Addendum 1
November 2003
Addendum Effective Date: May 1, 2004
Recommended Practice for Drill
Stem Design and Operating Limits
API RECOMMENDED PRACTICE 7G
SIXTEENTH EDITION, AUGUST 1998
EFFECTIVE DATE: DECEMBER 1998
ERRATA: MAY 2000
Addendum 1 to Recommended Practice for Drill Stem Design and Operating Limits
Page 3, 4.5:
Change “A.8” to “A.9”
Page 5, Table 2, Footnote :
Change “A.15” to “A.16”
Page 12, Table 8 and Page 14, Table 9, Note 4:
Change “5/8 inch” to “3/4 inch” in Note 4
For Pages 15 – 17, most corrections for Table 10 are in Column 7. Additional corrections in Table 10:
Page 15:
23/8 in, 4.85 lb/ft, E75 drill pipe with 23/8 OHLW connections the makeup torque for premium class (Column 10) should be “1,723”
23/8 in, 4.85 lb/ft, E75 drill pipe with 23/8 OHLW connections the makeup torque for Class 2 (Column 13) should be “1,481”
23/8 in, 6.65 lb/ft, E75 drill pipe with 23/8 OHSW connections the makeup torque for premium class (Column 10) should be “2,216”
23/8 in, 6.65 lb/ft, E75 drill pipe with 23/8 OHSW connections the makeup torque for Class 2 (Column 13) should be “1,967”
27/8 in, 6.85 lb/ft, E75 drill pipe with 27/8 OHLW connections the makeup torque for premium class (Column 10) should be “3,290”
27/8 in, 6.85 lb/ft, E75 drill pipe with 27/8 OHLW connections the makeup torque for Class 2 (Column 13) should be “2,804”
27/8 in, 10.40 lb/ft, E75 drill pipe with 27/8 OHSW connections the makeup torque for premium class (Column 10) should be “4,411”
27/8 in, 10.40 lb/ft, E75 drill pipe with 27/8 OHSW connections the makeup torque for Class 2 (Column 13) should be “4,079”
27/8 in, 10.40 lb/ft, E75 drill pipe with 27/8 PAC connections the makeup torque for premium class (Column 10) should be “3,424”
27/8 in, 10.40 lb/ft, E75 drill pipe with 27/8 PAC connections the makeup torque for Class 2 (Column 13) should be “3,424”
Page 16:
41/2 IEU-X95, NC46, Column 6, change “31/4” to “3”
Page 17:
Last line, Column 11, minimum OD for 65/8 in, 27.70 lb/ft S135 drill pipe, Class 2, change “727/64” to “727/32”
1
2
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
Table 10—Recommended Minimum OD* and Make-up Torque of Weld-on Type Tool Joints
Based on Torsional Strength of Box and Drill Pipe
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
Premium Class
Drill Pipe
New Tool Joint Data
Nominal Nom
Size
Weight Type Upset
in.
lb/ft and Grade
3
2 /8
03
23/8
03
23/8
Conn.
New
OD
in.
New
ID
in.
Make-up
Torque6
ft-lb
Min.
OD
Tool
Joint
in.
Min.
OD
Tool
Joint
in.
4.85
4.85
4.85
4.85
EU-E75
EU-E75
EU-E75
EU-E75
NC26
W.O.
23/8 OHLW
23/8 SL-H90
33/8
33/8
31/8
31/4
13/4
2
2
2
4,125 B
2,541 P
2,716 P
3,042 P
31/8
31/16
3
231/32
/64
/16
1
/16
1
/16
1,945
1,994
1,723
1,996
33/32
31/32
231/32
215/16
6.65
6.65
6.65
6.65
IU-E75
EU-E75
EU-E75
EU-E75
23/8 PAC2
NC26
23/8 SL-H90
23/8 OHSW
27/8
33/8
31/4
31/4
13/8
13/4
2
13/4
2,803 P
4,125 B
3,042 P
3,783 B
225/32
33/16
31/32
31/16
9
/64
/64
3
/32
3
/32
2,455
2,467
2,549
2,216
223/32
35/32
231/32
31/32
6.65
EU-X95
NC26
33/8
13/4
4,125 B
31/4
7
3,005
37/32
3
3
9
5
/64
1
Make-up
Torque for
Min. OD
Tool Joint
ft-lb
/32
/64
3
/64
3
/64
1,689
1,746
1,481
1,726
7
/64
/16
1
/16
5
/64
2,055
2,204
1,996
1,967
3
2,734
3,005
3
1
/32
2 /8
6.65
EU-G105
NC26
3 /8
1 /4
4,125 B
3 /32
1
/8
3,279
3 /4
7
27/8
6.85
6.85
6.85
6.85
EU-E75
EU-E75
EU-E75
EU-E75
NC31
27/8 WO
27/8 OHLW2
27/8 SL-H90
41/8
41/8
33/4
37/8
21/8
27/16
27/16
27/16
7,074 P
4,209 P
3,290 P
4,504 P
311/16
35/8
31/2
31/2
5
/64
5
/64
7
/64
3
/32
3,154
3,216
3,290
3,397
321/32
319/32
37/16
37/16
1
/16
1
/16
5
/64
1
/16
2,804
2,876
2,804
2,666
27/8
10.40
10.40
10.40
10.40
10.40
10.40
EU-E75
IU-E75
IU-E75
EU-E75
EU-E75
IU-E75
NC31
27/8 XH
NC262
27/8 OHSW2
27/8 SL-H90
27/8 PAC2
41/8
41/4
33/8
37/8
37/8
31/8
21/8
17/8
13/4
25/32
25/32
11/2
7,074 P
7,853 P
4,125 B
5,194 P
6,732 P
3,424 P
313/16
323/32
33/8
319/32
319/32
31/8
9
/64
/64
11
/64
5
/32
9
/64
15
/64
4,597
4,357
4,125
4,411
4,529
3,424
33/4
321/32
311/32
39/16
317/32
31/8
7
/64
/64
5
/32
7
/64
7
/64
15
/64
3,867
3,664
3,839
4,079
3,770
3,424
10.40
10.40
EU-X95
EU-X95
NC31
27/8 SL-H902
41/8
37/8
2
25/32
7,895 P
6,732 P
329/32
311/16
3
5,726
5,702
327/32
35/8
5
5
4,969
4,915
10.40
EU-G105
NC31
41/8
2
7,895 P
315/16
6,110
37/8
11
5,345
NC31
3
4 /8
4
15
/64
6,893
3
3
/32
/32
7
/64
3
/32
4,797
4,797
4,868
5,003
9
6,268
6,110
6,299
6,487
7,785
7,647
7,646
27/8
27/8
7
2 /8
1
3 /2
31/2
03
31/2
10.40
EU-S135
5
1 /8
9
/16
/16
3
13
/64
10,086 P
1
4 /16
17
13
1
/64
11
9.50
9.50
9.50
9.50
EU-E75
EU-E75
EU-E75
EU-E75
NC38
NC38
31/2 OHLW
31/2 SL-H90
4 /4
43/4
43/4
45/8
3
211/16
3
3
7,595 P
10,843 P
7,082 P
7,469 P
4 /32
413/32
49/32
43/16
/8
/8
1
/8
7
/64
5,773
5,773
5,340
5,521
4 /32
411/32
41/4
45/32
13.30
13.30
13.30
13.30
13.30
13.30
13.30
EU-E75
IU-E75
EU-E75
EU-E75
EU-X95
EU-X95
EU-X95
NC38
NC312
31/2 OHSW
31/2 H90
NC38
31/2 SL-H902
31/2 H90
43/4
41/8
43/4
51/4
5
45/8
51/4
211/16
21/8
211/16
23/4
29/16
211/16
23/4
10,843 P
7,074 P
10,300 P
14,043 P
12,057 P
11,073 P
14,043 P
41/2
4
413/32
417/32
419/32
43/8
45/8
11
7,274
6,893
7,278
7,064
8,822
8,742
8,826
47/16
315/16
411/32
41/2
417/32
45/16
49/16
13.30
EU-G105
NC38
5
27/16
13,221 P
421/32
1
9,879
419/32
9
12,569
12,614
7,785
3
7
1
/64
/64
3
/16
1
/8
7
/32
13
/64
11
/64
15
/4
1
3 /2
13.30
13.30
EU-S135
EU-S135
NC40
NC38
5 /8
5
2 /16
21/8
17,858 P
15,902 P
5
413/16
/32
21
/64
31/2
15.50
EU-E75
NC38
5
29/16
12,057 P
417/32
3
1
3 /2
15.50
EU-X95
NC38
5
2 /16
13,221 P
31/2
15.50
15.50
EU-G105
EU-G105
NC38
NC40
5
51/4
21/8
29/16
15,902 P
16,616 P
31/2
15.50
EU-S135
NC40
51/2
21/4
19,616 P
6
53/4
1
4
7,694
1
Min. Box
Shoulder
with Eccentric Wear
in.
3
03
2
1
(13)
Class 2
Min. Box Make-up
Shoulder Torque for
with Eccen- Min. OD
tric Wear Tool Joint
in.
ft-lb
3
(12)
11.85
11.85
EU-E75
EU-E75
NC46
4 WO
7
3 /4
37/16
19,937 P
17,186 P
21
/16
/64
7
/32
/32
/64
3
/64
/64
5
/32
7
/64
3
/16
11
/64
9
/64
13
7
8,822
4 /32
423/32
15
10,768
10,957
415/32
5
6,769
8,822
29
19
/32
/64
9
/32
/32
4 /32
1
/4
9,879
4 /32
7
423/32
415/16
9
/32
1
/4
10,957
11,363
45/8
427/32
15
/64
13
/64
9,348
9,595
53/32
21
14,419
431/32
17
11,963
7
5 /32
57/32
/64
7
/64
7
/64
7,843
7,843
5
/32
/64
5
5 /32
/64
6,476
5
5
5 /32
/64
6,476
(Table continued on next page.)
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
3
Table 10—Recommended Minimum OD* and Make-up Torque of Weld-on Type Tool Joints
Based on Torsional Strength of Box and Drill Pipe (Continued)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
Premium Class
Conn.
New
OD
in.
New
ID
in.
Make-up
Torque6
ft-lb
Min.
OD
Tool
Joint
in.
4 OHLW
4 H90
51/4
51/2
315/32
213/16
13,186 P
21,185 P
5
47/8
9
IU-E75
EU-E75
IU-E75
EU-E75
IU-E75
NC40
NC46
4 SH2
4 OHSW
4 H90
51/4
6
45/8
51/2
51/2
213/16
31/4
29/16
31/4
213/16
13,968 P
19,937 P
9,016 P
16,236 P
21,185 P
413/16
59/32
47/16
51/16
415/16
3
14.00
14.00
14.00
IU-X95
EU-X95
IU-X95
NC40
NC46
4 H90
51/4
6
51/2
211/16
31/4
213/16
15,319 P
19,937 P
21,185 P
415/16
53/8
51/32
14.00
14.00
14.00
IU-G105
EU-G105
IU-G105
NC40
NC46
4 H90
51/2
6
51/2
27/16
31/4
213/16
17,858 P
19,937 P
21,185 P
14.00
EU-S135
NC46
6
3
23,399 P
Drill Pipe
New Tool Joint Data
Nominal Nom
Size
Weight Type Upset
in.
lb/ft and Grade
11.85
11.85
EU-E75
IU-E75
14.00
14.00
14.00
14.00
14.00
4
4
4
4
1
11
(12)
(13)
Class 2
Min. Box Make-up
Shoulder Torque for
with Eccen- Min. OD
tric Wear Tool Joint
in.
ft-lb
Min.
OD
Tool
Joint
in.
Min. Box
Shoulder
with Eccentric Wear
in.
Make-up
Torque for
Min. OD
Tool Joint
ft-lb
7,866
7,630
415/16
427/32
7
9,017
9,233
8,782
9,131
8,986
43/4
57/32
43/8
5
47/8
5
/32
/64
13
/64
9
/64
7
/64
7,877
7,843
7,817
7,839
7,630
/4
/16
3
/16
11,363
11,363
11,065
427/32
55/16
431/32
13
9,595
9,937
9,673
5
57/16
53/32
9
/32
/32
7
/32
12,569
12,813
12,481
429/32
511/32
51/32
15
59/16
9
7
/64
/64
7
/16
/64
15
/64
11
/64
9
/64
9
1
3
7
/64
/32
3
7
/64
/32
5
/32
5
6,593
6,962
/64
/64
3
/16
10,768
10,647
11,065
11
15,787
51/2
1
14,288
7
25
8,444
8,535
8,305
/32
/4
4
15.70
15.70
15.70
IU-E75
EU-E75
IU-E75
NC40
NC46
4 H90
5 /4
6
51/2
2 /16
31/4
213/16
15,319 P
19,937 P
21,185 P
4 /8
55/16
431/32
/32
5
/32
5
/32
10,179
9,937
9,673
4 /32
51/4
429/32
11
4
15.70
15.70
15.70
IU-X95
EU-X95
IU-X95
NC40
NC46
4 H90
51/2
6
51/2
27/16
3
213/16
17,858 P
23,399 P
21,185 P
5
57/16
53/32
9
/32
/32
7
/32
12,569
12,813
12,481
429/32
511/32
51/32
15
/64
/64
3
/16
10,768
10,647
11,065
15.70
15.70
EU-G105
IU-G105
NC46
4 H90
6
51/2
3
213/16
23,399 P
21,185 P
515/32
55/32
15
13,547
13,922
513/32
51/16
13
12,085
11,770
15.70
15.70
IU-S135
EU-S135
NC46
NC46
6
6
25/8
27/8
26,982 B
25,038 P
521/32
521/32
21
18,083
18,083
517/32
517/32
17
16.60
16.60
16.60
16.60
16.60
IEU-E75
IEU-E75
IEU-E75
EU-E75
IEU-E75
41/2 FH
NC46
41/2 OHSW
NC50
41/2 H-90
6
61/4
57/8
65/8
6
3
31/4
33/4
33/4
31/4
20,620 P
19,937 P
16,162 P
22,361 P
23,126 P
53/8
513/32
57/16
523/32
511/32
13
/64
/64
13
/64
5
/32
3
/16
12,125
12,085
11,862
11,590
12,215
59/32
511/32
53/8
511/16
59/32
16.60
16.60
16.60
16.60
IEU-X95
IEU-X95
EU-X95
IEU-X95
41/2 FH
NC46
NC50
41/2 H-90
6
61/4
65/8
6
23/4
3
33/4
3
23,695 P
19,937 P
22,361 P
26,969 P
51/2
517/32
527/32
515/32
17
/64
/64
7
/32
1
/4
14,945
15,035
14,926
15,441
513/32
57/16
525/32
53/8
/32
/32
3
/16
13
/64
16.60
16.60
16.60
16.60
IEU-G105
IEU-G105
EU-G105
IEU-G105
41/2 FH
NC46
NC50
41/2 H-90
6
61/4
65/8
6
23/4
3
33/4
3
23,695 P
23,399 P
22,361 P
26,969 P
59/16
519/32
529/32
51/2
19
/64
/64
1
/4
17
/64
16,391
16,546
16,633
16,264
515/32
51/2
513/16
57/16
/4
/4
13
/64
15
/64
14,231
14,288
14,082
14,625
16.60
16.60
IEU-S135
EU-S135
NC46
NC50
61/4
65/8
23/4
31/2
26,615 P
26,674 P
525/32
61/16
25
21,230
21,017
521/32
531/32
21
18,083
18,367
20.00
20.00
20.00
20.00
IEU-E75
IEU-E75
EU-E75
IEU-E75
41/2 FH
NC46
NC50
41/2 H-90
6
61/4
65/8
6
3
3
35/8
3
20,620 P
23,399 P
24,549 P
26,969 P
515/32
51/2
513/16
513/32
/4
/4
13
/64
7
/32
14,231
14,288
14,082
13,815
53/8
513/32
53/4
511/32
20.00
20.00
20.00
20.00
IEU-X95
IEU-X95
EU-X95
IEU-X95
41/2 FH
NC46
NC50
41/2 H-90
6
61/4
65/8
6
21/2
23/4
31/2
3
26,528 P
26,615 P
26,674 P
26,969 P
55/8
521/32
515/16
59/16
21
17,861
18,083
17,497
17,929
517/32
59/16
57/8
515/32
4
4
41/2
41/2
41/2
41/2
41/2
41/2
7
/64
/4
1
/64
/64
21
13
17
19
/64
/64
21
1
1
/64
/64
17
/64
19
/64
21
/64
1
/8
1
/8
11
/64
/64
13
/64
/64
15,035
15,035
/32
/64
11
/64
9
/64
5
/32
10,072
10,647
10,375
10,773
10,642
7
12,821
12,813
13,245
13,013
17
5
11
7
1
1
/64
/32
9
13
/64
/64
12
/64
3
/16
12,125
12,085
12,415
12,215
9
15,665
15,787
15,776
15,441
13
/32
/32
15
/64
1
/4
9
(Table continued on next page.)
03
03
4
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
Table 10—Recommended Minimum OD* and Make-up Torque of Weld-on Type Tool Joints
Based on Torsional Strength of Box and Drill Pipe (Continued)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
Premium Class
Conn.
New
OD
in.
New
ID
in.
Make-up
Torque6
ft-lb
Min.
OD
Tool
Joint
in.
Drill Pipe
New Tool Joint Data
Nominal Nom
Size
Weight Type Upset
in.
lb/ft and Grade
1
4 /2
41/2
523/32
61/32
23
20.00
EU-S135
NC50
65/8
3
34,520 P
67/32
13
5
3
7
/64
/16
5
19,644
20,127
55/8
529/32
5
/16
/4
1
17,311
16,633
25,569
63/32
11
21,914
/64
15,776
13
5 /16
13
14,082
/32
/32
NC50
6 /8
3 /4
22,361 P
5 /8
5
19.50
19.50
IEU-X95
IEU-X95
NC50
5 H-90
65/8
61/2
31/2
31/4
26,674 P
30,732 P
61/32
527/32
5
/16
19
/64
20,127
19,862
515/16
53/4
17
17,497
17,116
5
19.50
19.50
IEU-G105
IEU-G105
NC50
5 H-90
65/8
61/2
31/4
3
30,730 P
34,805 P
63/32
529/32
11
21,914
21,727
6
513/16
19
19,244
18,940
19.50
19.50
IEU-S135
IEU-S135
NC50
51/2 FH
65/8
71/4
23/4
31/2
38,036 P
43,328 P
65/16
63/4
29
/64
/8
28,381
28,737
63/16
65/8
25
25.60
25.60
IEU-E75
IEU-E75
NC50
51/2 FH
65/8
7
31/2
31/2
26,674 P
37,742 B
61/32
61/2
5
/16
/4
20,127
20,205
515/16
613/32
17
25.60
25.60
IEU-X95
IEU-X95
NC50
51/2 FH
65/8
7
3
31/2
34,520 P
37,742 B
67/32
621/32
13
/32
/64
25,569
25,483
63/32
69/16
11
25.60
25.60
IEU-G105
IEU-G105
NC50
51/2 FH
65/8
71/4
23/4
31/2
38,036 P
43,328 P
69/32
623/32
/16
/64
27,437
27,645
65/32
65/8
25.60
IEU-S135
51/2 FH
71/4
31/4
47,230 B
615/16
35,446
613/16
5
5
1
5 /2
21.90
IEU-E75
5 /2 FH
7
4
51/2
21.90
21.90
IEU-X95
IEU-X95
51/2 FH
51/2 H-90
7
7
33/4
31/2
51/2
21.90
IEU-G105
51/2 FH
71/4
31/2
1
5 /2
21.90
IEU-S135
1
1
5 /2 FH
1
1
7 /2
3
/32
/64
21
3
1
21
7
23
15
/32
617/32
63/32
17
/64
9
/32
21,246
21,349
43,328 P
623/32
23
27,645
619/32
52,059 P
/64
15
9
6 /16
/32
4
33,412 P
6 /16
31/2
43,328 P
623/32
23
1
1
3 /2
71/2
3
65/8
25.20
IEU-E75
IEU-X95
IEU-G105
IEU-S135
65/8 FH
65/8 FH
65/8 FH
65/8 FH
8
8
81/4
81/2
65/8
27.70
IEU-E75
IEU-X95
IEU-G105
IEU-S135
65/8 FH
65/8 FH
65/8 FH
65/8 FH
8
81/4
81/4
81/2
17,127
6 /32
71/4
7 /4
30,943
/32
24,412
24,414
7
5 /2 FH
13
19,172
5 /2 FH
51/2 FH
23,728
24,412
/8
/16
/64
51/2 FH
IEU-S135
3
5
/16
21
/64
IEU-E75
IEU-G105
21,914
22,294
5
IEU-X95
24.70
/32
/32
9
65/8
63/16
24.70
24.70
17,497
17,127
6 /32
24.70
51/2
/64
/64
13
24,645
24,412
33,412 P
51/2
5 /2
/64
/16
5
37,742 B
34,820 P
5 /2
1
/64
/32
9
13
9
1
/64
1
/4
15
15
/32
/64
35,446
13
/64
15
1
1
/64
19
23,350
13
13
30,943
15
19,172
6 /16
/64
/32
22,294
6 /32
15
27,645
619/32
19
23,350
11
/64
/64
43,328 P
25
6 /32
25
29,836
6 /16
11
/32
26,560
52,059 P
71/32
33
38,901
67/8
7
/16
33,180
5
5
43/4
41/4
43,934 P
43,934 P
51,280 P
65,012 P
77/16
75/8
711/16
729/32
1
/4
11
/32
5
/8
31
/64
26,810
35,139
37,983
48,204
73/8
71/2
719/32
725/32
7
/32
9
/32
21
/64
27
/64
24,100
29,552
33,730
42,312
5
43/4
43/4
41/4
43,934 P
51,280 P
51,280 P
65,012 P
71/2
711/16
73/4
8
9
29,552
37,983
40,860
52,714
713/32
79/16
721/32
727/32
15
25,451
32,329
36,556
45,241
/64
/64
/32
/8
13
/32
17
/32
3
/64
/16
23
/64
29
/64
5
The use of outside diameters (OD) smaller than those listed in the table may be acceptable due to special service requirements.
Tool joint with dimensions shown has lower torsional yield ratio than the 0.80 which is generally used.
3
Recommended make-up torque is based on 72,000 psi stress.
4
In calculation of torsional strengths of tool joints, both new and worn, the bevels of the tool joint shoulders are disregarded. This thickness measurement should
be made in the plane of the face from the I.D. of the counter bore to the outside diameter of the box, disregarding the bevels.
5
Any tool joint with an outside diameter less than API bevel diameter should be provided with a minimum 1/32 inch depth x 45 degree bevel on the outside and
inside diameter of the box shoulder and outside diameter of the pin shoulder.
6
P = Pin limit; B = Box limit.
*Tool joint diameters specified are required to retain torsional strength in the tool joint comparable to the torsional strength of the attached drill pipe. These should
be adequate for all service. Tool joints with torsional strengths considerably below that of the drill pipe may be adequate for much drilling service.
2
00
29,578 P
26,674 P
IEU-E75
5
03
21/2
31/2
Make-up
Torque for
Min. OD
Tool Joint
ft-lb
19.50
5
03
61/4
65/8
Min. Box
Shoulder
with Eccentric Wear
in.
5
5
03
NC46
NC50
Min.
OD
Tool
Joint
in.
15
03
03
IEU-G105
EU-G105
(13)
Class 2
Min. Box Make-up
Shoulder Torque for
with Eccen- Min. OD
tric Wear Tool Joint
in.
ft-lb
20.00
20.00
(12)
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
5
Page 38, Table 14, Footnote 1:
Change “A.8” to “A.9”
Page 112, replace 13.1 with the following:
13.1 DRILL STRING MARKING AND IDENTIFICATION
Sections of drill string manufactured in accordance with API Specification 7 are identified with markings on the base of the pin
connection. An additional pin base marking, representing the drill pipe weight code, is recommended as shown in Figure 82. The
recommended weight codes are shown in Figure 83. It is recommended that drill string members not covered by API Specification
7 also be stenciled at the base of the pin as shown in Figure 82. It is also recommended that drill string members be marked using
the mill slot and groove method as shown in Figure 83.
Page 113 and 114, replace Figures 82 and 83 with the following:
Sample markings at base of pin
1,2
1
2
3
4
5
6
ZZ
3
02
N
S
2
1
Tool Joint Manufacturer's Symbol:
ZZ Company (fictional for example only)
2
Month Welded:
3 – March
3
Year Welded
02 – 2002
4
Pipe Manufacturer's Symbol:
N – United States Steel Company
5
Drill Pipe Grade
S – Grade S135 drill pipe
6
Drill Pipe Weight Code
2
Notes:
1.
Tool Joint manufacturer's symbol, month welded, year welded, pipe manufacturer and drill pipe grade symbol shall be stenciled at the base of the pin
