Wellhead Equipment and Flow Control Devices

Chapter 3

Wellhead Equipment and Flow Control Devices James H. Foster, Foster Oil Field Equipment John Beson, Foster Oil Field Equipment Co. W.G. Boyle, Otis Engineering Corp.**

Co.*

Introduction Wellhead equipment is a general term used to describe equipment attached to the top of the tubular goods used in a well-to support the tubular strings, provide seals between strings, and control production from the well. Since the American Petroleum Inst. (API) is an active organization set up to establish standards in sizes. grades, designs, dimensions, and quality, to provide safe interchangeable equipment for the industry, this section is conlined to equipment covered by API Spec. 6A for wellhead equipment. ’

Fig. 3.1 shows a typical wellhead assembly.

All manufacturers build safety factors into their product based on sound engineering and past experience, but stresses caused by vibration, impact loads, and temperature variations are impossible to predict. Equipment should never be subjected to pressures above the recommended working pressure. If, for any reason, the equipment is to be used at unusually high or extreme working pressure, manufacturers will insist that a disclaimer clause be written and properly worded to relieve them of legal responsibility. The disclaimer should state possible results that are expected because of equipment failure. Table 3.1 shows the standard API working pressure ratings and their respective body test pressures.

Working- and Test-Pressure Terminology

Thread Limitation

The maximum working pressure is the maximum operating pressure at which the equipment should be used. The hydrostatic test pressure is the static-body test pressure for ensuring a margin of safety above the rated working pressure. It is the test pressure imposed by the manufacturer to prove adequacy in design, materials, and workmanship of the body or shell member and should not be applied as a differential pressure across internal hanger-packer mechanisms or closure mechanisms. Occasionally wellhead equipment and valves are accidentally or purposely subjected to pressures in excess of design working pressures during high-pressure remedial work. Although the equipment often withstands the mistreatment, such practices should be avoided.

In view of the complex mechanics involved in sealing high-pressure threaded connections, it is recommended that field installations be adequately supervised and that API RP 5Cl be followed with regard to lubricants, makeup, etc., of API threads. ’ The working pressure of a properly assembled threaded connection joining a wellhead or flowline component and a tubular member often is determined by the rating of the tubular element. In such a case, the maximum working pressure rating of the connection is taken as the internal yield pressure at minimum yield as stipulated in API Bull. SC2 for the particular size and type of thread and weight and grade of tubing or casing, reduced by a suitable factor of safety.’ However, this pressure rating shall not exceed the maximum working pressure rating shown in Table 3.2. In-plant hydrostatic test pressures of components using tubing or casing threads are shown in Table 3.1

API Flanged or Clamped Wellhead Equipment

‘James ti Fosterwrote the orlglnal chapleron thisloplcinthe 1962 edwn “W G Boyle isauthorof the SafetyShut-InSystems sectionof th!schapter

PETROLEUM

3-2

ENGINEERING

HANDBOOK

When line pipe threads are used as end or outlet connections of wellhead or flowlinr components. the maximum working pressure rating of the assembled joint is stipulated in Table 3.2. The in-plant hydrostatic test pressure of components using line pipe threads is shown in Table 3.1. In many cases the OD of these female threaded members will be greater than API-tabulated coupling or joint diameter to ensure that the structural integrity of the threaded member will not be less than that of the compatible mating API male tubular member. In addition to the API threads listed in Specs. 5A and 5L, there are a number of proprietary threads available in the same sizes as the API tubing and casing threads. J.5 Some of the proprietary threads offer advantages over the API threads, such as maximum clearance for multiple completions, special corrosion protection from internal fluids, low torque requirements, superior internal and external pressure integrity, and high joint strength.

Tubmg

Physical Properties API body and bonnet members are made from steel with properties equal to or exceeding these specified in Tables 3.3 and 3.4. Lowermost Casing Heads

Fig. 3.1-Typical

wellhead

The lowermost casing head is a unit or housing attached to the top end of the surface pipe to provide a means for supporting the other strings of pipe, and sealing the annular space between the two strings of casing. It is composed of a casing-hanger bowl to receive the casing hanger necessary to support the next string of casing, a top flange for attaching blowout preventers (BOP’s), other intermediate casing heads or tubing heads, and a lower connection.

assembly.

TABLE

Working Pressure

(Psi) 1,000 1,500’ 2,000 3,000 5,000 10,000 15,000 20,000

3.1-TEST

PRESSURE

Flanges

Flanges (14 in. 1355.6 mm] and smaller)

(16%

In. 1425.5 mm]

and larger) (Psi) (bar)

(bar)

(Psi)

(bar)

69 103 138 207 345 690 1,035 1,380

2,000 -

138 -

1,500 -

103 -

4,000 6,000 10,000 15,000 22,500 30,000

276 414 690 1,035 1,551 2,070

3,000 4,500 10,000 15,000 -

207 310 690 1,035 -

Casing

4%- t0 [114.3-

l&%-in. to 273.1-mm]

Threads*

Clamp-Type Connectors (Psi) -

(bar) -

4,000 6,000 10,000 15,000 -

276 414 690 1,035 -

(Psi)

0-W

2,000

138

-

4,000’* 6.000* 10,000’* 15,000* * l

276 414 690 1,035 -

l

11% to 13%in. [298.5-lo 339.7.mm]

16-to 2&n. [406.4- to 508.0-mm]

(Psi)

(bar)

(Psi)

(bar)

(Psi)

(bar)

2,000 4,000 6,000 7.500

138 276 414 517

2,000

138 276 310

2,000 2,250 -

138 155 -

4,000 4,500

Line Pipe and Tubing Threads

*Working pressureof lhread “When threadsare used as end or outletconnectwns of wellheador flowllne components, the maximum sllpulated inTable 3.2 and the testpressureshallbe as tabulated !n Table 3 1

working pressureof the assembled low shallbe

WELLHEAD

EQUIPMENT

AND FLOW CONTROL

TABLE 3.2-API FOR WELLHEAD

3-3

DEVICES

MAXIMUM WORKING PRESSURE RATINGS MEMBERS HAVING FEMALE THREADED END OR OUTLET CONNECTIONS

Size

Thread Type Line Pipe (nominal

sizes)

Tubing, nonupset and external upset (API round thread) Casing (eight round, buttress and extreme line)

(in.)

[mm1

‘12 z/i to 2 2’/2 to 6

12.7 19.1 to 50.8 63.5 to 152.4

1,050

t0 4’h

4% to 10% 11 s/4 to 13% 16to20

The lower connection may be a female or male thread or a slip-on socket for welding. Most common is the female-threaded lower connection, although the slip-on socket connection provides the strongest joint unless the surface casing is of such composition that welding causes serious weakening. The male lower thread is the weakest of the three connections because of the thin cross section necessary to provide full opening. It is used in most cases only to prevent removing the coupling on the surface pipe. The welded connection is most frequently used on deep wells to give the additional strength needed to suspend heavy casing loads without overstressing the threads on the surface pipe. A landing base is sometimes used with the lowermost casing head to provide additional support for extremely heavy casing strings. The landing base is a separate unit welded to the lowermost casing head and to the surface pipe with a lower flange or skirt to transfer part of the weight to conductor strings, pilings, or a concrete foundation. The lower connection is usually the weakest vertical load-supporting connection in an API wellhead assembly. The body-wall thickness of the lowestworking-pressure lowermost casing head is sufficient to support the most extreme casing loads. Therefore, it is not necessary to increase the working pressure of the head because heavy casing loads are anticipated.

TABLE

Maximum Working Pressure Rating

3.3-PHYSICAL

(bar) 345 207

114.3

5,000

345

114.3 to 273.1 298.5 to 339.7 406.4 to 508.0

5,000 3,000 1,500

345 207 103

to

26.7

Most lowermost casing heads are furnished with two 2-in. line-pipe threaded side outlets, although studded or extended flanged outlets are sometimes used to provide additional strength for attaching valves. Internal valveremoval threads should be included in the studded or extended flanged outlets to provide a means for seating a valve-removal plug to seal the outlet while installing or removing a valve under pressure. In the event a valve on the side outlet of a casing head cuts out or it is desirable to install or remove a valve under pressure, after the well is completed a special tool can be attached to the outlet or the valve and a valveremoval plug can be inserted into the valve-removal thread to seal the pressure while necessary adjustments are made. A full&opening valve must be used for this application to provide clearance for the plug. In case threaded outlets are used, a valve-removal nipple may be used to provide the same facility. Internal threads inside the valve-removal nipple provide a receptacle to seat the plug for removing, installing, or replacing the valve. Lowermost casing heads are available with or without lock screws in the top flange. Lock screws usually are used only to hold the casing hanger down against pressures that may occur during nipple-up operations or when casing-string weights are too light to effect an automatic seal and require a lockscrew to effect the seal.

AND CHEMICAL Type 1

Tensile strength, minimum, psi [MPa] Yteld strength, minimum, psi [MPa] Elongation in 2 in., minimum, % Reduction In area, mimmum, % Carbon, maximum, % Manganese, maximum, % Sulfur, maximum, % Phosphorus, maximum, %

(Psi) -690 10,000 5,000 3,000

PROPERTIES’

Type

2

Type 3

70,000 [483] 36,000 [246] 22 30

90,000 [621] 60,000 [414] 18 35

100,000 [690] 75,000 [517] 17 35

:

:

:

:

: t t

Type 4’* 70,000 [483] 45,000 [31 O] 19 32 0.35 0.90 0.05 0.05

‘The des~~natw Type 1,Type 2 Type 3. and Type 4 ISa nomenclatureselectedby the API Committee on Standarduatlonof Valves and Wellhead Equlpmenl to ldentlfy material falling wllhm ihe ranges of tensile requ~remenlslosted above “Flanges made lrom Type 4 steelare recognlredas readily weldable,however,expeilencelndlcates thata moderate preheating1s dewable under allcondlllons and ISnecessaryIIweldingISdone at amblent temperaturesbelow 40°F (4%) tChemlcal analysesof Types 1 2. and 3 materials are purposelyomllledfrom lhlsspeclllcatlon m orderto providethe manulaclurer w,thcomplete freedom lo develop~leelsmw.t s”Lxblelorthe mul,~pkQ of reqwemenls encountered I”lh,scN,calservice

3-4

PETROLEUM

ENGINEERING

HANDBOOK

TABLE 3.4--MATERIAL APPLICATION, API MATERIAL TYPES SHOWN (1,2,3, or 4)

1,000

[691

Pressure

Ratings,

2,000

3,000

5,000

10,000

[I381

[2071

[3451

[690]

--2

Body (valve, Christmas tree or wellhead equipment) Integral end connection flanged threaded clamp type Bonnets Independently screwed equipment Loose pieces weld-neck flange blind flange threaded flange

2orl’

2orl’

psi (bar)

2 2

2 2

2

2

2

-

12

12

12

12

3,4

3,4

12

3,4 1,2 3,4

-

-

4 2 2

4 2 2

-

20,000

[1035]

[I3801

3

3

2orl*

-

3,4

15,000

2

2

3

-

4 2

-

3,4

I,2 3,4

I,2 3,4

-

-

2 2

2

3

-

-

3 3

-

3

-

-

'Provld~ng end ~onne~ttons are Type 2 and weld!ng IS done accordmg to generally accepted welding practices

A wellhead component must have a minimum internal diameter approximately X2 in. larger than the drift diameter of the tube over which it is used in order to be considered full-opening. Tables 3.6 and 3.7 give the minimum nominal flange size to give full-opening access to each standard tube size. Because of the problems encountered in sealing large threaded connections at high pressures in field makeup, Table 3.2 gives the maximum recommended thread pressure ratings for various pipe sizes.

The bowl surface can be protected by the use of a bowl protector during the drilling operations. The bowl protector is then removed before the hanger is set. Sizes and Working Pressures. Lowermost casing heads range in size from 7x6 in. to nominal 21 Y4in. to support casing in sizes from 4% to 16 in. (Table 3.5). Table 3.5 shows the various casinghead sizes needed for common surface, intermediate, and production string sizes. The sizes of lowermost casing heads are designated by the nominal size of the API flanged-end connection and the nominal size of the lower connection. Since the wellhead equipment attached above tubular materials should be full-opening to pass full-sized downhole tools, the bore of the tubular materials below an equipment component determines the minimum nominal size of the flange providing access to that tube.

TABLE

3.5-API

CASINGHEAD

Selection. In selecting a lowermost casing head for a particular application, the following factors should be considered. Design. The casing head should be designed to receive a casing hanger that will not damage the casing string to be suspended when supporting a full-joint-strength cas-

AND TUBING-HEAD

First Intermediate

Surface

ToSupport

API

CasInghead

Flanoe

Pipe

Pipe

Stze.

Lower

Size

Size

Casinghead

7

4%,5

8% g5/8 10%

4%,5.5'/2 4'/2,5.5'/2.65/8.7 5'/2,6=/,,7,7%

7x6 9 11 11

11%

5'/2.6%.7.7%

13%

Flange

Nommal

FLANGES Second

Size

Bottom

Top

Pipe Size

7x6 9 11 11 13%

-

-

-

-

Bottom

13%

13%

8% 0%

135% 13%

13%

13%

13%

13% 16

9 518 8 5/a

13% 16%

135% 16%

13% 16 %

16

9='8

16%

16%

16%

16 16

10% 10 3/a

16% 16 s/i

16% 16 %

16% 16 %

1s5/B or 1 I

16

13%

16%

16%

16%

13%

8%

or 11 13%

16 20

13% 13%

16% 21 '14

16% 2 1 '14

16%

21'!4

21 'in

13% 13% 13%

9% 8 vi? 9 518

13% 13% 13%

21% 21%

21 'I4 21 '/a

13% 16

20

16

21 '14 2 1 'I4 2 1 '/4

Flange

llor9 11or9

4Y2.5 4%,5,5'/2

11 or9 11

4%.5,5X 5'/2.65/&7

-

11or9 11

41/2,5% 5'h.6%7

-

13%

or 11

-

Top'

7x6 9 11

7% 7% 7%

11 13%

7%

-

-

-

5%,6%,7,7% 75%

-

-

-

13%

16%

10%

163%

2 1%

13%

21%

Stze

Bottom

-

13%

21'1

Pipe se

-

13%

20 20

Top -

13%

Tubtng-Head To Support

7%

1 1% 11%

IntermedIate

Casing"

ToSupport

Size

(in.)

11or9 ii or9

7% 7l& 7%

11 or9 11

7x6 7 ',,,',6

llor9 11

7% 6 7 I,,,:6

13%

or 11

4v2.5

11 or9

7x6 7'h 6

11 or9

4%,5'h

11 or9

7'/

s/,6 Y 6

I=/,,6

wl.5 WI6

179.4 226.6

10%

279.4 3461 425.5 450.9 527.1

12% 15 18% 21 23

11 13% 16% “17% 20%

Length Threaded Casmg

Hub Length Tubing

Neck Diameter

Maximum

Welding Neck Line-Pipe

Bore of Welding Neck

Flange

[mm]

Flange

(In)

[mm]

(in)

-

2

-

Flange

Flange

[mm] ___~ 51

(in.)

