Drillstring Design: WOB & BHA Calculations

Drillstring Design
A. Weight of Drillpipe and BHA based on WOB
Bottom hole assembly (BHA) is the part of the drillstring which is just above the bit and
below the drillpipe. It usually consists of drill collars, stabilizers and various other components
including jar, heavy weight drill pipe, etc. Drill bit and BHA (bottom hole assembly) data
contained on these well are as follows :
Bit
Manufacturer
12 1/4"
Rock Bit
Hycalog
Bit
Manufacturer
12 1/4"
PDC
Hycalog
Bit
Manufacturer
8 1/2"
PDC
Hycalog
Serial
Number
1619103324
Serial
Number
123121
Serial
Number
124031
Nozzle
3x16
Nozzle
5x18
Nozzle
5x16
Length (ft)
0,95
Length
1,02
Length
0,72
Bit Sub (ft)
3
Bit Sub
3
Bit Sub
3
1x8" DC (ft)
30,44
1 JTS 8" DC
30,44
1x6 1/2" DC
30,65
12 1/4" STB
(ft)
5,78
xo
5,78
xo
1,64
5x8" DC (ft)
152,53
5 JTS 8" DC
152,53
8 1/2" STB
5,58
x/o (ft)
1x5" HWDP
(ft)
x/o (ft)
6 1/4" JAR
(ft)
x/o (ft)
15x5"
HWDP (ft)
1,6
xo
1,6
1,64
30,85
1x5" HWDP
30,85
337,55
1,63
xo
1,63
xo
11x6 1/2"
DC
1x5" HWDP
32,84
6 1/4" JAR
32,5
xo
1,63
1,6
xo
15x5"
HWDP
1,6
6 1/4" JAR
32,5
462,04
xo
1,6
15x5"
HWDP
462,04
Total BHA
(ft)
909,4
Total BHA
(ft)
462,04
532,91
Total BHA
(ft)
722,99
30,85
WOB (lb/ft x
1000)
5 sampai
10
WOB (lb/ft x
4 sampai 7
1000)
Table 9.1
WOB (lb/ft x
1000)
5 sampai
10
And parameters of the drill bit is used for the depth interval of the well can be seen in the table
below
Section
1
2
Bit Data
Nozzle
Depth
Interval (ft)
WOB (klbs)
RR 12 1/4”
Rock Bit S/N
1619-103324
3x16
572 – 1208
5 – 10
RR 12 1/4”
PDC S/N
123121
5x18
1208 – 1874
4–7
RR 8 1/2” PDC
S/N 124031
5x18
1874 – 3610
5 – 10
Table 9.2
The pendulum principle was originally used to drill vertical wells with slick (non
stabilised) BHAs.The physical properties of the various downhole components of the BHA have
a significant effect on how the bit will drill. The principle uses the weight of the BHA hanging
below the tangent point to produce, via gravity, a force that pushes the bit to the low side of the
hole. The effect of the pendulum varies with the length of the BHA below the tangent point. The
fundamental pendulum assembly increases the restoring force by increasing the pendulum length
with a stabiliser in the proper position.
When the drillstring is lowered into the borehole, the total length of the drillstring is
under tension due to its own weight which is partly counterbalanced by the buoyancy. To drill a
well, the rock beneath the bit has to be destroyed. Part of this destruction force is obtained by a
certain amount of weight on bit (WOB) which forces the bit against the rock.
Therefore during drilling, the lower part of the drill string is set under compression,
leaving the upper part of it still under tension. When drilling vertical wells, standard practice is to
avoid putting ordinary drill pipe into compression (recommended by Lubinski in 1950). This is
achieved by making sure that the “buoyed weight” of the drill collars and HWDP exceed the
maximum WOB. The buoyed weight of the drill collars is the amount of weight that must be
supported by the derrick when collars are run in the hole. This load is always less than the in-air
weight if mud is used in the well.
The higher the weight on bit, the more the assembly will bend. This can move the tangent
point nearer to the bit and hence is detrimental to the effectiveness of the assembly. Furthermore,
the side force at the bit, produced by the weight on bit, acts against the pendulum force. Weight
on bit as low as possible is desirable for a pendulum assembly.
WOB data are available for each type of bits from this well, we can determine the weight
of BHA minimum in air using the formula below.
Required air weight of BHA =
Maximum WOB x safety factor
buoyancy factor x cosθ
...................................................9.1
where
the safety factor = 1 +
percentage safety margin
100
......................................................................9.2
and
The BF (buoyancy factor), assuming that the drillstring is not lowered empty (ρsteel = 65.5 ppg),
can be computed as :
ρ
BF = (1 − ρ mud ) ....................................................................................................................9.3
steel
The normal drill string design practice aim is to avoid abrupt changes in component cross
sectional areas. Abrupt changes can lead to concentrations in bending stresses which in turn can
lead to a twist off (Refer to figure 9.1). The ratio I/C between the moment of inertia (I) and
radius (C) of the pipe is directly related to the resistance to bending. The following are used to
determine the section modulus I/C:
I = Moment of inertia ...........................................................................................................9.4
𝜋
= 64 𝑥(OD4 -ID4 )
𝜋
C = 64 Radius of the tube .....................................................................................................9.5
=
OD
2
At a crossover from one tubular size to another size, the ratio (I/C large pipe)/(I/C small
pipe) should be less than 5.5 for soft formations and less than 3.5 for hard formations.