as shown above. Pipe manufacturer symbol and drill pipe grade symbol applied shall be as represented by manufacturer. Supplier, owner, or user shall
be indicated on documents such as mill certification papers or purchase orders.
2.
Stamping the drill pipe weight code on the pin base and milled slot is recommended, in addition to the marking requirements of API Specification 7.
TOOL JOINT MANUFACTURER'S SYMBOL
Refer to the current edition of the IADC Drilling Manual* for a list of Tool Joint Manufacturer's symbols.
*Available from: International Association of Drilling Contractors (IADC) P.O. Box 4287, Houston, TX 77210.
Pipe Manufacturers
(Pipe Mills or Processors)
Month and Year Welded
Month
Year
1 through 12
Last two digits of year
Active
Drill Pipe Grade
Grade
Symbol
E75 . . . . . . . . . . . . . . . . . E
X95 . . . . . . . . . . . . . . . . .X
G105 . . . . . . . . . . . . . . . . G
S135 . . . . . . . . . . . . . . . .S
The "manufacturer" may be either a pipe mill or processor. See
API Specification 5D, Specification for Drill Pipe.
These symbols are provided for pipe manufacture r
identification and have been assigned at pipe manufacturer's
requests. Manufacturers included in this list may not be current
API Specification 5D licensed pipe manufacturers. A list o f
current licensed pipe manufacturers is available in the Composite
List of Manufacturers. (Licensed for Use of the API Monogram).
Pipe mills may upset and heat treat their own drill pipe, or they
may have this done according to their own specifications. In
either case, the mill's assigned symbol should be used on each
drill string assembly since they are the pipe manufacturer.
Pipe processors may buy "green" tubes and upset and heat treat
these according to their own specifications. In this case, the
processor's assigned symbol should be used on each drill string
assembly since they are the pipe manufacturer.
Mill
Algoma
Inactive
Symbol
X
British Steel
Mill
Symbol
Armco
A
American Seamless
AI
Seamless Tubes LTD
B
B&W
W
Dalmine
D
CF&I
C
Kawasaki
H
J&L
J
Nippon
I
Lone Star
L
NKK
K
Ohio
O
Mannesmann
M
Republic
R
Reynolds Aluminum
RA
TI
Sumitomo
S
Z
Tubemuse
TU
Voest
VA
Siderca
SD
Tamsa
T
Wheeling Pittsburgh
P
US Steel
N
Youngstown
Y
Vallourec
V
Used
U
Processor
Symbol
Grant TFW
TFW
Omsco
OMS
Prideco
PI
Texas Steel Conversion
TSC
Figure 82—Marking on Tool Joints for Identification of Drill String Components
6
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
1 7/16'' ± 1/16''**
Depth *
45°
ZZ 6 02 N E 2
/8''
1'' ± 1/8''
± /16''**
1
Standard weight grade E75 drill pipe
3 ''
/8 ± 1/16''
/8'' ± 1/16''**
R 1/16" TYP.
3
Heavy weight grade E75 drill pipe
1 7/16'' ± 1/16''**
3 ''
/8 ± 1/16''**
ZZ 6 02 N S 3
ZZ 6 02 N S 2
R 3/8"
ZZ 6 02 N E 3
3
7
Heavy weight high strength drill pipe
Standard weight high strength drill pipe
Allowance for serial
number (optional)
Pipe weight code
1 7/8'' hardfacing allowance (TYP.)
for 1 1/2'' of hardfacing
3 ''
1 ''
±
/8
/8 to hardfacing
Pipe grade code
ZZ 3 02 N S 3
* Groove and milled slot to be 1/4'' deep on 5 1/4''
O.D. and larger tool joints, 3/16'' deep on 5" O.D.
and smaller tool joints.
Stencil milled slot with 1/4'' high characters so
marking may be read with drill pipe hanging in
elevators.
Stamping the drill pipe weight code on the pin
base and milled slot is recommended, in addition
to the marking requirements of API Specification 7.
Heavy weight high strength drill pipe
with hardfacing allowance
** When pin hardfacing is required, increase these
dimensions by the length of the hardfacing allowance.
See example above.
Drill Pipe Weight Code
(1)
Size OD
inches
23/8
(2)
(3)
Nominal Weight Wall Thickness
lb per ft
inches
4.85
.190
6.65*
.280
(4)
Weight Code
Number
1
2
27/8
6.85
10.40*
.217
.362
1
2
31/2
9.50
13.30*
15.50
.254
.368
.449
1
2
3
4
11.85
14.00*
15.70
.262
.330
.380
1
2
3
41/2
13.75
.271
16.60*
.337
*Designates standard weight for drill pipe size.
1
2
(1)
Size OD
inches
41/2
(2)
(3)
Nominal Weight Wall Thickness
lb per ft
inches
20.00
.430
22.82
.500
24.66
.550
25.50
.575
(4)
Weight Code
Number
3
4
5
6
5
16.25
19.50*
25.60
.296
.362
.500
1
2
3
51/2
19.20
21.90*
24.70
.304
.361
.415
1
2
3
65/8
25.20*
27.70
.330
.362
2
3
Figure 83—Recommended Practice for Mill Slot and Groove Method of Drill String Identification
8
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
Page 127, replace Section 14 with the following:
14 Special Processes
14.1 DRILL STEM SPECIAL PROCESSES
14.1.1 Usually the materials used in the manufacture of down hole drilling equipment (tool joints, drill collars, stabilizers and
subs) are AISI–4135, 4137, 4140, or 4145 steels.
14.1.2 These are alloy steels and are normally in the heat treated state, these materials are not weldable unless proper procedures are used to prevent cracking and to recondition the sections where welding has been performed.
14.1.3 It should be emphasized that areas welded can only be reconditioned and cannot be restored to their original state free of
metallurgical change unless a complete heat treatment is performed after welding, which cannot be done in the field.
14.2 CONNECTION BREAK-IN
Based on field experience, it has been observed that used rotary shouldered connections are less likely to gall than new connections. It is believed that this is due to work hardening the connection surfaces. The process of Connection Break-In is a make-up
and break-out of the connection under controlled conditions in order to provide surface work hardening prior to use. Connection
Break-In may be done on the rig, as an optional manufacturing step, or at a service facility.
Since many factors effect connection galling, Connection Break-In does not eliminate the possibility of galling.
14.2.1 Preparation for Connection Break-In
Remove any storage or rust preventative coatings. Make sure that the connections are free of dirt or other debris. Thoroughly
coat the threads and shoulders of both pin and box connections with a thread compound suitable for rotary shouldered connections. Determine the recommended make-up torque of the connection. Make note of the friction factor of the thread compound
and any adjustment required to the applied make up torque. See API Specification 7, Appendix G and API Recommended Practice
7A1 for further information on thread compounds and friction factor.
14.2.2
Connection Break-In at the Rig
Taking care to align the connection, stab and make-up the connection slowly. Spinning in with a chain or high speed power
spinner may cause galling. Using a calibrated torque gage or line pull indicator, slowly make-up to the recommended make-up
torque. With manual tongs, use both sets of tongs and keep lines at 90 degrees for the final torque. Slowly break-out the connection. During both make-up and break-out, watch for excessive resistance or other signs that could indicate the possibility of galling. Wipe clean the pin and box connections and visually inspect for evidence of galling in the threads or sealing shoulders. If
galling occurs, rework the connection prior to use.
14.2.3
Connection Break-In During Manufacturing
When performing break-in at the factory or service facility, the connection should be finished machined, inspected, cold rolled
(if specified) and preferably coated with an anti-gall material such as a phosphate or copper.
Note: Break-in will change thread gage standoff.
Slowly make-up three times to the recommended torque. Between each make-up, break-out only far enough to apply additional
thread compound to the shoulders and last engaged threads. Break out the connection after final make-up. Wipe clean the pin and
box and visually inspect for galling on the threads or shoulder. If galling occurs, the connection is rejected.
Page 130, Table 33, add the following sizes:
Connection
Maximum
Pin ID
in.
Bit Sub
OD
in.
1 API REG
11/2 API REG
0.75
1.00
1.56
2.00
Page 130, Table 33, Note:
Change “A.8” to “A.9”
Replace Appendix A with the following:
Minimum
Make-up Torque
ft-lb
185
665
APPENDIX A— STRENGTH AND DESIGN FORMULAS
A.1 Torsional Strength of Eccentrically
Worn Drill Pipe
Note: Torsional yield strengths for Premium Class, Table 4, and Class 2,
Table 6 were calculated from Equation A.1, using the assumption that wear is
uniform on the external surface.
Assume 1: Eccentric hollow circular section (see Figure A-1).
Reference: Formulas for Stress & Strain, Roark, 3rd Edition.
A.2 Safety Factors
Values for various performance properties of drill pipe are
given in Tables 2 through 7. The values shown are minimum
values and do not include factors of safety. In the design of
drill pipe strings, factors of safety should be used as are considered necessary for the particular application.
A.3 Collapse Pressure for Drill Pipe
Note: See API Bulletin 5C3 for derivation of equations in A.3.
The minimum collapse pressures given in Tables 3, 5, and
7 are calculated values determined from equations in API
Bulletin 5C3. Equations A.2 through A.5 are simplified equations that yield similar results. The D/t ratio determines the
applicable formula, since each formula is based on a specific
D/t ratio range.
For minimum collapse failure in the plastic range with
minimum yield stress limitations: the external pressure that
generates minimum yield stress on the inside wall of a tube.
e
(D ⁄ t) – 1
P c = 2Y m ---------------------2
(D ⁄ t)
d
(A.2)
D
Applicable D/t ratios for application of Equation A.2 are as
follows:
Figure A-1—Eccentric Hollow Section of Drill Pipe
πS s ( D – d )
T = -------------------------------------,
12 × 16 × D × F
4
4
Grade
(A.1)
E75 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.60 and less
where
X95. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.85 and less
4N φ
32N φ
F = 1 + ------------------ + ----------------------------------------2
2
4
(1 – N ) (1 – N ) (1 – N )
2
N =
φ =
=
=
=
=
2
2
G105. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.57 and less
S135 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.92 and less
3
48N ( 1 + 2N + 3N + 2N ) φ ,
+ ----------------------------------------------------------------------2
4
6
(1 – N ) (1 – N ) (1 – N )
d/D,
e
---- ,
D
torque, ft-lbs.,
minimum shear strength, psi,
outside diameter, in.,
inside diameter, in.
2
T
Ss
D
d
D/t Ratio
2
4
6
For minimum collapse failure in the plastic range:
A'
P c = Y m  --------- – B' – C
 D ⁄ t
(A.3)
Factors and applicable D/t ratios for application of Equation A.3 are as follows:
Formula Factors
Assume 2: The internal diameter, d, remains constant and
at the nominal ID of the pipe throughout its life.
Assume 3: The external diameter D is d + t nominal + t
minimum; i.e., all wear occurs on one side. This diameter is
not the same as diameter for uniform wear.
9
Grade
A'
B'
C
D/t Ratio
E75
X95
G105
S135
3.054
3.124
3.162
3.278
0.0642
0.0743
0.0794
0.0946
1806
2404
2702
3601
13.60 to 22.91
12.85 to 21.33
12.57 to 20.70
11.92 to 19.18
10
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
For minimum collapse failure in conversion or transition
zone between elastic and plastic range:
A
P c = Y m  --------- – B
 D ⁄ t
(A.4)
Factors and applicable D/t ratios for application of Equation A.4 are as follows:
where
L1
E
e
WdP
P
=
=
=
=
=
length of free drill pipe, ft.,
modulus of elasticity, lb/in.,2
differential stretch, in.,
weight per foot of pipe, lbs/ft.,
differential pull, lbs.
Where E = 30 x 106, this formula becomes:
735,294 × e × W dP
L 1 = -----------------------------------------P
Formula Factors
Grade
A
B
D/t Ratio
E75
X95
G105
S135
1.990
2.029
2.053
2.133
0.0418
0.0482
0.0515
0.0615
22.91 to 32.05
21.33 to 28.36
20.70 to 26.89
19.18 to 23.44
A.5 Internal Pressure
A.5.1 DRILL PIPE
2Y m t
P i = ----------,
D
For minimum collapse failure in the elastic range:
46.95 × 10
P c = --------------------------------------------2
(D ⁄ t)[(D ⁄ t) – 1]
6
(A.5)
Applicable D/t ratios for application of Equation A.5 are as
follows:
Grade
D/t Ratio
E75. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32.05 and greater
X95 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .28.36 and greater
G105 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .26.89 and greater
S135 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23.44 and greater
where
Pi
Ym
t
D
=
=
=
=
=
=
=
=
(A.8)
Notes:
1. Internal pressures for new drill pipe in Table 3 were determined by using the
nominal wall thickness for t in the above equation and multiplying by the factor
0.875 due to permissible wall thickness tolerance of minus 121/2 percent.
2. Internal pressures for used drill pipe were determined by adjusting the
nominal wall thickness according to footnotes below Table 5 and 7 and using
the nominal outside diameter, in the above Equation A.8.
A.5.2 KELLYS
Y m [ D FL – ( D FL – 2t ) ]
P i = ------------------------------------------------------,
4
4
3 ( D FL ) + ( D FL – 2t )
minimum collapse pressure, psi,
nominal outside diameter, in.,
nominal wall thickness, in.,
material minimum yield strength, psi.
Notes:
*Collapse pressures for used drill pipe are determined by adjusting the nominal outside diameter, D, and wall thickness, t, as if the wear is uniform on the
outside of the pipe body and the inside diameter remains constant. Values of
D and t for each class of used drill pipe follow. These values are to be used in
applicable Equation A.2, A.3, A.4, or A.5, depending on the D/t ratio, to
determine collapse pressure.
Premium Class: t = (0.80) (nominal wall), D = nominal OD – (0.40) (nominal wall)
Class 2: t = (0.70) (nominal wall), D = nominal OD – (0.60) (nominal wall)
98
internal pressure, psi,
material minimum yield strength, psi,
remaining wall thickness of tube, in.,
nominal outside diameter of tube, in.
2
where
Pc
*D
*t
Ym
(A.7)
where
Pi
Ym
DFL
t
=
=
=
=
2
(A.9)
98
internal pressure, psi,
material minimum yield strength, psi,
distance across drive section flats, in.,
minimum wall, in.
Note: The dimension t is the minimum wall thickness of the drive section and
must be determined in each case through the use of an ultrasonic thickness
gauge or similar device.
A.6 Stretch of Suspended Drill Pipe
When pipe is freely suspended in a fluid, the stretch due to
its own weight is:
A.4 Free Length of Stuck Pipe
98
The relation between differential stretch and free length of
a stuck string of steel pipe due to a differential pull is:
E × e × W dp
-,
L 1 = -------------------------40.8 P
(A.6)
2
L1
- [ W a – 2W f ( 1 – µ ) ] ,
e = --------24E
where
e = stretch, in.,
L1 = length of free drill pipe, ft.,
(A.10)
98
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
E
Wa
Wf
µ
00
=
=
=
=
modulus of elasticity, psi,
weight of pipe material, lb/cu ft.,
weight of fluid, lb/cu ft.,
Poisson’s ratio.
For steel pipe where Ws = 489.5 lb/cu ft, E = 30 x 106 psi
and µ = 0.28, this formula will be:
2
L1
-7 [ 489.5 – 1.44W f ] ,
e = ------------------72 × 10
(A.11)
where
P = minimum tensile strength, lbs.,
Ym = material minimum yield strength, psi,
A = cross-section area, sq. in. (Table 1, Column 6, for
drill pipe).
A.8 Torsional Yield Strength of Drill Pipe
Body
A.8.1 PURE TORSION
2
(A.12)
where
Wf = weight of fluid, lb/cu ft.,
Wg = weight of fluid, lb/gal.
03
03
0.096167JY
Q = -------------------------------m ,
D
or
L1
-7 [ 65.44 – 1.44W g ] ,
e = -------------------------9.625 × 10
A.7 Tensile Strength of Drill Pipe Body
P = Ym A,
(A.13)
where
Q = minimum torsional yield strength, ft-lb.,
Ym = material minimum yield strength, psi,
J = polar moment of inertia
π
= ------ (D4 – d4) for tubes
32
= 0.098175 (D4 – d4),
D = outside diameter, in.,
d = inside diameter, in.
3/
4
5/
8
p
3/
8
θ
AB
Box
AP
Rs
QC
C
11
Pin
Lt
2
Lt
2
Rt
ID
Figure A-2—Rotary Shouldered Connection
θ
(A.14)
12
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
A.8.2 TORSION AND TENSION
where
π
Ap = --- [(C – B)2 – ID2] = without relief grooves,
4
2
0.096167J
P
Q T = ------------------------- Ym2 – -----2
D
A
(A.15)
where
QT = minimum torsional yield strength under tension,
ft-lb.,
J = polar moment of inertia
D
d
Ym
P
A
π
= ------ (D4 – d4) for tubes
32
= 0.098175 (D4 – d4),
= outside diameter, in.,
= inside diameter, in.,
= material minimum yield strength, psi,
= total load in tension, lbs.,
= cross section area, sq. in.
A.9 Torque Calculations for Rotary
Shouldered Connections (see Table
A-1 and Figure A-2)
A.9.1 TORQUE TO YIELD A ROTARY
SHOULDERED CONNECTION
Ym A  p
Rt f
- ------ + ---------- + R s f
T y = --------