[mm]

3%

88.9

2%

6.5

4%~

-

2’3/6 2'5/&

71 75

2

51

124

29/,6

65

-

5% 6%

137 156

213h6 2"/,6

71 62

-

7.94 7.94

7% 8%

181 216

3% 3%,

76 a7

3'/2 4

89 102

3% -

241

31x6

94

4'/2

114

-

(in.)

Flange

[mm]

(in.)

[mm]

1.90

48 3

1.500

38.10

1095

2.38

60.5

1.939

4925

4’/,6 4%6

112 7 109.5

2.813 3.50

73.2 88 9

2 323 2 900

59.00 73.66

69 -

4's~ 5%e'

122 2 134.9

4.50 5.56

114.3 141.2

3 826 4.813

97.18 122.25

-

5'j/,s

147.9

6.63

1684

5.761

146.33

8.63

219.2

7 439

188.95

273 1 -

9.314 ~ -

236 56 _ ~

‘%*

11 91

Y,6

7.94

9%

‘%z

11.91

% 6

7.94

12%

308

45/j6

110

5

127

-

-

S"/,,

169.9

323 05 361 00 469 90 533.40

‘S/3* ‘& 2'/,2 25/3*

11.91 11.91 16.67 19.84

362 419 524 594

43/,6 4’5h6 5'1/,, 6’/2

116 125 144 165

5% 4’5/,6 5x'?/,, 6%

133 125 144 165-

-

-

7%~ -

192.1 -

z/32 19.84

7.94 7.94 11.11 12.70 12.70

14% 16% 20% 23%

564.20

s/,6 %6 %G ‘A! l/z

25%

648

6%

171

63/4

17,

_

_

_

f3?,8211 14 269.88

7x6 9

11.91 11.91

(in.)

Hub Length Welding Neck Line-Pipe

Hub

Length Threaded Lme-Pipe Flange

[mm]

**

(continued)

-

10.75 _

-

-

:

‘207 bar “See Table 3 18 sketch tThese s,zes,nact,vewallablean specialorderonly.

RECXJIREMENTS

FOR TABLE 3.19

1.3, 4, and 5 See Table 3 18 2 Rmg-groove radiusT.~shallbe ‘A2I”.IO.79mm] forgroove wdlhs “& and ‘% [873 and 1 I 91 mm] and 1/,6 I” [1.59mm] forwidths2’/32 and z:& ]I6 67 and 19 84 mm] ,,stn [460 10 65.1 mm]. inclusive, are ldentlcal withS.OOO-PSI [345-bar] flangesI”Table 3.20 6 Excepl forbore of weldmg neck flanges, dlmerwons forsizes11%6 10 Z9/ 7 MaxImum throughbores of 33/,6. 4X, and 7’16I” [El0. 108.0,and 181 0 mm] are permwble fornommal sws 3%. 4’/ls. and 7’1,~ [79.4,103 2, and 179 4 mm]. respectiveiy 8. Flangedend connectionsofsome casingand tubingheads may have entrybevelrecessesand/orcounterbores greaterthand, maximum 10receivea packer mechanism The s,~esand shapes of these bevels.recesses,and/orcounterboresare prapriefary and are “01 covered by thisspeclflcatlon

Llqud

Manual

Regulator

Fus,hle

IF

Emergency ShuGOown Valve a, Boat Landmo

(ESD)

-

\

I

Lx-

Pressure Sensors

ControlPanel ./

““I,

‘I

t SurfaceControlled Subsurface Safety Valve

Fig. 3.6-Production

platform

safety

shut-in

system.

PETROLEUM

3-20

TABLE3.20-API Basic Nominal

“Old”

Size and

Nominal

Bore of Flange

TYPE 68 FLANGES Dimensions’

Outside

Total

Basic

Diameter of Flange

Thvzkness of Flange

Thickness of Flange

(m)

1%

7

1%

38.1

1 ‘/4

52.4

2

8%

178 216

1’3,s

46.0

65.1 79.4

3

9% 10%

244 267

l’5/,16 2%

49.2

3’/s 4% 5%

103.2 130.2

4 5

12% 14%

311 375

7%

179 4

6

15%

394

3%

9

228.6

8

19

483

4%~ 41%~ -

119 - 1

[mm]

WE 2%6

&h

346.1 279.4

$163/q

425.5

2%

‘,35/8 10 ,lj3/4

23-

584 -

MAXIMUM

WORKING Boltmg

[mm]

(in.)

FOR 5,000~psi’

’

(in.)

-46.0 t I’%.._

t

Size of Flange (in.)

Flange

[mm]

Diameter

~ (in.)

[mm]

Number of Bolts

4% 6%

123.8 165.1

4 8

of Bolts

Olameter

Length

of Bolt Holes

of Stud Bolts

1%

55.6

1% 1%

41.3 47.6

4% 5%

123.8 133.4

7% 8

190.5 203.2

8 8

1 1 ‘/B

1.12 1 25

29 32

61 .9 81 0

2% 27/e

54.0 73 0

6% 7%

161.9 196.9

91/z 11%

241.3 292.1

:

1 ‘/r ‘/2

1 38 1.62

35 42

8 10

203 254

39 44

92.1

31%

82.6

9

228.6

12%

317.5

12

1 3/a

1 50

39

10%

273

46

103.2

35/a

92.1

11%

292.1

15%

393.7

45 51

12 13%

305 349

50 54

108.0 -

14% -

368.3 -

19 -

482.6 _

1% 1 ‘/s -

1.75 200

4% -

12 12 -

-

-

-

-

-

-

-

-

-

On.1

(in.)

[mm]

(In.)

[mm]

R or RX

1

1.12 1.00

29 26

5%

V8

6

140 152

20 24

6% 7%

165 184

27 35

‘345 bar. *‘See Table 3 18 sketch +These sues ,nactwe,wallableon spectal orderonly *See Table 3 22 fordtmenslondetails an these sizes.

Fusible Plug

Pneumatic -

Surface

Safety Valve Control

Surface

Hydraulic

Surface

’

Valve

Safety

Panel

c1””

Controlled

Subsurface

Safety

Valve

Fig. 3.7-Safety

Rtng Number

2% 4%

-

(in.)

PRESSURE

Dimensions”

31 8 38 1

33/jG

[mm]

HANDBOOK

[mm] --~ 69.9 104.3

256

(In.)

Diameter of Bolt Circle

Diameter of Hub

ENGINEERING

shut-in

system

with

hydraulic

valves

and

pneumatic

valves

3-21

WELLHEAD EQUIPMENT AND FLOW CONTROL DEVICES

TABLE 3.20—API TYPE 6B FLANGES FOR 5,000-psi* MAXIMUM WORKING PRESSURE (continued) Ring-Joint Groove and Flange Facing Dimensions” Pitch Diameter of Type R Ring and Groove

Nominal Size and Bore of Flange (in.) t

1’%6 2’/,,

24, 3%

4’116 t 5’18 7%6 9 11 $135/E

$163/q

[mm]

(in.) [mm] ~211/,, 68 26 “/zz 3% 9 5 2 5 ‘% 4% 107.95 ‘Sk* 5% 136.53 1%

(in.)

46.0 52 4 65 1 79.4 1032 1302 179.4 228.6 279 4

Width of Groove

“_

6% 7% 85/j6 10% 12% -

346.1 4255

161.93 193.68 211.14 269.88 323.85 -

-

1%~ 1Yz2 “/zz *l/x2 2’/~2 -

Depth of Groove

‘Hub and Bore Dimensions**

Diameter of Raised Face

Hub Length Threaded Line-Pipe Flange

[mm] (m) [mm] (in.) [mm] (in.) [mm] -__8.73 ‘/4 6 35 3% 92 2 51 11.91 %f 7 94 4 % 124 2%~ 65 11.91 %6 ‘7 94 5 a/a 137 213/16 71 11 91 %6 7.94 6% 168 33/16 81 11.91 11.91 1349 16.67 16.67 -

%6 %6 3/s ‘/I 6 %6 _

7 94 7.94 9.53 11 11 11 11 _ -

7s/, 9 9% 12% 14% -

194 229 248 318 371 -

3% 4%6 5x6

98 113 129 154 6’%6 170 _ -

WI,

Hub Length Threaded Casing Flange (In.) [mm] __~ -

Hub Length Tubing Flange

On.) Imml -~ 2 29~~ 2’3/16 33/16

51 65 71 81

Hub Length Welding Neck Line-Pipe Flange

bn)

lmml

3 ‘/2 889 45/j6 109 5 47/,6 1 1 2 7 415/]6 125 4

Neck Diameter Welding Neck Line-Pipe Flange

0n)

lmml

Maximum Bore of Welding Neck Flange

t(n)

1.904831337 2.38 605 1 689 2 88 73.2 2.125 3 50 889 2624

~ [mm1 33 42 53 66

96 90 98 65

3% 4x6 5x6

98 53/,6 131 8 3% 98 450 1143 3438 87 33 113 556 141 2 4313 10955 6’/,6 163 5 129 7% 181 0 663 1684 5189 131 80 154 8’3/>~ 223 8 863 2192 6.813 17305 6”/,6 170 lOY,e 265 1 1 0 7 5 2 7 3 1 8 5 0 0 2 1 5 9 0 _ _ _ _ _ _ _ _ _ _ _ -

wl6

‘345 bar ‘See Table 3 16 skerch

REQUIREMENTS FOR TABLE 3.20 ,,3,4,and5 SeeTable 2 R1n9.groove radius r,g shall Ye jhz m (0 79 mm] for 9roove widths “& and ‘s/S2 m [8 73 and 11 91 mm]. 1/,6 1”. (1 59 mm] for wdths ‘Xz and 2’& [13 49 and 16 67 mm] 6 Except for bore of welding-neck flanges, dtmenslons for suxs 11%6 III to 23/,5 !n [46 0 to 65 1 mm]. mclus~ve, are ldentlcal with 3,000.PSI [207-bar] flanges I” Table 3 19 7 and 8 See Table 3 19

Surface Safety Valves (SSV’s) An SSV on the Christmas tree is usually the second valve in the flow stream. Hence it is the second master valve, if it is in the vertical run, otherwise it is a wing valve. SSV’s can be located downstream of the well in the process train at such places as (1) flowline headers, (2) suction, discharge, and bypass on a compressor (the bypass safety valve safe mode is open instead of closed), or (3) at the entrance to the sales pipeline or the pipeline leaving a platform. Most SSV’s are reverse-acting production-gate valves with piston-type actuators (Fig. 3.8). Valve-body pressure against the lower stem area moves the gate to the up/closed position. Control pressure applied to the piston pushes the gate to the down/open position. Usual-

ly a spring is used to close the valve if valve-body pressure is not present. Valve-body pressure and piston/stem area ratio determine the control pressure required. Large-ratio pneumatic actuators are used because the larger ratio permits use of lower control pressure. Lower-pressure control-system valves can be simpler and more reliable. Compressed air or produced gas are the usual control fluids. Control pressures are generally 250 psi or less. Low-ratio hydraulic actuators are used where the SSV is to be controlled by the same system that controls the SSSV, or where limited space is available on the Christmas tree (Fig. 3.9). Control pressures are generally slightly greater than the shut-in pressure of the well.

Fig. 3.8—Pneumatic-powered ratio-piston surface safety valve.

Fig. 3.9—Pneumatic and hydraulic surface safety valves

PETROLEUM

3-22

TABLE

3.21-API

TYPE 6BX INTEGRAL

FLANGES

FOR 5,000-AND Bmc

Nommal Sue and Bore (in1

OutsIde Diameter

lmml

On)

2.000 PSI(138 bar)

26%

6795

41

3.000 PSI (207 bar)

26%

6795

5,000 PSI (345 bar)

13% 716% 18% 2 1%

346.1 425.5 476.3 539.8

'*I"&

429 46.0 52.4

10,000 ps, (690 bar)

I'%16 2%6

Small Diameter of Hub

Large Diameter of Hub

w 2.000 MI (138 bar) 3.000 psr (207 bar) 5,000 ps; (345 bar1

10,000 ps, (690bar)

1

[mm]

(m)

(in)

bml

(ln)

743 0

73/,6 166

vu

159

43%

1102 6"/>, 161 1

870.0

30%,

7763

75&

186

518

15 9

26% 30% 35% 39

673 772 905 991

4x6 1127 la'%, 5% 1302 21% 6'7/,21659 26%~ 7% 181.0 29%

481 0 5556 674 7 7588

16"/,6 20% 23%, 26%

423 9 527 1 598 5 679.5

4% 3 6 6%

114 76 152 165

ve 74 % "AS

159 19 1 159 175

183 187 200

1% 12%~ 14%4

a4 1 08 9 1000

2'3/>2 61.1 12y32 2% 65.1 1% 2'5& 746 2%

47 48 52

ve % K

9.5 9 5 9 5

3% 92.1 2M 4"/32 110.3 2% 5% 1461 2% 7'& 182.6 3%

57 64 73 81

V8 3% W 3/s

9.5 9 5 95 9 5

3% 3'Xs 4vj6

95 94 103

5% s/s 5/s

159 15.9 15.9

4% 3 6% 6%

114 76 156 165

9 'h 10% 12',$6 14'/IS

232 2%. 270 2'Ysq 316 2-/s, 357 31/s

1794 2286 2794

18% 21% 25%

479 552 654

4%. 4% 5%6

34%

42.1 42 1 44.1

3% 3% 3'%.