Ratio =
I/C Drill Collars
I/C Drill Pipes
............................................................................................................9.6
Drill pipe will be subjected to serious damage if run in compression. To make sure the
drill pipe is always in tension, the top 10 to 15% of the drill collar or HWDP must also be in
Figure 9.1
tension. This gives a safety margin and keeps the buoyancy neutral point within the collars when
unforeseen forces (bounce, hole friction, deviation) move the buckling point up into the weaker
drillpipe section or this will put the change over from tension to compression, or neutral zone,
down in the stiff drill collar string where it is desirable and can be tolerated. According to
Lubinski, the neutral point is defined as point along the drillstring where it is divided into two
parts, an upper part, being suspended from the elevators and which is under tension as well as a
lower part that generates the appropriate WOB and is under compression.
Since the collars are under compression, they will tend to bend under the applied load.
The amount of bending will depend on the material and the dimensions of the collar. The shape
of the drill collar may have a circular or square cross section. A string of square collars provides
good rigidity and wear resistance, but it is expensive, has high maintenance costs for certain
conditions and may become stuck in key-seated dog-leg. Typically, standard and spiral drill
collars with external grooves cut into their profile may be used to reduce the contact area
between the BHA and the formation.
Using equation 9.3 and the data of the mud used in these wells are shown in Table 9.3,
the obtained BF (buoyancy factor) in Table 9.8.
Depth (ft)
572
953
1190
1198
1870
1877
2569
2983
3159
3457
Mud Weight Yield Point
(ppg)
(lb/100ft2)
8,7
10
8,8
10
9
12
9,2
13
9,2
14
9,2
8
9,3
11
9,4
12
9,4
14
9,4
14
Table 9.3
For the portion of pendulum BHA below the tangent point or first drill string stabiliser, it
is desirable to run drill collars with the largest possible outside diameter. But potential problems
associated with fishing the drill collars must be considered in the design stage. Due to lack of
data, the selection of drillpipe with a size of 5" OD and drillcollar 8" OD based on the table
below from ENI which illustrates the possibility and acceptability for 12 1/4 “ hole of soft
formations.
Hole
size
(in)
12 1/4"
Drill collar /
Drill pipe
I/C
I/C
Ratio
DC 9 1/2" x 3"
83,8
1,5
55,9
5,2
10,7
1,9
5,7
-
DC 8 1/4" x 2
13/16"
HWDP 5" x
42.6 lb/ft
DP 5" x 19.5
lb/ft
Table 9.4
Remarks
OK for soft
formations
Here is the dimensional data and performance properties of new drill pipe 5" OD from API
RP7G
Weight (lb/ft)
OD
(in)
Approx. Wt.
Incl. Tube &
Joint (lb)
Plain
End
ID
(in)
Section
Wall
Area
Thickness Body of
(in)
Pipe
(sq.in)
16,25
14,87
4,408
0,296
19,5
17,93
4,276
0,362
5
Grade
E
X-95
4,3743
G-105
S-135
E
X-95
5,2746
G-105
S-135
Table 9.5
Torsional Tensile
Collapse
Burst
Yield
Yield
Pressure Pressure
Strength Strength
(psi)
(psi)
(ft.lb)
** (lb)
35.040
44.390
49.060
63.080
41.170
52.140
57.600
74.100
328.070
415.560
459.300
590.530
395.600
501.090
553.830
712.070
6.940
8.110
8.620
9.830
10.000
12.030
13.000
15.670
Therefore chosen drillpipe size 5 “x 3” and drillcolar size 8 “x 3”. Proved by calculating the ratio
of the I/C at a crossover from one tubular size to another size by using equation 9.6, its value is
less than 5.5.
Drill collar /
Drill pipe
(in)
I/C
I/C Ratio
DC 8” x 3”
49,3
4,607476636
HWDP
10,7
1,877192982
DP 5” x
4.276”
5,7
-
Remarks
Between DC
and HWDP
Between
HWDP and
DP
-
Table 9.6
There is heavy weight drillpipe on bottom hole assembly, the dimensional data and
performance properties of HWDP from the drilling data book of Baker Huges company can be
seen in the table 9.7.
7.770
9.840
10.880
13.990
9.960
12.040
13.300
17.110
TUBE
Nom. Tube Dim.
Nom
size
(in)
ID
(in)
Weight
Upset Sec.
Wall
Thick.
(in)
Center
(in)
Ends
(in)
Perform. Prop.