12 2π cosθ
where
Ty
Ym
p
f
00
98
(A.16)
or
π
Ap = --- [(DRG2 – ID2] = with relief grooves,
4
where
DRG = diameter of relief groove (Specification 7, Table
16, Column 5), in.,
C = pitch diameter of thread at gauge point (Specification 7, Table 25, Column 5), in.,
ID = inside diameter, in.,
H
B = 2  ---- – S rs + tpr x 1/8 x 1/12,
2

H = thread height not truncated (Specification 7, Table
26, Column 3), in.,
Srs = root truncation (Specification 7, Table 26, Column
5), in.,
tpr = taper (Specification 7, Table 25, Column 4), in./ft.,
π
Ab= --- [OD2 – (Qc – E)2],
4
where
OD = outside diameter, in.,
Qc = box counterbore (Specification 7, Table 25,
Column 11), in.,
E = tpr x 3/8 x 1/12
A.9.2 MAKE-UP TORQUE FOR ROTARY
SHOULDERED CONNECTIONS
=
=
=
=
turning moment or torque required to yield, ft-lbs.,
material minimum yield strength, psi,
lead of thread, in.,
coefficient of friction on mating surfaces, threads
and shoulders, assumed 0.08 for thread compounds containing 40 to 60 percent by weight of
finely powdered metallic zinc. (Reference the caution regarding the use of hazardous materials in
Appendix G of Specification 7.),
1
θ = /2 included angle of thread (Figures 21 or 22,
Specification 7), degrees,
C + [ C – ( L pc – .625 ) × tpr × 1 ⁄12 ]
-,
Rt = ---------------------------------------------------------------------------------4
Lpc = length of pin (Specification 7, Table 25, Column
9), in.,
Rs = 1/4 (OD + Qc), in.
The maximum value of Rs is limited to the value
obtained from the calculated OD where Ap = Ab,
A = cross-section area Ab or Ap whichever is smaller,
sq. in.
Rt f
SA p
T = ------  ------ + ---------- + R s f


