Lyons W.C. (ed.). Standard handbook of petroleum and natural gas engineering.2001- Volume 1

Tubing and Tubing String Design

1245

(contlnued)

12

13 14 15 16 17 18 19

20

-

7,540

8,100

- -

122,000

-

9,630 149,100 194,300

-

178,600

-

- -

10,040 9,680 9,630

-

11,360 10,840

-

- -

14860 14.060 14,060 9,990 231,000 276,100

-

7,870

8,640

-

130,100

-

- -

10,650

10.160 10,160

10,160

169,100

207,200

-

- -

12.120

11,660

-

185.100

-

16,SlO 16,000 15,000 10,660 246,400 294,600

- -

13.060

18,846

18,340

13,340

208.900

272,000

-

- -

20,090

19,690 19.680

13,990

823,400 386,600

-

6,690

7,910

-

114,000

-

8,800

9,170

- -

246,100

-

~ ~~ ~ ~~

-

4,600

4,220

-

104,400 114,OOO

-

6,720

6,800

5,800

-

143,600 198,000

-

7300

7,900

7.900

-

196,700

270,000

-

7mO

8,430 8,430

-

208,700

zeS.000

-

1246

Drilling and Well Completions

(text

continued

from

page

1239)

a. Familiarize her or himself with inspection practices specified in the

standards and employed by the respective mills and with the definition

of “injurious defect” contained in the standards.

b. Thoroughly evaluate any nondestructive inspection to be used by him

or her on API tubular goods to ensure that the inspection does in fact

correctly locate and differentiate injurious defects from other variables

that can be and frequently are sources of misleading “defect” signals with

such inspection methods.

Caution:

Due to the permissible tolerance on the outside diameter imme-

diately behind the tubing upset, the user is cautioned that difficulties may

occur when wraparound seal-type hangers are installed on tubing manufac-

tured on the high side of the tolerance; therefore, it is recommended that

the user select the joint of tubing to be installed at the top of the string.

2.

All tubing, whether new, used or reconditioned, should always be handled

with thread protectors in place. Tubing should be handled at all times on

racks or on wooden or metal surfaces free of rocks, sand or dirt other

than normal drilling mud. When lengths of tubing are inadvertently

dragged in the dirt, the threads should be recleaned.

a. Before running in the hole for the first time, tubing should be drifted

with an API drift mandrel to ensure passage of pumps, swabs and packers.

b. Elevators should be in good repair and should have links of equal length.

c. Slip-type elevators are recommended when running special clearance

d. Elevators should be examined to note if latch fitting is complete.

e. Spider slips that will not crush the tubing should be used. Slips should

Note:

Slip and tong marks are injurious. Every possible effort should be made

to keep such damage at a minimum by using proper up-todate equipment.

f.

Tubing tongs that will not crush the tubing should be used on the body

of the tubing and should fit properly to avoid unnecessary cutting

of

the pipe wall. Tong dies should fit properly and conform to the curvature

of the tubing. The use of pipe wrenches is not recommended.

g.

The following precautions should be taken in the preparation of tubing

threads:

1.

Immediately before running, remove protectors from both field end

and coupling end and clean threads thoroughly, repeating as additional

rows become uncovered.

2.

Carefully inspect the threads. Those found damaged, even slightly,

should be laid aside unless satisfactory means are available for correcting

thread damage.

3.

The length of each piece

of

tubing should be measured prior to

running. A steel tape calibrated in decimal feet to the nearest

0.01

ft

should be used. The measurement should be made from the outermost

face of the coupling or box to the position on the externally threaded

end where the coupling or the box stops when the joint is made up

powertight. The total of the individual length

so

measured will represent

the unloaded length of the tubing string.

4.

Place clean protectors on the field end of the pipe

so

that the thread

will not be damaged while rolling the pipe onto the rack and pulling it

into the derrick.

5.

Check each coupling for makeup. If the stand off is abnormally great,

check the coupling for tightness. Loose couplings should be removed,

couplings, especially those beveled on the lower end.

be examined before using to see that they are working together.

Tubing and Tubing String Design

1247

the threads thoroughly cleaned and fresh compound should be applied

over the entire thread surfaces. Then the coupling should be replaced

and tightened before pulling the tubing into the derrick.