Tensile Torsional
Yield(lb)
(ft.lb)
Approx. Wt. Incl. Tube & Joint
(lb)
Range II
Range III
lb/ft
lb/jt
30ft
lb/ft
lb/jt 45
ft
3 1/2
2
1/16
0,719
4
3 5/8
345.400
19.535
26
810
-
-
4
2
9/16
0,719
4 1/2
4 1/8
407.550
28.745
28
870
-
-
4 1/2
2 3/4
0,875
5
4 5/8
548.075
40.625
42
1290
40
1745
5
3
1
5 1/2
5 1/8
691.185
Table 9.7
56.365
50
1550
48
2090
Using equation 9.1 and equation 9.3 with a safety margin of 10% gained weight drillpipe and
BHA are shown in the following table
Interval
Depth (ft)
MW ratarata (ppg)
Max
Required air
WOB
weight of
(lbfx1000) BHA (lb)
0,862900763
10
12747,69993
LBHA
(ft)
LDP (ft)
WDP in air
(lb)
532,91
675,09
13164,255
7
8958,259325
722,99
1151,01
22444,695
10
12826,8057
909,4
2700,6
52661,7
BF
572-1208
8,98
12089,2
0,859541985
1874
18749,328571429 0,857579062
3610
Table 9.8
The length of drillpipe in the above table is obtained using the following formula
LDP = Depth − LBHA ..............................................................................................................9.7
While the weight of drillpipe obtained using the formula below
WDP in air = LDP x API approximate weight .........................................................................9.8
B. Chart of Tension and Compression along Drillstring
The tension load is evaluated using the maximum load concept. The tension load can be
evaluated after the weights, grades, and section lengths have been established from the collapse
designs. Buoyancy is included in the design to represent realistic drilling conditions due to the
manner in which biaxial stresses alter the collapse properties of the pipe.
The tension design is established by consideration of the following:
1. Tensile Forces: These include:

weight carried

shock loading

bending forces
2. Design factor
3. Slip Crushing Design
The tension design line is established as the maximum load resulting from applying three
different design considerations, including overpull, design factors,and slip crushing. Each
consideration is applied separately to the load line. The design line is selected as the worst case
from the three design loads.
A minimum overpull factor is applied to the tension load. The difference between the
maximum allowable tension and the calculated load represents the Margin of Over Pull (MOP).
MOP is the minimum tension force above expected working load to account for any drag or
stuck pipe. The minimum recommended value of MOP is 60.000 lb and it shall be calculated for
the topmost joint of each size, weight, grade and classification of drill pipe. The anticipated total
depth with next string run and expected mud weight should be considered when calculating the
MOP.A typical range for the overpull value is 50.000-100.000 lb. When deciding on the
magnitude of the MOP, the following should be considered:

Overall drilling conditions

Hole drag

Likelihood of getting stuck (may require higher values of MOP)
When the depth is reached where the MOP approaches the minimum recommended value,
stronger drill pipe shall be added to the string.
A range of tension design factors has been frequently used for drillpipe design. This
range is typically from 1,1-1,5 although 1,1-1,3 seems to be most common. A design factor of
1,6 should be applied to the tension loads calculated above if shock loading is not accounted
for.The primary purpose of the design factor is to ensure an overdesign of the pipe to minimize
the catastrophic problem of pipe parting near the surface when the pipe is fully loaded. In
addition, it is selected to account for acceleration loading of the pipe, which occurs when the
slips are set.
The maximum allowable tension load must also be designed to prevent slip crushing. In
an analysis of the slip crushing problem, Reinhold and Spini, and also Vreeland, proposed an
equation to calculate the relation between the hoop stress (SH ) caused by the action of the slips
and the tensile stress in pipe (ST) resulting from the load of the pipe hanging in the slips. The
equations used are as follows:
S
Ts = TL ( SH) ...........................................................................................................................9.9
T
Where
Ts = Tension load due to slip crushing
Ts = Static load tension
(SH /ST ) is hoop stress to tension stress ratio as derived from the equation bellow :
S
DK
ST
2Ls
( H) = (1 +
+(
0.5
DK 2
2Ls
) )
..............................................................................................9.10
Where
SH = Hoop stress (psi)
ST = Tensile stress (psi)
D = Outer Diameter of the pipe (in)
1
K = Later load factor on slips (
)
tan(y + z)
y = Slip taper (typically 9° 27′ 45" or 9,4625 degrees)
z = Arctan μ
μ = Coefficient of friction, typically 0,06 − 0,14
Ls = Length of slips, usually 12 − 16 in
In as much as tool joint lubricants are usually applied to the back of rotary slips, a coefficient of
friction of 0.08 should be used for most calculations.
To create a graph of tension and compression along the drillstring requires the following
calculation.
1. Calculate the buoyancy force (BF1) acting on the bottom of the drill collars using:
BF1 = −(P x A) ........................................................................................................9.11
π
P = 0,052xDepth(ft)xMud Weight(ppg)x 4 (ODDC in)2 − (IDDC in) 2 ................9.12
2. Calculate the buoyancy force (BF2) acting at the top of the drillcollars.
BF2 = (P x A) ...........................................................................................................9.13
Due to the well drillstring consists of drillcollar, HWDP, and drillpipe then the formula
used to calculate P is as follows.