12 2π cosθ
(A.17)
where
A = Ab or AP whichever is smaller; AP shall be based on
pin connections without relief grooves, sq. in.,
S = recommended make-up stress level, psi.
Note: For values of S, see 4.8.1 for Tool Joints and 5.2 for Drill Collars.
A.10 Combined Torsion and Tension to
Yield Rotary Shouldered
Connection and Drill Pipe Body
A.10.1 INTRODUCTION
Field-operating practice should always maintain operating
torque below the make-up torque. Since there is no margin of
safety applied in these curves, the actual dimensions of the
tool joint and tube (inspection classification) must be used in
the construction of the curve. Always be aware of the operating limits of the pipe in combination with the tool joint.
03
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
03
13
A.10.2 DRILL PIPE SELECTION AND NORMAL
OPERATIONS (SEE FIGURE A.3a)
curves. In these cases, the horizontal axis will represent the
torque applied after tension is applied.
At torque levels up to the make-up torque of the tool joint,
the Make-up Torque THEN Tension curves are used to determine the capacity. These curves are used when the maximum
torque a connection will experience is the torque applied before
tension is applied. The torque value used in this set of curves is
the make-up torque or the applied torque, whichever is greater.
CAUTION: The dynamic loads considered in this simplified
approach are different than static loads. API recommends
staying in safe zone of operations. Going outside this zone or
getting close to the boundaries can result in a catastrophic
failure.
A.10.4
A.10.3 SPECIAL OPERATIONS (SEE FIGURE A.3b)
For operations where the applied downhole torque to the
drill string might exceed the tool joint make-up torque (fishing, back-reaming, etc.), use the Tension THEN Torque
03
EQUATION DEFINITIONS
The variables used in the equations below are defined in
A.9.1.
P1 = Y m A p
(A.18)
03
Figure A-3a—Make-up Torque Then Tension
03
Figure A-3b—Tension Then Torque
14
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
12 ( A b + A p )T a
P o = -------------------------------------------------Rt f
p
- + R s f
A b  ------ + ---------- 2π cos θ

