Drillstring & BHA Design

9. Drillstring & BHA Design
Habiburrohman abdullah 1

Drill String Design
• Drill Pipe
• Pressure Control Equipment
• Drill String Loads
• Monitoring Equipment
2

Bottom-Hole Assembly (BHA)
Design
• Purpose
• Components
• Assemblies:
- Slick, Packed, Pendulum, Directional
• Properties:
- Weight, Stiffness
3

Introduction
• The drillstring design is the mechanical
linkage connecting the drillbit at the bottom of
the hole to the rotary drive system on the
surface.
• The drillstring has several functions:
- transmit rotation to the drillbit.
- exerts weight on bits (WOB)
- guides & controls trajectory of the bit
- allows fluid circulation
4

Drillstring Components
• The components of drillsting:
1. Drill Pipe
2. Drill Collar
3. Accessories including:
- HWDP
- Stabilizers
- Reamer
- Directional control equipment
Figure 1: Drillstring Components
5

Drill Pipe Selection
Grade Minimum Yield
Strength, psi
Letter Designation Alternate
Designation
D D-55 55,000
E E-75 75,000
X X-95 95,000
G G-105 105,000
S S-135 135,000
• Only grade E, G and S are actually used in oilwell drilling.
• API RP7G established guidelines for Drill Pipe as follows:
- New = no wear, never been used
- Premium = uniform wear, 80% wall thickness of new pipe
- Class 2 = 65% wall thickness of new pipe
- Class 3 = 55% wall thickness of new pipe
6
Table 1: DP grade and yield strength

Tool Joints
• Tool joints are screw-type connectors that
join the individual joints of drillpipe.
• All API tool joints have minimum a yield
strength of 120,000 psi.
7

Washout in Drillstrings
• Tool joint failure is one of the main causes of
fishing jobs in drilling industry. This failure is
due entirely to the joint threads not holding
or not being made properly.
8
Figure 2: Make Up Torque

Washout in Drillstrings
• Washout can also develop due to cracks develop
within drill pipe due to severe drilling vibrations.
• Washout are usually detected by a decrease in the
standpipe pressure, between 100 – 300 psi over 5 –
15 minutes.
• The life of tool joints can be tripled if the joints if
hardfaced with composites of steel and tungsteen
carbide.
9

Approximate Weight of DP
and Tool Joint
• Nominal weight of DP is always less than the actual
weight of DP and tool joint because of the extra
weight added by tool joint and due to extra metal
added at the pipe ends to increase the pipe
thickness.
10
Figure 3: Tool joint dimension

and Tool Joint
• Calculations of approximate weight of tool joint and DP:
a)
b)
Approximate adjusted weight of DP = Plain end weight + upset weight
29.4
( 2 2
)
Approximate adjusted weight of tool jo int = 0.222
x L D -
d
x ( D 3 D 3 ) TE x d 2
x ( D DTE
) + - - -
0.167 0.501
Where :
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) 11

and Tool Joint
c)
Approximate adjusted weight of DP assembly
approx adjusted wt DP x approx wt tool jo
= +
. . 29.4 . . int
where,
12
tool jo adjusted length
+
29.4 int
( tool jo int adjusted length = L + 2.253 x D -
DTE ) ft
12

Tool Joint Dimension
13
Table 2: Tool joint dimension table

and Tool Joint
• Example
calculate the approximate weight of tool joint and DP assembly for 5 in
OD, 19.5 lb/ft Grade E DP having a 6.375 in OD, 3.5 in ID. With NC50
tool joint. Assume the pipe to be internally-externally upset (IEU) and the
weight increased due to upsetting to be 8.6 lb.
• Solution
Referring to Table 2, NC50, 6.375 in OD, 3.5 in ID tool joint for 19.5 lb/ft
nominal weight DP is available in grade X95
Thus L = 17 in ; DTE = 5.125 in
D = 6.375 in ; and d = 3.5 in
14

and Tool Joint
a) Approximate adjusted weight of Tool Joint
= 0.222 x 17 6.3752 - 3.52 + 0.167 x 6.3753 - 5.1253 - 0.501 x 3.52 x
6.375 -
5.125
=
b). Approximate adjusted weight of Drill Pipe
15
= 0.222 x L (D2 - d 2 )+ 0.167 x (D3 - D3TE )- 0.501 x d 2 x (D- DTE )
( ) ( ) ( )
lb
120.27
= plain - end weight + upset weight
29.4
( ) 29.4
= p 2 - 2 x x +
=17.93+0.293=18.22 lb / ft
489.5 8.6
5 4.276 1
4
144

and Tool Joint
Adjusted length of tool joint:
= L + 2.253 x D - DTE = 17 + 2.253 x 6.375 - 5.125
=
c) Hence, approximate weight of tool joint and DP assembly :
16
( ) ( ) 1.651
12
12
x 21.2 lb / ft
18.22 120.27 =
+
1.651 29.4
=

Drill Collar (DC) Selection
• There are two types of DC :
- Slick DC
- Spiral DC
• In areas where differential
sticking is a possibility
spiral DC should be used in
order to minimize contact
area with formation.
Figure 4:Type of Drill Collars 17