π
P = 0,052 x LDP x MW x 4 (ODDC )2 − (ODDP ) 2 ...................................................9.14
π
+ 0,052 x (Depth − LDC ) x MW x 4 (ODDC )2 − (ODHWDP ) 2
π
+ 0,052 x LDP x MW x 4 (IDDP )2 − (IDDC ) 2
3. Calculate the drill collar weight
lb
WDC in air ( ft ) = A (cross sectional area)x 1 ft x ρsteel ........................................9.15
π
lb
1
= 4 x((OD in)2 − (ID in) 2 )x1 ft x (489,5 ft ) x 144
lb
WDC in air (lb) = WDC in air ( ft )xLDC .....................................................................9.16
4. Calculate the shock load
Shock load (lb) = 1500 x pipe weight per foot ...................................................9.17
Note : 1500 was used to represent slow running speeds.
5. Calculate the total dynamic and static load at surface
Total dynamic load (lb) = BF1 + BF2 + drillcollar weight + drillpipeweight
+shock load .............................................................9.18
Static load without shock load (lb) = BF1 + BF2 + drillcollar weight
+drillpipe weight ..................................9.19
6. Static load at top of drillcollars (lb) = BF1 + WDC in air ...................................9.20
7. Static load at bottom of drillpipe (lb) = BF2 + Static load at top
of drillcollars .......................................9.21
8. Dynamic load at bottom of drillpipe (lb) = Static load at bottom
of drillpipe + shock load ..........................9.22
9. Calculate the design line for the tension load by multiplying the load on the drill pipe at
surface and at the top of the collars by the 1,3 design factor (since shock loads have been
included).
10. Calculate the design line for the MOP by adding the 50.000-100.000 lb overpull factor to
the static tension load values calculated earlier.
11. Calculate the design line for slip crushing using equation 9.9 and equation 9.10 with TL =
static load at surface without shock load.
Assumes production test zone or DST (Drill Stem Test) packer depth was just above the
BHA, the design factor of 1.3 for the tension. For the interval depth 572-1208 ft MOP 100.000 lb
and for the interval 1208-3610 ft MOP 60.000 lb. Using equations above, obtained the following
Static & dynamic loads and complete tension design graph along the drillstring for each type of
bit and BHA used. The results of the calculations can be seen in the table 9.9, 9.10, and 9.11
Bit Data
Tension Load Line
Bouyant force
Bouyant
acting on the force acting
top of the
on the top of
collars / BF1
the collars /
(lb)
BF2 (lb)
Drill collar
weight (lb)
Drillpipe
Weight
(lb)
HWDP
weight
(lb)
Shock
load
(lb)
RR 12 1/4"
Rock Bit S/N
1619-103324
-24366,83853
26490,28689 28156,46621 13164,255 25390,08 29250
RR 12 1/4"
PDC S/N
123121
-38726,95299
45532,75167
28156,47
22439,43
25450,56 29250
RR 8 1/2"
PDC S/N
124031
-75644,65695
97670,91262
55807,8
56291,43
25373,76 29250
Table 9.9
Bit Data
Total
dynamic
load at
surface (lb)
Static load at
surface
without
shock load
(lb)
Static load at
top of
drillcollars (lb)
RR 12 1/4”
Rock Bit S/N
1619-103324
98084,24956
68834,2496
3789,627675
30279,91456 59529,91456
RR 12 1/4”
PDC S/N
123121
112102,2549
82852,25488
-10570,48679
34962,26488 64212,26488
RR 8 1/2” PDC
S/N 124031
188749,2503
159499,2503
-19836,85227
77834,06035 107084,0603
Static load at
bottom of
DP+HWDP
(lb)
Dynamic
load at
bottom of
DP+HWDP
(lb)
Table 9.10
Design line tension load
Design line for MOP
Design line for slip crushing
Total
Dynamic
load at
surface (lb)
Dynamic
load at
bottom of
DP+HWDP
(lb)
Static load at
surface
without
shock load
(lb)
Static load
at bottom
of
DP+HWDP
(lb)
SH/ST
Slip crushing
load at
surface (lb)
Slip crushing
load at
bottom of
DP+HWDP
(lb)
RR 12 1/4"
Rock Bit S/N
1619-103324
127509,524
77388,8889
168834,25
130279,915
1,299572579
89455,10325
39350,94667
RR 12 1/4"
PDC S/N
123121
145732,9314
83475,94435
142852,255
94962,2649
1,29957258
107672,5
45436,001
RR 8 1/2"
PDC S/N
124031
245374,0255
139209,2785
219499,25
137834,06
1,29957258
207280,9
101151,01
Bit Data
Table 9.11
Static & Dynamic Loads RR 12 1/4" Rock Bit S/N
1619-103324
Compression (lb)
-50000
0
Tension (lb)
50000
100000
150000
0
200
400
Dpeth (ft)
Static Load line
600
Dynamic load line
Dynamic load line x 1.3
800