6. Before stabbing, liberally apply thread compound to the entire

internally and externally threaded areas. It is recommended that high-

pressure, modified thread compound as specified in API Bulletin

5A2:

“Bulletin on Thread Compounds” be used except in special cases where

severe conditions are encountered. In these special cases it is recom-

mended that high-pressure silicone thread compound as specified in

Bulletin

5A2

be used.

h.

For

high-pressure or condensate wells, additional precautions to insure

tight joints should be taken as follows:

1.

Couplings should be removed and both the mill-end pipe thread and

coupling thread thoroughly cleaned and inspected. To facilitate this

operation, tubing may be ordered with couplings handling tight, which

is approximately one turn beyond hand tight,

or

may be ordered with

the couplings shipped separately.

2.

Thread compound should be applied to both the external and internal

threads, and the coupling should be reapplied handling tight. Field-end

threads and the mating coupling threads should have thread compounds

applied just before stabbing.

Stabbing, Making Up and Lowering

1.

Do not remove thread protector fmm field end of tubing until ready to stab.

2.

If necessary, apply thread compound over entire surface of threads just

before stabbing.

3.

In stabbing, lower tubing carefully to avoid injuring threads. Stab vertically,

preferably with the assistance of someone on a stabbing board. If the tubing

tilts to one side after stabbing, lift up, clean and correct any damaged

thread with a three-cornered file, then carefully remove any filings and

reapply compound over thread surface. Intermediate supports may be

placed in the derrick to limit bowing of the tubing.

4. After stabbing, start screwing the pipe together by hand or apply regular

or power tubing tongs slowly. To prevent galling when making up connec-

tions in the field, the connections should be made up to a speed not to

exceed

25

rpm. Power tubing tongs are recommended for high-pressure or

condensate wells to ensure uniform makeup and tight joints. Joints should

be made up tight, approximately two turns beyond the hand-tight position,

with care being taken not to gall the threads.

Field Makeup

1.

Joint life of tubing under repeated field makeup is inversely proportional

to the field makeup torque applied. Therefore, in wells where leak resis-

tance is not a great factor, minimum field makeup torque values should

be used to prolong joint life. Table 4-168 contains recommended optimum

makeup torque values for nonupset, external upset, and integral joint

tubing, based on 1% of the calculated joint pullout strength determined

from the joint pull-out strength formula for eight-round thread casing in

Bulletin

5C3.

Minimum torque values listed are

75%

of optimum values,

and maximum torque values listed are

125%

of optimum values.

All

values

are rounded to the nearest 10 ft-lb. The torque values listed in Table 4-168

1248

Drilling and Well Completions

Table

4-168

Recommended Tubing Makeup Torque

1

23 4 6 6 7

8

9 10 11 12 18 14

Na4h.I

wd.ht

To-.

it-lb

81":

Ibmrrt.

oaldlk

in.

In&

Joint

.--

NOn-Uprt

U*

D-

'

Tbdmd

c-mnr

'YE?'

ad

I

g%i

uprt

Opb

Mln.

Mu.

0r.t

We

Mu.

Opt.

Yln.

Max.

1.050 1.14 110

-

H-40

140 110 180 460 360 680

-

1.14 110

-

5-66

180 140 230 600 460 760

-

1.14 1.20

-

C76 230 170 290 780

690

980

-

1.14 1.20

-

LBO

240

180

300 810 610 1010

-

1.14 110

-

N-80 260 190 310 830 620 1040

-

1.316 1.70

1.70

1.660

-

230

2.80

2.30

-

1.80 1.72

H-IO

1.80

1.72

5-65

1.80 1.12

C75

1.80 1.72

L-80

1.30

1.72 N-80

-

2.10

H-40

2.40

2.38

H-40

-

2.10

5-66

2.40

2.38

5-65

2.40

2.33 C76

2.40 2.53 L-80

2.40

2.33 N-80

210

270

360

370

880

-

270

360

460

470

490

-

160

200

270

280

290

-

200

260

a60

350

370

-

260

340

460

480

-

340

-

440

680

690

610

440

670

740

760

790

-

630

690

910

940

960

-

330

430

660

670

690

-

400

620

680

710

720

-

660

710

930

960

990

-

660

860

1140

1180

1200

-

310

400

620

540

660

380

500

660

670

690

-

230

300

390

400

410

280

880

490

600

620

390

600

650

680

690

480

6%'