P T4T2




T a 12
= ( A b + A p )  Y m – --------------------------------------------------
Rt f
p


A p  ------ + ----------- + R s f 

 2π cos θ

P T3T2
Rt f
p
Y m A p  ------ + ----------- + R s f  – 12T DH
 2π cos θ

= -----------------------------------------------------------------------------Rs f
(A.20)
(A.21)
T2 = torsional strength of the pin of the tool joint, ft-lbs
T3 = torsional load required to produce additional makeup of the connection when the shoulders are separated by an external tensile load on the pipe that
produces yield stress in the tool joint pin, ft-lbs
T4 = make-up torque at which pin yield and shoulder
separation occur simultaneously with an externally applied tensile load, ft-lbs
PQ = yield of the drill pipe tube in the presence of torsion represented by the elliptical curve, lbs. Equation was produced by rearranging Equation A.15
A.10.5 FAILURE MODES
The failure modes under combined torsion/tension loads are:
1. Pin yield.
2. Box yield.
3. Shoulder separation (seal failure).
4. Tube yield.
Y
Rt f
p
- + R s f
T1 =  -----m- A b  ------ + ---------- 12
 2π cos θ

(A.22)
Y
Rt f
p
- + R s f
T2 =  -----m- A p  ------ + ---------- 12
 2π cos θ

(A.23)
A.10.6 USING THE CURVES
(A.24)
Calculate the above values using the actual dimensions of
the tool joints and tube. Use these values to plot a working
curve.
Y
Rt f 
p
T3 =  -----m- A p  ------ + ---------- 12
 2π cos θ
03
(A.19)
Ap Ab   p
Y
Rt f
- ------ + ----------- + R s f
T4 =  -----m-  --------------- 12  A p + A b  2π cos θ