1000
1200
1400
Figure 9.2
Complete Tension Design RR 12 1/4" Rock Bit
S/N 1619-103324
Compression (lb)
-50000
0
Tension (lb)
50000
100000
150000
200000
0
200
Static Load line
Depth (ft)
400
Dynamic load line
600
100,000 lb overpull load line
800
Slip crushing design line
1000
1200
1400
Figure 9.3
Static & Dynamic Loads RR 12 1/4" PDC S/N
123121
Compression (lb)
Depth (ft)
-50000
0
Tension (lb)
50000
100000
150000
200000
0
200
400
600
800
1000
1200
1400
1600
1800
2000
Static Load line
Dynamic load line
Dynamic load line x 1.3
Figure 9.4
Comple Tension Design RR 12 1/4" PDC S/N
123121
Compression (lb)
Depth (ft)
-50000
0
Tension (lb)
50000
100000
150000
0
200
400
600
800
1000
1200
1400
1600
1800
2000
200000
Static Load line
Dynamic load line
60,000 overpull load line
Slip crushing design line
Figure 9.5
Static & Dynamic Loads RR 8 1/2" PDC S/N
124031
Compression (lb)
-100000
0
Tension (lb)
100000
200000
300000
0
Depth (ft)
500
1000
Static Load line
1500
Dynamic load line
2000
Dynamic load line x 1.3
2500
3000
3500
4000
Figure 9.6
Complete Tension Design RR 8 1/2" PDC S/N
124031
Compression (lb)
-100000
0
Tension (lb)
100000
200000
300000
0
500
Static Load line
Depth (ft)
1000
Dynamic load line
1500
60,000 lb overpull load line
2000
Slip crushing design line
2500
3000
3500
4000
Figure 9.7
Rig Sizing and Selection
To determine the maximum load the rig then we should know the type of casing used.
That way we will know the weight of the casing so as to obtain the maximum load of the rig that
will be used. The type and weight of the casing is different for different sizes. To determine the
amount of the maximum load sustained by the rig used the following formula, where the total
load is the heaviest load to be lifted rig.
𝑙𝑏
𝑇𝑜𝑡𝑎𝑙 𝑊𝑒𝑖𝑔ℎ𝑡 (𝑙𝑏𝑠) = 𝐶𝑎𝑠𝑖𝑛𝑔 𝑊𝑒𝑖𝑔ℎ𝑡 (𝑓𝑡) × 𝐶𝑎𝑠𝑖𝑛𝑔𝐷𝑒𝑝𝑡ℎ (𝑚) × 3.281.................. 10.1
𝑅𝑖𝑔 𝐿𝑜𝑎𝑑 =
𝑇𝑜𝑡𝑎𝑙 𝐿𝑜𝑎𝑑
𝑛
× (𝑛 + 2) ........................................................................................10.2
In the optimal drilling operations , it is important for us to support the weight of the rig
during operation. This is to prevent us from losses that may result, if the rig that we have "
collapse ". In the calculation of the maximum load of the rig we use the formula given above.
Rig load calculation we do for every case that we will attach to the wellbore, starting from the
surface casing, intermediate casing, production casing, until the liner if necessary.
Based on the given data and the assumption that the surface casing is a casing with OD
13 3/8 "with a grade of C-75 in accordance with the proposed casing which has been described
previously as there was no surface casing of the data used in the development well, obtained rig
load calculation as follows :
Rig Load
Casing
Casing Weight
Depth
Total Weight
Rig Load
Grade
lbm/ft
m
lbm
lbm
13 3/8"
C-75
68
571
127394,668
152873,6
9 5/8"
K-55
36
1874,81
221445,058
265734,1
K-55
29
681,21
64816,45029
77779,74
N-80
23
785,74
59294,29762
71153,16
K-55
23
3610
272421,43
326905,7
Casing
7"
Table 10.1
Nominal weight threads and coupling / casing weight obtained from reference Burgoyne
book which is a minimum performance properties of casing based API. Specifications Type
Casing used in this calculation Buorgoyne obtained from reference books . In this book , has
included the things you need to know to perform the calculations . It - it is the grade of the
casing, casing diameter and weight of the casing. In writing grade casing , we must know what it
means. For example, H-40, H indicates a casing forming material specifications that we have
(marked with the letter H or C, can also be other types). 40 states the minimum yield strength,
which states how strong case that we have to hold the load, until deformed and cannot return to
its original size, in this case 40,000 psi.
Selected Nominal weight threads and coupling C-75 at table 10.1 is the least desirable
because it produces smaller rig loads. Rig with a small load will make the selection of the rig that
is not too big so that the costs would be even cheaper. This also applies to the selection of casing
weight on the proposed design of the casing is selected and rig loads obtained in the following
table.