680

810

850

860

1.900

-

2.40

HA0

- -

-

460

340

660

2.76 2.90 2.76

H-40

320 240 400 670 500

840

460 340 660

680

440

730

-

2.40

5-65

-

- -

-

2.76

2.90 2.76

5-66

410 310 510

880

660

1100 580

440 730

2.76

2.90 2.76

C-76

540

410

680

1160 860 1440 760

670 950

2.76

2.90 2.76

LBO

560

420

700 1190 890 1490

790

690

990

2.76

2.90 2.76

N-80

670

430

710 1220

920 1630

810

610 1010

apply only to tubing with zinc-plated couplings. When making up connec-

tions with tin-plated couplings,

80%

of the listed value can be used as a guide.

2.

Spider slips and elevators should be cleaned frequently, and slips should

be kept sharp.

3.

Finding bottom should be accomplished with extreme caution.

Do

not set

tubing down heavily.

Pulling Tublng

1.

A

caliper survey prior to pulling a worn string of tubing will provide a

quick means of segregating badly worn lengths for removal.

2.

Break-out tongs should be positioned close to the coupling. Hammering

the coupling to break the joint is an injurious practice.

3.

Great care should be exercised to disengage all of the thread before lifting

the tubing out of the coupling. Do not jump the tubing out of the coupling.

4.

Tubing stacked in the derrick should be set on a firm wooden platform

without the bottom thread protector since the design of most protectors is

not such as to support the joint or stand without damage to the field thread.

Tubing and Tubing String Design

1249

Table

4-1

68

(continued)

1 23 4 5 6 7 8 9 10

11

12 13 14

~~

2.063

-

3.25 H-40

-

- -

-

570 430 710

740 660 920

- -

3.25 C-75

- -

-

970 730 1210

--

3.26

L-80

-

1010 760 1260

-

3.25

N-80

-

1030

770 1290

-

3.25 J-55

-

2% 4.00

- -

H-40 470 360 590

-

4.60 4.70

-

E-40 660 420 700 990 740 1240

- -

-

4.00

-

5-65

610

460

760

-

4.60

4.70

-

J-55

730

560 910

1290

970

1610

-

4.00

-

C-75

800

600

1000

-

4.60

4.70

-

C-75

960

720

1200 1700 1280

2130

-

- -

5.80

5.95

-

C-75

1380 1040

1730 2120 1590

2650

-

- -

L-80 830 620 1040

-

- -

4.00

- -

4.60 4.70

-

L-80 990 740 1240 1760 1320 2200

-

5.80 5.95

-

L-80 1420 1070 1780 2190 1640 2740

-

- -

4.00

-

N-80

860

640

1060

-

4.60

4.70

-

N-80

1020 770 1280

1800

1350

2250

-

5.80

5.95

-

N-80

1460

1100

1830

2240

1680

2800

-

4.60

4.70

-

P-106

1280 960

1600

2270

1700

2840

-

5.80

5.95

-

P-105

1840 1380

2300 2830

2120

3540

-

2% 6.40 6.50

-

H-40

800 600

1000

1250 940 1560

-

6.40 6.50

-

5-55 1050 790 1310 1650 1240 2060

- -

-

6.40

6.60

-

C-75 I380 1040 1730

2170 1630

2710

-

- -

8.60

8.70

-

C-75

2090 1570

2610

2860

2140

3660

-

6.40

6.50

-

L-80

1430 1070 1790

2260

1690

2810

-

8.60

8.70

-

LBO

2160

1620 2700

2960

2210

3680

-

6.40

6.50

-

N-80

1470 1100

1840

2300

1730

2880

-

8.60

8.70

-

N-80

2210 1660

2760 3020

2270

3780

-

- -

6.40

6.50

-

P-106

1860 1390

2910

2180

3640

-

8.60

8.70

-

P-105

2190

2090

3490 3810

2860

4760

-

5.

Protect threads from dirt

or

injury when the tubing is out

of

the hole.

6.