51.2 563 702 79.4

120 7 4% 5'9,& 142.1 73/,e 1826 813/,,2238

1032 1238 141 3

6% 1683 6% 1683 Sz5/,z223 0 9% 2413

11% 14% 17%

3016 374.7 450 9

IO 12% 15%

20

21% 25'%a 29% 33%

5525 6556 752.5 8477

lS'/z 4953 23'1/,6 601.7 21?/~ 674 7 30 762 0

(in.) [mm]

Raised Face Diameter (ln)

[mm]

Gr0CW? OD (1n.1

/mm]

=/s 15.9 19.1 % 15.9 % 13/,rj206

Dimensions Width of GKPSe (in)

Depth of GrCO!e

[mm]

(in.) [mm]

t3ng Number

1%

1.88

48

13%

349

31"',,,804 9 30.249 768.32 0902

22.91

2',3221.43

BX-167

2

2.12

54

17

432

32%

831.9 30.481 774.22 1.018 25.86

25'3221.43

8X-168

590.6 676.3 603.3 885.8

16 16 20 24

178 1% 2 2

1.75 2.00 2.12 2.12

45 51 54 54

12% 14% 17% 18%

318 368 445 476

I8 21%~ 24"& 27%

4572 535 0 627.1 701.7

V,s 1429 *'kn 6.33 '3& 18.26 % 19 05

BX-160 8X-162 8X.163 BX-165

141.3 146 1 1586

8 8 8

088 088 0.88

23 23 23

5 5 5%

127 127 133

4 4% 4%

101 6 2.893 104 8 3062 111.1 3395

'& ?& '%a

5 56 5 56 5 95

EX-150 8X-151 8X-152

'/s 1 1'/a

100 112 125

26 29 32

6 6% 8

152 171 203

5% 6 7%

131 8 152.4 184 9

'%a 6 75 's,64 7 54 ?%a 8 33

8X-153 8X-154 BX-155

37%

9525

39%

10001

13% t16% 18% 2 1%

346.1 425.5 476.3 539.8

23% 26% 31% 34%

* *11% 6 1'%6

429 46 0 524

5% 6%

4',&

65 1 77 6 1032

7% 184 2 8% 2159 1O3/,6 2588

5% 71:s 9 11

1302 1794 2286 2794

ll'Y,s 15% 18% 22%

13% 16% 18% 21%

346 1 4255 4763 5396

26% 30% 36% 40%

3%6

Lenath of Siud Bolts

lmml (ln 1 lmml

24

679.5 6795

6

254.0 327.0 400.1

Facing andGroove Diameter of Bolt H&S

[mm]

26%

5%

Radus at Hub

29%

65.1 77 8 1032 1302

W )

Length of Hub

Imml

Diameter Number 01 Bolls of Bolts (117 ) (m ) [mm]

26%

2’h 2%

PRESSURE

835.8

7%6 7% 7%

bml

Boltmg Dlmensms Diameter of Bolt Circle

WORKING

1041 4='/2>126 2 322%~

346 1 30% 768 425 5 345ie 872 476 3 40'5/,,1040 5398 45 1143

Nominal Sam and Bore

MAXIMUM

HANDBOOK

Flange Dlmerwons

Total Thickness

[mm1 -__ bn)

lO,OOO-psi’

ENGINEERING

~

I3 6 8

u 3'4 %

3000 4032 4763 5652

12 12 16 16

1'/a 1'h 1'h 1%

125 162 1 62 1 88

32 42 42 48

8% 11% 13 15

222 286 330 381

6'%s 11% 14% 16%

6731 7763 9255 10224

20 24 24 24

1w 1% 2% 2%

200 200 238 262

51 51 61 67

17% 17% 22% 24'h

438 445 572 622

20% 517.5 22"/,,576.3 27'A6 696.9 30% 781.1

16063 16.832 22.185 24.904

408.00 478.33 563.50 63256

0786 0.705 1.006 1.071

1996 1791 25 55 27 20

73.48 0.450 11 43 77.77 0.466 11 84 8628 0.498 12 65

4.046 10277 0.554 14 07 4685 11900 0.606 1539 5.930 150.62 0.698 17 73

220.7 6.955 301.6 9.521 358.8 11 774 428.6 14064 17.033 18.832 22752 25.507

17666 0666 241 83 0.921 29906 1039 35723 1.149

1692 23 39 26 39 2918

3/s 9 53 %6 11 11 'h 1270 %h 1429

8X-169 8X-156 BX-157 BX-158

43264 1279 478 33 0 705 57790 1290 64788 1373

5/s 15 88 3249 8 33 17.91 z'& 32 77 23& 18 26 % 19 05 3487

6X-159 6X-162 EX-164 BX~l66

'345and 690 bar '.ThlSflange 14InaCtIve avaIlable on s&x?clal Olderonly +ThtstlangewasadopledJ"ne 1969and shall be markedwth boththeworking ,xessure (50OOWP)and thetest ~ressure,10,000TPI ,nadd,l,on ,aalher mark,nSrequwemenfs

WELLHEAD

TABLE

EQUIPMENT

3.22-API

AND

FLOW CONTROL

3-23

DEVICES

TYPE 68X WELDING-NECK

FLANGES

FOR lO,OOO- AND 15,000-psi’

MAXIMUM

WORKING

PRESSURE

Basic Flange Dlmenslons Nominal Size and Bore

OutsIde Diameter

bml 10.000 psi

429 460 524

(690 bar)

**1”/j6 1'3/.. ,”

15,000 PSI (1035 bar)

2%6 244 6

3% 6 4x5 7'/< 6

Large Dlametet of Hub

Total Thickness

S"Mll Diameter of Hub

(1"1 10.000 DSI (690 ba;)

. f1',< c 1 '% 6

2%6

42 9 46.0 524

(in) 5%. 5%6%

[mm]

(in.) [mm]

(tn.) [mm]

lvx 1v3* I'%4

42 1 42 1 44 1

3%6 84 1 3'/2 88.9 3'Yje 1000

2'Y32 29/~6 2'7,6

12x2 47 129/,1 48 2%2 52

51 2 58.3 70 2

4% 120 7 5f=/32142 1 73/,6 182.6

35/e 92.1 4"/s2 110 3 5% 1461

(in)

[mm]

I % ?/8

9 5 95 9 5

57 64 73

3/s =/a 318

95 9 5 9 5

9% 232 lO~/n 270 12%6 316

2'/64 2's& PS&

1302 1794 2286

14%6 357 18v.. 479 21% 552

31% 794 4'/16 1032 47/s 1238

6"/,vj2236 11R 301.6 14% 374.7

7x6 1826 10 254.0 127/n 327.0

3Y,e 81 3% 95 3('/(6 94

3h 5/a 78

9.5 159 159

2794 346 1 425 5

25% 30'14 34%,

654 768 872

5Y6 141 3 65/s 1683 65/s 1683

17% 4509 21% 5525 2513/,56556

15% 19'h 23'%6

4'& 4'h 3

108 114 76

s/s s/a %

159 159 19.1

42 9 46 0 524 651 778 103 2 1794

75/e 8%..” 6% IO ll%e 143/,, 19vn

194 208 222 254 287 360 505

1% 12%.2 2% 2'/;, 33/32 4"&

3"/18 32'/w 4%51/15 6%, 7"/js 12'3h6

48 48 54 57 64 73 92

?/s 3/a k % Vs Ye VI3

9 5 9 5 9 5 9 5 95 95 159

44 5 45 2 50 8 57 2 64.3 786 119 1

937 97.6 111.1 128.6 1540 195.3 3254

400.1 495.3 601 7

21Y,6 68 3 2'3h. ,” 71 4 3'/4 82 6 31%6 100 0 4'3/16 122 2 6'/4 158 8 10% 2762 Facmg

Dlametet of Bolt Holes

8 a

61.1 65 1 74.6

651 778 1032

Diameter Number of Bolts (1") [mm] of Bolts (1"1

141 8 146 1 1588

(m ) [mm]

Imml

183 187 200

7%6 7% 7%

% % %

068 088 088

23 23 23

Length of Stud Bolts (in) [mm] 5

Ralsed Face Dwneter (in.) [mm]

2'14 2'/2 2'ls

178 1% 2Vs 2'14 2'12 27/e 35/s

and Groove Dlmenslons

G"JOVt? 00

Width of Groove

(in.)

[mm]

73.48 0.450 77.77 0.466 8623 0498

(1”)

127 127 133

4 101 6 4?e 104.8 43/a 111 1

2.893 3.062 3395

5%~ 6 7%,

4.046 102.77 0554 4685 11900 0606 5.930 150.62 0.698

131 8 1524 184 9

Depth of GVXNe

[mm]

(tn.) [mm]

mng Number

11 43 11 84 1265

'/w 556 :i; 5 56 's/h4 5 95

BX-151 BX-152

1407 1539 1773

‘%4

'!/64 6 75 754 2'ka 8 33

BX-153 BX-154 BX-155

291,s 65 1 3'& 778 4'& 1032

7'/s 184 2 a','* 215 9 lOz& 2588

8 8 8

7/s 1 1'/s

100 112 125

26 29 32

152 171 203

5'18 1302 7'h. .I 1794 9 2286

11'v,/,6 3000 15'/s 4032 18% 4763

12 12 16

1'ia 1'/2 1'h

125 1.62 162

32 42 42

222 286 330

8"h 220 7 6.955 176.66 0.666 16 92 IlVe 301 6 9.521 241.83 0.921 2339 14'/s 358 8 11.774 299.06 1.039 2639

3/s 9 53 '/,e 11 11 '/2 12 70

BX-169 BX-156 BX-157

221/n 5652 26% 6731 30%~ 7763

16 20 24

1% 1'/a 1 '/a

1.88 200 200

48 51 51

381 438 445

1678 428 6 14.064 357.23 1.149 29 18 203/s 517 5 17.033 432.64 1.279 32 49 22'%8 576.3 18.832 476.33 0.705 17.91

5/E =h4

14 29 15 66 8.33

8X-158 8X-159 6X-162

a 8 8 8 8

% % xl 1 1'18

0.88 100 1.00 1.12 125 1.50 1.62

23 26 26 29 32 39 42

133 140 152 171 191 235

3'3A, 96.8 43/,6 106.4' 4% 114.3 5'/4 133.4 6'/,, 154.0 7Vs 193.7 12 304.8

',& 5.56 "32 5.56 '%4 5 95 '%A 675 '?& 7.54 VM 8 33 '/I/(6 11 11

BX-150 BX-151 6X-152 BX-153 BX-154 BX-155

11 135/a 16% 15,000 PSI (1035 bar)

[mm]

R&us at Hub

On.) lmml (ln)

BoltingDlmensons Diameter of Bolt Circle

Nominal SIX and B0te

Length of Hub

2794 346 1 425 5

* *1 'j/,6 429 I?/,6 46 0 52 4 2%6 65 1 3% I 77 8

2%6

6 1524 65/16 1603 6% 174.6 7'/s 2000 9% 2302

324

2.893 3.062 3.395 4.046 4.685 5.930 9.521

73.48 77.77 66.23 102.77 119.00 150.62 241.83

0.450 11 43 0.466 11 84 0 498 12 65 0.554 14.07 0.606 15 39 0 698 1773 0.921 23.39

91.

BX-156

REQUlREMENTSFORTABLES3.22ANO3.24 1 Dueto thed~ff~cuity offteld weldingAPI Types 2 and 3 materialfrom which theseilangesaremade,atransjt~on p~ecemay beshopwelded tothebase flangeand theweld properlyheattreatedThisfrans~t~on pieceshallbe made from the same or smlar matenalas the pipetowhich IIISLobewelded by the cusfomer Trans~t~on prxe ID and OD al the heldweid~ngend. and 11smaternal. shallbe speclfled on the purchase order 2 The lengthof the lransit~on pwe shallbe greatenough thalthe near from fleid weldmg willnot affect the metallurgIcal properws of the shop weld 3 The API monogram shallbe apphed lo the weldmg-neck flange(solld outl~nej The API monogram does "at applyto the shop weld or the trans,tion p,ece 4 D~mensianh,,may be omlttedonstudded connections

3-24

PETROLEUM

TABLE 3.23-API

TYPE 68X INTEGRAL

FLANGES

FOR 15,000-AND

20,000-psi’

ENGINEERING

MAXIMUM

WORKING

HANDBOOK

PRESSURE

Basic Flange Dimensions” Nominal sze and Bore [mm]

(In ) 15,000 psi (1035 bar)

W'%s 1 '%s

429 460 524 2% 6 651 3%, 77.6 4'116 1032

7'116 1794 9 2266 11 2794 20,000 psf (1360 bar)

460 524 2% e 65 1 3x5 778 4x6 1032 7s/16 1794

136

2%6

Small Ofameter of Hub

Total Thtckness

(in)

[mm]

(In.) [mm]

(in.) [mm]

(In)

194 206 222 254 267 360

19s 505 25'/z 646 32 813

1% 44.5 12=& 45 2 2 50.6 2'14 57.2 2'%, 64.3 33h2 76.6 41& 119.1 5% 146.1 7% 167.3

3"/,6 93.7 3zYz2 97.6 4% 111.1 5'/,s 126.6 6%~ 154.0 7"/,6 195.3 12'%8 325.4 17 431.0 23 564.2

211/,,,66.3 1% 2'=A6 71.4 1% 3s 62.6 2'18 3'%6 100.0 2’14 4'%, 122.2 2'12 6'/4 156.6 2'/8 lo'/8 276.2 3Vx0 13% 349.3 47/8 161J/(64270 9%~

lo'/8 257 llYjs 267 12'3/,6325 14'/,, 357 17%~ 446 25'3& 656

2'12 63.5 5% 2'Y,6 71.4 6%~ 3'18 79.4 6'3& 3s 05.7 79h6 43/,s 106.4 9%~ 6'/2 165.1 153hb

7% 83/,6 8% 10 115/?6 143/,6

WI6

Large Diameter of Hub

OutsIde Dtameter

fin ) 15,000 PSI -42.96 t l"A6 (1035bar) 1s

(m.)

[mm]

46.0 52 4 65 1 77 8 103 2 1794 2266 2794

6%~ 67/a 7s 9x6 11x6 16% 21% 26

46 0 52 4 65 1 77 8 103.2 1794

8 203.2 9'/,6 230.2 10%~ 261.9 11%~ 267.3 14'/,6 3572 21'3/,,6 5540

152.4 -3148 160 3 8 1746 8 2000 a 230.2 8 290.5 6 426.6 16 552.5 16 711.2 20

Length of Stud Bolts

(fn) [mm]

(in.)[mm]

(lo.) [mm]

1 1l/a 1 3/s 1'12 1% 2

088 1 00 00 12 125 1 50 1 62 200 212

23 26 26 29 32 39 42 51 54

5'/4 5% 6 6% 7'/2 9% 12% 15% 19'/4

133 140 152 171 191 235 324 400 489

1 15% 1'/a 1% 1% 2

ll2 125 136 150 1 66 212

29 32 35 39 46 54

7% a'/4 9% 10 12% 17%

191 210 235 254 311 445

78 '/s

8 8 6 6 6 16

(in.) [mm]

(In.)[mm]

46 46 54 57 64 73 92 124 236 49 52 59 64 73 97

Ys 9.5 318 95 318 9 5 % 9 5 l/s 9 5 =/P. 95 i/s 159 V8 159 5% 159 % "h 318 Ye % %

9 5 9 5 9 5 9 5 95 159

Facing and Groove Drmensrons” Diameter of Bolt IdOleS

Diameter Number of Bolts of Bolts on I

[mm]

Radius at Hub

133.4 4%~ 109.5 l'%s 154.0 5 127.0 2'/,6 173 0 5"/,6 144.5 2%~ 192.1 65/,, 1603 2% 242.9 Et'/8206.4 2'/s 365.6 13%6 338.1 3'%6

Bolting Drmensrons” Dtameter of Bolt Circle

Nommal Stze and Bore

[mm]

Length of Hub

Ratsed Face Drameter

Wldlh of Groove

Groove OD

Depth of GVXXe

(in)

[mm]

(In)

[mm]

(In.) [mm]

Rfng Number

3'%r 96.8 43/16-106.4 1143 133.4 154.0 193.7 304.8 361.0 454.0

2.893 3.062 3 395 4.046 4.665 5 930 9.521 11 774 14064

73.46 77.77 66 23 102 77 119 00 150 62 241.63 299.06 35723

0.450 0.466 0 496 0 554 0.606 0.696 0921 1039 1149

11.43 11.64 12.65 14.07 15.39 17.73 23.39 26.39 29.16

%, 5 56 %z 5 56 's/s4 5 95 '%a 6 75 'g& 7 54 2’/k4 a 33 ‘/,6 11 11 Vz 12 70 q/~6 1429

6X-150 BX-151 BX-152 6X-153 6X-154 BX-155 BX-156 BX-157 BX-156

117.5 131.6 150.8 171.5 219.1 3524

3.062 3395 4.046 4665 5.930 9 521

77 77 86 23 102 77 11900 150 62 24163

0 466 11.84 'h2 5 0 496 12.65 '%a 5 0 554 14.07 '7/6. 6 0606 15.39 '%a 7 0 698 17.73 "kn 0 0921 2339 '/,6 11

__

56 95 75 54 33 11

BX-151 6X-152 BX-153 0x-154 BX-155 BX-156

'1035and 1380 bar .'See Table321 sketch +Th,sIlangeIS,nact,ve. available 0" spew1 orderonly

TABLE 3.24-API

TYPE 6BX WELDING-NECK

FLANGES

Basic Flange

FOR 20,000-psi’

Large

Small

Size and

Outside

Total

Diameter

Diameter

Length

Bore

Diameter

Thtckness

of Hub

of Hub

of Hub

(in.)