Rig Load
Casing
Casing
Grade
13 3/8"
9 5/8"
7"
C-75
L-80
H-40
Casing Weight
lbm/ft
68
40
17
Depth
m
571
1874,81
681,21
Total Weight
lbm
127394,668
246050,0644
37995,85017
Rig Load
lbm
152873,6
295260,1
45595,02
Table 10.2
Casing with most big rig loads, will be the limit for the selection of rigs that we use in
drilling operations. Load biggest rig on calculations in both tables previously obtained amounted
to 326,905.7 LBM design development well casing while the casing design proposed by
295,260.1 LBM. Therefore, it can be concluded that the proposed design of the casing would
result in a smaller rig and the rig will be cheaper. Selection of the casing design development
wells are more than likely caused by the unavailability of a lighter casing or drilling back to do
so it is necessary for further development of the larger rigs ability to withstand the loads resulting
from the use of casing.
Productive Time and NPT
It is important to realize that each step should follow the preceding steps in drilling
without delay. Each step should take the least possible time with good practice. Non-productive
time is the time spent during drilling operations that are not in accordance with the operating
plan that has been designed previously or any time that has been spent for routine or abnormal
operations which are carried out as a result of failure.
From the existing data of development well, cannot be found any day intervals from the
drilling process is done. However, there is a pie chart that contains percentage of each of the
process compared to the total drilling time.
Well Activity
Run Csg
7%
WOC Work BOP Test BOP
3%
8%
5%
Drill Cmt
LOT
3%
1% Cementing
2%
Drill
Cond./Circ.
Log
8%
Non-productive
time
0%
Trip
Log
Run Csg
WOC
Work BOP
Trip
19%
Drill
38,00%
Test BOP
LOT
Cementing
Drill Cmt
Non-productive time
Cond./Circ.
6%
Figure 11.1
Therefore, from the available pie chart obtained the required time for each process can be seen in
table below.
Process
Drill
Cond. / Circ.
Trip
Log
Run Csg
WOC
Work BOP
Test BOP
LOT
Cementing
Drill Cmt.
Days
3,8
0,6
1,9
0,8
0,7
0,3
0,5
0,8
0,07
0,2
0,3
Total days
productive time
9,97
Total day non0,03
productive time
Table 11.1
And a comparison can be made between productive time and the NPT as shown below
Well Activity
Productive time
(%)
100%
Non-productive
time (%)
0,30%
Non-productive time
(%)
Productive time (%)
Figure 11.2
The cause of the occurrence of Non-Productive Time is diverse, it can be due to the
occurrence of rig down time, also when an error occurs that requires us to do fishing, or even
abandon a well, which might happen if it turns out well that we drill dry hole. Differential
sticking, mechanical sticking, and lost circulation are the main events which cause NPT in the
drilling industry. In operations, there are also weather down time, this is because there is the
possibility of a storm that would impede the course of the operation. Simply NPT classified into
three types:
o Repair Time
o Rectification time
o Client time
Details of the NPT should be recorded by the operator on a daily basis and should be
checked against historical NPT in the area to obtain trends and then arrive at solutions. Repair
time is the time spent on repairs on the rig and related equipment during which drilling
operations is shut down. Based on drilling activity summary data, there were repair in the blind
ram BOP at 14-08-2009 when drilling stopped at a depth of 1874 ft which is included in the
calculation of repair time. Any operation that might be carried out to place the well in safe
conditions before attempting repair and on completion returning the well to former status,
waiting on spare parts, weather or personnel before normal drilling operations are carried out
also part of the calculation of repair time.
Rectification time is the time spent in overcoming downhole problems that delay
operations. In these wells that are part of the rectification time is at a depth of 1208 ft was
decided to replace the rock bit with the PDC bit, it is because the very low rate of drilling at that
depth using rock bit. In addition, there are other problems which are at a depth of 1827 ft
overpull of 40,000 lb while being carried POOH 12 1/4" PDC bit f / 1874 ft to 1827 ft and the
overpull at a depth of 1796 ft 47,000 lb while being carried POOH 12 1/4" PDC bit f / 1874 ft to
1802 ft on 12-08-2009. Examples of other issues are freeing stuck pipe, fishing lost cones,
squeeze cement, and well kill operation. The NPT time includes normal operations such as
POOH, RIH, circulating etc. It is as if these operations are not part of the drilling process and
they are merely carried out to get us to where we were before the problem.
While the client time is the time spent on operations requested by client that was not
included in the drilling program earlier. These are not NPT, but indirectly linked and might
affect the AFE. Operations are plugging back extra coring, and extra logging.
Based on existing data such as overpull, drill bit replacement, and repairs blind ram BOP,
it can be concluded that the NPT should be greater than the actual value of the NPT which is
listed on the pie chart on the data provided.
In the drilling operation, which we want is the smallest of the NPT, we do not want any
additional drilling time period of the plan that we have the previous design . This would increase
our expenses in renting rigs, which are quite expensive. Accurate calculation of NPT is essential
if the operator attempts to improve future drilling operations.