Tubing set back in the derrick should be properly supported to prevent

undue bending. Tubing that is 24-in.

OD

and larger preferably should be

pulled in stands approximately

60

ft long

or

in doubles of range 2. Stands

of tubing 1.900-in.

OD

or

smaller and stands longer than

60

ft

should have

intermediate support.

Causes

of

Tubing Trouble

The more common causes of tubing troubles are as follows:

1.

Improper selection for strength and life required.

2.

Insufficient inspection of finished product at the mill and in the yard.

3.

Careless loading, unloading and cartage

4.

Damaged threads resulting

from

protectors loosening and falling

off.

5.

Lack of care in storage to give proper protection.

6.

Excessive hammering on couplings.

1250

Drilling and Well Completions

Table

4-1

68

(continued)

1

23 4

6

7

8 9 10 11 12 13 14

TO-

n&

Nominal Weight

Si-:

Ib.

mr

it.

Outside

I.-

Joint

r

-A-

Nan-Uprt

Diameter

'

Thm

snd

In-I

'

in.

cm.unp

Joint

Cdc

mt.

xin.

yu.

OPL

xin.

mu.

WL

mi-

x-

woo-

UP&

---

3%

7.70

- -

H-40

920 690 1150

-

9.20 9.30

-

H-40

1120 840 1400

1730

1% 2ZO

- -

-

10.20

-

H-40

1310 980 1640

- - -

-

- -

J-55

1210 910 1610

-----

7.70

-

9.20 9.30

-

J-55

1480 1110 1860 2280 1710

2850

-

10.20

- -

J-55

1720 1290 2160

-

- - - - -

7.70

- -

C-75

1600 1200

ZOO0

9.20

9.30

-

C-75

1950 1460 2440

3%0 2260

350

-

12.70

12.96

-

(3-76

3030 2270

3790

4&

3ZO

6060

-

7.70

-

LBO

1660

1250

2080

-

- -

9.20 9.30

-

LBO

2030 1520

2540

3130 2350 3910

- -

-

10.20

-

dB0 2360

1770

2950

-

---

12.70 12.95

-

L-80

3140 2360 3980 4200 3160

6ZO

-

N-80

1700

1280 2130

----

7.70

-

9.20

3.30

-

N-80

2070

1550 2590

3&

2z 4000

- - -

10.20

-

N-80 2410 1810

8010

-

---

12.70

12.95

-

N-80

3210 2410

4010 4290

SSO

6860

-

9.20

9.30

-

P-106 2620 1970

8280

4050

SO40

5060

-

12.70

12.96

-

P-105 4060

3060

6080 6430 4070

6790

-

---

10.20

- -

C-75

2270 1700 2840

---

4 9.50

-

H-40

940 710 1180

---

-

1100

-

H-40

- - -

1z lZ0 2zo

- -

-

9.60

-

J-66

1240 980 1650

- - -

-

- -

-

11.00

-

J-66

- - -

2660 1920 3200

- -

-

9.60

-

C-76

1640 1230 2060

-

11.00

-

C76

- -

-

3590

2640

4240

-

9.50

-

LBO

1710 1280 2140

- -

-

11.00

-

LSO

-

3530

2650 4410

- -

-

9.50

- -

N-80 1740 1810 2180

-

- - -

- -

3600 2700 4500

- -

-

11.00

-

N-80

-

4% 12.60 12.76

-

H-40

1820

990

1660 2160 1620 2700

- - -

12.60 12.75

-

J-65

1740 1310 2180 2860 2160 3680

-

12.60

12.76

-

C-75

2800 1730 2880 3780

2840

4780

-

- -

12.60 12.76

-

LBO

2400 1800

3000

3940 2960 4930

-

12.60 12.75

-

N-80

2440 1830 3060 4020 3020

5030

- - -

-

Soarm

Fmm

Rd

I1751.

7.

Use

of

worn-out and wrong types

of

handling equipment.

8.

Nonobservance

of

proper rules in running and pulling tubing.

9.

Coupling wear and rod cutting.

10.

Excessive sucker rod breakage.

11.

Fatigue that often causes failure at the last engaged thread. There is no

positive remedy, but using external upset tubing in place

of

nonupset

tubing greatly delays the start

of

this trouble.

12.