Drill Collar (DC) Selection
Table 2: Drill Collar & Hole Size
18

Procedure for Selecting DC
1) Determine the Buoyancy Factor (BF) of the mud weight:
MW = mud weight, ppg
65.5 = weight of a gallon of steel, ppg
BF =1- MW
2) Calculate the required collar length to achieve desired WOB:
WOB = weight on bit, lbf (x1000)
Wdc = DC weight in air, lb/ft
0.85 = safety factor
BF = buoyancy factor, dimensionless
Length x BF xW
3) For directional well:
I = well inclination
19
65.5
dc
DC WOB
0.85
=
DC DC Length vertical Length =
cos
I

Bending Strength Ratio (BSR)
• Bending strength ratio defined as the ratio of
relative stiffness of the box to the pin for a
given connection.
• Large OD drill collars provide greater
stiffness and reduce hole deviation problem.
20

Stiffness Ratio (SR)
• Stiffness ratio define as follows:
SR = Section modulus of lower section tube/section
modulus of upper section tube
SR = OD OD -
ID
• From field experience, a balance BHA should have:
- SR = 5.5 for routine drilling
- SR = 3.5 for severe drilling or significant failure
rate experience
21
( )
( 2
2 )
2
1 2
2
1
2
2 1
OD OD -
ID

Heavy Weight Drill Pipe (HWDP)
• HWDP has the same OD
of a standard DP but with
much reduce inside
diameter (usually 3”)
22
Figure 5:Type of HWDP

Stabilizer
• Stabilizer tools are
places above the drill
bit and along the BHA
to control hole
deviation, dogleg
severity and prevent
differential sticking.
• There are two types of
stabilizer:
– rotating stabilizer
– non rotating
stabilizer
23
Figure 6:Type of Stabilizer

Standard BHA Configuration
• There are five types of BHA configuration:
1. Pendulum assembly
2. Packed bottom hole assembly
3. Rotary build assembly
4. Steerable assembly
5. Mud motor and bent sub assembly
24

Drillstring Design Criteria
• The criteria used in drillstring design are :
- Collapse
- Tension
- Dogleg Severity Analysis
25

Collapse Design
• The criteria to be used as worst case for the
collapse design of DP is typically a DST. The
maximum collapse pressure should be determined
for an evacuated string, with mud hydrostatic
pressure acting on the outside of the DP.
• A design factor is used in constructing the collapse
design line. The design factor to be used for this full
evacuation scenario is 1.0.
26

Collapse Calculation
1. DST (Drill Stem Test)
P L xr1 L Y xr2 c
= - -
• Where:
- Pc = collapse pressure (psia)
- Y = depth to fluid inside DP (f)
- L = total depth of well (ft)
- r1 = fluid density outside DP (ppg)
- r1 = fluid density inside DP (ppg)
27
( )
19.251 19.251

Collapse Calculation
2. Design Factor in Collapse
DF = collapse resis ce of Drillpipe
a DF of 1.125 is normally used
28
( )
tan
collapse pressure Pc

Tension Design
• The tension load is evaluated using the
maximum load concept. Buoyancy is included
in the design to represent realistic drilling
condition.
• The tension design is established by
consideration of the following :
- tensile force
- design factor
- slip crushing design 29

Tension Design
(Tensile Force)
Weight Carried
• The greatest tension (P) on drillstring
occurs at top joint at the maximum
drilled depth.
P = [(Ldp xWdp + Ldc xWdc )]x BF
Where :
Ldp = length of DP per foot
Wdp = weight of DP per unit length
Ldc = length of DC per foot
Wdc = weight of DC per unit length
BF = Buoyancy Factor 30

Tension Design
(Tensile Force)
• The drillstring should not be designed to its
maximum yield strength to prevent the DP
from yielding and deforming. At yield, the DP
will have:
– Deformation made up of elastic and plastic (permanent)
deformation.
– Permanent elongation.
– Permanent bend & it may be difficult to keep it straight.
31

Tension Design
(Tensile Force)
• To prevent this, API recommends that the use of maximum
allowable design load (Pa), given by :
Where :
- Pa = max. allowable design load in tension, lb
- Pt = theoretical yield strength from API tables, lb
- 0.9 = a constant relating proportional limit to yield strength
32
Pa = 0.9 x Pt

Tension Design
(Tensile Force)
• From above (tensile force) equation, we
obtain:
MOP = Pa – P
DF = Pa / P
where :
MOP = margin of overpull, lbs
DF = design factor, dimensionless
33

Dogleg Severity Analysis
• The most common DP failure is
fatigue wear. Fatigue is
tendency of material to fracture
under repeated cyclic stress
and chemical attack.
• A DP fatigue wear generally
occurs because the outer wall
of the pipe in a dogleg is
stretched resulting in additional
tension loads.
34

Dogleg Severity Analysis
• The maximum possible dogleg severity for
fatigue damage considerations can be
calculated using the following formula:
35
x KL
KL
MaxD x b
ED
s
432,000 s tanh
p
=

Drillstring & BHA Design

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Drillstring & BHA Design