Directional Well Design
A. Consideration for Directional Well Design
Directional drilling is the process of directing the wellbore along some trajectory to a
predetermined target. It includes selecting the most appropriate survey techniques, defining the
best control tools, researching applicable government regulations, and gathering pertinent
geological data. In addition, the directional program may alter or affect the casing and cement
program, hydraulics, centralization and completion techniques. Directional drilling is required
when :
1. Reaching a target which is below inaccessible or restricted areas such as a mountain, a
highly populated area, a national park, etc.,
2. Multiple wells have to be drilled from one offshore platform to deplete large portions of a
reservoir from one structure,
3. Side tracking has to be done around a fish,
4. Fault drilling is necessary,
5. Salt dome drilling takes place,
6. Drilling a relief well to intersect a blowout well,
7. Sidetracking from an old well to explore different horizons and/or directions.
When drilling a well, formations are often encountered that are under a different pressure
regime. These formations are named to be “abnormally pressured”. Abnormal pressures can be
positive which means actual formation pressures are higher than hydrostatic pressure. Directional
wells are drilled to avoid drilling a vertical well through a steeply inclined fault plane where
abnormal pressure develop and may lead to slip and shear the casing. This fault in sedimentary
rocks is caused by tectonic activities. Sedimentary beds are broken up, moved up and down or
twisted. There are a variety of reasons why abnormal pressure develop due to faulting:
1. The fault plane act as a seal against a permeable formation thereby preventing further
pore fluid expulsion with compaction. The permeable zone will become overpressured.
2. If the fault is non sealing, it may transmit fluids from a deeper permeable formation
to a shallower zone, causing abnormal pressures in the shallow zone.
3. A zone may move down the fault plane causing the zone to be subjected to a higher
overburden pressure and higher geothermal temperature. If the zone further compacts and
the pore fluids cannot escape, abnormal pressure will result.
4. Rate of sedimentation usually increases on the downthrown block and this rapid
sedimentation can lead to undercompaction and development of overpressure.
At the beginning of the Middle Miocene is the beginning of the movement of
compressible in South Sumatra Basin. History of the formation of the basin since the Middle
Miocene is characterized by regression cycles reflected by Air Benakat formations, which cover
Gumai formation. Air Benakat formations deposited in the marine environment to the deep sea,
consisting of claystone at the bottom that changes gradually became dominant sandstone to the
top. Regionally lithology penetrated by the well is included in the South Sumatra basin
stratigraphic order in which zones are the prospects of Air Benakat sandstone formations. These
wells are located in the south of reverse fault trending east-west relative (Thrown Down Block).
Through this knowledge it is known manufacture directional drilling will turn before the
indication of clay and rock layers should not lead to the south where there is a reverse fault.
The study analyzes the integration of sedimentology and log data ever conducted,
provides an overview of the delta depositional environment Air Benakat formation. Existing
deposition system is a variation of sediment delta front which is believed deposited on the
transition conditions between fluvial and marine. Sandstones in the sediment is interpreted as
distributary channels and delta front of the bar mounth relatively not affected by fluvial
processes or tidal processes. This is another consideration which is expected to be a lot of oil
reserves that can be taken by applying directional drilling in the layer. Of course this requires
further studies and surveys as well as the calculation of the economics of the directional drilling.
We can use the MWD (Measurement While Drilling) which is a tool to increase the drilling
efficiency (stick-slip), be applied to detect the abnormal formation pressures or any kind of hole
problems that may occur on the reverse fault in Air Benakat formation that can help in designing
directional drilling.
B. Data for Directional Well Design
The values that must be identified for directional well design are as follows:
1. lateral, or horizontal, displacement from the target to a vertical line from the rig site
2. kickoff point (KOP)
3. desired build angle rate
4. final drift angle
5. plan type: L type, S type, and J type
The selection of KOP (kick-off point) and the build-up rate depends on several being hole
pattern, casing program, mud program, required horizontal displacement and maximum tolerable
inclination. Choice of kick-off points can be limited by requirements to keep the well path at a
safe distance from existing wells. The higher in the hole the kickoff point, the lower the dogleg
severity needs to be in order to minimize fatigue in the drill string through the build section. It
may not always be possible to drill a directional well and not cause some fatigue in the drill
string or to keep the inclination below 30°. It depends upon the target departure. With high
departure targets, high inclinations will be required.
The build angle rate describes the amount of angle build up below the KOP until the drift
angle reaches the desired value. The build-rate can be chosen to minimize fatigue in drill pipe,
minimize keyseat possibility, or help to minimize torque and drag. Build-up rates are usually in
the range 1.5°/100 ft M.D. to 4.0°/100 ft M.D. for normal directional wells. The build rate is
chosen trying to keep below the endurance limit of the drill string in order to minimize the
possibility of fatigue damage.
When drilling directional wells the Directional Contractor should be asked to provide an
assessment of the required BHA changes, motor requirements and any limitations on bit
operating parameters which may impact on the selection of bits. In addition bit characteristics in
terms of walk, build and drop tendencies will need to be assessed for their impact on the well
path. The double cone profile allows more cutters to be placed near the gauge giving better
gauge protection and allowing better directional control. Diamond side tracking bits are designed
to drill “sideways” making it a natural choice for “kicking off” in directional drilling situations.