Replacement

of

worn couplings with non-API couplings.

13.

Dropping a string, even a short distance.

14.

Leaky joints, under external

or

internal pressure.

Tubing and Tubing String Design

1251

15.

Corrosion. Both the inside and outside of tubing can be damaged by corro-

sion. The damage is generally in the form of pitting, box wear, stresscorrosion

cracking, and sulfide stress cracking, but localized attack like corrosion-

erosion, ringworm and caliper tracks-can also occur. Since corrosion can

result from many causes and influences and can take different forms, no

simple and universal remedy can be given for control. Each problem must

be treated individually, and the solution must be attempted in light of

known factors and operating conditions.

a. Where internal or external tubing corrosion

is

known

to

exist and

corrosive fluids are being produced, the following measures can be

employed:

1.

In flowing wells the annulus can be packed off and the corrosive

fluid confined to the inside of the tubing. The inside of the tubing

can be protected with special liners, coatings or inhibitors. Under severe

conditions, special alloy steel or glass-reinforced plastics may be used.

Alloys do not eliminate corrosion. When

H,S

is present in the well

fluids, tubing of high-yield strength may be subject to sulfide corrosion

cracking. The concentration of

H,S

necessary to cause cracking in

different strength materials is not yet well defined. Literature on sulfide

corrosion or persons competent in this field should be consulted.

2.

In pumping and gas-lifting wells, inhibitors introduced via the casing-

tubing annulus afford appreciable protection.

In

this type of comple-

tion, especially in pumping wells, better operating practices can also

aid in extending the life of tubing; viz., through the use of rod

protectors, rotation of tubing and longer and slower pumping strokes.

b. To determine the value and effectiveness of the above practices and

measures, cost and equipment failure records can be compared before

and after application of control measures.

c. In general, all new areas should be considered as being potentially

corrosive, and investigations should be initiated early in the life of a

field, and repeated periodically,

to

detect and localize corrosion before

it has done destructive damage. Where conditions favorable to corro-

sion exist, a qualified corrosion engineer should be consulted.

Selection

of

Wall Thickness and Steel Grade of Tubing

Tubing design relies on the selection

of

the most economical steel grades and

wall thicknesses (unit weight of tubing) that will withstand, without failure, the

forces to which tubing will be exposed throughout the expected tubing life.

Tubing must be designed on:

collapse

burst

tension

possibility

of

permanent corkscrewing

Tubing string design is very much the same as for casing. For shallow and

moderately deep holes, uniform strings are preferable; however, in deep wells,

a tapered tubing can be desirable.

A

design factor (safety factor) for tension

should be about

1.6.

The collapse design factor must not be less than

1.0,

assuming an annulus filled up with fluid and tubing empty inside. The design

factor for burst should not be less than

1.1.

1252

Drilling and Well Completions

Tubing EiongationKontraction Due to the Effect

of

Changes in Pressure and Temperature

During the service life of a well, tubing can experience various combinations

of pressures and temperatures that result in tubing length changes. The four

basic effects to consider are as follows:

1.

piston effect

2. helical buckling effect

3.

ballooning and reverse ballooning effect

4.

temperature change effect

The tubing movement due to piston effect is

Tubing movement due to helical buckling is

rSFi

AL,=-

8EI(W,

+

Wi

-

W,)

where

x

I

=

-(oD~

-ID')

64

F,

=

(APi

-

AP,)A,

Note:

If F,

<

0,

AL2

=

0.

The tubing movement due to ballooning effect is

1+2vg

Api

-

R2Apo

-

L

2v

L2--

2v Api

-

R'Ap,

AL3

=

-1

E

R2

-

1

E

R2-1

The tubing movement due to change in temperature is

AL4

=

PLAT

Two approaches can be used to handle tubing movement:

1.

Provide seals of enough length.

2.

Slack off enough weight of tubing to prevent movement.

(4-333)

(4-33.4)

(4-335)

(4-336)

For

practical purposes a combination of the approaches mentioned above can

be applicable.

Tubing and Tubing String Design

1253

If slack off weight is applied, the tubing compensating movement is calculated

from

LF

r2Ff

AL5

=

L+

EA,

8EI(W,

+

Wi

-

W,)

(4-337)

Notations used in the above equations are

A,

=

area corresponding to tubing ID in in.'