[mm]

(in.)

[mm]

(In.)

[mm]

(in.) __~

(in.) ~1’s

WI6 wl6

[mm]

at Hub

(in.) --

]mm]

(In.) [mm]

(In.) ]mm]

l’%

46.0

lo'/8

257

2'12

63.5

5'/4

133.4

4%5

109.5

l’s/,6

49

3/a

9.5

2%6

52.4

lls/,,j

287

2’3/,6

71.4

6’/,,

154.0

5

127.0

2’/,6

52

%

9.5

2% 6 3x6

65.1 77.6

12’3/la 14’/le

325 357

3’/n 3 V8

79.4 65.7

6’3/la 7%5

173.0 192.1

5”/,, 6%~

144.5 160.3

2s/,, 2’/2

59 64

Ya 3%

9.5 9 5

4%~ 7%6

103.2 179.4

179/,6 446 25'3/16 656

43/,6 6’12

106.4 165.1

9%s 153/1k

242.9 385.8

8’18 13%6

206.4 338.1

27/a 3’3/,,6

73 97

3/s %

9.5 15.9

Diameter of Bolt Circle

Diameter Number of Bolts

of Bolts (in.)

Facina Diameter

Length

of Bolt Holes

(m)

[mm]

46.0 52.4

8 9’/,,

203.2 230.2

El El

1 1 ‘/a

1.12 1.25

29 32

and Groove

of Stud

Raised Face

Groove

Bolts

Diameter

OD

(in.) --(In.) [mm1

PRESSURE

Radius

(mm]

Bolttng Dimensions”

Size and Bore

WORKING

Dimensions”

Nominal

Nominal

MAXIMUM

lmm]

7’/2 w/4

191 210

9%

(in.) --~ 45/s 5a/18

[mm]

(in.)

117.5 131.6

Dimensions”

Width

of

Groove

3 062 3.395

[mm] -~ 77.77 66.23

(in.) 0.466 0.498

[mm] ~-11.84 12.65

Depth

of

Groove _________ (In.) [mm]

Ring Number

r/s2 ‘5/64

5.56 5.95

BX-151 BX-152

65.1

lO%s

261.9

6

1 ‘I4

1.36

35

235

5’%6

150.6

4.046

102.77

0.554

14.07

‘764

6.75

8X-153

3x6

77.0

lls/,a

2873

8

1 a/a

1.50

39

10

254

6%

171.5

4 685

119.00

0.606

15.39

‘a/&

7.54

BX-154

4’/,a

103.2

14%~

357.2

8

1%

311

8%

219.1

5 930

150.62

0.698

17.73

*‘/64

6.33

BX-155

179.4

21’+‘,6

554.0

16

46 54

12’/4

7lyta

1.88 2.12

17’/2

445

1376

352.4

9 521

241.83

0.921

23.39

‘/,e

11.11

BX-156

'1360 bar. '*See Table 322 sketch

2

WELLHEAD

EQUIPMENT

TABLE 3.25-API

AND FLOW CONTROL

3-25

DEVICES

TYPE 6BX BLIND AND TEST FLANGES

FOR lO,OOO- AND 15,000-psi’

MAXIMUM

WORKING

PRESSURE

Basic Flange Dimensions Nommal Size and Bore

10,000 psi (690 bar)

Large Diameter” of Hub

Small Dlameler” of Hub

Outside Diameter

Total Thickness

(I”.) [mm]

(I”.) [mm]

11% 11%,+

7%$ 7% 7Vs

183 187 200

(1”) [mm] -1”/3? 42.1 1% 42.1 14’/64 44.1

3sj& 84.1 3% 68.9 3’%, 100.0

2’3/32 2%. 2’S/,,

9’18 232 270 10% 12%~ 316

21,&a 51.2 219h, 58.3 Z-164 70.2

4% 5’& 7%5

120.7 142.1 182.6

3% 4,‘&, 5%

1% I=,&

44.5 45.2

3J& 32%2

93.7 97.6

2 2% 2”/32 33/52

50.8 57.2 64.3 78.6

4% 5’/,6 6%~ 71%~

wl, 2%

42.9 46.0 52.4

65.1 3x6 77.8 4’/,5 103.2

194 7% 8y16 208 222 52.4 6% 254 651 10 3%6 77.8 11%~ 287 4’116 103.2 14%~ 360

15,000 psi f1Y16 (1035 bar) I’%s

42.9 46 0

wl6 2%

(in.) [mm]

(in.) [mm] -61.1 65.1 74.6

1*%2 1%. 21/,

92.1 110.3 146.1

2% 2% 27/s

60.3 71.4

.-

2”/la 213/,,

111.1 128.6 154.0 195.3

82.6 3% 3’7,s 100.0 4’3/,e 120.7 6’/4 158.8

(I”.) 10,000 DSI (690 b;r)

1’%6 VW;

WI6 2% 31x6 41x6

15,000 psi 1VW (1035 bar) l’s/,6

WI6 29h 3x6 41x15

Dwneter of Bolt Orcle

Diameter Number of Bolts of Bolts (in)

Radus al Hub

(in.) [mm] --47 48 52

(m ) [mm] % % M

9.5 9.5 9.5

57 64 73

3/s % 3/s

9.5 9.5 9.5

17/ 17/s

48 48

% %

9.5 9.5

2% 2% 2% 2%

54 57 64 73

3/s % H %

9.5 9.5 9.5 9.5

Facing and Groove Dimensions

BoltingDimensions Nominal Size and Bore

Length” of Hub

Diameter of Bolt Holes

Length of Stud Bolts

Raised Face Diameter

(in) [mm]

(in.)[mm]

(tn.) [mm]

Groove OD

141 3 146 1 158.6

8 8 8

% % %

0.88 0.88 0 88

23 23 23

5 127 5 127 5’/1 133

4 4’/8 4%

101.6 2.893 104.6 3.062 111 .I 3.395

[mm] (in.) [mm] -~ --~ 73.48 0.450 11 43 77.77 0.466 11 84 86.23 0.498 1265

,65.1 71/n 184.2 77.8 5% 215.9 103.2 lOY,e 258.6

6 8 8

78 1 1‘/a

1 00 1.12 1.25

26 29 32

6 6% 8

152 171 203

5% 6 79/z

131.8 4.046 152.4 4.685 184.9 5.930

102.77 0.554 1407 119.00 0.606 1539 150.62 0.698 1773

6 8

% T/e

0.88 100

23 26

5% 5%

133 140

3’%6 96.8 2.893 4%/16 106.4 3.062 4% 114.3 3.395 5’/4 133.4 4.046 6x6 154.0 4.685 7% 193.7 5.930

[mm] 42.9 46.0 52.4

42.9 4.6.0 52.4 65.1 77.8 103.2

(in.) [mm] 5%. 5%. 6V4

6 6%~ 67/e 7’/0 9% 11%~

152.4 160.3 174.6 200.0 230.2 290.5

8 8 8 8

78 1 1l/s 1%

1.00 1.12 1.25 1.50

26 29 32 39

6 6% 7% 9’h

152 171 191 235

(in.)

Width of Groove

Depth of GK?OW (in) [mm]

Ring Number

%, -_ 5.56 ‘h> 5.56 ‘5/s4 5 95

BX-150 BX-151 8X-152

I’/& 6.75 ‘?/~a 7.54 2’& 8.33

BX-153 BX-154 BX-155

‘/32 5.56 x2 5.56

BX.150 BX-151 BX-152 BX-153 BX-154 6X-155

73.48 0.450 11 43 77.77 0.466 11.84 86.23 102.77 119.00 150.62

0.498 0.554 0.606 0.698

12.65 14 07 15 39 17.73

1% 5 95 ‘1/., 6.75 ‘?& 7.54 z’/s4 8.33

‘690and 1035 bar. “Type BX blindflanges mus1 be provided witha prolongon therearface,described by thelargeand smalldwwters and lengthofthehub.

I-----dol

B TO RlNG GROOYE ,YUST GE CONCENTR,C WmflN O.Q10TOTAL lNOfCATOR R”NO”T

I

FdbCl

I

LOCATED WITHIN 0.03 OF THEOffETICAL E.C AND EOUAL SPACING TOP VfEW

h” ‘,NE PlPE THffEADS

L

all2

1

;::,I; h,

FLANGE

SECTION

;y=b’e may be omlted

on studded flanges

3.29)

PETROLEUM

3-26

Pressure

Difference

Sensing

Types

Ambient

Pressure

Balanced

Sensing

Type

Two Control

ENGINEERING

Piston, Lines

HANDBOOK

Single

Control

(Flapper

Line

Valve)

(Ball Valve)

H

c

LOW-Pressure ControlLlrE

1 3-way Block and Bleed Valve

K Low-Pressure A,,or Gas Source

A

C

M W,reluwRelrlevable Tubmg SaletyValve

Emergency Shul-Down Valve

Hydraulic ControlMamlold

N

Cas,nglTublng A”““llJSiclr ConlrolFlwd

0

Tub,ng Retrievable Tubng SafetyVatve

D-

E

Surface-ConiroUed SaletyValve

P

Ram Latch Hanger System

F

Hydrauhc Surface SaletyValve

a

scoop Head

G

Pneumal~c Surface SafetyValve

General

R

LocatorHead

S

Hydraulk Set Hangar

Schematic

Fig. 3.10-Types

Dual Installation

Annular

To Tubing Hangar and Retrievable Valves

Control

of subsurface safety valves and completions

Single Line

Line,

Control Small

Parallel

Line

WELLHEAD

EQUIPMENT

AND FLOW CONTROL

TABLE 3.26-API

DEVICES

3-27

TYPE 6BX BLIND AND TEST FLANGES Basic Flanae

Size and

Outside

Total

BOW

Diameter

Thickness

(In.) ~1?/16

[mm]

(in.)

79.4

3%

85.7 1064

65.1

12’3/6

Bolting

Circle

3%

52.4

103.2

of Bolt

325

257

4%s

Bore

635 71.4

lO’/e 115/,6

77.8

Size and

287

2% Z’S6

46.0

3%,

Diameter

[mm]

On 1

WI6 PA6

Nominal

lmml (in.)

lmml

43/lF,

[mm]

of Bolts

Diameter of Bolts (in.)

Lengtht

Radius

of Hub

of Hub

of Hub

at Hub

@ml

W

[mm1 W

5%

1334

6%~

154.0

45/,6 5

109.5 127.0

6’3/,6

1730

5”/,6

144.5

7%5

192.1

WI,

VI6 2%

160.3

9%6

242.9

8%

206.4

On.) -__

8

~

1’5/rs

Imml (IN l/s 49 52 V8

9.5

2%

318

9.5

2%

73

3/a

9.5

of Bolt

Groove

Holes

Bolts

Diameter

OD

(in)

[mm]

9.5

3/a

Raised Face

[mm]

Imml 9 5

59 64

Length of Stud

(in.)

PRESSURE

Small Dlametert

Basic Flange Diameter

WORKING

Diametert

Dimensions”

Number

MAXIMUM

Dimensions” Large

Nommal

-~(in ) 11%

FOR 20,000-psi’

Dimensmns*

Width

’

of

Depth

Groove

of

Groove

(m)

[mm]

(in.)

[mm]

(in.)

[mm]

(1~)

[mm]

Ring Number

46.0

8

203.2

1

1.12

29

7%

191

4%

117.5

3.062

77.77

0.466

11.84

‘/zz

2’/16

52.4

9’/,6

230.2

8

1 ve

1.25

32

8%

210

53/16

131.8

3.395

86.23

0.498

12.85

‘s/s4

5.95

6X-152

2%6

65.1

105-G

261 9

8

1 ‘/4

1.38

35

9%

235

5’5%

150.6

4.046

102.77

0.554

14.07

“/~a

6.75

6X-153

31x6

77.8

115h6

2873

8

1%

1.50

39

10

254

6%

171.5

4.685

119.00

0.606

15.39

‘?&

7.54

5X-154

14%~

357.2

8

1 314

1.88

48

12’/4

311

8%

219.1

5.930

150.62

0.698

17.73

2’/64

8.33

BX-155

4x5

103.2

5.56

Bx-151

‘1380 bar “See Table 325sketch +Type 68X blind flanges must be provided wth a prolong on the rear lace, described by Ihe large and small diameters and length of the hub

SSV’s usually have a stem protruding from a threaded boss on the actuator cylinder head for several reasons. 1, Stem position gives a visual position indication. 2. A position-indicator switch can be attached to provide telemetry feedback information. 3. A manually operated mechanical or hydraulic jack can be attached to open a closed safety valve where the control pressure source is downstream of the safety valve or where system failure makes control pressure unavailable. 4. A lockout cap, or heat-sensitive lockout cap, can be attached to hold the valve open while wireline work is being done through the valve or when the control system is out of service for maintenance. ’ Special Designs. Special designs of SSV’s may have various modifications. 1. Extra-strong springs for cutting wireline, should an emergency occur while wireline work is in progress. Special hardened gates are used for these valves. 2. Extra extension of the cylinder from the valve for nesting of two pneumatic actuators on a dual valve or tree where there is not enough space for the large cylinders to be mounted side-by-side. 3. Cover sleeve or cylinder over the bonnet bolting to protect the bolts from tire. 4. Integral pressure sensors to monitor flowline pressure and control the safety valve. Selection. When ordering an SSV the entire system should be considered. The size of the valve is determined by the flowstream in which it is installed. If it is to be in the vertical run of the tree, it should be the same size as the lower master valve. Pressure, temperature, and service ratings should be the same as for the lower master valve. Actuator specifications should consider control system pressure that is available. Valve body pressure. ratio, and control pressure are related by 2(Pvh) Pcl

=

F,,,

, ..