Window cutting through casing using diamond bits is now an effective, field-proven method for
re-entering older wells to increase production, to apply directional drilling techniques, or to
sidetrack. Using permanent casing whipstocks and specially designed diamond bits, wider and
longer windows are cut when sidetracking.
Since gravity acts vertically, only the weight of the along component of the BHA
elements will contribute to the WOB. The problem this creates is that if high WOB is required
when drilling a high inclination borehole, a long and expensive BHA would be needed to prevent
putting the drillpipe into compression. However, for high inclination wells, it is common practice
to use about the same BHA weight as used on low inclination wells. On highly deviated wells,
operators have been running drillpipe in compression for years. If drilling a horizontal well, the
build rate may be selected based on steerability of the bottomhole assembly. In practice, BHA
weight for steerable assemblies on typical directional wells is not a problem for the following
reasons :

The WOB is usually fairly low, especially when a PDC bit is used.

When the drillstring is not rotated, the drill pipe is not subjected to the cyclical stresses
which occur during rotary drilling.
Therefore, sinusoidal buckling can be tolerated when there is no rotation of the
drillstring. Helical buckling however, must be avoided. Analysis of drillpipe buckling in inclined
wells, by a number of researchers has shown that drillpipe can tolerate significant levels of
compression in small diameter of high inclination boreholes. This is because of the support
provided by the “low-side” of the borehole. Drillpipe is always run in compression in horizontal
wells, without apparently causing damage to the drillpipe. Selection of the drill pipe grade is
based upon predicted values of pick-up load. For a directional well, the prediction of pick-up
load is best obtained using a Torque and Drag program, as well as including the capacity for
overpull.
Maximum permissible dogleg severity must be considered when choosing the appropriate
rate. In practice, well trajectory can be calculated for several KOPs and build-up rates and the
results compared. The optimum choice is one which gives a safe clearance from all existing
wells, keeps the maximum inclination within desired limits and avoids unnecessarily high dogleg
severities.
When a number of drill collars are used in directional drilling, they produce a great
amount of contact area with the low side of the hole. As the collars are rotated, this high friction
contact with the hole wall causes the collars to climb the side of the wall. Rotating big, stiff
collars through doglegs, developed in directional drilling, can cause very high-rotating torque
and excessive bending loads at the threaded connections. HWDP (heavy weight drillpipe) bends
primarily in the tube. This reduces the likelihood of tool joint fatigue failures occurring in the
HWDP as it rotates through doglegs and hole angle changes. HWDP design offers less wall
contact area between the pipe and hole wall which results in:

Less rotary torque.

Less chance of differential sticking.

Less vertical drag.

Better directional and hole angle control.
L type wells are made up of a KOP, one buildup section and a tangent section up to the
target. They are also called Build and Hold Trajectory or L Profile Wells. These wells are drilled
vertically from the surface to kick-off point at a relatively shallow depth. From the kick off point,
the well is steadily and smoothly deflected until a maximum angle and the desired direction are
achieved (build). Then, if desired, casing is run and cemented. Further, the established angle
and direction are maintained (hold) while drilling upto the target depth. Usually this method is
employed when drilling shallow wells with single producing zones.
Drop angle rates apply only in S plans, the S curve will drop angle prior to drilling into
the target so entry is vertical. S type are made up of a vertical section, a kick- off point, a buildup section, a tangent section, a drop-off section and a hold section upto target. The S curve is
selected primarily because it allows vertical entry into the target zone. Many operators believe
that vertical entry may improve completion and production efficiency. And effective cement jobs
may be easier to achieve in a vertical well.
From the KOP, the well is steadily and smoothly deflected until a maximum angle and
the desired direction are achieved (build). The angle and direction are maintained until a
specified depth and horizontal departure has been reached (hold). Then, the angle is steadily and
smoothly dropped (drop) until the well is near vertical. Finally the angle and direction is
maintained till we reach the target depth.
The S curve requires careful consideration prior to its implementation. Since the angle
change will occur deeper in the well where the formations are harder, directional control may be
more difficult. In addition, since angle dropping requires fewer stabilizers in the bottom-hole
assembly (BHA), azimuth control problems may occur. If a high-angle hole is returned to the
vertical position, keyseating may develop if a long section of vertical hole is drilled. The S curve
will usually require 10-20% more drilling time than a L type.
J type wells are made up of a vertical section, a deep kick off and a build up to target.
They are also called Deep Kick off wells or J Profile wells (as they are J - shaped). They are
similar to the Type I well except the kickoff point is at a deeper depth. The well is deflected at
the kickoff point, and inclination is continually built through the target interval (build). The
inclinations are usually high and the horizontal departure low. This type of well is generally used
for multiple sand zones, fault drilling, salt dome drilling, and stratigraphic tests. It is not used
very often.