A.

=

area corresponding to tubing

OD

in in.'

AP

=

area corresponding to packer bore in in.2

As

=

cross-sectional area of the tubing wall in in.2

F,

=

fictitious force in presence of no restraint in the packer in lb,

I

=

moment of inertia of tubing cross-section with respect to its diameter

L

=

length of tubing in in.

in in4

Pt,

Po

=

pressure inside and outside the tubing at the packer level respectively

AP,, APo

=

change in pressure inside and outside

of

tubing at the packer level

Ap,, Apo

=

change in pressure inside and outside

of

tubing at the surface in

in psi

psi

R

=

ratio OD/ID of the tubing

r

=

tubing and casing radial clearance in in.

Apl

=

change in density of liquid in the tubing in lbm/in.3

Ap

=

change in density of liquid in annulus in lbm/in.3

6

=

coefficient of thermal expansion of the tubing material (for steel,

Ws

=

average (i.e., including coupling) weight of tubing per unit length

Wl

=

weight of liquid in the tubing per unit length in lb/in.

W

=

weight of outside liquid displaced per unit length

AT

=

change in average tubing temperature in

"F

p

=

6.9

x

10-6/oF)

in Ib/in.

6

=

drop of pressure in the tubing due to flow per unit length in psi/in.

v

=

Poisson's ratio of the tubing material (for steel,

v

=

0.3)

E

=

Young's modulus (for steel,

E

=

30

X

lo6

psi)

Nomenclature used is as in the paper by

A.

Lubinski et al.

[171].

Example

1

Calculate the expected movement

of

tubing under conditions as specified

below. Initially both tubing and annulus are filled with a crude of

3O"API.

Thereafter, the crude

in

the tubing

is

replaced by

a

15-lb/gal cement slurry to

perform a squeeze cementing operation. While the squeeze cementing job is

performed, pressures p,

=

5,000

psi and p,

=

1,000

psi are applied at the surface

on the tubing and annulus respectively.

Tubing:

2%

in;

6.5

lb/ft

Casing:

7

in.;

32

lb/ft (r

=

1.61

in.)

A.

=

6.49

in.',

A,

=

4.68 in.2,

As

=

1.81 in.'

Ratio

of

OD/ID

of

tubing,

R

=

1.178

1254

Drilling and Well Completions

AP

=

8.30

in.5

Length of tubing

=

10,000

ft

(120,000

in.)

Average change in temperature:

-20°F

Pressure drop due to flow is disregarded

(6

=

0)

Solution

Pressure changes are the following. At the surface the pressures are Api

=

5,000

psi and Apo

=

1,000

psi. At the packer level,

Ni

=

9,000

psi and APo

=

1,000

psi.

Liquid density changes are Api

=

0.0332

psi/in. and Apo

=

0.0

psi/in. The unit

weight of tubing is

6.5 1.5x4.68 0.876~8.34~6.49

=0.641b/in.

12

23

1

23

1

w

=

w,

+

wi

-

w,

=

-+

The moment of inertia is

I

=

1.61

in.4 The tubing movement due to piston effect is

AL,

=-

120~000[(8.3-4.68)9,000-(8.3-6.49)1,000]

=

-68.0

in.

30 x

lo6

The tubing movement due to buckling effect is

(1.612)X(8.32)(9,000-

1,000)2

=

46.23

in.

AL2

=

8 x 30 x

lo6

x 1.61 x 0.64

The tubing movement due to ballooning effect is

The temperature effect is

AL4

=

-6.9

x

120,000

x

20

=

-16.56

in.

The total expected tubing movement is

AL6

=

AL,

+

AL2

+

AL3

+

AL4

=

-165.48

in.

Packer-To-Tubing Force

Certain types of packers permit no tubing motion in either direction. Depend-

ing upon operational conditions, a tubing can be landed either in compression

(slack off) or tension (pull up). Landing tubing in compression is desirable if

the expected tubing movement would produce tubing shortening while landing

in tension to compensate the expected tubing elongation.

Lyons W.C. (ed.). Standard handbook of petroleum and natural gas engineering.2001- Volume 1

Подождите немного. Документ загружается.