2
Qt D
2
-
P Q = A Y m –  --------------------------- 0.096167 ⋅ J
Example 1: Drilling an Extended Reach Well
(See Figure A.3c)
(A.25)
(A.26)
A description of the values calculated above and those used
to plot the curves are:
Ta = torque that is applied to the tool joint before tension is applied, make-up torque, ft-lbs
TDH = applied downhole torque, ft-lbs
P1 = yield strength of the tool joint pin at 5/8" from the
make-up shoulder, lbs
Po = tension required to separate the tool joint shoulders after Ta is applied, lbs. Po is represented by the
line from the origin to the point T4. Do not use this
formula if Ta is greater than T4 since Po will be
greater than P1
PT4T2 = tension required to yield pin after Ta is applied, lbs.
PT4T2 is represented by the line from T4 to T2
PT3T2 = tension required to yield pin after TDH is applied,
lbs. PT3T2 is represented by the line from T3 to T2
T1 = torsional strength of the box of the tool joint and is
represented by a vertical line at that value on the xaxis, ft-lbs
Assume:
Anticipated Maximum Drilling Torque = 25,000 ft-lbs
Drill Pipe string is 5", 19.50 ppf, Grade S, Premium Class
with NC50 tool joints (65/16" OD × 23/4" ID)
Calculated values:
P = 560,764 lbs
Q = 58,113 ft-lbs
Ta (make-up torque) = 28,381ft-lbs
P1 = 1,532,498 lbs
T1 = 47,302 ft-lbs
T2 = 62,608 ft-lbs
T4 = 26,945 ft-lbs
Questions
Is the drill pipe string adequate for the anticipated torque?
{{Yes}}
What is the allowable hook load at anticipated maximum
drilling torque? {{P = 504,772 lbs at 25,000 ft-lbs}}
Example 2: Fishing Drill Pipe String in Example 1
(See Figure A.3c)
Question:
What is the maximum pull without exceeding yield
strength in the absence of torque? {{With a straight pull and
no torque, the maximum pull is the tensile capacity of the
tube which is P = 560,764 lbs.}}
03
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
15
03
Figure A-3c—Make-up Torque Then Tension
03
Figure A-3d—Tension Then Torque
Example 3: Back-reaming Hole with Drill Pipe Stinger
(See Figure A.3d)
03
Assume:
Back-reaming Pull = 300,000 lbs
Drill pipe stinger is 31/2", 15.50 ppf, Grade S, Premium
Class with NC38 tool joints (43/4" OD × 29/16" ID)
Calculated values:
P = 451,115 lbs
Q = 29,063 ft-lbs
Make-up Torque = 11,504 ft-lbs
P1 = 634,795 lbs
T1 = 19,174 ft-lbs
T2 = 20,062 ft-lbs
T3 = 10,722 ft-lbs
Question:
What is yield torque if back-reaming pull is 300,000 lbs?
{TDH = 15,648 ft-lbs}
CAUTION: If a back-reaming pull of 300,000 lbs has a torque
exceeding make-up torque (11,054 ft-lbs), the chance of pin
failure increases as you approach PT3T2. Always use a safety
factor.
A.10.7 CAUTION: The loads considered in this simplified
approach are torsion and tension. These curves are approximations that do not consider the effects of internal pressure or
bending. For this reason, the answers from these curves
should be derated. A safety factor of one was used.
03
16
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
A.11 Drill Collar Bending Strength Ratio
The bending strength ratios in Figures 26 through 32 were
determined by application of Equation A.27. The effect of
stress-relief features was disregarded.
Z
BSR = ----BZP
( OD – b )
0.098 -------------------------OD
= ----------------------------------------4
4
( R – ID )
0.098 -----------------------R
4
4
(A.27)
03
4
4
OD – b
--------------------OD
= ---------------------------------,
4
4
R – ID
-------------------R
03
where
BSR
ZB
ZP
OD
ID
b
bending strength ratio,
box section modulus, cu. in.,
pin section modulus, cu. in.,
outside diameter of pin and box (Figure A-4), in.,
inside diameter or bore (Figure A-4), in.,
thread root diameter of box threads at end of pin
(Figure A-4), in.,
R = thread root diameter of pin threads 3/4 inch from
shoulder of pin (Figure A-4), in.
To use Equation A.27, first calculate:
Dedendum, b, and R
(A.28)
tpr ( L pc – 0.625 )
b = C – -------------------------------------- + ( 2 × dedendum ) (A.29)
12
where
C = pitch diameter at gauge point, in.,
tpr = taper, in./ft.
An example of the use of Equation A.27 in determining the
bending strength of a typical drill collar connection is as follows:
Determine the bending strength ratio of drill collar NC4662 (61/4 OD x 213/16) ID connection.
D = 6.25 (Specification 7, Table 13, Column 2),
d = 213/16 = 2.8125 (Specification 7, Table 13, Column 3),
C = 4.626 (Specification 7, Table 25, Column 5),
Taper = 2 (Specification 7, Table 25, Column 4),
Lpc = 4.5 (Specification 7, Table 25, Column 9),
H = 0.216005 (Specification 7, Table 26, Column 3),
frn = 0.038000 (Specification 7, Table 26, Column 5).
H
.216005
Dedendum = ---- – frn = ------------------- – .038000 = .0700025
2
2
tpr ( L pc – 0.625 )
b = C – -------------------------------------- + (2 × dedendum)
12
03
2 ( 4.5 – .625 )
b = 4.626 – ------------------------------- + (2 × .0700025)
12
b = 4.120,
R = C – (2 x dedendum) – (tpr × 1/8 × 1/12)
R = 4.626 – (2 x .0700025) – (2 × 1/8 × 1/12)
R = 4.465.
Substituting these values in Equation A.27 determines the
bending strength ratio as follows:
where
H = thread height not truncated, in.,
frn = root truncation, in.
00
(A.30)
First calculate dedendum, b, and R
=
=
=
=
=
=
H
Dedendum = ---- – frn,
2
R = C – (2 x dedendum) – (tpr x 1/8 x 1/12)
4
4
OD – b
BSR (NC46-62) = --------------------OD
-------------------4
4
R – ID
-------------------R
03
( 6.25 ) – ( 4.120 )
------------------------------------------6.25
------------------------------------------------4
=
4
( 4.465 ) – ( 2.8125 )
------------------------------------------------4.465
4
= 2.64:1
4
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
 Approximate Adjusted +
Approximate Weight
 Weight of Drill Pipe × 29.4
of Tool Joint 
----------------------------------------------------------------------------------------------------------------------------------------Tool Joint Adjusted Length + 29.4
Pin length, LPC
Box
5/
8
1/
8
,
(A.31)
Pin
3/
4
D
C
R
17
b
d
where
Approximate Adjusted Weight of Drill Pipe, lb/ft =
Upset Weight
Plain End Weight + --------------------------------29.4
Figure A-4—Rotary Shouldered Connection Location
of Dimensions for Bending Strength
Ratio Calculations
A.12 Torsional Yield Strength of Kelly
Drive Section
The torsional yield strength of the kelly drive section values listed in Tables 15 and 17 were derived from the following equation:
Approximate Weight of Tool Joint, lbs =
0.222 L(D2 – d2) + 0.167 (D3 – DTE3) – 0.501 d2(D – DTE)
(A.33)
00
Dimensions for L, D, d, and DTE are in API Specification 7,
Figure 6 and Table 7.
Adjusted Length of Tool Joint, ft =
3
where
Ym = tensile yield, psi,
a = distance across flats, in.,
b = kelly bore, in.
98
Plain end weight and upset weight are found in API Specification 5D.
0.577Y m [ 0.200 ( a – b ) ]
-,
Y = ---------------------------------------------------------12
3
(A.32)
L + 2.253 ( D – D TE )
-----------------------------------------------12
(A.34)
A.15 Critical Buckling Force for Curved
Boreholes27,29,30,31,32
A.13 Bending Strength, Kelly Drive
Section
The yield in bending values of the kelly drive section listed
in Tables 15 and 17 were determined by one of the following
equations:
A.15.1 The following equations define the range of hole
curvatures that buckle pipe in a three dimensionally curved
borehole. The pipe buckles whenever the hole curvature is
between the minimum and maximum curvatures defined by
the equations.
4×E×I
if F b < ---------------------------- pipe not buckled,
12 × h c × R L
a. Yield in bending through corners of the square drive section, YBC, ft-lb:
4×E×I
if F b ≥ ---------------------------- ,
12 × h c × R L
Y m ( 0.118 a – 0.069 b )
Y BC = -------------------------------------------------------12a
4
4
12 × h c × Fb
W eq = ---------------------------,
4×E×I
2
b. Yield in bending through the faces of the hexagonal drive
section YBF, ft-lb:
F 2 1⁄2
– 5730
2
B Vmin = ---------------  Weq –  -----b  + W m × sin θ ,


Fb
R L 
Y m ( 0.104 a – 0.085 b )
Y BF = -------------------------------------------------------12a
4
4
A.14 Approximate Weight of Tool Joint
Plus Drill Pipe
Approximate Weight of Tool Joint Plus Drill Pipe
Assembly, lb/ft =
F 2 1⁄2
5730
2
B Vmax = ------------  Weq –  -----b  – W m × sin θ ,
 R L 
Fb 
where
Fb = critical buckling force (+ compressive) (lb),
BVmin = minimum vertical curvature rate to cause buckling (+ building, – dropping) (°/100 ft),
98
18
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
BVmax = maximum vertical curvature rate that buckles
pipe (+ building, – dropping) (°/100 ft),
Weq = equivalent pipe weight required to buckle pipe
at Fb axial load,
E = 29.6 x 106 psi,
0.7854 ( OD – ID )
I = ----------------------------------------------- ,
16
4
4
65.5 – MW
Wm = W a  -------------------------- buoyant weight of pipe (lb/ft),
 65.5 
Wa = actual weight in air (lb/ft),
MW = mud density (lb/gal),
D H – TJOD
- radial clearance of tool joint to
hc =  --------------------------