. ..

.

(3)

where pcl = control pressure, p,+, = valve body pressure, and F,,,. = actuator ratio. Materials for the actuator parts that contact flowline fluids should be consistent with the service and valve body. Subsurface Safety Valves (SSSV’s) SSSV’s are used because they are located in the wellbore and isolated from possible damage by fire, collision, or sabotage. They are designed to be operational when needed most-in catastrophies. but they are more difficult to maintain. SSSV’s are recommended for use with an SSV. Control circuit logic should be designed to close the SSV for routine alarm conditions. Under catastrophic conditions both valves close. SSSV’s are either subsurface- or surface-controlled (Fig, 3.10). Selection. Various features should be considered selecting an SSSV (Fig. 3.11). Tubing-Retrievable

vs.

in

Wireline-Retrievable.

Tubing-retrievable valves have larger bores through the valve for less flowing pressure drop and allow wireline work through the valve without having to retrieve the valve. Since the tubing-retrievable valve is a part of the tubing string and requires a workover rig for retrieval. maintenance is more expensive. Wireline-retrievable valves are located in special landing nipples that are part of the tubing string, and they can be retrieved for maintenance with lower cost wireline methods (Fig. 3.12). Valve Type. The most common type of valves are rotating ball and flapper. Single-Control Line vs. Balance Line. Permafrost, paraffin problems or other equipment such as centrifugal or hydraulic pumps may require setting the safety valve deep, and thus require a balance line (two-control-line system).

3-28

PETROLEUM

TABLE X27-API

Ring Number R20 R23 R24 R26 R27 R31 R35 R37 R39 R41 R44 R45 R46 R47 R49 R50 R53 R.54 R57 R63 R65 R66 R69 R70 R73 R74 R82 R84 R85 Ra6 R87 Raa R89 R90 R91 R99

Pitch Diameter of Ring andGroove

--

(in.)

2’%s 3% 3% 4 4% 4% 5% 5% 6% 7% 7% as6 8%6 9 10%

10% 12% 12% 15 16% 18% i 8% 21 21 23 23 2% 2% 3% 3% 3’5h6

4% 4% 6% 10% 9%

Mm1 68.26 82.55 95.25 101.60 107.95 123.83 136.53 149.23 161.93

180.98 I 93.68 211.14 211.14 228.60

269.88 269.88 323.85 323.85 381.00 419.10 469.90 469.90 533.40 533.40 584.20 584.20 57.15 63.50 79.38 90.49 100.01 123.83 114.30 155.58 260.35 234.95

TYPE R RING-JOINT

(in.)

[mm]

%6 7.94 7/16 11.11 'hs 'A6 7,6

11.11 11.11 11.11 7h6 11.11 y,e 11.11 T/j6 11.11 '/js 11.11 %6 11.11 '/js 11.11 '/j6 11.11 % 12.70 54 19.05 T/,6 11.11 5/e 15.88 T/j6 11.11 % is.88 7,s 11.11 1 25.40 y,s 11.11 =/s 15.88 'he 11.11 v4 19.05 '/z 12.70 % 19.05 56 11.11 5s 11.11 'h 12.70 v8 15.88 5/8 15.88 vi 19.05 3/4 19.05 7/a 22.23 1% 31.75 y,s 11.11

Oval (in.) -9/,6 "/,8 "A6 "A6 "A6 "/,5 '& "A6 "A6 "A5 "/16 "A6 3/i 1 "As 7/s "As 7% "/,6 15/ls 1%~ % 'l/16 1 3/4

1 -

Octagonal

[mm] 14.29 17.46 17.46 17.46 17.46 17.46 17.46 17.46 17.46 17.46 17.46 17.46 19.05 25.40 17.46 22.23 17.46 22.23 17.46 33.34 17.46 22.23 17.46 25.40 19.05 25.40 -

HANDBOOK

GASKET

Height of Ring

Width of Ring

ENGINEERING

(in.) ‘12

[mm]

12.70 =/s 15.88 % 15.88 =/0 15.88 % 15.88 5/s 15.88 % 15.88 51% 15.88 xl 15.88 v8 15.88 S/8 15.88 s/s 15.88 "h,j 17.46 'S/16 23.81 73 15.88 '3h6 20.64 5% 15.88 'se 20.64 va 15.88 1% 31.75 %I 15.88 's6 20.64 =/a 15.88 's6 23.81 1%~ 17.46 '%s 23.81 5/a 15.88 =I8 15.88 "/,s 17.46 '3/ls 20.64 '3/ls 20.64 's6 23.81 '%6 23.81 1'/,6 26.99 1% 38.10 5/a 15.88

Width of Flal of Octagonal Ring (in.) ~0.206 0.305 o.xl5 0.305 0.305 0.305 0.305 0.305 0.305 0.305 0.305 0.305 0.341 0.485 0.305 0.413 0.305 0.413 0.305 0.681 0.305 0.413 0.305 0.485 0.341 0.485 0.305 0.305 0.341 0.413 0.413 0.485 0.485 0.583 0.879 0.305

[mm] 5.23 7.75 7.75 7.75 7.75 7.75 7.75 7.75 7.75 7.75 7.75 7.75 a.66 12.32 7.75 10.49 7.75 10.49 7.75 17.30 7.75 10.49 7.75 12.32 a.66 12.32 7.75 7.75 a.66 10.49 10.49 12.32 12.32 14.81 22.33 7.75

TOLERANCES (InI -.

“r

(wdth of ring,see Note 3)

g: b,D d,{ ,, ,O 23O

(widthof groove) (averagepitchdiameter01 rmg) (average pitchdiameterof groove) (radiusm rmgs) (radiusI” groove, (angle).

Cc--,--i OCTAGONAL

OVAL

GROOVE

1.The 23’ suriaceson both grooves and octagonalringsshallhave a surfacefinish no rougherthan 63 RMS 2.A smallbead on the centerof e,therova,or oclagonalrmgs. locatedso that,tw,llnot enterthe groove,IS permwible 3 A plustolerance of % in [l 19 mm] on rmg heightISpermitted, prowded the varlataon m heightofany given rmg does not exceed X4 I” 1039 mm] throughoutthe entireclrcumterence

+oooe + l/64 *0008 +1/64,-O ~0008 10007 *0.005 -fl/64 -

Imml + 0.20 to39 to20 +039.-O f 0.20 f0.17 *0.12 t 0.39 max + ‘ho

WELLHEAD

EQUIPMENT

AND FLOW CONTROL

TABLE

Rwt Number -~~ R20 R23 R24 R26 R27 R31 R35 R37 R39 R41 R44 FM5 R46 R47 R49 R50 R53 R54 R57 R63 R65 R66 R69 R70 R73 R74 Ra2 R04 R85 R86 R87 R08 R89 R90 R91 R99

DEVICES

TYPER RING-JOINTGASKET(continued)

3.27-API

Radius in Octagonal Ring

3-29

Depth of Groove

Width of Groove

Approximate Distance Between Made Up Flanges

Radius in Groove

(in.)

[mm]

(in.)

[mm]

(in.)

[mm]

‘/j6 '/I 6

1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59

‘14

6.35 7.94 7.94 7.94 7.94 7.94 7.94 7.94 7.94 7.94 7.94 7.94 9.53

' %2 'S/3* '5/s* '5/s* '5/s* '5/s* '5/s* 'S/3* 'S/32 '5/z* 'S/32 '5/z* "/a*

8.73 11.91 11.91 11.91 11.91 11.91 11.91 11.91 11.91 11.91 11.91 11.91 13.49

12.70 7.94 11.11 7.94 11.11 7.94 15.88 7.94 11.11 7.94 12.70 ‘12 9.53 "/s 12.70 '/2 7.94 %6 7.94 % 6 9.53 3/s % 6 11.11 '/I 6 11.11 12.70 % 12.70 '/2 Yi6 14.29 1x16 17.46 7.94 =i 6

25& 'S/s2 21/s* 'S/3* 2'/32 'S/32 l'hij '5/a* 2& 'S/3* 25/32 '%2

19.84 11.91 16.67 11.91 16.67 11.91 26.99 11.91 16.67 11.91 19.84 13.49

'A 6 7132 'i 6 l/32 'i 6 '/x2 3/32 '/a* 'A 6 '/& 'i 6 'As

1.59 0.79 1.59 0.79 1.59 0.79 2.38 0.79 1.59 0.79 1.59 1.59

25& 'S/3* '5/a* "/S>

19.84 11.91 11.91 13.49

'A 6 '/a* '/32 '/16

1.59 0.79 0.79 1.59

3il6 Yl.9 %6 '/a

21/32 Q2 =/32 *5& =/x2 15/E

16.67 16.67 19.84 19.84 23.02 33.34 11.91

'A 6 'i 6 'A 6 ',I 6

1.59 1.59 1.59 1.59 1.59 2.38 0.79

%2

% 6

%6 %6 '/l6 %6 %6 %6 'il6 %6 %6 %6 %6 %6 %6 %6 %6 'A 6 y3p 'il6 '/I 6 'A6

%6 %6

'/I 6 'il6 %6 %6 '/l6

1.59 1.59 1.59 1.59 1.59 1.59 2.38 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59

% 6

1.59 1.59 1.59 1.59

%6 3& 'i 6

1.59 2.38 1.59

% 6

'il6

%6 Y's Yl6 %6 %6 Y’s %6 %6 %6 %6 %6 w % s/l 6 y'6 %6 y'6 %6 =/a %6 y'6 %6

Equalizing Valves. For equalizing pressure differentials across the closed valve rather than equalizing from an external source. Soft Seat vs. Lapped-Metal Seat. Soft seats can have less minor leakage, but are more susceptible to damage, especially at higher pressure.

Subsurface-Controlled Subsurface Safety Valves (SSCSV’s). These valves sense flow conditions in the well at the valve and close when the flow exceeds a preset limit. They are usually located in a landing nipple in the tubing. There are two main types. Excess flow valves sense the pressure drop across an orifice in the valve and close the valve when the increased flow rate causes the pressure drop to increase past a preset limit. Low-pressure valves have a stored reference pressure in the valve. The valve closes when tubing pressure at the valve draws down below the reference pressure due to restriction of the formation. Both types of valves depend on a flow rate substantially in excess of normal maximum. The presumption is that essentially a complete structural failure (opening) of

‘732

(in.) ~J/32 '/& j/31

[mm]

0.79 0.79 0.79 ‘/32 0.79 0.79 '/a2 ‘/32 0.79 0.79 y& 0.79 '/32 0.79 '/aa 0.79 '/3* 1132 0.79 T/z2 0.79 1.59 'A 6

56 3/Z '/a2

-

(in.) 732 %6 3/16 3il 6 3h Yils 3/l 6 %6 3/16 %6 3/'5 %6 '/a 6i32

3/16 Y32 %6 %2 3/'6

'i2 Yl6 %2

3/16 3/6 '/a

%2 3/6

3/16 ‘/16

%6 3h6

[mm1 4.0 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 3.2 4.0 4.8 4.0 4.8 4.0 4.8 5.6 4.8 4.0 4.8 4.8 3.2 4.8 4.8 4.8 3.2 4.0 4.0 4.0 4.8 4.8 7.9 4.8

the Christmas tree exists ahead of the choke. Caution must be exercised that the well is capable of closing the valve at the setting used. Surface-Controlled Subsurface Safety Valves (SCSSV’s). These valves are normally controlled by pressure maintained by a unit at the surface in response to a pilot system. Pressure is transmitted to the safety valve through a small-diameter parallel-tube control line in the annulus or through the tubing/casing annulus in conjunction with a packer below the safety valve (Fig. 3.10). Volumetric compression and expansion of the control fluid usually makes the small tubing system preferable to the annulus conduit even though it is not as rugged. However, the small tubing will convey higher control pressures more economically. When the control pressure is released, a spring and well pressure on the control piston will close the valve. Since well pressure is not always assumed dependable, some valves have a second line, or balance line, to the surface, which is filled with control liquid. This provides a hydrostatic pressure to the back side of the piston for closure. Single control-line valves have depth failsafe

3-30

PETROLEUM

ENGINEERINGHANDBOOK

TABLE3.28-APITYPERXPRESSUREENERGlZEDRING-JOINTGASKETS

Ring Number RX20 RX23 RX24 RX25 RX26 RX27 RX31 RX35 RX37 RX39 RX41 RX44 RX45 RX46 RX47 RX49 RX50 RX53 RX54 RX57 RX63 RX65 RX66 RX69 RX70 RX73 RX74 RX82 RX84 RX85 RX86 RX87 RX08 RX89 RX90 RX91 RX99 RX201 RX205 RX210 RX215

Outside Diameter of Ring (In.)

[mm1

3 34%4 41x4 4% 4% 42%2 5% 55%

76.20 93.27 105.97 109.54 111.92 118.27 134.54 147.24 W& 159.94 ‘W& 172.64 7%4 191.69 V’s4 204.39 84%4 221.85 8% 222.25 w32 245.27 11%4 280.59 11% 283.37 13"/& 334.57 13% 337.34 152'/G4 391.72 1725h4 441.72 185%4 480.62 1Q%2 483.39 21%4 544.12 213?!32 550.07 231%~ 596.11 232x2 600.87 2?& 67.87 wm 74.22 3% 90.09 4% 103.58 w&4 113.11 5% 139.30 57/w 129.78 6% 174.63 11 'Ym 286.94 w64 245.67 2.026 51.46 2% 62.31 3=/x 97.63 53% 140.89

‘Tolerancean fhese dmens~ons is +0

Total Width of Ring (in.)

[mm]

-8.73 "A '5&

11.91 11.91 8.73 11.91 11.91 11.91 11.91 11.91 11.91 11.91 11.91 11.91 13.49 19.84 11.91 16.67 11.91 16.67 11.91 26.99 11.91 16.67 11.91 19.84 13.49 19.84 11.91 11.91 13.49 15.08 15.08 17.46 18.26 19.84 30.16 11.91 5.74 5.56 9.53 11.91

'% ' %2 '%2 '%2 '% '%2 '%2 '5/x* '% '%2 '% ' %2 %2 '%2 %2 ‘%2 vi2 '%2 1’h ‘%2 v32 ' x2 %2 '%2 %2 ‘%2

'%2 '%2 '%2 '%2 ’ ‘A 6 2%~ %2 1% '% 0.226 %2 3/e ' %2 -0 015 m

[co

Width of Flat (in.)

[mm]

Height of Outside Bevel (in.)

