Tube is de-rated to account for Biaxial Tensile reduction and a design factor of is used SLB DFcis 1.1-1.15
Drill String Design Factors
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DPT Drill String and BHA design
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Burst DFb Simple burst is used with no allowance for axial effects SLB DFB is 1.0
Buckling DFB In Highly deviated wells it is possible to use DP in compression, provided it is not buckled.
Drill String Design Factors
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DPT Drill String and BHA design
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I. Introduction to Drill String Design: Overview
II. Drill String Components
Drill Collars - Drill Pipe - HWDP
III. Drill String Design
Bottom Hole Assembly Selection
Drill Pipe Selection
Buckling and max WOB
Agenda
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DPT Drill String and BHA design
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Buoyancy is the weight of the displaced fluid
Buoyancy is usually accounted for via BF
Buoyancy is creating a hydrostatic effect: the Pressure-Area Force
The forces acting on a drillstring are the self-weight and the hydrostatic pressure of the drilling fluid
Buoyancy is creating a force acting at the bottom of the drill string and placing the lower portion of the drill string in compression and reducing the hook load by HP x CSA
Buoyancy
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DPT Drill String and BHA design
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DP12 - Buoyancy We are running open ended DCs9 x 3 192ppf The fluid in the well is 14 ppg The depth is 10000 ft
What is the hook load with BF? What is the hook load with Pressure Area Force?
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DPT Drill String and BHA design
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A tube subjected to a load will bend
Bent is a condition in which the bending increases proportionally with load
When a little increase in load will result in large displacements, the tube is said to be buckling
The tube may not necessarily be yielded as buckling does not necessarily occurs plastically
The load which produces buckling is called the Critical Buckling Load
Bending & Buckling
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Neutral Point of Tension & Compression:
The point within a tube where the sum of the axial forces are equal to zero
Neutral Point of Bending:
The point within a tube where the sum of moments are equal to zero
The point within a tube where the average of the radial and tangential stress in the tube equals the axial stress
The point within a tube where the buoyed weight of the tube hanging below that point is equal to an applied force at its bottom end
Neutral Points
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DPT Drill String and BHA design
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Neutral Point of Bending occurs where the effective hydrostatic force equals the compressive force in the drillstring.
Forces in the Drill String
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DPT Drill String and BHA design
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Neutral point of bending is H = WOB / buoyed weight per foot of string
In vertical wells, buckling will occur only below the neutral point of bending, hence the necessity to keep the buoyed weight of the BHA exceeding the WOB
In deviated wells, buckling will not only occur below the neutral point of bending but also above the neutral point of bending when the compressive force in the drillstring exceeds a critical load
Buckling
tooljthole ODDIDODBFIDODFcrit
= )sin(*)(**)(16172244
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DPT Drill String and BHA design
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DP13 Max WOB in inclined holes
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DPT Drill String and BHA design
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Now you should be able to describe:
Drillstring Design
Functions of Drill Pipe , Drill Collars and BHA selection Grades of Drill Pipe and strength properties Thread types and tool joints Drill collar weight and neutral point Bending Stress Ratios and Stiffness Ratios Margin of overpull Slip crushing force Basic design calculations based on depth to be drilled. Functions of stabilizers and roller reamers Critical Buckling force and Neutral Point of Bending