2
hole (in.),
DH = diameter of hole (in.),
TJOD = OD tool joints (in.),
BL =
2
2
BT – B V lateral curvature rate (°/100 ft),
BT = total curvature rate (°/100 ft),
5730
RL = ------------ lateral build radius (ft),
BL
θ = inclination angle (deg).
98
A.15.2 If the hole curvature is limited to the vertical plane,
the buckling equations simplify to the following:
12 × h c × Fb
-,
W eq = --------------------------4×E×I
2
– 5730 × ( Weq + W m × sin θ )
B Vmin = ----------------------------------------------------------------,
Fb
B Vmax
5730 × ( Weq – W m × sin θ )
= ------------------------------------------------------------- ,
Fb
where
BVmin = minimum vertical curvature rate for buckling
(+ building, – dropping) (°/100 ft),
BVmax = maximum vertical curvature rate for buckling
(+ building, – dropping) (°/100 ft),
Fb = buckling force (lb),
E = 29.6 x 106 (psi),
π
4
4
I = ------ ( OD – ID ) ,
64
Weq = buoyant weight equivalent for pipe in curved
borehole (lb/ft),
65.5 – MW
Wm = W a  -------------------------- buoyant weight of pipe (lb/ft),
 65.5 
Wa = actual weight of pipe in air (lb/ft),
MW = mud density (lb/gal),
DH – TJOD
hc =  ------------------------------ radial clearance of tool joint to


2
hole (in.),
DH = diameter of hole (in.),
TJOD = OD of tool joint (in.),
θ = inclination angle (deg).
A.15.3 Figures A-5 and A-6 show the effect of hole curvature on the buckling force for 5-inch and 31⁄2-inch drillpipe.
Figure A-7 shows the effect of lateral curvatures on the buckling force of 5-inch drillpipe. For lateral and upward curvatures, the critical buckling force increases with the total
curvature rate.
A.16 Bending Stresses on Compressively
Loaded Drillpipe in Curved
Boreholes33,34
A.16.1 The type of loading can be determined by comparing
the actual hole curvature to calculated values of the critical curvatures that define the transition from no pipe body contact to
point contact and from point contact to wrap contact. The two
critical curvatures are computed from the following equations.
57.3 × 100 × 12 × ∆D
B c = -------------------------------------------------------------------- ,
57.3 × L
L
J × L tan  ------------------- – ---------- 4×J  4×J
where
Bc = the critical hole curvature that defines the transition from no pipe body contact to point contact (°/100 ft),
∆D = (TJOD – OD),
TJOD = tool joint OD (in.),
OD = pipe body OD (in.),
E × I 1⁄2
J =  -----------
(in.),
 F 
L = length of one joint of pipe (in.),
E = Young’s modulus 30 x 106 for steel (psi),
I = moment of inertia of pipe body (in.)
π ( OD – ID )
= --------------------------------- ,
64
F = axial compressive load on pipe (lb),
ID = pipe body ID (in.).
4
4
57.3 × 100 × 12 × ∆D
B w = --------------------------------------------------------------------------------------------------------- ,
4J
L
2
J × L ----- + ----------------------------------------- – --------------------------L
57.3L
2  57.3L
4J × tan -------------- tan  --------------
 4J 
 4J 
where
Bw = the critical curvature that defines the transition
from point contact to wrap contact (°/100 ft),
98
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
19
5-in. 19.5 lb/ft Drill Pipe, 6.375 in Tool Joint
10 ppg mud, 90 deg 8.5 in hole
100
90
80
70
Critical buckling force—1000 lbs.
Pipe is
buckled
60
50
98
Not buckled
Pipe on high
side of hole
40
30
Not buckled
Pipe on low
side of hole
20
10
0
-10
-5
0
Vertical build rate—°/100 ft.
Figure A-5—Buckling Force vs Hole Curvature
5
10
20
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
3.5-in. 13.3 lb/ft Drill Pipe, 4.75 in Tool Joint
10 ppg mud, 90 deg 6.0 in hole
100
90
80
70
98
Critical buckling force—1000 lbs.
Pipe is
buckled
60
50
40
Not buckled
Pipe on high
side of hole
30
Not buckled
Pipe on low
side of hole
20
10
0
-10
-5
0
Vertical build rate—°/100 ft.
Figure A-6—Buckling Force vs Hole Curvature
5
10
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
21
5-in. 19.5 lb/ft Drill Pipe, 6.375 in Tool Joint
10 ppg mud, 90 deg 8.5 in hole
100
90
110
TFA
130
T FA
150 T
FA
TFA
90
FA
60
T
0T
FA
80
60
50
98
40
170 TFA
Critical buckling force—1000 lbs.
70
30
20
180 T
FA
10
0
0
2
4
6
Total curvature rate—°/100 ft.
Figure A-7—Buckling Force vs Hole Curvature
8
10
22
API RECOMMENDED PRACTICE 7G—ADDENDUM 1
∆D = (TJOD – OD),
TJOD = tool joint OD (in.),
OD = pipe body OD (in.),
L = length of one joint of drillpipe for point contact
of pipe body (in.),
L = Le for wrap contact (in.),
2 U
4 × R × ∆D
4
- sin U – ---- × sin  ---- ,
A =  1 + -------------------------2


 2
U
L
E × I 1⁄2
J =  -----------
(in.),
 F 
L = length of one joint of pipe (in.),
E = Young’s modulus 30 x 106 for steel (psi),
I = moment of inertia of pipe (in.4)
π ( OD – ID )
= --------------------------------- ,
64
F = axial compressive load on pipe (lb),
ID = pipe body ID (in.).
4
B × OD × F × J × L
S b = ---------------------------------------------------------------------------------------- ,
57.3L
57.3 × 100 × 12 × 4 × I × sin  --------------
 2J 
where
Sb = maximum bending stress (psi),
B = hole curvature,
F = axial compressive load on pipe (lb),
E × I 1⁄2
J =  -----------
(in.),
 F 
E = Young’s modulus 30 x 106 for steel (psi),
I = moment of inertia (in.)
π ( OD – ID )
= --------------------------------- ,
64
OD = pipe body OD (in.),
ID = pipe body ID (in.).
L = length of one joint of pipe (in.),
4
E × I 1⁄2
J =  -----------
(in.),
 F 
π
4
4
I = ------ ( OD – ID ) (in.4),
64
∆D = diameter difference tool joint minus pipe body
OD,
∆D = (TJOD – OD) (in.),
TJOD = tool joint OD (in.),
R = 57.3 x 100 x 12B,
B = hole curvature (°/100 ft.).
A.16.4 If the hole curvature exceeds the critical curvature
that separates point contact from wrap contact, we need to
first compute an effective pipe length in order to calculate the
maximum bending stress. The effective pipe span length is
calculated from the following equation by trial and error until
the calculated curvature matches the actual hole curvature:
57.3 × 100 × 12 × ∆D
B = -------------------------------------------------------------------------------------------------------------- ,
Le
4J
2
J × L e ----- + ------------------------------------------ – ----------------------------Le
57.3L
57.3L
2
4J × tan  ---------------e tan  ---------------e
 4J 
 4J 
4
A.16.3 If the hole curvature is between the two critical curvatures calculated, the pipe will have center body point contact and the maximum bending stress is given by the
following equation:
E × OD × U
A × sin θ + B × cos θ
S b = ------------------------------- -------------------------------------------------------- ,
4R
2 U
U × sin U – 4 × sin  ----
 2
2
where
E = Young’s modulus, 29.6 x 106 for steel (psi),
OD = pipe body OD (in.),
ID = pipe body ID (in.),
L
U = ----- ,
2J
A
θ = arc tan  --- ,
 B
4
A.16.2 If the hole curvature is less than the critical curvature required to begin point contact, the maximum bending
stress is given by the following:
98
sin U
4 × R × ∆D 2  U
- sin ---- ,
B = 2 1 – ------------ –  1 + -------------------------2

 2
U 
L
where
Le = effective span length (in.),
B = hole curvature (°/100 ft.),
∆D = diameter difference between tool joint and pipe
body,
∆D = TJOD – OD (in.),
TJOD = tool joint OD (in.),
OD = pipe body OD (in.),
ID = pipe body ID (in.).
E × I 1⁄2
J =  -----------
(in.),
 F 
E = Young’s modulus 29.6 x 106 for steel (psi),
π
4
4
I = ------ ( OD – ID ) ,
64
F = axial compressive load (lb),
Lw = length of pipe body touching hole (in.),
Lw = L – Le,
L = length of one joint of pipe (in.).
98
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
A.16.5 The maximum bending stresses can then be computed using the equation for point contact and a pipe body
length equal to the effective span length.
98
A.16.6 One of our major concerns when drilling with compressively loaded drillpipe is the magnitude of the lateral contact forces between the tool joints and the wall of the hole and
the pipe body and the wall of the hole. Various authors have
suggested operating limits in the range of two to three thousand pounds or more for tool joint contact faces. There are no
generally accepted operating limits for compressively loaded
pipe body contact forces. For loading conditions in which
there is no pipe body contact, the lateral force on the tool
joints is given by:
F×L×B
LF TJ = ------------------------------------- ,
57.3 × 100 × 12
where
FTJ = lateral force on tool joint (lb),
L = length of one joint of pipe (in.),
B = hole curvature (°/100 ft.).
A.16.7 For loading conditions with point or wrap contact,
the following equations give the contact forces for the tool
joint and the pipe body:
23
4 2 U
× ∆D
 1 – 4R
-------------------- sin U – ---- sin  ----
2