0.1824.620.1253.18 0.254 6.45 0.167 0.167 0.254 6.45 0.182 4.62 0.125 0.167 0.254 6.45 0.167 0.254 6.45 0.167 0.254 6.45 0.254 6.45 0.167 0.167 0.254 6.45 0.254 6.45 0.167 0.254 6.45 0.167 0.167 0.254 6.45 0.254 6.45 0.167 0.188 0.263 6.68 0.271 0.407 10.34 0.254 6.45 0.167 0.335 8.51 0.208 0.254 6.45 0.167 0.335 8.51 0.208 0.167 0.254 6.45 0.582 14.78 0.333 0.167 0.254 6.45 0.335 8.51 0.208 0.167 0.254 6.45 0.271 0.407 10.34 0.263 6.66 0.208 0.407 10.34 0.271 0.254 6.45 0.167 0.167 0.254 6.45 0.167 0.263 6.68 0.335 8.51 0.188 0.188 0.335 8.51 0.208 0.407 10.34 0.407 10.34 0.208 0.292 0.479 12.17 0.297 0.780 19.81 0.254 6.45 0.167 0.057 0.126 3.20 0.072 0.120 3.05 0.213 5.41 0.125 0.167 0.210 5.33

[mm] 4.24 4.24 3.18 4.24 4.24 4.24 4.24 4.24 4.24 4.24 4.24 4.24 4.78 6.88 4.24 5.28 4.24 5.28 4.24 8.46 4.24 5.28 4.24 6.88 5.28 6.88 4.24 4.24 4.24 4.78 4.70 5.28 5.28 7.42 7.54 4.24 1.45* 1.83' 3.18* 4.24'

Height of Ring (in.)

[mm]

3/h

19.05 25.40 25.40 19.05 25.40 25.40 25.40 25.40 25.40 25.40 25.40 25.40 25.40 28.58 41.28 25.40 31.75 25.40 31.75 25.40 50.80 25.40 31.75 25.40 41.28 31.75 41.28 25.40 25.40 25.40 28.58 28.58 31.75 31.75 44.45 45.24 25.40 11.30 11.10 19.05 25.40

1 1 Y4 1 1 1 1 1 1 1 1 1 1% 1 =/s 1 1 ‘h 1 1 '/4 1 2 1 1 7/4 1 1% 1 'I4 1% 1 1 1 1% 1 '/a 1'/4 1 '/4 1% 12% 1 0.445 0.437 0.750 1.000

-0 38 mm]

TOLERANCES on I (wdlh of rmg) (wdth of flat) (helghlof chamfer) (depth of groove) lwldthof aroavel iheIghtoi ring) fOD of rlnal

+0008,-0000 +0006,-0000 +oooo,-003 +002.-o + 0 008

+0008.~0000

lmml +020.-000 i-0 15 -000 +ooo -079 +039.-o + 0 20

+0020.-0000 10005 * 0 02 max + “”

‘A plustolerance of0 006 I” iorb, and h, ISpermeted providedIhevanalioninwdfh or helghlof any rungdoes nofexceed 0 004 m throughout11sentire wcumference

NOTE 1 The pressurepassage hole ,llustrated ,nthe RX nng crosssecl,onISreqwed I”ringsRX-82 through RX-91 only Cenlerlmeofholeshallbe locateda!mldpolnlofdlmenslonb, Hole diametershallbe ‘;s I” [l6 mm] forringsRX-82through RX-65.?Izz I” [24 mm] forrmgs RX-86 and RXG37.and 1s in 13 2 mm] iorringsRX-68 lhrough RX-91 NOTE 2 The 23O surfaceson both rungsand grooves shallhave a surfacefimshno roughe:than 63 RMS

WELLHEADEQUIPMENTAND

FLOWCONTROL

TABLE 3.28-API

Ring Number

-z--.-u RX20

RX23 RX24 RX25 RX26 RX27 RX31 RX35 RX37 RX39 RX41 RX44 RX45 RX46 RX47 RX49 RX50 RX53 RX54 RX57 RX63 RX65 RX66 RX69 RX70 RX73 RX74 RX82 RX84 RX85 RX86 RX87 RX86 RX89 RX90 RX91 RX99 RX201 RX205 RX210 RX215

Radius in Ring (in.) 'A6 '/'6 'A6 '/16 '/'6 '/'lj '/'6 'h '/s '/16 '/Is '/16 'Alj 'As 3/32 '/'#j l/16 '/I@? 1/,, '/'6 ?/a2 'A6 '/,6 %6 Z/32 '/16 ys2 '/'6 '/16 '/'6 '/16 '/'#j '/16 '/'+j s2 Ys2 '/'6 '/& '/& 'h2 '/,6

[mm) 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 1.59 2.38 1.59 1.59 1.59 1.59 1.59 2.30 1.59 1.59 1.59 2.38 1.59 2.38 1.59 1.59 1.59 1.59 1.59 1.59 1.59 2.38 2.38 1.59 0.40" 0.40" 0.79" 1.59"

DEVICES

TYPE RX PRESSURE

[mm]

'/4 %6 %6 l/4 7' 6 %6 %6 %6 7' 6 %6 %6 %6 %6 3/s

6.35 7.94 7.94 6.35 7.94 7.94 7.94 7.94 7.94 7.94 7.94 7.94 7.94 9.53 ‘12 12.70 %6 7.94 7,s 11.11 =/IR 7.94 7/1; 11.11 %6 7.94 %! 15.88 %6 7.94 56 11.11 =/I16 7.94 '/2 12.70 3/a 9.53 ‘/2 12.70 %6 7.94 %6 7.94 va 9.53 7/16 11.11 7/16 11.11 '/2 12.70 ‘/2 12.70 %6 14.29

732 732 ‘/4 %6

3.97 3.97 6.35 7.94

ENERGIZEDRING-JOINTGASKETS(continued)

Pitch Diameter of Groove

Width of Groove

Depth of Groove (in.)

3-31

(in.)

-u

’%2

(in.)

lmml

8.73 '5/a* 11.91 '5% 11.91 "h 8.73 'S/32 11.91 'S/a2 11.91 'S/32 11.91 'S/a2 11.91 '5/m 11.91 'S/32 11.91 'S/16 11.91 'y'6 11.91 'S/32 11.91 "/3* 13.49 25/x2 19.84 'S/a2 11.91 *'/22 16.67 '5/x2 11.91 2%~ 16.67 ‘5/32 11.91 l'/,E 26.99 ‘S/3211.91 Q2 16.67 'S/32 11.91 25& 19.84 "/a2 13.49 =/32 19.84 '5/32 11.91 'S/3* 11.91 "/32 13.49 2%~ 16 67 Q2 16.67 25& 19 84 2542 19.84 2& 23.02 15/ls 33.34 '$ 11 91 732 5.56 %2 5.56 3/s 9.53 '5/a* 11.91

limitations. The limit is determined by the ability of the spring to overcome friction and the force of the hydrostatic pressure against the piston without help from well pressure. A depth limitation of the two-control-line system may be the time for closure due to control liquid expansion and flow restriction in the small-diameter long control line. Control System The control system is the interface system between the power source, the sensors, and the safety valves. The design of the control system depends on several factors: (1) type of power source available-compressed air, produced gas, or electricity: (2) pressure and volume requirements of the safety valves; (3) number and types of sensors (pneumatic-twoor three-way valves-or electric); (4) power requirements and limitations of the pilots; (5) number and type of indicators (position status.

[mm]

211/1668.26 3% 82.55 3% 95.25 4

101.60 107.95 i; 123.83 5% 136.53 5% 149.23 6% 161.93 7% 180.98 7% 193.68 as/,, 211.14 85/16 211.14 9 228.60 105/ 269.88 10% 269.88 12% 323.85 123I4 323.85 381.00 :s,* 419.10 18% 469.90 18% 469.90 21 533.40 21 533.40 23 584.20 23 584.20 2% 57.15 2% 63.50 3% 79.38 90.49 3%6 3'5/,6 100.01 4% 123.83 4'/2 114.30 6% 155.58 lo'/4 260.35 9% 234.95 -

Radius in In Groove (in.) -%2 'h2 %2

‘h 'I.32 'Lx2 552

‘h 'Lx2 ‘Ii2 %2

'L32

752 ‘A6

%6 %2 '/I3

%2 %6 %2

%2 'h 'A 6

‘h ‘A3 ‘A6 'A6 'h x2 %6

‘/l6 %6

'A 6 'A 6 'A6 3,i2

'h2 %2

‘/64 %2

‘/32

[mm] 0.79 0.79 0.79 0.79 0.79 0.79 0.79 0.79 0.79 0.79 0.79 0.79 0.79 1.59 1.59 0.79 1.59 0.79 1.59 0.79 2.38 0.79 1.59 0.79 1.59 1.59 1.59 0.79 0.79 1.59 1.59 1.59 1.59 1.59 1.59 2.38 0.79 0.79 0.40 0.79 0.79

Approximate Distance Between Made Up

(In.) Imml -9.5 3/s ‘%2 ‘732

15/32 ‘X2 ‘5/32 ‘732

'%2 ‘%2

' %2 ' %2 ' %2 ' %2 2g/32 ' %2 .-

’732 ' %2

’ %2 ' %2 2% ‘%2

1% ' Y32 2% ' %2 23/32 ' %2 ' 5/32 3% 3/s

V8 3/a

310 23/32

%I ' =I32 -

-

11.9 11.9 11.9 11.9 11.9 11.9 11.9 11.9 11.9 11.9 11.9 11.9 18.3 11.9 11.9 11.9 11.9 11.9 21.4 11.9 11.9 11.9 18.3 15.1 18.3 11.9 11.9 9.5 9.5 9.5 9.5 9.5 18.3 19.1 11.9 -

-

pressure status, first-out sensor): (6) telemetry interface: and (7) logic required. (Will any pilot shut all the safety valves or should certain sensors close certain valves or combinations of valves?) We recommend a time delay after SSV’s close before the SSSV’s close, and that SSSV’s open first. Most systems are pneumatically powered because compressed air or gas is usually available. The power needed by most pilots and safety valves is pneumatic or hydraulic. Power is consumed only when a valve is being opened; most of the time the system is static. Most electrically powered sensors continuously consume power and are sensitive to short-duration power transients. Electra-hydraulic systems arc well suited to cold environments. The air or gas supply should be kept clean and dry. Electrical power should be protected from transient disruptions, especially in the sensor circuitry. Such precautions greatly enhance reliability.

PETROLEUM

3-32

TABLE

Ring Number BX-150 BX-151

8X-152 BX-153 BX-154 BX-I 55 BX-156 8X-157 BX-158

3.29-API

(in.)

wl6 2%6 3% 4’/,6 71/16 9 11

ENERGIZED

Outside Diameter of Ring

Nominal Size

-42.9 1’%6 I’%6

TYPE BX PRESSURE

[mm]

(in.)

RING-JOINT Total Width of Ring

Height of Ring

[mm]

(in.)

[mm]

(in.)

[mm]

ENGINEERING

GASKETS

Diameter of Flat (in,)

[mm]

2.84272.190.3669.300.3669.30 3.008 76.40 0.379 9.63 3.334 84.68 0.403 10.24

0.379 0.403

9.63 10.24

2.79070.87 2.954 75.03 3.277 83.24

65.1 77.8 103.2 179.4 228.6 279.4

3.974 4.600 5.825 9.367 11.593 13.860

100.94 116.84 147.96 237.92 294.46 352.04

0.448 0.488 0.560 0.733 0.826 0.911

11.38 12.40 14.22 18.62 20.98 23.14

0.448 0.488 0.580 0.733 0.826 0.911

11.38 12.40 14.22 18.62 20.98 23.14

3.910 4.531 5.746 9.263 11.476 13.731

99.31 115.09 145.95 235.28 291.49 348.77

16.800 15.850 19.347 18.720

426.72 402.59 491.41 475.49

1.012 0.938 1.105 0.560

25.70 23.83 28.07 14.22

1.012 0.541 0.638 0.560

25.70 13.74 16.21 14.22

16.657 15.717 19.191 18.641

423.09 399.21 487.45 473.48

46.0 52.4

BX-159 BX-160 BX-161 BX-162

13% 163/4 16%

346.1 346.1 425.5 425.5

BX-163 BX-164

18% 18%

476.3 476.3

21.896 22.463

556.16 570.56

1.185 1.185

30.10 30.10

0.684 0.968

17.37 24.59

21.728 22.295

551.89 566.29

BX-165 BX-166

21% 21%

539.8 539.8

24.595 25.198

624.71 640.03

1.261 1.261

32.03 32.03

0.728 1.029

18.49 26.14

24.417 25.020

620.19 635.51

BX-167 BX-168 BX-169 BX-170 BX-171 BX-172

26% 26% 5% 9 11 13%

679.5 679.5 130.2 228.6 279.4 346.1

29.896 30.128 6.831 8.584 10.529 13.113

759.36 765.25 173.52 218.03 267.44 333.07

1.412 1.412 0.624 0.560 0.560 0.560

35.86 35.86 15.84 14.22 14.22 14.22

0.516 0.632 0.509 0.560 0.560 0.560

13.11 16.05 12.93 14.22 14.22 14.22

29.696 29.928 6.743 8.505 10.450 13.034

754.28 760.17 171.27 216.03 265.43 331.06

13%

Hole Size

Width of Flat

Outside Diameter of Groove

Depth of Groove

Width of Groove

Ring Number

(in.)

[mm]

(in.)

[mm]

(in.)

BX-150 BX-151 BX-152

-7.98 0.314 0.325 0.346

8.26 8.79

%6 %6 %6

1.6 1.6 1.6

-5.56 %2 %2 ’ %4

5.56 5.95

BX-153 BX-154 BX-155 BX-156 BX-I 57 BX-158

0.385 0.419 0.481 0.629 0.709 0 782

9.78 10.64 12.22 15.98 18.01 19.86

‘A 6 %6 %6 1 ‘/a ‘/a

1.6 1.6 1.6 3.2 3.2 3.2

’ ‘/A ’ gh4 v64 VI.5 ‘12 g/l 6

6.75 7.54 8.33 11.11 12.70 14.29

4.046 4.685 5.930 9.521 11.774 14.064

102.77 119.00 150.62 241.83 299.06 357.23

0.554 0.606 0.698 0.921 1.039 1.149

14.07 15.39 17.73 23.39 26.39 29.18

BX-159 BX-160 BX-161 BX-162

0 869 0.408 0.482 0.481

22.07 10.36 12.24 12.22

‘/a ‘/a ‘/a

=/s %6 43/&

%a

3.2 3.2 3.2 1.6

%4

15.88 14.29 17.07 8.33

17.033 16.063 19.604 18.832

432.64 408.00 497.94 478.33

1.279 0.786 0.930 0.705

32.49 19.96 23.62 17.91

BX-I 63 BX-164

0.516 0.800

13.11 20.32

‘/a ‘/a

3.2 3.2

*a/3* 23/22

18.26 18.26

22.185 22.752

563.50 577.90

1.006 1.290

25.55 32.77

0X-165 8X-166

0.550 0.851

13.97 21.62

‘/a ‘/a

3.2 3.2

vi vi

19.05 19.05

24.904 25.507

632.56 647.88

1.071 1.373

27.20 34.87

BX-167 BX-168 BX-169 BX-170 BX-171 BX-172

0.316 0.432 0.421 0.481 0.481 0.481

8.03 10.97 10.69 12.22 12.22 12.22

‘A 6 %6 X6 ‘A6 %s X6

1.6 1.6 1.6 1.6 1.6 1.6

2’/~ 2%~ V6

21.43 21.43 9.5 8.33 8.33 8.33

30.249 30.481 6.955 8.926 10.641 13.225

768.32 774.22 176.66 220.88 270.28 335.92

0.902 1 ,018 0.666 0.705 0.705 0.705

22.91 25.86 16.92 17.91 17.91 17.91

vi4 %4 v64

[mm]

(in.)