 2
U
Le
2×E×I×U
- ,
= --------------------------------- ----------------------------------------------------------------------------R × Le
4 2  U
sin U – ---- sin --- 2
U
2
LF TJ
where
F×L
LFpipe = ------------- – LF tj
R
LFtj = lateral force on tool joint (lb),
LFpipe = lateral force on pipe body (lb),
Lw = L – Le,
Lw = length of pipe for wrap contact (in.),
Le = L for point contact (in.),
Le = effective span length for wrap contact,
57.3 × 100 × 12
R = ------------------------------------B
B = hole curvature (°/100 ft.),
L
U = -----e
2J
E × I 1⁄2
J =  -----------
(in.),
 F 
∆D = diameter difference tool joint minus pipe OD (in.),
∆D = TJOD – OD (in.),
π
4
4
I = ------ ( OD – ID ) .
64
98
00
98
03
98
03
00
03
00
03
00
Taper
Pitch
Diameter
C
1.063000
1.265000
1.391000
1.609000
2.355000
2.668000
3.183000
3.531000
3.808000
4.072000
4.417000
4.626000
5.041700
5.616000
6.178000
7.053000
7.741000
6.189000
7.251000
1.154000
1.541000
2.365370
2.740370
3.239870
4.364870
5.234020
5.757800
6.714530
7.666580
3.365400
3.734000
4.532000
5.591000
6.519600
2.578000
Connection
Type
NC10
NC12
NC13
NC16
NC23
NC26
NC31
NC35
NC38
NC40
NC44
NC46
NC50
NC56
NC61
NC70
NC77
51/2 IF
65/8 IF
1 REG
11/2 REG
23/8 REG
27/8 REG
31/2 REG
41/2 REG
51/2 REG
65/8 REG
75/8 REG
85/8 REG
27/8 FH
31/2 FH
41/2 FH
51/2 FH
65/8 FH
23/8 SL-H90
1.500000
1.500000
1.500000
1.500000
2.000000
2.000000
2.000000
2.000000
2.000000
2.000000
2.000000
2.000000
2.000000
3.000000
3.000000
3.000000
3.000000
2.000000
2.000000
1.500000
1.500000
3.000000
3.000000
3.000000
3.000000
3.000000
2.000000
3.000000
3.000000
3.000000
3.000000
3.000000
2.000000
2.000000
1.250000
(3)
(2)
(1)
1.500000
1.750000
1.750000
1.750000
3.000000
3.000000
3.500000
3.750000
4.000000
4.500000
4.500000
4.500000
4.500000
5.000000
5.500000
6.000000
6.500000
5.000000
5.000000
1.500000
2.000000
3.000000
3.500000
3.750000
4.250000
4.750000
5.000000
5.250000
5.375000
3.500000
3.750000
4.000000
5.000000
5.000000
2.812500
Pin
Length
(4)
0.144100
0.144100
0.144100
0.144100
0.216005
0.216005
0.216005
0.216005
0.216005
0.216005
0.216005
0.216005
0.216005
0.215379
0.215379
0.215379
0.215379
0.216005
0.216005
1.441000
1.441000
0.172303
0.172303
0.172303
0.172303
0.215379
0.216005
0.215379
0.215379
0.172303
0.172303
0.172303
0.216005
0.216005
0.166215
Thread
Height Not
Truncated
(5)
0.040600
0.040600
0.040600
0.040600
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.040600
0.040600
0.020000
0.020000
0.020000
0.020000
0.025000
0.025000
0.025000
0.025000
0.020000
0.020000
0.020000
0.025000
0.025000
0.034107
Root
Truncation
(6)
1.204000
1.406000
1.532000
1.751000
2.625000
2.937500
3.453125
3.812500
4.078125
4.343750
4.687500
4.906250
5.312500
5.937500
6.500000
7.375000
8.062500
6.453125
7.515625
1.301000
1.688000
2.687500
3.062500
3.562500
4.687500
5.578125
6.062500
7.093750
8.046875
3.687500
4.046875
4.875000
5.906250
6.843750.
2.765625
Nominal
Counterbore
(7)
.166667
.166667
.166667
.166667
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
1.66667
1.66667
.200000
.200000
.200000
.200000
.250000
.250000
.250000
.250000
.200000
.200000
.200000
.250000
.250000
.333333
Thread
Pitch
(8)
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
45
Thread
Angle
θ
(9)
—
—
—
—
2.140625
2.375000
2.890625
3.231000
3.508000
3.772000
4.117000
4.326000
4.742000
5.277000
5.839000
6.714000
7.402000
5.890625
6.953125
—
—
2.015625
2.390625
2.906250
4.013000
4.869000
5.417000
6.349000
7.301000
—
3.421875
4.180000
5.250000
6.171875
2.328125
Stress Relief
Groove
Diameter
(10)
Table A-1—Rotary Shouldered Connection Thread Element Information
—
—
—
—
2.218750
2.531250
2.953125
3.234375
3.468750
3.656250
4.000000
4.203125
4.625000
4.796875
5.234375
5.984375
6.546875
5.687500
6.750000
—
—
2.062500
2.312500
2.718750
3.718750
4.500000
5.281250
5.859375
6.781250
—
3.218750
3.953125
5.109375
6.046875
2.531250
Bore-Back
Cylinder
Diameter
(11)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
7.750000
9.000000
—
—
—
—
—
—
Low
Torque
Counterbore
(12)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9.250000
10.500000
—
—
—
—
—
—
Low
Torque Bevel
Diameter
(13)
24
API RECOMMENDED PRACTICE 7G
3.049000
3.688000
3.929860
4.303600
4.637600
4.908100
5.178600
5.803600
6.252300
7.141100
8.016100
2.203000
2.369000
2.884000
2.230000
2.668000
3.183000
3.604000
3.808000
3.119000
3.604000
5.041700
2.588000
2.588000
2.984000
2.984000
3.728000
3.728000
4.416000
4.416000
4.752000
4.752000
2.605000
3.121000
3.808000
4.626000
5.041700
27/8 SL-H90
31/2 SL-H90
31/2 H-90
4 H-90
41/2 H-90
5 H-90
51/2 H-90
65/8 H-90
7 H-90
75/8 H-90
85/8 H-90
23/8 PAC
27/8 PAC
31/2 PAC
23/8 SH
27/8 SH
31/2 SH
4 SH
1
00 4 /2 SH
27/8 XH
31/2 XH
00 5 XH
23/8 OH SW
23/8 OH LW
27/8 OH SW
27/8 OH LW
31/2 OH SW
31/2 OH LW
4 OH SW
4 OH LW
41/2 OH SW
41/2 OH LW
23/8 WO
27/8 WO
31/2 WO
4 WO
41/2 WO
1.250000
1.250000
2.000000
2.000000
2.000000
2.000000
2.000000
2.000000
3.000000
3.000000
3.000000
1.500000
1.500000
1.500000
2.000000
2.000000
2.000000
2.000000
2.000000
2.000000
2.000000
2.000000
1.500000
1.500000
1.500000
1.500000
1.500000
1.500000
1.500000
1.500000
1.500000
1.500000
2.000000
2.000000
2.000000
2.000000
2.000000
Taper
Connection
Type
03
(3)
(2)
Pitch
Diameter
C
(1)
2.937500
3.187500
4.000000
4.250000
4.500000
4.750000
4.750000
5.000000
5.500000
6.125000
6.625000
2.375000
2.375000
3.250000
2.875000
3.000000
3.500000
3.500000
4.000000
4.000000
3.500000
4.500000
2.375000
2.375000
2.875000
2.500000
3.250000
3.250000
4.000000
3.500000
3.750000
3.750000
2.375000
3.000000
3.500000
4.500000
4.500000
Pin
Length
(4)
0.166215
0.166215
0.141865
0.141865
0.141865
0.141865
0.141865
0.141865
0.140625
0.140625
0.140625
0.216224
0.216224
0.216224
0.216005
0.216005
0.216005
0.216005
0.216005
0.216005
0.216005
0.216005
0.216224
0.216224
0.216224
0.216224
0.216224
0.216224
0.216224
0.216224
0.216224
0.216224
0.216005
0.216005
0.216005
0.216005
0.216005
Thread
Height Not
Truncated
(5)
0.034107
0.034107
0.017042
0.017042
0.017042
0.017042
0.017042
0.017042
0.016733
0.016733
0.016733
0.057948
0.057948
0.057948
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.038000
0.057948
0.057948
0.057948
0.057948
0.057948
0.057948
0.057948
0.057948
0.057948
0.057948
0.038000
0.038000
0.038000
0.038000
0.038000
Root
Truncation
(6)
3.234375
3.875000
4.187500
4.562500
4.890625
5.171875
5.437500
6.062500
6.562500
7.453125
8.328125
2.406250
2.578125
3.109375
2.500000
2.937500
3.453125
3.875000
4.078125
3.359375
3.875000
5.312500
2.796875
2.796875
3.203125
3.203125
3.953125
3.953125
4.640625
4.640625
4.953125
4.953125
2.859375
3.375000
4.078125
4.906250
5.312500
Nominal
Counterbore
(7)
.333333
.333333
.285710
.285710
.285710
.285710
.285710
.285710
.285710
.285710
.285710
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
.250000
Thread
Pitch
(8)
45
45
45
45
45
45
45
45
45
45
45
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
Thread
Angle
θ
(9)
2.671875
3.312500
3.656250
4.031250
4.359375
4.625000
4.906250
5.531250
6.031250
6.906250
7.781250
1.984375
2.156250
—
1.937500
2.375000
2.890625
3.312500
3.508000
2.828125
3.312500
4.742000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Stress Relief
Groove
Diameter
(10)
Table A-1—Rotary Shouldered Connection Thread Element Information
(11)
2.984375
3.593750
3.562500
3.875000
4.187500
4.406250
4.687500
5.265625
5.265625
6.000000
6.750000
2.171875
2.343750
—
2.093750
2.531250
2.953125
3.375000
3.468750
2.781250
3.375000
4.625000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Bore-Back
Cylinder
Diameter
(12)
—
—
—
—
—
—
—
—
7.125000
8.000000
9.375000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Low
Torque
Counterbore
(13)
—
—
—
—
—
—
—
—
8.250000
9.250000
10.500000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Low
Torque Bevel
Diameter
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
25
11/03
Additional copies available through Global Engineering
Documents at (800) 854-7179 or (303) 397-7956
Information about API Publications, Programs and Services is
available on the World Wide Web at: http://www.api.org
Product No. G07GA1