[mm]

2.89373.48 3.062 77.77 3.395 86.23

HANDBOOK

(in.)

[mm]

0.45011.43 0.466 11.84 0.498 12.65

TOLERANCES

(in1

b,’ b, 3 dg h;’

0,

(widthof ring) (widthof Ilat) (hole we) (depth 01 groove) (00 Of groove) !heigM PI ring) (wldt”

Of grOO”e,

d,

(00 of ring) (OD of flat) (rad,usI” ““9)

L=

mw

d,

+ 0 008,-0.000 +0006,-00w “One +o 02, -0 +0004.-0000

+ 0.008.-0 000 +0004.-0000 + 0 000.- 0.006 too02

Imml tom-000 to 15.-000 “DW +o 39.-o +o lO,-000 +o.zo.-000

‘A plusfoleranceof0 006 ,n fo,b, and h, ISpermlUed providedIhe “ariall~” I”widthDI heightof any r,ngdoes notexceed 0 004 I” throughout11s entire cw cumference

SHARP CORNER

NOTE

,, shallbe 6 10 12% of the gaskelh,

WELLHEAD

EQUIPMENT

AND FLOW CONTROL

DEVICES

3-33

Tubing Retrievable

13 in. Wireline Retrievable h

I SingleContrDl

I Two Control

1

Fig. 3.1 l-Subsurface

safety valve design

options

Hydraulically powered safety valves require a pump/control unit in the system (Fig. 3.13). The preferred type of pump is the ratio-piston pneumatic-overhydraulic pump. These pumps have pneumatic pressure operating on a relatively large piston to push a relatively small pump plunger. Low pneumatic pressure can thus develop high hydraulic pressure. The output pressure is easily controlled by the pressure of the input power gas, which can be controlled by a simple demand-pressure regulator. Pressure maintenance is automatic and continuous. Care should be taken to select a pump that is free of continuous bleeding of gas and that will not stall in its reciprocating motion at the end of a stroke. Valve control and system logic is performed by pneumatic/hydraulic or pneumatic/pneumatic relays. These relays permit the use of either bleed (two-way) or block and bleed (three-way) sensors (Figs. 3.14 and 3.15). Relays are reset manually to put the system back in service after a closure. This safety feature ensures that a person is present to determine that the cause for closure has been corrected and that reopening would not be hazardous.

in.

Fig. 3.12-Tubing-retrievable and wireline-retrievable controlled subsurface safety valves.

surface-

Circuit design determines the hierarchy of closure. All surface and subsurface safety valves should close in case of fire, collision, and manual actuation of the emergency shutdown system (ESD). Many systems close only the SSV of a single well when sensors on a single well actuate because of high liquid level, high pressure resulting from freezing or valve malfunction downstream, or low pressure resulting from flowline rupture or backpressure

Filter

Regulators

Pneumatic

Relay

‘Ire

Supply Gas n

Tank

lsolatlon Valve Fig 3.13-Basic

Relief Valve

Strainer hydraulic

control

circuit

Hydraulic Relay

3-34

PETROLEUM

Fig. 3.14-Single branched system for two hierarchies trol (bleed-type sensors).

of con-

ENGINEERING

HANDBOOK

bleed (two-way) or block-and-bleed (three-way). Electric sensors interface with pneumatic systems with solenoid valves. Conditions that are usually monitored include (Fig. 3.16): (1) pressure-high or low because of flowline or pressure vessel blockage or rupture: (2) level-high or low in separator or storage tank resulting from control valve system malfunction; (3) fire-heat is sensed by fusible plugs or fusible control line, flames are sensed by ultraviolet detectors, and temperature is detected by infrared detectors; (4) toxic or flammable gas mixtures-detectors located at four or more locations around the perimeter or in enclosures; (5) manual control-ESD system valves at boat landings, living quarters, and other critical locations. Pressure sensors should be located at any point in the production system where sections of the system can be isolated by a check valve or block valve, or where there is a change in pressure due to a choke or pressure reducing valve. lo Pressure sensors may have a moving-seal sensing element or an elastic element such as a Bourdon tube. Moving-seal sensors have poorer repeatability but are considerably less susceptible to damage by abuse and overpressure.

valve failure. Sometimes several wells on a platform or lease will be closed as a group if they are high vs. low pressure, oil vs. gas wells, etc. Every system should be designed to suit the characteristics of the wells and the severity of consequences of malfunctions. Platforms and compact land leases may have all the control system in a cabinet or console. Communication between the cabinet and well should be with control system media. If well pressure is piped to sensors in the cabinet, the well fluids may freeze and prevent proper operation. There is also the danger of high-pressure, high-volume flow from a ruptured line and leakage of toxic or flammable fluids to an enclosed area. Electric devices and lines usually need to be explosion proof. Requirements for the designation “explosion proof” are explained in the Nat]. Electrical Code. s API RP14F9 defines which installation areas require explosion-proof equipment.

Regulations Governmental regulations control the design and operation of some safety shut-in systems. For example, the Minerals Management Service of the U.S. government controls installations in the outer continental shelf (OCS) waters of the U.S. The rules are published in the OCS Order No. 5. 6 The OCS orders require that safety valves installed in or on wells in the federally controlled waters be made according to the ANSIIASME SPPE-1 ” specification and API Specs. 14Ai2 and 14D.7 ANSIIASME SPPE-1 is an extensive quality-assurance specification. API Specs. 14A and 14D are performance and design specifications for SSSV’s and SSV’s.

Sensors Sensors monitor conditions that indicate production system hazards or malfunctions. The sensor then actuates an integral pilot valve or switch to activate a control valve. The pilot valve and/or control valve may

Most flow-control functions are described in this chapter in the sections on Wellheads and Safety Shut-In Systems, and in Chaps. 11 through 16. Some valves and controls are discussed in Chaps. 4 (Production Packers) and 5 (Gas Lift). Other flow-control devices are discussed in the following.

n

Other Flow-Control Devices

I

4Lir SUPPlY

Valve

Pressure Sensors

Level Sensors

Actuator

Valve

Relay Valve

Fire (Heat) Sensors

kManual (ESD) Electric Solenoid (Computer Control)

On Pilot Line Fig. 3.15-Single branched system trol (block-and-bleed-type

for two hierarchies sensors).

of con-

Fig. 3.16--Remote

controlled

SSV system

WELLHEAD

EQUIPMENT

AND FLOW

CONTROL

DEVICES

Landing Nipple ProfIle Klckover TOOI

A

Nipple

__

Male Packing Adapter

c-

___

Spht Ring

1

0.Rng

Valve or Plug

R

Female Packing Adapter

Fig. 3.18-Side

l

L

V-Packing

1

0.Rng

L

Female Packing Adapter

pocket

mandrel.

they do not obstruct flow up through the tubing. Sidepocket-mandrel valves can be removed by wireline for redressing the seals, which are subject to damage when the circulation path is first opened. Sliding-sleeve valves can be provided with landing-nipple profiles for isolation with a wireline lock mandrel in case of sealing failure. Sliding-sleeve valves can be incorporated in safety-valve nipples to isolate the control line when the safety valve is removed. Tubing Plug

Fig. 3.17-Sliding

sleeve

valve

The tubing should be plugged to prevent flow or loss of control when the tree and/or master valve is to be removed. Plugs are available for landing nipples in the wellhead and for nipples in the tubing string. Tubing plugs are set and retrieved with wireline methods. Chemical Injection Valves

Input Safety Valves (ISV’s) Injection wells can be protected by the safety shut-in systems discussed earlier in this chapter. The ISV is a lower-cost safety valve that can be used for wells where there is only flow downward into the well. It is basically a check valve mounted on a wireline-retrievable mandrel located in a landing nipple. Upward flow closes the valve. Circulating Devices Circulating devices are wireline-operable valves or devices used to permit selective communication between the tubing and the tubing/casing annulus. Variations include (1) sliding-sleeve valve (Fig. 3.17), (2) sidepocket mandrel and inserted “dummy” valve (Fig. 3.18). and (3) potted nipple and lock mandrel. Sliding-sleeve valves and side-pocket mandrels permit wireline operations to be performed through them, and

Some wells require frequent or continuous injection of small quantities of chemicals, such as methanol, for protection from freezing or as inhibitors for corrosion control. The chemicals can be injected down through a small-diameter parallel tubing or through the tubing/casing annulus. Chemical injection valves can be installed in a circulating device to better control the injection rate and to provide backflow protection.

Corrosion Wellhead Corrosion Aspects Corrosion has often been defined as the destruction of a metal by reactions with its environment. The attack may be internal or external and may result from chemical or electrochemical action. Internal attack usually results from weight loss corrosion (“sweet corrosion”) caused by the presence of CO* and organic acids, or sulfide or chloride stress cracking

3-36

corrosion (“sour corrosion”) caused by the presence of HzS. chlorides, or a combination of these elements. External attack usually results from “oxygen corrosion” caused by exposure to atmospheric oxygen, “electrochemical corrosion” caused by the flow of electric currents, or a combination of the two. One or more methods may be employed to control corrosion in wellhead equipment, depending on the type of corrosion present and the economics involved: (1) use of special corrosion-resistant alloys, (2) injection of an effective inhibitor, (3) application of effective coatings, and/or (4) properly applied and maintained cathodic protection. Although a detailed discussion of corrosion is not the purpose of this section, it is necessary to describe briefly the various types of corrosion encountered in wellhead equipment to explain the various methods of control. Internal and external corrosion are controlled differently and are discussed separately. Internal Corrosion Weight Loss Corrosion. Weight loss corrosion is usually defined as corrosion occurring in oil or gas wells where no iron sulfide corrosion product or H 1 S odor exists. Corrosion of this type in gas-condensate wells is often attributed to CO2 and organic acids. Although noncorrosive in the absence of moisture, when moisture is present, CO? dissolves and forms carbonic acid. Carbonic acid with the organic acids contributes to corrosion. The quantity of CO2 dissolved in the corroding fluid determines the severity of corrosion. Generally, corrosion can be expected when the partial pressure of the CO?, at bottomhole conditions, exceeds 30 psi. The partial pressure of COZ can be easily determined: partial pressure equals (total pressure) times (percent CO*). Wellhead Protection Methods. Wellhead protection methods for weight loss corrosion may take two forms. 1. An effective inhibitor, protective coatings. or special-alloy equipment is generally required when the CO? partial pressure, at bottomhole conditions, exceeds 30 psi. 2. Special-alloy equipment is generally required when the CO1 partial pressure, at bottomhole conditions, exceeds 100 psi. Sulfide or Chloride Stress Cracking Corrosion. Sulfide or chloride stress cracking corrosion is defined as corrosion occurring in oil or gas wells when hydrogen sulfide or chlorides are present. Iron sulfide appears as a black powder or scale. Hydrogen sulfide, like COz, is not corrosive in the absence of moisture. If moisture is present. the gas becomes corrosive. If CO? is also present, the gas is more severely corrosive. Attack by H?S causes the formation of iron sulfide. and the adherence of the iron sulfide to steel surfaces creates an electrolytic cell. The iron sulfide is cathodic to the steel and accelerates local corrosion. Hydrogen sulfide also causes hydrogen embrittlement by releasing hydrogen into the steel grain structure to reduce ductility and cause extreme brittleness. Wellhead Protection Methods for Sulfide or Chloride Stress Cracking. These protection methods take three

forms

PETROLEUM

ENGINEERING

HANDBOOK

1. Special alloy equipment is generally required when pressures exceed 65 psia and the partial pressure of H 1S exceeds 0.05 psia. 2. Proper injection of an effective inhibitor. 3. Carbon and low alloy steels that should not exceed a hardness level of HRC 22. Extreme Sour Senfice. This is sometimes referred to as critical service. An extreme sour condition exists when both CO1 and HIS are present in the well fluids. In this case, protection is required for both sulfide stress cracking and metal loss. In general, stainless steel, Monel*, or other nonferrous materials are used for this service. API Spec. 6A refers to NACE Standard MR-01-75 as the governing standard for materials to resist sulfide stress cracking. I3 External Corrosion Oxygen Corrosion. Oxygen corrosion is caused by the oxidation or rusting of steel due to exposure to atmospheric oxygen or a corrosive atmosphere. The severity of corrosion depends on temperature, erosion of the metal surface, property of corrosion product, surface films, and the availability and type of electrolyte. Salt water causes a very rapid increase in corrosion rate. On offshore installations, wellhead equipment is often subjected to one or more of three zones of attack: (I) the underwater or submerged zone, (2) the splash zone (most severe), and (3) the spray zone. Wellhead Protection Methods for Oxygen Corrosion.

The protection methods for oxygen corrosion include (1) use of special-alloy equipment, (2) application of effective external protective coatings of metallic or nonmetallic materials, and (3) use of cathodic protection for the underwater zone. Electrochemical Corrosion. There are two major types of electrochemical corrosion. One type is somewhat of a reverse plating reaction caused by stray direct electric currents flowing from the steel anode to a cathode. Another type of electrochemical corrosion occurs when pipe or a wellhead is exposed to certain types of moist soil. Bimetallic corrosion, another form of electrochemical corrosion aggravated by use of dissimilar metals, is often called galvanic corrosion. Wellhead Protection Methods for Electrochemical Corrosion. There are four protection methods for elec-

trochemical corrosion: (1) use of properly applied and maintained cathodic protection, (2) application of effective external surface coatings, (3) avoiding use of dissimilar metals, and (4) use of electrical insulation of surface lines from wellhead assembly. Material Selection Table 3.30 shows the general accepted materials for various wellhead services.

Special Application High Pressure Seals Flange connections for pressures through 20,000 psi have been standardized by API and the specifications for these flanges are given in API Spec. 6A.’ However, other pressure-sealing elements in wellhead equipment

WELLHEAD

EQUIPMENT

AND FLOW CONTROL

TABLE

DEVICES

3-37

3.30-ENVIRONMENTS

AND APPLICATIONS Gas/Gas-Condensate

Wells LOW-TemDerature

1. Casing 2. Casing

heads hangers

3. None 4. None 5. None 6. Intermediate casing heads 7. Casing hangers 8. Gaskets 9 Bolts 10. Nuts 11 Tubing heads 12. Tubing

hangers

Part

General Service

H,S

body housing slips pack-off gasket bolts’

Al A J K H M

nuts*

N,N2

see see see see see

body Item Item Item Item Item

housing top bottom pack-off

13. Tubing head adapters 14. Tees and crosses 15. Valves

body body body bonnet

16. Adjustable

17. Positive

A A, A2 A3 61 62 Cl C2 0 E F G H J K L M Ml M2 M3 N N, N2 N3 P R S T

chokes

chokes

bonnet gasket bonnet bolts gates seats stems body bonnet stem seat body bull plug

2 3 4 5 1

Al -

Al,61 Al Al K Al Al Al Al H M A,Bl A,Bl R Al Al R R Al Bl

H,S/

General Service

H,S

CO,

A3 A J K,L H M,Ml M2,M3 Nl,N2

Al,A2 A J K.L F,G M.M3

H,S/ CO,

A3 A J K H M,Ml ,M2

co2 A3 A J K F,G M

co2 A3 A J K F,G Ml,M2

N,Nl,NZ

N,N2

Nl,N2

N3

A3 -

A3 -

Al ,A2

A3

Al,A2

-

-

-

-

A1,Bl A3 A3 K,L

AI,Bl Al Al K,L

Al,Bl A3 A3 K,L

A3,P A3,P A3,P A3,P

P P P P

H.G M,Ml M2,M3 A3 A3 D A3 A3 S T A3 R

F.G M,MS

A3 -

Al ,A2 A J KL H M,M2.M3

-

Al ,Bl Al Al

Al ,B 1 Al Al K

Al,Bl A3 A3 K

A3 A3 A3 A3

Cl Cl Cl Cl

c2 c2 c2 c2

H,G Ml .M2

F,G M

F.G Ml,M2

H M3

A3,B2 A3,BZ D A3 A3 s T A3 82

Cl Cl

c2 c2 D c2 c2 S T c2 82

Al Al R Al Al R R Al R

A1,Bl A3 A3 K

c’, c2 S T c2 Bl

AlSl4130 or ASTM A487-9 (normalized) AISI4130 or ASTM A467-90 (quenched 8 tempered) AlSl4130 or ASTM A467-90 modriledby mckel AISI4130 or ASTM A407-90 or 90 modriiedcontrolled hardness HRC 22 Carbon sleelsuch as AISI 1020, 1030, 1040 Carbon steel. controlled hardness HRC 22 max AlSt410 S S or ASTM A217-CA15 AlSt410 S S or ASTM A217-CA15 controlled hardness HRC 22 r,,ax K-500 Monel, HRC 36 max 17.4PH. CondltrOnHi 150 (final heat-treating temperature) AISI316 S S annealed AISI304 S S annealed Softll0” AlSl8620 carbonrtrrded Elastomer,Hycar Elastomer,Hydrl” Bolts, ASTM A19387 Bolts. ASTM A193B7M GiRC 22 max) Bolts. ASTM A453grade 660 Bolts, A320.L7 Nuts,ASTM A194-2H Nuts,ASTM A194GHM (HRC 22 max) Nuts.ASTM A194-2 Nuts:AsTM A194, grade 4 or 7 ASTM A487-CA6NM S S AlSl 4140 low alloy K-500 Monel withcarbldetrrm AtSl4140 wth carbrdetrrm

‘Ballsand nuts must not be burredor covered I” accordance wllh NACE

MR

01-75

KL Al Al Al Al

,A2 ,A2 ,A2 ,A2

N3

Cl Cl E C2 C2 S T C2 R

A3 A J K,L F,G M,Ml M2.M3 Nl,N2

Waterflood

F,G M N,N2

A3 -

L P P F,G M,Ml M2,M3 C2 C2 D C2 C2 S T C2 R

Al Al G M F F E Al Al S T -

PETROLEUM

3-38

TABLE

3.31-CHARPY

Size of

NOTE

IMPACT

[mm]

(ft-lbm)

100 75 50 25

15.020 12.5 10.0 5.0

REQUIREMENTS

(ft-lbm)

[J]

lo.014 8.5 7.0 3.5

17 14 7

[J] 12 9 5

Purchasersare cautionedthatthe energy valuestabulatedabove have been selected10 cow a broad range 01 possiblephysicalproperues,and care should be exercwd ln energy value ~nterpretahons for the higherstrengthTypes 2 and 3 matemls where mlnlmum energy valueshave no, been clearly estabkhed

practice fire test for valves. I4 The fire test is conducted in a flame with a temperature of 1,400 to 1,600”F for a 30-minute test period.

such as valve seat, valve stem, fittings, hanger-packer, casing secondary seals, lockscrews, etc., have not been standardized and are subject to agreement between purchaser and manufacturer. Seals other than flange seals for 20,000 psi and higher working pressures require special consideration because of the difficulty in sealing these high pressures, which are usually encountered in combination with hostile fluids and are subject to agreement between purchaser and manufacturer. Low- and High-Temperature

Subsea Applications Although subsea wellhead and Christmas-tree equipment has been available for a number of years and a number of installations have been made, most of the installations have been made in relatively shallow water. Equipment is now being designed for use in water depths of several thousand feet. Various methods for installing. operating, repairing, or replacing subsea equipment are being utilized such as by remote operation, the use of divers. or the use of submarines or robots. At this time, subsea equipment is proprietary, with each manufacturer pmviding his own design. Subsea installations are designed for specific projects and are agreed on by the manufacturer and the customer. Offshore wells can be broadly classified as those drilled from a fixed or bottom-supported platform or from a floating platform. Floating platforms are either of the semisubmersible or floating-ship type.

Application

Unless otherwise specified, API Spec. 6A for wellhead equipment is designed to operate in temperatures from -20 to 250°F. Low Temperature. API Spec. 6A also provides specifications for materials to operate in temperatures below -20°F. Materials operating in extremely low temperatures become brittle and have low impact resistance. API Spec. 6A specifies minimum impact values at -25”F, -5O”F, and -75°F test temperatures. The specified impact values are shown in Table 3.31.

Fixed Platform Drilling. Offshore wells drilled from a fixed platform normally are drilled with the wellhead and the BOP’s on the platform. The well is completed with the Christmas tree attached to the wellhead on the platform. Wells drilled using a bottom-supported drilling rig (jackup rig) normally utilize mudline-suspension wellheads. The wellhead is installed on the ocean floor, with riser pipe extending from the wellhead to the rig floor. The well is drilled with BOP’s attached to the riser

High Temperature. As the temperature rises, the strength of steel decreases. Table 3.32 shows the working pressure-temperature relationship of wellhead steel pressure containing parts at temperatures from -20 to 650°F. There are some applications where valves with fireresistance capability are required, particularly on offshore platforms where a fire on one well endangers the other wells. API provides API RP 6F, a recommended

TABLE

HANDBOOK

Minimum impact Value Permitted for One Specimen Only Per Set

Minimum Impact Value Required for Average of Each Set of Three Specimens

Specimen (in.) -3.93 2.95 1.97 0.98

V NOTCH

ENGINEERING

3.32-PRESSURE/TEMPERATURE

Temperature

(OF) - 20 to 250 300 350 400 450 500 550 600 650

RATINGS Maximum

I”Cl - 29 to 121 149 177 204 232 260 228 316 343

(Psi) 2ooo1955 1905 1860 1810 1735 1635 1540 1430

(bar) 138 134.8 131.4 128.2 124.8 119.6 112.7 106.2 98.6

OF STEEL

Workinq

(Psi) 3ooo2930 2860 2785 2715 2605 2455 2310 2145

PARTS

Pressure

(bar) 207 202 197.2 192 187.2 179.5 169.3 159.3 147.9

(Psi) -iiGi---4880 4765 4645 4525 4340 4090 3850 3575

(bar) 345 336.5 328.5 320.3 312 299.2 282 265.5 246.5

WELLHEAD

EQUIPMENT

AND FLOW

CONTROL

DEVICES

pipe and the completion is made at the top of the riser pipe. above water, usually on a fixed platform that is installed for the completion. Floating Drilling Vessels. Wells drilled utilizing floating drilling vessels normally utilize remote subsea equipment. The wellhead equipment is installed on the ocean floor. The BOP’s are installed on the wellhead on the ocean floor. Riser pipes connect the equipment on the ocean floor with the vessel. Guidelines extending from the wellhead to the vessel are used for guiding equipment to the wellhead. For water depths too deep to utilize guidelines, guidelineless drilling systems are available. The guidelineless systems are normally used with dynamically positioned vessels. Guidance is accomplished by the use of acoustics, sonar, or TV. The completion (installation of the Christmas tree) on remote subsea equipment can be made either on the ocean floor or on a platform by utilizing tieback equipment. A variety of completion systems can be utilized for the production of oil and gas in various subsea environments. Some of these include single-well (diverassisted or diverless) satellite, platform, template, production riser, caisson or capsule (wet or dry), or combinations of the various basic systems. SPPElOCS Equipment. The U.S. Geological Survey (USGS), in cooperation with API and ASME. has established rules and regulations for safety and pollution prevention equi ment (SPPE) used in offshore oil and gas operations. 8 As described under Surface Safety Valve, the USGS rules and regulations require an SSV on each Christmas tree installed in federal offshore waters. The specification governing SSV’s is API Spec. 14D. ’ To qualify as a manufacturer and/or an assembler of SPPE equipment, a company must become an SPPE certificate holder. To become an SPPE certificate holder, a company must be qualified by ASME to certify compliance with ANSIlASME SPPE-1 standard on quality assurance and certification of safety and pollution prevention equipment used in offshore oil and gas operations. ’ ’ An SPPE certificate holder certifies his equipment by marking it with an authorized OCS symbol.

Independent Screwed Wellhead API Independently

Screwed Wellhead Equipment

This section covers casing and tubing heads having upper-body connections other than API flanges or clamps, in l,OOO- and 2,000-psi working pressures. A typical arrangement of this equipment is shown in Fig. 3.4. Lowermost Casing Heads. Lowermost casing heads are furnished with a lower thread, which is threaded onto the surface pipe. Usually the top of the casing head is equipped with an external thread to receive a threaded cap used to compress the packing to make a seal and hold the slips down. The top thread can also be used to support a companion flange with an API ring groove and bolt holes for attaching standard BOP’s.

3-39

Casing Hanger. The casing-hanger slip segments are wrap-around type with a lower capacity than API casing hangers. The slips can be dropped through the BOP’s to support the casing, but the seal must be placed around the suspended casing after the cutoff has been made. Intermediate Casing Heads. Intermediate casing heads in this class are identical in design to lowermost casing heads. If an intermediate-casing string is used, it is usually suspended in the lower-casing head with a thread positioned just above the lower-casing head to permit easy installation of the intermediate-casing head. If proper spacing is impractical, the intermediate casing may be cut off a few inches above the lower-casing head and a socket-type nipple with a top thread welded to the intermediate casing. Then the intermediate casing head can be attached to the thread. Tubing Heads. A tubing head threads onto the top thread of the production string to support and seal the tubing string. The tubing may be supported with a set of slips and sealed with a sealing element compressed with a cap screwed down on top of the tubing head. Maximum capacity of the slip-type tubing hanger is about 125,000 Ibm of tubing weight. A mandrel or doughnut tubing hanger may be used to support the tubing if desirable. Maximum weight-supporting capacity of this type of tubing hanger is limited only to the weightsupporting strength of the tubing head. A BOP can be attached to the tubing head with a companion flange for protection while running tubing. A stripper rubber may also be used to strip the tubing in or out of the hole under pressure, if needed. If a stripper rubber is used, it can be placed in the tubing-head bowl and a separate bowl can be attached to the tubing head to support the slip assembly or mandrel hanger. Casing heads arc available in all standard sizes with working pressures of 1,000 psi and lower. Tubmg heads are available in working pressures of 1,000 and 2,000 psi. Both units are usually furnished with two 2-in. linepipe outlets, although 3-in. outlets are available. Christmas-Tree Assembly. Christmas-tree assemblies for this type of equipment are usually very simple. If the well is expected to flow, a master valve is screwed onto the top tubing thread, a nipple and tee are screwed into the master valve, and a wing valve and choke are screwed into the tee. Selection. In selecting this class of equipment, the following factors should be considered. 1. Casinghead and tubing-head components should be constructed of cast steel or forged steel and should be full-opening. 2. Casing-hanger slips should be of drop-through type. 3. Caps used to hold down the suspension members and provide a seal should have hammer lugs for easy effective installation. 4. Both casing heads and tubing heads should be easily adaptable, with a full-opening adapter, to a standard BOP.

PETROLEUM

3-40

References 1. S/w;ficcrrion.s fi,r t+‘c//hetrd (r!rr/ C/trr.cirrrcr.cTree Eqrr;pwrrf. API Spec. 6A. 15th edition. API. Dallas (April I. 19861. 2. Reu~mmmdd Prucricr for Cart fmd lJsc of Cmrny cd Tuhui,q. API RP SCl, 12th editjon. APl. Dalla (March 19X1). 3. “Bulletin on Performance Propcntca of Casing. Tubing and Drill Ptpe.” 18th edition, API Bull. 5CZ. API, Dallas (March 1982). 4. Spr~~iJjmf~vr.~ fhr Cusiq Tuhip ad DrYi/ Pipc~ API Spec. 5A. 36th edition, API. Dallas (March 1982). 5. SpeciJkarions for Line Pipe. API Spec. 5L. 33rd e&ton. API. Dallas (March 1983). 6. Prdutrion Sa~?r~ Swrrrrts. OCS Order No. 5. U.S. Dept. of the lntenor (Jan. 197.5).

12. 13.

14. IS.

ENGINEERING

HANDBOOK

, , ~-- -r-.---. -. ANSliASME SPPE-I-82 and Addendum SPPE-lh-19X.3. ANSIIASME. New York City. Sprc~jfjuilim fiw Suhsur/ia P .Sojer~ Vo/w Equipmwl, API Spec. 14A. fifth edition, API. Dallas (March 1981). Muiericrl Reyuiwmrt~~\ , Sulfide S/r-c, t.5 Crtrdiu~ Rei.c rum M~~rnlli~~ Mtrlrricrl fiw Oi!fir/ci Eyrrii,nxvrr. N ACE Standard MR-01-75, NACE. Houston (1978). Rrc~ommcndcd Pwricc,for Fit-c, Tc\tj/r Vu/w.s. API RP 6F. third edition. API, Dallas (Jan. 1982). Fowler. E.D. and Rhodes. A.E.: “Checklist Can Help Specify Proper Wellhead Material.“ Oil and Gus J (Jan. 1977) 59-6 I,